SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
X Annual Report Pursuant to Section 13 or 15(d) of the Securities
---
Exchange Act of 1934 for the fiscal year ended September 30, 1995
Transition Report Pursuant to Section 13 or 15(d) of the Securities
---
Exchange Act of 1934
COMMISSION FILE NUMBER 1-5103
BARNWELL INDUSTRIES, INC.
(Exact name of registrant as specified 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
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
Common Stock, par value American Stock Exchange
$0.50 per share Toronto Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 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
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not 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-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates of the
Registrant on December 12, 1995, based on the closing price on that date on the
American Stock Exchange, was 478,423 shares x $17.00 = $8,133,000.
As of December 12, 1995 there were 1,322,052 shares of common stock, par value
$.50, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
-----------------------------------
1.Proxy statement to be forwarded to shareholders on or about January 18, 1996
is incorporated by reference in Part III hereof.
TABLE OF CONTENTS
PART I
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 Properties
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 Price of and Dividends on the Registrant's
Common Stock and Related Stockholder Matters
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
PART III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
PART IV
Item 14. Exhibits, Financial Statement Schedules
and Reports on Form 8-K
PART I
Item 1. Description of Business
-----------------------
(a) General Development of Business
-------------------------------
Barnwell Industries, Inc. (referred to herein together with its
subsidiaries as "Barnwell" or the "Company") was incorporated in 1956. During
its last completed fiscal year Barnwell was engaged principally in exploring
for, developing, producing and selling oil and natural gas in Canada and the
United States, investing in leasehold land in Hawaii, and drilling and
maintaining water systems in Hawaii. The Company's oil and natural gas
activities comprise its largest business segment. Approximately 70% of the
Company's revenues and 87% of the Company's capital expenditures for the fiscal
year ended September 30, 1995 were attributable to its oil and natural gas
activities. The Company's contract drilling activities accounted for 25% of the
Company's revenues in fiscal 1995 with interest income and other comprising the
remaining 5% of fiscal 1995 revenues. The Company had no land investment
revenue in 1995.
(i) Oil and Natural Gas Activities. In fiscal 1995, the Company invested
------------------------------
$3,434,000 in the acquisition, exploration and development of oil and natural
gas properties, principally in Alberta, Canada. The Company participated in the
drilling of 30 wells, of which nine were successful oil wells and six were
successful natural gas wells, the recompletion of six wells and the acquisition
of two wells in fiscal 1995. The Company continued development of prospects in
the following areas of Alberta: Barrhead, Gilby, Hillsdown, Dunvegan and
Thornbury in addition to new areas of Gilwood and Halkirk. Also during fiscal
1995, the Company sold interests in two non-core, non-producing natural gas
properties. The proceeds of $613,000 were used to reduce long-term debt.
The Company also continued development of oil prospects in North Dakota
with the drilling of four wells in fiscal 1995. Of these four wells, one
exploratory well and two development wells were successful. One well was dry
and abandoned. Additionally, the Company acquired a minor interest in the Blind
River field in Louisiana in fiscal 1995.
(ii) Contract Drilling. Barnwell's wholly-owned subsidiary Water Resources
-----------------
International, Inc. ("WRI") conducts water well drilling, production and
maintenance operations in Hawaii. WRI owns and operates four rotary drill rigs,
pump service equipment and maintains drilling materials and pump inventory in
Hawaii. WRI contracts are usually fixed price contracts and are either
negotiated with private individuals or entities or are obtained through
competitive bidding with various local, state and Federal agencies. Contract
drilling contracts are not subject to renegotiation of profits or termination of
contracts at the election of the governmental entities involved. Contracts
provide for arbitration in the event of disputes.
In fiscal 1995, WRI started six water well and four water well pump
installation contracts and completed five water well and two pump installation
contracts. All five of the completed water wells were started in the current
fiscal year and one of the two completed water well pump installations was
started in the prior year. Twenty-eight percent (28%) of such well drilling and
pump installation jobs, representing 40% of total contract drilling revenues in
fiscal 1995, have been pursuant to government contracts.
At December 1, 1995, WRI had a backlog of four water well contracts, two of
which were in progress as of September 30, 1995, and nine pump installation
contracts, seven of which were in progress as of September 30, 1995. These
contracts represent a backlog of contract drilling revenues of approximately
$2,700,000 as of September 30, 1995.
(iii) Land Development. In fiscal 1994, Kaupulehu Developments submitted a
-----------------
petition to the State Land Use Commission to reclassify approximately 1,000
acres of the approximately 2,180 acres zoned conservation. Kaupulehu
Developments seeks to have the 1,000 acres rezoned to permit the development of
golf courses and residential sites. In December 1994, the State Land Use
Commission began the public hearing process of the rezoning petition; this
process is currently ongoing. See Item 2. "Land Investment Operations".
In April 1995, the option under which Kaupulehu Makai Venture could have
acquired Kaupulehu Developments' leasehold interest in the approximately 2,180
leasehold acres of conservation zoned property in North Kona, Hawaii expired,
unexercised. There is no affiliation between Kaupulehu Makai Venture and the
Company. Costs applicable to the rezoning of the approximately 1,000 acres of
the aforementioned 2,180 acres of conservation zoned property incurred
subsequent to April 1995 are capitalized. Such costs, inclusive of capitalized
interest, amounted to $293,000 at September 30, 1995.
Kaupulehu Makai Venture has completed a significant amount of the
construction of the first golf course, hotel and condominiums and related
infrastructure in the 620 acre urban area. The golf course is essentially
complete and is expected to open in early 1996. The hotel is expected to open
in late 1996.
(iv) Discontinued Food Products Activities. In 1994, the Company
-------------------------------------
transferred its 25% limited partnership interests in Pacific Tropical Products
("PTP") and Orchard Development ("Orchard"), which had a carrying value of nil,
to Mr. Anderson, a director and shareholder of the Company ("Anderson") in
consideration for the release of the Company's future obligations with respect
to PTP and Orchard. Accordingly, operating results related to the food product
segment have been reclassified and included in the statement of operations as
discontinued operations. PTP filed a petition under Chapter 11 of the Federal
Bankruptcy Code in May 1994.
There were no revenues, expenses nor income taxes allocable to discontinued
operations for fiscal 1994. In fiscal 1993, the Company transferred its
ownership of the two subsidiaries (together the "Subsidiaries") that held
general partner ownership interests in PTP and Orchard to Anderson whereupon the
Company was relieved of the Subsidiaries' liabilities and recorded a gain of
$617,000 which represented the Company's proportionate share of the
partnerships' excess liabilities over assets at December 31, 1992.
Simultaneously in fiscal 1993, the partnerships each issued a 25% limited
partnership interest to a wholly-owned subsidiary of the Company, in
consideration for the Company's agreement to provide certain accounting and
operational services to the partnerships for a period of six months. The
earnings from discontinued food products operations of $296,000 for fiscal 1993
represents the aforementioned gain on the transfer of ownership of the Company's
general partnership interest in PTP and Orchard less the Company's share of the
fiscal 1993 losses of PTP and Orchard, net of income taxes. Revenues and income
taxes allocable to discontinued operations for fiscal 1993 amounted to $620,000
and $152,000, respectively.
(b) Financial Information about Industry Segments
---------------------------------------------
<TABLE>
<CAPTION>
Revenues of each industry segment for the fiscal years ended
September 30, 1995, 1994 and 1993 are summarized as follows (all revenues were
from unaffiliated customers with no intersegment sales or transfers):
1995 1994 1993
<S> <C> <C> <C>
------------------- ------------------- -------------------
Oil and natural gas $ 10,520,000 70% $ 13,950,000 70% $ 11,250,000 67%
Contract drilling 3,770,000 25% 5,090,000 25% 4,570,000 27%
Corporate and other 420,000 3% 760,000 4% 400,000 3%
------------ ---- ------------ ---- ------------ ----
Revenues for segments 14,710,000 98% 19,800,000 99% 16,220,000 97%
Interest income 240,000 2% 200,000 1% 500,000 3%
------------ ---- ------------ ---- ------------ ----
Total revenues $ 14,950,000 100% $ 20,000,000 100% $ 16,720,000 100%
============ ==== ============ ==== ============ ====
<FN>
For further discussion see Note 10 (Segment and Geographic Information) of
"Notes to Consolidated Financial Statements" in Item 8.
</TABLE>
(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, 1995, Barnwell employed 39 full-time employees. Twelve
are employed in oil and natural gas activities, 16 are employed in contract
drilling, and 11 are members of the corporate and administrative staff.
(d) Financial Information about Foreign and Domestic Operations and
---------------------------------------------------------------
Export Sales
------------
Revenues, operating profit or loss and identifiable assets by geographic
area for the three years ended September 30, 1995, 1994 and 1993 are set forth
in Note 10 (Segment and Geographic Information) of "Notes to Consolidated
Financial Statements" in Item 8.
Item 2. Description of Properties
-------------------------
OIL AND NATURAL GAS OPERATIONS
------------------------------
General
- -------
Barnwell's oil and natural gas properties are located in Canada,
principally in the Province of Alberta with the exception of the investment of
$448,000 in oil wells in North Dakota and Louisiana. 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, give Barnwell the right to remove oil, natural gas
and related substances subject to payment of specified royalties on production.
Barnwell participates in exploratory and developmental operations for oil
and natural gas on property in which it has an interest and evaluates proposals
by third parties with regard to participation in such exploratory and
developmental operations elsewhere. Exploratory and developmental operations on
property in which Barnwell has an interest and third party proposals for
exploratory and developmental operations on other property are evaluated by
Barnwell's Calgary, Alberta staff. Barnwell also relies on independent
consultants to aid in the evaluation of such exploration opportunities. In
fiscal 1995, Barnwell participated in exploratory and developmental operations
in the Canadian Province of Alberta and North Dakota, although Barnwell does not
limit its consideration of exploratory and developmental operations to these
areas.
Barnwell's producing natural gas properties are located principally in
Alberta. The Province of Alberta determines its royalty share of natural gas by
using a reference price which averages all natural gas sales in Alberta. In
fiscal 1995, the weighted average royalty paid on natural gas from the Dunvegan
Unit, Barnwell's principal oil and natural gas property, was reduced to 21%
compared to 26% in fiscal 1994 due to a reduction in the royalty rate applied by
the Government. This decrease in royalty rate was due to the approval by the
Alberta Government of a change in the classification for royalty purposes of a
portion of the Dunvegan natural gas. The weighted average royalty paid on all
natural gas was approximately 18% in fiscal 1995 compared to 20% in fiscal 1994
primarily due to the change in classification of natural gas from the Dunvegan
area.
In fiscal 1995, 96% of Barnwell's oil production was from properties
located in Alberta. Oil royalty rates under government leases in Alberta are
based on the selling price of oil. In fiscal 1995, the weighted average royalty
paid on oil was approximately 14%. The remaining 4% of Barnwell's oil
production came from properties located in North Dakota; the weighted average
royalty paid on oil produced in North Dakota was 12.5% Additionally, the
Company pays 5% of oil revenues as a severance tax on oil produced in North
Dakota.
In fiscal 1995, the Company spent approximately $375,000 in fiscal 1995 for
land acquisition and seismic costs in various areas of Alberta to be evaluated
and developed subsequent to fiscal 1995.
Typically, unit sales of natural gas are higher in the winter than at other
times due to demand for heating. Unit sales of oil are not subject to seasonal
fluctuations.
Well Drilling Activities
- ------------------------
During fiscal 1995, Barnwell participated in the drilling of 16 development
wells and 14 exploratory wells, of which 15 are capable of production. The
Company also acquired one natural gas and one oil well, and participated in the
recompletion of six wells. The most significant drilling operations took place
in the West Greene/Coastal areas of North Dakota and the Barrhead and Thornbury
areas of Alberta.
In fiscal year 1995, the Company continued to participate in the
development of oil reserves discovered in fiscal 1994 in the state of North
Dakota. Four oil wells were drilled in this pool in 1995, two of which are
capable of production and are producing. One successful exploratory well was
drilled in a similar prospect. The Company now has four wells capable of
producing from two petroleum reservoirs. The Company's working interests in
these wells is 11.667%. The Company's portion of current production from these
wells is approximately 37 barrels per day.
In fiscal 1995, the Company continued further development of a natural gas
project in the Thornbury area. The Company participated in the drilling and
flowline installation of two natural gas wells and the recompletion of one
natural gas well. A total of 33 zones of production from 31 wells are now
contributing to an average daily production of 11 MMCF ("MMCF" means 1,000,000
cubic feet and "MCF" means 1,000 cubic feet) per day. The Company's working
interest in these wells varies between 8.4375% and 22.5%.
The Company participated in the drilling of four wells in the Barrhead area
of Central Alberta in fiscal 1995. Two were completed as natural gas wells and
two were dry and abandoned. Approximately $180,000 was spent in construction of
a natural gas plant. The Company's working interests in these wells varies
between 10.0% and 17.5%, with a 17.5% working interest in the Barrhead natural
gas plant.
At September 30, 1995, the Company was participating in the drilling of two
wells; one was subsequently completed as an oil well and the other was dry and
abandoned.
The following table sets forth more detailed information with respect to
the number of exploratory ("Exp.") and development ("Dev.") wells drilled and
acquired for the fiscal years ended September 30, 1995, 1994 and 1993 in which
Barnwell participated:
<TABLE>
<CAPTION>
Total
Productive Productive Acquired Productive
Oil Wells Gas Wells Wells Wells Dry Holes Total Wells
---------- ----------- ----------- ----------- --------- -------------
Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev.
----- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
- -----------------------------------------------------------------------------------
1995
- ----
Gross* 3.00 6.00 - 6.00 - 2.00 3.00 14.00 11.00 4.00 14.00 18.00
Net* 0.26 1.01 - 1.08 - 0.20 0.26 2.29 1.89 .83 2.15 3.12
1994
- ----
Gross* 3.00 7.00 8.00 23.00 - - 11.00 30.00 9.00 2.00 20.00 32.00
Net* 0.64 1.60 1.26 3.20 - - 1.90 4.80 1.33 0.18 3.23 4.98
1993
- ----
Gross* 1.00 3.00 6.00 13.00 1.00 2.00 8.00 18.00 3.00 2.00 11.00 20.00
Net* 0.20 0.70 1.25 1.95 0.40 0.21 1.85 2.86 0.55 0.23 2.40 3.09
<FN>
* The term "Gross" refers to the total number of wells in which Barnwell owns
an interest, and "Net" refers to Barnwell's aggregate interest therein. For
example, a 50% interest in a well represents 1 gross well, but .50 net
well. The gross figure includes interests owned of record by Barnwell and,
in addition, the portion owned by others.
</TABLE>
The Dunvegan Unit, the Company's principal property located in Alberta,
Canada, has 134 natural gas wells comprising a total of 192 producing well zones
with a sustained capacity of the Unit estimated at 100,000 MCF per day, plus
additional capacity due to the storage capacity program implemented in 1991. In
fiscal 1995, the Company expended $365,000 in the continued development of the
Dunvegan Unit by participating in the drilling of two natural gas wells, one of
which is capable of production while the other was dry and abandoned. Further
developmental drilling will be carried out, which is expected to maintain
current production levels for the immediate future.
Oil and Natural Gas Production
- ------------------------------
In fiscal 1995, approximately 49%, 40%, and 11% of the Company's oil and
natural gas revenues were from the sale of natural gas, sale of oil (including
liquids) and the royalty tax credit (see "Description of Properties - Oil and
Natural Gas Operations - Taxation"), respectively.
Barnwell's natural gas production reached a Company record high in fiscal
1995 with an average net sales volume after royalties of 13,500 MCF per day,
which represents an increase of 5% over fiscal 1994. This increase was
primarily attributable to production from new areas. Dunvegan provided 46% of
the Company's fiscal 1995 natural gas production.
In fiscal 1994, approximately 58%, 30% and 12% of the Company's oil and
natural gas revenues were from the sale of natural gas, sale of oil (including
liquids) and the royalty tax credit, respectively.
Barnwell's natural gas production in fiscal 1994 averaged net sales volume
after royalties of 12,800 MCF per day, an increase of 4% over fiscal 1993. This
increase was primarily attributable to production from new areas. Dunvegan
provided 44% of the Company's fiscal 1994 natural gas production.
