U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-KSB
X ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE
--- SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1998
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
--- SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-5103
BARNWELL INDUSTRIES, INC.
(Name of small business issuer in its charter)
DELAWARE 72-0496921
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1100 ALAKEA STREET, SUITE 2900, HONOLULU, HAWAII 96813-2833
(Address of principal executive offices) (Zip code)
(808) 531-8400
(Issuer's telephone number)
Securities registered under Section 12(b) of the Exchange Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common Stock, par value American Stock Exchange
$0.50 per share Toronto Stock Exchange
Securities registered under Section 12(g) of the Exchange Act:
None
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes X No
--- ---
<PAGE>
1
Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-B, and no disclosure will be contained, to the best of
registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB. [X]
Issuer's revenues for the fiscal year ended September 30, 1998: $11,920,000
The aggregate market value of the voting stock held by non-affiliates (508,555
shares) of the Registrant on December 3, 1998, based on the closing price of
$11.625 on that date on the American Stock Exchange, was $5,912,000.
As of December 3, 1998 there were 1,316,952 shares of common stock, par
value $.50, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
-----------------------------------
1. Proxy statement to be forwarded to shareholders on or about January 21,
1999 is incorporated by reference in Part III hereof.
Transitional Small Business Disclosure Format Yes No X
--- ---
<PAGE>
2
TABLE OF CONTENTS
PART I
Discussion of Forward-Looking Statements
Item 1. Description of Business
General Development of Business
Financial Information about Industry Segments
Narrative Description of Business
Financial Information about Foreign and
Domestic Operations and Export Sales
Item 2. Description of Property
Oil and Natural Gas Operations
General
Well Drilling Activities
Oil and Natural Gas Production
Productive Wells
Developed Acreage and Undeveloped Acreage
Reserves
Estimated Future Net Revenues
Marketing of Oil and Natural Gas
Governmental Regulation
Competition
Contract Drilling Operations
Activity
Competition
Land Investment Operations
Activity
Competition
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market For Common Equity and Related Stockholder Matters
Item 6. Management's Discussion and Analysis or Plan of Operation
Liquidity and Capital Resources
Results of Operations
Item 7. Financial Statements
Item 8. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons,
Compliance With Section 16(a) of the Exchange Act
Item 10. Executive Compensation
Item 11. Security Ownership of Certain Beneficial Owners and Management
Item 12. Certain Relationships and Related Transactions
Item 13. Exhibits and Reports on Form 8-K
<PAGE>
3
PART I
Forward-Looking Statements
- --------------------------
This Form 10-KSB, and the documents incorporated herein by reference,
contain forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended, including various forecasts, projections of Barnwell
Industries, Inc.'s (referred to herein together with its subsidiaries as
"Barnwell" or the "Company") future performance, statements of the Company's
plans and objectives and other similar types of information. Although the
Company believes that its expectations are based on reasonable assumptions, it
cannot assure that the expectations contained in such forward-looking statements
will be achieved. Such statements involve risks, uncertainties and assumptions,
including, but not limited to, those relating to the factors discussed below, in
other portions of this Form 10-KSB, in the Notes to Consolidated Financial
Statements, and in other documents filed by the Company with the Securities and
Exchange Commission from time to time, which could cause actual results to
differ materially from those contained in such statements. These forward-looking
statements speak only as of the date of filing of this Form 10-KSB, and the
Company expressly disclaims any obligation or undertaking to publicly release
any updates or revisions to any forward-looking statements contained herein.
The Company's oil and natural gas operations are affected by domestic and
international political, legislative, regulatory and legal actions. Such actions
may include changes in the policies of the Organization of Petroleum Exporting
Countries ("OPEC") or other developments involving or affecting oil-producing
countries, including military conflict, embargoes, internal instability or
actions or reactions of the government of the United States in anticipation of
or in response to such developments. Domestic and international economic
conditions, such as recessionary trends, inflation, interest, monetary exchange
rates and labor costs, as well as changes in the availability and market prices
of crude oil, natural gas and petroleum products, may also have a significant
effect on the Company's oil and natural gas operations. While the Company
maintains reserves for anticipated liabilities and carries various levels of
insurance, the Company could be affected by civil, criminal, regulatory or
administrative actions, claims or proceedings. In addition, climate and weather
can significantly affect the Company in several of its operations. The Company's
oil and gas operations are also affected by political developments and laws and
regulations, particularly in the United States and Canada, such as restrictions
on production, restrictions on imports and exports, the maintenance of specified
reserves, tax increases and retroactive tax claims, expropriation of property,
cancellation of contract rights, environmental protection controls,
environmental compliance requirements and laws pertaining to workers' health and
safety.
The Company's land investment business segment is affected by the
condition of Hawaii's real estate market. The Hawaii real estate market is
affected by Hawaii's economy in general, and Hawaii's tourism industry in
particular. Any future cash flows from the Company's land development activities
are subject to, among other factors, the level of real estate prices, the demand
for new hotels and resorts on the Island of Hawaii, the rate of increase in the
cost of building materials and labor, the introductions of building code
modifications, changes to zoning laws, and the level of consumer confidence in
Hawaii's economy.
The Company's contract drilling operations, which are located in Hawaii,
are also indirectly affected by the factors discussed in the preceding
paragraph. The Company's contract drilling operations are materially dependent
upon levels of activity in land development in Hawaii. Such activity levels are
affected by both short-term and long-term trends in Hawaii's economy. In recent
years, Hawaii's economy has experienced very slow growth and therefore the level
of contract drilling activity has declined. As events during recent years have
demonstrated, any prolonged reduction or lack of growth in Hawaii's economy will
depress the demand for the Company's contract drilling services. Such a decline
could have a material adverse effect on the Company's revenues and
profitability.
<PAGE>
4
Item 1. Description of Business
-----------------------
(a) General Development of Business
-------------------------------
Barnwell was incorporated in 1956. During its last three completed fiscal
years, the Company was engaged in oil and natural gas exploration, development,
production and sales in Canada and the United States, investment in leasehold
land in Hawaii, and water well drilling and water pumping system installation
and repair in Hawaii. The Company's oil and natural gas activities comprise its
largest business segment. Approximately 79% of the Company's revenues for the
fiscal year ended September 30, 1998 were attributable to its oil and natural
gas activities. The Company's contract drilling activities accounted for 13% of
the Company's revenues in fiscal 1998, with natural gas processing and other
revenues comprising the remaining 8% of fiscal 1998 revenues. Approximately 86%
of the Company's capital expenditures for the fiscal year ended September 30,
1998 were attributable to oil and natural gas activities, 11% to land investment
and 3% to other activities. The Company had no land investment revenue in 1998;
land investment revenues relate to sales of leasehold interests and development
rights, which do not occur every year.
(i) Oil and Natural Gas Activities.
------------------------------
The Company's wholly-owned subsidiary, Barnwell of Canada, Limited ("BOC"),
is involved in the acquisition, exploration and development of oil and natural
gas properties, principally in Alberta, Canada. BOC participates in exploratory
and developmental operations for oil and natural gas on property in which it has
an interest and evaluates proposals by third parties with regard to
participation in such exploratory and developmental operations elsewhere.
(ii) Contract Drilling.
------------------
The Company's wholly-owned subsidiary, Water Resources International, Inc.
("WRI"), drills water wells and installs and repairs water pumping systems in
Hawaii. WRI owns and operates four rotary drill rigs, one rotary drill/workover
rig, and pump installation and service equipment, and maintains drilling
materials and pump inventory in Hawaii. WRI contracts are usually fixed price
contracts that are either negotiated with private individuals or entities, or
are obtained through competitive bidding with various local, state and federal
agencies.
(iii) Land Investment.
---------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii general partnership. Between 1986 and 1989, Kaupulehu Developments
obtained the state and county zoning changes necessary to permit development of
the Four Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club,
a planned second golf course, and single and multiple family residential units
on land acquired from Kaupulehu Developments. Kaupulehu Developments currently
owns development rights in approximately 100 acres of residentially zoned
leasehold land and leasehold rights in approximately 2,100 acres of land located
in the North Kona District of the Island of Hawaii.
<PAGE>
5
(b) Financial Information about Industry Segments
---------------------------------------------
Revenues of each industry segment for the fiscal years ended September 30,
1998, 1997 and 1996 are summarized as follows (all revenues were from
unaffiliated customers with no intersegment sales or transfers):
1998 1997 1996
---------------- ----------------- ----------------
Oil and natural gas $ 9,400,000 79% $ 11,520,000 78% $10,660,000 75%
Contract drilling 1,510,000 13% 2,160,000 14% 2,650,000 19%
Other 920,000 7% 873,000 6% 717,000 5%
----------- ---- ------------ ---- ----------- ----
Revenues from
segments 11,830,000 99% 14,553,000 98% 14,027,000 99%
Interest income 90,000 1% 277,000 2% 153,000 1%
----------- ---- ------------ ---- ----------- ----
Total revenues $11,920,000 100% $ 14,830,000 100% $14,180,000 100%
=========== ==== ============ ==== =========== ====
For further discussion see Note 11 (Segment and Geographic Information)
and Note 13 (Concentrations of Credit Risk) of "Notes to Consolidated Financial
Statements" in Item 7.
(c) Narrative Description of Business
---------------------------------
See the table above in Item 1(b) detailing revenue of each industry
segment and description of each industry segment of the Company's business under
Item 2.
As of September 30, 1998, Barnwell employed 37 employees, all on a
full-time basis. Ten (10) are employed in oil and natural gas activities, 16 are
employed in contract drilling, and 11 are members of the corporate and
administrative staff.
For further discussion see "Governmental Regulation" and "Competition"
sections in Item 2 hereof.
(d) Financial Information about Foreign and Domestic Operations and
---------------------------------------------------------------
Export Sales
------------
Revenues, operating profit or loss and identifiable assets by geographic
area for the three years ended and as of September 30, 1998, 1997 and 1996 are
set forth in Note 11 (Segment and Geographic Information) of "Notes to
Consolidated Financial Statements" in Item 7.
Item 2. Description of Property
-----------------------
OIL AND NATURAL GAS OPERATIONS
------------------------------
General
- -------
Barnwell's investments in oil and natural gas properties consist of
investments in Canada, principally in the Province of Alberta, with minor
holdings in Saskatchewan. These property interests are principally held under
governmental leases or licenses. Under the typical Canadian provincial
governmental lease, Barnwell must perform exploratory operations and comply with
certain other conditions. Lease terms vary with each province, but, in general,
grant Barnwell the right to remove oil, natural gas and related substances
subject to payment of specified royalties on production.
Barnwell participates in exploratory and developmental operations for oil
and natural gas on property in which it has an interest. The Company also
evaluates proposals by third parties for participation in other exploratory and
developmental opportunities. All exploratory and developmental operations are
evaluated by Barnwell's Calgary, Alberta staff along with independent
consultants as necessary. In fiscal 1998, Barnwell participated in exploratory
and developmental operations in the Canadian Province of Alberta, and in the
states of Michigan and North Dakota, although Barnwell does not limit its
consideration of exploratory and developmental operations to these areas.
<PAGE>
6
Barnwell's producing natural gas properties are located principally in
Alberta. The Province of Alberta determines its royalty share of natural gas by
using a reference price that averages all natural gas sales in Alberta. In
fiscal 1998, the weighted average royalty paid on natural gas from the Dunvegan
Unit, Barnwell's principal oil and natural gas property, increased to 23%, as
compared to 19% in fiscal 1997. The weighted average royalty paid on all of the
Company's natural gas was approximately 21% in fiscal 1998 versus 18% in fiscal
1997.
In fiscal 1998, 97% of Barnwell's oil production was from properties
located in Alberta. Royalty rates under government leases in Alberta are based
on the selling price of oil and production volumes. In fiscal 1998, the weighted
average royalty paid on oil was approximately 19%.
Unit sales and prices of natural gas are typically higher in the winter
than at other times due to demand for heating. Unit sales and prices of oil are
also subject to seasonal fluctuations, but to a lesser degree.
Well Drilling Activities
- ------------------------
During fiscal 1998, the Company participated in the drilling of 50
development wells and 9 exploratory wells, of which, in the Company's view, 45
are capable of production. The Company also participated in the recompletion of
14 wells. The most significant drilling operations took place in the Dunvegan,
Chauvin, and Red Earth areas of Alberta.
In fiscal 1998, almost 75% of the wells drilled in which the Company
participated were in its major properties. Multi-well programs took place in
Dunvegan, Chauvin, Manyberries, Red Earth, Thornbury, Pouce Coupe and Belloy
with varying degrees of success.
In the Dunvegan Unit (where the Company holds an 8.9% interest), the
Company participated in 5 wells, 2 of which were high cost horizontal wells. The
results of the program are still being evaluated, and will impact future
drilling plans for the unit.
In the Debolt BB pool in the Dunvegan area (where the Company holds a
10.3% interest), two horizontal oil wells, two injection wells and a water
source well were drilled and a battery was constructed during the year. The pool
commenced production in September 1998 at choked back rates of approximately 500
gross barrels per day.
In the Chauvin Sparky Unit (where the Company holds a 19.2% interest), a
successful 6 well infill drilling program was undertaken. Initial oil rates from
these wells increased unit production by almost 25% during the year.
At Red Earth (where the Company holds a 24.7% interest), the Company
participated in drilling 3 Granite Wash oil wells which are currently producing
over 250 gross barrels per day of oil.
In addition, the Company drilled 4 wells in Alberta on 3 internally
generated projects. All wells were cased and completed. At Sunnynook, the
Company (holding a 44% interest after payout) drilled a Glauconite gas well
which is currently producing 1.5 MMCF ("MMCF" means 1,000,000 cubic feet and
"MCF" means 1,000 cubic feet) per day. At Rat Creek, a Rock Creek oil well was
drilled (the Company has a 32% interest after payout) and currently produces at
35 gross barrels per day of oil. The other two wells drilled at Wilson Creek for
Belly River oil are currently shut-in pending workovers.
<PAGE>
7
In November 1996, the Company entered into a participation agreement with
KEP Energy Resources, LLC and Presco Inc. to develop natural gas and oil
reserves in the Central Basin in Michigan.
The initial drilling program in Michigan included one new well, and seven
existing well bores, which were re-entered with the goal of producing natural
gas. One well was commercial and seven were non-commercial wells. A second
drilling program, comprised of six wells, commenced in 1998 in order to more
fully evaluate the extensive land position acquired in the Michigan Basin. The
target for three of the wells was the deep natural gas targeted in the initial
program, with the other three wells targeting shallower oil formations. These
six wells were not commercial.
Under the full cost method of accounting, the amount of oil and natural
gas properties' capitalized costs less accumulated depletion (on a country by
country basis) is subject to a ceiling test limitation that requires any excess
of such costs over the present value of estimated future cash flows from proved
reserves to be expensed. As of March 31, 1998, the Company's investment in the
Michigan Basin prospect was determined to be impaired and was transferred to the
amortization base. Upon transfer, capitalized oil and natural gas properties'
costs in the United States exceeded the full cost ceiling test limitation and,
accordingly, the Company recorded a non-cash write-down of $2,070,000 in the
quarter ended March 31, 1998. Due to further declines in oil prices and
disappointing seismic and drilling results in North Dakota, the Company
abandoned its U.S. oil and natural gas prospects and recorded an additional U.S.
ceiling test write-down of $660,000 during the quarter ended June 30, 1998 to
fully write-off its investment in U.S. oil and natural gas properties.
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, 1998, 1997 and 1996 in which
the Company participated:
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.
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----
1998
- ----
Gross* 1.00 20.00 - 24.00 - - 1.00 44.00 8.00 6.00 9.00 50.00
Net* 0.18 3.36 - 1.51 - - 0.18 4.87 1.20 0.37 1.38 5.24
1997
- ----
Gross* 4.00 25.00 3.00 21.00 - - 7.00 46.00 10.00 9.00 17.00 55.00
Net* 0.72 2.92 0.14 2.27 - - 0.86 5.19 0.80 1.13 1.66 6.32
1996
- ----
Gross* 3.00 10.00 5.00 9.00 - 3.00 8.00 22.00 6.00 4.00 14.00 26.00
Net* 0.55 1.63 0.94 1.20 - 0.34 1.49 3.17 0.94 0.57 2.43 3.74
- ----------------------------------
* 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.
The Dunvegan Unit, the Company's principal property located in Alberta,
Canada, has over 140 natural gas wells comprising a total of 195 producing well
zones. In fiscal 1998, the Company spent $1,750,000 to further develop the
property. An attempt was made by the operator to test the limits of the field,
the results of which are still being evaluated.
<PAGE>
8
Oil and Natural Gas Production
- ------------------------------
In fiscal 1998, approximately 54%, 36% and 10% of the Company's oil and
natural gas revenues were from the sale of natural gas, the sale of oil
(including liquids) and the royalty tax credit, respectively.
In fiscal 1998, the Company's natural gas production in fiscal 1998
averaged net sales volume after royalties of 10,100 MCF per day, a decrease of
5% from 10,600 MCF per day in fiscal 1997. This decrease was due to expected
natural declines in production from some of the Company's mature properties
(Dunvegan, Hillsdown, Charlotte Lake, Thornbury, and Pouce Coupe). Dunvegan
continues to contribute about 47% of the Company's natural gas production.
In fiscal 1998, oil sales averaged net production of 575 barrels per day,
an increase of 6% from fiscal 1997. The Company's major oil producing properties
are the Red Earth, Chauvin and Manyberries areas in Canada.
In fiscal 1998, natural gas liquid sales averaged net production of 178
barrels per day, unchanged from fiscal 1997. Dunvegan provided 72% of the
Company's fiscal 1998 natural gas liquids production. Other major natural gas
liquids producing properties are the Hillsdown, Pembina and Pouce Coupe areas in
Alberta.
In fiscal 1997, approximately 49%, 43% and 8% of the Company's oil and
natural gas revenues were from the sale of natural gas, the sale of oil
(including liquids) and the royalty tax credit, respectively.
The following table summarizes (a) Barnwell's net production for the last
three fiscal years, based on sales of crude oil, natural gas, condensate and
other natural gas liquids, from all wells in which Barnwell has or had an
interest, and (b) the average sales prices and average production costs for such
production during the same periods. Barnwell's net production in fiscal 1998 was
derived primarily from the Province of Alberta. All dollar amounts in this table
are in U.S. dollars.
