U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-KSB
X ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE
--- SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2000
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
--- SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-5103
BARNWELL INDUSTRIES, INC.
(Name of small business issuer in its charter)
DELAWARE 72-0496921
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1100 Alakea Street, Suite 2900, Honolulu, Hawaii 96813-2833
(Address of principal executive offices) (Zip code)
(808) 531-8400
(Issuer's telephone number)
Securities registered under Section 12(b) of the Exchange Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, par value American Stock Exchange
$0.50 per share Toronto Stock Exchange
Securities registered under Section 12(g) of the Exchange Act: None
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes X No
----- -----
Check if there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B, and no disclosure will be contained, to the best of registrant's
knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-KSB or any amendment to this Form
10-KSB. [X]
Issuer's revenues for the fiscal year ended September 30, 2000: $26,570,000
The aggregate market value of the voting stock held by non-affiliates (590,797
shares) of the Registrant on December 15, 2000, based on the closing price of
$18.50 on that date on the American Stock Exchange, was $10,930,000.
As of December 15, 2000 there were 1,310,952 shares of common stock, par value
$.50, outstanding.
Documents Incorporated by Reference
-----------------------------------
1. Proxy statement to be forwarded to shareholders on or about January 18,
2001 is incorporated by reference in Part III hereof.
Transitional Small Business Disclosure Format Yes No X
----- -----
<PAGE>
TABLE OF CONTENTS
PART I
Discussion of Forward-Looking Statements
Item 1. Description of Business
General Development of Business
Financial Information about Industry Segments
Narrative Description of Business
Financial Information about Foreign and
Domestic Operations and Export Sales
Item 2. Description of Property
Oil and Natural Gas Operations
General
Well Drilling Activities
Oil and Natural Gas Production
Productive Wells
Developed Acreage and Undeveloped Acreage
Reserves
Estimated Future Net Revenues
Marketing of Oil and Natural Gas
Governmental Regulation
Competition
Contract Drilling Operations
Activity
Competition
Land Investment Operations
Activity
Competition
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market For Common Equity and Related Stockholder Matters
Item 6. Management's Discussion and Analysis or Plan of Operation
Liquidity and Capital Resources
Results of Operations
Item 7. Financial Statements
Item 8. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons,
Compliance With Section 16(a) of the Exchange Act
Item 10. Executive Compensation
Item 11. Security Ownership of Certain Beneficial Owners and Management
Item 12. Certain Relationships and Related Transactions
Item 13. Exhibits and Reports on Form 8-K
<PAGE>
PART I
Forward-Looking Statements
--------------------------
This Form 10-KSB, and the documents incorporated herein by reference,
contains forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended, including various forecasts, projections of Barnwell
Industries, Inc.'s (referred to herein together with its subsidiaries as
"Barnwell" or the "Company") future performance, statements of the Company's
plans and objectives and other similar types of information. Although the
Company believes that its expectations are based on reasonable assumptions, it
cannot assure that the expectations contained in such forward-looking statements
will be achieved. Such statements involve risks, uncertainties and assumptions,
including, but not limited to, those relating to the factors discussed below, in
other portions of this Form 10-KSB, in the Notes to Consolidated Financial
Statements, and in other documents filed by the Company with the Securities and
Exchange Commission from time to time, which could cause actual results to
differ materially from those contained in such statements. These forward-looking
statements speak only as of the date of filing of this Form 10-KSB, and the
Company expressly disclaims any obligation or undertaking to publicly release
any updates or revisions to any forward-looking statements contained herein.
The Company's oil and natural gas operations are affected by domestic
and international political, legislative, regulatory and legal actions. Such
actions may include changes in the policies of the Organization of Petroleum
Exporting Countries ("OPEC") or other developments involving or affecting
oil-producing countries, including military conflict, embargoes, internal
instability or actions or reactions of the government of the United States in
anticipation of or in response to such developments. Domestic and international
economic conditions, such as recessionary trends, inflation, interest costs,
monetary exchange rates and labor costs, as well as changes in the availability
and market prices of crude oil, natural gas and petroleum products, may also
have a significant effect on the Company's oil and natural gas operations. While
the Company maintains reserves for anticipated liabilities and carries various
levels of insurance, the Company could be affected by civil, criminal,
regulatory or administrative actions, claims or proceedings. In addition,
climate and weather can significantly affect the Company in several of its
operations. The Company's oil and gas operations are also affected by political
developments and laws and regulations, particularly in the United States and
Canada, such as restrictions on production, restrictions on imports and exports,
the maintenance of specified reserves, tax increases and retroactive tax claims,
expropriation of property, cancellation of contract rights, environmental
protection controls, environmental compliance requirements and laws pertaining
to workers' health and safety.
The Company's land investment business segment is affected by the
condition of Hawaii's real estate market. The Hawaii real estate market is
affected by Hawaii's economy in general and Hawaii's tourism industry in
particular. Any future cash flows from the Company's land development activities
are subject to, among other factors, the level of real estate activity and
prices, the demand for new housing and second homes on the Island of Hawaii, the
rate of increase in the cost of building materials and labor, the introduction
of building code modifications, changes to zoning laws, and the level of
consumer confidence in Hawaii's economy.
<PAGE>
The Company's contract drilling operations, which are located in Hawaii,
are also indirectly affected by the factors discussed in the preceding
paragraph. The Company's contract drilling operations are materially dependent
upon levels of activity in land development in Hawaii. Such activity levels are
affected by both short-term and long-term trends in Hawaii's economy. In prior
years, Hawaii's economy has experienced very slow growth, and as events during
previous years have demonstrated, any prolonged reduction or lack of growth in
Hawaii's economy will depress the demand for the Company's contract drilling
services. Such a decline could have a material adverse effect on the Company's
contract drilling revenues and profitability.
Item 1. Description of Business
-----------------------
(a) General Development of Business
-------------------------------
Barnwell was incorporated in 1956. During its last three fiscal years,
the Company was engaged in oil and natural gas exploration, development,
production and sales primarily in Canada, investment in leasehold land in
Hawaii, and water and exploratory well drilling and water pumping system
installation and repair in Hawaii. Additionally, the Company has provided
contract labor for the drilling and workovers of geothermal wells.
The Company's oil and natural gas activities comprise its largest
business segment. Approximately 57% of the Company's revenues for the fiscal
year ended September 30, 2000 were attributable to its oil and natural gas
activities. The Company's land investment activity accounted for 25% of the
Company's revenues in fiscal 2000. The Company's contract drilling activities
accounted for 13% of the Company's revenues in fiscal 2000, with natural gas
processing and other revenues comprising the remaining 5% of fiscal 2000
revenues. Approximately 80% of the Company's capital expenditures for the fiscal
year ended September 30, 2000, were attributable to oil and natural gas
activities, 10% to land investment, 6% to contract drilling activities and 4% to
other activities.
(i) Oil and Natural Gas Activities.
-----------------------------------
The Company's wholly-owned subsidiary, Barnwell of Canada, Limited
("BOC"), is involved in the acquisition, exploration and development of oil
and natural gas properties, principally in Alberta, Canada. BOC participates
in exploratory and developmental operations for oil and natural gas on
property in which it has an interest and evaluates proposals by third parties
with regard to participation in such exploratory and developmental operations
elsewhere.
(ii) Contract Drilling.
------------------
The Company's wholly-owned subsidiary, Water Resources International,
Inc. ("WRI"), drills water, geothermal and exploratory wells and installs and
repairs water pumping systems in Hawaii. WRI owns and operates four rotary drill
rigs, one rotary drill/workover rig, and pump installation and service
equipment, and maintains drilling materials and pump inventory in Hawaii. WRI's
contracts are usually fixed price per lineal foot drilled or day rate contracts
that are either negotiated with private individuals or entities, or are obtained
through competitive bidding with various private entities or local, state and
federal agencies.
<PAGE>
(iii) Land Investment.
----------------
The Company owns a 50.1% controlling interest in Kaupulehu
Developments, a Hawaii general partnership. Between 1986 and 1989, Kaupulehu
Developments obtained the state and county zoning changes necessary to permit
development of the Four Seasons Resort Hualalai at Historic Ka'upulehu and
Hualalai Golf Club, a second golf course (currently under construction), and
single and multiple family residential units on land acquired from Kaupulehu
Developments. Kaupulehu Developments currently owns development rights in
approximately 80 acres of residentially zoned leasehold land and leasehold
rights in approximately 2,100 acres of land located in the North Kona District
of the Island of Hawaii.
(b) Financial Information about Industry Segments
---------------------------------------------
Revenues of each industry segment for the fiscal years ended September
30, 2000, 1999 and 1998 are summarized as follows (all revenues were from
unaffiliated customers with no intersegment sales or transfers):
2000 1999 1998
---------------- ---------------- ----------------
Oil and natural gas $15,270,000 57% $10,130,000 67% $ 9,400,000 79%
Contract drilling 3,520,000 13% 4,230,000 28% 1,510,000 13%
Land investment 6,540,000 25% - - - -
Other 891,000 4% 668,000 4% 920,000 7%
----------- ---- ----------- ---- ----------- ----
Revenues from
segments 26,221,000 99% 15,028,000 99% 11,830,000 99%
Interest income 349,000 1% 132,000 1% 90,000 1%
----------- ---- ----------- ---- ----------- ----
Total revenues $26,570,000 100% $15,160,000 100% $11,920,000 100%
=========== ==== =========== ==== =========== ====
For further discussion see Note 11 (Segment and Geographic Information)
and Note 13 (Concentrations of Credit Risk) of "Notes to Consolidated Financial
Statements" in Item 7.
(c) Narrative Description of Business
---------------------------------
See the table above in Item 1(b) detailing revenue of each industry
segment and description of each industry segment of the Company's business under
Item 2.
As of September 30, 2000, Barnwell employed 44 employees, all on a
full-time basis. Twenty are employed in contract drilling activities, 13 are
employed in oil and natural gas activities, and 11 are members of the corporate
and administrative staff. This is a decrease of 27 employees, all contract
drilling employees temporarily hired for coring and geothermal drilling
projects, as compared to 71 employees at September 30, 1999.
For further discussion see "Governmental Regulation" and "Competition"
sections in Item 2 hereof.
(d) Financial Information about Foreign and Domestic Operations and
-------------------------------------------------------------------
Export Sales
------------
Revenues and long-lived assets by geographic area for the three years
ended and as of September 30, 2000, 1999 and 1998 are set forth in Note 11
(Segment and Geographic Information) of "Notes to Consolidated Financial
Statements" in Item 7.
<PAGE>
Item 2. Description of Property
-----------------------
OIL AND NATURAL GAS OPERATIONS
------------------------------
General
-------
Barnwell's investments in oil and natural gas properties consist of
investments in Canada, principally in the Province of Alberta, with minor
holdings in Saskatchewan, British Columbia and North Dakota. These property
interests are principally held under governmental leases or licenses. Under the
typical Canadian provincial governmental lease, Barnwell must perform
exploratory operations and comply with certain other conditions. Lease terms
vary with each province, but, in general, the terms grant Barnwell the right to
remove oil, natural gas and related substances subject to payment of specified
royalties on production.
Barnwell participates in exploratory and developmental operations for
oil and natural gas on property in which it has an interest. The Company also
evaluates proposals by third parties for participation in other exploratory and
developmental opportunities. All exploratory and developmental operations are
overseen by Barnwell's Calgary, Alberta staff along with independent consultants
as necessary. In fiscal 2000, Barnwell participated in exploratory and
developmental operations in the Canadian Provinces of Alberta and British
Columbia, although Barnwell does not limit its consideration of exploratory and
developmental operations to these areas.
Barnwell's producing natural gas properties are located principally in
Alberta. A small amount of producing properties are located in British Columbia
and Saskatchewan. The Province of Alberta determines its royalty share of
natural gas by using a reference price that averages all natural gas sales in
Alberta. Royalty rates are calculated on a sliding scale basis, increasing as
prices increase. Additionally, Barnwell pays gross overriding royalties on a
portion of its natural gas sales to other parties.
In fiscal 2000, the weighted average rate of royalties paid on natural
gas from the Dunvegan Unit, Barnwell's principal oil and natural gas property,
before the Alberta Royalty Tax Credit, was approximately 30%. The weighted
average rate of royalties paid on all of the Company's natural gas was
approximately 15% in fiscal 2000, versus approximately 12% in fiscal 1999. The
increase in the weighted average royalty rate was primarily due to higher gas
prices in fiscal 2000.
In fiscal 2000, virtually all of Barnwell's oil production was from
properties located in Alberta. A small amount of producing properties are
located in North Dakota. Royalty rates under government leases in Alberta are
based on the selling price of oil and production volumes. In fiscal 2000, the
weighted average royalty rate paid on oil was approximately 27%. In fiscal 1999,
the weighted average royalty rate paid on oil was approximately 20%.
Unit sales and prices of natural gas are typically higher in the winter
than at other times due to demand for heating. Unit sales and prices of oil are
also subject to seasonal fluctuations, but to a lesser degree.
<PAGE>
Well Drilling Activities
------------------------
During fiscal 2000, the Company participated in the drilling of 32
development wells and eight exploratory wells, of which, in the Company's view,
34 are capable of production. The Company also participated in the recompletion
of 13 wells. The most significant drilling and recompletion operations took
place in the Dunvegan area; see paragraph below. Additionally, the Company
participated in drilling seven gross, 0.71 net, new development wells at
Manyberries, and four gross, 0.22 net, new development wells at Red Earth/Loon.
These three areas are all in Alberta.
The Dunvegan Unit, which is the Company's principal oil and natural gas
property and is located in Alberta, Canada, has over 140 natural gas wells
producing from over 200 well zones. The Company holds an 8.9% interest in the
Dunvegan Unit. In fiscal 2000, the Company spent approximately $460,000 to
further develop the property through drilling and recompletions and $170,000 on
production equipment. Specifically, the Company participated in the drilling of
two natural gas wells and the recompletion of eight natural gas wells. The
results of the 2000 program were positive with the majority of the recompletions
contributing to natural gas production.
The following table sets forth more detailed information with respect to
the number of exploratory ("Exp.") and development ("Dev.") wells drilled for
the fiscal years ended September 30, 2000, 1999 and 1998 in which the Company
participated:
Total
Productive Productive Productive
Oil Wells Gas Wells Wells Dry Holes Total Wells
----------- ----------- ----------- ----------- ------------
Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev.
---- ---- ---- ---- ---- ---- ---- ---- ---- ----
2000
----
Gross* 1.00 16.00 5.00 12.00 6.00 28.00 2.00 4.00 8.00 32.00
Net* 0.50 1.60 1.30 2.20 1.80 3.80 0.80 1.30 2.60 5.10
1999
----
Gross* - 3.00 2.00 8.00 2.00 11.00 - 2.00 2.00 13.00
Net* - 0.25 0.35 0.62 0.35 0.87 - 0.14 0.35 1.01
1998
----
Gross* 1.00 20.00 - 24.00 1.00 44.00 8.00 6.00 9.00 50.00
Net* 0.18 3.36 - 1.51 0.18 4.87 1.20 0.37 1.38 5.24
------------------------------------
* The term "Gross" refers to the total number of wells in which Barnwell owns
an interest, and "Net" refers to Barnwell's aggregate interest therein. For
example, a 50% interest in a well represents 1 gross well, but .50 net well.
The gross figure includes interests owned of record by Barnwell and, in
addition, the portion owned by others.