In fiscal 1995, oil sales averaged net production of 564 barrels per day,
an increase of 13% over the 500 barrels per day average in fiscal 1994. New
production from the North Dakota project contributed approximately 30 barrels
per day. The Company's major oil producing properties are the Red Earth, Chauvin
and Manyberries areas in Canada and the West Greene and Coastal areas in North
Dakota.
In fiscal 1995, natural gas liquid sales averaged net production of 246
barrels per day, the same volume as in fiscal 1994. The Company's major natural
gas liquids producing properties are the Dunvegan, Hillsdown and Pouce Coupe
areas in Alberta.
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. All of Barnwell's net production in
fiscal 1995, other than 100 barrels of oil and 98,000 MCF of natural gas derived
from the Province of Saskatchewan, 11,200 barrels of oil from the State of North
Dakota and 200 barrels of oil from the State of Louisiana, was derived from the
Province of Alberta. All dollar amounts in this table are in U.S. dollars.
Year Ended September 30,
---------------------------------------
1995 1994 1993
------------ ------------ ------------
Annual net production:
Natural gas liquids (BBLS)* 90,000 90,000 64,000
Oil (BBLS)* 206,000 182,000 183,000
Natural gas (MCF)* 4,916,000 4,679,000 4,506,000
Annual average sale price
per unit of production:
BBL of liquids** $10.98 $ 9.48 $12.55
BBL of oil** $15.71 $14.06 $15.96
MCF of natural gas** $ 1.03 $ 1.57 $ 1.33
Annual average production cost
per unit of gross production:
BBL of oil or liquids $ 3.79 $ 3.49 $ 3.96
MCF of natural gas $ 0.30 $ 0.30 $ 0.24
Productive Wells
- ----------------
Productive Wells***
-----------------------------
Gross**** Net****
------------- ---------------
Location Oil Gas Oil Gas
- -------- ----- ----- ----- -----
Canada
- ------
Alberta 173 337 55.11 46.17
British Columbia - - - -
Saskatchewan 3 21 0.25 3.48
USA
- ---
North Dakota 4 - 0.47 -
Louisiana 1 - 0.02 -
------ ----- ------ -----
Total 181 358 55.85 49.65
====== ===== ====== =====
* When used in this report, "MCF" means 1,000 cubic feet of natural gas at
14.65 psia and 60 degrees F. and the term "BBLS" means stock tank barrels
of oil equivalent to 42 U.S. gallons.
** Calculated on revenues before royalty expense and royalty tax credit
divided by gross production.
*** Seventy natural gas wells have dual or multiple completions and six 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, 1995:
Developed Undeveloped Developed and Undeveloped
Acreage(1) Acreage(1) Acreage(1)
----------------- ---------------- -------------------------
Location Gross(2) Net(2) Gross(2) Net(2) Gross(2) Net(2)
- -------- -------- ------ -------- ------ ---------- ------
Canada
- ------
Alberta 239,639 37,415 116,874 25,676 356,513 63,091
British Columbia 483 40 2,086 281 2,569 321
Saskatchewan 3,696 719 200 11 3,896 730
USA
- ---
North Dakota 560 64 4,588 552 5,148 616
Louisiana 80 2 3,440 69 3,520 71
-------- ------ -------- ------ ---------- -------
Total 244,458 38,240 127,188 26,589 371,646 64,829
======== ====== ======== ====== ========== =======
Barnwell's leasehold interests in its undeveloped acreage, if not
developed, expire over the next five fiscal years as follows: 7% expire during
fiscal 1996; 6% expire during fiscal 1997; 11% expire during fiscal 1998; 15%
expire during fiscal 1999; and 7% expire during fiscal 2000.
Barnwell's undeveloped acreage includes major concentrations in Alberta at
Red Earth (5,977 net acres), Thornbury (2,541 net acres), Foley Lake (1,633 net
acres) and Sutton (2,067 net acres).
Reserves
- --------
The amounts set forth in the table below, prepared by Paddock Lindstrom and
Associates, Ltd., Barnwell's independent reservoir analysts, summarize the
estimated net quantities of proved developed producing reserves and proved
developed reserves of crude oil (including condensate and natural gas liquids)
and natural gas as of September 30, 1995, 1994 and 1993 on all properties in
which Barnwell has an interest. These reserves are before deductions for
indebtedness secured by the properties and are based on constant dollars. No
estimates of total proved net oil or natural gas reserves have been filed with
or included in reports to any other federal authority or agency since October 1,
1980.
(1) "Developed Acreage" includes the acres covered by leases upon which there
are one or more producing wells. "Undeveloped Acreage" includes acres
covered by leases upon which there are no producing wells and which are
maintained in effect by the payment of delay rentals or the commencement of
drilling thereon.
(2) "Gross" refers to the total number of wells or acres in which Barnwell owns
an interest, and "Net" refers to Barnwell's aggregate interest therein. For
example, a 50% interest in a well represents 1 Gross Well, but .50 Net
Well, and similarly, a 50% interest in a 320 acre lease represents 320
Gross Acres and 160 Net Acres. The gross wells and gross acreage figures
include interests owned of record by Barnwell and, in addition, the portion
owned by others.
Proved Developed Producing Reserves September 30,
- ----------------------------------- --------------------------------------
1995 1994 1993
------------ ------------ ------------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 2,025,000 2,133,000 2,005,000
Natural gas - thousand
cubic feet (MCF) 31,700,000 34,624,000 35,895,000
Total Proved Developed Reserves
(Includes Proved
Developed Producing Reserves) September 30,
- ----------------------------------- --------------------------------------
1995 1994 1993
------------ ------------ ------------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 2,296,000 2,427,000 2,222,000
Natural gas - thousand
cubic feet (MCF) 46,746,000 51,850,000 50,711,000
As of September 30, 1995, all of Barnwell's proved developed producing and
total proved developed reserves were located in the Province of Alberta, with
the exception of 3,000 proved developed producing barrels of oil and 460,000
proved developed producing MCF of natural gas located in the Province of
Saskatchewan, 40,000 proved developed producing MCF of natural gas and 12,000
proved developed producing barrels of oil located in the State of Louisiana and
47,000 proved developed producing barrels of oil located in the State of North
Dakota.
During fiscal 1995, Barnwell's total net proved developed reserves
decreased by 131,000 barrels of oil, condensate and natural gas liquids and by
5,104,000 MCF of natural gas. The decrease in oil, condensate and natural gas
liquids reserves was the net result of (a) production during the year of 296,000
barrels; (b) the addition of 97,000 barrels from the drilling of productive oil
wells; (c) the independent engineer's 101,000 barrel upward revision of the
Company's oil reserves; and (d) the sale of reserves in place of 33,000 barrels.
Barnwell's natural gas reserves decreased as a net result of (a) production
during the year of 4,916,000 MCF; (b) the addition of 1,041,000 MCF from the
drilling of productive wells; (c) the sale of reserves in place of 2,585,000
MCF; and (d) the independent engineer's 1,356,000 MCF upward revision of the
Company's natural gas reserves.
Barnwell's working interest in the Dunvegan Unit accounted for
approximately 56% of its total proven natural gas reserves at September 30, 1995
compared to approximately 51% of its proven natural gas reserves at September
30, 1994, and approximately 35% of proven oil and condensate reserves at
September 30, 1995 compared to approximately 30% of proven oil and condensate
reserves at September 30, 1994.
The following table sets out the Company's oil and natural gas
reserves at September 30, 1995, by property name, based on information prepared
by Paddock Lindstrom and Associates, Ltd., Barnwell's independent reservoir
analysts. Gross reserves are before the deduction of royalties; net reserves
are after the deduction of royalties net of the Alberta Royalty Tax Credit.
This table is based on constant dollars where reserve estimates are based on
sales prices, costs and statutory tax rates in existence at the date of the
projection. Oil, which includes natural gas liquids, is shown in thousands of
barrels ("MBBLS") and natural gas is shown in millions of cubic feet ("MMCF").
OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 1995
Proved Producing Total Proved
---------------------------- -----------------------------
Oil Gas Oil Gas
-------------- ------------- -------------- --------------
Property Name GROSS NET GROSS NET GROSS NET GROSS NET
- -------------
(MBBLS) (MMCF) (MBBLS) (MMCF)
Dunvegan Unit 691 618 22,595 19,915 893 797 29,209 26,066
Manyberries 95 89 80 69 95 89 769 676
Ardley (Alix) 10 9 - - 10 9 - -
Barrhead - - 607 515 7 7 960 872
Belloy - - 99 91 - - 99 91
Bow Island 9 9 - - 9 9 - -
Brooks - - 48 44 - - 48 45
Cessford 2 2 - - 2 2 - -
Charlotte Lake - - 875 802 - - 1,394 1,289
Chauvin 132 122 - - 132 121 - -
Coyote - - 3 3 - - 3 3
Donalda - - - - - - 106 103
Dunvegan (Non-Unit) 14 13 503 456 17 16 1,095 1,007
Faith South - - - - - 906 863
Fenn Big Valley - - 26 24 - - 26 24
Gilby 16 15 - - 35 34 - -
Gilwood 17 16 - - - - 91 81
Halkirk - - - - 17 16 - -
Highvale 18 17 - - 18 18 - -
Hilda - - 16 16 - - 16 16
Hillsdown 102 93 4,096 3,678 120 110 4,384 3,956
Joffre - - 4 4 - - 4 4
Lanaway - - - - - - 237 207
Lacombe 21 19 915 833 21 19 915 836
Leduc 1 1 76 67 1 1 261 247
Majeau Lake - - 43 39 - - 43 39
Medicine River 68 62 243 220 73 66 366 325
Mitsue - - 51 48 - - 90 85
Pembina 19 17 760 721 22 20 1,053 996
Pouce Coupe 10 9 1,932 1,762 11 10 2,643 2,430
Provost 17 16 - - 17 16 - -
Rainbow 5 4 - - 5 4 - -
Red Earth 770 740 - - 766 734 328 298
Staplehurst 8 7 - - 15 15 - -
Thornbury - - 1,682 1,554 - - 3,596 3,342
Wood River Unit 4 4 318 293 21 20 340 315
Wood River (Non Unit) - - 6 5 - - 6 5
Worsley 11 10 - - 11 10 - -
Zama 78 71 48 41 97 91 2,225 2,025
Hatton, Saskatchewan - - 608 460 - - 608 460
Webb, Saskatchewan 3 3 - - 3 3 - -
Coastal, ND 14 11 - - 14 11 - -
West Greene, ND 46 36 - - 46 36 - -
Blind River, LA 17 12 53 40 17 12 53 40
----- ----- ------ ------ ------ ------ ------ ------
2,198 2,025 35,687 31,700 2,495 2,296 51,874 46,746
===== ===== ====== ====== ====== ====== ====== ======
Properties are located in Alberta, Canada unless otherwise noted.
Estimated Future Net Revenues
- -----------------------------
The following table sets forth Barnwell's "Estimated Future Net Revenues"
from proved producing reserves and total proved oil, natural gas and condensate
reserves and the present value of Barnwell's "Estimated Future Net Revenues"
(discounted at 10%). Estimated future net revenues for total proved reserves
are net of estimated development costs. Net revenues have been calculated using
current sales prices and costs, after deducting all royalties, operating costs,
future estimated capital expenditures, and income taxes.
Proved Total
Producing Proved
Reserves Reserves
------------- ------------
Year ending September 30,
1996 $ 5,073,000 $ 4,095,000
1997 3,879,000 4,375,000
1998 3,045,000 3,235,000
Thereafter 15,865,000 22,118,000
----------- -----------
$27,862,000 $33,823,000
=========== ===========
Present value (discounted at 10%)
at September 30, 1995 $16,558,000 $20,350,000
=========== ===========
Marketing of Oil and Natural Gas
- --------------------------------
Barnwell sells substantially all of its oil and condensate production under
short-term contracts between the operator of the property and marketers of oil.
The price of oil is determined by negotiation between the parties.
In fiscal 1995, natural gas production from the Dunvegan Unit was
responsible for approximately 46% of the Company's natural gas sales. In fiscal
1995, the Company had only one significant customer, ProGas Limited, which
accounted for 15% of the Company's oil and natural gas sales.
In compliance with certain regulatory events and orders in the U.S. and
Canada affecting the sale and delivery of Canadian natural gas supplies to the
California market, the natural gas purchase, sales and transportation
agreements, under which Barnwell's Dunvegan natural gas was previously sold to
Alberta and Southern Gas Co., Ltd., were terminated, effective November 1993.
New marketing arrangements were made for the sale of Dunvegan natural gas
for fiscal 1994 and future years. Essentially all of Barnwell's Dunvegan
production and a significant portion of its natural gas production from other
properties is sold to several aggregators and marketers under various short-term
and long-term contracts, with the price of natural gas determined by
negotiations between the parties.
Governmental Regulation
- -----------------------
General
-------
The jurisdictions in which the oil and natural gas properties of Barnwell
are located have regulatory provisions relating to permits for the drilling of
wells, the spacing of wells, the prevention of waste of oil and natural gas,
allowable rates of production and other matters. The amount of oil and natural
gas produced is subject to control by regulatory agencies in each province and
state which periodically assign allowable rates of production. The Province of
Alberta also regulates the volume of natural gas which may be removed from the
province and the conditions of removal.
There is no current government regulation of the price that may be charged
on the sale of Canadian oil or natural gas production. Canadian natural gas
production destined for export is, as of November 1, 1988, priced by market
forces subject to export contracts meeting certain criteria prescribed by
Canada's National Energy Board and the government of Canada.
The right to explore for and develop oil and natural gas on lands in
Alberta and Saskatchewan is controlled by the Governments of each of those
provinces. Changes in royalties and other terms of provincial leases, permits
and reservations may have a substantial effect on the Company's operations. In
addition to the foregoing, Barnwell's Canadian operations may be affected in the
future, from time to time, by political developments in Canada and by Canadian
Federal, provincial and local laws and regulations, such as restrictions on
production and export, oil and natural gas allocation and rationing, price
controls, tax increases, expropriation of property, modification or cancellation
of contract rights, and environmental protection controls. Further, 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. The
Province of Alberta announced a series of changes in the calculation of
royalties, which became effective on January 1, 1993. The new calculation of
royalties is more price-sensitive, reducing the royalty rates when prices are
low and increasing them when prices are high. These changes included reduced
royalties for new oil pools discovered after October 1, 1992. Effective
January 1, 1994, the mechanics of the natural gas royalty calculation were
simplified; the Company does not believe this simplification has had or will
have a significant impact on the amount of net oil and natural gas revenues.
Canadian taxpayers are not permitted to deduct royalties, taxes, rentals
and similar levies paid to the Federal or provincial governments in connection
with oil and natural gas production in computing income for purposes of Canadian
Federal income tax. However, they are allowed to deduct a "Resource Allowance"
which is 25% of the taxpayer's "Resource Profits for the Year" (essentially,
income from the production of oil, natural gas or minerals) in computing their
taxable income. The resource properties located in the United States are
freehold mineral interests leased under market conditions, subject to extraction
and severance taxes imposed according to state regulations.
The Province of Alberta has a "Royalty Tax Rebate" in its Income Tax Act
which eliminates the provincial share of income tax attributable to the
inability to deduct such royalties, rentals and similar levies. In addition, the
Alberta Income Tax Act provides for a royalty tax credit to taxpayers calculated
as a percentage of the taxpayer's "Attributed Alberta Royalty Income" (being
that portion of the royalties paid to the Province of Alberta which have been
disallowed as a deduction or added back in computing income for tax purposes)
subject to an annual limitation of the credit. In effect, this returns to the
taxpayer a portion of the royalties paid to the Province of Alberta. For fiscal
years 1994 and 1993 and for the first quarter of fiscal 1995 the royalty tax
credit was determined according to the prevailing price of oil and varied from a
high of 85% at prices below $15.00 a barrel to 73% at $20.00 a barrel and to a
low of 25% at $30.00 a barrel or higher. The maximum credit is equal to the
applicable percentage multiplied by the Crown Royalty Shelter, which amounted to
$2,500,000 Canadian (referred to herein as "C") for fiscal 1994 and 1993 and for
the first quarter of fiscal 1995.