Year Ended September 30,
-------------------------------------------
1998 1997 1996
------------- ------------- ------------
Annual net production:
Natural gas liquids (BBLS)* 65,000 65,000 73,000
Oil (BBLS)* 210,000 199,000 206,000
Natural gas (MCF)* 3,684,000 3,852,000 4,347,000
Annual average sale price
per unit of production:
BBL of liquids** $11.36 $17.55 $13.40
BBL of oil** $13.02 $19.55 $17.38
MCF of natural gas** $ 1.38 $ 1.45 $ 1.14
Annual average production cost
per MCFE produced***** $ 0.61 $ 0.62 $ 0.57
<PAGE>
9
The following table sets forth the gross and net number of productive
wells Barnwell has an interest in as of September 30, 1998.
Productive Wells
- ----------------
Productive Wells***
----------------------------
Gross**** Net****
------------ --------------
Location Oil Gas Oil Gas
- ---------------------- ------ ----- ------ -------
Canada
- ------
Alberta 188 353 48.64 42.05
Saskatchewan 3 21 0.25 3.55
------ ----- ------ -------
Total 191 374 48.89 45.60
====== ===== ====== =======
- -------------------------------
* When used in this report, "MCF" means 1,000 cubic feet of natural gas at
14.65 psia and 60 degrees F and the term "BBLS" means stock tank barrels
of oil equivalent to 42 U.S. gallons.
** Calculated on revenues before royalty expense and royalty tax credit
divided by gross production.
*** Seventy-two gross natural gas wells have dual or multiple completions and
six gross oil wells have dual completions.
**** Please see note (2) on the following table.
***** Natural gas liquids, oil and natural gas units were combined by converting
barrels of natural gas liquids and oil to an MCF equivalent ("MCFE") on
the basis of 5.8 MCF = 1 BBL.
Developed Acreage and Undeveloped Acreage
- -----------------------------------------
The following table sets forth certain information with respect to oil and
natural gas properties of Barnwell as of September 30, 1998:
Developed and
Developed Undeveloped Undeveloped
Acreage(1) Acreage(1) Acreage(1)
-------------------- -------------------- ------------------
Location Gross(2) Net(2) Gross(2) Net(2) Gross(2) Net(2)
- ------------------- ---------- --------- ---------- --------- ---------- -------
Canada
- ------
Alberta 249,395 36,467 179,942 38,459 429,337 74,926
British Columbia 483 40 2,789 284 3,272 324
Saskatchewan 3,696 543 200 11 3,896 554
U.S.
- ----
North Dakota - - 23,330 10,916 23,330 10,916
------- ------ ------- ------- ------- ------
Total 253,574 37,050 206,261 49,670 459,835 86,720
======= ====== ======= ======= ======= ======
Barnwell's leasehold interests in its undeveloped acreage, if not
developed, expire over the next five fiscal years as follows: 21% expire during
fiscal 1999; 23% expire during fiscal 2000; 33% expire during fiscal 2001; 14%
expire during fiscal 2002 and 9% expire during fiscal 2003. There can be no
assurance that the Company will be successful in renewing its leasehold
interests in the event of expiration.
Barnwell's undeveloped acreage includes major concentrations in Alberta at
Thornbury (6,604 net acres), Archie (4,000 net acres), and Boulder (2,880 net
acres), and in the state of North Dakota (10,916 net acres).
<PAGE>
10
Reserves
- --------
The amounts set forth in the table below, prepared by Paddock Lindstrom
and Associates, Ltd., Barnwell's independent reservoir engineering consultants,
summarize the estimated net quantities of proved developed producing reserves
and proved developed reserves of crude oil (including condensate and natural gas
liquids) and natural gas as of September 30, 1998, 1997 and 1996 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,
-----------------------------------------
1998 1997 1996
------------ ------------ ------------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 2,109,000 2,087,000 2,108,000
Natural gas - thousand
cubic feet (MCF) 28,306,000 29,483,000 33,096,000
Total Proved Developed Reserves
(Includes Proved
Developed Producing Reserves)
- -----------------------------
September 30,
-----------------------------------------
1998 1997 1996
------------ ------------ ------------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 2,413,000 2,613,000 2,374,000
Natural gas - thousand
cubic feet (MCF) 40,561,000 43,951,000 46,252,000
As of September 30, 1998, essentially all of Barnwell's proved developed
producing and total proved developed reserves were located in the Province of
Alberta, with minor volumes located in the Province of Saskatchewan.
During fiscal 1998, Barnwell's total net proved developed reserves,
including proved developed producing reserves, of oil, condensate and natural
gas liquids decreased moderately by 200,000 barrels, and total net proved
developed reserves of natural gas decreased by 3,390,000 MCF. The decrease in
oil, condensate and natural gas liquids reserves was the net result of
production during the year of 275,000 barrels, and the addition of 191,000
barrels from the drilling of productive oil wells, and the independent
engineer's 116,000 barrel downward revision of the Company's oil reserves.
Barnwell's proved developed natural gas reserves decreased as a net result of
production during the year of 3,684,000 MCF, sale of reserves of 46,000 MCF, the
independent engineer's 1,370,000 MCF downward revision of the Company's natural
gas reserves, and the addition of 1,710,000 MCF from the drilling of productive
natural gas wells.
<PAGE>
11
Barnwell's working interest in the Dunvegan Unit accounted for
approximately 62% of its total proved developed natural gas reserves at both
September 30, 1998 and 1997, and approximately 28% of proved developed oil and
condensate reserves at September 30, 1998, as compared to approximately 31% of
proved developed oil and condensate reserves at September 30, 1997.
The following table sets forth the Company's oil and natural gas reserves
at September 30, 1998, by property name, based on information prepared by
Paddock Lindstrom and Associates, Ltd., Barnwell's independent reservoir
engineering consultant. Gross reserves are before the deduction of royalties;
net reserves are after the deduction of royalties net of the Alberta Royalty Tax
Credit. This table is based on constant dollars where reserve estimates are
based on sales prices, costs and statutory tax rates in existence at the date of
the projection. Oil, which includes natural gas liquids, is shown in thousands
of barrels ("MBBLS") and natural gas is shown in millions of cubic feet
("MMCF").
<PAGE>
12
<TABLE>
OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 1998
<CAPTION>
Total Producing Total Proved
--------------------------------- --------------------------------
Oil Gas Oil Gas
--------------- ---------------- --------------- ----------------
GROSS NET GROSS NET GROSS NET GROSS NET
(MBBLS) (MMCF) (MBBLS) (MMCF)
--------------- ---------------- --------------- ----------------
Property Name
- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dunvegan Unit 602 524 20,966 19,255 780 683 27,158 24,980
Dunvegan Non-Unit 94 92 393 361 97 95 1,004 923
Hillsdown 122 109 1,901 1,734 184 167 2,497 2,276
Thornbury - - 2,203 2,059 - - 2,567 2,402
Manyberries 115 112 62 54 125 122 621 543
Pouce Coupe 6 5 1,004 914 12 10 1,807 1,648
Red Earth 922 910 - - 957 946 - -
Pembina 16 14 404 373 16 14 404 373
Barrhead 3 3 421 401 3 3 437 417
Bashaw - - 81 75 - - 81 75
Belloy - - 112 105 - - 470 435
Brooks - - 71 66 - - 71 66
Cessford 3 3 - - 3 3 - -
Charlotte Lake 26 25 570 539 26 25 968 913
Chauvin 119 116 - - 119 116 - -
Clear Hills 1 1 - - 1 1 - -
Coyote - - 7 7 - - 7 7
Cyn-Pem 22 22 - - 22 22 - -
Faith - - - - - - 1,026 942
Gilby 3 3 226 210 3 3 226 210
Gilwood - - - - - - 96 83
Highvale 23 23 80 71 23 23 80 71
Hilda - - 31 30 - - 31 30
Lanaway - - - - - - 203 182
Leduc - - - - - - 204 198
Majeau Lake - - 28 26 - - 28 26
Medicine River 80 76 134 117 85 81 256 225
Mikwan 1 1 43 41 1 1 43 41
Mitsue - - 10 9 - - 13 12
Rainbow 1 1 - - 1 1 - -
Richdale - - - - - - 178 167
Staplehurst - - - - 16 16 - -
Sunnynook 4 3 1,001 929 4 3 1,001 929
Wood River 33 32 253 238 33 32 253 238
Worsley 3 3 43 40 3 3 43 40
Zama 28 28 336 300 43 40 1,930 1,757
Hatton, Saskatchewan - - 494 352 - - 494 352
Webb, Saskatchewan 3 3 - - 3 3 - -
----- ----- ------ ------ ----- ----- ------ ------
TOTAL 2,230 2,109 30,874 28,306 2,560 2,413 44,197 40,561
===== ===== ====== ====== ===== ===== ====== ======
<FN>
Properties are located in Alberta, Canada unless otherwise noted.
</FN>
</TABLE>
<PAGE>
13
Estimated Future Net Revenues
- -----------------------------
The following table sets forth Barnwell's "Estimated Future Net Revenues"
from total proved oil, natural gas and condensate reserves and the present value
of Barnwell's "Estimated Future Net Revenues" (discounted at 10%). Estimated
future net revenues for total proved developed reserves are net of estimated
development costs. Net revenues have been calculated using current sales prices
and costs, after deducting all royalties, operating costs, future estimated
capital expenditures, and income taxes.
Proved Developed Total
Producing Proved Developed
Reserves Reserves
------------------ ------------------
Year ending September 30,
1999 $ 4,841,000 $ 4,549,000
2000 3,903,000 4,384,000
2001 3,179,000 4,256,000
Thereafter 16,357,000 23,835,000
----------- -----------
$28,280,000 $37,024,000
=========== ===========
Present value (discounted at 10%)
at September 30, 1998 $17,226,000 $22,673,000
=========== ===========
Marketing of Oil and Natural Gas
- --------------------------------
Barnwell sells substantially all of its oil and condensate production
under short-term contracts between itself or the operator of the property and
marketers of oil. The price of oil is freely negotiated between the buyers and
sellers.
Natural gas sold by the Company is generally sold under both long-term and
short-term contracts with prices indexed to market prices and renegotiated
annually. The price of natural gas and natural gas liquids is freely negotiated
between buyers and sellers. In 1998, the Company took most of its oil and
natural gas "in kind" where the Company markets the products instead of having
the operator of a producing property market the products on the Company's
behalf.
In fiscal 1998, natural gas production from the Dunvegan Unit was
responsible for approximately 47% of the Company's natural gas revenues. In
fiscal 1998, the Company had one significant customer that accounted for 23% of
the Company's oil and natural gas revenues. A substantial portion of Barnwell's
Dunvegan natural gas production and natural gas production from other properties
is sold to aggregators and marketers under various short-term and long-term
contracts, with the price of natural gas determined by negotiations between the
aggregators and the final purchasers.
Governmental Regulation
- -----------------------
The jurisdictions in which the oil and natural gas properties of Barnwell
are located have regulatory provisions relating to permits for the drilling of
wells, the spacing of wells, the prevention of oil and natural gas waste,
allowable rates of production and other matters. The amount of oil and natural
gas produced is subject to control by regulatory agencies in each province and
state that periodically assign allowable rates of production. The Province of
Alberta also regulates the volume of natural gas that may be removed from the
province and the conditions of removal.
There is no current government regulation of the price that may be charged
on the sale of Canadian oil or natural gas production. Canadian natural gas
production destined for export is, 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.
<PAGE>
14
The right to explore for and develop oil and natural gas on lands in
Alberta and Saskatchewan is controlled by the governments of each of those
provinces. Changes in royalties and other terms of provincial leases, permits
and reservations may have a substantial effect on the Company's operations. In
addition to the foregoing, Barnwell's Canadian operations may be affected in the
future, from time to time, by political developments in Canada and by Canadian
Federal, provincial and local laws and regulations, such as restrictions on
production and export, oil and natural gas allocation and rationing, price
controls, tax increases, expropriation of property, modification or cancellation
of contract rights, and environmental protection controls. Furthermore,
operations may also be affected by United States import fees and restrictions.
Different royalty rates are imposed by the producing provinces, the
Government of Canada and private interests with respect to the production and
sale of crude oil, natural gas and liquids. In addition, some producing
provinces receive additional revenue through the imposition of taxes on crude
oil and natural gas owned by private interests within the province. Essentially,
provincial royalties are calculated as a percentage of revenue, and vary
depending on production volumes, selling prices and the date of discovery.
Canadian taxpayers are not permitted to deduct royalties, taxes, rentals
and similar levies paid to the Federal or provincial governments in connection
with oil and natural gas production in computing income for purposes of Canadian
Federal income tax. However, they are allowed to deduct a "Resource Allowance"
which is 25% of the taxpayer's "Resource Profits for the Year" (essentially,
income from the production of oil, natural gas or minerals) in computing their
taxable income. The resource properties located in the United States are
freehold mineral interests leased under market conditions, subject to extraction
and severance taxes imposed according to state regulations.
In Alberta, a producer of oil or natural gas is entitled to a credit
against the royalties payable to the Crown by virtue of the Alberta Royalty Tax
Credit ("ARTC") program. The ARTC rate is based on a price-sensitive formula and
varies between 75% at prices below a specified royalty tax credit reference
price decreasing to 25% at prices above a specified royalty tax credit reference
price. The ARTC will be applied to a maximum annual amount of $2,000,000
Canadian dollars of Alberta Crown royalties payable for each producer or
associated group of producers. Crown royalties on production from producing
properties acquired from corporations claiming maximum entitlements to ARTC will
generally not be eligible for ARTC. The rate is established quarterly based on
the average royalty tax credit reference price, as determined by the Alberta
Department of Energy. The royalty tax credit reference price is based on a
weighted average oil and gas price.
The Province of Alberta has stated that changes in the ARTC will be
announced three years in advance. The ARTC program has been in effect in various
forms since 1974 and the Company anticipates that it will be continued in some
form for the foreseeable future. If the ARTC is not continued, it will have a
material adverse effect on the Company.
Competition
- -----------
The majority of Barnwell's natural gas sales take place in Alberta, Canada
and the remainder is sold in the mid-continental United States, northeastern
United States and the northern California area. Natural gas prices in Alberta
are generally very competitive as there is a significant supply of shut-in
natural gas. This situation is expected to improve in late 1998 as new pipeline
capacity comes onstream, improving access to U.S. markets. 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 and North Dakota with prices determined by the world
price for oil.
<PAGE>
15
The Company competes in the sale of oil and natural gas on the basis of
price, and on the ability to deliver product. The oil and natural gas industry
is intensely competitive in all phases, including the exploration for new
production and reserves and the acquisition of equipment and labor necessary to
conduct drilling activities. The competition comes from numerous major oil
companies as well as numerous other independent operators. There is also
competition between the oil and natural gas industry and other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers. Barnwell is a minor participant in the industry and
competes in its oil and natural gas activities with many other companies having
far greater financial and other resources.
CONTRACT DRILLING OPERATIONS
----------------------------
Barnwell owns 100% of Water Resources International, Inc. ("WRI"). WRI
drills water wells and installs and repairs water pumping systems in Hawaii, and
has also drilled geothermal wells in Hawaii in previous years. WRI owns and
operates four rotary drill rigs, one rotary drill/workover rig and a two acre
parcel of real estate near Hilo, Hawaii that is currently held for sale. WRI
also leases a three-quarter of an acre maintenance facility in Honolulu and a
one acre maintenance and storage facility with 2,800 square feet of interior
space in Kawaihae, Hawaii, and maintains drill and pump inventory. As of
September 30, 1998, WRI employed 16 drilling, pump and administrative employees,
none of whom are union members.
WRI drills both shallow and deep water wells in Hawaii. WRI also installs
and repairs water pumps after wells are completed. Additionally, WRI is a
distributor, in the state of Hawaii, for Centrilift pumps and equipment. Pump
installation and maintenance contracts are primarily obtained from municipal
water utilities. The demand for WRI's services is dependent upon land
development activities in Hawaii, which has decreased from prior years' levels.
WRI markets its services to land developers and government agencies, and
identifies potential contracts through public notices and referrals. Contracts
are usually fixed price contracts and are negotiated with private entities or
obtained through competitive bidding with various local, state and Federal
agencies. Contract revenues are not dependent upon the discovery of water, and
contracts are not subject to renegotiation of profits or termination at the
election of the governmental entities involved. Contracts provide for
arbitration in the event of disputes.
The Company's contract drilling subsidiary derived 42%, 73% and 42% of its
contract drilling revenues in fiscal 1998, 1997, and 1996, respectively,
pursuant to State of Hawaii and local county contracts. At September 30, 1998,
the Company had accounts receivable from the State of Hawaii and local county
entities totaling approximately $118,000. Additionally, the Company's contract
drilling segment had a net receivable from a private developer totaling
approximately $250,000. The Company has lien rights on contracts with the state
of Hawaii and local county entities and with the aforementioned private
developer.
The Company's contract drilling segment currently operates in Hawaii and
is not subject to seasonal fluctuations.
Activity
- --------
In fiscal 1998, WRI started three water well and three water well pump
installation contracts and completed one water well and six pump installation
contracts. The completed water well was started in the current fiscal year and
four of the six completed water well pump installations were started in the
prior year. Eighty-six percent (86%) of such well drilling and pump installation
jobs, representing 42% of total contract drilling revenues in fiscal 1998, have
been pursuant to government contracts. At September 30, 1998, WRI had a backlog
of five water well drilling and ten pump installation and repair contracts, two
and three of which, respectively, were in progress as of September 30, 1998.
<PAGE>
16
The dollar amount of the Company's backlog of firm well drilling and pump
installation and repair contracts at December 1 is as follows:
1998 1997
---------- ----------
Well drilling $1,500,000 $ -
Pump installation and repair 500,000 1,000,000
---------- ----------
$2,000,000 $1,000,000
========== ==========
All of the contracts in backlog at December 1, 1998 are expected to be
completed within fiscal year 1999.