Oil and Natural Gas Production
------------------------------
The following table summarizes (a) Barnwell's net production for the
last three fiscal years, based on sales of crude oil, natural gas, condensate
and other natural gas liquids, from all wells in which Barnwell has or had an
interest, and (b) the average sales prices and average production costs for such
<PAGE>
production during the same periods. Production amounts reported are net of
royalties and the Alberta Royalty Tax Credit; production reported in prior years
has been restated to include units attributable to the Alberta Royalty Tax
Credit. Barnwell's net production in fiscal 2000, 1999 and 1998 was derived
primarily from the Province of Alberta. All dollar amounts in this table are in
U.S. dollars.
Year Ended September 30,
-------------------------------------
2000 1999 1998
---------- ---------- ---------
Annual net production
Natural gas liquids (BBLS)* 104,000 89,000 66,000
Oil (BBLS)* 187,000 211,000 225,000
Natural gas (MCF)* 3,501,000 3,634,000 4,145,000
Annual average sale price
per unit of production:
BBL of liquids** $16.91 $ 9.78 $11.36
BBL of oil** $26.15 $14.08 $13.02
MCF of natural gas** $ 2.41 $ 1.57 $ 1.38
Annual average production cost
per MCFE produced*** $ 0.60 $ 0.63 $ 0.55
In fiscal 2000, approximately 56%, 32% and 12% of the Company's oil and
natural gas revenues were from the sale of natural gas, the sale of oil and the
sale of natural gas liquids, respectively.
In fiscal 2000, the Company's natural gas production averaged net sales
volume after royalties of 9,560 MCF per day, a decrease of 4% from 9,960 MCF per
day in fiscal 1999. This decrease was due to natural declines in production from
some of the Company's mature properties (Hillsdown, Charlotte Lake, Thornbury,
and Pouce Coupe) and higher royalty percentage rates due to higher prices.
Dunvegan continues to contribute approximately 51% of the Company's natural gas
production.
In fiscal 2000, oil sales averaged net production of 510 barrels per
day, a decrease of 12% from 580 barrels per day in fiscal 1999. The Company's
major oil producing properties are the Red Earth, Chauvin and Manyberries areas
in Canada. This decrease was due to higher royalty percentage rates due to
higher prices and natural declines in production from some of the Company's
mature properties (Red Earth, Chauvin and Manyberries).
In fiscal 2000, natural gas liquid sales averaged net production of 280
barrels per day, an increase of 17% from 240 barrels per day in fiscal 1999.
This increase was due to increased liquids production at Dunvegan. Dunvegan
provided 83% of the Company's fiscal 2000 natural gas liquids production. Other
major natural gas liquids producing properties are the Hillsdown, Pembina and
Pouce Coupe areas in Alberta.
In fiscal 1999, approximately 60%, 31% and 9% of the Company's oil and
natural gas revenues were from the sale of natural gas, the sale of oil and the
sale of natural gas liquids, respectively.
The following table sets forth the gross and net number of productive
wells Barnwell has an interest in as of September 30, 2000.
<PAGE>
Productive Wells
----------------
Productive Wells****
-------------------------
Gross***** Net*****
---------- -----------
Location Oil Gas Oil Gas
-------- --- --- ---- ----
Canada
Alberta 151 418 23.3 40.8
Saskatchewan 2 14 0.2 2.4
British Columbia - 1 - 0.5
--- --- ---- ----
Total 153 433 23.5 43.7
=== === ==== ====
--------------------------------
* When used in this report, "MCF" means 1,000 cubic feet of natural gas at
14.65 psia and 60 degrees F and the term "BBLS" means stock tank barrels
of oil equivalent to 42 U.S. gallons.
** Calculated on revenues before royalty expense and royalty tax credit
divided by gross production.
*** Natural gas liquids, oil and natural gas units were combined by
converting barrels of natural gas liquids and oil to an MCF equivalent
("MCFE") on the basis of 5.8 MCF = 1 BBL.
**** Seventy-two gross natural gas wells have dual or multiple completions
and six gross oil wells have dual completions.
***** Please see note (2) on the following table.
Developed Acreage and Undeveloped Acreage
-----------------------------------------
The following table sets forth certain information with respect to oil
and natural gas properties of Barnwell as of September 30, 2000:
Developed and
Developed Undeveloped Undeveloped
Acreage(1) Acreage(1) Acreage(1)
---------------- ---------------- ----------------
Location Gross(2) Net(2) Gross(2) Net(2) Gross(2) Net(2)
------------------ -------- ------ -------- ------ -------- ------
Canada
------
Alberta 247,907 29,814 146,469 31,445 394,376 61,259
British Columbia 1,193 395 4,931 1,355 6,124 1,750
Saskatchewan 3,696 543 200 11 3,896 554
U.S.
----
North Dakota 1,520 264 22,039 10,008 23,559 10,272
------- ------ ------- ------ -------- ------
Total 254,316 31,016 173,639 42,819 427,955 73,835
======= ====== ======== ====== ======== ======
---------------------------------
(1) "Developed Acreage" includes the acres covered by leases upon which
there are one or more producing wells. "Undeveloped Acreage" includes
acres covered by leases upon which there are no producing wells and
which are maintained in effect by the payment of delay rentals or the
commencement of drilling thereon.
(2) "Gross" refers to the total number of wells or acres in which Barnwell
owns an interest, and "Net" refers to Barnwell's aggregate interest
therein. For example, a 50% interest in a well represents one Gross
Well, but .50 Net Well, and similarly, a 50% interest in a 320 acre
lease represents 320 Gross Acres and 160 Net Acres. The gross wells and
gross acreage figures include interests owned of record by Barnwell and,
in addition, the portion owned by others.
<PAGE>
Barnwell's leasehold interests in its undeveloped acreage, if not
developed, expire over the next five fiscal years as follows: 28% expire during
fiscal 2001; 18% expire during fiscal 2002; 13% expire during fiscal 2003; 7%
expire during fiscal 2004 and 34% expire during fiscal 2005. There can be no
assurance that the Company will be successful in renewing its leasehold
interests in the event of expiration.
Barnwell's undeveloped acreage includes major concentrations in Alberta
at Thornbury (6,360 net acres), Archie (4,000 net acres), Red Earth (2,220 net
acres) and Gere (2,100 net acres).
Reserves
--------
The amounts set forth in the table below, prepared by Paddock Lindstrom
Associates Ltd., Barnwell's independent reservoir engineering consultants,
summarize the estimated net quantities of proved developed producing reserves
and proved developed reserves of crude oil (including condensate and natural gas
liquids) and natural gas as of September 30, 2000, 1999 and 1998 on all
properties in which Barnwell has an interest. These reserves are before
deductions for indebtedness secured by the properties and are based on constant
dollars. No estimates of total proved net oil or natural gas reserves have been
filed with or included in reports to any federal authority or agency since
October 1, 1980.
Proved Producing Reserves
-------------------------
September 30,
--------------------------------------
2000 1999 1998
---------- ---------- ----------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 1,508,000 1,759,000 2,109,000
Natural gas - thousand
cubic feet (MCF) 20,594,000 25,908,000 28,306,000
Total Proved Reserves
(Includes Proved Producing Reserves)
--------------------------------------
September 30,
--------------------------------------
2000 1999 1998
---------- ---------- ----------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 1,781,000 2,138,000 2,413,000
Natural gas - thousand
cubic feet (MCF) 29,796,000 36,879,000 40,561,000
As of September 30, 2000, essentially all of Barnwell's proved producing
and total proved reserves were located in the Province of Alberta, with minor
volumes located in the Provinces of Saskatchewan and British Columbia.
<PAGE>
During fiscal 2000, Barnwell's total net proved reserves, including
proved producing reserves, of oil, condensate and natural gas liquids decreased
by 357,000 barrels, and total net proved reserves of natural gas decreased by
7,083,000 MCF. The change in oil, condensate and natural gas liquids reserves
was the net result of production during the year of 291,000 barrels, the
addition of 72,000 barrels from the drilling of productive wells, the deduction
of 131,000 barrels due to higher royalty rates, and the independent engineer's
7,000 barrel downward revision of the Company's oil reserves. Barnwell's proved
natural gas reserves decreased as a net result of production during the year of
3,501,000 MCF, the addition of 2,417,000 MCF from the drilling of productive
natural gas wells, the deduction of 5,699,000 MCF due to higher royalty rates,
and the independent engineer's 300,000 MCF downward revision of the Company's
natural gas reserves. The deduction of reserve units due to higher royalty rates
is the result of Alberta's royalties being calculated on a sliding scale basis,
with the royalty percentage increasing as prices increase. The Province of
Alberta takes its royalty share of production based on commodity prices; as all
commodity prices were significantly higher at September 30, 2000, as compared to
September 30, 1999, significantly more reserves were deducted for royalty
volumes at September 30, 2000, as compared to September 30, 1999.
Barnwell's working interest in the Dunvegan Unit accounted for
approximately 64% and 65% of its total proved natural gas reserves at September
30, 2000 and 1999, respectively, and approximately 35% of proved developed oil
and condensate reserves at September 30, 2000, as compared to approximately 32%
of proved developed oil and condensate reserves at September 30, 1999.
The following table sets forth the Company's oil and natural gas
reserves at September 30, 2000, by property name, based on information prepared
by Paddock Lindstrom and Associates, Ltd., Barnwell's independent reservoir
engineering consultant. Gross reserves are before the deduction of royalties;
net reserves are after the deduction of royalties net of the Alberta Royalty Tax
Credit. This table is based on constant dollars where reserve estimates are
based on sales prices, costs and statutory tax rates in existence at the date of
the projection. Oil, which includes natural gas liquids, is shown in thousands
of barrels ("MBBLS") and natural gas is shown in millions of cubic feet
("MMCF").
<PAGE>
<TABLE>
<CAPTION>
OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 2000
Total Proved Producing Total Proved
--------------------------- ---------------------------
Oil & NGL's Gas Oil & NGL's Gas
------------- ------------- ------------- -------------
Property Name Gross Net Gross Net Gross Net Gross Net
(MBBLS) (MMCF) (MBBLS) (MMCF)
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dunvegan 674 471 19,175 14,483 883 621 25,099 19,185
Dunvegan Non-Unit 113 86 248 181 124 93 556 393
Hillsdown 35 26 1,489 1,172 55 42 1,654 1,304
Thornbury -- -- 1,460 1,184 -- -- 1,724 1,408
Manyberries 108 90 19 12 124 103 23 14
Pouce Coupe 3 2 680 474 36 25 1,899 1,297
Red Earth/Loon 680 593 -- -- 701 606 -- --
Barrhead 3 3 267 234 3 3 383 315
Bashaw -- -- 20 17 -- -- 20 17
Belloy 1 1 291 205 1 1 437 317
Cessford 6 5 -- -- 6 5 -- --
Charlotte Lake 18 15 420 365 18 15 857 712
Chauvin 84 71 -- -- 84 71 -- --
Chigwell -- -- 9 9 -- -- 9 9
Coyote 1 1 22 22 1 1 22 22
Cynthia-Pembina 35 29 505 355 35 29 505 355
Drumheller 15 10 370 236 15 10 370 236
Faith South -- -- -- -- -- -- 1,011 701
Fenn-Big Valley -- -- 3 2 -- -- 3 2
Gilby 1 1 38 28 1 1 38 28
Gilwood -- -- -- -- -- -- 82 51
Heathdale -- -- 286 219 -- -- 286 219
Hilda -- -- 44 41 -- -- 44 41
Killam -- -- 1 1 -- -- 1 1
Leduc 14 11 61 48 14 11 265 199
Majeau Lake -- -- 19 16 -- -- 19 16
Medicine River 50 38 137 103 76 56 1,074 693
Mikwan -- -- 21 19 -- -- 21 19
Mitsue -- -- 25 19 -- -- 25 19
Pembina 3 2 71 48 3 2 71 48
Rainbow 1 -- -- -- 1 -- -- --
Richdale -- -- -- -- -- -- 178 136
Staplehurst 10 9 -- -- 23 20 -- --
Sunnynook 4 3 770 541 4 3 770 541
Tomahawk -- -- -- -- 14 12 285 185
Wood River 13 11 280 208 13 11 280 208
Worsley 1 1 1 1 1 1 1 1
Zama 29 26 202 119 31 27 575 350
Rigel, British Columbia -- -- -- -- 12 9 732 522
Hatton, Saskatchewan -- -- 329 232 -- -- 329 232
Webb-Beverley, Saskatchewan 3 3 -- -- 3 3 -- --
------ ------ ------ ------ ------ ------ ------ ------
TOTAL 1,905 1,508 27,263 20,594 2,282 1,781 39,648 29,796
====== ====== ====== ====== ====== ====== ====== ======
<FN>
Properties are located in Alberta, Canada unless otherwise noted.
</FN>
</TABLE>
<PAGE>
Estimated Future Net Revenues
-----------------------------
The following table sets forth Barnwell's "Estimated Future Net
Revenues" from total proved oil, natural gas and condensate reserves and the
present value of Barnwell's "Estimated Future Net Revenues" (discounted at 10%).
Estimated future net revenues for total proved reserves are net of estimated
development costs. Net revenues have been calculated using current sales prices
and costs, after deducting all royalties net of the Alberta Royalty Tax Credit,
operating costs, future estimated capital expenditures, and income taxes.
Proved Producing Total Proved
Reserves Reserves
---------------- ------------
Year ending September 30,
2001 $ 7,208,000 $ 7,488,000
2002 6,924,000 8,321,000
2003 5,714,000 7,502,000
Thereafter 35,999,000 50,795,000
----------- -----------
$55,845,000 $74,106,000
=========== ===========
Present value (discounted at 10%)
at September 30, 2000 $32,026,000 $42,500,000
=========== ===========
Marketing of Oil and Natural Gas
--------------------------------
Barnwell sells substantially all of its oil and condensate production
under short-term contracts between itself or the operator of the property and
marketers of oil. The price of oil is freely negotiated between the buyers and
sellers.
Natural gas sold by the Company is generally sold under both long-term
and short-term contracts with prices indexed to market prices. The price of
natural gas and natural gas liquids is freely negotiated between buyers and
sellers. In 2000, 1999 and 1998, the Company took most of its oil and natural
gas "in kind" where the Company markets the products instead of having the
operator of a producing property market the products on the Company's behalf.
In fiscal 2000, natural gas production from the Dunvegan Unit was
responsible for approximately 49% of the Company's natural gas revenues. In
fiscal 2000, the Company had three individually significant customers that
accounted for 63% of the Company's oil and natural gas revenues. A substantial
portion of Barnwell's Dunvegan natural gas production and natural gas production
from other properties is sold to aggregators and marketers under various
short-term and long-term contracts, with the price of natural gas determined by
negotiations between the aggregators and the final purchasers. In fiscal 2000,
Barnwell continued to increase the volumes of natural gas sold into spot markets
to take advantage of new pipeline access to premium markets and higher prices.
<PAGE>
Governmental Regulation
-----------------------
The jurisdictions in which the oil and natural gas properties of
Barnwell are located have regulatory provisions relating to permits for the
drilling of wells, the spacing of wells, the prevention of oil and natural gas
waste, allowable rates of production and other matters. The amount of oil and
natural gas produced is subject to control by regulatory agencies in each
province and state that periodically assign allowable rates of production. The
Province of Alberta and Government of Canada also monitor and regulate the
volume of natural gas that may be removed from the province and the conditions
of removal.