The Province of Alberta stated that changes in the Royalty Tax Rebate would
be announced three years in advance and that the royalty tax credit
program would be continued to December 31, 1997. In 1994, the Province of
Alberta reduced the above-mentioned royalty tax credit percentage from 85% to
75%, and reduced the above-mentioned Crown Royalty Shelter from C $2,500,000 to
C $2,000,000, effective January 1, 1995. As a result of this change, the
Company's royalty tax credit for fiscal 1995 was $230,000 lower than the amount
received for fiscal 1994. The royalty tax credit program has been in effect in
various forms since 1974 and the Company anticipates that it will be continued
in some form for the foreseeable future. If the Alberta Royalty Tax Credit is
not continued, it will have a material adverse effect on the Company. In 1995,
the Province of Alberta made the royalty tax credit percentage increase or
decrease based upon both natural gas and oil prices. Under this program, the
total royalty tax credit the Company receives declines as oil and natural gas
prices rise and increases as oil and natural gas prices decline. The Company
estimates that these changes, which were effective with the beginning of
Barnwell's second quarter of fiscal 1995, will result in an approximate
reduction of $80,000 in net earnings for fiscal 1996 as compared to fiscal 1995.
Natural Gas Pricing
-------------------
The price of natural gas is freely negotiated between buyers and sellers.
Natural gas sold by the Company is generally sold under both long-term and
short-term contracts with prices indexed to market prices and renegotiated
annually.
Oil Pricing
-----------
The price of oil is freely negotiated between buyers and sellers.
Competition
- -----------
The majority of Barnwell's natural gas sales take place in Alberta, Canada
and the Northern California area. Natural gas prices in Alberta are generally
very competitive as there is a significant supply of natural gas with shut-in
capacity. Northern California prices are also competitive and are influenced by
competition from producers in the Southwestern United States (Texas, etc.).
Barnwell's oil and natural gas liquids are sold in Alberta, North Dakota and
Louisiana and are determined by the world price for oil.
The Company competes in the sale of oil and natural gas on the basis of
price, and on the ability to deliver product currently. The oil and natural gas
industry is intensely competitive in all phases, including the exploration for
new production and reserves and the acquisition of equipment and labor necessary
to conduct drilling activities. The competition comes from numerous major oil
companies as well as numerous other independent operators. There is also
competition between the oil and natural gas industry and other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers. Barnwell is a minor factor 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
conducts water well drilling, pump installation and pump maintenance activities
in Hawaii, and has also drilled geothermal wells in Hawaii in previous years.
WRI owns and operates four rotary drill rigs, owns a two acre storage and
maintenance yard near Hilo, Hawaii, leases a three-quarter of an acre
maintenance facility in Honolulu and a one acre maintenance and storage facility
with 2,800 square feet of interior space in Kawaihae, Hawaii, and maintains
drill and pump inventory. As of September 30, 1995, WRI employed 16 drilling,
pump and administrative employees, none of whom are union members.
WRI is capable of drilling both shallow and deep water wells in Hawaii, and
has drilled the deepest water well in the State. Additionally, WRI is
contracted to install and repair water pumps after wells are completed. Pump
installation and maintenance contracts are primarily obtained from municipal
water utilities. The demand for WRI's services is dependent upon land
development activities in Hawaii, which can currently be described as moderate.
WRI markets its services to land developers and government agencies, and
identifies potential contracts through public notices and referrals. Contracts
are usually fixed price contracts and are negotiated with private entities or
obtained through competitive bidding with various local, state and Federal
agencies. Contract revenues are not dependent upon the discovery of water, and
contracts are not subject to renegotiation of profits or termination at the
election of the governmental entities involved. Contracts provide for
arbitration in the event of disputes.
The Company's contract drilling segment which operates in Hawaii is not
subject to seasonal fluctuations.
Activity
- --------
In fiscal 1995, WRI started six water well and four water well pump
installation contracts and completed five water well and two pump installation
contracts. All five of the completed water wells were started in the current
fiscal year and one of the two completed water well pump installations was
started in the prior year. Twenty-eight percent (28%) of such well drilling and
pump installation jobs, representing 40% of total contract drilling revenues in
fiscal 1995, have been pursuant to government contracts. At December 1, 1995,
WRI had a backlog of four water well contracts, two of which were in progress as
of September 30, 1995, and nine pump installation contracts, seven of which were
in progress as of September 30, 1995. These thirteen contracts represent a
backlog of contract drilling revenues of approximately $2,700,000 as of
September 30, 1995.
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 the
State of Hawaii which use cable tool and rotary drill rigs that are capable of
drilling water wells in Hawaii. These contractors compete actively with WRI for
government and private contracts. Pricing is the Company's major method of
competition; reliability of service is also a major factor.
LAND INVESTMENT OPERATIONS
- --------------------------
In May 1984, the Company, through a wholly-owned subsidiary, acquired a
50.1% interest in approximately 10,800 acres of leasehold property on the Kona
coast of the Island of Hawaii. The Company's interest and the remaining
leasehold interest in the property were contributed to a joint venture,
Kaupulehu Developments, in which the Company has a 50.1% controlling interest.
The property is located in the North Kona District between the Pacific
Ocean and Mamalahoa Highway. The western end of the property features extensive
ocean frontage with shoreline lagoons formed by the interaction of the lava
flows and the ocean. The original approximately 10,800 acre parcel was divided
by more than two miles of the Queen Kaahumanu Highway and had approximately four
miles of frontage on the Mamalahoa Highway along the eastern boundary of the
property. The land area between the Queen Kaahumanu Highway and the Pacific
Ocean is approximately 2,800 acres in size and the land area between the Queen
Kaahumanu Highway and the Mamalahoa Highway ("the upland portion") is
approximately 8,000 acres in size. Kaupulehu Developments obtained the rezoning
of approximately 620 acres of such leasehold property to urban for both state
and county purposes to allow for two hotel sites, two golf courses, several
residential sites interspersed around and within the planned golf courses and
one commercial site.
Kaupulehu Developments granted options to independent third parties to
acquire the leasehold interest for the development of the hotel, commercial,
golf course and residential sites, comprising the approximately 620 acre
property, the approximately 2,180 acres zoned conservation adjoining the
approximately 620 acre urban area and the approximately 8,000 acre upland
portion.
In fiscal 1989 and 1990, options were exercised with respect to hotel and
golf course sites, the commercial site and the approximately 8,000 acre upland
portion.
In fiscal 1991, Kaupulehu Developments entered into no land transactions.
In fiscal 1992, Kaupulehu Developments entered into definitive agreements
with Kaupulehu Makai Venture. Kaupulehu Makai Venture succeeded to all
development rights and obligations previously held by other independent third
parties. The managing general partner of Kaupulehu Makai Venture is an
affiliated company of Kajima Corporation of Japan, one of the largest
construction companies in Japan. There is no affiliation between Kaupulehu
Makai Venture or its predecessors and the Company. Kaupulehu Developments
received cash consideration in partial payment for the residential sites in
fiscal 1992. This transaction resulted in a pre-tax gain, net of minority
interests, of $2,410,000.
In fiscal 1994, Kaupulehu Developments submitted a petition to the State
Land Use Commission to reclassify approximately 1,000 acres of the approximate
2,180 acres zoned conservation. Kaupulehu Developments seeks to have the 1,000
acres rezoned to permit the development of golf courses and residential sites.
Kaupulehu Developments, as part of the rezoning process, submitted to the State
Land Use Commission an Environmental Impact Statement. In September 1994, the
State Land Use Commission accepted the Environmental Impact Statement. In
December 1994, the State Land Use Commission began the public hearing process of
the rezoning petition; this process is currently ongoing.
Activity
- --------
In fiscal 1995, there were no land transactions.
In April 1995, the option under which Kaupulehu Makai Venture could have
acquired Kaupulehu Developments' leasehold interest in approximately 2,180
leasehold acres of conservation zoned property in North Kona, Hawaii expired,
unexercised. Costs applicable to the rezoning of the approximately 1,000 acres
of the aforementioned 2,180 acres of conservation zoned property incurred
subsequent to April 1995 are capitalized. Such costs, inclusive of capitalized
interest, amounted to $293,000 at September 30, 1995.
Kaupulehu Makai Venture has completed a significant amount of the
construction of the first golf course, hotel and condominiums and related
infrastructure in the 620 acre urban area. The golf course is essentially
complete and is expected to open in early 1996. The hotel is expected to open
in late 1996.
At September 30, 1995, the remaining real estate position (i.e. leasehold
interests and related development rights) held by Kaupulehu Developments is
comprised of the approximately 2,180 leasehold acres zoned conservation and
development rights with respect to lands zoned residential in the adjacent 620
acre urban area. The residential lands are under option to Kaupulehu Makai
Venture. This option, if exercised, entitles the Company to receive $16,157,000
in connection with its 50.1% interest in Kaupulehu Developments. The
residential site option expires on April 30, 2007; however, this option will
expire sooner unless 20% of the consideration is received on or before
December 31, 1999 and 50% of the then remaining consideration is received on or
before April 30, 2003. There is no assurance that this option or any portion
thereof will be exercised.
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 factor
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 three years Hawaii's economy has been in a recession. While
the current outlook is for moderate economic growth of 1% to 2%, the real estate
market is not expected to experience a measurable improvement in the near term.
Item 3. Legal Proceedings - None.
-----------------
Item 4. Submission of Matters to a Vote of Security Holders - None.
---------------------------------------------------
PART II
Item 5. Market Price of and Dividends on the Registrant's Common Stock
--------------------------------------------------------------
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, 1993 19-7/8 18-1/2 December 31, 1994 19-1/2 19
March 31, 1994 23-5/8 18-5/8 March 31, 1995 20 19
June 30, 1994 21 19-1/2 June 30, 1995 20 18-1/8
September 30, 1994 19-3/4 18-1/2 September 30, 1995 19-1/8 18-1/8
As of December 1, 1995, there were 1,322,052 shares of common stock, par
value $.50, outstanding. Additionally, there were approximately 500 holders of
the common stock of the registrant as of December 1, 1995.
The Company declared four quarterly dividends of $0.05 per share in fiscal
1994 and two quarterly dividends of $0.075 per share in fiscal 1995. In May
1995, quarterly dividend payments were suspended.
<TABLE>
<CAPTION>
Item 6. Selected Financial Data
-----------------------
For the fiscal year ended September 30:
- ---------------------------------------
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Revenues $14,950,000 $20,000,000 $16,720,000 $21,450,000 $16,530,000
=========== =========== =========== =========== ===========
Earnings from
continuing operations
before extraordinary
gain and cumulative
effect of accounting
change $ 650,000 $ 2,520,000 $ 2,114,000 $ 2,525,000 $ 2,973,000
Earnings (loss) from
discontinued operations - - 296,000 (585,000) (1,213,000)
Extraordinary gain - - - 230,000 -
Cumulative effect
of accounting change - - 800,000 - -
----------- ----------- ----------- ----------- -----------
Net earnings $ 650,000 $ 2,520,000 $ 3,210,000 $ 2,170,000 $ 1,760,000
=========== =========== =========== =========== ===========
Net earnings per share,
primary:
Earnings from
continuing operations
before extraordinary
gain and cumulative
effect of accounting
change $0.49 $1.90 $1.59 $1.87 $2.13
Earnings (loss) from
discontinued operations - - 0.22 (0.43) (0.87)
Extraordinary gain - - - 0.17 -
Cumulative effect
of accounting change - - 0.61 - -
---------- ---------- ---------- ---------- ---------
Net earnings per share,
primary $0.49 $1.90 $2.42 $1.61 $1.26
========== ========== ========== ========= =========
Cash dividends
declared per share $0.15 $0.20 $0.10 $0.30 $0.60
===== ===== ===== ===== =====
Weighted average number
of shares outstanding 1,326,100 1,326,500 1,329,067 1,345,449 1,394,528
=========== =========== ========== =========== ===========
As of September 30:
- -------------------
Long-term debt,
excluding current portion $11,100,000 $10,600,000 $10,600,000 $12,000,000 $14,486,000
=========== =========== =========== =========== ===========
Total assets $28,780,000 $30,622,000 $28,081,000 $31,231,000 $31,333,000
=========== =========== =========== =========== ===========
Market price per share $18.38 $19.00 $19.63 $14.25 $21.13
====== ====== ====== ====== ======
Proved developed reserves:
Oil and liquids-barrels 2,296,000 2,427,000 2,222,000 2,179,000 2,369,000
=========== =========== =========== =========== ===========
Natural gas-thousand
cubic feet 46,746,000 51,850,000 50,711,000 48,184,000 49,430,000
=========== =========== =========== =========== ===========
<FN>
For further discussion see Items 7 and 8.
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
-------------------------------------------------
CONDITION AND RESULTS OF OPERATIONS
-----------------------------------
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Cash flows from operations for fiscal 1995 were $1,924,000 as compared to
$4,336,000 in fiscal 1994. This decrease of $2,412,000 was due to lower
earnings resulting from lower natural gas prices and the receipt of $1,586,000
in the prior year as a result of the termination of natural gas purchase, sales
and transportation agreements with Alberta and Southern Gas Co., Ltd. No such
payment was received in the current period, and approximately $700,000 of taxes
due on this fiscal 1994 receipt were paid in fiscal 1995. Additionally, in
fiscal 1995 the Company paid $1,420,000 in estimated income taxes related to the
April 1995 expiration of the unexercised option under which Kaupulehu Makai
Venture could have acquired Kaupulehu Developments' leasehold interest in
conservation zoned property in North Kona, Hawaii. These decreases were
partially offset by the sale of $958,000 of trading securities in 1995 which
were purchased in 1994.
The decrease in natural gas prices, which contributed significantly to the
Company's reduced earnings and cash flows from operations, has also led to
reduced prices for natural gas leases. To improve the Company's capacity to
acquire more petroleum properties, the Company suspended its dividend in May
1995 and issued $2,000,000 in convertible debentures in June 1995. The notes
are payable in 20 consecutive equal quarterly installments beginning in
October 1998. Interest is payable quarterly at an initial rate of 10% per annum
until October 1, 1995, after which the interest rate will be adjusted quarterly
to the greater of 10% per annum or 1% over the prime rate of interest. 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 after July 1, 1997 at premiums declining 1% annually from
5% to 0% of the principal amount of the notes. $1,900,000 of such notes were
issued to affiliates of the Company. Due to the time involved in developing
petroleum prospects, the proceeds from the issuance of these debentures will be
largely utilized in fiscal 1996.
The Company's major credit facility is with the Royal Bank of Canada, a
Canadian bank, for Canadian (referred to herein as "C") $16,000,000 or its U.S.
dollar equivalent of approximately $11,900,000 at September 30, 1995. Under the
credit facility agreement, the facility is reviewed annually, based primarily on
the future cash flows related to the Company's oil and natural gas properties.
The next review is planned for February 1996. Subject to that review, the
facility may be extended one year with no required debt repayments for one year
or converted to a 6-year term loan by the bank. The Company anticipates that
the bank will reduce the amount of this facility upon its February 1996 review
due to lower natural gas prices; any such reduction is not anticipated to be in
excess of available credit. If the facility is converted to a 6-year term loan,
the Company has agreed to the following repayment schedule of the then
outstanding loan balance: year 1-26%; year 2-24%; year 3-17%; year 4-15%; year
5-12% and year 6-6%. 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 Company utilized $1,500,000 of its cash
during fiscal 1995 to repay a portion of the debt outstanding under the
facility. At September 30, 1995, the Company had an unused line of credit
available under this facility of approximately $2,800,000.
Barnwell's consolidated cash balance at September 30, 1995 was $2,976,000,
a decrease of $1,222,000 from the Company's cash balance of $4,198,000 at
September 30, 1994. This decrease was primarily due to oil and natural gas
capital expenditures totaling $3,434,000, which exceeded the $1,924,000 of cash
flows provided by operations.
In fiscal 1995, the Company sold two non-producing natural gas properties
for $613,000 in cash; no revenue or income was recognized as these proceeds were
credited to the full cost pool. These proceeds were utilized to make a portion
of the long-term debt repayment discussed above.
Cash flows from operations in fiscal 1994 decreased from fiscal 1993 due to
the collection of a receivable in fiscal 1993 for an income tax refund of
$1,220,000, the investment of $978,000 in trading securities in fiscal 1994 and
an increase in contract drilling receivables attributable to an increase in
contract drilling work at the end of fiscal 1994 compared to the end of fiscal
1993. These cash flow decreases were partially offset by an increase in natural
gas profits which resulted from higher natural gas prices and the receipt of the
aforementioned compensatory payment as a result of the termination of the
natural gas sales contracts. This payment was recognized as income in fiscal
1994.
In fiscal 1995, the Company invested $3,434,000 in the acquisition,
exploration and development of oil and natural gas properties. In fiscal 1995,
the Company participated in the drilling of 16 development wells and 14
exploratory wells, 15 of which are capable of production. The Company also
participated in two development oil and four development natural gas well
recompletions.