Competition
- -----------
WRI utilizes rotary drill rigs which have the capability of drilling wells
faster than cable tool rigs. There are seven other drilling contractors in
Hawaii which use cable tool or rotary drill rigs that are capable of drilling
water wells, and seven other Hawaii contractors who are capable of installing
and repairing vertical turbine and submersible water pumping systems in Hawaii.
These contractors compete actively with WRI for government and private
contracts. Pricing is the Company's major method of competition; reliability of
service is also a major factor.
The Company expects competitive pressures within the industry to continue
as demand for water well drilling and pump installation in Hawaii is not
expected to increase significantly in the 1999 fiscal year.
LAND INVESTMENT OPERATIONS
--------------------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii joint venture. Between 1986 and 1989, Kaupulehu Developments obtained the
state and county zoning changes necessary to permit development of the Four
Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club, a planned
second golf course, and single and multiple family residential units on land
acquired from Kaupulehu Developments. Kaupulehu Developments currently owns
development rights in approximately 100 acres of residentially zoned leasehold
land and leasehold rights in approximately 2,100 acres of land located
approximately six miles north of the Kona International Airport in the North
Kona District of the Island of Hawaii.
Kaupulehu Developments' residential development rights in the
approximately 100 acres are under option to Hualalai Development Company, an
affiliate of Kajima Corporation of Japan. If Hualalai Development Company
exercises this option, the Company will receive a total of $16,157,000 in
connection with its 50.1% interest in Kaupulehu Developments. The option expires
on December 31, 1999, unless 20% of the total consideration is received on or
before December 31, 1999; on April 30, 2003 unless 50% of the then remaining
consideration is received on or before April 30, 2003; and the remainder of the
option would then expire on April 30, 2007. There is no assurance that this
option or any portion of it will be exercised.
Kaupulehu Developments also holds leasehold rights in approximately 2,100
acres of land located adjacent to and north of the Four Seasons Resort Hualalai
at Historic Ka'upulehu. Kaupulehu Developments is in the process of negotiating
a revised development agreement and residential fee purchase prices with the
lessor of the 2,100 acre parcel. Management cannot predict the outcome of these
negotiations.
<PAGE>
17
Activity
- --------
In June 1996, the State Land Use Commission ("LUC") approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of the
2,100 acres of land into the Urban District for resort/residential development.
Subsequent to the LUC's approval, a notice of appeal was filed with the Third
Circuit Court of the State of Hawaii by parties seeking to reverse the LUC's
decision. The Third Circuit Court of the State of Hawaii upheld the Land Use
Commission's approval of Kaupulehu Developments' rezoning request in all
respects in a Decision and Order issued in August 1997. In November 1997, a
notice of appeal was filed with the Supreme Court of the State of Hawaii by
parties seeking to reverse the Third Circuit Court's decision. The Company
anticipates that the Supreme Court of the State of Hawaii will rule on the
appeal in 1999 and management cannot predict the outcome of such appeal.
In addition to State of Hawaii approvals, Kaupulehu Developments must also
obtain additional approvals from the County of Hawaii. In June 1998, the
Kaupulehu Developments filed an Application for a Project District zoning
ordinance and a Special Management Area ("SMA") Use Permit Petition with the
County of Hawaii, requesting changes in zoning and use of approximately 1,000 of
the 2,100 acres of land to allow residential, resort and commercial development.
The SMA permit is granted by the Planning Commission of the County of Hawaii and
the zoning ordinance is passed by the Hawaii County Council following
recommendations for approval from the Planning Commission of the County of
Hawaii and the Planning Committee of the Hawaii County Council. In December
1998, following a contested case hearing procedure conducted in November, the
Planning Commission of the County of Hawaii granted the requested SMA use permit
to Kaupulehu Developments to be effective when the zoning ordinance is adopted.
The Planning Commission of the County of Hawaii and the Planning Committee of
the Hawaii County Council have both made favorable recommendations for approval
of the zoning ordinance, however, the Hawaii County Council has not as yet heard
or taken action on the zoning ordinance. Management cannot predict the outcome
of the county zoning petition and there is no assurance that these approvals
will be forthcoming at any time.
Competition
- -----------
The Company's land investment segment is subject to intense competition in
all phases of its operations including the acquisition of new properties, the
securing of approvals necessary for land rezoning, and the search for potential
buyers of property interests presently owned. The competition comes from
numerous independent land development companies and other industries involved in
land investment activities. The principal methods of competition are the
location of the project and pricing. Kaupulehu Developments is a minor
participant in the land development industry and competes in its land investment
activities with many other entities having far greater financial and other
resources.
For the past several years, Hawaii's economy has experienced little or no
growth and the real estate market has been slow. However, the South Kohala/North
Kona area of the island of Hawaii, the area in which Kaupulehu Developments'
property is located, has experienced a significant increase over recent years in
the number of and the median price of real estate sales. As of October 1998, the
Hualalai Resort, located in the first phase of land interests rezoned and sold
by Kaupulehu Developments, reports to have generated $172 million in sales in 91
transactions, for an average sales price of $1.9 million, since opening in late
1996. Management believes that the effects of the unstable Asian economies have
not had a significant detrimental impact on sales at the Hualalai Resort area as
the majority of the buyers in the area are reported to be from the western U.S.
<PAGE>
18
Item 3. Legal Proceedings
-----------------
In June 1996, the State Land Use Commission approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of land
into the Urban District for resort/residential development. Subsequent to the
Land Use Commission's approval, a notice of appeal was filed in the Third
Circuit Court of the State of Hawaii by Ka Lahui Hawai'i, Kona Hawaiian Civic
Club, Protect Kohanaiki Ohana and Plan to Protect (collectively, the
"Appellants") against the Land Use Commission, State of Hawaii; Office of State
Planning, State of Hawaii; County of Hawaii Planning Department; and Kaupulehu
Developments seeking to reverse the Land Use Commission's decision. The Third
Circuit Court of the State of Hawaii upheld the Land Use Commission's approval
of Kaupulehu Developments' rezoning request in all respects in a Decision and
Order issued in August 1997. In November 1997, the Appellants filed a notice of
appeal in the Supreme Court of the State of Hawaii seeking to reverse the Third
Circuit Court's decision. The Company anticipates that the Supreme Court of the
State of Hawaii will rule on the appeal in 1999 and management cannot predict
the outcome of such appeal.
The Company is involved in routine litigation and is subject to
governmental and regulatory controls that are incidental to the business. The
Company's management believes that routine claims and litigation involving the
Company are not likely to have a material adverse effect on its financial
position, results of operations or liquidity.
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
None.
PART II
Item 5. Market For Common Equity and Related Stockholder Matters
--------------------------------------------------------
The principal market on which the Company's common stock is being traded
is the American Stock Exchange. The following tables present the quarterly high
and low closing prices, on the American Stock Exchange, for the registrant's
common stock during the periods indicated:
Quarter Ended High Low Quarter Ended High Low
- ------------- ---- --- ------------- ---- ---
December 31, 1996 19 15-1/2 December 31, 1997 20 16-1/4
March 31, 1997 20-7/8 18 March 31, 1998 17-5/8 16-1/4
June 30, 1997 19-3/4 17 June 30, 1998 16-7/8 14
September 30, 1997 22-1/2 18 September 30, 1998 14-3/8 12-3/8
As of December 3, 1998, there were 1,316,952 shares of common stock, par
value $.50, outstanding. There were approximately 400 holders of the common
stock of the registrant as of December 3, 1998.
In May 1995, quarterly dividend payments were suspended and remain
suspended to date.
<PAGE>
19
Item 6. Management's Discussion and Analysis or Plan of Operation
---------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------
The following section contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended, including various
forecasts, projections of Barnwell's future performance, statements of the
Company's plans and objectives and other similar types of information. Although
the Company believes that its expectations are based on reasonable assumptions,
it cannot assure that the expectations contained in such forward-looking
statements will be achieved. Such statements involve risks, uncertainties and
assumptions, including, but not limited to, those relating to the factors
discussed below, in other portions of this Form 10-KSB, in the Notes to
Consolidated Financial Statements, and in other documents filed by the Company
with the Securities and Exchange Commission from time to time, which could cause
actual results to differ materially from those contained in such statements.
These forward-looking statements speak only as of the date of filing of this
Form 10-KSB, and the Company expressly disclaims any obligation or undertaking
to publicly release any updates or revisions to any forward-looking statements
contained herein.
Cash flows from operations were $2,961,000 in fiscal 1998, as compared to
$7,449,000 in fiscal 1997, a decrease of $4,488,000. The decrease was
principally due to lower operating results generated by both the oil and natural
gas segment and the contract drilling segment. Significant declines in oil and
natural gas liquids prices adversely impacted the oil and gas segment, and less
contract drilling work, due to Hawaii's poor economy, adversely impacted the
contract drilling segment. Oil and natural gas liquids prices declined 33% and
35%, respectively, from fiscal 1997 to fiscal 1998.
Fiscal 1998 operating cash flows were also impacted by the payment of
$900,000 of crown royalties accrued at September 30, 1997. As reported in the
Company's 10-KSB for the year ended September 30, 1997, the Province of Alberta
completed its royalty calculations in 1997 for calendar years 1994, 1995, 1996
and a portion of 1997. As a result of its initial calculations, the Province
remitted $630,000 to the Company in August 1997 for estimated overpaid
royalties. The Company recorded this receipt as a liability at September 30,
1997 as the Company had not overpaid royalties. In October 1997, after
completion of its final calculations, the Province submitted a $900,000 invoice
for underpaid royalties, which agreed with the Company's records; the Company
paid this invoice in October 1997.
The Company's revolving credit facility is with the Royal Bank of Canada
for $19,000,000 Canadian dollars or its U.S. dollar equivalent of approximately
$12,400,000 at September 30, 1998. The facility is reviewed annually with a
primary focus on the future cash flows that will be generated by the Company's
oil and natural gas properties. The next review is planned for February 1999.
Subject to that review, the facility may be extended one year with no required
debt repayments for one year, or converted to a 5-year term loan by the bank. If
the facility is converted to a 5-year term loan, the Company has agreed to the
following repayment schedule of the then outstanding balance: year 1 - 30%; year
2 - 27%; year 3 - 16%; year 4 - 14%; year 5 - 13%. The facility is
collateralized by the Company's interests in its major oil and natural gas
properties and a negative pledge on its remaining oil and natural gas
properties. No compensating bank balances are required on any of the Company's
indebtedness under the facility.
<PAGE>
20
The Company has $2,000,000 of convertible notes outstanding at September
30, 1998, that are payable in 20 consecutive, equal quarterly installments
beginning in October 1998. Interest is payable quarterly at a rate to be
adjusted each quarter to the greater of 10% per annum or 1% over the prime rate
of interest. The Company paid interest on these notes at the rate of 10% per
annum throughout fiscal 1998. In 1998, the Company, through Kaupulehu
Developments, obtained a $1,000,000 credit facility, increasable to $1,500,000
under certain conditions, with a Hawaii bank to finance the land investment
segment's rezoning expenditures. Total available credit and outstanding
borrowings under the land investment facility at September 30, 1998 amounted to
$635,000 and $365,000, respectively. For more information on the Company's
credit facilities, see Note 5 of "Notes to the Consolidated Financial
Statements" in Item 7.
At September 30, 1998, the Company's consolidated cash and cash
equivalents amounted to $2,178,000 and available credit under the Royal Bank of
Canada's revolving credit facility was approximately $700,000.
The Company's oil and natural gas capital expenditures in fiscal 1998
totaled $6,969,000. The Company participated in drilling 59 wells of which 45
were successful. In fiscal 1998, the Company's capital expenditures for oil and
natural gas properties increased $492,000 or 8% from the prior fiscal year. This
was due to a significant increase in capital expenditures at Dunvegan, the
Company's principal oil and gas property, where a new horizontal oil drilling
program was implemented and an ethane extraction facility was constructed. Total
capital expenditures at Dunvegan were $1,750,000. Significant capital
expenditures were also made at Red Earth, Thornbury, Pembina and Manyberries.
The following table sets forth the gross number of oil and natural gas
wells the Company participated in drilling and purchased for each of the last
three fiscal years:
1998 1997 1996
--------- --------- ---------
Development oil and natural
gas wells drilled 50 55 23
Exploratory oil and natural
gas wells drilled 9 17 14
Development oil and natural
gas wells purchased - - 3
Successful oil and natural
wells drilled and purchased 45 53 30
The Company has reduced its oil and natural gas capital expenditures
budget for fiscal 1999, as compared to the level of capital expenditures for
fiscal 1998, due to the decline in oil prices. The Company's current estimate
for fiscal 1999 capital expenditures is between $2,000,000 and $3,000,000.
<PAGE>
21
The following table sets forth the Company's capital expenditures for each
of the last three fiscal years:
1998 1997 1996
--------------- --------------- ------------
Oil and natural gas - U.S. $ 960,000 $1,750,000 $ 380,000
Oil and natural gas - Canada 6,009,000 4,727,000 4,669,000
---------- ---------- ----------
Total oil and natural gas 6,969,000 6,477,000 5,049,000
Land investment 862,000 733,000 646,000
Contract drilling 91,000 189,000 53,000
Other 205,000 97,000 219,000
---------- ---------- ----------
Total capital expenditures $8,127,000 $7,496,000 $5,967,000
========== ========== ==========
Increase in total
oil and natural gas capital
expenditures from prior year $ 492,000 $1,428,000 $1,615,000
========== ========== ==========
In fiscal 1998, $862,000 of the Company's capital expenditures were
applicable to the rezoning of leasehold land in North Kona, Hawaii, from
conservation to urban. These expenditures, comprised of legal, consulting and
planning fees as well as capitalized interest, were funded by both the Company
and through bank borrowings. As of September 30, 1998, the Company has advanced
$1,565,000 to Kaupulehu Developments. As mentioned above, the Company, through
Kaupulehu Developments, obtained a $1,500,000 credit facility with a Hawaii bank
to finance future rezoning costs; borrowings under the facility amounted to
$365,000 at September 30, 1998.
Starting in 1997, the Company took more of its oil and natural gas "in
kind" where the Company markets the products instead of having the operator of a
producing property market the products on the Company's behalf. This has
shortened the length of time that the Company's receivables are outstanding as
Barnwell gets paid directly, instead of by the operator for the property.
The Company believes its current cash balances, future cash flows from
operations, capability to provide additional collateral, and available credit
will be sufficient to fund its estimated capital expenditures, make the
scheduled repayments on its convertible notes and land investment borrowings,
and meet the repayment schedule on its Royal Bank of Canada facility, should the
Company or the Royal Bank of Canada elect to convert the facility to a term
loan.
The Company did not receive any revenues in fiscal 1998, 1997, and 1996
related to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments'
revenues specifically relate to sales of leasehold interests and development
rights, which do not occur every year.
The Company's computer systems are in the process of being upgraded. The
Company expects to complete its information systems upgrades, which are
represented to be Year 2000 compliant by respective vendors, by the summer of
1999. The Company estimates that the total combined internal and external cost
of upgrading information systems specifically for Year 2000 compliance to be
less than $30,000, and expects to fund these costs by utilizing cash flows from
operations. Analysis of embedded technology issues, including, but not limited
to, such items as microprocessors in petroleum and water pump controls, and
potential impacts relating to third parties with which the Company has a
material relationship is ongoing and to date has not brought to light evidence
of potential negative impacts. Expenditures related to Year 2000 compliance in
fiscal years 1998 and 1997 were not significant and were expensed as incurred.
<PAGE>
22
No amount of preparation and testing can guarantee Year 2000 compliance.
Accordingly, the Company is developing contingency plans to overcome the most
reasonably likely worst case scenarios which may result from failure by the
Company or third parties to complete their Year 2000 initiatives on a timely
basis. The Company expects to complete its contingency plans by September of
1999. Such contingency plans may include using alternative processes, such as
manual procedures or work-around applications to substitute for non-compliant
systems; arranging for alternate marketers, operators, and suppliers and service
providers; and developing procedures internally and in collaboration with
significant third parties to address compliance issues as they arise. There is
particular difficulty in the assessment of Year 2000 compliance of third
parties. Accordingly, the Company considers the potential disruptions caused by
such parties to present the most reasonably likely worst case scenarios. Adverse
effects on the Company could include business disruption, increased costs,
delays of sales and other similar ramifications.
The costs to address Year 2000 issues, the dates on which the Company
believes that it will complete activities to address such issues and the
Company's evaluation of third-party effects are estimates and subject to change.
Actual results could differ from those currently anticipated. Factors that could
cause such differences include, but are not limited to, the availability of key
Year 2000 project personnel, the ability of systems vendors to meet their
represented specifications and timetables, the Company's ability to respond to
unforeseen Year 2000 complications, the readiness of third parties, the accuracy
of third party assurances regarding Year 2000 compliance and similar
uncertainties.
RESULTS OF OPERATIONS
- ---------------------
Summary
-------
Barnwell reported a net loss of $3,890,000 in fiscal 1998, principally due
to non-cash write-downs of $2,995,000. Due to unsuccessful drilling results in
the Michigan Basin prospect, the Company and its joint venture partners
discontinued development of the prospect. Accordingly, the Company wrote off its
entire investment in the prospect, including additional costs for estimated site
restoration and abandonment. This write-off totalled $1,600,000. In addition,
due to unfavorable drilling results and a significant decline in oil prices, the
Company abandoned its remaining U.S. oil and gas prospects during fiscal 1998
and recorded a write-off of such properties of $1,130,000. The Company also
wrote down available-for-sale investment securities amounting to $95,000 and
contract drilling land and land improvements held for sale amounting to $170,000
as a result of recent declines in the market values of these assets. The
aforementioned write-downs, coupled with decreases of 33%, 35% and 5% in oil,
liquids and natural gas prices, respectively, and negative contract drilling
margins, resulted in the net loss for the Company of $3,890,000 in fiscal 1998,
a decrease of $4,940,000 from net earnings of $1,050,000 in fiscal 1997.