There is no current government regulation of the price that may be
charged on the sale of Canadian oil or natural gas production. Canadian natural
gas production destined for export is priced by market forces subject to export
contracts meeting certain criteria prescribed by Canada's National Energy Board
and the Government of Canada.
The right to explore for and develop oil and natural gas on lands in
Alberta, Saskatchewan and British Columbia is controlled by the governments of
each of those provinces. Changes in royalties and other terms of provincial
leases, permits and reservations may have a substantial effect on the Company's
operations. In addition to the foregoing, in the future, Barnwell's Canadian
operations may be affected from time to time by political developments in Canada
and by Canadian Federal, provincial and local laws and regulations, such as
restrictions on production and export, oil and natural gas allocation and
rationing, price controls, tax increases, expropriation of property,
modification or cancellation of contract rights, and environmental protection
controls. Furthermore, operations may also be affected by United States import
fees and restrictions.
Different royalty rates are imposed by the producing provinces, the
Government of Canada and private interests with respect to the production and
sale of crude oil, natural gas and liquids. In addition, some producing
provinces receive additional revenue through the imposition of taxes on crude
oil and natural gas owned by private interests within the province. Essentially,
provincial royalties are calculated as a percentage of revenue, and vary
depending on production volumes, selling prices and the date of discovery.
Canadian taxpayers are not permitted to deduct royalties, taxes, rentals
and similar levies paid to the Federal or provincial governments in connection
with oil and natural gas production in computing income for purposes of Canadian
Federal income tax. However, they are allowed to deduct a "Resource Allowance"
which is 25% of the taxpayer's "Resource Profits for the Year" (essentially,
income from the production of oil, natural gas or minerals) in computing their
taxable income.
In Alberta, a producer of oil or natural gas is entitled to a credit
against the royalties payable to the Crown by virtue of the Alberta Royalty Tax
Credit ("ARTC") program. The ARTC rate is based on a price-sensitive formula and
varies between 75% at prices below a specified royalty tax credit reference
price decreasing to 25% at prices above a specified royalty tax credit reference
price. The ARTC will be applied to a maximum annual amount of $2,000,000
Canadian dollars of Alberta Crown royalties payable for each producer or
associated group of producers. Crown royalties on production from producing
properties acquired from corporations claiming maximum entitlements to ARTC will
generally not be eligible for ARTC. The rate is established quarterly based on
<PAGE>
the average royalty tax credit reference price, as determined by the Alberta
Department of Energy. The royalty tax credit reference price is based on a
weighted average oil and gas price.
The Province of Alberta has stated that changes in the ARTC will be
announced three years in advance. In 1999, the Alberta government announced that
it would introduce new rules to preclude companies that pay less than
approximately $6,500 in royalties per year from qualifying for the program; this
change will not impact the Company. The ARTC program has been in effect in
various forms since 1974 and the Company anticipates that it will be continued
in some form for the foreseeable future. In fiscal 2000, the Company's ARTC
totaled approximately $450,000. If the ARTC is not continued, it will have an
adverse effect on the Company.
The resource properties located in the United States are freehold
mineral interests leased under market conditions, subject to extraction and
severance taxes imposed according to state regulations.
Competition
-----------
The majority of Barnwell's natural gas sales take place in Alberta,
Canada. Natural gas prices in Alberta are generally competitive with other major
North American areas due to increased pipeline capacity into the United States.
Barnwell's oil and natural gas liquids are sold in Alberta with prices
determined by the world price for oil.
The Company competes in the sale of oil and natural gas on the basis of
price, and on the ability to deliver products. The oil and natural gas industry
is intensely competitive in all phases, including the exploration for new
production and reserves and the acquisition of equipment and labor necessary to
conduct drilling activities. The competition comes from numerous major oil
companies as well as numerous other independent operators. There is also
competition between the oil and natural gas industry and other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers. Barnwell is a minor participant in the industry and
competes in its oil and natural gas activities with many other companies having
far greater financial and other resources.
CONTRACT DRILLING OPERATIONS
----------------------------
Barnwell owns 100% of Water Resources International, Inc. ("WRI"). WRI
drills water and exploratory wells and installs and repairs water pumping
systems in Hawaii. Additionally, in fiscal 1999, the Company started providing
contract labor for the drilling and workovers of geothermal wells; this work
continued into and was completed during fiscal 2000. WRI owns and operates four
Spencer-Harris portable rotary drill rigs ranging in drilling capacity from
3,500 feet to 7,000 feet, and one IDECO H-35 rotary drill/workover rig.
Additionally, WRI owns a two acre parcel of real estate in an industrial park 11
miles south of Hilo, Hawaii. WRI also leases a three-quarter of an acre
maintenance facility in Honolulu and a one acre maintenance and storage facility
with 2,800 square feet of interior space in Kawaihae, Hawaii, and maintains an
inventory of drilling and pump supplies. As of September 30, 2000, WRI employed
20 drilling, pump and administrative employees, none of whom are union members.
WRI drills water, geothermal and exploratory wells of varying depths in
Hawaii. In fiscal 1999, in addition to drilling water wells and drilling and
plugging geothermal wells, WRI drilled a 10,370 feet deep exploratory
<PAGE>
core-sampling well for the Hawaii Scientific Drilling Project, in which an
almost continuous two mile core of the earth's crust was extracted for
scientific research purposes. This project was completed fiscal 2000. WRI also
installs and repairs water pumps and is the state of Hawaii's distributor for
Floway pumps and equipment. The demand for WRI's services is primarily dependent
upon land development activities in Hawaii. WRI markets its services to land
developers and government agencies, and identifies potential contracts through
public notices, its officers' involvement in community activities and referrals.
Contracts are usually fixed price per lineal foot or day rate contracts and are
negotiated with private entities or obtained through competitive bidding with
private entities or with local, state and Federal agencies. Contract revenues
are not dependent upon the discovery of water, geothermal production zones or
other, similar targets, and contracts are not subject to renegotiation of
profits or termination at the election of the governmental entities involved.
Contracts provide for arbitration in the event of disputes.
The Company's contract drilling subsidiary derived 70%, 43% and 42% of
its contract drilling revenues in fiscal 2000, 1999 and 1998, respectively,
pursuant to federal, State of Hawaii and local county contracts. At September
30, 2000, the Company had accounts receivable from the State of Hawaii and local
county entities totaling approximately $277,000. The Company has lien rights on
contracts with federal, State of Hawaii, local county and private entities.
The Company's contract drilling segment currently operates in Hawaii and
is not subject to seasonal fluctuations.
Activity
--------
In fiscal 2000, WRI started six well drilling contracts and three pump
installation contracts and completed seven well drilling contracts and five pump
installation contracts. Four of the seven completed well contracts and three of
the five completed pump installation contracts were started in the prior year.
Ninety percent (90%) of such well drilling and pump installation jobs,
representing 70% of total contract drilling revenues in fiscal 2000, have been
pursuant to government contracts.
At September 30, 2000, WRI had a backlog of eight well drilling
contracts and six pump installation and repair contracts, three and one of
which, respectively, were in progress as of September 30, 2000.
The dollar amount of the Company's backlog of firm well drilling and
pump installation and repair contracts at November 30, 2000 and 1999 is as
follows:
2000 1999
---------- ----------
Well drilling $2,700,000 $2,000,000
Pump installation and repair 900,000 300,000
---------- ----------
$3,600,000 $2,300,000
========== ==========
All but two of the contracts in backlog at November 30, 2000 are
expected to be completed within fiscal year 2001.
<PAGE>
Competition
-----------
WRI utilizes rotary drill rigs that have the capability of drilling
wells faster than cable tool rigs. There are seven other drilling contractors in
Hawaii which use cable tool or rotary drill rigs that are capable of drilling
wells, and six other Hawaii contractors who are capable of installing and
repairing vertical turbine and submersible water pumping systems in Hawaii.
These contractors compete actively with WRI for government and private
contracts. Pricing is the Company's major method of competition; reliability of
service is also a significant factor.
The number of available water well drilling jobs has not changed
significantly from the prior year. However, the Company was able to bid
successfully and obtain significant drilling contracts for scientific and
geothermal work. The Company expects competitive pressures within the industry
to remain high as demand for well drilling and pump installation in Hawaii is
not expected to increase significantly in fiscal year 2001.
LAND INVESTMENT OPERATIONS
--------------------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments,
a Hawaii general partnership. Between 1986 and 1989, Kaupulehu Developments
obtained the state and county zoning changes necessary to permit development of
the Four Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club,
which opened in 1996, a second golf course (currently under construction), and
single and multiple family residential units on land acquired from Kaupulehu
Developments, located approximately six miles north of the Kona International
Airport in the North Kona District of the Island of Hawaii.
At September 30, 2000, Kaupulehu Developments owns residential
development rights in approximately 80 acres which are under option to Kaupulehu
Makai Venture, an affiliate of Kajima Corporation of Japan. If Kaupulehu Makai
Venture fully exercises this option applicable to these approximately 80 acres,
Kaupulehu Developments will receive a total of $25,500,000. The option expires
on April 30, 2003 unless 50% of the option proceeds are received on or before
April 30, 2003. The remainder of the option would then expire on April 30, 2007.
There is no assurance that this option or any portion of it will be exercised.
At September 30, 2000, Kaupulehu Developments also holds leasehold
rights in approximately 2,100 acres of land located adjacent to and north of the
Four Seasons Resort Hualalai at Historic Ka'upulehu. These approximately 2,100
acres are located between the Queen Kaahumanu Highway and the Pacific Ocean. In
June 1996, the State Land Use Commission ("LUC") approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of
these 2,100 acres of land into the Urban District for resort/residential
development. Subsequent to the LUC's approval, a notice of appeal was filed with
the Third Circuit Court of the State of Hawaii by parties seeking to reverse the
LUC's decision. The Third Circuit Court of the State of Hawaii upheld the LUC's
approval of Kaupulehu Developments' rezoning request in all respects in a
Decision and Order issued in August 1997. In November 1997, a notice of appeal
was filed with the Supreme Court of the State of Hawaii by parties seeking to
reverse the Third Circuit Court's decision.
In June 1998, Kaupulehu Developments filed an Application for a Project
District zoning ordinance and a Special Management Area ("SMA") Use Permit
<PAGE>
Petition with the County of Hawaii, requesting changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential, resort and
commercial development. Both the County zoning ordinance and the SMA Use Permit
are required for development of the property. In December 1998, following a
contested case hearing conducted in November 1998, the Planning Commission of
the County of Hawaii granted the requested SMA Use Permit to Kaupulehu
Developments to be effective when the zoning ordinance is adopted. Subsequent to
the Planning Commission's approval, in January 1999, a notice of appeal was
filed with the Third Circuit Court of the State of Hawaii by parties seeking to
reverse the Planning Commission's decision. In April 1999, the County of Hawaii
adopted an ordinance granting zoning approval of Kaupulehu Developments'
Application for a Project District zoning ordinance, which requested changes in
zoning and use of the aforementioned 1,000 acres of land to allow residential,
resort and commercial development.
Activity
--------
In January 2000, Kaupulehu Makai Venture exercised a portion of the
option granted in 1990 by Kaupulehu Developments for the development of
residential parcels within the Four Seasons Resort Hualalai at Historic
Ka'upulehu on the Island of Hawaii. The Company recognized revenues of
$6,540,000, net of costs associated with the transaction, from the receipt of
the option monies. $1,300,000 of the proceeds were used to repay Kaupulehu
Developments' borrowings from a Hawaii bank, and $873,000 were distributed to
Kaupulehu Developments' minority interest partner, Cambridge Hawaii Limited
Partnership ("CHLP"), which holds the remaining 49.9% interest in Kaupulehu
Developments. CHLP is a Hawaii limited partnership comprised of three Canadian
limited partnerships, comprised of individuals, one of whom is Mr. Terry
Johnston. Mr. Johnston was elected to the Board of Directors of the Company in
March 2000.
In December 1999, the Third Circuit Court of the County of Hawaii
remanded Kaupulehu Developments' SMA Use Permit Petition back to the County of
Hawaii Planning Commission for further review due to procedural issues. In late
December 1999, the County of Hawaii Planning Commission reaffirmed their
approval of the SMA Use Permit Petition.
In September 2000, the Supreme Court of the State of Hawaii ruled on the
appeal of the LUC's decision, finding in favor of Kaupulehu Developments on
three of the issues on appeal, but on the fourth issue, the court remanded the
matter to the LUC for the limited purpose of entering specific findings and
conclusions, with further hearing if necessary, regarding: (1) the identity and
scope of "valued cultural, historical, or natural resources" in the petition
area, including the extent to which traditional and customary native Hawaiian
rights are exercised in the petition area; (2) the extent to which those
resources - including traditional and customary native Hawaiian rights - will be
affected or impaired by the proposed action; and (3) the feasible action, if
any, to be taken by the LUC to reasonably protect native Hawaiian rights if they
are found to exist. In October 2000, Kaupulehu Developments filed a motion with
the LUC to bring the matter in front of the LUC. Management cannot predict the
timing or outcome of the LUC's procedures or findings and, accordingly, there is
no assurance that State of Hawaii zoning approval will be forthcoming at any
time. If the Company is unable to obtain the LUC's approval, there will be a
materially adverse impairment of the value of the Company's leasehold rights in
this approximately 1,000 acres.
<PAGE>
Kaupulehu Developments continues to negotiate a revised development
agreement and residential fee purchase prices with the lessor of the 2,100 acre
parcel. Management cannot predict the outcome of these negotiations.
The Company did not receive any revenues in fiscal 1999 and 1998 related
to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments'
revenues specifically relate to sales of leasehold interests and development
rights, which do not occur every year.
Competition
-----------
The Company's land investment segment is subject to intense competition
in all phases of its operations including the acquisition of new properties, the
securing of approvals necessary for land rezoning, and the search for potential
buyers of property interests presently owned. The competition comes from
numerous independent land development companies and other industries involved in
land investment activities. The principal methods of competition are the
location of the project and pricing. Kaupulehu Developments is a minor
participant in the land development industry and competes in its land investment
activities with many other entities having far greater financial and other
resources.
For the past several years, Hawaii's economy has experienced little or
no growth and the real estate market has been slow. However, the South
Kohala/North Kona area of the island of Hawaii, the area in which Kaupulehu
Developments' property is located, has experienced strong demand in recent
years. This trend continued through fiscal 2000 and is not expected to decline
significantly in the near term, although there can be no assurance this trend
will in fact continue.
Item 3. Legal Proceedings
-----------------
In June 1996, the State Land Use Commission ("LUC") approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of
these 2,100 acres of land into the Urban District for resort/residential
development. Subsequent to the LUC's approval, a notice of appeal was filed with
the Third Circuit Court of the State of Hawaii by parties seeking to reverse the
LUC's decision. The Third Circuit Court of the State of Hawaii upheld the Land
Use Commission's approval of Kaupulehu Developments' rezoning request in all
respects in a Decision and Order issued in August 1997. In November 1997, a
notice of appeal was filed with the Supreme Court of the State of Hawaii by
parties seeking to reverse the Third Circuit Court's decision. In September
2000, the Supreme Court of the State of Hawaii ruled on the appeal of the LUC's
decision, finding in favor of Kaupulehu Developments on three of the issues on
appeal, but on the fourth issue, the court remanded the matter to the LUC for
the limited purpose of entering specific findings and conclusions, with further
hearing if necessary, regarding: (1) the identity and scope of "valued cultural,
historical, or natural resources" in the petition area, including the extent to
which traditional and customary native Hawaiian rights are exercised in the
petition area; (2) the extent to which those resources - including traditional
and customary native Hawaiian rights - will be affected or impaired by the
proposed action; and (3) the feasible action, if any, to be taken by the LUC to
reasonably protect native Hawaiian rights if they are found to exist. In October
2000, Kaupulehu Developments filed a motion with the LUC to bring the matter in
front of the LUC. Management cannot predict the timing or outcome of the LUC's
procedures or findings and, accordingly, there is no assurance that State of
Hawaii zoning approval will be forthcoming at any time. If the Company is unable
<PAGE>
to obtain the LUC's approval, there will be a materially adverse impairment of
the value of the Company's leasehold rights in this approximately 1,000 acres.