The Company continued the development of several oil prospects in North
Dakota in fiscal 1995, drilling one exploratory and three development wells. Of
these four wells, one exploratory well and two development wells were
successful. One other development well was dry and abandoned. The Company
further expanded its U.S. oil and natural gas operations acquiring an interest
in an oil and natural gas prospect in Southwestern Louisiana for $163,000.
The Company spent $203,000 on contract drilling and other property and
equipment and $293,000 towards the rezoning of land in North Kona, Hawaii, in
fiscal 1995.
The following table sets forth the Company's capital expenditures and the
number of wells drilled for each of the last three fiscal years:
1995 1994 1993
----------- ----------- -----------
Other capital expenditures $ 496,000 $ 387,000 $ 73,000
Oil and natural gas capital expenditures $ 3,434,000 $ 5,350,000 $ 3,193,000
Total capital expenditures $ 3,930,000 $ 5,737,000 $ 3,266,000
Increase (decrease) in oil and natural
gas capital expenditures $(1,916,000) $ 2,157,000 $ 447,000
Development oil and
natural gas wells drilled 16 32 18
Exploratory oil and
natural gas wells drilled 14 20 10
Successful oil and
natural gas wells drilled 15 41 23
It is anticipated that Barnwell's total fiscal 1996 capital expenditures
will be approximately one-third higher than that of fiscal 1995. The Company
also has a commitment to construct $200,000 of improvements at its contract
drilling yard at Sand Island on Oahu, Hawaii, by June 1997. The Company
believes current cash balances and future cash flows from operations will be
sufficient to fund these expenditures, make the scheduled repayments of its
convertible notes, and repay the outstanding balance on its credit facility,
should the Company or Royal Bank of Canada elect to convert the facility to a
term loan.
The Company did not receive any cash payments in fiscal 1995, 1994 and 1993
related to its 50.1% interest in Kaupulehu Developments. Kaupulehu
Developments' cash flows specifically relate to the sale of leasehold interests,
which do not occur every year.
In fiscal 1994, Kaupulehu Developments submitted a petition to the State
Land Use Commission to reclassify approximately 1,000 acres of the approximate
2,180 acres zoned conservation. Kaupulehu Developments seeks to have the 1,000
acres rezoned to permit the development of golf courses and residential sites.
In December 1994, the State Land Use Commission began the public hearing process
of the rezoning petition; this process is currently ongoing.
Kaupulehu Makai Venture has completed a significant amount of the
construction of the first golf course, hotel and condominiums and related
infrastructure in the 620 acre urban area. The golf course is essentially
complete and is expected to open in early 1996. The hotel is expected to open
in late 1996.
The remaining real estate position (i.e. leasehold interests and related
development rights) held by Kaupulehu Developments at September 30, 1995, is
comprised of the approximately 2,180 leasehold acres zoned conservation and
development rights with respect to lands zoned residential in the adjacent 620
acre urban area. The residential lands are under option to Kaupulehu Makai
Venture. This option, if exercised, entitles the Company to receive $16,157,000
in connection with its 50.1% interest in Kaupulehu Developments. The
residential site option expires on April 30, 2007; however, this option will
expire sooner unless 20% of the consideration is received on or before
December 31, 1999 and 50% of the then remaining consideration is received on or
before April 30, 2003. There is no assurance that this option or any portion
thereof will be exercised.
In fiscal 1993, the Company repurchased 16,500 shares of its common stock
from officers of the Company for $236,000, an average of $14.30 per share,
under a stock repurchase program announced in March 1991. The Company did not
repurchase any shares of its common stock in fiscal 1995 or 1994. At
September 30, 1995, the Company could purchase an additional 19,800 shares under
the March 1991 program.
In fiscal 1994, the Company declared regular quarterly dividends on its
common stock at the rate of $0.05 per share. The Company also declared and paid
dividends totaling $198,000 during the first half of fiscal 1995. In May 1995,
due to the decline in natural gas prices, the Company elected to suspend the
payment of dividends pending further review of investment opportunities.
RESULTS OF OPERATIONS
- ---------------------
Barnwell reported net earnings of $650,000 in fiscal 1995, a decrease of
$1,870,000 from net earnings of $2,520,000 in fiscal 1994. This decrease was
due in part to net earnings of $880,000 recognized in fiscal 1994 as a result
of cash received for the termination of natural gas purchase, sales and
transportation agreements with Alberta and Southern Gas Co., Ltd. No such
payment was received in fiscal 1995. In addition, fiscal 1995 earnings were
reduced by a 34% decrease in natural gas prices, partially offset by a 5%
increase in natural gas production and 13% and 12% increases in oil production
and prices, respectively.
Barnwell reported earnings from continuing operations of $2,520,000 in
fiscal 1994, an increase of $406,000 (19%) over the $2,114,000 of earnings from
continuing operations reported in fiscal 1993. This increase was due to an
$880,000 oil and natural gas decontracting payment, net of income taxes,
received in November 1993, and 18% higher natural gas prices, which contributed
to a $205,000 after-tax increase in the Company's oil and natural gas operating
profit. The increase in earnings from continuing operations was partially
offset by a decrease in contract drilling profits due to lower demand for water
well drilling work and an increase in Canadian taxes due to higher Canadian
income.
Fiscal 1993 earnings from continuing operations of $2,114,000 decreased
$411,000 (16%) from earnings from continuing operations of $2,525,000 in fiscal
1992. This decrease was due to the fact that Kaupulehu Developments did not
complete any land transactions in fiscal 1993 as compared to fiscal 1992. In
fiscal 1992, the Company earned $1,520,000 after taxes from Kaupulehu
Developments. This decrease was partially offset by higher fiscal 1993 natural
gas prices and production which increased operating profit by $699,000, and by
the fact that the Company incurred in fiscal 1992, a $286,000 after-tax write-
off of the Company's advances to a Canadian corporation to improve an apartment
building in British Columbia, Canada.
<TABLE>
<CAPTION>
Oil and Natural Gas
- -------------------
Annual Average Price
Annual Net Production Per Unit
----------------------------------- ----------------------------
Increase Increase
(Decrease) (Decrease)
------------- -------------
1995 1994 Units % 1995 1994 $ %
--------- --------- -------- ---- ------ ------ ------- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Liquids (barrels) 90,000 90,000 - - $10.98 $ 9.48 $ 1.50 16%
Oil (barrels) 206,000 182,000 24,000 13% $15.71 $14.06 $ 1.65 12%
Natural Gas (MCF) 4,916,000 4,679,000 237,000 5% $ 1.03 $ 1.57 $(0.54) (34%)
</TABLE>
<TABLE>
<CAPTION> Annual Average Price
Annual Net Production Per Unit
----------------------------------- -----------------------------
Increase Increase
(Decrease) (Decrease)
-------------- -------------
1994 1993 Units % 1994 1993 $ %
--------- --------- -------- ---- ------ ------ ------- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Liquids (barrels) 90,000 64,000 26,000 41% $ 9.48 $12.55 $(3.07) (24%)
Oil (barrels) 182,000 183,000 (1,000) (1%) $14.06 $15.96 $(1.90) (12%)
Natural Gas (MCF) 4,679,000 4,506,000 173,000 4% $ 1.57 $ 1.33 $ 0.24 18%
</TABLE>
In fiscal 1995, oil and natural gas revenues decreased $3,430,000 (25%), as
compared to fiscal 1994. A $1,586,000 decontracting payment, received from
Alberta and Southern Gas Co., Ltd. in November 1993, was included in oil and
natural gas revenues for fiscal 1994. There was no such payment received in
fiscal 1995. This decontracting payment was the result of the termination of
the Company's Dunvegan natural gas purchase, sales and transportation agreements
with Alberta and Southern Gas Co., Ltd., effective November 1, 1993.
The remaining $1,844,000 decrease was due to a 34% decrease in natural gas
prices, partially offset by a 5% increase in natural gas production, 13% and 12%
increases in oil production and prices, respectively. Additionally, the
Province of Alberta changed their royalty tax credit program effective January
1, 1995 reducing the amount of the credit that Barnwell received. The royalty
tax credit program changes resulted in a reduction in net earnings in fiscal
1995, as compared to fiscal 1994, of $230,000. The Company estimates that these
changes, which were effective with the beginning of Barnwell's second quarter of
fiscal 1995, will result in an approximate reduction of $80,000 in net earnings
in fiscal 1996 as compared to fiscal 1995.
Marketing arrangements for the majority of the Company's natural gas
production are handled on an individual contract basis with many agreements
renegotiated annually. The Dunvegan natural gas production is sold to
aggregators under various short and long-term contracts. A minimal amount of
all production is sold on the spot market receiving the current market price.
Oil and natural gas operating expenses increased $185,000 (6%) in fiscal
1995, as compared to fiscal 1994, due to new production at the Pembina, Lacombe
and Barrhead areas and due to increased repairs and maintenance in the older
areas of the Dunvegan, Provost and Red Earth properties. The Company expects
oil and natural gas operating expenses to continue to increase at a rate higher
than inflation due to higher costs of acquiring and developing new properties
and higher costs associated with certain of the Company's older properties.
In fiscal 1994, oil and natural gas revenues increased $2,700,000 (24%) as
compared to fiscal 1993, due to 18% higher natural gas prices, partially offset
by a 12% decrease in oil prices and a 24% decrease in liquids prices. In fiscal
1994, natural gas production increased 4% and oil production decreased 1% as
compared to fiscal 1993. Additionally, the natural gas sales contracts
involving the sale of the Company's Dunvegan natural gas were terminated
effective November 1, 1993. As a result of these contract terminations, the
Company received a compensatory payment of $1,586,000, which was recognized as
income in fiscal 1994.
Oil and natural gas operating expenses increased $365,000 (13%) for fiscal
1994, as compared to fiscal 1993, due to new production at the Hillsdown and
Thornbury areas.
In fiscal 1993, oil and natural gas revenues increased $1,020,000 (10%), as
compared to fiscal 1992, due to higher natural gas production which increased by
593,000 MCF (15%) and higher natural gas prices which increased 7%. Oil and
liquids production and price changes essentially offset themselves. The
increase in natural gas production was due to higher production from the
Company's principal producing property and higher production from the Company's
newer developed areas.
Oil and natural gas operating expenses increased $208,000 (8%) for fiscal
1993 as compared to fiscal 1992, primarily due to an increase in new production
from properties brought on-line in 1993 and late 1992. Increases in costs of
maintaining existing oil production accounted for $30,000 of the increase.
Contract Drilling
- -----------------
Contract drilling revenues and operating costs are associated with water
well drilling and water pump installation in Hawaii. Increases or decreases in
these revenues and costs are partially dependent on fluctuations in land
development activity in Hawaii.
Contract drilling revenues and operating costs decreased $1,320,000 (26%)
and $1,251,000 (30%), respectively, in fiscal 1995 as compared to fiscal 1994,
due to decreased pump installation activity partially offset by higher water
well drilling activity. Combined operating profit before depreciation decreased
$69,000 (7%) in fiscal 1995, as compared to fiscal 1994, due to less cost
efficiencies in fiscal 1995 brought on by the lower overall work performed by
the contract drilling segment.
Contract drilling revenues and operating costs increased $520,000 (11%) and
$1,035,000 (33%), respectively, in fiscal 1994 as compared to fiscal 1993, due
to higher pump installation activity partially offset by lower water well
drilling activity. Pump installation revenues and operating costs increased
$3,010,000 (702%) and $2,311,000 (739%), respectively, in fiscal 1994, whereas
water well drilling revenues and operating costs decreased $2,446,000 (60%) and
$1,205,000 (53%), respectively, in fiscal 1994, as compared to fiscal 1993.
Combined operating profit before depreciation decreased $515,000 (35%) in fiscal
1994 primarily due to the fact that the gross margins on the pump installation
contracts are lower than the gross margins for well drilling contracts.
Additionally, water well drilling operations were at full capacity during part
of fiscal 1993, enabling operations to be completed more efficiently.
Contract drilling revenues and operating costs decreased $780,000 (15%) and
$786,000 (20%), respectively, in fiscal 1993, as compared to fiscal 1992, due to
a decrease in pump installation work performed by the Company. Operating profit
before depreciation increased $6,000 due to a $333,000 increase in water well
drilling margin resulting from the simultaneous operation of four drilling rigs
for a period of time in fiscal 1993, as compared to three rigs in the first half
of fiscal 1992. This increase was offset by a $327,000 decrease in pump
installation gross margin due to significantly less pump installation work.
The Company expects fiscal 1996 contract drilling activity to be fairly
consistent with or slightly lower than that of fiscal 1995. Demand for water
well drilling continues to be lower than in previous years due to the continuing
reduced rate of land development in the State of Hawaii. However, land
development continues throughout the State of Hawaii and the Company believes
that its water well drilling activity in fiscal 1996 will be stable.
At December 1, 1995, WRI had a backlog of four water well contracts, two of
which were in progress as of September 30, 1995, and nine pump installation
contracts, seven of which were in progress as of September 30, 1995. These
thirteen contracts represent a backlog of contract drilling revenues of
approximately $2,700,000 as of September 30, 1995.
Investment in Land
- ------------------
In fiscal 1995, 1994 and 1993, Kaupulehu Developments entered into no land
transactions.
In April 1995, the option under which Kaupulehu Makai Venture could have
acquired Kaupulehu Developments' leasehold interest in approximately 2,180
leasehold acres of conservation zoned property in North Kona, Hawaii expired,
unexercised. Costs applicable to the rezoning of the approximately 1,000 acres
of the 2,180 acres of conservation zoned property incurred subsequent to April
1995 are being capitalized. Such costs, inclusive of capitalized interest,
amounted to $293,000 at September 30, 1995.
For the past three years Hawaii's economy has been in a recession. While
the current outlook is for moderate economic growth of 1% to 2%, the real estate
market is not expected to experience a measurable improvement in the near term.
Discontinued Food Products Operations
- -------------------------------------
There was no impact of discontinued operations on fiscal years 1995 and
1994. In May 1994, the Company transferred its 25% limited partnership
interests in Pacific Tropical Products ("PTP") and Orchard Development
("Orchard"), which had a carrying value of nil, to Mr. Anderson, a director and
shareholder of the Company. For further discussion see Note 14 (Discontinued
Operations) of "Notes to Consolidated Financial Statements". Accordingly,
operating results related to the food products segment have been reclassified
and included in the statement of operations as discontinued operations for the
year ended September 30, 1993. The earnings from discontinued food products
operations of $296,000 for fiscal 1993 represents the $617,000 gain on the
transfer of ownership of the Company's general partnership interest in PTP and
Orchard less the Company's share of the fiscal 1993 losses of PTP and Orchard,
net of income taxes.
Interest Income and Other
- -------------------------
Interest income and other income decreased $300,000 (31%) in fiscal 1995,
as compared to fiscal 1994, due to lower average interest-bearing cash balances
and reduced dividend income as a result of the sale of investments in preferred
stocks.
Interest income and other income increased $60,000 (7%) in fiscal 1994, as
compared to fiscal 1993, due to increased dividend income as a result of the
Company's investments in preferred stocks.
Interest income and other income increased $260,000 in fiscal 1993, as
compared to fiscal 1992, due to higher interest income on interest bearing
deposits due to the receipt of cash in September 1992 from the Kaupulehu
Developments land transaction.
General and Administrative Expenses
- -----------------------------------
General and administrative expenses decreased $412,000 (10%) in fiscal
1995, as compared to fiscal 1994, due to decreased personnel costs, decreases in
certain rezoning costs incurred by Kaupulehu Developments and non-recurring
costs related to the relocation of the corporate office in Honolulu, Hawaii.
General and administrative expenses increased $198,000 (5%) in fiscal 1994,
as compared to fiscal 1993, due to increases in salaries, pension costs and
costs related to the relocation of the corporate office in Honolulu, Hawaii.
General and administrative expenses decreased $693,000 (15%) in fiscal
1993, as compared to fiscal 1992. The decrease was due to the following items
which were included in fiscal 1992 results but not in fiscal 1993 results: (i)
a non-recurring provision for the plugging of a geothermal well and related
expenses of $200,000 and (ii) a $99,000 increase in the allowance for doubtful
accounts. The remaining decrease is attributable to a decline in property taxes
and legal costs of Kaupulehu Developments and to decreases in personnel costs.