Barnwell reported net earnings of $1,050,000 in fiscal 1997, a decrease of
$180,000 from net earnings of $1,230,000 in fiscal 1996. This decrease was due
to (i) the fact that fiscal 1996 earnings included a $290,000 deferred income
tax benefit resulting from a decrease in the Canadian Branch tax rate; there was
no such benefit in fiscal 1997; (ii) a write-down of U.S. oil and gas properties
of $270,000 in fiscal 1997; and (iii) decreases in the volumes of natural gas
liquids, oil and natural gas sold in fiscal 1997 as compared to fiscal 1996 of
11%, 3% and 11%, respectively. These decreases were partially offset by 31%, 12%
and 27% increases in natural gas liquids, oil and natural gas prices,
respectively, in fiscal 1997, as compared to fiscal 1996.
<PAGE>
23
Barnwell reported net earnings of $1,230,000 in fiscal 1996, an increase
of $580,000 from net earnings of $650,000 in fiscal 1995. This increase was due
primarily to higher natural gas processing revenues, a $290,000 deferred income
tax benefit resulting from a decrease in the Canadian Branch tax rate and 11%
higher prices for both natural gas and oil and 22% higher prices for natural gas
liquids, partially offset by lower natural gas production. Additionally,
rezoning costs applicable to the leasehold land in Hawaii were capitalized in
fiscal 1996; such costs incurred during the first seven months of fiscal 1995
were related to land under option and accordingly expensed in fiscal 1995; such
expenses, net of minority interest in losses, amounted to approximately $220,000
before income taxes.
Oil and Natural Gas
- -------------------
Selected Operating Statistics
The following tables set forth the Company's annual net production and
annual average price per unit of production for fiscal 1998 as compared to
fiscal 1997, and fiscal 1997 as compared to fiscal 1996.
Fiscal 1998 - Fiscal 1997
- -------------------------
Annual Net Production
-------------------------------------------------------
Increase
(Decrease)
--------------------------
1998 1997 Units %
------------ ------------ ------------ ------------
Liquids (Bbl)* 65,000 65,000 - -
Oil (Bbl)* 210,000 199,000 11,000 6%
Natural gas (MCF)** 3,684,000 3,852,000 (168,000) (4%)
Annual Average Price Per Unit
-------------------------------------------------------
Increase
(Decrease)
--------------------------
1998 1997 $ %
------------ ------------ ------------ ------------
Liquids (Bbl)* $11.36 $17.55 $(6.19) (35%)
Oil (Bbl)* $13.02 $19.55 $(6.53) (33%)
Natural gas (MCF)** $ 1.38 $ 1.45 $(0.07) (5%)
Fiscal 1997 - Fiscal 1996
- -------------------------
Annual Net Production
-------------------------------------------------------
Increase
(Decrease)
--------------------------
1997 1996 Units %
------------ ------------ ------------ ------------
Liquids (Bbl)* 65,000 73,000 (8,000) (11%)
Oil (Bbl)* 199,000 206,000 (7,000) (3%)
Natural gas (MCF)** 3,852,000 4,347,000 (495,000) (11%)
Annual Average Price Per Unit
-------------------------------------------------------
Increase
(Decrease)
--------------------------
1997 1996 $ %
------------ ------------ ------------ ------------
Liquids (Bbl)* $17.55 $13.40 $ 4.15 31%
Oil (Bbl)* $19.55 $17.38 $ 2.17 12%
Natural gas (MCF)** $ 1.45 $ 1.14 $ 0.31 27%
*Bbl = stock tank barrel equivalent to 42 U.S. gallons
**MCF = 1,000 cubic feet
<PAGE>
24
Oil and natural gas revenues decreased $2,120,000 or 18% in fiscal 1998,
as compared to fiscal 1997, due to significant decreases in the average price
received for oil and natural gas liquids, and a 5% decrease in average gas
prices received. In addition, gas volumes decreased slightly, 4%, as compared to
fiscal 1997. This production decline was the result of normal production
declines at the Company's mature properties exceeding new production coming on
line. The decreases were partially offset by a 6% increase in oil volumes
brought about by new oil wells.
Operating expenses were relatively unchanged, decreasing $103,000 (3%) in
fiscal 1998, as compared to fiscal 1997. The Company expects oil and natural gas
operating expenses to increase on par with inflation due to competitive
pressures for services in the oil industry offset by higher costs associated
with certain older properties.
Oil and natural gas revenues increased $860,000 or 8% in fiscal 1997, as
compared to fiscal 1996, due to price increases for natural gas liquids (31%),
natural gas (27%), and oil (12%), partially offset by 11% declines in both
natural gas and natural gas liquids production and a 3% decline in oil
production. The decline in production was due to production declines in the
Company's more mature properties and to the reduction of its interest in
producing gas reserves in the Thornbury property due to the rationalization of
the Company's Thornbury property.
Operating expenses were relatively unchanged, decreasing $80,000 (2%) in
fiscal 1997, as compared to fiscal 1996.
Revenues were relatively unchanged, increasing $140,000 (1%) in fiscal
1996 as compared to fiscal 1995 due to price increases for natural gas (11%),
oil (11%) and natural gas liquids (22%), offset by 12% and 19% declines in
natural gas and natural gas liquids production, respectively. The declines in
natural gas and natural gas liquids production were due to production declines
at some Dunvegan wells. Decreased natural gas sales were supplanted with gas
processing revenues of an almost equal amount. Additionally, third parties spent
approximately $2,500,000 increasing the Dunvegan gas plant capacity so that the
plant can now process 200,000 MCF per day. These third parties did not earn an
interest in the gas plant with these expenditures but will be charged a lower
processing tariff.
Operating expenses were relatively unchanged, increasing $33,000 (1%) in
fiscal 1996, as compared to fiscal 1995, as costs remained relatively constant
and natural gas production declined 12%.
Contract Drilling
- -----------------
Contract drilling revenues and costs are associated with water well
drilling and water pump installation, replacement and repair in Hawaii. Demand
for well drilling and pump installation services is dependent upon land
development activities in Hawaii, which has decreased significantly from prior
years' levels. Demand for water pump replacement and repair is primarily
dependent upon the timing of water system renovations and replacements by water
utilities and other entities.
Contract drilling revenues decreased $650,000 (30%) in fiscal 1998, as
compared to fiscal 1997, due primarily to lower demand for both water well
drilling work and pump installation and to increased competition for these fewer
jobs. The increase in competition has driven contract bid prices down, resulting
in lower revenues and contract margins. Contract drilling operating costs
remained fairly constant (decreased $28,000 or 2%). As a result of the decrease
in contract prices, contract drilling operating results before depreciation
decreased to a loss of $482,000 in fiscal 1998, as compared to an operating
profit before depreciation of $310,000 in fiscal 1997. Included in fiscal 1998's
operating results is a $170,000 write-down of a contract drilling yard held for
sale.
<PAGE>
25
The Company expects competitive pressures within the industry to continue
as demand for water well drilling and pump installation in Hawaii is not
expected to increase significantly in the 1999 fiscal year. In an effort to
obtain drilling contracts, management investigated opportunities to relocate one
drilling rig to the continental U.S. to drill for oil or natural gas.
Unfortunately, the decline in oil prices has reduced the need for drilling rigs
and no attractive opportunities were located.
The Company has reduced its labor costs and was able to obtain two
contracts totaling approximately $1,500,000 in late fiscal 1998. At September
30, 1998 the Company had two drilling rigs operating concurrently and had a
backlog of ten pump installation and repair contracts and five water well
drilling contracts, three and two of which, respectively, were in progress as of
September 30, 1998. These fifteen contracts represent a backlog of contract
drilling revenues of approximately $2,000,000 as of December 1, 1998.
Contract drilling revenues and operating costs decreased $490,000 (18%)
and $35,000 (2%), respectively, in fiscal 1997 as compared to fiscal 1996. As a
result, operating profit before depreciation decreased $455,000 (59%) in fiscal
1997, as compared to fiscal 1996. Operating profit before depreciation as a
percentage of revenues decreased to 14%, as compared to 29% in fiscal 1996.
These decreases were due to lower demand for water well drilling work and to
increased competition for well drilling and pump installation and repair jobs.
Contract drilling revenues and operating costs decreased $1,120,000 (30%)
and $1,005,000 (35%), respectively, in fiscal 1996 as compared to fiscal 1995,
due to lower water well drilling activity in fiscal 1996. As a result of the
lower activity, operating profit before depreciation decreased $115,000 (13%) in
fiscal 1996, as compared to fiscal 1995. Operating profit before depreciation as
a percentage of revenues increased to 29%, as compared to 23% in fiscal 1995, as
the Company was able to reduce operating costs in fiscal 1996 by a higher
percentage than the decrease in revenues as a result of operational efficiencies
due to all contract drilling jobs during 1996 being in the same area.
Investment in Land
- ------------------
Kaupulehu Developments holds leasehold rights in approximately 2,100 acres
of land located adjacent to and north of the Four Seasons Resort Hualalai at
Historic Ka'upulehu. In June 1996, the State Land Use Commission ("LUC")
approved Kaupulehu Developments' petition for reclassification of approximately
1,000 acres of the 2,100 acres of land into the Urban District for
resort/residential development. Subsequent to the LUC's approval, a notice of
appeal was filed with the Third Circuit Court of the State of Hawaii by parties
seeking to reverse the LUC's decision. The Third Circuit Court of the State of
Hawaii upheld the Land Use Commission's approval of Kaupulehu Developments'
rezoning request in all respects in a Decision and Order issued in August 1997.
In November 1997, a notice of appeal was filed with the Supreme Court of the
State of Hawaii by parties seeking to reverse the Third Circuit Court's
decision. The Company anticipates that the Supreme Court of the State of Hawaii
will rule on the appeal in 1999 and management cannot predict the outcome of
such appeal.
In addition to State of Hawaii approvals, Kaupulehu Developments must also
obtain additional approvals from the County of Hawaii. In June 1998, the
Kaupulehu Developments filed an Application for a Project District zoning
ordinance and a Special Management Area ("SMA") Use Permit Petition with the
County of Hawaii, requesting changes in zoning and use of approximately 1,000 of
the 2,100 acres of land to allow residential, resort and commercial development.
The SMA permit is granted by the Planning Commission of the County of Hawaii and
the zoning ordinance is passed by the Hawaii County Council following
recommendations for approval from the Planning Commission of the County of
Hawaii and the Planning Committee of the Hawaii County Council. In December
1998, following a contested case hearing procedure conducted in November, the
Planning Commission of the County of Hawaii granted the requested SMA use permit
to Kaupulehu Developments to be effective when the zoning ordinance is adopted.
The Planning Commission of the County of Hawaii and the Planning Committee of
the Hawaii County Council have both made favorable recommendations for approval
of the zoning ordinance, however, the Hawaii County Council has not as yet heard
or taken action on the zoning ordinance. Management cannot predict the outcome
of either the state or county petitions and there is no assurance that these
approvals will be forthcoming at any time.
<PAGE>
26
Costs related to the rezoning of the conservation land are capitalized and
included in the consolidated balance sheets under the caption, "Investment in
Land." Such costs, comprised of legal, consulting and planning fees as well as
capitalized interest, amounted to $862,000, $733,000, and $646,000 for fiscal
1998, 1997, and 1996, respectively. For additional information regarding
Investment in Land, refer to Note 4 in the Notes to Consolidated Financial
Statements.
For the past several years, Hawaii's economy has experienced little or no
growth and the real estate market has been slow. However, the South Kohala/North
Kona area of the island of Hawaii, the area in which Kaupulehu Developments'
property is located, has experienced a significant increase over recent years in
the number of and the median price of real estate sales. As of October 1998, the
Hualalai Resort, located in the first phase of land interests rezoned and sold
by Kaupulehu Developments, reports to have generated $172 million in sales in 91
transactions, for an average sales price of $1.9 million, since opening in late
1996. Management believes that the effects of the unstable Asian economies have
not had a significant detrimental impact on sales at the Hualalai Resort area as
the majority of the buyers in the area are reported to be from the western U.S.
Gas Processing and Other Income
- -------------------------------
Gas processing and other income decreased $140,000 (12%) in fiscal 1998,
as compared to fiscal 1997, due to a decrease in interest income as a result of
lower average cash balances.
Gas processing and other income increased $280,000 (32%) in fiscal 1997,
as compared to fiscal 1996, due to an increase in the amount of gas processed
for third parties at the Dunvegan gas plants and an increase in interest income
as a result of higher average cash balances.
Gas processing and other income increased $210,000 (32%) in fiscal 1996,
as compared to fiscal 1995, due primarily to increased non-unit gas processed at
the Dunvegan gas plant, partially offset by a decrease in interest income as a
result of lower average cash balances and interest rates.
Write-down of Oil and Natural Gas Properties and Other Assets
- -------------------------------------------------------------
In November 1996, the Company entered into a participation agreement with
KEP Energy Resources, LLC and Presco Inc. to develop natural gas and oil
reserves in the Central Basin in Michigan.
The initial drilling program in Michigan included one new well, and seven
existing well bores, which were re-entered with the goal of producing natural
gas. One well was commercial and seven were non-commercial wells. A second
drilling program, comprised of six wells, commenced in 1998 in order to more
fully evaluate the extensive land position acquired in the Michigan Basin. The
target for three of the wells was the deep natural gas targeted in the initial
program, with the other three wells targeting shallower oil formations. These
six wells were not commercial.
<PAGE>
27
Under the full cost method of accounting, the amount of oil and natural
gas properties' capitalized costs less accumulated depletion (on a country by
country basis) is subject to a ceiling test limitation that requires any excess
of such costs over the present value of estimated future cash flows from proved
reserves to be expensed. As of March 31, 1998, the Company's investment in the
Michigan Basin prospect was determined to be impaired and was transferred to the
amortization base. Upon transfer, capitalized oil and natural gas properties'
costs in the United States exceeded the full cost ceiling test limitation and,
accordingly, the Company recorded a non-cash write-down of $2,070,000 in the
quarter ended March 31, 1998. Due to further declines in oil prices and
disappointing seismic and drilling results in North Dakota, the Company
abandoned its U.S. oil and natural gas prospects and recorded an additional U.S.
ceiling test write-down of $660,000 during the quarter ended June 30, 1998 to
fully write-off its investment in U.S. oil and natural gas properties.
In fiscal 1998, the Company also wrote down $170,000 of land and land
improvement costs related to a contract drilling yard held for sale due to a
decline in the market value of the property, and $95,000 of available-for-sale
securities due to a decline in market value deemed other than temporary.
In fiscal 1997, the Company recorded a U.S. oil and natural gas properties
ceiling test write-down of $270,000. This write-down was largely related to
activities in North Dakota where one dry well was drilled, a producing oil well
watered out and the independent engineer revised downward the estimate of
reserves in the remaining North Dakota wells. Additionally, the disappointing
results from the initial drilling program in the Michigan Basin prospect (8
wells were drilled, 1 of which was commercial), and a dry hole in Louisiana
contributed to the write-down.
General and Administrative Expenses
- -----------------------------------
General and administrative expenses increased $84,000 (3%) in fiscal 1998,
as compared to fiscal 1997, due to general inflationary increases.
General and administrative expenses increased $94,000 (3%) in fiscal 1997,
as compared to fiscal 1996, also due to general inflationary increases.
General and administrative expenses decreased $658,000 (17%) in fiscal
1996, as compared to fiscal 1995. This decrease was due to decreased outside
services, decreased foreign currency transaction losses, and rezoning costs.
Foreign currency transaction losses were immaterial in fiscal 1996 while foreign
currency transaction losses of $176,000 were included in general and
administrative expenses in fiscal 1995. $438,000 of costs incurred by Kaupulehu
Developments for the rezoning of leasehold property under option were included
in general and administrative expenses in fiscal 1995. In fiscal 1996, rezoning
costs incurred by Kaupulehu Developments were related to leasehold property no
longer under option and were accordingly capitalized and included in investment
in land.
Depreciation, Depletion and Amortization
- ----------------------------------------
Depreciation, depletion and amortization expense increased $124,000 (4%)
to $2,898,000 in fiscal 1998, as compared to $2,774,000 in fiscal 1997, due to
an 11% increase in the depletion rate per MCF equivalent, partially offset by a
decline in production volumes. The higher depletion rate is the result of
increased extraction and processing costs for proven reserves. The increase in
depletion was also partially offset by decreased depreciation expense resulting
from certain water well drilling assets becoming fully depreciated in fiscal
1997.
<PAGE>
28
Depreciation, depletion and amortization expense decreased $186,000 (6%)
to $2,774,000 in fiscal 1997, as compared to $2,960,000 in fiscal 1996, due to
an 11% decline in natural gas production and a 5% decline in combined oil and
liquids production and decreased depreciation expense resulting from certain
water well drilling assets becoming fully depreciated in fiscal 1996. These
items were partially offset by a 5% higher depletion rate per MCF equivalent.
Depreciation, depletion and amortization expense decreased $143,000 (5%)
to $2,960,000 in fiscal 1996, as compared to $3,103,000 in fiscal 1995, due to
certain contract drilling assets having been fully depreciated in fiscal 1995
and a 12% decline in natural gas production, partially offset by a 10% higher
depletion rate per MCF equivalent. The depletion rate per MCF equivalent
increased to $0.44 per MCF equivalent in fiscal 1996 from $0.40 per MCF
equivalent in fiscal 1995 due to higher finding costs for proven reserve
additions in 1996 as compared to earlier years.
Interest Expense
- ----------------
Interest expense increased $98,000 (16%) in fiscal 1998, as compared to
fiscal 1997, due primarily to higher average loan balances and interest rates.
The average interest rate incurred during fiscal 1998 on the Company's
$11,665,000 of debt with the Royal Bank of Canada increased to 6.67% as compared
to 6.35% in fiscal 1997, the interest rate on the $2,000,000 of convertible
notes in fiscal 1998 was unchanged at 10.00% per annum, and the average interest
rate on Kaupulehu Developments' $365,000 of borrowings was 10.00% in fiscal
1998.
Interest expense decreased $83,000 (12%) in fiscal 1997, as compared to
fiscal 1996, due to an $82,000 increase in capitalization of interest costs
related to the Company's investments in land in Hawaii and unproven undeveloped
oil and natural gas properties in Michigan. The average interest rate incurred
during fiscal 1997 on the Company's $9,100,000 of debt with the Royal Bank of
Canada remained essentially unchanged at 6.35% from 6.33% in fiscal 1996, and
the interest rate on the $2,000,000 of convertible notes in fiscal 1997 was
unchanged at 10% per annum from fiscal 1996.