The Company is involved in routine litigation and is subject to
governmental and regulatory controls that are incidental to the business. The
Company's management believes that routine claims and litigation involving the
Company are not likely to have a material adverse effect on its financial
position, results of operations or liquidity.
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
None.
PART II
Item 5. Market For Common Equity and Related Stockholder Matters
--------------------------------------------------------
The principal market on which the Company's common stock is being traded
is the American Stock Exchange. The following tables present the quarterly high
and low closing prices, on the American Stock Exchange, for the registrant's
common stock during the periods indicated:
Quarter Ended High Low Quarter Ended High Low
------------- ------ ------ ------------------ ------ ------
December 31, 1998 12-7/16 11-1/8 December 31, 1999 12-3/4 9-3/4
March 31, 1999 12-1/8 11 March 31, 2000 14-3/4 12-3/4
June 30, 1999 11-3/4 10-7/8 June 30, 2000 15-3/4 13-3/8
September 30, 1999 13-1/4 10-3/8 September 30, 2000 18-7/8 14-3/4
As of November 30, 2000, there were 1,310,952 shares of common stock,
par value $.50, outstanding. There were approximately 400 holders of the common
stock of the registrant as of November 30, 2000.
The Company declared and paid $131,000 in dividends ($0.10 per share) in
the fourth quarter of fiscal 2000.
In December 2000, the Company declared a dividend of $0.15 per share
payable January 3, 2001, to stockholders of record December 12, 2000.
<PAGE>
Item 6. Management's Discussion and Analysis or Plan of Operation
---------------------------------------------------------
The following section contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended, including various
forecasts, projections of Barnwell's future performance, statements of the
Company's plans and objectives and other similar types of information. Although
the Company believes that its expectations are based on reasonable assumptions,
it cannot assure that the expectations contained in such forward-looking
statements will be achieved. Such statements involve risks, uncertainties and
assumptions, including, but not limited to, those relating to the factors
discussed below, in other portions of this Form 10-KSB, in the Notes to
Consolidated Financial Statements, and in other documents filed by the Company
with the Securities and Exchange Commission from time to time, which could cause
actual results to differ materially from those contained in such statements.
Factors that could cause or contribute to such differences include, but are not
limited to, those discussed under Part I, "Forward-Looking Statements," as well
as those discussed elsewhere in this Form 10-KSB. All forward-looking statements
contained in this Form 10-KSB are qualified in their entirety by this statement
and speak only as of the date of filing of this Form 10-KSB, and the Company
expressly disclaims any obligation or undertaking to publicly release any
updates or revisions to any forward-looking statements contained herein.
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------
Cash flows from operations were $8,194,000 in fiscal 2000, as compared to
$2,725,000 in fiscal 1999, an increase of $5,469,000 (201%). The increase was
due to higher operating profit generated by the Company's oil and natural gas
segment and differences in the timing of accounts payable and accrued expense
disbursements in fiscal 2000, as compared to fiscal 1999.
In January 2000, Kaupulehu Makai Venture, an affiliate of Kajima
Corporation of Japan, exercised a portion of the option granted in 1990 by
Kaupulehu Developments, a 50.1%-owned general partnership, for the development
of residential parcels within the Four Seasons Resort Hualalai at Historic
Ka'upulehu on the Island of Hawaii. The Company received $6,540,000 in cash, net
of costs associated with the transaction, from this partial exercise of the
option. $1,300,000 of the proceeds were used to repay borrowings, and $873,000
were distributed to Kaupulehu Developments' minority interest partner, Cambridge
Hawaii Limited Partnership ("CHLP"), which holds the remaining 49.9% interest in
Kaupulehu Developments.
During fiscal 2000, the Company repaid $3,066,000 of its borrowings under
a revolving credit facility with the Royal Bank of Canada. The facility is for
$17,000,000 Canadian dollars or its U.S. dollar equivalent of approximately
$11,300,000 at September 30, 2000. The facility is reviewed annually with a
primary focus on the future cash flows generated by the Company's oil and
natural gas properties. The next review is planned for April 2001. Subject to
that review, the facility may be extended one year with no required debt
repayments for one year, or converted to a five-year term loan by the bank. If
the facility is converted to a five-year term loan, the Company has agreed to
the following repayment schedule of the then outstanding balance: year 1 - 30%;
year 2 - 27%; year 3 - 16%; year 4 - 14%; year 5 - 13%. The facility is
collateralized by the Company's interests in its major oil and natural gas
properties and a negative pledge on its remaining oil and natural gas
properties. No compensating bank balances are required on any of the Company's
indebtedness under the facility.
<PAGE>
The Canadian bank has represented that it will not require any repayments
under the facility before September 30, 2001. Accordingly, the Company has
classified outstanding borrowings under the facility as long-term debt.
The Company has $1,200,000 of convertible notes outstanding at September
30, 2000 that are payable in 12 consecutive, equal quarterly installments.
Interest is payable quarterly at a rate to be adjusted each quarter to the
greater of 10% per annum or 1% over the prime rate of interest. The Company paid
interest on these notes at an average rate of 10.13% per annum in fiscal 2000.
For more information on the Company's long-term debt, see Note 5 of "Notes to
the Consolidated Financial Statements" in Item 7.
During fiscal 2000, the Company repurchased 6,000 shares of its common
stock on the open market for $93,000 (average price of $15.50 per share) under a
March 2000 stock buyback plan authorizing the repurchase of up to 100,000
shares. The Company plans to repurchase additional shares from time to time in
the open market or in privately negotiated transactions, depending on market
conditions. The Company also declared and paid $131,000 in dividends ($0.10 per
share) in the fourth quarter of fiscal 2000.
At September 30, 2000, the Company's consolidated cash and cash
equivalents amounted to $5,701,000, working capital was $1,734,000, and
available credit under the Royal Bank of Canada's revolving credit facility was
approximately $2,960,000.
The Company believes its current cash balances, future cash flows from
operations, and available credit will be sufficient to fund its estimated
capital expenditures, make the scheduled repayments on its convertible notes,
and meet the repayment schedule on its Royal Bank of Canada facility, should the
Company or the Royal Bank of Canada elect to convert the facility to a term
loan.
The following table sets forth the Company's capital expenditures for each
of the last three fiscal years:
2000 1999 1998
----------- ----------- ------------
Oil and natural gas $ 5,003,000 $ 1,753,000 $ 6,969,000
Land investment 631,000 809,000 862,000
Contract drilling 393,000 121,000 91,000
Other 222,000 148,000 205,000
----------- ----------- -----------
Total capital expenditures $ 6,249,000 $ 2,831,000 $ 8,127,000
=========== =========== ===========
Increase (decrease) in oil
and natural gas capital
expenditures from prior year $ 3,250,000 $(5,216,000) $ 492,000
=========== =========== ===========
The Company increased its capital expenditures in fiscal 2000, as compared
to fiscal 1999, in response to the upturn in petroleum prices in fiscal 2000.
The Company participated in drilling 40 wells, 34 of which were successful, and
the recompletion of 13 wells (1.2 net wells).
<PAGE>
The following table sets forth the gross and net numbers of oil and
natural gas wells the Company participated in drilling and purchased for each of
the last three fiscal years:
2000 1999 1998
------------ ------------ ------------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
Exploratory oil and natural
gas wells drilled 8 2.60 2 0.35 9 1.38
Development oil and natural
gas wells drilled 32 5.10 13 1.01 50 5.24
Successful oil and natural
Wells drilled 34 5.60 13 1.22 45 5.05
In fiscal 1999 and continuing in fiscal 2000, the Company built a
technical team to internally generate oil and gas exploration projects. The team
is focused on areas encompassing Northwest and Central Alberta.
The Company estimates that oil and natural gas capital expenditures for
fiscal 2001 will increase significantly to between $7,500,000 and $9,000,000.
This estimated amount may increase or decrease as dictated by management's
assessment of the oil and gas environment and prospects.
In fiscal 2000, $631,000 of the Company's capital expenditures were
applicable to the rezoning of leasehold land in North Kona, Hawaii, from
conservation to urban, as compared to $809,000 in fiscal 1999. These
expenditures were comprised of legal, consulting and planning fees incurred to
process Kaupulehu Developments' applications through the entitlement and
judiciary processes, as well as capitalized interest. The fiscal 2000 rezoning
expenditures were funded by cash generated from the sale of development rights.
In fiscal 2000, the Company invested $393,000 in capital expenditures
applicable to contract drilling operations, an increase from $121,000 in fiscal
1999. $288,000 of the contract drilling capital expenditures in fiscal 2000 were
for the improvement of the contract drilling storage and maintenance yard at
Sand Island, Oahu, Hawaii. These improvements were made to satisfy the Company's
obligation to improve the property, located between downtown Honolulu and the
Honolulu airport, under the terms of the 55 year property lease. All of these
capital expenditures were funded by cash flows generated by contract drilling
operations.
RESULTS OF OPERATIONS
---------------------
Summary
-------
Barnwell reported net earnings of $5,010,000 in fiscal 2000, an increase
of $4,490,000 (863%) over fiscal 1999, due to significant increases in operating
profits generated by its land investment and oil and natural gas segments.
Additionally, the Company's contract drilling operations generated an operating
<PAGE>
profit of $603,000 in fiscal 2000. Oil and natural gas segment operating profit
increased $4,833,000 (115%) from $4,188,000 in fiscal 1999 to $9,021,000 in
fiscal 2000 due primarily to 86% and 54% increases in oil and natural gas
prices, respectively. The land investment segment generated an operating profit
of $3,232,000 in fiscal 2000 due to the exercise of a portion of an outstanding
option to purchase development rights for certain residential parcels within the
Four Seasons Resort Hualalai at Historic Ka'upulehu on the Island of Hawaii. The
Company recognized revenues of $6,540,000, net of costs associated with the
transaction, from the receipt of the option monies.
Barnwell reported net earnings of $520,000 in fiscal 1999, an increase of
$4,410,000 over fiscal 1998, due to significant increases in operating profit
generated by both its oil and natural gas and contract drilling segments, and to
the absence of write-downs in fiscal 1999. Operating profits generated by the
Company's contract drilling segment increased $1,292,000 from an operating loss
of $550,000 in fiscal 1998 to an operating profit of $742,000 in fiscal 1999,
due primarily to an increased number of drilling contracts and due to the fact
that the scientific coring and geothermal well contracts performed in fiscal
1999 were operated on a 24 hour basis; the prior years' revenues were generated
by water well contracts which typically operate during daylight only. Operating
profit generated by the Company's oil and gas segment, excluding the 1998
non-cash write-downs, increased $709,000 from $3,479,000 in fiscal 1998 to
$4,188,000 in fiscal 1999 due primarily to 14% and 8% increases in natural gas
and oil prices, respectively.
Oil and Natural Gas Revenues
----------------------------
Selected Operating Statistics
The following tables set forth the Company's annual net production and
annual average price per unit of production for fiscal 2000 as compared to
fiscal 1999, and fiscal 1999 as compared to fiscal 1998. Production amounts
reported are net of royalties and the Alberta Royalty Tax Credit; production
reported in prior years has been restated to include units attributable to the
Alberta Royalty Tax Credit.
Fiscal 2000 - Fiscal 1999
-------------------------
Annual Net Production
---------------------------------------------------
Increase
(Decrease)
---------------------
2000 1999 Units %
---------- ---------- --------- -----
Liquids (Bbl)* 104,000 89,000 15,000 17%
Oil (Bbl)* 187,000 211,000 (24,000) (11%)
Natural gas (MCF)** 3,501,000 3,634,000 (133,000) (4%)
Annual Average Price Per Unit
---------------------------------------------------
Increase
---------------------
2000 1999 $ %
---------- ---------- --------- -----
Liquids (Bbl)* $16.91 $ 9.78 $ 7.13 73%
Oil (Bbl)* $26.15 $14.08 $12.07 86%
Natural gas (MCF)** $ 2.41 $ 1.57 $ 0.84 54%
<PAGE>
Fiscal 1999 - Fiscal 1998
-------------------------
Annual Net Production
---------------------------------------------------
Increase
(Decrease)
---------------------
1999 1998 Units %
---------- ---------- --------- -----
Liquids (Bbl)* 89,000 66,000 23,000 35%
Oil (Bbl)* 211,000 225,000 (14,000) (6%)
Natural gas (MCF)** 3,634,000 4,145,000 (511,000) (12%)
Annual Average Price Per Unit
---------------------------------------------------
Increase
(Decrease)
---------------------
1999 1998 $ %
---------- ---------- --------- -----
Liquids (Bbl)* $ 9.78 $11.36 $(1.58) (14%)
Oil (Bbl)* $14.08 $13.02 $ 1.06 8%
Natural gas (MCF)** $ 1.57 $ 1.38 $ 0.19 14%
*Bbl = stock tank barrel equivalent to 42 U.S. gallons
**MCF = 1,000 cubic feet
Oil and natural gas revenues increased $5,140,000 or 51% in fiscal 2000 to
$15,270,000, as compared to $10,130,000 in fiscal 1999, due to 86%, 54%, and 73%
increases in the average price received for oil, natural gas, and natural gas
liquids, respectively, and a 17% increase in natural gas liquids volumes. The
increase was partially offset by decreases in natural gas and oil volumes of 4%
and 11%, respectively. The decrease in natural gas and oil production was due to
higher royalty percentage rates due to higher prices in fiscal 2000, as compared
to fiscal 1999, and production declines at the Company's non-principal more
mature natural gas and oil properties.
Oil and natural gas revenues increased $730,000 or 8% in fiscal 1999 to
$10,130,000, as compared to $9,400,000 in fiscal 1998, due to 14% and 8%
increases in the average price received for natural gas and oil, respectively,
and a 35% increase in natural gas liquids volumes. The increase was partially
offset by decreases in natural gas and oil volumes of 12% and 6%, respectively,
and a 14% decrease in natural gas liquids prices. The decrease in natural gas
and oil production was due to projected production declines at the Company's
principal natural gas and oil properties.
Oil and Natural Gas Operating Expenses
--------------------------------------
Operating expenses decreased to $3,128,000 in fiscal 2000, a $240,000 (7%)
decrease from $3,368,000 in fiscal 1999. The decrease is due to significantly
lower turnaround costs at the Dunvegan area and the sale of non-performing
properties in the Provost and Rainbow areas.
Operating expenses were $3,368,000 in fiscal 1999, relatively unchanged
from $3,223,000 in fiscal 1998 (increased $145,000 or 4%).
<PAGE>
Contract Drilling
-----------------
Contract drilling revenues and costs are associated with water well,
geothermal well and exploratory well drilling, and water pump installation,
replacement and repair in Hawaii.