Interest Expense
- ----------------
Interest expense increased $263,000 (53%) in fiscal 1995, due to higher
average interest rates on the Company's credit facility borrowings with the
Royal Bank of Canada and interest on the convertible notes issued in June 1995.
The average interest rate incurred during fiscal 1995 on the Company's
outstanding debt was 6.67%, an increase of 41% from fiscal 1994's average of
4.73%. The average interest rate paid during fiscal 1995 on the Company's debt
with the Royal Bank of Canada increased 37% from an average of 4.73% in fiscal
1994 to 6.47% in fiscal 1995. The interest rate on the convertible notes issued
in June 1995 was 10% per annum for the period June through September 1995.
Interest expense decreased $140,000 (22%) in fiscal 1994, due to a lower
average outstanding debt balance under the Company's credit facility with the
Royal Bank of Canada in fiscal 1994, as compared to fiscal 1993. The effect of
the lower outstanding debt was partially offset by higher interest rates; the
average interest rate paid during fiscal 1994 on the Company's debt with the
Royal Bank of Canada increased 20% from an average of 3.94% in fiscal 1993 to
4.73% in fiscal 1994.
Interest expense decreased $208,000 (25%) in fiscal 1993, as compared to
fiscal 1992, due to a significant reduction in debt during fiscal 1993
(outstanding long-term debt was reduced by $4,676,000 (31%) in fiscal 1993). In
addition, the average interest rate paid during fiscal 1993 on the Company's
debt with the Royal Bank of Canada decreased 24% from an average of 5.19% in
fiscal 1992 to an average of 3.94% in fiscal 1993.
Depreciation, Depletion and Amortization
- ----------------------------------------
Depreciation, depletion and amortization increased $206,000 (7%) in fiscal
1995, as compared to fiscal 1994, due to a $297,000 increase in depletion,
partially offset by a $91,000 decrease in depreciation. Depletion increased due
to a 5% increase in natural gas production and an increase in the depletion rate
of $.02 per MCF equivalent (5%). The depletion rate increased due to higher
finding costs in fiscal 1995. Depreciation decreased because certain well
drilling assets were fully depreciated in fiscal 1994.
Depreciation, depletion and amortization increased $270,000 (10%) in fiscal
1994, as compared to fiscal 1993, due to a $347,000 increase in depletion,
partially offset by a $62,000 decrease in depreciation. Depletion increased due
to a 4% increase in natural gas production and an increase in the depletion rate
of $.04 per MCF equivalent (12%). The Company's depletion rate increased as a
result of the Company's capital expenditures on natural gas plants and natural
gas gathering systems. Depreciation decreased because certain corporate and
well drilling assets were fully depreciated in fiscal 1993.
Depreciation, depletion and amortization increased $118,000 (5%) in fiscal
1993, as compared to fiscal 1992, primarily because of a $113,000 increase in
depletion. Depletion increased due to a 15% increase in natural gas production
partially offset by a decrease in the depletion rate of $.02 per
MCF equivalent (6%).
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. During fiscal 1995, the Company realized foreign currency transaction
losses of $176,000. Immaterial foreign currency transaction gains were realized
in fiscal 1994 and foreign currency transaction losses of $140,000 were realized
in fiscal 1993. The Company cannot accurately predict future fluctuations
between the Canadian and U.S. dollars.
Taxes
- -----
Effective October 1, 1992, the Company adopted Statement of Financial
Accounting Standards ("SFAS") 109, "Accounting for Income Taxes" which requires
a change from the deferred method of accounting for income taxes of APB Opinion
11 to the asset and liability method of accounting for income taxes. Under the
asset and liability method of SFAS 109, 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. Under SFAS 109,
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. The
cumulative effect of this change in accounting method (for years prior to fiscal
1993 which were not restated) increased net earnings by $800,000 in fiscal 1993.
In fiscal 1995, 1994 and 1993, the provision for income taxes does not bear
a normal relationship to earnings because Canadian taxes were payable on the
Canadian operations and losses from U.S. operations provide no foreign tax
benefits.
In November 1995, officials of the U.S. and Canada formally ratified a new
agreement amending the Canada-U.S. Tax Treaty reducing the Canadian Branch tax,
effective January 1, 1996, from 10% to 6% and effective January 1, 1997 to 5%.
This change will decrease current tax expenses in fiscal 1996 by approximately
$50,000 and decrease deferred tax expenses in fiscal 1996 by approximately
$300,000.
Environmental Matters
- ---------------------
The application of Federal, state, and Canadian regulations to protect the
environment, particularly in regard to the discharge of materials into the
environment, may increase the cost of operation for the Company's oil and
natural gas and contract drilling operations. The Company presently spends
certain amounts, from time to time, to comply with environmental regulations.
Although the Company is not aware of any specific problems, recent past may not
be indicative of the amounts of expenditures that the Company may be required to
expend for these purposes in subsequent years.
Inflation
- ---------
The effect of inflation on the Company has generally been to increase its
cost of operations, interest cost (as essentially all of the Company's debt is
at variable short-term rates of interest which tend to increase as inflation
increases), general and administrative costs and direct costs associated with
oil and natural gas production and contract drilling operations. In the case of
contract drilling, the Company has not been able to increase its
contract revenues to fully compensate for increased costs. In the case of oil
and natural gas, prices realized by the Company are essentially determined by
world prices for oil and western Canadian/California/Southwest U.S. natural gas
prices for natural gas.
New Statements of Financial Accounting Standards
- ------------------------------------------------
In March 1995, the Financial Accounting Standards Board issued SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets To Be
Disposed Of." SFAS 121 requires that long-lived assets to be held and used are
evaluated for impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be 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 to be recognized. Such impairment loss is measured as the amount by
which the carrying amount of the asset exceeds the fair value of the asset.
SFAS 121 also requires that long-lived assets to be disposed of be reported at
the lower of the asset carrying amount or fair value, less cost to sell.
Effective September 30, 1995, the Company adopted the provisions of SFAS
121. Adoption of the statement had no impact on financial condition or net
earnings.
In October 1995, the Financial Accounting Standards Board issued SFAS 123,
"Accounting for Stock-Based Compensation". SFAS 123 establishes a new, fair
value based method of measuring stock-based compensation, but does not require
an entity to adopt the new method for preparing its basic financial statements.
For entities not adopting the new method, SFAS 123 requires disclosure in the
footnotes of proforma net earnings and earnings per share information as if the
fair value based method had been adopted. Adoption of SFAS 123 is required for
no later than the Company's year ending September 30, 1997. The Company has not
yet determined if it will adopt the fair value based method of accounting for
stock-based compensation for purposes of preparing its basic financial
statements.
<PAGE>
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
-------------------------------------------
Independent Auditors' Report
----------------------------
The Board of Directors
Barnwell Industries, Inc.:
We have audited the consolidated financial statements of Barnwell Industries,
Inc. and subsidiaries as listed in the index at Part IV, Item 14. In
connection with our audits of the consolidated financial statements, we also
have audited the financial statement schedule as listed in the index at Part
IV, Item 14. These consolidated financial statements and financial statement
schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Barnwell
Industries, Inc. and subsidiaries as of September 30, 1995 and 1994, and the
results of their operations and their cash flows for each of the years in the
three-year period ended September 30, 1995, in conformity with generally
accepted accounting principles. Also in our opinion, the related financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly, in all material
respects, the information set forth therein.
As discussed in note 1 to the consolidated financial statements, Barnwell
Industries, Inc. changed its method of accounting for income taxes in the
fiscal year ended September 30, 1993.
KPMG PEAT MARWICK LLP
Honolulu, Hawaii
November 28, 1995
<PAGE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS September 30,
- ------ --------------------------
CURRENT ASSETS: 1995 1994
------------ -----------
Cash, interest bearing of $2,976,000 in 1995
and $4,182,000 in 1994 $ 2,976,000 $ 4,198,000
Trading securities (Note 3) - 948,000
Accounts receivable (Notes 2 and 11) 2,485,000 2,719,000
Royalty tax credit and taxes receivable 215,000 239,000
Costs and estimated earnings in excess of
billings on uncompleted contracts (Note 2) 113,000 198,000
Deferred income tax assets (Note 6) 120,000 200,000
Inventories and other current assets 215,000 191,000
----------- -----------
TOTAL CURRENT ASSETS 6,124,000 8,693,000
----------- -----------
INVESTMENT IN LAND (Notes 4 and 5) 648,000 -
----------- -----------
OTHER ASSETS (Notes 2 and 3) 1,011,000 903,000
----------- -----------
PROPERTY AND EQUIPMENT (Note 5):
Land 631,000 631,000
Oil and natural gas properties
(full cost accounting) 37,799,000 34,841,000
Drilling rigs and equipment 7,879,000 7,796,000
Other property and equipment 2,445,000 2,351,000
----------- -----------
48,754,000 45,619,000
Accumulated depreciation, depletion
and amortization 27,757,000 24,593,000
----------- -----------
TOTAL PROPERTY AND EQUIPMENT 20,997,000 21,026,000
----------- -----------
TOTAL ASSETS $28,780,000 $30,622,000
=========== ===========
<PAGE>
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable $ 1,065,000 $ 1,536,000
Accrued expenses 523,000 840,000
Billings in excess of costs and estimated
earnings on uncompleted contracts (Note 2) 436,000 251,000
Payable to joint interest owners 457,000 289,000
Income taxes payable (Note 6) - 856,000
----------- ------------
TOTAL CURRENT LIABILITIES 2,481,000 3,772,000
----------- -----------
LONG-TERM DEBT (Note 5) 11,100,000 10,600,000
----------- -----------
DEFERRED INCOME TAXES (Note 6) 4,837,000 6,468,000
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 7 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 12,891,000 12,439,000
Foreign currency translation adjustments (1,683,000) (1,891,000)
Unrealized holding (losses) gains
on securities (Notes 3 and 6) (65,000) 15,000
Treasury stock, at cost, 320,745 shares (4,705,000) (4,705,000)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY 10,362,000 9,782,000
----------- ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $28,780,000 $30,622,000
=========== ===========
See Notes to Consolidated Financial Statements
<PAGE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended September 30,
--------------------------------------
1995 1994 1993
----------- ----------- ----------
<S> <C> <C> <C>
Revenues:
Oil and natural gas (Note 13) $10,520,000 $13,950,000 $11,250,000
Contract drilling 3,770,000 5,090,000 4,570,000
Interest income and other 660,000 960,000 900,000
----------- ----------- -----------
14,950,000 20,000,000 16,720,000
----------- ----------- -----------
Costs and expenses:
Oil and natural gas operating 3,373,000 3,188,000 2,823,000
Contract drilling operating 2,890,000 4,141,000 3,106,000
General and administrative 3,596,000 4,008,000 3,810,000
Depreciation, depletion and amortization 3,103,000 2,897,000 2,627,000
Interest expense (Note 5) 756,000 493,000 633,000
Foreign exchange losses 176,000 - 140,000
Minority interest in losses (Note 4) (286,000) (250,000) (265,000)
----------- ----------- -----------
13,608,000 14,477,000 12,874,000
----------- ----------- -----------
Earnings from continuing operations before
income taxes and cumulative effect
of accounting change 1,342,000 5,523,000 3,846,000
Provision for income taxes (Note 6) 692,000 3,003,000 1,732,000
----------- ----------- -----------
Earnings from continuing operations before
cumulative effect of accounting change 650,000 2,520,000 2,114,000
Earnings from discontinued food
products subsidiary, net of income tax
effect (Note 14) - - 296,000
----------- ---------- -----------
Earnings before cumulative effect
of accounting change 650,000 2,520,000 2,410,000
Cumulative effect of accounting
change (Note 6) - - 800,000
----------- ----------- -----------
NET EARNINGS $ 650,000 $ 2,520,000 $ 3,210,000
=========== =========== ===========
NET EARNINGS PER SHARE:
Earnings from continuing operations before
cumulative effect of accounting change $0.49 $1.90 $1.59
Earnings from discontinued food
products subsidiary, net of income tax
effect - - 0.22
Cumulative effect of accounting change - - 0.61
----------- ----------- -----------
Net earnings $0.49 $1.90 $2.42
=========== =========== ===========
WEIGHTED AVERAGE
NUMBER OF SHARES OUTSTANDING 1,326,100 1,326,500 1,329,067
=========== =========== ===========
<FN>
See Notes to Consolidated Financial Statements
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended September 30,
----------------------------------------
1995 1994 1993
---------- ---------- ----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Earnings from continuing operations $ 650,000 $2,520,000 $2,114,000
Adjustments to reconcile earnings from
continuing operations to net cash
provided by operating activities:
Depreciation, depletion and amortization 3,103,000 2,897,000 2,627,000
Deferred income taxes (1,522,000) 564,000 470,000
Minority interest in losses (286,000) (250,000) (265,000)
Prepaid natural gas delivered and other - - (563,000)
---------- ---------- ----------
1,945,000 5,731,000 4,383,000
(Decrease) increase from changes in
current assets and liabilities (Note 15) (21,000) (1,395,000) 1,444,000
---------- ---------- ----------
Net cash provided by operating activities 1,924,000 4,336,000 5,827,000
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (3,930,000) (5,737,000) (3,266,000)
Increase in other assets (300,000) (84,000) (350,000)
Proceeds from sale of property
and equipment 613,000 254,000 -
Reduction of cash restricted for
repayment of long-term debt - - 883,000
---------- ---------- ----------
Net cash used in investing activities (3,617,000) (5,567,000) (2,733,000)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt borrowings (including
$1,900,000 from affiliates (Note 5)) 2,000,000 - -
Payment of dividends (198,000) (396,000) -
Repayment of long-term debt (1,500,000) - (4,676,000)
Purchases of common stock for treasury - - (236,000)
Proceeds from exercise of stock options - - 206,000
---------- ---------- ----------
Net cash provided by (used in) financing
activities 302,000 (396,000) (4,706,000)
---------- ---------- ----------
Effect of exchange rate changes on cash 169,000 (10,000) 293,000
---------- ---------- ----------
Net decrease in cash (1,222,000) (1,637,000) (1,319,000)
Cash at beginning of year 4,198,000 5,835,000 7,154,000
---------- ---------- ----------
Cash at end of year $2,976,000 $4,198,000 $5,835,000
========== ========== ==========
<FN>
See Notes to Consolidated Financial Statements
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Foreign Unrealized
Common Stock Additional Currency Holding
------------------------ Paid-In Retained Translation Gains/ Treasury
Shares Amount Capital Earnings Adjustments (Losses) Stock
----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Balances at September 30, 1992 1,642,797 $ 821,000 $ 3,111,000 $ 7,105,000 $(1,306,000) $ - $(4,683,000)
Net earnings - - - 3,210,000 - - -
Dividends declared ($.10 per share) - - - (132,000) - - -
Purchase of 16,500 common shares
for treasury - - - - - - (236,000)
Exercise of stock options, 20,500
shares - - (8,000) - - - 214,000
Foreign currency translation
adjustments - - - - (471,000) - -
----------- ----------- ----------- ----------- ----------- ----------- -----------
Balances at September 30, 1993 1,642,797 821,000 3,103,000 10,183,000 (1,777,000) - (4,705,000)
Net earnings - - - 2,520,000 - - -
Dividends declared ($.20 per share) - - - (264,000) - - -
Foreign currency translation
adjustments - - - - (114,000) - -
Unrealized holding gain on
securities - - - - - 15,000 -
----------- ----------- ----------- ----------- ----------- ----------- -----------
Balances at September 30, 1994 1,642,797 821,000 3,103,000 12,439,000 (1,891,000) 15,000 (4,705,000)
Net earnings - - - 650,000 - - -
Dividends declared ($.15 per share) - - - (198,000) - - -
Foreign currency translation
adjustments - - - - 208,000 - -
Unrealized holding loss on
securities - - - - - (80,000) -
----------- ----------- ----------- ----------- ----------- ----------- -----------
Balances at September 30, 1995 1,642,797 $ 821,000 $ 3,103,000 $12,891,000 $(1,683,000) $ (65,000) $(4,705,000)
=========== =========== =========== =========== =========== =========== ===========
<FN>
See Notes to Consolidated Financial Statements
</TABLE>
<PAGE>
BARNWELL INDUSTRIES, INC.
-------------------------
AND SUBSIDIARIES
----------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
YEARS ENDED SEPTEMBER 30, 1995, 1994, AND 1993
----------------------------------------------
1. SIGNIFICANT ACCOUNTING POLICIES
-------------------------------
Principles of consolidation
- ---------------------------
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.