Interest expense decreased $49,000 (6%) in fiscal 1996, as compared to
fiscal 1995, due to lower average interest rates and average loan balances on
the Company's credit facility borrowings with the Royal Bank of Canada, and a
$74,000 increase in capitalization of interest costs related to the Company's
investment in land. This was partially offset by higher interest expense
attributable to the convertible notes that were issued in June 1995 and thus
outstanding for only four months in fiscal 1995. The average interest rate paid
during fiscal 1996 on the Company's debt with the Royal Bank of Canada decreased
from an average of 6.47% in fiscal 1995 to 6.33% in fiscal 1996. The interest
rate on the convertible notes was 10% per annum during both fiscal 1996 and the
last four months of fiscal 1995.
Foreign Currency Fluctuations
- -----------------------------
The Company conducts foreign operations in Canada. Consequently, the
Company is subject to foreign currency transaction gains and losses due to
fluctuations of the exchange rates between the Canadian dollar and the U.S.
dollar. Foreign currency transaction gains and losses were not material in
fiscal 1998, 1997 and 1996. The Company cannot accurately predict future
fluctuations between the Canadian and U.S. dollars.
<PAGE>
29
Taxes
- -----
In fiscal 1998, 1997, and 1996, the provision for income taxes does not
bear a normal relationship to earnings because Canadian taxes were payable on
the Canadian operations and losses from U.S. operations provide no foreign tax
benefits.
In November 1995, officials of the U.S. and Canada ratified a new
agreement amending the Canada-U.S. Tax Treaty that reduced the Canadian Branch
tax. This change resulted in the recognition of a deferred Canadian income tax
benefit of $290,000 in fiscal 1996.
Environmental Matters
- ---------------------
Federal, state, and Canadian governmental agencies issue rules and
regulations and enforce laws to protect the environment which are often
difficult and costly to comply with and which carry substantial penalties for
failure to comply, particularly in regard to the discharge of materials into the
environment. The regulatory burden on the oil and gas industry increases its
cost of doing business. These laws, rules and regulations affect the operations
of the Company and could have a material adverse effect upon the capital
expenditures, earnings or competitive position of the Company. Although
Barnwell's experience has been to the contrary, there is no assurance that this
will continue to be the case.
Inflation
- ---------
The effect of inflation on the Company has generally been to increase its
cost of operations, interest cost (as a substantial portion of the Company's
debt is at variable short-term rates of interest which tend to increase as
inflation increases), general and administrative costs and direct costs
associated with oil and natural gas production and contract drilling operations.
In the case of contract drilling, the Company has not been able to increase its
contract revenues to fully compensate for increased costs. In the case of oil
and natural gas, prices realized by the Company are essentially determined by
world prices for oil and western Canadian/California U.S. prices for natural
gas.
New Statements of Financial Accounting Standards and Statements of Position
- ---------------------------------------------------------------------------
In June 1997, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 130, "Reporting Comprehensive Income." SFAS No. 130 establishes
standards for reporting and display of comprehensive income and its components
(revenues, expenses, gains and losses) in a full set of general-purpose
financial statements. This statement requires that all items currently
recognized under accounting standards as components of comprehensive income be
reported in a financial statement that is displayed with the same prominence as
other financial statements and is effective for fiscal years beginning after
December 15, 1997. SFAS No. 130 requires reclassification of financial
statements presented for earlier periods. The Company will adopt the provisions
of SFAS No. 130 in the first quarter of fiscal 1999. The Company conducts
operations in Canada and the assets and liabilities and income and expense items
of the foreign operations are translated at exchange rates in effect as of and
for the period ending on the financial statement date. The resulting translation
gains and losses are accounted for in a stockholders' equity account entitled
"Foreign currency translation adjustments." Under SFAS No. 130, these foreign
currency translation gains and losses will be included as a component of
comprehensive income. Foreign currency fluctuations can occur rapidly and
management expects that these fluctuations will at times be material to
comprehensive income. The Company cannot accurately predict future fluctuations
between the Canadian and U.S. dollars.
<PAGE>
30
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This statement provides
guidance for public business enterprises in reporting information about
operating segments in annual financial statements and requires that those
enterprises report selected information about operating segments in interim
financial reports to shareholders. This statement also establishes standards for
related disclosures about products and services, geographic areas and major
customers. This statement is effective for fiscal years beginning after December
15, 1997. The Company will adopt the provisions of SFAS No. 131 in the first
quarter of fiscal 1999. SFAS No. 131 requires restatement of comparative
information presented for earlier periods. Management does not expect adoption
of SFAS No. 131 will have a material effect on the Company's reported financial
information.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits," which amends the disclosure
requirements of SFAS No. 87, "Employers' Accounting for Pensions," SFAS No. 88,
"Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits," and SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." This statement
standardizes the disclosure requirements of SFAS No.'s 87 and 106 to the extent
practicable and recommends a parallel format for presenting information about
pensions and other postretirement benefits. SFAS No. 132 addresses disclosure
only and does not change any of the measurement or recognition provisions
provided for in SFAS No.'s 87, 88 or 106. This statement is effective for
periods beginning after December 15, 1997. The Company will adopt the provisions
of SFAS No. 132 in the first quarter of fiscal 1999. SFAS No. 132 requires
restatement of comparative information presented for earlier periods. Management
does not expect adoption of SFAS No. 132 will have a material effect on the
Company's reported financial information.
In March 1998, the American Institute of Certified Public Accountants
("AICPA") Accounting Standards Executive Committee issued Statement of Position
("SOP") 98-1, "Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use," which requires that certain costs, including certain
payroll and payroll-related costs, be capitalized and amortized over the
estimated useful life of the software. The provisions of SOP 98-1 are effective
for fiscal years beginning after December 31, 1998. The Company plans to adopt
the provisions of SOP 98-1 in the first quarter of fiscal 1999. Management
estimates that the adoption of SOP 98-1 will not have a material effect on the
Company's financial condition, results of operations or liquidity.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which establishes accounting and reporting
standards for derivative instruments and hedging activities and requires that an
entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value. The
provisions of SFAS No. 133 are effective for all fiscal quarters of fiscal years
beginning after June 15, 1999. The Company has not determined when it will adopt
SFAS No. 133. The Company currently holds no derivative instruments, nor is it
currently participating in hedging activities.
<PAGE>
31
Item 7. FINANCIAL STATEMENTS
--------------------
Independent Auditors' Report
----------------------------
The Board of Directors
Barnwell Industries, Inc.:
We have audited the consolidated financial statements of Barnwell Industries,
Inc. and subsidiaries as listed in the index at Part III, Item 13. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Barnwell Industries,
Inc. and subsidiaries as of September 30, 1998 and 1997, and the results of
their operations and their cash flows for each of the years in the three-year
period ended September 30, 1998, in conformity with generally accepted
accounting principles.
/s/ KPMG Peat Marwick LLP
Honolulu, Hawaii
December 4, 1998
<PAGE>
32
<TABLE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<CAPTION>
ASSETS
- ------ September 30,
---------------------------
CURRENT ASSETS: 1998 1997
----------- -----------
<S> <C> <C>
Cash and cash equivalents $ 2,178,000 $ 4,402,000
Accounts receivable, net (Notes 3 and 13) 1,593,000 2,065,000
Royalty tax credit and taxes receivable 350,000 223,000
Costs and estimated earnings in excess of
billings on uncompleted contracts (Note 3) 112,000 30,000
Deferred income taxes (Note 6) 130,000 100,000
Inventories and other current assets 263,000 132,000
----------- -----------
TOTAL CURRENT ASSETS 4,626,000 6,952,000
----------- -----------
INVESTMENT IN LAND (Notes 4 and 5) 2,710,000 1,848,000
----------- -----------
OTHER ASSETS 213,000 491,000
----------- -----------
PROPERTY AND EQUIPMENT (Notes 5 and 10):
Land 478,000 631,000
Oil and natural gas properties
(full cost accounting):
Properties being amortized 44,842,000 44,369,000
Properties not subject to amortization 628,000 2,405,000
Drilling rigs and equipment 7,934,000 8,104,000
Other property and equipment 2,335,000 2,682,000
----------- -----------
56,217,000 58,191,000
Accumulated depreciation,
depletion and amortization 32,105,000 33,084,000
----------- -----------
TOTAL PROPERTY AND EQUIPMENT 24,112,000 25,107,000
----------- -----------
TOTAL ASSETS $31,661,000 $34,398,000
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable $ 2,836,000 $ 3,180,000
Accrued expenses 1,963,000 1,213,000
Billings in excess of costs and estimated
earnings on uncompleted contracts (Note 3) 201,000 31,000
Payable to joint interest owners 250,000 920,000
Current portion of long-term debt (Note 5) 400,000 -
Income taxes payable (Note 6) - 3,000
----------- -----------
TOTAL CURRENT LIABILITIES 5,650,000 5,347,000
----------- -----------
LONG-TERM DEBT (Note 5) 13,630,000 11,100,000
----------- -----------
DEFERRED INCOME TAXES (Note 6) 5,637,000 5,801,000
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 7, 8 and 9)
STOCKHOLDERS' EQUITY (Notes 5 and 8):
Common stock, par value $.50 per share:
Authorized, 4,000,000 shares
Issued, 1,642,797 shares 821,000 821,000
Additional paid-in capital 3,103,000 3,103,000
Retained earnings 11,281,000 15,171,000
Foreign currency translation adjustments (3,672,000) (2,251,000)
Unrealized holding gains on securities - 11,000
Treasury stock, at cost,
325,845 shares in 1998 and 320,745 shares in 1997 (4,789,000) (4,705,000)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY 6,744,000 12,150,000
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $31,661,000 $34,398,000
=========== ===========
<FN>
See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>
33
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended September 30,
-------------------------------------------
1998 1997 1996
---------- -------------- --------------
Revenues:
Oil and natural gas $ 9,400,000 $11,520,000 $10,660,000
Contract drilling 1,510,000 2,160,000 2,650,000
Gas processing and other 1,010,000 1,150,000 870,000
----------- ----------- -----------
11,920,000 14,830,000 14,180,000
----------- ----------- -----------
Costs and expenses:
Oil and natural gas operating 3,223,000 3,326,000 3,406,000
Write-down of oil and natural gas
properties and other
assets (Note 10) 2,995,000 270,000 -
Contract drilling operating 1,822,000 1,850,000 1,885,000
General and administrative 3,292,000 3,208,000 3,114,000
Depreciation, depletion
and amortization 2,898,000 2,774,000 2,960,000
Interest expense, net (Note 5) 722,000 624,000 707,000
----------- ---------- -----------
14,952,000 12,052,000 12,072,000
----------- ---------- -----------
(Loss) earnings before income taxes (3,032,000) 2,778,000 2,108,000
Provision for income taxes (Note 6) 858,000 1,728,000 878,000
----------- ---------- -----------
NET (LOSS) EARNINGS $(3,890,000) $1,050,000 $ 1,230,000
=========== ========== ===========
BASIC AND DILUTED
NET (LOSS) EARNINGS PER SHARE $(2.95) $0.79 $0.93
=========== ========== ===========
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING
BASIC 1,319,719 1,322,052 1,322,052
=========== ========== ===========
DILUTED 1,319,719 1,325,963 1,324,440
=========== ========== ===========
See Notes to Consolidated Financial Statements
<PAGE>
34
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended September 30,
-------------------------------------
1998 1997 1996
----------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) earnings $(3,890,000) $1,050,000 $1,230,000
Adjustments to reconcile
net (loss) earnings to net cash
provided by operating activities:
Depreciation, depletion
and amortization 2,898,000 2,774,000 2,960,000
Deferred income taxes 524,000 886,000 237,000
Write-down of assets 2,995,000 270,000 -
----------- ---------- ----------
2,527,000 4,980,000 4,427,000
Increase from changes in
current assets and
liabilities (Note 14) 434,000 2,469,000 1,273,000
----------- ---------- ----------
Net cash provided
by operating activities 2,961,000 7,449,000 5,700,000
----------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (8,127,000) (7,496,000) (5,967,000)
Decrease (increase) in other assets 8,000 (17,000) 285,000
Proceeds from sale of
oil and natural gas properties
and other equipment 93,000 977,000 414,000
----------- ---------- ----------
Net cash used in
investing activities (8,026,000) (6,536,000) (5,268,000)
----------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt borrowings 3,067,000 - -
Purchases of common
stock for treasury (84,000) - -
Net contributions from joint
venture minority interest owner - - 180,000
----------- ---------- ----------
Net cash provided
by financing activities 2,983,000 - 180,000
----------- ---------- -----------
Effect of exchange rate changes
on cash and cash equivalents (142,000) (64,000) (35,000)
----------- ---------- ----------
Net (decrease) increase in
cash and cash equivalents (2,224,000) 849,000 577,000
Cash and cash equivalents
at beginning of year 4,402,000 3,553,000 2,976,000
----------- ---------- ----------
Cash and cash equivalents
at end of year $ 2,178,000 $4,402,000 $3,553,000
=========== ========== ==========
See Notes to Consolidated Financial Statements
<PAGE>
35
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Foreign Unrealized
Additional Currency Holding
Common Stock 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, 1995 1,642,797 $821,000 $3,103,000 $12,891,000 $(1,683,000) $(65,000) $(4,705,000)
Net earnings - - - 1,230,000 - - -
Foreign currency
translation adjustments - - - - (242,000) - -
Unrealized holding
gain on securities - - - - - 53,000 -
--------- -------- ---------- ----------- ----------- -------- -----------
Balances at September 30, 1996 1,642,797 821,000 3,103,000 14,121,000 (1,925,000) (12,000) (4,705,000)
Net earnings - - - 1,050,000 - - -
Foreign currency
translation adjustments - - - - (326,000) - -
Unrealized holding
gain on securities - - - - - 23,000 -
--------- -------- ---------- ----------- ----------- -------- -----------
Balances at September 30, 1997 1,642,797 821,000 3,103,000 15,171,000 (2,251,000) 11,000 (4,705,000)
Net loss - - - (3,890,000) - - -
Foreign currency
translation adjustments - - - - (1,421,000) - -
Purchase of 5,100 common
shares for treasury - - - - - - (84,000)
Unrealized holding
loss on securities - - - - - (11,000) -
--------- -------- ---------- ----------- ----------- -------- -----------
BALANCES AT SEPTEMBER 30, 1998 1,642,797 $821,000 $3,103,000 $11,281,000 $(3,672,000) $ - $(4,789,000)
========= ======== ========== =========== =========== ======== ===========
<FN>
See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>
36
BARNWELL INDUSTRIES, INC.
-------------------------
AND SUBSIDIARIES
----------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
YEARS ENDED SEPTEMBER 30, 1998, 1997, AND 1996
----------------------------------------------
1. DESCRIPTION OF THE REPORTING ENTITY AND BUSINESS
------------------------------------------------
The consolidated financial statements include the accounts of Barnwell
Industries, Inc. and all majority-owned subsidiaries, including a land
development joint venture (collectively referred to herein as "Company"). All
significant intercompany accounts and transactions have been eliminated.
During its last three completed fiscal years, the Company was engaged in
exploring for, developing, producing and selling oil and natural gas in Canada
and the United States, investing in leasehold land in Hawaii, and drilling water
wells and installing and repairing water pumping systems in Hawaii. The
Company's oil and natural gas activities comprise its largest business segment.
Approximately 79% of the Company's revenues and 86% of the Company's capital
expenditures for the fiscal year ended September 30, 1998 were attributable to
its oil and natural gas activities. The Company's contract drilling activities
accounted for 13% of the Company's revenues in fiscal 1998 with gas processing
and other revenues comprising the remaining 8%. The Company had no land
investment revenue in 1998; land investment revenues relate to sales of
leasehold interests and development rights, which do not occur every year.
Changes in the marketplace of any of the aforementioned industries may
significantly affect management's estimates and the Company's performance.
2. SIGNIFICANT ACCOUNTING POLICIES
-------------------------------
Cash and cash equivalents
- -------------------------
Cash and cash equivalents includes cash on hand, demand deposits and
short-term investments with maturities of three months or less.
Oil and natural gas properties
- ------------------------------
The Company uses the full cost method of accounting under which all costs
incurred in the acquisition, exploration and development of oil and natural gas
reserves, including unsuccessful wells, are capitalized until such time as the
aggregate of such costs, on a country by country basis, equals the discounted
present value (at 10%) of the Company's estimated future net cash flows from
estimated production of proved oil and natural gas reserves, as determined by
independent petroleum engineers, less related income tax effects. Any
capitalized costs in excess of the discounted present value are charged to
expense. Depletion of all such costs, except costs related to major development
projects, is provided by the unit-of-production method based upon proved oil and
natural gas reserves of all properties on a country by country basis.
Investments in major development projects are not amortized until proved
reserves associated with the projects can be determined or until impairment
occurs. If the results of an assessment indicate that the properties are
impaired, the amount of the impairment is added to the capitalized costs to be
amortized. General and administrative costs related to oil and natural gas
operations are expensed as incurred. Estimated future site restoration and
abandonment costs are charged to earnings at the rate of depletion and are
included in accumulated depreciation, depletion and amortization. Proceeds from
the disposition of minor producing oil and natural gas properties are credited
to the cost of oil and natural gas properties. Gains or losses are recognized on
the disposition of significant oil and natural gas properties.
<PAGE>
37
Contract drilling
- -----------------
Revenues, costs and profits applicable to contract drilling contracts are
included in the consolidated statements of operations using the percentage of
completion method, principally measured by the percentage of labor dollars
incurred to date for each contract to total estimated labor dollars for each
contract. Contract losses are recognized in full in the year the losses are
identified. The performance of drilling contracts may extend over more than one
year and, in the interim periods, estimates of total contract costs and profits
are used to determine revenues and profits earned for reporting the results of
the contract drilling operations. Revisions in the estimates required by
subsequent performance and final contract settlements are included as
adjustments to the results of operations in the period such revisions and
settlements occur. Contracts are normally less than one year in duration.
Investment in land and revenue recognition
- ------------------------------------------
The Company's investment in land is comprised of land under development
and development rights under option. Investment in land under development is
evaluated for impairment whenever events or changes in circumstances indicate
that the recorded investment balance may not be fully recoverable. Development
rights under option is reported at the lower of the asset carrying value or fair
value, less cost to sell.