Contract drilling revenues decreased $710,000 (17%) to $3,520,000 in
fiscal 2000, as compared to $4,230,000 in fiscal 1999, and contract drilling
operating expenses decreased $637,000 (19%) to $2,741,000 in fiscal 2000, as
compared to $3,378,000 in fiscal 1999, as revenues and operating expenses for
the prior year period included work under a contract that required
around-the-clock operations, 24 hours per day, seven days a week; all of the
revenues for the current year period were under daylight-only contracts. As a
result of the decrease in activity, operating profit before depreciation
decreased $73,000 to $779,000 for fiscal 2000, as compared to an operating
profit before depreciation of $852,000 for fiscal 1999.
At September 30, 2000, WRI had a backlog of eight well drilling contracts
and six pump installation and repair contracts, three and one of which,
respectively, were in progress as of September 30, 2000. These 14 contracts
represent a backlog of contract drilling revenues of approximately $3,600,000 as
of November 30, 2000.
Contract drilling revenues increased $2,720,000 (180%) to $4,230,000 in
fiscal 1999, as compared to $1,510,000 in fiscal 1998, and contract drilling
operating expenses increased $1,556,000 (85%) to $3,378,000 in fiscal 1999, as
compared to $1,822,000 in fiscal 1998, due primarily to the Company's
performance on contracts for the Hawaii Scientific Drilling Project and a
geothermal well. These jobs were operated seven days a week, 24 hours per day,
as opposed to water well contracts, which are typically operated five days a
week, eight hours per day. As a result of the significant increase in activity,
operating profit before depreciation increased to $852,000 for fiscal 1999, as
compared to an operating loss before depreciation of $482,000 in fiscal 1998.
Gas Processing and Other Income
-------------------------------
Gas processing and other income increased $440,000 (55%) to $1,240,000 in
fiscal 2000, as compared to $800,000 in fiscal 1999, due primarily to a $238,000
gain on the sale of marketable securities and interest and dividends earned on
higher average cash and cash equivalents balances.
Gas processing and other income decreased $210,000 (21%) to $800,000 in
fiscal 1999, as compared to $1,010,000 in fiscal 1998, due primarily to a
decrease in the amount of gas processed by the Company's interest in the
Stolberg pipeline.
Sale of Development Rights and Minority Interest in Earnings
------------------------------------------------------------
In January 2000, Kaupulehu Makai Venture exercised a portion of the option
granted in 1990 by Kaupulehu Developments, a 50.1%-owned general partnership,
for the development of residential parcels within the Four Seasons Resort
Hualalai at Historic Ka'upulehu on the Island of Hawaii. The Company recognized
$6,540,000 of revenues, net of costs associated with the transaction, and
$3,293,000 of minority interest in earnings from this partial exercise of the
<PAGE>
option in fiscal 2000. The Company did not receive any revenues in fiscal 1999
and 1998 related to its 50.1% interest in Kaupulehu Developments. Kaupulehu
Developments' revenues specifically relate to sales of leasehold interests and
development rights, which do not occur every year.
General and Administrative Expenses
-----------------------------------
General and administrative expenses increased $283,000 (9%) to $3,470,000
in fiscal 2000, as compared to $3,187,000 in fiscal 1999, due to higher
personnel costs due to an increase in the number of oil and natural gas segment
personnel and costs associated with an incentive compensation plan for the Vice
President of Canadian Operations.
General and administrative expenses were $3,187,000 in fiscal 1999,
relatively unchanged from $3,292,000 in fiscal 1998 (decreased $105,000 or 3%).
Depreciation, Depletion and Amortization
----------------------------------------
Depreciation, depletion and amortization expense increased $752,000 (27%)
to $3,572,000 in fiscal 2000, as compared to $2,820,000 in fiscal 1999, due
primarily to a 25% increase in the depletion rate per MCF equivalent. The higher
depletion rate is the result of increased capital expenditures, an increase in
the cost of finding and developing proven reserves and a decrease in net proved
reserves due to higher royalty deductions due to higher product prices.
Depreciation, depletion and amortization expense decreased $78,000 (3%) to
$2,820,000 in fiscal 1999, as compared to $2,898,000 in fiscal 1998, due
primarily to a decline in production volumes, partially offset by a 4% increase
in the depletion rate per MCF equivalent and a $42,000 increase in contract
drilling depreciation. The higher depletion rate is the result of increased cost
of finding and developing proven reserves. The increase in contract drilling
depreciation is attributable to the addition of equipment as a result of the
increase in contract drilling activity.
Interest Expense
----------------
Interest expense was $813,000 in fiscal 2000, relatively unchanged from
interest expense of $809,000 in fiscal 1999. The weighted average balance of the
outstanding borrowings from the Royal Bank of Canada decreased from
approximately $11,700,000 in fiscal 1999 to approximately $10,076,000 in fiscal
2000 due to repayment of $3,066,000 of debt during fiscal 2000. In addition, the
borrowings on Kaupulehu Developments' credit facility, $1,250,000 at September
30, 1999, were fully repaid in January 2000, and $400,000 of the convertible
notes were repaid during fiscal 2000. Partially offsetting these decreases were
higher average interest rates and a decrease in interest capitalized on costs
related to its investment in land. The average interest rate incurred during
fiscal 2000 on the Company's borrowings from the Royal Bank of Canada increased
to 7.00%, as compared to 6.18% in fiscal 1999. The average interest rate on the
convertible notes in fiscal 2000 was marginally higher at 10.13% per annum, as
compared to 10.00% per annum in fiscal 1999. Capitalized interest costs
decreased from $201,000 in fiscal 1999 to $93,000 in fiscal 2000, due to the
repayment of a portion of debt associated with the Company's investment in land.
<PAGE>
Interest expense increased $87,000 (12%) in fiscal 1999 to $809,000, as
compared to $722,000 in fiscal 1998, due to higher average loan balances. The
weighted average balance of the outstanding borrowings from the Royal Bank of
Canada increased from approximately $10,300,000 in fiscal 1998 to approximately
$11,700,000 in fiscal 1999 as borrowings made in the latter half of fiscal 1998
were outstanding for ostensibly all of fiscal 1999. Partially offsetting the
increase were lower average interest rates. The average interest rate incurred
during fiscal 1999 on the Company's borrowings from the Royal Bank of Canada
decreased to 6.18% as compared to 6.67% in fiscal 1998, and the average interest
rate on Kaupulehu Developments' borrowings was 9.40% in fiscal 1999 as compared
to 10.00% in fiscal 1998. The interest rate on the convertible notes in fiscal
1999 was unchanged at 10.00% per annum.
Write-down of Assets
--------------------
Under the full cost method of accounting, the amount of oil and natural
gas properties' capitalized costs less accumulated depletion (on a country by
country basis) is subject to a ceiling test limitation that requires any excess
of such costs over the present value of estimated future cash flows from proved
reserves to be expensed. As of March 31, 1998, the Company's investment in the
Michigan Basin prospect was determined to be impaired and was transferred to the
amortization base. Upon transfer, capitalized oil and natural gas properties'
costs in the United States exceeded the full cost ceiling test limitation and,
accordingly, the Company recorded a non-cash write-down of $2,070,000 in the
quarter ended March 31, 1998. Due to further declines in oil prices and
disappointing seismic and drilling results in North Dakota, the Company
abandoned its U.S. oil and natural gas prospects and recorded an additional U.S.
ceiling test write-down of $660,000 during the quarter ended June 30, 1998 to
fully write-off its investment in U.S. oil and natural gas properties. In fiscal
1998, the Company also wrote down $170,000 of land and land improvement costs
related to a contract drilling yard held for sale due to a decline in the market
value of the property, and $95,000 of available-for-sale securities due to a
decline in market value deemed other than temporary.
There were no write-downs of oil and natural gas properties and other
assets in fiscal years 2000 or 1999.
Foreign Currency Fluctuations
-----------------------------
The Company conducts foreign operations in Canada. Consequently, the
Company is subject to foreign currency transaction gains and losses due to
fluctuations of the exchange rates between the Canadian dollar and the U.S.
dollar. The Company incurred realized foreign currency transaction losses
amounting to $420,000 in fiscal 2000. Foreign currency transaction gains and
losses were not material in fiscal 1999 and 1998. The Company cannot accurately
predict future fluctuations between the Canadian and U.S. dollars.
Taxes
-----
The government of the Province of Alberta announced recently that they
will propose significant decreases in corporate tax rates during the 2001
session of the legislative assembly. The proposal was to reduce the province's
corporate tax rate from the current 15.5% rate to 13.5% effective April 1, 2001;
to 11.5% effective April 1, 2002; to 10.0% effective April 1, 2003; and to 8.0%
<PAGE>
effective April 1, 2004. If enacted into law, each 1% reduction in the tax rates
would reduce the Company's current tax provision by an estimated $60,000
(utilizing fiscal 2000's earnings before taxes) over a one year period and
reduce the deferred income tax liability by an estimated $120,000.
In fiscal 1999 and 1998, the provision for income taxes did not bear a
normal relationship to earnings because Canadian taxes were payable on Canadian
operations and losses from U.S. operations provide no foreign tax benefits.
Environmental Matters
---------------------
Federal, state, and Canadian governmental agencies issue rules and
regulations and enforce laws to protect the environment which are often
difficult and costly to comply with and which carry substantial penalties for
failure to comply, particularly in regard to the discharge of materials into the
environment. The regulatory burden on the oil and gas industry increases its
cost of doing business. These laws, rules and regulations affect the operations
of the Company and could have a material adverse effect upon the earnings or
competitive position of the Company. Although Barnwell's experience has been to
the contrary, there is no assurance that this will continue to be the case.
Inflation
---------
The effect of inflation on the Company has generally been to increase its
cost of operations, interest cost (as a substantial portion of the Company's
debt is at variable short-term rates of interest which tend to increase as
inflation increases), general and administrative costs and direct costs
associated with oil and natural gas production and contract drilling operations.
In the case of contract drilling, the Company has not been able to increase its
contract revenues to fully compensate for increased costs. In the case of oil
and natural gas, prices realized by the Company are essentially determined by
world prices for oil and western Canadian/Midwestern U.S. prices for natural
gas.
Recent Accounting Pronouncements
--------------------------------
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which establishes accounting and
reporting standards for derivative instruments and hedging activities and
requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. In July 1999, the FASB issued SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No. 133, an Amendment of FASB Statement No. 133," which defers
the effective date of SFAS No. 133 to be effective for all fiscal quarters of
fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS
No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an Amendment of FASB Statement No. 133," which addresses a limited
number of issues causing implementation difficulties for certain entities that
apply SFAS No. 133. Management does not expect adoption of SFAS No. 133, as
amended by SFAS No. 138, will have a material effect on the Company's financial
condition, results of operations or liquidity.
<PAGE>
In March 2000, the FASB issued FASB Interpretation No. 44, "Accounting
for Certain Transactions involving Stock Compensation, an interpretation of APB
Opinion No. 25." Interpretation No. 44 clarifies the application of Accounting
Principles Board ("APB") Opinion No. 25 for certain issues involving employee
stock compensation and is generally effective July 1, 2000. Adoption of
Interpretation No. 44 did not have a material effect on the Company's financial
condition, results of operations or liquidity.
In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities, a
replacement of FASB Statement No. 125." SFAS No. 140 is effective for transfers
and servicing of financial assets and extinguishments of liabilities occurring
after March 31, 2001. SFAS No. 140 is effective for recognition and
reclassification of collateral and for disclosures relating to securitization
transactions and collateral for fiscal years ending after December 15, 2000.
Management does not expect adoption of SFAS No. 140 will have a material effect
on the Company's financial condition, results of operations or liquidity.
In December 1999, the Securities and Exchange Commission ("SEC") issued
Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial
Statements." The SAB summarizes certain of the SEC staff's views in applying
U.S. generally accepted accounting principles to revenue recognition in
financial statements. In June 2000, the SEC issued SAB No. 101B, which delays
the implementation date of SAB No. 101 until no later than the fourth quarter of
fiscal years beginning after December 15, 1999. The adoption of SAB No. 101 is
not expected to have a material effect on the Company's financial condition,
results of operations or liquidity.
<PAGE>
Item 7. FINANCIAL STATEMENTS
--------------------
Independent Auditors' Report
----------------------------
The Board of Directors
Barnwell Industries, Inc.:
We have audited the consolidated balance sheets of Barnwell Industries, Inc. and
subsidiaries as of September 30, 2000 and 1999, and the related consolidated
statements of operations, stockholders' equity and comprehensive income (loss),
and cash flows for each of the years in the three-year period ended September
30, 2000. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Barnwell Industries,
Inc. and subsidiaries as of September 30, 2000 and 1999, and the results of
their operations and their cash flows for each of the years in the three-year
period ended September 30, 2000, in conformity with accounting principles
generally accepted in the United States of America.