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 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 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.
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 accounts for its investment in land at cost plus capitalized
interest on its investment. Land sales for real estate under option as of
September 30, 1995 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 land sold. The balance sheet
includes zero cost for lands under option and accordingly, all cash receipts in
excess of costs will be reported as revenues. The Company's cost and
capitalized interest for the land not under option is included in the balance
sheet under the caption "Investment in Land." Costs are capitalized until the
aggregate of such costs equals the land's estimated net realizable value.
Investments
- -----------
In May 1993, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") 115, "Accounting for Certain Investments
in Debt and Equity Securities." SFAS 115 requires that investments be
classified in three categories and accounted for as follows: (i) debt securities
which are purchased with the positive intent and ability to hold to maturity are
classified as held-to-maturity and are reported at amortized cost, (ii) debt and
equity securities which are bought and held principally for the purpose of
selling them in the near term are classified as trading securities and are
reported at fair value, with unrealized gains and losses included in earnings
and (iii) debt and equity securities which are not classified as either held-to-
maturity or trading securities are classified as available for sale and are
reported at fair value, with unrealized gains and losses, net of related tax
effect, excluded from earnings and reported as a separate component of
stockholders' equity. Effective September 30, 1994, the Company adopted the
provisions of SFAS 115.
A decline in the market value of any available-for-sale or held-to-maturity
security below cost that is deemed other than temporary is charged to earnings,
resulting in the establishment of a new cost basis for the security.
Cost in computing realized gains and losses is determined using the
specific identification method.
Drilling rigs and other equipment
- ---------------------------------
Drilling rigs and other equipment are stated at cost. Depreciation is
computed using the straight-line method based on estimated useful lives.
Inventories
- -----------
Inventories are comprised of drilling materials and are valued at the lower
of weighted average cost or net realizable value.
Income taxes
- ------------
Effective October 1, 1992, the Company adopted SFAS 109, "Accounting for
Income Taxes", and has reported the cumulative effect of that change in the
method of accounting for income taxes in the 1993 consolidated statement of
operations. Deferred income taxes are determined using the asset and liability
method. Deferred tax assets and liabilities are recognized for the estimated
future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates in effect for the year in which those temporary differences
are expected to be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the period that
includes the enactment date.
Earnings per share
- ------------------
Primary earnings per share are based on the weighted average number of
outstanding common shares during the year after consideration of the dilutive
effect of outstanding stock options and convertible securities. Fully diluted
earnings per share are not presented because dilution is less than 3%.
Foreign currency translation
- ----------------------------
Assets and liabilities of foreign operations and subsidiaries are
translated at the year-end exchange rate and resulting translation gains or
losses are accounted for in a stockholders' equity account entitled "foreign
currency translation adjustments". Operating results of foreign subsidiaries
are translated at average exchange rates during the period. Foreign currency
transaction gains and losses are reflected in the accompanying consolidated
statements of operations.
New Statements of Financial Accounting Standards
- ------------------------------------------------
In March 1995, the Financial Accounting Standards Board issued SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets To Be
Disposed Of." SFAS 121 requires that long-lived assets to be held and used are
evaluated for impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be 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 to be recognized. Such impairment loss is measured as the amount by
which the carrying amount of the asset exceeds the fair value of the asset.
SFAS 121 also requires that long-lived assets to be disposed of be reported at
the lower of the asset carrying amount or fair value, less cost to sell.
Effective September 30, 1995, the Company adopted the provisions of SFAS
121. Adoption of the statement had no impact on financial condition or net
earnings.
In October 1995, the Financial Accounting Standards Board issued
SFAS 123 "Accounting for Stock-Based Compensation". SFAS 123 establishes a
new, fair value based method of measuring stock-based compensation, but does
not require an entity to adopt the new method for purposes of preparing its
basic financial statements. For entities not adopting the new method, SFAS 123
requires disclosure in the footnotes of proforma net earnings and earnings per
share information as if the fair value based method had been adopted. Adoption
of SFAS 123 is required for no later than the Company's year ending September
30, 1997. The Company has not yet determined if it will adopt the fair value
based method of accounting for stock-based compensation for purposes of
preparing its basic financial statements.
2. RECEIVABLES AND CONTRACT COSTS
------------------------------
Accounts receivable, current, are net of allowances for doubtful accounts
of $64,000 and $26,000 as of September 30, 1995 and 1994, respectively.
Included in accounts receivable are contract retainage balances of $546,000 and
$315,000 as of September 30, 1995 and 1994, respectively. These balances are
expected to be collected within one year, specifically within 45 days after the
related contracts have received final acceptance and approval.
Included in other assets are long-term notes and other receivables of
$642,000 and $341,000, net of an allowance for doubtful accounts of $267,000, as
of September 30, 1995 and 1994, respectively.
Costs and estimated earnings on uncompleted contracts are as follows:
September 30,
-----------------------
1995 1994
---- ----
Costs incurred on uncompleted contracts $3,950,000 $4,687,000
Estimated earnings 1,723,000 1,600,000
---------- ----------
5,673,000 6,287,000
Less billings to date 5,996,000 6,340,000
---------- ---------
$ (323,000) $ (53,000)
========== ==========
Costs and estimated earnings on uncompleted contracts are included in the
consolidated balance sheets under the following captions:
September 30,
---------------------
1995 1994
---- ----
Costs and estimated earnings in excess
of billings on uncompleted contracts $ 113,000 $ 198,000
Billings in excess of costs and
estimated earnings on uncompleted contracts (436,000) (251,000)
--------- ---------
$(323,000) $( 53,000)
========= =========
3. INVESTMENTS
-----------
Included in other assets are available-for-sale equity securities. The
following summarizes the aggregate market value, cost, gross unrealized holding
gains and losses and income tax effect of available-for-sale securities:
September 30,
------------------
1995 1994
---- ----
Market value $163,000 $285,000
Cost 261,000 261,000
-------- --------
Gross unrealized holding
(losses) gains before income tax effect (98,000) 24,000
Income tax effect 33,000 (9,000)
-------- --------
Gross unrealized holding (losses) gains, net of
income tax effect, included in stockholders' equity $(65,000) $ 15,000
======== ========
Realized losses on trading securities amounted to $68,000 in fiscal 1995,
$58,000 of which was recognized as unrealized holding losses in fiscal 1994.
4. INVESTMENT IN LAND
------------------
In May 1984, the Company, through a wholly-owned subsidiary, acquired a
50.1% interest in approximately 10,800 acres of leasehold property at Kaupulehu,
North Kona, on the Kona coast of the Island of Hawaii. The Company's interest
and the remaining leasehold interest in the property were contributed to a joint
venture, Kaupulehu Developments, in which the Company has a 50.1% controlling
interest. Kaupulehu Developments subsequently obtained the rezoning of
approximately 620 acres of such leasehold property to urban for both state and
county purposes to allow for two hotel sites, two golf courses, several
residential sites interspersed around and within the planned golf courses and
one commercial site. Kaupulehu Developments granted options to independent
third parties to acquire the leasehold interest for the development of the
hotel, commercial, golf course and residential sites, comprising the
approximately 620 acre property, the approximately 2,180 acres zoned
conservation adjoining the approximately 620 acre urban area and the
approximately 8,000 acre upland portion.
In fiscal 1989 and 1990, options were exercised with respect to hotel and
golf course sites, the commercial site and the approximately 8,000 acre upland
portion.
In fiscal 1991, Kaupulehu Developments entered into no land transactions.
In fiscal 1992, Kaupulehu Developments entered into definitive agreements
with Kaupulehu Makai Venture. Kaupulehu Makai Venture succeeded to all
development rights and obligations previously held by other independent third
parties. The managing general partner of Kaupulehu Makai Venture is an
affiliated company of Kajima Corporation of Japan. There is no affiliation
between Kaupulehu Makai Venture or its predecessors and the Company. Kaupulehu
Developments received cash consideration in partial payment for the residential
sites in fiscal 1992. This transaction resulted in a pre-tax gain, net of
minority interests, of $2,410,000.
In fiscal 1994, Kaupulehu Developments submitted a petition to the State
Land Use Commission to reclassify approximately 1,000 acres of the approximate
2,180 acres zoned conservation. Kaupulehu Developments seeks to have the 1,000
acres rezoned to permit the development of golf courses and residential sites.
In December 1994, the State Land Use Commission began the public hearing process
of the rezoning petition; this process is currently ongoing.
In fiscal 1995, 1994 and 1993, Kaupulehu Developments entered into no land
transactions.
In April 1995, the option under which Kaupulehu Makai Venture could have
acquired Kaupulehu Developments' leasehold interest in approximately 2,180
leasehold acres of conservation zoned property in North Kona, Hawaii expired,
unexercised. Costs, inclusive of capitalized interest, applicable to the
rezoning of the approximately 1,000 acres of the aforementioned 2,180 acres of
conservation zoned property incurred subsequent to April 1995 are capitalized.
Kaupulehu Makai Venture has completed a significant amount of the
construction of the first golf course, hotel and condominiums and related
infrastructure in the 620 acre urban area. The golf course is virtually
complete and is expected to open in early 1996. The hotel is expected to open
in late 1996.
At September 30, 1995, the real estate position (i.e. leasehold interests
and related development rights) held by Kaupulehu Developments consists of the
approximately 2,180 leasehold acres zoned conservation and development rights
with respect to lands zoned residential in the adjacent 620 acre urban area.
The residential lands are under option to Kaupulehu Makai Venture. This option,
if exercised, entitles the Company to receive $16,157,000 in connection with its
50.1% interest in Kaupulehu Developments. The residential site option expires
on April 30, 2007; however, this option will expire sooner unless 20% of the
consideration is received on or before December 31, 1999 and 50% of the then
remaining consideration is received on or before April 30, 2003. There is no
assurance that this option or any portion of it will be exercised.
5. LONG-TERM DEBT
--------------
The Company has a credit facility at the Royal Bank of Canada, a Canadian
bank, for Canadian (referred to herein as "C") $16,000,000 or its U.S. dollar
equivalent of approximately $11,900,000 at September 30, 1995. Borrowings under
this facility were $9,100,000 and $10,600,000 at September 30, 1995 and
September 30, 1994, respectively, and are included in long-term debt.
The facility is available in U.S. dollars at the London Interbank Offer
Rate ("LIBOR") plus 3/4%, at U.S. prime plus 1/2%, or in Canadian dollars at
Canadian prime plus 1/2%. Under the financing agreement, the facility is
reviewed annually, with the next review planned for February 1996. Subject to
that review, the facility may be extended one year with no required debt
repayments for one year or converted to a 6-year term loan by the bank. If the
facility is converted to a 6-year term loan, the Company has agreed to the
following repayment schedule of the then outstanding loan balance: year 1-26%;
year 2-24%; year 3-17%; year 4-15%; year 5-12% and year 6-6%.
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, 1995, the Company paid interest at rates
ranging from 4.563% to 6.875%. At September 30, 1995, the rate was 6.625%. 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 based primarily on the future
cash flows related to the Company's oil and natural gas properties. No
compensating bank balances are required on any of the Company's indebtedness.
At September 30, 1995, the Company had unused credit available under this
facility of approximately $2,800,000.
In June 1995, the Company issued $2,000,000 of convertible notes due
July 1, 2003. $400,000 of such notes were purchased by Mr. Kinzler, President,
Chief Executive Officer and Chairman of the Board of Directors of the Company,
$200,000 were purchased by Mr. Anderson, a director, $200,000 were purchased by
Dr. Magaro, a 15.9% shareholder of the Company, $100,000 were purchased by
Dr. Sudarsky, a 9.2% shareholder of the Company, and $1,000,000 were purchased
by Ingalls and Snyder Value Partners, L.P., a 7.5% shareholder of the Company.
The notes are payable in 20 consecutive equal quarterly installments beginning
in October 1998. Interest is payable quarterly at an initial rate of 10% per
annum until October 1, 1995, after which the interest rate will be adjusted
quarterly to the greater of 10% per annum or 1% over the prime rate of interest.
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 after July 1, 1997, at premiums declining 1% annually from
5% to 0% of the principal amount of the notes. These notes, amounting to
$2,000,000 at September 30, 1995, are included in long-term debt.
At September 30, 1995, the maturities of long-term debt, exclusive of the
credit facility with the Canadian bank, are as follows:
1996 $ -
1997 -
1998 -
1999 400,000
2000 400,000
Thereafter 1,200,000
----------
$2,000,000
==========
The Company capitalized interest related to its investment in land for the
year ended September 30, 1995. Interest expense for the year ended
September 30, 1995 is as follows:
Interest incurred $ 769,000
Less interest capitalized on
investment in land 13,000
---------
Interest expense $ 756,000
=========
6. TAXES ON INCOME
---------------
The components of earnings/(loss) from continuing operations before income
taxes and cumulative effect of accounting change are as follows:
Year ended September 30,
-----------------------------------------
1995 1994 1993
----------- ----------- -----------
United States $(1,444,000) $(1,446,000) $ (980,000)
Canadian 2,786,000 6,969,000 4,826,000
----------- ----------- ----------
$ 1,342,000 $ 5,523,000 $3,846,000
=========== =========== ==========
The components of the provision for income taxes related to the above
earnings/(loss) are as follows:
Year ended September 30,
------------------------------------
1995 1994 1993
---------- ---------- ----------
Current:
United States - Federal $1,069,000 $ 170,000 $ 6,000
United States - State and local 241,000 - -
---------- ---------- ----------
United States - total 1,310,000 170,000 6,000
Canadian 904,000 2,269,000 1,256,000
---------- ---------- ----------
Total current 2,214,000 2,439,000 1,262,000
---------- ---------- ----------
Deferred:
United States (1,420,000) (60,000) (234,000)
Canadian (102,000) 624,000 704,000
---------- ---------- ----------
Total deferred (1,522,000) 564,000 470,000
---------- ---------- ----------
$ 692,000 $3,003,000 $1,732,000
========== ========== ==========
For fiscal 1995, $33,000 of deferred income tax benefit related to the
unrealized holding loss on available for sale securities is reflected as a
credit to stockholders' equity. For fiscal 1994, $9,000 of deferred income tax
expense related to the unrealized holding gain on available for sale securities
is reflected as a charge to stockholders' equity.
As discussed in Note 1, the Company adopted SFAS 109 effective
October 1, 1992. The cumulative effect of the change in accounting method (for
years prior to fiscal 1993, which were not restated) increased net earnings by
$800,000 in fiscal 1993.
A reconciliation between the reported provision for income taxes and the
amount computed by multiplying the earnings from continuing operations before
income taxes and cumulative effect of accounting change by the United States
federal tax rate is as follows:
Year ended September 30,
------------------------------------
1995 1994 1993
---------- ---------- ----------
Tax computed by applying statutory rate $ 470,000 $1,933,000 $1,336,000
Effect of foreign tax
provision on the total tax provision 206,000 960,000 428,000
Other 16,000 110,000 (32,000)
---------- ---------- ----------
$ 692,000 $3,003,000 $1,732,000
========== ========== ==========
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at
September 30, 1995 and 1994 are as follows:
Deferred income tax assets: 1995 1994
------------ ------------
Tax basis in land in excess of book basis $ 1,106,000 $ 1,018,000
Write-off of asset not deducted for tax 148,000 148,000
U.S. tax effect of deferred Canadian taxes 2,049,000 2,042,000
Foreign tax credit carryforward 319,000 336,000
Other 520,000 433,000
---------- -----------
Total gross deferred tax assets 4,142,000 3,977,000
Less-valuation allowance (2,368,000) (2,378,000)
---------- -----------
Net deferred tax assets 1,774,000 1,599,000
---------- -----------
Deferred tax liabilities:
Option proceeds received on investment
in land (25,000) (1,643,000)
Property and equipment tax depreciation
and depletion in excess of book (6,028,000) (6,005,000)
Other (438,000) (219,000)
----------- -----------
Total deferred tax liabilities (6,491,000) (7,867,000)
----------- -----------
Net deferred income tax liability $(4,717,000) $(6,268,000)
=========== ===========
The net change in the total valuation allowance for the years ended
September 30, 1995 and 1994 was a $10,000 decrease and $537,000 increase,
respectively. The increase for fiscal 1994 was due to $201,000 of additional
Canadian deferred income taxes and $336,000 of foreign tax credit carryforwards
for which the Company did not provide a U.S. tax benefit.