Land sales for development rights under option as of September 30, 1998
are accounted for under the cost recovery method. Under the cost recovery
method, no gain is recognized until cash received exceeds the cost and the
estimated future costs related to the development rights sold. The accompanying
consolidated balance sheets include no cost for development rights under option
and, accordingly, cash receipts, if any, in excess of costs will be reported as
revenues. The Company's cost, including capitalized interest, of the land under
development is included in the consolidated balance sheets under the caption
"Investment in Land."
Long-Lived Assets
- -----------------
Long-lived assets to be held and used, other than oil and natural gas
properties, are evaluated for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be fully
recoverable. If the future cash flows expected to result from use of the asset
(undiscounted and without interest charges) are less than the carrying amount of
the asset, an impairment loss is recognized. Such impairment loss is measured as
the amount by which the carrying amount of the asset exceeds the fair value of
the asset. Long-lived assets to be disposed of are reported at the lower of the
asset carrying value or fair value, less cost to sell.
Drilling rigs and other equipment
- ---------------------------------
Drilling rigs and other equipment are stated at cost. Depreciation is
computed using the straight-line method based on estimated useful lives.
Inventories
- -----------
Inventories are comprised of drilling materials and are valued at the
lower of weighted average cost or market value.
<PAGE>
38
Environmental
- -------------
The Company is subject to extensive environmental laws and regulations.
These laws, which are constantly changing, regulate the discharge of materials
into the environment and maintenance of surface conditions and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are expensed. Liabilities
for expenditures of a noncapital nature are recorded when environmental
assessment and/or remediation is probable, and the costs can be reasonably
estimated.
Income taxes
- ------------
Deferred income taxes are determined using the asset and liability method.
Deferred tax assets and liabilities are recognized for the estimated future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
in effect for the year in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes the
enactment date.
Earnings per share
- ------------------
The Company adopted the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 128, "Earnings per Share," effective October 1, 1997. The
new standard replaced the presentation of primary and fully diluted earnings per
share ("EPS") with a presentation of basic and diluted EPS, respectively. The
new standard also requires dual presentation of basic and diluted EPS on the
face of the income statement and requires a reconciliation of the numerator and
denominator of the basic EPS computation to the numerator and denominator of the
diluted EPS computation. Prior year EPS amounts have been restated to conform
with the provisions of SFAS No. 128.
Basic EPS excludes dilution and is computed by dividing net (loss)
earnings by the weighted-average common shares outstanding for the period. The
weighted-average common shares outstanding was 1,319,719 for the year ended
September 30, 1998 and 1,322,052 for the years ended September 30, 1997 and
1996.
Diluted EPS includes the potentially dilutive effect of outstanding common
stock options and securities which are convertible to common shares. The
weighted-average number of common and potentially dilutive common shares for the
years ended September 30, 1998, 1997 and 1996 was 1,319,719, 1,325,963 and
1,324,440, respectively. Assumed conversion of common stock options is excluded
from the computation of diluted EPS for the year ended September 30, 1998
because its effect would be antidilutive. As of September 30, 1998, options to
acquire 67,500 shares of the Company's common stock were outstanding. Assumed
conversion of the Company's convertible debentures to 100,000 shares of common
stock was also excluded from the computation of diluted EPS for all periods
presented because its effect would be antidilutive.
<PAGE>
39
Reconciliations between the numerators and denominators of the basic and
diluted EPS computations for the years ended September 30, 1997 and 1996 are as
follows:
Year ended September 30, 1997
--------------------------------------------
Net Earnings Shares Per-Share
(Numerator) (Denominator) Amount
-------------- -------------- -----------
Basic earnings per share $1,050,000 1,322,052 $ 0.79
Effect of dilutive securities -
common stock options - 3,911 -
---------- ---------- ------
Diluted earnings per share $1,050,000 1,325,963 $ 0.79
========== ========== ======
Year ended September 30, 1996
--------------------------------------------
Net Earnings Shares Per-Share
(Numerator) (Denominator) Amount
-------------- -------------- -----------
Basic earnings per share $1,230,000 1,322,052 $ 0.93
Effect of dilutive securities -
common stock options - 2,388 -
---------- ---------- ------
Diluted earnings per share $1,230,000 1,324,440 $ 0.93
========== ========== ======
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 or losses were not material in fiscal years 1998, 1997 and
1996.
New Statements of Financial Accounting Standards and Statements of Position
- ---------------------------------------------------------------------------
In June 1997, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 130, "Reporting Comprehensive Income." SFAS No. 130 establishes
standards for reporting and display of comprehensive income and its components
(revenues, expenses, gains and losses) in a full set of general-purpose
financial statements. This statement requires that all items currently
recognized under accounting standards as components of comprehensive income be
reported in a financial statement that is displayed with the same prominence as
other financial statements and is effective for fiscal years beginning after
December 15, 1997. SFAS No. 130 requires reclassification of financial
statements presented for earlier periods. The Company will adopt the provisions
of SFAS No. 130 in the first quarter of fiscal 1999. The Company conducts
operations in Canada and the assets and liabilities and income and expense items
of the foreign operations are translated at exchange rates in effect as of and
for the period ending on the financial statement date. The resulting translation
gains and losses are accounted for in a stockholders' equity account entitled
"Foreign currency translation adjustments." Under SFAS No. 130, these foreign
currency translation gains and losses will be included as a component of
comprehensive income. Foreign currency fluctuations can occur rapidly and
management expects that these fluctuations will at times be material to
comprehensive income. The Company cannot accurately predict future fluctuations
between the Canadian and U.S. dollars.
<PAGE>
40
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This statement provides
guidance for public business enterprises in reporting information about
operating segments in annual financial statements and requires that those
enterprises report selected information about operating segments in interim
financial reports to shareholders. This statement also establishes standards for
related disclosures about products and services, geographic areas and major
customers. This statement is effective for fiscal years beginning after December
15, 1997. The Company will adopt the provisions of SFAS No. 131 in the first
quarter of fiscal 1999. SFAS No. 131 requires restatement of comparative
information presented for earlier periods. Management does not expect adoption
of SFAS No. 131 will have a material effect on the Company's reported financial
information.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits," which amends the disclosure
requirements of SFAS No. 87, "Employers' Accounting for Pensions," SFAS No. 88,
"Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits," and SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." This statement
standardizes the disclosure requirements of SFAS No.'s 87 and 106 to the extent
practicable and recommends a parallel format for presenting information about
pensions and other postretirement benefits. SFAS No. 132 addresses disclosure
only and does not change any of the measurement or recognition provisions
provided for in SFAS No.'s 87, 88 or 106. This statement is effective for
periods beginning after December 15, 1997. The Company will adopt the provisions
of SFAS No. 132 in the first quarter of fiscal 1999. SFAS No. 132 requires
restatement of comparative information presented for earlier periods. Management
does not expect adoption of SFAS No. 132 will have a material effect on the
Company's reported financial information.
In March 1998, the American Institute of Certified Public Accountants
("AICPA") Accounting Standards Executive Committee issued Statement of Position
("SOP") 98-1, "Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use," which requires that certain costs, including certain
payroll and payroll-related costs, be capitalized and amortized over the
estimated useful life of the software. The provisions of SOP 98-1 are effective
for fiscal years beginning after December 31, 1998. The Company plans to adopt
the provisions of SOP 98-1 in the first quarter of fiscal 1999. Management
estimates that the adoption of SOP 98-1 will not have a material effect on the
Company's financial condition, results of operations or liquidity.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which establishes accounting and reporting
standards for derivative instruments and hedging activities and requires that an
entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value. The
provisions of SFAS No. 133 are effective for all fiscal quarters of fiscal years
beginning after June 15, 1999. The Company has not determined when it will adopt
SFAS No. 133. The Company currently holds no derivative instruments, nor is it
currently participating in hedging activities.
Use of Estimates in the Preparation of Financial Statements
- -----------------------------------------------------------
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and the disclosure of contingent assets and liabilities. Actual
results could differ significantly from those estimates. Significant assumptions
are required in the valuation of deferred tax assets and proved oil and natural
gas reserves, and such assumptions may impact the amount at which deferred tax
assets and oil and natural gas properties are recorded.
<PAGE>
41
Reclassification
- ----------------
Certain reclassifications have been made to the fiscal 1997 financial
statements to conform to classifications used in the fiscal 1998 financial
statements. Such reclassifications had no effect on previously reported results
of operations.
3. RECEIVABLES AND CONTRACT COSTS
------------------------------
Accounts receivable, current, are net of allowances for doubtful accounts
of $86,000 and $10,000 as of September 30, 1998 and 1997, respectively. Included
in accounts receivable are contract retainage balances of $199,000 and $136,000
as of September 30, 1998 and 1997, respectively. These balances are expected to
be collected within one year, generally within 45 days after the related
contracts have received final acceptance and approval.
Costs and estimated earnings on uncompleted contracts are as follows:
September 30,
---------------------------
1998 1997
------------ -------------
Costs incurred on uncompleted contracts $ 1,588,000 $ 877,000
Estimated earnings 172,000 405,000
----------- ----------
1,760,000 1,282,000
Less billings to date 1,849,000 1,283,000
----------- ----------
$ (89,000) $ (1,000)
=========== ==========
Costs and estimated earnings on uncompleted contracts are included in the
consolidated balance sheets under the following captions:
September 30,
---------------------------
1998 1997
------------ -------------
Costs and estimated earnings
in excess of billings on uncompleted contracts $ 112,000 $ 30,000
Billings in excess of costs
and estimated earnings on uncompleted contracts (201,000) (31,000)
---------- ----------
$ (89,000) $ (1,000)
========= ==========
4. INVESTMENT IN LAND
------------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii joint venture. Between 1986 and 1989, Kaupulehu Developments obtained the
state and county zoning changes necessary to permit development of the Four
Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club, a planned
second golf course, and single and multiple family residential units on land
acquired from Kaupulehu Developments. Kaupulehu Developments currently owns
development rights in approximately 100 acres of residentially zoned leasehold
land and leasehold rights in approximately 2,100 acres of land located
approximately six miles north of the Kona International Airport in the North
Kona District of the Island of Hawaii.
Kaupulehu Developments' residential development rights in the
approximately 100 acres are under option to Hualalai Development Company, an
affiliate of Kajima Corporation of Japan. If Hualalai Development Company
exercises this option, the Company will receive a total of $16,157,000 in
connection with its 50.1% interest in Kaupulehu Developments. The option expires
on December 31, 1999, unless 20% of the total consideration is received on or
before December 31, 1999; on April 30, 2003 unless 50% of the then remaining
consideration is received on or before April 30, 2003; and the remainder of the
option would then expire on April 30, 2007. There is no assurance that this
option or any portion of it will be exercised.
<PAGE>
42
Kaupulehu Developments also holds leasehold rights in approximately 2,100
acres of land located adjacent to and north of the Four Seasons Resort Hualalai
at Historic Ka'upulehu. Kaupulehu Developments is in the process of negotiating
a revised development agreement and residential fee purchase prices with the
lessor. Management cannot predict the outcome of these negotiations.
In June 1996, the State Land Use Commission ("LUC") approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of the
2,100 acres of land into the Urban District for resort/residential development.
Subsequent to the LUC's approval, a notice of appeal was filed with the Third
Circuit Court of the State of Hawaii by parties seeking to reverse the LUC's
decision. The Third Circuit Court of the State of Hawaii upheld the Land Use
Commission's approval of Kaupulehu Developments' rezoning request in all
respects in a Decision and Order issued in August 1997. In November 1997, a
notice of appeal was filed with the Supreme Court of the State of Hawaii by
parties seeking to reverse the Third Circuit Court's decision. The Company
anticipates that the Supreme Court of the State of Hawaii will rule on the
appeal in 1999 and management cannot predict the outcome of such appeal.
In addition to State of Hawaii approvals, Kaupulehu Developments must
obtain additional approvals from the County of Hawaii. In June 1998, Kaupulehu
Developments filed an Application for a Project District zoning ordinance and a
Special Management Area ("SMA") Use Permit Petition with the County of Hawaii,
requesting changes in zoning and use of approximately 1,000 of the 2,100 acres
of land to allow residential, resort and commercial development. In December
1998, following a contested case hearing procedure conducted in November, the
Planning Commission of the County of Hawaii granted the requested SMA use permit
to Kaupulehu Developments to be effective when the zoning ordinance is adopted.
Management cannot predict the outcome of the county zoning petition and there is
no assurance that these approvals will be forthcoming at any time.
Costs related to the rezoning of the conservation land are capitalized and
included in the consolidated balance sheets under the caption, "Investment in
Land."
5. LONG-TERM DEBT
--------------
The Company has a credit facility at the Royal Bank of Canada, a Canadian
bank, for $19,000,000 Canadian dollars, or its U.S. dollar equivalent of
approximately $12,400,000 at September 30, 1998. Borrowings under this facility
were $11,665,000 and $9,100,000 at September 30, 1998 and 1997, respectively,
and are included in long-term debt. At September 30, 1998, the Company had
unused credit available under this facility of approximately $700,000.
The facility is available in U.S. dollars at the London Interbank Offer
Rate ("LIBOR") plus 3/4%, at U.S. prime, or in Canadian dollars at Canadian
prime. A standby fee of 1/2% per annum is charged on the unused facility
balance. Under the financing agreement, the facility is reviewed annually, with
the next review planned for February 1999. Subject to that review, the facility
may be extended one year with no required debt repayments for one year or
converted to a 5-year term loan by the bank. If the facility is converted to a
5-year term loan, the Company has agreed to the following repayment schedule of
the then outstanding loan balance: year 1-30%; year 2-27%; year 3-16%; year
4-14% and year 5-13%.
The Company has the option to change the currency denomination and
interest rate applicable to the loan at periodic intervals during the term of
the loan. During the year ended September 30, 1998, the Company paid interest at
rates ranging from 6.41% to 7.50%. At September 30, 1998, $9,250,000 of the
loans were denominated in U.S. dollars at an interest rate of 6.44%, and
$2,415,000 of the loans were denominated in Canadian dollars (CDN $3,697,000) at
an interest rate of 7.25%. The facility is collateralized by the Company's
interests in its major oil and natural gas properties and a negative pledge on
its remaining oil and natural gas properties. The facility is reviewed annually
with a primary focus on the future cash flows that will be generated by the
Company's Canadian oil and natural gas properties. No compensating bank balances
are required for this facility.
<PAGE>
43
In June 1995, the Company issued $2,000,000 of convertible notes due July
1, 2003. $400,000 of such notes were purchased by Mr. Morton H. Kinzler,
President, Chief Executive Officer and Chairman of the Board of Directors of the
Company, $200,000 were purchased by Mr. Martin Anderson, a director, $200,000
were purchased by Dr. Joseph E. Magaro, a 16.0% shareholder of the Company,
$100,000 were purchased by Dr. R. David Sudarsky, a 9.2% shareholder of the
Company, and $1,000,000 were purchased by Ingalls and Snyder Value Partners,
L.P., an affiliate of a 7.6% shareholder of the Company. The notes are payable
in 20 consecutive equal quarterly installments beginning in October 1998.
Interest is payable quarterly at a rate to be adjusted each quarter to the
greater of 10% per annum or 1% over the prime rate of interest. The Company paid
interest on these convertible notes at the rate of 10% per annum throughout
fiscal years 1998, 1997 and 1996. The notes are unsecured and convertible at any
time at the holder's option into shares of the Company's common stock at a price
of $20.00 per share, subject to adjustment for certain events including a stock
split of, or stock dividend on, the Company's common stock. The notes are
redeemable, at the option of the Company, at any time at premiums declining 1%
annually from 4% of the principal amount of the notes at July 1, 1998. At
September 30, 1998, $1,600,000 of these notes are included in long-term debt and
$400,000 of these notes are included in the current portion of long-term debt.
In fiscal 1998, the Company obtained a $1,000,000 credit facility,
increasable to $1,500,000 under certain conditions, with a Hawaii bank through
Kaupulehu Developments, a 50.1%-owned joint venture. The facility is secured by
Kaupulehu Developments' assets and cash collateral and a personal guaranty from
an affiliate of Kaupulehu Developments' minority interest partner. Interest on
borrowings is guaranteed by the Company. Borrowings under the facility are due
in full on March 31, 2000, and interest is payable monthly at a rate of 1.5%
above the Hawaii bank's prime rate of interest (9.75% at September 30, 1998).
Borrowings under the facility at September 30, 1998 amounting to $365,000 are
included in long-term debt. The total available credit under the facility at
September 30, 1998 amounted to $635,000.
At September 30, 1998, the maturities of current and long-term debt by
fiscal year, exclusive of the credit facility with the Canadian bank, are as
follows:
1999 $ 400,000
2000 765,000
2001 400,000
2002 400,000
2003 400,000
----------
$2,365,000
==========
The Company capitalizes interest on costs related to its investment in
land. The Company also capitalized interest on its investment in undeveloped
natural gas and oil leases in the Central Basin in Michigan during the year
ended September 30, 1997 and during the first quarter of the year ended
September 30, 1998. Interest costs for the years ended September 30, 1998, 1997
and 1996 are summarized as follows:
<PAGE>
44
1998 1997 1996
--------- --------- ---------
Interest costs incurred $ 901,000 $ 793,000 $ 794,000
Less interest costs capitalized on:
Investment in land 169,000 120,000 87,000
Investment in natural
gas and oil properties 10,000 49,000 -
--------- --------- ---------
Interest expense $ 722,000 $ 624,000 $ 707,000
========= ========= =========
6. TAXES ON INCOME
---------------
The components of earnings/(loss) before income taxes are as follows:
Year ended September 30,
---------------------------------------------
1998 1997 1996
----------- ----------- -----------
United States $(4,736,000) $(1,662,000) $(1,200,000)
Canadian 1,704,000 4,440,000 3,308,000
----------- ----------- -----------
$(3,032,000) $ 2,778,000 $ 2,108,000
=========== =========== ===========
The components of the provision for income taxes related to the above
earnings/(loss) are as follows:
Year ended September 30,
------------------------------------------
1998 1997 1996
------------ ------------- ------------
Current:
United States - Federal $ - $ 51,000 $ (67,000)
United States - State and local - (51,000) (51,000)
---------- ---------- ----------
United States - total - - (118,000)
Canadian 334,000 842,000 759,000
---------- ---------- ----------
Total current 334,000 842,000 641,000
---------- ---------- ----------
Deferred:
United States (23,000) 40,000 56,000
Canadian 547,000 846,000 181,000
---------- ---------- ----------
Total deferred 524,000 886,000 237,000
---------- ---------- ----------
$ 858,000 $1,728,000 $ 878,000
========== ========== ==========
In November 1995, officials of the U.S. and Canada ratified a new
agreement amending the Canada-U.S. Tax Treaty that reduced the Canadian Branch
tax. This change resulted in the recognition of a deferred Canadian income tax
benefit of $290,000 in the year ended September 30, 1996.