/s/ KPMG LLP
Honolulu, Hawaii
November 22, 2000
<PAGE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS September 30,
------ ----------------------------
CURRENT ASSETS: 2000 1999
----------- -----------
<S> <C> <C>
Cash and cash equivalents $ 5,701,000 $ 2,577,000
Accounts receivable, net (Notes 3 and 13) 2,018,000 1,873,000
Royalty tax credit and taxes receivable 133,000 261,000
Costs and estimated earnings in excess of
billings on uncompleted contracts (Note 3) 496,000 172,000
Deferred income taxes (Note 6) 160,000 130,000
Prepaid royalties, inventories and other 613,000 584,000
----------- -----------
TOTAL CURRENT ASSETS 9,121,000 5,597,000
----------- -----------
INVESTMENT IN LAND (Notes 4 and 5) 3,975,000 3,519,000
----------- -----------
OTHER ASSETS 216,000 207,000
----------- -----------
PROPERTY AND EQUIPMENT (Notes 5 and 10):
Land 465,000 465,000
Oil and natural gas properties
subject to amortization (full cost accounting) 52,462,000 48,934,000
Drilling rigs and equipment 5,135,000 8,043,000
Other property and equipment 2,820,000 2,539,000
----------- -----------
60,882,000 59,981,000
Accumulated depreciation, depletion and amortization 35,534,000 36,009,000
----------- -----------
TOTAL PROPERTY AND EQUIPMENT 25,348,000 23,972,000
----------- -----------
TOTAL ASSETS $38,660,000 $33,295,000
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
Accounts payable $ 1,821,000 $ 1,894,000
Accrued expenses 3,383,000 1,975,000
Billings in excess of costs and estimated
earnings on uncompleted contracts (Note 3) 350,000 139,000
Payable to joint interest owners 783,000 648,000
Income taxes payable (Note 6) 650,000 251,000
Current portion of long-term debt (Note 5) 400,000 1,650,000
----------- -----------
TOTAL CURRENT LIABILITIES 7,387,000 6,557,000
----------- -----------
LONG-TERM DEBT (Note 5) 9,133,000 12,631,000
----------- -----------
DEFERRED INCOME TAXES (Note 6) 7,206,000 6,301,000
----------- -----------
MINORITY INTEREST 2,260,000 -
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 4, 7, 8 and 9)
STOCKHOLDERS' EQUITY (Notes 5 and 8):
Common stock, par value $.50 per share:
Authorized, 4,000,000 shares
Issued, 1,642,797 shares 821,000 821,000
Additional paid-in capital 3,103,000 3,103,000
Retained earnings 16,680,000 11,801,000
Accumulated other comprehensive loss -
foreign currency translation adjustments (3,048,000) (3,130,000)
Treasury stock, at cost, 331,845 shares at
September 30, 2000 and 325,845 shares at
September 30, 1999 (4,882,000) (4,789,000)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY 12,674,000 7,806,000
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $38,660,000 $33,295,000
=========== ===========
<FN>
See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended September 30,
-------------------------------------
2000 1999 1998
----------- ----------- -----------
Revenues:
Oil and natural gas $15,270,000 $10,130,000 $ 9,400,000
Contract drilling 3,520,000 4,230,000 1,510,000
Gas processing and other 1,240,000 800,000 1,010,000
Sale of development
rights, net (Note 4) 6,540,000 - -
----------- ----------- -----------
26,570,000 15,160,000 11,920,000
----------- ----------- -----------
Costs and expenses:
Oil and natural gas operating 3,128,000 3,368,000 3,223,000
Contract drilling operating 2,741,000 3,378,000 1,822,000
General and administrative 3,470,000 3,187,000 3,292,000
Depreciation, depletion
and amortization 3,572,000 2,820,000 2,898,000
Interest expense, net (Note 5) 813,000 809,000 722,000
Foreign exchange losses 420,000 - -
Minority interest
in earnings (Note 4) 3,308,000 - -
Write-down of assets (Note 10) - - 2,995,000
----------- ----------- -----------
17,452,000 13,562,000 14,952,000
----------- ----------- -----------
Earnings (loss) before income taxes 9,118,000 1,598,000 (3,032,000)
Provision for income taxes (Note 6) 4,108,000 1,078,000 858,000
----------- ----------- -----------
NET EARNINGS (LOSS) $ 5,010,000 $ 520,000 $(3,890,000)
=========== =========== ===========
BASIC EARNINGS PER COMMON SHARE $3.81 $0.39 $(2.95)
=========== =========== ===========
DILUTED EARNINGS PER COMMON SHARE $3.67 $0.39 $(2.95)
=========== =========== ===========
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING
BASIC 1,315,312 1,316,952 1,319,719
=========== =========== ===========
DILUTED 1,388,540 1,316,952 1,319,719
=========== =========== ===========
See Notes to Consolidated Financial Statements
<PAGE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended September 30,
---------------------------------------
2000 1999 1998
----------- ----------- -----------
Cash flows from operating activities:
<S> <C> <C> <C>
Net earnings (loss) $ 5,010,000 $ 520,000 $(3,890,000)
Adjustments to reconcile net earnings (loss)
to net cash provided by operating activities:
Depreciation, depletion and amortization 3,572,000 2,820,000 2,898,000
Minority interest in earnings 3,308,000 - -
Deferred income taxes 1,036,000 314,000 524,000
Foreign exchange losses 420,000 - -
Gain on sale of equity securities (238,000) - -
Earnings on sale of development rights, net (6,540,000) - -
Write-down of assets - - 2,995,000
----------- ----------- -----------
6,568,000 3,654,000 2,527,000
Increase (decrease) from changes in
current assets and liabilities (Note 14) 1,626,000 (929,000) 434,000
----------- ----------- -----------
Net cash provided by operating activities 8,194,000 2,725,000 2,961,000
----------- ----------- -----------
Cash flows from investing activities:
Proceeds from sale of development rights, net 6,540,000 - -
Proceeds from sale of marketable securities 379,000 - -
Proceeds from sale of property and equipment 142,000 309,000 93,000
Decrease (increase) in other assets (9,000) 6,000 8,000
Capital expenditures (6,249,000) (2,831,000) (8,127,000)
----------- ----------- -----------
Net cash provided by
(used in) investing activities 803,000 (2,516,000) (8,026,000)
----------- ----------- -----------
Cash flows from financing activities:
Long-term debt borrowings 50,000 885,000 3,067,000
Purchases of common stock for treasury (93,000) - (84,000)
Payment of dividends (131,000) - -
Distribution to minority interest partner (873,000) - -
Repayments of long-term debt (4,766,000) (739,000) -
----------- ----------- -----------
Net cash (used in)
provided by financing activities (5,813,000) 146,000 2,983,000
----------- ----------- -----------
Effect of exchange rate
changes on cash and cash equivalents (60,000) 44,000 (142,000)
----------- ----------- -----------
Net increase (decrease) in
cash and cash equivalents 3,124,000 399,000 (2,224,000)
Cash and cash equivalents at beginning of year 2,577,000 2,178,000 4,402,000
----------- ----------- -----------
Cash and cash equivalents at end of year $ 5,701,000 $ 2,577,000 $ 2,178,000
=========== =========== ===========
<FN>
See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
Years ended September 30, 2000, 1999, and 1998
Accumulated
Additional Comprehensive Other Total
Common Paid-In Income Retained Comprehensive Treasury Stockholders'
Stock Capital (Loss) Earnings Loss Stock Equity
--------- ----------- ------------ ----------- ------------ ------------ -------------
Balances at
<S> <C> <C> <C> <C> <C> <C> <C>
September 30, 1997 $ 821,000 $ 3,103,000 $15,171,000 $ (2,240,000) $ (4,705,000) $ 12,150,000
Comprehensive loss:
Net loss $ (3,890,000) (3,890,000) (3,890,000)
------------
Other comprehensive
loss, net of income taxes:
Foreign currency
translation adjustments (1,421,000)
Unrealized holding
loss on securities (11,000)
------------
Other comprehensive loss (1,432,000) (1,432,000) (1,432,000)
------------
Total comprehensive loss $ (5,322,000)
============
Purchases of 5,100 shares of
common stock for treasury (84,000) (84,000)
--------- ----------- ----------- ------------ ------------ -------------
Balances at
September 30, 1998 $ 821,000 $ 3,103,000 $11,281,000 $ (3,672,000) $ (4,789,000) $ 6,744,000
Comprehensive income:
Net earnings $ 520,000 520,000 520,000
Other comprehensive income,
net of income taxes -
foreign currency
translation adjustments 542,000 542,000 542,000
------------
Total comprehensive income $ 1,062,000
--------- ----------- ============ ----------- ------------ ------------ -------------
Balances at
September 30, 1999 $ 821,000 $ 3,103,000 $11,801,000 $ (3,130,000) $ (4,789,000) $ 7,806,000
========= =========== =========== ============ ============ =============
<FN>
(continued on next page)
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
Years ended September 30, 2000, 1999, and 1998
(continued from previous page)
Accumulated
Additional Comprehensive Other Total
Common Paid-In Income Retained Comprehensive Treasury Stockholders'
Stock Capital (Loss) Earnings Loss Stock Equity
--------- ----------- ------------ ----------- ------------ ------------ -------------
Balances at
<S> <C> <C> <C> <C> <C> <C> <C>
September 30, 1999 $ 821,000 $ 3,103,000 $11,801,000 $ (3,130,000) $ (4,789,000) $ 7,806,000
Purchase of 6,000
common shares for treasury (93,000) (93,000)
Dividends declared
($0.10 per share) (131,000) (131,000)
Comprehensive income:
Net earnings $ 5,010,000 5,010,000 5,010,000
Other comprehensive loss,
net of income taxes -
foreign currency
translation adjustments (205,000) (205,000) (205,000)
------------
Total comprehensive income $ 4,805,000
============
Foreign exchange
losses realized -
net of income taxes 287,000 287,000
--------- ----------- ----------- ------------ ------------ -------------
Balances at
September 30, 2000 $ 821,000 $ 3,103,000 $16,680,000 $ (3,048,000) $ (4,882,000) $ 12,674,000
========= =========== =========== ============ ============ =============
<FN>
See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>
BARNWELL INDUSTRIES, INC.
-------------------------
AND SUBSIDIARIES
----------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
YEARS ENDED SEPTEMBER 30, 2000, 1999 AND 1998
---------------------------------------------
1. DESCRIPTION OF THE REPORTING ENTITY AND BUSINESS
------------------------------------------------
The consolidated financial statements include the accounts of Barnwell
Industries, Inc. and all majority-owned subsidiaries, including a land
development joint venture (collectively referred to herein as "Company"). All
significant intercompany accounts and transactions have been eliminated.
During its last three fiscal years, the Company was engaged in exploring
for, developing, producing and selling oil and natural gas in Canada, investing
in leasehold land in Hawaii, and drilling wells and installing and repairing
water pumping systems in Hawaii. The Company's oil and natural gas activities
comprise its largest business segment. Approximately 57% of the Company's
revenues and 80% of the Company's capital expenditures for the fiscal year ended
September 30, 2000 were attributable to its oil and natural gas activities. The
Company's land investment activities accounted for 25% of the Company's
revenues, contract drilling activities accounted for 13% of the Company's
revenues, and gas processing and other revenues comprised the remaining 5% of
revenues for fiscal 2000. Land investment revenues relate to sales of leasehold
interests and development rights, which do not occur every year. Changes in the
marketplace of any of the aforementioned industries may significantly affect
management's estimates and the Company's performance.
2. SIGNIFICANT ACCOUNTING POLICIES
-------------------------------
Cash and cash equivalents
-------------------------
Cash and cash equivalents includes cash on hand, demand deposits and
short-term investments with original maturities of three months or less.
Oil and natural gas properties
------------------------------
The Company uses the full cost method of accounting under which all costs
incurred in the acquisition, exploration and development of oil and natural gas
reserves, including unsuccessful wells, are capitalized until such time as the
aggregate of such costs, on a country by country basis, equals the discounted
present value (at 10%) of the Company's estimated future net cash flows from
estimated production of proved oil and natural gas reserves, as determined by
independent petroleum engineers, less related income tax effects. Any
capitalized costs in excess of the discounted present value are charged to
expense. Depletion of all such costs, except costs related to major development
projects, is provided by the unit-of-production method based upon proved oil and
natural gas reserves of all properties on a country by country basis.
Investments in major development projects are not amortized until proved
reserves associated with the projects can be determined or until impairment
occurs. If the results of an assessment indicate that the properties are
impaired, the amount of the impairment is added to the capitalized costs to be
amortized. General and administrative costs related to oil and natural gas
operations are expensed as incurred. Estimated future site restoration and
<PAGE>
abandonment costs are charged to earnings at the rate of depletion and are
included in accumulated depreciation, depletion and amortization. Proceeds from
the disposition of minor producing oil and natural gas properties are credited
to the cost of oil and natural gas properties. Gains or losses are recognized on
the disposition of significant oil and natural gas properties.
Contract drilling
-----------------
Revenues, costs and profits applicable to contract drilling contracts are
included in the consolidated statements of operations using the percentage of
completion method, principally measured by the percentage of labor dollars
incurred to date for each contract to total estimated labor dollars for each
contract. Contract losses are recognized in full in the year the losses are
identified. The performance of drilling contracts may extend over more than one
year and, in the interim periods, estimates of total contract costs and profits
are used to determine revenues and profits earned for reporting the results of
the contract drilling operations. Revisions in the estimates required by
subsequent performance and final contract settlements are included as
adjustments to the results of operations in the period such revisions and
settlements occur. Contracts are normally less than one year in duration.
Investment in land and revenue recognition
------------------------------------------
The Company's investment in land is comprised of land under development
and development rights under option.
Investment in land under development is evaluated for impairment whenever
events or changes in circumstances indicate that the recorded investment balance
may not be fully recoverable. The Company's cost, including capitalized
interest, of the land under development is included in the consolidated balance
sheets under the caption "Investment in Land."
Development rights under option are reported at the lower of the asset
carrying value or fair value, less costs to sell. Land sales for development
rights under option are accounted for under the cost recovery method. Under the
cost recovery method, no gain is recognized until cash received exceeds the cost
and the estimated future costs related to the development rights sold. The
accompanying consolidated balance sheets include no cost for development rights
under option and, accordingly, cash receipts, if any, in excess of costs will be
reported as revenues.
Long-lived assets
-----------------
Long-lived assets to be held and used, other than oil and natural gas
properties, are evaluated for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be fully
recoverable. If the future cash flows expected to result from use of the asset
(undiscounted and without interest charges) are less than the carrying amount of
the asset, an impairment loss is recognized. Such impairment loss is measured as
the amount by which the carrying amount of the asset exceeds the fair value of
the asset. Long-lived assets to be disposed of are reported at the lower of the
asset carrying value or fair value, less cost to sell.
Drilling rigs and other equipment
---------------------------------
Drilling rigs and other equipment are stated at cost. Depreciation is
computed using the straight-line method based on estimated useful lives ranging
from three to ten years.
<PAGE>
Inventories
-----------
Inventories are comprised of drilling materials and are valued at the
lower of weighted average cost or market value.
Environmental
-------------
The Company is subject to extensive environmental laws and regulations.
These laws, which are constantly changing, regulate the discharge of materials
into the environment and maintenance of surface conditions and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are expensed. Liabilities
for expenditures of a noncapital nature are recorded when environmental
assessment and/or remediation is probable, and the costs can be reasonably
estimated.
Income taxes
------------
Deferred income taxes are determined using the asset and liability method.
Deferred tax assets and liabilities are recognized for the estimated future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
in effect for the year in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes the
enactment date.
Earnings per common share
-------------------------
Basic earnings per share excludes dilution and is computed by dividing net
earnings (loss) by the weighted-average number of common shares outstanding for
the period.
Diluted earnings per share includes the potentially dilutive effect of
outstanding common stock options and securities which are convertible to common
shares.
Reconciliations between the numerator and denominator of the basic and
diluted earnings per share computations for the year ended September 30, 2000
are as follows (there were no differences in fiscal 1999 or 1998):
September 30, 2000
-----------------------------------------
Net Earnings Shares Per-Share
(Numerator) (Denominator) Amount
----------- ---------- ------
Basic earnings per share $ 5,010,000 1,315,312 $ 3.81
======
Effect of dilutive securities -
Common stock options - 13,228
Convertible debentures 90,000 60,000
----------- ----------
Diluted earnings per share $ 5,100,000 1,388,540 $ 3.67
=========== ========== ======
<PAGE>
Assumed conversion of common stock options to acquire 50,000, 50,000 and
67,500 shares of the Company's stock was excluded from the computation of
diluted earnings per share for the years ended September 30, 2000, 1999 and
1998, respectively, because their inclusion would be antidilutive.
Assumed conversion of convertible debentures to 80,000 and 100,000 shares
of common stock was excluded from the computation of diluted earnings per share
for the years ended September 30, 1999 and 1998, respectively, because their
inclusion would be antidilutive.
Foreign currency translation
----------------------------
Assets and liabilities of foreign operations and subsidiaries are
translated at the year-end exchange rate and resulting translation gains or
losses are accounted for in a stockholders' equity account entitled "accumulated
other comprehensive loss - foreign currency translation adjustments." Operating
results of foreign subsidiaries are translated at average exchange rates during
the period. Realized foreign currency transaction losses amounting to $420,000
for the fiscal year ended September 30, 2000 are reflected in the accompanying
consolidated statements of operations. Realized foreign currency transaction
gains or losses were not material in fiscal years 1999 and 1998.
Use of Estimates in the Preparation of Financial Statements
-----------------------------------------------------------
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and the disclosure of contingent assets and liabilities. Actual
results could differ significantly from those estimates. Significant assumptions
are required in the valuation of deferred tax assets and proved oil and natural
gas reserves, and such assumptions may impact the amount at which deferred tax
assets and oil and natural gas properties are recorded.
3. RECEIVABLES AND CONTRACT COSTS
------------------------------
Accounts receivable, current, are net of allowances for doubtful accounts
of $154,000 and $196,000 as of September 30, 2000 and 1999, respectively.