A valuation allowance is provided when it is more likely than not that some
portion of the deferred tax asset will not be realized. The Company has
established a valuation allowance for the Canadian tax deductions and foreign
tax credits 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 for U.S. tax purposes. Net deferred tax assets will primarily be
realized through the deduction of the cost basis in investment in land against
proceeds from investment in land for tax purposes. Under the cost recovery
accounting method, this cost basis has already been expensed for book purposes.
7. PENSION PLAN
------------
The Company has 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
consist primarily of listed government mortgages.
The funded status of the pension plan and the amounts recognized in the
consolidated financial statements is as follows:
Year ended September 30,
---------------------------
1995 1994
------------ ------------
Accumulated benefit obligation, including
vested benefits of $1,482,000 and
$1,363,000, respectively $ 1,530,000 $ 1,416,000
=========== ===========
Projected benefit obligation for service
rendered to date $(1,925,000) $(1,790,000)
Plan assets at fair market value 1,815,000 1,669,000
----------- -----------
Plan assets less than
projected benefit obligation (110,000) (121,000)
Unrecognized net gain from past
experience different from that assumed
and effects of changes in assumptions (7,000) (21,000)
Unrecognized prior service cost 57,000 120,000
Unrecognized net asset at
October 1, 1988 being recognized over
12.3 years (5,000) (6,000)
----------- -----------
Accrued pension cost $ (65,000) $ (28,000)
=========== ===========
As of September 30, 1995 and 1994, the discount rate assumed in determining
the actuarial present value of the projected benefit obligation was 7.5% and
8.0%, respectively.
Net pension cost includes the following components:
Year ended September 30,
--------------------------------
1995 1994 1993
---------- ---------- --------
Service cost, benefits earned during the year $ 38,000 $138,000 $115,000
Interest cost on projected benefit obligation 126,000 135,000 127,000
Actual return on plan assets, (gain) loss (217,000) 8,000 (104,000)
Net amortization and deferral 90,000 (122,000) (19,000)
-------- -------- --------
Net pension cost $ 37,000 $159,000 $119,000
======== ======== ========
Year ended September 30,
---------------------------
1995 1994 1993
---- ---- ----
Assumed rate of increase in future
compensation levels 6.0% 6.0% 7.0%
==== ==== ====
Expected long-term rate of return on assets 8.0% 9.0% 9.0%
==== ==== ====
8. COMMON STOCK
------------
In March, 1995, the Company granted 20,000 non-qualified stock options to
an officer of the Company at a purchase price of $19.625 per share (market
price on date of grant), with 4,000 of such options vesting annually commencing
one year from the date of grant. These options have stock appreciation rights
which permit the holder to receive stock, cash or a combination thereof equal
to the amount by which the fair market value, at the time of exercise of the
option, exceeds the option price. The options expire ten years from the date of
grant.
In fiscal 1995 and 1994, the Company did not repurchase any shares of its
common stock. In fiscal 1993, the Company repurchased 16,500 shares of its
common stock from officers of the Company for $236,000, an average of $14.30 per
share (market price on date of purchase). These purchases were made under a
March 1991 authorization by the Company's Board of Directors. As of July 1992,
repurchases on the open market were suspended; privately negotiated repurchases
will continue to be made if suitable opportunities become available. At
September 30, 1995, the Company could purchase an additional 19,800 shares under
the March 1991 authorization.
The Company had a stock option plan ("Option Plan") which became effective
November 1981 and expired November 1991. Under the Option Plan, options to
purchase a maximum of 120,000 shares of the Company's common stock could be
granted to officers and key employees of the Company and its subsidiaries at
prices not less than 100% of the fair market value at the date of the option
grant. Options granted under this plan became exercisable 25% annually
beginning one year from the date of grant and expire five or ten years from the
date of grant.
Option transactions during fiscal 1995, 1994 and 1993 are as follows:
Options
------------------------
Outstanding Exercisable
----------- -----------
Balance at September 30, 1992 66,000 52,125
Became exercisable - 13,875
Exercised ($6.25 to $13.625 per share) (20,500) (20,500)
Canceled (1,500) (1,500)
------- ---------
Balance at September 30, 1993 44,000 44,000
Canceled (20,000) (20,000)
------- ---------
Balance at September 30, 1994 24,000 24,000
Issued ($19.625 per share) 20,000 -
------- ---------
Balance at September 30, 1995 44,000 24,000
======= =========
Exercisable options at September 30, 1995 are as follows:
Per share price Number of options
--------------- -----------------
$13.625 14,000
$22.250 10,000
------
Total 24,000
======
9. COMMITMENTS AND CONTINGENCIES
-----------------------------
The Company is contingently liable for the repayment of loans under a
$750,000 loan facility to three participants in one of the Company's oil and
natural gas ventures. At September 30, 1995, the loan balance was $395,000,
$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 balance.
The Company has several operating leases for office space. Rental expense
was $392,000 in 1995, $386,000 in 1994 and $299,000 in 1993. The Company is
committed under several non-cancelable operating leases for office and other
space with minimum rental payments summarized by fiscal year period as follows:
1996 - $360,000, 1997 - $339,000, 1998 - $349,000, 1999 - $361,000, 2000 -
$362,000 and thereafter an aggregate of $1,888,000.
The Company has committed to construct $200,000 of improvements at its yard
at Sand Island on Oahu, Hawaii, by June 1997.
10. SEGMENT AND GEOGRAPHIC INFORMATION
----------------------------------
The Company operates in three industries: oil and natural gas exploration,
development and production, contract drilling and land investment.
<TABLE>
<CAPTION>
Segment information is as follows:
Depreciation,
YEAR ENDED depletion and Operating Capital
SEPTEMBER 30, 1995 Revenues amortization Profit/(loss) expenditures
- ------------------ ---------- ------------- ------------- ------------
<S> <C> <C> <C> <C>
Oil and natural gas $10,520,000 $ 2,658,000 $ 4,489,000 $ 3,434,000
Contract drilling 3,770,000 317,000 563,000 83,000
Land investment - - - 293,000
Corporate and other 420,000 128,000 292,000 120,000
----------- ------------- ------------ ------------
Total $14,710,000 $ 3,103,000 5,344,000 $ 3,930,000
=========== ============= =============
General and administrative expenses (3,596,000)
Interest expense (net of interest
income of $240,000) (516,000)
Minority interest in losses 286,000
Foreign exchange losses (176,000)
-------------
Earnings before income taxes $ 1,342,000
============
Depreciation,
YEAR ENDED depletion and Operating Capital
SEPTEMBER 30, 1994 Revenues amortization Profit/(loss) expenditures
- ------------------ ---------- ------------- ------------- ------------
Oil and natural gas $13,950,000 $ 2,361,000 $ 8,401,000 $ 5,350,000
Contract drilling 5,090,000 441,000 508,000 94,000
Land investment - - - -
Corporate and other 760,000 95,000 665,000 293,000
----------- ------------- ------------ ------------
Total $19,800,000 $ 2,897,000 9,574,000 $ 5,737,000
=========== ============= ============
General and administrative expenses (4,008,000)
Interest expense (net of interest
income of $200,000) (293,000)
Minority interest in losses 250,000
------------
Earnings before income taxes $ 5,523,000
============
Depreciation,
YEAR ENDED depletion and Operating Capital
SEPTEMBER 30, 1993 Revenues amortization Profit/(loss) expenditures
- ------------------ ---------- ------------- ------------- ------------
Oil and natural gas $11,250,000 $ 2,014,000 $ 6,413,000 $ 3,193,000
Contract drilling 4,570,000 463,000 1,001,000 49,000
Land investment - - - -
Corporate and other 400,000 150,000 250,000 24,000
----------- ------------- ------------ ------------
Total $16,220,000 $ 2,627,000 7,664,000 $ 3,266,000
=========== ============= ============
General and administrative expenses (3,810,000)
Interest expense (net of interest
income of $500,000) (133,000)
Minority interest in losses 265,000
Foreign exchange losses (140,000)
-----------
Earnings from continuing operations
before income taxes and cumulative
effect of accounting change $ 3,846,000
============
</TABLE>
September 30,
----------------------------------------------------
ASSETS BY SEGMENT: 1995 1994 1993
- ------------------ ----------------- ----------------- ----------------
Oil and gas (1) $20,918,000 73% $21,555,000 70% $18,625,000 66%
Contract drilling (2) 2,461,000 9% 2,881,000 9% 2,851,000 10%
Land investment (2) 648,000 2% - - - -
Other:
Cash 2,976,000 10% 4,198,000 14% 5,835,000 21%
Corporate and other 1,777,000 6% 1,988,000 7% 770,000 3%
----------- ---- ----------- ---- ---------- ----
Total $28,780,000 100% $30,622,000 100% $28,081,000 100%
=========== ==== =========== ==== =========== ====
(1) Primarily located in the Province of Alberta, Canada.
(2) Located in Hawaii.
Geographic information is as follows:
September 30,
----------------------------------------------------
ASSETS BY GEOGRAPHIC AREA: 1995 1994 1993
- -------------------------- ----------------- ----------------- -----------------
United States $ 6,308,000 22% $ 6,380,000 21% $ 9,121,000 32%
Canada 22,472,000 78% 24,242,000 79% 18,960,000 68%
----------- ---- ----------- ---- ----------- ----
Total $28,780,000 100% $30,622,000 100% $28,081,000 100%
=========== ==== =========== ==== =========== ====
CAPITAL EXPENDITURES BY September 30,
- ----------------------- -----------------------------------------------------
GEOGRAPHIC AREA: 1995 1994 1993
- ---------------- ----------------- ----------------- ---------------
United States $ 780,000 20% $ 462,000 8% $ 73,000 2%
Canada 3,150,000 80% 5,275,000 92% 3,193,000 98%
----------- ---- ----------- ---- ----------- ----
Total $ 3,930,000 100% $ 5,737,000 100% $ 3,266,000 100%
=========== ==== =========== ==== =========== ====
OPERATIONS BY GEOGRAPHIC AREA: Depreciation,
- ------------------------------ depletion and Operating
Revenue amortization Profit
---------- ------------ ----------
YEAR ENDED
SEPTEMBER 30, 1995
- ------------------
United States $ 3,965,000 $ 448,000 $ 613,000
Canada 10,745,000 2,655,000 4,731,000
---------- ------------ ----------
Total $14,710,000 $ 3,103,000 $5,344,000
=========== ============ ==========
YEAR ENDED
SEPTEMBER 30, 1994
- ------------------
United States $ 5,528,000 $ 489,000 $ 898,000
Canada 14,272,000 2,408,000 8,676,000
----------- ------------ ----------
Total $19,800,000 $ 2,897,000 $9,574,000
=========== ============ ==========
YEAR ENDED
SEPTEMBER 30, 1993
- ------------------
United States $ 4,770,000 $ 550,000 $1,110,000
Canada 11,450,000 2,077,000 6,554,000
---------- ------------ ----------
Total $16,220,000 $ 2,627,000 $7,664,000
=========== ============ ==========
Depletion per 1,000 cubic feet of natural gas (MCF) and natural gas
equivalent was $0.40 in fiscal 1995, $0.38 in fiscal 1994 and $0.34 in fiscal
1993. The increase in the per unit rate from fiscal 1994 to 1995 was due to
higher finding costs in fiscal 1995 as compared to the prior years. The
increase in the per unit rate from fiscal 1993 to 1994 was due to increased
expenditures on natural gas plants and natural gas gathering facilities.
In fiscal 1995, the Company had one significant customer, ProGas, Limited,
which accounted for 15% of the Company's oil and natural gas sales. In fiscal
1994, the Company had one significant customer, Pacific Gas & Electric, which
accounted for 10% of the Company's oil and natural gas sales, exclusive of the
$1,586,000 decontracting payment. A contract with a Canadian company, Alberta
and Southern Gas Co., Ltd., a wholly-owned subsidiary of Pacific Gas & Electric,
a Northern California electric utility, for the sale of natural gas accounted
for approximately 22% of the Company's total oil and natural gas sales in fiscal
1993.
The Company's contract drilling subsidiary derived 28%, 40% and 78% of its
contract drilling revenues in fiscal 1995, 1994 and 1993, respectively, pursuant
to State of Hawaii and local county contracts.
11. CONCENTRATIONS OF CREDIT RISK
-----------------------------
For the fiscal year ended September 30, 1995, 28% of the contract drilling
revenues were derived from the State of Hawaii and local county entities.
Accounts receivable from the State of Hawaii and local county entities totaled
approximately $212,000 at September 30, 1995. The Company has lien rights on
contracts with the State of Hawaii and local county entities. For the year
ended September 30, 1995, there was one significant customer for the oil and
natural gas segment. The Company had a receivable balance at September 1995
from this customer of approximately $110,000. Historically, the Company has not
incurred any significant credit related losses on its trade receivables, and
management does not believe significant credit risk related to these trade
receivables exists at September 30, 1995.
12. SUMMARY OF QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
------------------------------------------------------
The following is a summary of unaudited quarterly results of operations for
the years ended September 30, 1995 and 1994:
Year ended September 30, 1995: Quarter ended
- ----------------------------- -------------------------------------------------
December 31 March 31 June 30 September 30
----------- ---------- --------- ------------
Revenues $4,390,000 $3,730,000 $3,290,000 $3,540,000
=========== ========== ========== ==========
Operating income $1,708,000 $1,252,000 $1,226,000 $1,158,000
=========== ========== ========== ==========
Net earnings $ 200,000 $ 140,000 $ 140,000 $ 170,000
=========== ========== ========== ==========
Net earnings per share: $ 0.15 $ 0.11 $ 0.11 $ 0.13
=========== ========== ========== ==========
Year ended September 30, 1994: Quarter ended
- ----------------------------- -------------------------------------------------
December 31 March 31 June 30 September 30
----------- ---------- --------- ------------
Revenues $5,840,0001 $5,540,000 $4,490,000 $4,130,000
=========== ========== ========== ==========
Operating income $3,580,000 $2,505,000 $2,095,000 $1,394,000
=========== ========== ========== ==========
Net earnings $1,350,000 $ 470,000 $ 370,000 $ 330,000
=========== ========== ========== ==========
Net earnings per share: $ 1.02 $ 0.36 $ 0.28 $ 0.24
=========== ========== ========== ==========
13. OIL AND NATURAL GAS REVENUES
----------------------------
In compliance with certain regulatory events and orders in the U.S. and
Canada affecting the sale and delivery of Canadian natural gas supplies to the
California market, the Company's Dunvegan natural gas purchase, sales and
transportation agreements with Alberta and Southern Gas Co., Ltd., were
terminated on November 1, 1993. As a result of these contract terminations, the
Company received a compensatory payment of U.S. $1,586,000 on November 1, 1993.
This payment was included in Revenues - oil and natural gas in the consolidated
statement of operations for the year ended September 30, 1994.
14. DISCONTINUED OPERATIONS
-----------------------
In 1994, the Company transferred its 25% limited partnership interests in
Pacific Tropical Products ("PTP") and Orchard Development ("Orchard"), which had
a carrying value of nil, to Mr. Anderson, a director and shareholder of the
Company ("Anderson") in consideration for the release of the Company's future
obligations with respect to PTP and Orchard. Accordingly, operating results
related to the food product segment have been reclassified and included in the
statement of operations as discontinued operations.
There were no revenues, expenses nor income taxes allocable to discontinued
operations for fiscal 1994. In fiscal 1993, the Company transferred its
ownership of the two subsidiaries (together the "Subsidiaries") that held
general partner ownership interests in PTP and Orchard to Anderson whereupon the
Company was relieved of the Subsidiaries' liabilities and recorded a gain of
$617,000 which represented the Company's proportionate share of the
partnerships' excess liabilities over assets at December 31, 1992.
Simultaneously in fiscal 1993, the partnerships each issued a 25% limited
partnership interest to a wholly-owned subsidiary of the Company, in
consideration for the Company's agreement to provide certain accounting and
operational services to the partnerships for a period of six months. The
earnings from discontinued food products operations of $296,000 for fiscal 1993
represents the aforementioned gain on the transfer of ownership of the Company's
general partnership interest in PTP and Orchard less the Company's share of the
fiscal 1993 losses of PTP and Orchard, net of income taxes. Revenues and income
taxes allocable to discontinued operations for fiscal 1993 amounted to $620,000
and $152,000, respectively.
15. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
-------------------------------------------------
<TABLE>
<CAPTION>
The following details the effect of changes in current assets and
liabilities on the statements of cash flows and supplemental disclosure of cash
flow information:
Year ended September 30,
----------------------------------------
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Increase (decrease) from changes in:
Proceeds from sale of trading securities $ 958,000 $ - $ -
Purchase of trading securities - (978,000) -
Receivables 131,000 (619,000) 1,152,000
Costs and estimated earnings in excess
of billings on uncompleted contracts 85,000 (4,000) 129,000
Inventories 7,000 (24,000) 1,000
Other current assets 62,000 (152,000) (4,000)
Accounts payable (457,000) 366,000 177,000
Accrued expenses (272,000) 52,000 (561,000)
Billings in excess of costs and
estimated earnings on uncompleted
contracts 185,000 (213,000) 102,000
Payable to joint interest owners 118,000 (315,000) 265,000
Income taxes payable (838,000) 492,000 183,000
----------- ----------- ----------
(Decrease) increase from changes
in current assets and liabilities $ (21,000) $(1,395,000) $1,444,000
=========== =========== ==========
Supplemental disclosure of cash flow information
Cash paid during the year for:
Interest $ 764,000 $ 471,000 $ 721,000
=========== =========== ==========
Income taxes $ 3,288,000 $ 1,914,000 $1,078,000
=========== =========== ==========
</TABLE>
16. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION
---------------------------------------------
The following tables summarize information relative to the Company's oil
and natural gas operations, which are substantially all conducted in Canada.
Proved reserves are the estimated quantities of crude oil, condensate and
natural gas which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed producing oil and natural
gas reserves are reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods. The estimated net interests
in total proved developed and proved developed producing reserves are based upon
subjective engineering judgments and may be affected by the limitations inherent
in such estimations. The process of estimating reserves is subject to continual
revision as additional information becomes available as a result of drilling,
testing, reservoir studies and production history. There can be no assurance
that such estimates will not be materially revised in subsequent periods.
(A) Oil and Natural Gas Reserves (Unaudited)
----------------------------------------
The following table, based on information prepared by independent petroleum
engineers, Paddock Lindstrom and Associates, Ltd., summarizes changes in the
estimates of the Company's net interests in total proved developed reserves of
crude oil and condensate and natural gas ("MCF" means 1,000 cubic feet of
natural gas) which are substantially all in Canada:
OIL GAS
Proved developed reserves: (Barrels) (MCF)
---------- ----------
Balance at September 30, 1992 2,179,000 48,184,000
Revisions of previous estimates 102,000 1,460,000
Extensions, discoveries and other additions 188,000 5,573,000
Less production (247,000) (4,506,000)
---------- ----------
Balance at September 30, 1993 2,222,000 50,711,000
Revisions of previous estimates 132,000 (775,000)
Extensions, discoveries and other additions 366,000 6,890,000
Less production (272,000) (4,679,000)
Sales of reserves in place (21,000) (297,000)
--------- ----------
Balance at September 30, 1994 2,427,000 51,850,000
Revisions of previous estimates 101,000 1,356,000
Extensions, discoveries and other additions 97,000 1,041,000
Less production (296,000) (4,916,000)
Sales of reserves in place (33,000) (2,585,000)
--------- ----------
Balance at September 30, 1995 2,296,000 46,746,000
========= ==========
OIL GAS
Proved developed producing reserves at: (Barrels) (MCF)
---------- ---------
September 30, 1992 1,975,000 34,417,000
========= ==========
September 30, 1993 2,005,000 35,895,000
========= ==========
September 30, 1994 2,133,000 34,624,000
========= ==========
September 30, 1995 2,025,000 31,700,000
========= ==========
Included in the above tables are proved developed producing reserves in the
U.S. of 59,000 barrels of oil and 40,000 MCF at September 30, 1995.
(B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities
----------------------------------------------------------------------
September 30,
---------------------------------------
1995 1994 1993
----------- ----------- -----------
Proved properties $35,438,000 $32,562,000 $27,956,000
Unproved properties 2,361,000 2,279,000 1,914,000
----------- ----------- -----------
Total capitalized costs 37,799,000 34,841,000 29,870,000
Accumulated depletion
and depreciation 18,644,000 15,897,000 13,612,000
----------- ----------- -----------
Net capitalized costs $19,155,000 $18,944,000 $16,258,000
=========== =========== ===========
(C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and
---------------------------------------------------------------------------
Development
-----------
Year ended September 30,
------------------------------------
1995 1994 1993
---------- ---------- ----------
Acquisition of properties:
Unproved $ 176,000 $ 589,000 $ 85,000
========== ========== ==========
Proved $ 152,000 $ 292,000 $ 144,000
========== ========== ==========
Exploration costs $ 273,000 $1,662,000 $ 712,000
========== ========== ==========
Development costs $2,833,000 $2,807,000 $2,252,000
========== ========== ==========
Included in the table above are capital expenditures of $112,000 and
$336,000 in fiscal 1994 and 1995, respectively, in the United States.
(D) The Results of Operations of Barnwell's Oil and Natural Gas Producing
----------------------------------------------------------------------
Activities, Which Exclude Corporate Overhead and Interest and, in Fiscal
------------------------------------------------------------------------
1994, Contract Termination Fees of $1,586,000
---------------------------------------------
Year ended September 30,
---------------------------------------
1995 1994 1993
----------- ----------- -----------
Gross revenues $11,367,000 $14,321,000 $12,904,000
Royalties, net of credit 847,000 1,957,000 1,654,000
----------- ----------- -----------
Net revenues 10,520,000 12,364,000 11,250,000
Production costs 3,373,000 3,188,000 2,756,000
Depletion and depreciation 2,658,000 2,361,000 2,014,000
----------- ----------- -----------
Pre-tax results of operations 4,489,000 6,815,000 6,480,000
Estimated income tax expense 2,338,000 3,634,000 2,941,000
----------- ----------- -----------
Results of operations $ 2,151,000 $ 3,181,000 $ 3,539,000
=========== =========== ===========
Revenues of $160,000 were received in fiscal 1995 from U.S. oil and natural
gas properties; no revenues were received in fiscal 1994 or fiscal 1993 from
U.S. properties.
(E) Standardized Measure, Including Year-to-Year Changes Therein, of Discounted
---------------------------------------------------------------------------
Future Net Cash Flows (Unaudited)
---------------------------------
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.
<TABLE>
<CAPTION>
Standardized Measure of Discounted Future Net Cash Flows
- --------------------------------------------------------
As of September 30,
-------------------------------------------
1995 1994 1993
------------ ----------- -----------
<S> <C> <C> <C>
Future cash inflows $ 74,143,000 $107,440,000 $96,798,000
Future production costs (25,690,000) (30,147,000) (24,531,000)
Future development costs (2,289,000) (2,668,000) (1,322,000)
------------- ----------- -----------
Future net cash flows before income
taxes 46,164,000 74,625,000 70,945,000
Future income tax expenses (12,341,000) (22,677,000) (22,451,000)
------------ ------------ -----------
Future net cash flows 33,823,000 51,948,000 48,494,000
10% annual discount for timing of
cash flows (13,473,000) (20,686,000) (19,358,000)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 20,350,000 $ 31,262,000 $ 29,136,000
============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
Changes in the Standardized Measure of Discounted Future Net Cash Flows
- -----------------------------------------------------------------------
Year ended September 30,
---------------------------------------
1995 1994 1993
----------- ---------- -----------
<S> <C> <C> <C>
Beginning of year $31,262,000 $29,136,000 $26,275,000
----------- ----------- -----------
Sales of oil and natural gas
produced, net of production costs (7,147,000) (9,176,000) (8,494,000)
Net changes in prices and production
costs, net of royalties and wellhead
taxes (13,335,000) 3,214,000 2,000,000
Extensions and discoveries 941,000 5,306,000 4,147,000
Purchases (sales) of reserves in place,
net (482,000) (161,000) 346,000
Revisions of previous quantity estimates 63,000 1,114,000 4,044,000
Net change in Canadian dollar translation
rate (144,000) (287,000) (1,346,000)
Changes in the timing of
future production and other (604,000) (1,120,000) (176,000)
Net change in income taxes 6,413,000 (366,000) (579,000)
Accretion of discount 3,383,000 3,602,000 2,919,000
----------- ----------- -----------
Net change (10,912,000) 2,126,000 2,861,000
------------ ----------- -----------
End of year $20,350,000 $31,262,000 $29,136,000
=========== =========== ===========
</TABLE>
Item 9. Changes in and Disagreements with Accountants on Accounting and
---------------------------------------------------------------
Financial Disclosure
--------------------
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
--------------------------------------------------
Item 11. Executive Compensation
----------------------
Item 12. Security Ownership of Certain Beneficial Owners and Management
--------------------------------------------------------------
Item 13. Certain Relationships and Related Transactions
----------------------------------------------
Items 10, 11, 12, and 13 are omitted pursuant to General Instructions G(3)
of Form 10-K, since the Registrant will file its definitive proxy statement for
the 1996 Annual Meeting of Stockholders not later than 120 days after the close
of its fiscal year ended September 30, 1995, which proxy statement is
incorporated herein by reference.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A) 1. Financial Statements
The following consolidated financial statements of Barnwell Industries,
Inc. and its subsidiaries are included in Part II, Item 8:
Independent Auditors' Report - KPMG Peat Marwick LLP
Consolidated Balance Sheets - September 30, 1995 and 1994
Consolidated Statements of Operations -
for the three years ended September 30, 1995
Consolidated Statements of Cash Flows -
for the three years ended September 30, 1995
Consolidated Statements of Stockholders' Equity -
for the three years ended September 30, 1995
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts and Reserves
All other schedules have been omitted because they were not applicable, not
required, or the information is included in the 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, 1995.
(C) Exhibits
No. 3.1 Certificate of Incorporation
No. 3.2 Amended and Restated By-Laws
No. 4.0 Form of the Registrant's certificate of common stock, par value
$.50 per share.
No. 10.4 The Barnwell Industries, Inc. Employees' Pension Plan (restated
as of October 1, 1989).
Exhibits 3.1 and 3.2 are incorporated by reference to the Exhibits 3.3
and 3.4, respectively, to the Registrant's Form S-8 dated November 8,
1991. Exhibit 4 is incorporated by reference to the registration
statement on Form S-1 originally filed by the Registrant January 29, 1957
and as amended February 15, 1957 and February 19, 1957. Exhibit 10.4 is
incorporated by reference to Form 10-K for the year ended September 30,
1989.
No. 10.17 Phase I Makai Development Agreement dated June 30, 1992, by and
between Kaupulehu Makai Venture and Kaupulehu Developments.
No. 10.18 KD/KMV Agreement dated June 30, 1992 by and between Kaupulehu
Makai Venture and Kaupulehu Developments.
Exhibits 10.17 thru 10.18 are incorporated by reference to Form 10-K for
the year ended September 30, 1992.
No. 21 Subsidiaries of the Registrant.
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC.
AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Balance at Additions Balance
beginning charged to at end
of year expense Deductions of year
---------- ----------- ---------- --------
YEAR ENDED SEPTEMBER 30, 1995:
<S> <C> <C> <C> <C>
Allowance for doubtful
accounts - accounts
receivable $ 26,000 $ 38,000 $ - $ 64,000
Allowance for doubtful
accounts - long-term notes
receivable 267,000 - - 267,000
---------- ---------- ---------- --------
Total allowance for doubtful
accounts $ 293,000 $ 38,000 $ - $331,000
========== ========== ========== ========
YEAR ENDED SEPTEMBER 30, 1994:
Allowance for doubtful
accounts - accounts
receivable $ 26,000 $ 34,000 $ 34,000 (1) $ 26,000
Allowance for doubtful
accounts - long-term notes
receivable 267,000 - - 267,000
---------- ---------- ---------- --------
Total allowance for doubtful
accounts $ 293,000 $ 34,000 $ 34,000 $293,000
========== ========== ========== ========
YEAR ENDED SEPTEMBER 30, 1993:
Allowance for doubtful
accounts - accounts
receivable $ 29,000 $ - $ 3,000 (2) $ 26,000
Allowance for doubtful
accounts - long-term notes
receivable 271,000 - 4,000 (3) 267,000
---------- ---------- ---------- --------
Total allowance for doubtful
accounts $ 300,000 $ - $ 7,000 $293,000
========== ========== ========== ========
<FN>
(1) Accounts written off less recoveries.
(2) Effect of change in the Canadian dollar exchange rate.
(3) Collections.
</TABLE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BARNWELL INDUSTRIES, INC.
(Registrant)
/s/Morton H. Kinzler
By: Morton H. Kinzler
Chief Executive Officer,
President and
Chairman of the Board
Date: December 5, 1995
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/ Russell M. Gifford
RUSSELL M. GIFFORD
Chief Financial Officer, Vice President
Date: December 5, 1995
/s/ Morton H. Kinzler
MORTON H. KINZLER
Chief Executive Officer,
President and Director
Date: December 5, 1995
/s/ Martin Anderson /s/ Alan D. Hunter
MARTIN ANDERSON, Director ALAN D. HUNTER, Director
Date: December 5, 1995 Date: December 5, 1995
/s/ H. Whitney Boggs, Jr. /s/ Daniel Jacobson
H. WHITNEY BOGGS, JR., Director DANIEL JACOBSON, Director
Date: December 5, 1995 Date: December 5, 1995
/s/ Barry E. Emes /s/ William C. Warren
BARRY E. EMES, Director WILLIAM C. WARREN, Director
Date: December 5, 1995 Date: December 5, 1995
/s/ Erik Hazelhoff-Roelfzema /s/ Glenn Yago
ERIK HAZELHOFF-ROELFZEMA, Director GLENN YAGO, Director
Date: December 5, 1995 Date: December 5, 1995
Exhibit 21 List of Subsidiaries
- --------------------------------
The subsidiaries of Barnwell Industries, Inc., at September 30, 1995 were:
Percentage Jurisdiction of
Name of Subsidiary of Ownership Incorporation
- ------------------ ------------ ---------------
Barnwell of Canada, Limited 100% Delaware
Barnwell Hawaiian Properties, Inc. 100% Delaware
Water Resources International, Inc. 100% Delaware
Barnwell Management Co., Inc. 100% Delaware
Barnwell Shallow Oil, Inc. 100% Delaware
Barnwell Geothermal Corporation 100% Delaware
Barnwell Mining Co. 100% Delaware
Barnwell Land Co. 100% Delaware
Barnwell Overseas, Inc. 100% Delaware
Barnwell GEDCO Corporation 100% Delaware
Geothermal Exploration Co., Inc. 100% Delaware
Victoria Properties, Inc. 100% Delaware
Barnwell Israel, Ltd. 100% Israel
Barnwell Oil & Gas, Ltd. 100% Israel
Bill Robbins Drilling, Ltd. 100% Alberta, Canada
Dartmouth Petroleum, Ltd. 100% Alberta, Canada
Gypsy Petroleums Ltd. 100% Alberta, Canada
J.H. Wilson Associates, Ltd. 100% Alberta, Canada
Salcona Gas, Ltd. 100% Alberta, Canada
Barnwell Investment Corporation 100% Hawaii
Barnwell Kona Corporation 100% Hawaii
Barnwell Financial Corporation 100% Delaware
NDTX, Inc. 100% Delaware
WRI Properties, Inc. 100% Hawaii
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from
Barnwell Industries, Inc.'s 1995 10-K405 and is qualified in its
entirety by reference to such 10-K405 filing.
</LEGEND>
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1995
<PERIOD-END> SEP-30-1995
<CASH> 2976
<SECURITIES> 0
<RECEIVABLES> 2549
<ALLOWANCES> 64
<INVENTORY> 112
<CURRENT-ASSETS> 6124
<PP&E> 48754
<DEPRECIATION> 27757
<TOTAL-ASSETS> 28780
<CURRENT-LIABILITIES> 2481
<BONDS> 11100
0
0
<COMMON> 821
<OTHER-SE> 9541
<TOTAL-LIABILITY-AND-EQUITY> 28780
<SALES> 14290
<TOTAL-REVENUES> 14950
<CGS> 6263
<TOTAL-COSTS> 6263
<OTHER-EXPENSES> 3103
<LOSS-PROVISION> 38
<INTEREST-EXPENSE> 756
<INCOME-PRETAX> 1342
<INCOME-TAX> 692
<INCOME-CONTINUING> 650
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 650
<EPS-PRIMARY> .49
<EPS-DILUTED> 0
</TABLE>