<PAGE>
45
A reconciliation between the reported provision for income taxes and the
amount computed by multiplying the (loss) earnings before income taxes by the
United States federal tax rate is as follows:
Year ended September 30,
-------------------------------------------
1998 1997 1996
------------ ---------- ------------
Tax (benefit) expense computed
by applying statutory rate $(1,061,000) $ 972,000 $ 738,000
Change in the balance
of the valuation allowance 1,339,000 193,000 40,000
Effect of the foreign tax
provision on the
total tax provision 489,000 786,000 596,000
State net operating
losses generated (70,000) (110,000) (120,000)
Effect on deferred income
tax assets and liabilities of
reduction in Canadian
Branch tax rate - - (290,000)
Other 161,000 (113,000) (86,000)
----------- ---------- ---------
$ 858,000 $1,728,000 $ 878,000
=========== ========== =========
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at September
30, 1998 and 1997 are as follows:
Deferred income tax assets: 1998 1997
----------- -----------
U.S. tax effect of deferred Canadian taxes $ 2,278,000 $ 2,335,000
Tax basis in land in excess of book basis 1,057,000 1,075,000
Foreign tax credit carryforwards 603,000 211,000
Write-down of assets not deducted for tax 741,000 148,000
U.S. federal net operating loss carryforwards 340,000 -
State of Hawaii net operating loss carryforwards 353,000 230,000
Expenses accrued for books but not for tax 213,000 114,000
Alternative minimum tax credit carryforwards 101,000 101,000
Other 154,000 171,000
----------- -----------
Total gross deferred tax assets 5,840,000 4,385,000
Less-valuation allowance (3,940,000) (2,601,000)
----------- -----------
Net deferred income tax assets 1,900,000 1,784,000
----------- -----------
Deferred income tax liabilities:
Property and equipment accumulated
tax depreciation and depletion
in excess of book under Canadian tax law (6,699,000) (6,869,000)
Property and equipment accumulated
tax depreciation and depletion
in excess of book under U.S. tax law (444,000) (281,000)
Other (264,000) (335,000)
----------- -----------
Total deferred income tax liabilities (7,407,000) (7,485,000)
----------- -----------
Net deferred income tax liability $(5,507,000) $(5,701,000)
=========== ===========
The total valuation allowance increased $1,339,000, $193,000 and $40,000
for the years ended September 30, 1998, 1997 and 1996, respectively. The
increase for the year ended September 30, 1998 relates primarily to foreign tax
credit carryforwards and U.S. federal net operating loss carryforwards for which
it is more likely than not that some portion of such carryforwards will not be
utilized to reduce the Company's U.S. tax obligation. Historically, the Company
has reduced U.S. regular taxes due on consolidated U.S. taxable income by
utilizing foreign tax credits. If the net operating loss is utilized to reduce
consolidated U.S. taxable income in a year in which the Company would normally
have utilized foreign tax credits to fully offset regular taxes, the net
operating loss will provide no incremental tax benefit; therefore a valuation
allowance has been provided.
<PAGE>
46
A valuation allowance is provided when it is more likely than not that
some portion or all of the deferred tax asset will not be realized. The Company
has established a valuation allowance for Canadian tax deductions, foreign tax
credits, U.S. federal net operating loss carryforwards and state of Hawaii net
operating loss carryforwards which may not be realizable in future years as
there can be no assurance of any specific level of earnings or that the timing
of U.S. earnings will coincide with the payment of Canadian taxes to enable
Canadian taxes to be fully deducted (or recoverable) for U.S. tax purposes.
Additionally, utilization of U.S. federal net operating loss carryforwards will
provide no incremental tax benefit if foreign tax credits generated in future
years will be displaced by the net operating loss carryforwards as it is more
likely than not that the foreign tax credits will expire unused.
Net deferred tax assets will primarily be realized through the deduction
of the cost basis in investment in land against proceeds from investment in land
for tax purposes. Under the cost recovery accounting method, this cost basis has
already been expensed for book purposes. The amount of deferred income tax
assets considered realizable may be reduced in the near term if estimates of
future taxable income are reduced.
At September 30, 1998, the Company had net operating loss carryforwards
for U.S. federal income tax purposes of $1,001,000 which are available to offset
future U.S. federal taxable income, if any, through 2018. In addition, the
Company has alternative minimum tax credit carryforwards of $101,000 which are
available to reduce future U.S. federal regular income taxes, if any, over an
indefinite period. The Company has aggregate state of Hawaii net operating loss
carryforwards of approximately $5,506,000 which are available to offset future
state of Hawaii taxable income, if any, and expire between the years 2000 and
2018. The Company does not file a consolidated income tax return for state of
Hawaii purposes.
7. PENSION PLAN
------------
The Company sponsors a noncontributory defined benefit pension plan
covering substantially all employees, with benefits based on years of service
and the employee's highest consecutive five-year average earnings. The Company's
funding policy is intended to provide for both benefits attributed to service
to-date and for those expected to be earned in the future. The plan assets at
September 30, 1998 were invested as follows: 53% listed government mortgages and
47% common stocks.
<PAGE>
47
The funded status of the pension plan and the amounts recognized in the
consolidated financial statements are as follows:
September 30,
---------------------------
1998 1997
------------- -----------
Actuarial present value of benefit obligations:
Vested $ 1,484,000 $ 1,462,000
=========== ===========
Accumulated benefit obligation $ 1,541,000 $ 1,513,000
=========== ===========
Projected benefit obligation $(1,966,000) $(1,950,000)
Plan assets at fair value 2,224,000 2,171,000
----------- -----------
Plan assets greater than
projected benefit obligation 258,000 221,000
Unrecognized net gain (398,000) (332,000)
Unrecognized prior service cost 40,000 46,000
Unrecognized net transition asset (3,000) (4,000)
----------- -----------
Net pension liability $ (103,000) $ (69,000)
=========== ===========
As of September 30, 1998 and 1997, the discount rate utilized in
determining the actuarial present value of the projected benefit obligation was
6.75% and 7.5%, respectively.
Net pension cost is comprised of the following components and actuarial
assumptions:
Year ended September 30,
--------------------------------------
1998 1997 1996
----------- ------------ -----------
Service cost, benefits
earned during the year $ 66,000 $ 64,000 $ 61,000
Interest cost on projected
benefit obligation 139,000 136,000 130,000
Actual return on plan assets (221,000) (381,000) (151,000)
Net amortization and deferral 50,000 238,000 13,000
--------- --------- ---------
Net pension cost $ 34,000 $ 57,000 $ 53,000
========= ========= =========
Assumed rate of increase in future
compensation levels 5.0% 6.0% 6.0%
==== ==== ====
Expected long-term rate
of return on assets 8.0% 8.0% 8.0%
==== ==== ====
8. STOCK OPTIONS
-------------
The Company has outstanding stock options under a qualified plan that
expired in November 1991. Under this plan, options to purchase a maximum of
120,000 shares of the Company's common stock could be granted to officers and
key employees of the Company and its subsidiaries at prices not less than 100%
of the fair market value at the date of the option grant. Options granted under
this plan became exercisable 25% annually beginning one year from the date of
grant and expire five or ten years from the date of grant.
<PAGE>
48
In March 1995, the Company granted 20,000 stock options to an officer of
the Company under a non-qualified plan at a purchase price of $19.625 per share
(market price on date of grant), with 4,000 of such options vesting annually
commencing one year from the date of grant. These options have stock
appreciation rights that permit the holder to receive stock, cash or a
combination thereof equal to the amount by which the fair market value, at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant.
In June 1998, the Company granted 30,000 stock options to an officer of
the Company's oil and gas segment under a non-qualified plan at a purchase price
of $15.625 per share (market price on date of grant), with 6,000 of such options
vesting annually commencing one year from the date of grant. These options have
stock appreciation rights that permit the holder to receive stock, cash or a
combination thereof equal to the amount by which the fair market value, at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant.
During the year ended September 30, 1998, options to acquire 1,500 shares
and 5,000 shares of the Company's common stock with an exercise price per share
of $13.625 and $22.250, respectively, were forfeited.
There were no stock option transactions during the years ended September
30, 1997 and 1996.
The Company applies the provisions of APB Opinion No. 25 in accounting for
stock-based compensation and adopted the disclosure-only provisions of Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS No. 123"), effective October 1, 1996. No compensation cost
has been recognized for the aforementioned options for the years ended September
30, 1998, 1997 and 1996. Had compensation cost for the stock options granted in
June 1998 been determined based on the fair value method of measuring
stock-based compensation provisions of SFAS No. 123, the Company's net loss and
basic and diluted net loss per share would have been $3,920,000 and $2.97,
respectively, for the year ended September 30, 1998; fair value measurement of
these options was based on a Black Scholes option-pricing model which assumed an
expected life of seven years, expected volatility of 30%, a risk-free interest
rate of 5.5% and an expected dividend yield of 0%. The pro forma net loss
reflects only options granted since October 1, 1995. Therefore, the full impact
of calculating compensation cost for stock options under SFAS No. 123 is not
reflected in the net loss of $3,920,000 because compensation cost is reflected
over the options' vesting periods and compensation cost for options granted
prior to October 1, 1995 is not considered.
Stock options at September 30, 1998 were as follows:
Number of options
------------------------------
Per share price Outstanding Exercisable Expiration Date
-------------------- -------------- -------------- ----------------
$13.625 12,500 12,500 December 1998
$15.625 30,000 - May 2008
$19.625 20,000 12,000 March 2005
$22.250 5,000 5,000 May 1999
------ ------
Total 67,500 29,500
====== ======
Weighted average
exercise price $16.93 $17.53
====== ======
<PAGE>
49
Stock options at September 30, 1997 were as follows:
Number of options
------------------------------
Per share price Outstanding Exercisable Expiration Date
-------------------- -------------- -------------- ---------------
$13.625 14,000 14,000 December 1998
$19.625 20,000 8,000 March 2005
$22.250 10,000 10,000 May 1999
------ ------
Total 44,000 32,000
====== ======
Weighted average
exercise price $18.31 $17.82
====== ======
Stock options at September 30, 1996 were as follows:
Number of options
------------------------------
Per share price Outstanding Exercisable Expiration Date
-------------------- -------------- -------------- ----------------
$13.625 14,000 14,000 December 1998
$19.625 20,000 4,000 March 2005
$22.250 10,000 10,000 May 1999
------ ------
Total 44,000 28,000
====== ======
Weighted average
exercise price $18.31 $17.56
====== ======
Privately negotiated repurchases of common stock may be made if suitable
opportunities become available. At September 30, 1998, the Company could
purchase an additional 14,700 shares under a March 1991 stock repurchase
authorization.
9. COMMITMENTS AND CONTINGENCIES
-----------------------------
The Company is involved in routine litigation and is subject to
governmental and regulatory controls that are incidental to the ordinary course
of business. The Company's management believes that all claims and litigation
involving the Company are not likely to have a material adverse effect on its
financial position, results of operations, or liquidity.
The Company is contingently liable for the repayment of loans under a
$650,000 loan facility, granted by a bank, to three participants in one of the
Company's oil and natural gas ventures. At September 30, 1998, the loan balance
was $330,000, $100,000 of which is to an affiliate of the Company. The three
participants' interests in the venture are pledged as collateral to secure
repayment of the loans. The Company believes the value of the collateral is
significantly in excess of the loan balances.
The Company has committed to construct $200,000 of improvements at its
yard at Sand Island on Oahu, Hawaii, by January 2000.
The Company has several operating leases for office space. Rental expense
was $433,000 in 1998, $397,000 in 1997, and $398,000 in 1996. The Company is
committed under several non-cancelable operating leases for office and other
space with minimum rental payments summarized by fiscal year as follows: 1999 -
$453,000, 2000 - $429,000, 2001 - $328,000, 2002 - $329,000, 2003 - $310,000,
and thereafter through 2026 an aggregate of $1,600,000.
<PAGE>
50
10. WRITE-DOWN OF OIL AND NATURAL GAS PROPERTIES AND OTHER ASSETS
-------------------------------------------------------------
In November 1996, the Company entered into a participation agreement with
KEP Energy Resources, LLC and Presco Inc. to develop natural gas and oil
reserves in the Central Basin in Michigan.
Under the full cost method of accounting, the amount of oil and natural
gas properties' capitalized costs less accumulated depletion (on a country by
country basis) is subject to a ceiling test limitation that requires any excess
of such costs over the present value of estimated future cash flows from proved
reserves to be expensed. As of March 31, 1998, the Company's investment in the
Michigan Basin prospect was determined to be impaired and was transferred to the
amortization base. Upon transfer, capitalized oil and natural gas properties'
costs in the United States exceeded the full cost ceiling test limitation and,
accordingly, the Company recorded a non-cash write-down of $2,070,000 in the
quarter ended March 31, 1998. Due to further declines in oil prices and
disappointing seismic and drilling results in North Dakota, the Company
abandoned its U.S. oil and natural gas prospects and recorded an additional U.S.
ceiling test write-down of $660,000 during the quarter ended June 30, 1998 to
fully write-off its investment in U.S. oil and natural gas properties.
In fiscal 1998, the Company also wrote down $170,000 of land and land
improvement costs related to a contract drilling yard held for sale due to a
decline in the market value of the property, and $95,000 of available-for-sale
securities due to a decline in market value deemed other than temporary.
In fiscal 1997, the Company recorded a U.S. oil and natural gas properties
ceiling test write-down of $270,000. This write-down was largely related to
downward revisions of proved oil and natural gas reserves.
<PAGE>
51
11. SEGMENT AND GEOGRAPHIC INFORMATION
----------------------------------
The Company operates in three industries: oil and natural gas exploration,
development and production, contract drilling and land investment.
Year ended September 30,
-----------------------------------------------
1998 1997 1996
------------ ----------- -----------
Revenues:
Oil and natural gas $ 9,400,000 $11,520,000 $10,660,000
Contract drilling 1,510,000 2,160,000 2,650,000
Other 920,000 873,000 717,000
----------- ----------- -----------
Total $11,830,000 $14,553,000 $14,027,000
=========== =========== ===========
Depreciation, depletion
and amortization:
Oil and natural gas $ 2,698,000 $ 2,491,000 $ 2,658,000
Contract drilling 68,000 93,000 172,000
Other 132,000 190,000 130,000
----------- ----------- -----------
Total $ 2,898,000 $ 2,774,000 $ 2,960,000
=========== =========== ===========
Capital expenditures:
Oil and natural gas $ 6,969,000 $ 6,477,000 $ 5,049,000
Contract drilling 91,000 189,000 53,000
Land investment 862,000 733,000 646,000
Other 205,000 97,000 219,000
----------- ----------- ------------
Total $ 8,127,000 $ 7,496,000 $ 5,967,000
=========== =========== ===========
Operating profit (loss)
(before general and
administrative expenses):
Oil and natural gas $ 749,000 $ 5,433,000 $ 4,596,000
Contract drilling (550,000) 217,000 593,000
Other 693,000 683,000 587,000
----------- ----------- -----------
Total 892,000 6,333,000 5,776,000
General and
administrative expenses (3,292,000) (3,208,000) (3,114,000)
Interest expense (722,000) (624,000) (707,000)
Interest income 90,000 277,000 153,000
----------- ----------- -----------
(Loss) earnings before
income taxes $(3,032,000) $ 2,778,000 $ 2,108,000
=========== =========== ===========
<PAGE>
52
Depletion per 1,000 cubic feet of natural gas (MCF) and natural gas
equivalent was $0.51 in fiscal 1998, $0.46 in fiscal 1997, and $0.44 in fiscal
1996.
ASSETS BY SEGMENT:
- ------------------
September 30,
---------------------------------------------------
1998 1997 1996
----------------- ---------------- ----------------
Oil and natural gas (1) $23,959,000 76% $25,098,000 73% $22,622,000 73%
Contract drilling (2) 1,576,000 5% 1,700,000 5% 1,911,000 6%
Land investment (2) 2,710,000 8% 1,848,000 5% 1,115,000 4%
Other:
Cash 2,178,000 7% 4,402,000 13% 3,553,000 12%
Corporate and other 1,238,000 4% 1,350,000 4% 1,579,000 5%
---------------- ----------- ---- ----------- ----
Total $31,661,000 100% $34,398,000 100% $30,780,000 100%
=========== ==== =========== ==== =========== ====
(1) Primarily located in the Province of Alberta, Canada.
(2) Located in Hawaii.