Included in accounts receivable are contract retainage balances of $208,000 and
$274,000 as of September 30, 2000 and 1999, respectively. These balances are
expected to be collected within one year, generally within 45 days after the
related contracts have received final acceptance and approval.
Costs and estimated earnings on uncompleted contracts are as follows:
September 30,
---------------------------
2000 1999
---------- ----------
Costs incurred on uncompleted contracts $1,390,000 $3,211,000
Estimated earnings 249,000 957,000
---------- ----------
1,639,000 4,168,000
Less billings to date 1,493,000 4,135,000
---------- ----------
$ 146,000 $ 33,000
========== ==========
<PAGE>
Costs and estimated earnings on uncompleted contracts are included in the
consolidated balance sheets under the following captions:
September 30,
---------------------------
2000 1999
---------- ----------
Costs and estimated earnings
in excess of billings on uncompleted contracts $ 496,000 $ 172,000
Billings in excess of costs
and estimated earnings on uncompleted contracts (350,000) (139,000)
---------- ----------
$ 146,000 $ 33,000
========== ==========
4. INVESTMENT IN LAND
------------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii general partnership. Between 1986 and 1989, Kaupulehu Developments
obtained the state and county zoning changes necessary to permit development of
the Four Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club,
which opened in 1996, a second golf course (currently under construction), and
single and multiple family residential units on land acquired from Kaupulehu
Developments, located approximately six miles north of the Kona International
Airport in the North Kona District of the Island of Hawaii.
In January 2000, Kaupulehu Makai Venture, an affiliate of Kajima
Corporation of Japan, exercised a portion of the option granted in 1990 by
Kaupulehu Developments for the development of residential parcels within the
Four Seasons Resort Hualalai at Historic Ka'upulehu on the Island of Hawaii. The
Company recognized revenues of $6,540,000, net of costs associated with the
transaction, from the receipt of the option monies. $1,300,000 of the proceeds
were used to repay Kaupulehu Developments' borrowings from a Hawaii bank, and
$873,000 were distributed to Kaupulehu Developments' minority interest partner,
Cambridge Hawaii Limited Partnership ("CHLP"), which holds the remaining 49.9%
interest in Kaupulehu Developments. CHLP is a Hawaii limited partnership
comprised of three Canadian limited partnerships, comprised of individuals, one
of whom is Mr. Terry Johnston. Mr. Johnston was elected to the Board of
Directors of the Company in March 2000.
The Company did not receive any revenues in fiscal 1999 and 1998 related
to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments'
revenues specifically relate to the sales of leasehold interests and development
rights, which do not occur every year.
At September 30, 2000, the remaining unexercised portion of the
aforementioned option on residential development rights is for approximately 80
acres of residentially zoned leasehold land adjacent to the completed and
currently under construction golf courses. If Kaupulehu Makai Venture fully
exercises this option, Kaupulehu Developments will receive a total of
$25,500,000. The option expires on April 30, 2003 unless 50% of the option
proceeds are received on or before April 30, 2003. The remainder of the option
would then expire on April 30, 2007. There is no assurance that this option or
any portion of it will be exercised.
Kaupulehu Developments also holds leasehold rights in approximately 2,100
acres of land located adjacent to and north of the Four Seasons Resort Hualalai
at Historic Ka'upulehu. These approximately 2,100 acres are located between the
Queen Kaahumanu Highway and the Pacific Ocean. In June 1996, the State Land Use
Commission ("LUC") approved Kaupulehu Developments' petition for
<PAGE>
reclassification of approximately 1,000 acres of these 2,100 acres of land into
the Urban District for resort/residential development. Subsequent to the LUC's
approval, a notice of appeal was filed with the Third Circuit Court of the State
of Hawaii by parties seeking to reverse the LUC's decision. The Third Circuit
Court of the State of Hawaii upheld the LUC's approval of Kaupulehu
Developments' rezoning request in all respects in a Decision and Order issued in
August 1997. In November 1997, a notice of appeal was filed with the Supreme
Court of the State of Hawaii by parties seeking to reverse the Third Circuit
Court's decision.
In June 1998, Kaupulehu Developments filed an Application for a Project
District zoning ordinance and a Special Management Area ("SMA") Use Permit
Petition with the County of Hawaii, requesting changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential, resort and
commercial development. Both the County zoning ordinance and the SMA Use Permit
are required for development of the property. In December 1998, following a
contested case hearing conducted in November 1998, the Planning Commission of
the County of Hawaii granted the requested SMA Use Permit to Kaupulehu
Developments to be effective when the zoning ordinance is adopted. Subsequent to
the Planning Commission's approval, in January 1999, a notice of appeal was
filed with the Third Circuit Court of the State of Hawaii by parties seeking to
reverse the Planning Commission's decision. In April 1999, the County of Hawaii
adopted an ordinance granting zoning approval of Kaupulehu Developments'
Application for a Project District zoning ordinance, which requested changes in
zoning and use of the aforementioned 1,000 acres of land to allow residential,
resort and commercial development. In December 1999, the Third Circuit Court of
the County of Hawaii remanded Kaupulehu Developments' SMA Use Permit Petition
back to the County of Hawaii Planning Commission for further review due to
procedural issues. In late December 1999, the County of Hawaii Planning
Commission reaffirmed their approval of the SMA Use Permit Petition.
In September 2000, the Supreme Court of the State of Hawaii ruled on the
appeal of the LUC's decision, finding in favor of Kaupulehu Developments on
three of the issues on appeal, but on the fourth issue, the court remanded the
matter to the LUC for the limited purpose of entering specific findings and
conclusions, with further hearing if necessary, regarding: (1) the identity and
scope of "valued cultural, historical, or natural resources" in the petition
area, including the extent to which traditional and customary native Hawaiian
rights are exercised in the petition area; (2) the extent to which those
resources - including traditional and customary native Hawaiian rights - will be
affected or impaired by the proposed action; and (3) the feasible action, if
any, to be taken by the LUC to reasonably protect native Hawaiian rights if they
are found to exist. In October 2000, Kaupulehu Developments filed a motion with
the LUC to bring the matter in front of the LUC. Management cannot predict the
timing or outcome of the LUC's procedures or findings and, accordingly, there is
no assurance that State of Hawaii zoning approval will be forthcoming at any
time. If the Company is unable to obtain the LUC's approval, there will be a
materially adverse impairment of the value of the Company's leasehold rights in
this approximately 1,000 acres.
Kaupulehu Developments continues to negotiate a revised development
agreement and residential fee purchase prices with the lessor of the 2,100 acre
parcel. Management cannot predict the outcome of these negotiations.
Costs related to the rezoning of the conservation land are capitalized and
included in the consolidated balance sheets under the caption, "Investment in
Land."
<PAGE>
5. LONG-TERM DEBT
--------------
The Company has a credit facility at the Royal Bank of Canada, a Canadian
bank, for $17,000,000 Canadian dollars, or its U.S. dollar equivalent of
approximately $11,300,000 at September 30, 2000. Borrowings under this facility
were $8,333,000 and $11,431,000 at September 30, 2000 and 1999, respectively,
and are included in long-term debt. At September 30, 2000, the Company had
unused credit available under this facility of approximately $2,960,000.
The facility is available in U.S. dollars at the London Interbank Offer
Rate ("LIBOR") plus 7/8%, at U.S. prime, or in Canadian dollars at Canadian
prime. A standby fee of 1/2% per annum is charged on the unused facility
balance. Under the financing agreement, the facility is reviewed annually, with
the next review planned for April 2001. Subject to that review, the facility may
be extended one year with no required debt repayments for one year or converted
to a 5-year term loan by the bank. If the facility is converted to a 5-year term
loan, the Company has agreed to the following repayment schedule of the then
outstanding loan balance: year 1-30%; year 2-27%; year 3-16%; year 4-14% and
year 5-13%.
The Company has the option to change the currency denomination and
interest rate applicable to the loan at periodic intervals during the term of
the loan. During the year ended September 30, 2000, the Company paid interest at
rates ranging from 6.13% to 7.54%. The interest rate on the facility at
September 30, 2000 was 7.5%. The facility is collateralized by the Company's
interests in its major oil and natural gas properties and a negative pledge on
its remaining oil and natural gas properties. The facility is reviewed annually
with a primary focus on the future cash flows that will be generated by the
Company's Canadian oil and natural gas properties. No compensating bank balances
are required for this facility.
The Canadian bank has represented that it will not require any repayments
under the facility before September 30, 2001. Accordingly, the Company has
classified outstanding borrowings under the facility as long-term debt.
At September 30, 1999, the Company had long-term debt with a Hawaii bank
of $1,250,000. In the quarter ended December 31, 1999, the Company borrowed an
additional $50,000, and in January 2000 repaid the entire $1,300,000 outstanding
balance.
In June 1995, the Company issued $2,000,000 of convertible notes due July
1, 2003. $1,950,000 of such notes were purchased by an officer/shareholder, a
director/shareholder, and certain other shareholders of the Company. The notes
are payable in 20 consecutive equal quarterly installments beginning in October
1998. Four quarterly installments aggregating $400,000 were paid during fiscal
year 2000. Interest is payable quarterly at a rate to be adjusted each quarter
to the greater of 10% per annum or 1% over the prime rate of interest. The
Company paid interest on these convertible notes at an average rate of 10.13%
per annum in 2000 and 10.00% per annum throughout fiscal years 1999 and 1998.
The notes are unsecured and convertible at any time at the holder's option into
shares of the Company's common stock at a price of $20.00 per share, subject to
adjustment for certain events including a stock split of, or stock dividend on,
the Company's common stock. The notes are redeemable, at the option of the
Company, at any time at premiums declining 1% annually from 2% of the principal
amount of the notes at July 1, 2000. At September 30, 2000, $800,000 of these
notes are included in long-term debt and $400,000 of these notes are included in
the current portion of long-term debt.
<PAGE>
At September 30, 2000, the maturities of current and long-term debt by
fiscal year, exclusive of the credit facility with the Canadian bank, are as
follows:
2001 400,000
2002 400,000
2003 400,000
----------
$1,200,000
==========
The Company capitalizes interest on costs related to its investment in
land. The Company also capitalized interest on its investment in undeveloped
natural gas and oil leases in the Central Basin in Michigan during the first
quarter of the year ended September 30, 1998. Interest costs for the years ended
September 30, 2000, 1999, and 1998 are summarized as follows:
2000 1999 1998
---------- ---------- ----------
Interest costs incurred $ 906,000 $1,010,000 $ 901,000
Less interest costs capitalized on:
Investment in land 93,000 201,000 169,000
Investment in natural
gas and oil properties - - 10,000
---------- ---------- ----------
Interest expense $ 813,000 $ 809,000 $ 722,000
========== ========== ==========
6. TAXES ON INCOME
---------------
The components of earnings (loss) before income taxes are as follows:
Year ended September 30,
-----------------------------------------
2000 1999 1998
----------- ----------- -----------
United States $ 1,780,000 $(1,025,000) $(4,736,000)
Canadian 7,338,000 2,623,000 1,704,000
----------- ----------- -----------
$ 9,118,000 $ 1,598,000 $(3,032,000)
=========== =========== ===========
<PAGE>
The components of the provision for income taxes related to the above
earnings (loss) are as follows:
Year ended September 30,
-----------------------------------------
2000 1999 1998
----------- ----------- -----------
Current:
United States - Federal $ 50,000 $ - $ -
Canadian 3,022,000 764,000 334,000
----------- ----------- -----------
Total current 3,072,000 764,000 334,000
----------- ----------- -----------
Deferred:
United States 916,000 97,000 (23,000)
Canadian 120,000 217,000 547,000
----------- ----------- -----------
Total deferred 1,036,000 314,000 524,000
----------- ----------- -----------
$ 4,108,000 $ 1,078,000 $ 858,000
=========== =========== ===========
A reconciliation between the reported provision for income taxes and the
amount computed by multiplying the earnings (loss) before income taxes by the
United States federal tax rate is as follows:
Year ended September 30,
-----------------------------------------
2000 1999 1998
----------- ----------- -----------
Tax expense (benefit) computed
by applying statutory rate $ 3,191,000 $ 559,000 $(1,061,000)
Change in the balance
of the valuation allowance 906,000 170,000 1,339,000
Effect of the foreign tax
provision on the
total tax provision - 422,000 489,000
State net operating
losses utilized (generated) 83,000 (61,000) (70,000)
Other (72,000) (12,000) 161,000
----------- ----------- -----------
$ 4,108,000 $ 1,078,000 $ 858,000
=========== =========== ===========
<PAGE>
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at September
30, 2000 and 1999 are as follows:
Deferred income tax assets: 2000 1999
------------ -----------
U.S. tax effect of deferred Canadian taxes $ 2,439,000 $ 2,452,000
Foreign tax credit carryforwards 1,745,000 874,000
Tax basis in land in excess of book basis 908,000 1,097,000
Write-down of assets not deducted for tax 355,000 355,000
State of Hawaii net operating loss carryforwards 260,000 414,000
Expenses accrued for books but not for tax 274,000 261,000
Alternative minimum tax credit carryforwards 111,000 225,000
Other 106,000 118,000
U.S. federal net operating loss carryforwards - 158,000
------------ -----------
Total gross deferred tax assets 6,198,000 5,954,000
Less-valuation allowance (5,016,000) (4,110,000)
------------ -----------
Net deferred income tax assets 1,182,000 1,844,000
------------ -----------
Deferred income tax liabilities:
Property and equipment accumulated
tax depreciation and depletion
in excess of book under Canadian tax law (7,172,000 (7,213,000)
Property and equipment accumulated
tax depreciation and depletion
in excess of book under U.S. tax law (1,056,000) (581,000)
Other - (221,000)
------------ -----------
Total deferred income tax liabilities (8,228,000) (8,015,000)
------------ -----------
Net deferred income tax liability $ (7,046,000) $(6,171,000)
============ ===========
The total valuation allowance increased $906,000, $170,000, and $1,339,000
for the years ended September 30, 2000, 1999, and 1998, respectively. The
increase for the year ended September 30, 2000 relates primarily to foreign tax
credit carryforwards for which it is more likely than not that such
carryforwards will not be utilized to reduce the Company's U.S. tax obligation.
The increase for the year ended September 30, 1998 relates primarily to foreign
tax credit carryforwards and U.S. federal net operating loss carryforwards for
which it is more likely than not that some portion of such carryforwards will
not be utilized to reduce the Company's U.S. tax obligation. Historically, the
Company has reduced U.S. regular taxes due on consolidated U.S. taxable income
by utilizing foreign tax credits. If the net operating loss is utilized to
reduce consolidated U.S. taxable income in a year in which the Company would
normally have utilized foreign tax credits to fully offset regular taxes, the
net operating loss will provide no incremental tax benefit; therefore a
valuation allowance has been provided.
<PAGE>
A valuation allowance is provided when it is more likely than not that
some portion or all of the deferred tax asset will not be realized. The Company
has established a valuation allowance for Canadian tax deductions, foreign tax
credits, U.S. federal net operating loss carryforwards and state of Hawaii net
operating loss carryforwards which may not be realizable in future years as
there can be no assurance of any specific level of earnings or that the timing
of U.S. earnings will coincide with the payment of Canadian taxes to enable
Canadian taxes to be fully deducted (or recoverable) for U.S. tax purposes.
Additionally, utilization of U.S. federal net operating loss carryforwards will
provide no incremental tax benefit if foreign tax credits generated in future
years will be displaced by the net operating loss carryforwards as it is more
likely than not that the foreign tax credits will expire unused.