ASSETS BY GEOGRAPHIC AREA:
- --------------------------
September 30,
--------------------------------------------------
1998 1997 1996
---------------- ---------------- ----------------
United States $ 6,477,000 20% $ 9,166,000 27% $ 6,880,000 22%
Canada 25,184,000 80% 25,232,000 73% 23,900,000 78%
----------- ---- ----------- ---- ----------- ----
Total $31,661,000 100% $34,398,000 100% $30,780,000 100%
=========== ==== =========== ==== =========== ====
CAPITAL EXPENDITURES BY GEOGRAPHIC AREA:
- ----------------------------------------
Year ended September 30,
--------------------------------------------------
1998 1997 1996
---------------- ---------------- ----------------
United States $ 2,075,000 26% $ 2,739,000 37% $ 1,100,000 18%
Canada 6,052,000 74% 4,757,000 63% 4,867,000 82%
----------- ---- ----------- ---- ----------- ----
Total $ 8,127,000 100% $ 7,496,000 100% $ 5,967,000 100%
=========== ==== =========== ==== =========== ====
<PAGE>
53
OPERATIONS BY GEOGRAPHIC AREA:
- ------------------------------
Year ended September 30,
---------------------------------------------
1998 1997 1996
-------------- -------------- ------------
Revenue:
United States $ 1,690,000 $ 2,373,000 $ 2,938,000
Canada 10,140,000 12,180,000 11,089,000
----------- ----------- -----------
Total $11,830,000 $14,553,000 $14,027,000
=========== =========== ===========
Depreciation, depletion, and
amortization:
United States $ 199,000 $ 433,000 $ 404,000
Canada 2,699,000 2,341,000 2,556,000
----------- ----------- -----------
Total $ 2,898,000 $ 2,774,000 $ 2,960,000
=========== =========== ===========
Operating profit (loss)
(before general and
administrative expenses):
United States $(3,293,000) $ (238,000) $ 592,000
Canada 4,185,000 6,571,000 5,184,000
----------- ----------- -----------
Total $ 892,000 $ 6,333,000 $ 5,776,000
=========== =========== ===========
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
-----------------------------------
The carrying amount of cash and cash equivalents approximates fair value
because of the short maturity of these instruments. The fair values of
investment securities included in other assets are estimated based on quoted
market prices for those or similar investments. The fair values of the Company's
long-term debt are estimated based on the current terms offered for debt of the
same or similar remaining maturities.
The differences between the estimated fair values and carrying values of
the Company's financial instruments are not material.
13. CONCENTRATIONS OF CREDIT RISK
-----------------------------
The Company's oil and natural gas segment derived 23%, 19% and 19% of its
oil and natural gas revenues in fiscal 1998, 1997, and 1996, respectively, from
one company. At September 30, 1998, the Company had a receivable from the
aforementioned company of approximately $208,000.
The Company's contract drilling subsidiary derived 42%, 73% and 42% of its
contract drilling revenues in fiscal 1998, 1997, and 1996, respectively,
pursuant to State of Hawaii and local county contracts. At September 30, 1998,
the Company had accounts receivable from the State of Hawaii and local county
entities totaling approximately $118,000. Additionally, the Company's contract
drilling segment had a net receivable from a private developer totaling
approximately $250,000. The Company has lien rights on contracts with the state
of Hawaii and local county entities and with the aforementioned private
developer.
Historically, the Company has not incurred significant credit related
losses on its trade receivables, and management does not believe significant
credit risk related to these trade receivables exists at September 30, 1998.
<PAGE>
54
14. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
-------------------------------------------------
The following details the effect of changes in current assets and
liabilities on the consolidated statements of cash flows, and presents
supplemental cash flow information:
Year ended September 30,
--------------------------------------
1998 1997 1996
---------- ---------- ----------
Increase (decrease) from changes in:
Receivables $ 29,000 $ 167,000 $ 593,000
Costs and estimated earnings in excess
of billings on uncompleted contracts (82,000) 106,000 (23,000)
Inventories (6,000) (15,000) 43,000
Other current assets 223,000 17,000 (68,000)
Accounts payable (88,000) 1,510,000 645,000
Accrued expenses 833,000 539,000 67,000
Billings in excess of costs and
estimated earnings on uncompleted
contracts 170,000 11,000 (416,000)
Payable to joint interest owners (642,000) 289,000 274,000
Income taxes payable (3,000) (155,000) 158,000
--------- ---------- ----------
Increase from changes
in current assets and liabilities $ 434,000 $2,469,000 $1,273,000
========= ========== ==========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 616,000 $ 636,000 $ 740,000
========= ========== ==========
Income taxes $ 540,000 $1,146,000 $ 614,000
========= ========== ==========
15. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)
---------------------------------------------------------
The following tables summarize information relative to the Company's oil
and natural gas operations, which are substantially conducted in Canada. Proved
reserves are the estimated quantities of crude oil, condensate and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed producing oil and natural gas reserves
are reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. The estimated net interests in total
proved developed and proved developed producing reserves are based upon
subjective engineering judgments and may be affected by the limitations inherent
in such estimations. The process of estimating reserves is subject to continual
revision as additional information becomes available as a result of drilling,
testing, reservoir studies and production history. There can be no assurance
that such estimates will not be materially revised in subsequent periods.
<PAGE>
55
(A) Oil and Natural Gas Reserves
----------------------------
The following table, based on information prepared by independent
petroleum engineers, Paddock Lindstrom and Associates, Ltd., summarizes changes
in the estimates of the Company's net interests in total proved developed
reserves of crude oil and condensate and natural gas ("MCF" means 1,000 cubic
feet of natural gas) which are substantially in Canada:
OIL GAS
Proved developed reserves: (Barrels) (MCF)
---------- ----------
Balance at September 30, 1995 2,296,000 46,746,000
Revisions of previous estimates 252,000 1,357,000
Extensions, discoveries and other additions 116,000 2,852,000
Less production (279,000) (4,347,000)
Sales of reserves in place (11,000) (356,000)
--------- ----------
Balance at September 30, 1996 2,374,000 46,252,000
Revisions of previous estimates 169,000 761,000
Extensions, discoveries and other additions 339,000 1,786,000
Less production (264,000) (3,852,000)
Sales of reserves in place (5,000) (996,000)
--------- ----------
Balance at September 30, 1997 2,613,000 43,951,000
Revisions of previous estimates (116,000) (1,370,000)
Extensions, discoveries and other additions 191,000 1,710,000
Less production (275,000) (3,684,000)
Sales of reserves in place - (46,000)
---------- ----------
Balance at September 30, 1998 2,413,000 40,561,000
========== ==========
OIL GAS
Proved developed producing reserves at: (Barrels) (MCF)
---------- ----------
September 30, 1995 2,025,000 31,700,000
========= ==========
September 30, 1996 2,108,000 33,096,000
========= ==========
September 30, 1997 2,087,000 29,483,000
========= ==========
September 30, 1998 2,109,000 28,306,000
========= ==========
Included in the above tables are proved developed producing reserves in
the U.S. of 33,000 barrels of oil and 120,000 MCF of natural gas at September
30, 1997, and 50,000 barrels of oil and 39,000 MCF of natural gas at September
30, 1996.
<PAGE>
56
(B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities
----------------------------------------------------------------------
1998 1997 1996
----------- ----------- -----------
Proved properties $44,842,000 $44,369,000 $39,496,000
Unproved properties 628,000 2,405,000 2,401,000
----------- ----------- -----------
Total
capitalized costs 45,470,000 46,774,000 41,897,000
Accumulated depletion
and depreciation 23,041,000 23,481,000 21,033,000
----------- ----------- -----------
Net capitalized costs $22,429,000 $23,293,000 $20,864,000
=========== =========== ===========
U.S. capitalized costs totaled $1,903,000 and $823,000, as of September 30, 1997
and 1996, respectively. U.S. capitalized costs were fully written-off during the
year ended September 30, 1998.
(C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and
---------------------------------------------------------------------------
Development
-----------
Year ended September 30,
--------------------------------------
1998 1997 1996
---------- ---------- ----------
Acquisition of properties:
Unproved -
Canadian $ 184,000 $ 258,000 $ 414,000
United States 85,000 1,100,000 115,000
---------- ---------- ----------
$ 269,000 $1,358,000 $ 529,000
========== ========== ==========
Proved -
Canadian $ 48,000 $ 316,000 $ 94,000
United States - - 30,000
---------- ---------- ----------
$ 48,000 $ 316,000 $ 124,000
========== ========== ==========
Exploration costs:
Canadian $1,299,000 $ 936,000 $ 972,000
United States 493,000 279,000 85,000
---------- ---------- ----------
$1,792,000 $1,215,000 $1,057,000
========== ========== ==========
Development costs:
Canadian $4,478,000 $3,217,000 $3,189,000
United States 382,000 371,000 150,000
---------- ---------- ----------
$4,860,000 $3,588,000 $3,339,000
========== ========== ==========
<PAGE>
57
(D) The Results of Operations of Barnwell's Oil and Natural Gas Producing
---------------------------------------------------------------------
Activities
----------
Year ended September 30,
---------------------------------------------
1998 1997 1996
----------- ----------- ------------
Gross revenues:
United States $ 132,000 $ 210,000 $ 266,000
Canada 10,626,000 13,110,000 11,535,000
----------- ----------- -----------
Total gross revenues 10,758,000 13,320,000 11,801,000
Royalties, net of credit 1,358,000 1,800,000 1,141,000
----------- ----------- -----------
Net revenues 9,400,000 11,520,000 10,660,000
Production costs 3,223,000 3,326,000 3,406,000
Write-down 2,730,000 270,000 -
Depletion and depreciation 2,698,000 2,491,000 2,658,000
----------- ----------- -----------
Pre-tax results of operations* 749,000 5,433,000 4,596,000
Estimated income tax expense 1,886,000 2,760,000 2,441,000
----------- ----------- -----------
Results of operations $(1,137,000) $ 2,673,000 $ 2,155,000
=========== =========== ===========
* Before general and administrative expenses.
(E) Standardized Measure, Including Year-to-Year Changes Therein, of Discounted
---------------------------------------------------------------------------
Future Net Cash Flows
---------------------
The following tables have been developed pursuant to procedures prescribed
by SFAS 69, and utilize reserve and production data estimated by petroleum
engineers. The information may be useful for certain comparison purposes but
should not be solely relied upon in evaluating the Company or its performance.
Moreover, the projections should not be construed as realistic estimates of
future cash flows, nor should the standardized measure be viewed as representing
current value.
The future cash flows are based on sales prices, costs, and statutory
income tax rates in existence at the dates of the projections. Material
revisions to reserve estimates may occur in the future, development and
production of the oil and natural gas reserves may not occur in the periods
assumed and actual prices realized and actual costs incurred are expected to
vary significantly from those used. Management does not rely upon this
information in making investment and operating decisions; rather, those
decisions are based upon a wide range of factors, including estimates of
probable reserves as well as proved reserves and price and cost assumptions
different than those reflected herein.
<PAGE>
58
Standardized Measure of Discounted Future Net Cash Flows
- --------------------------------------------------------
As of September 30,
------------------------------------------------
1998 1997 1996
--------------- --------------- -------------
Future cash inflows $ 83,827,000 $106,086,000 $ 91,916,000
Future production costs (30,052,000) (36,965,000) (24,466,000)
Future development costs (1,372,000) (1,980,000) (1,447,000)
------------ ------------ ------------
Future net cash
flows before income taxes 52,403,000 67,141,000 66,003,000
Future income tax expenses (15,379,000) (21,369,000) (20,424,000)
------------ ------------ ------------
Future net cash flows 37,024,000 45,772,000 45,579,000
10% annual discount
for timing of cash flows (14,351,000) (17,790,000) (18,485,000)
------------ ------------ ------------
Standardized measure of
discounted future
net cash flows $ 22,673,000 $ 27,982,000 $ 27,094,000
============ ============ ============
Changes in the Standardized Measure of Discounted Future Net Cash Flows
- -----------------------------------------------------------------------
Year ended September 30,
---------------------------------------
1998 1997 1996
----------- ----------- -----------
Beginning of year $27,982,000 $27,094,000 $20,350,000
----------- ----------- -----------
Sales of oil and natural gas
produced, net of production costs (6,177,000) (8,194,000) (7,254,000)
Net changes in prices and
production costs, net of
royalties and wellhead taxes (2,295,000) 3,233,000 15,257,000
Extensions and discoveries 1,650,000 3,921,000 2,173,000
Sales of reserves in place (49,000) (970,000) (415,000)
Revisions of previous
quantity estimates (1,153,000) 1,937,000 366,000
Net change in Canadian
dollar translation rate (2,744,000) (362,000) (290,000)
Changes in the timing of
future production and other 447,000 (860,000) (346,000)
Net change in income taxes 2,466,000 (491,000) (4,896,000)
Accretion of discount 2,546,000 2,674,000 2,149,000
----------- ----------- -----------
Net change (5,309,000) 888,000 6,744,000
----------- ----------- -----------
End of year $22,673,000 $27,982,000 $27,094,000
=========== =========== ===========
<PAGE>
59
Item 8. Changes in and Disagreements with Accountants on Accounting and
---------------------------------------------------------------
Financial Disclosure
--------------------
None.
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons,
-------------------------------------------------------------
Compliance With Section 16(a) of the Exchange Act
-------------------------------------------------
Item 10. Executive Compensation
----------------------
Item 11. Security Ownership of Certain Beneficial Owners and Management
--------------------------------------------------------------
Item 12. Certain Relationships and Related Transactions
----------------------------------------------
Items 9, 10, 11, and 12 are omitted pursuant to General Instructions E.3.
of Form 10-KSB, since the Registrant will file its definitive proxy statement
for the 1998 Annual Meeting of Stockholders not later than 120 days after the
close of its fiscal year ended September 30, 1998, which proxy statement is
incorporated herein by reference.
<PAGE>
60
Item 13. Exhibits, List and Reports on Form 8-K
--------------------------------------
(A) Financial Statements
The following consolidated financial statements of Barnwell Industries,
Inc. and its subsidiaries are included in Part II, Item 7:
Independent Auditors' Report - KPMG Peat Marwick LLP
Consolidated Balance Sheets - September 30, 1998 and 1997
Consolidated Statements of Operations -
for the three years ended September 30, 1998
Consolidated Statements of Cash Flows -
for the three years ended September 30, 1998
Consolidated Statements of Stockholders' Equity -
for the three years ended September 30, 1998
Notes to Consolidated Financial Statements
Schedules have been omitted because they were not applicable, not
required, or the information is included in the consolidated financial
statements or notes thereto.
(B) Reports on Form 8-K
There were no reports on Form 8-K filed during the three months ended
September 30, 1998.
(C) Exhibits
No. 3.1 Certificate of Incorporation
No. 3.2 Amended and Restated By-Laws
No. 4.0 Form of the Registrant's certificate of common stock, par value
$.50 per share.
No. 10.4 The Barnwell Industries, Inc. Employees' Pension Plan (restated
as of October 1, 1989).
Exhibits 3.1 and 3.2 are incorporated by reference to the Exhibits 3.3
and 3.4, respectively, to the Registrant's Form S-8 dated November 8,
1991. Exhibit 4.0 is incorporated by reference to the registration
statement on Form S-1 originally filed by the Registrant January 29,
1957 and as amended February 15, 1957 and February 19, 1957. Exhibit
10.4 is incorporated by reference to Form 10-K for the year ended
September 30, 1989.
No. 10.17 Phase I Makai Development Agreement dated June 30, 1992, by
and between Kaupulehu Makai Venture and Kaupulehu Developments.
No. 10.18 KD/KMV Agreement dated June 30, 1992 by and between Kaupulehu
Makai Venture and Kaupulehu Developments.
Exhibits 10.17 and 10.18 are incorporated by reference to Form 10-K for
the year ended September 30, 1992.
No. 21 Subsidiaries of the Registrant.
<PAGE>
61
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BARNWELL INDUSTRIES, INC.
(Registrant)
/s/ Russell M. Gifford
----------------------------------
By: Russell M. Gifford
Chief Financial Officer,
Executive Vice President and
Treasurer
Date: December 7, 1998
<PAGE>
62
Pursuant to the requirements of the Securities Exchange Act of 1934, the
report has been signed below by the following persons on behalf of the
registrant in the capacities and on the dates indicated.
/s/ Morton H. Kinzler
- ----------------------------------
MORTON H. KINZLER
Chief Executive Officer,
President and Director
Date: December 7, 1998
/s/ Martin Anderson /s/ Alan D. Hunter
- ---------------------------------- ---------------------------
MARTIN ANDERSON, Director ALAN D. HUNTER, Director
Date: December 8, 1998 Date: December 8, 1998
/s/ Daniel Jacobson
- ---------------------------------- ---------------------------
H. WHITNEY BOGGS, JR., Director DANIEL JACOBSON, Director
Date: December 7, 1998
/s/ Barry E. Emes
- ---------------------------------- ---------------------------
BARRY E. EMES, Director WILLIAM C. WARREN, Director
Date: December 7, 1998
/s/ Erik Hazelhoff-Roelfzema /s/ Glenn Yago
- ---------------------------------- ---------------------------
ERIK HAZELHOFF-ROELFZEMA, Director GLENN YAGO, Director
Date: December 8, 1998 Date: December 7, 1998
/s/ Murray C. Gardner
- ----------------------------------
MURRAY C. GARDNER, Director
Date: December 8, 1998
<PAGE>
63
Exhibit 21 List of Subsidiaries
The subsidiaries of Barnwell Industries, Inc., at September 30, 1998 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 Overseas, Inc. 100% Delaware
Geothermal Exploration and Development Corp. 100% Delaware
Victoria Properties, Inc. 100% Delaware
Barnwell Financial Corporation 100% Delaware
NDTX, Inc. 100% Delaware
Barnwell Investment Corporation 100% Hawaii
Barnwell Kona Corporation 100% Hawaii
WRI Properties, Inc. 100% Hawaii
Barnwell Israel, Ltd. 100% Israel
Barnwell Oil & Gas, Ltd. 100% Israel
Bill Robbins Drilling, Ltd. 100% Alberta, Canada
Gypsy Petroleums Ltd. 100% Alberta, Canada
Dartmouth Petroleum, Ltd. 100% Alberta, Canada
J.H. Wilson Associates, Ltd. 100% Alberta, Canada
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from
Barnwell Industries, Inc.'s 1998 10-KSB and is qualified in its entirety
by reference to such 10-KSB filing.
</LEGEND>
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1998
<PERIOD-END> SEP-30-1998
<CASH> 2178
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<RECEIVABLES> 1679
<ALLOWANCES> 86
<INVENTORY> 76
<CURRENT-ASSETS> 4626
<PP&E> 56217
<DEPRECIATION> 32105
<TOTAL-ASSETS> 31661
<CURRENT-LIABILITIES> 5650
<BONDS> 14030
0
0
<COMMON> 821
<OTHER-SE> 5923
<TOTAL-LIABILITY-AND-EQUITY> 31661
<SALES> 10910
<TOTAL-REVENUES> 11920
<CGS> 5045
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<OTHER-EXPENSES> 5893
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<INCOME-PRETAX> (3032)
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</TABLE>