Net deferred tax assets will primarily be realized through the deduction
of the cost basis in investment in land against proceeds from investment in land
for tax purposes. Under the cost recovery accounting method, this cost basis has
already been expensed for book purposes. The amount of deferred income tax
assets considered realizable may be reduced if estimates of future taxable
income are reduced.
At September 30, 2000, the Company had alternative minimum tax credit
carryforwards of $111,000 which are available to reduce future U.S. federal
regular income taxes, if any, over an indefinite period.
7. PENSION PLAN
------------
The Company sponsors a noncontributory defined benefit pension plan
covering substantially all employees, with benefits based on years of service
and the employee's highest consecutive five-year average earnings. The Company's
funding policy is intended to provide for both benefits attributed to service
to-date and for those expected to be earned in the future. The plan assets at
September 30, 2000 were invested as follows: 8% in cash and cash equivalents,
31% listed government mortgages and 61% common stocks and equity mutual funds.
<PAGE>
The funded status of the pension plan and the amounts recognized in the
consolidated financial statements are as follows:
September 30,
--------------------------
2000 1999
---------- ----------
Change in Benefit Obligation
Benefit obligation at beginning of year $1,984,000 $1,966,000
Service cost 78,000 77,000
Interest cost 145,000 139,000
Actuarial (gain)/loss 16,000 (64,000)
Benefits paid (129,000) (134,000)
---------- ----------
Benefit obligation at end of year 2,094,000 1,984,000
---------- ----------
Change in Plan Assets
Fair value of plan assets at beginning of year 2,314,000 2,224,000
Actual return on plan assets 235,000 224,000
Employer contribution 80,000 -
Benefits paid (129,000) (134,000)
---------- ----------
Fair value of plan assets at end of year 2,500,000 2,314,000
---------- ----------
Funded status 406,000 330,000
Unrecognized net asset (2,000) (2,000)
Unrecognized prior service cost 29,000 34,000
Unrecognized actuarial gain (541,000) (514,000)
---------- ----------
Accrued benefit cost $ (108,000) $ (152,000)
========== ==========
Weighted-Average Assumptions as of September 30, 2000 1999
---------- ----------
Discount rate 7.50% 7.50%
Expected return on plan assets 8.00% 8.00%
Rate of compensation increase 5.00% 5.00%
Year ended September 30,
-------------------------------------
2000 1999 1998
--------- --------- ---------
Net Periodic Benefit Cost for the Year
Service cost $ 78,000 $ 77,000 $ 66,000
Interest cost 145,000 139,000 139,000
Expected return on plan assets (180,000) (172,000) (168,000)
Amortization of net asset (1,000) (1,000) (1,000)
Amortization of prior service cost 6,000 6,000 6,000
Amortization of net actuarial gain (12,000) - (8,000)
--------- --------- ---------
Net periodic benefit cost $ 36,000 $ 49,000 $ 34,000
========= ========= =========
<PAGE>
8. STOCK OPTIONS
-------------
In March 1995, the Company granted 20,000 stock options to an officer of
the Company under a non-qualified plan at a purchase price of $19.625 per share
(market price on date of grant), with 4,000 of such options vesting annually
commencing one year from the date of grant. These options have stock
appreciation rights that permit the holder to receive stock, cash or a
combination thereof equal to the amount by which the fair market value, at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant. No compensation cost has been recognized for these
options for the years ended September 30, 2000, 1999 and 1998.
In June 1998, the Company granted 30,000 stock options to an officer of
the Company's oil and gas segment under a non-qualified plan at a purchase price
of $15.625 per share (market price on date of grant), with 6,000 of such options
vesting annually commencing one year from the date of grant. These options have
stock appreciation rights that permit the holder to receive stock, cash or a
combination thereof equal to the amount by which the fair market value, at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant. The Company recognized $46,000 of compensation
costs relating to these options in the year ended September 30, 2000.
In December 1999, the Company granted qualified stock options to certain
employees of the Company to acquire 68,000 shares and 29,000 shares of the
Company's common stock with an exercise price per share of $11.875 (market price
at date of grant) and $13.063 (110% of market price at date of grant),
respectively. These options vest annually over four years commencing one year
from the date of grant. The $11.875 per share options expire ten years from the
date of grant, and the $13.063 per share options expire five years from the date
of grant. No compensation cost has been recognized for these options for the
year ended September 30, 2000.
The Company applies the provisions of APB Opinion No. 25 in accounting for
stock-based compensation and adopted the disclosure-only provisions of Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS No. 123"), effective October 1, 1996. Had compensation cost
for the stock options granted in June 1998 and December 1999 been determined
based on the fair value method of measuring stock-based compensation provisions
of SFAS No. 123, the Company's net earnings and basic and diluted earnings per
share would have been as follows:
Years ended September 30,
-------------------------------------
2000 1999 1998
---- ---- ----
Pro-forma net earnings (loss) $ 4,750,000 $ 440,000 $(3,920,000)
Pro-forma basic =========== =========== ===========
earnings (loss) per share $ 3.61 $ 0.33 $ (2.97)
Pro-forma diluted =========== =========== ===========
earnings (loss) per share $ 3.49 $ 0.33 $ (2.97)
=========== =========== ===========
Fair value measurement of these options was based on a Black Scholes
option-pricing model which included assumptions of a weighted average expected
life of 5.97 years, expected volatility of 30%, weighted average risk-free
interest rate of 6.12%, and an expected dividend yield of 0%. The pro-forma net
earnings (loss) reflects only options granted since October 1, 1995. Therefore,
the full impact of calculating compensation cost for stock options under SFAS
<PAGE>
No. 123 is not reflected in the pro-forma earnings (loss) reported above because
compensation cost is reflected over the options' vesting periods and
compensation cost for options granted prior to October 1, 1995 is not
considered.
During the year ended September 30, 1999, options to acquire 12,500 shares
and 5,000 shares of the Company's common stock with an exercise price per share
of $13.625 and $22.250, respectively, expired. During the year ended September
30, 1998, options to acquire 1,500 shares and 5,000 shares of the Company's
common stock with an exercise price per share of $13.625 and $22.250,
respectively, were forfeited.
Stock options at September 30, 2000 were as follows:
Number of options
---------------------------
Per share price Outstanding Exercisable Expiration Date
--------------- ----------- ----------- ---------------
$11.875 68,000 - December 2009
$13.063 29,000 - December 2004
$15.625 30,000 12,000 May 2008
$19.625 20,000 20,000 March 2005
------- ------
Total 147,000 32,000
======= ======
Weighted average
exercise price $13.93 $18.13
======= ======
Stock options at September 30, 1999 were as follows:
Number of options
---------------------------
Per share price Outstanding Exercisable Expiration Date
--------------- ----------- ----------- ---------------
$15.625 30,000 6,000 May 2008
$19.625 20,000 16,000 March 2005
------ ------
Total 50,000 22,000
====== ======
Weighted average
exercise price $17.23 $18.53
====== ======
Stock options at September 30, 1998 were as follows:
Number of options
---------------------------
Per share price Outstanding Exercisable Expiration Date
--------------- ----------- ----------- ---------------
$13.625 12,500 12,500 December 1998
$15.625 30,000 - May 2008
$19.625 20,000 12,000 March 2005
$22.250 5,000 5,000 May 1999
------ ------
Total 67,500 29,500
====== ======
Weighted average
exercise price $16.93 $17.53
====== ======
<PAGE>
During the year ended September 30, 2000, the Company repurchased 6,000
shares of its common stock on the open market for $93,000 (average price of
$15.50 per share) under a March 2000 stock buyback plan authorizing the
repurchase of up to 100,000 shares. The Company plans to repurchase additional
shares from time to time in the open market or in privately negotiated
transactions, depending on market conditions. At September 30, 2000, the Company
could purchase an additional 94,000 shares under the March 2000 repurchase
authorization.
9. COMMITMENTS AND CONTINGENCIES
-----------------------------
The Company is involved in routine litigation and is subject to
governmental and regulatory controls that are incidental to the ordinary course
of business. The Company's management believes that all claims and litigation
involving the Company are not likely to have a material adverse effect on its
financial statements taken as a whole.
See also Note 4 (Investment in Land) of "Notes to Consolidated Financial
Statements".
The Company has committed to compensate its Vice President of Canadian
Operations pursuant to an incentive compensation plan, the value of which
directly relates to the Company's oil and natural gas segment's net income and
the change in the value of the Company's oil and gas reserves since 1998 with
adjustments for changes in natural gas and oil prices and subject to other terms
and conditions. The Company recognized $290,000 of compensation costs pursuant
to this incentive plan in fiscal 2000.
The Company has several non-cancelable operating leases for office space
and leasehold land. Rental expense was $406,000 in 2000, $427,000 in 1999, and
$433,000 in 1998. The Company is committed under these leases for minimum rental
payments summarized by fiscal year as follows: 2001 - $472,000, 2002 - $457,000,
2003 - $408,000, 2004 - $293,000, 2005 - $179,000, and thereafter through 2026
an aggregate of $1,330,000.
The Company is contingently liable for the repayment of loans under a
$650,000 loan facility, granted by a bank, to three participants in one of the
Company's oil and natural gas ventures. At September 30, 2000, the loan balance
was $250,000, $100,000 of which is to an affiliate of the Company. The three
participants' interests in the venture are pledged as collateral to secure
repayment of the loans. The Company believes the value of the collateral is
significantly in excess of the loan balances.
<PAGE>
10. WRITE-DOWN OF ASSETS
--------------------
Under the full cost method of accounting, the amount of oil and natural
gas properties' capitalized costs less accumulated depletion (on a country by
country basis) is subject to a ceiling test limitation that requires any excess
of such costs over the present value of estimated future cash flows from proved
reserves to be expensed. As of March 31, 1998, the Company's investment in the
development of natural gas and oil reserves in the Central Basin in Michigan was
determined to be impaired and was transferred to the amortization base. Upon
transfer, capitalized oil and natural gas properties' costs in the United States
exceeded the full cost ceiling test limitation and, accordingly, the Company
recorded a non-cash write-down of $2,070,000 in the quarter ended March 31,
1998. Due to further declines in oil prices and disappointing seismic and
drilling results in North Dakota, the Company decided to abandon its U.S. oil
and natural gas prospects and recorded an additional U.S. ceiling test
write-down of $660,000 during the quarter ended June 30, 1998 to fully write-off
its investment in U.S. oil and natural gas properties. In fiscal 1998, the
Company also wrote down $170,000 of land and land improvement costs related to a
contract drilling yard held for sale due to a decline in the market value of the
property, and $95,000 of available-for-sale securities due to a decline in
market value deemed other than temporary.
There were no write-downs of oil and natural gas properties and other
assets in fiscal years 2000 and 1999.
11. SEGMENT AND GEOGRAPHIC INFORMATION
----------------------------------
The Company operates three segments: exploring for, developing, producing
and selling oil and natural gas in Canada; investing in leasehold land in
Hawaii; and drilling wells and installing and repairing water pumping systems in
Hawaii. The Company's reportable segments are strategic business units that
offer different products and services. They are managed separately as each
segment requires different operational methods, operational assets and marketing
strategies, and operate in different geographical locations.
<PAGE>
The Company does not allocate general and administrative expenses,
interest expense, interest income or income taxes to segments, and there are no
transactions between segments that affect segment profit or loss.
Year ended September 30,
-----------------------------------------
2000 1999 1998
----------- ----------- -----------
Revenues:
Oil and natural gas $15,270,000 $10,130,000 $ 9,400,000
Contract drilling 3,520,000 4,230,000 1,510,000
Land investment 6,540,000 - -
Other 891,000 668,000 920,000
----------- ----------- -----------
Total before interest income 26,221,000 15,028,000 11,830,000
Interest income 349,000 132,000 90,000
----------- ----------- -----------
Total revenues $26,570,000 $15,160,000 $11,920,000
=========== =========== ===========
Depreciation, depletion
and amortization:
Oil and natural gas $ 3,121,000 $ 2,574,000 $ 2,698,000
Contract drilling 176,000 110,000 68,000
Other 275,000 136,000 132,000
----------- ----------- -----------
Total $ 3,572,000 $ 2,820,000 $ 2,898,000
=========== =========== ===========
Write-downs of oil and natural gas
properties and other assets:
Oil and natural gas $ - $ - $ 2,730,000
Contract drilling - - 170,000
Other - - 95,000
----------- ----------- -----------
Total $ - $ - $ 2,995,000
=========== =========== ===========
Operating profit (loss)
(before general and
administrative expenses):
Oil and natural gas $ 9,021,000 $ 4,188,000 $ 749,000
Contract drilling 603,000 742,000 (550,000)
Land investment,
net of minority interest 3,232,000 - -
Other 616,000 532,000 693,000
----------- ----------- -----------
Total 13,472,000 5,462,000 892,000
General and
administrative expenses (3,470,000) (3,187,000) (3,292,000)
Foreign exchange losses (420,000) - -
Interest expense (813,000) (809,000) (722,000)
Interest income 349,000 132,000 90,000
----------- ----------- -----------
Earnings (loss)
before income taxes $ 9,118,000 $ 1,598,000 $(3,032,000)
=========== =========== ===========
Capital expenditures:
Oil and natural gas $ 5,003,000 $ 1,753,000 $ 6,969,000
Contract drilling 393,000 121,000 91,000
Land investment 631,000 809,000 862,000
Other 222,000 148,000 205,000
----------- ----------- -----------
Total $ 6,249,000 $ 2,831,000 $ 8,127,000
=========== =========== ===========
<PAGE>
Depletion per 1,000 cubic feet ("MCF") of natural gas and natural gas
equivalent ("MCFE"), converted at a rate of one barrel of oil and natural gas
liquids to 5.8 MCFE, was $0.60 in fiscal 2000, $0.48 in fiscal 1999 and $0.45 in
fiscal 1998.
<TABLE>
<CAPTION>
ASSETS BY SEGMENT:
------------------
September 30,
----------------------------------------------------------
2000 1999 1998
---------------- ----------------- ----------------
<S> <C> <C> <C> <C> <C> <C>
Oil and natural gas (1) $25,686,000 66% $23,864,000 72% $23,959,000 76%
Contract drilling (2) 1,925,000 5% 2,091,000 6% 1,576,000 5%
Land investment (2) 3,975,000 10% 3,519,000 10% 2,710,000 8%
Other:
Cash 5,701,000 15% 2,577,000 8% 2,178,000 7%
Corporate and other 1,373,000 4% 1,244,000 4% 1,238,000 4%
----------- ---- ----------- ---- ----------- ----
Total $38,660,000 100% $33,295,000 100% $31,661,000 100%
=========== ==== =========== ==== =========== ====
<FN>
(1) Primarily located in the Province of Alberta, Canada.
(2) Located in Hawaii.
</FN>
</TABLE>
LONG-LIVED ASSETS BY GEOGRAPHIC AREA:
-------------------------------------
<TABLE>
<CAPTION>
September 30,
----------------------------------------------------------
2000 1999 1998
---------------- ----------------- ----------------
<S> <C> <C> <C> <C> <C> <C>
United States $ 5,383,000 18% $ 4,720,000 17% $ 3,861,000 14%
Canada 23,940,000 82% 22,771,000 83% 22,961,000 86%
----------- ---- ----------- ---- ----------- ----
Total $29,323,000 100% $27,491,000 100% $26,822,000 100%
=========== ==== =========== ==== =========== ====
</TABLE>
REVENUE BY GEOGRAPHIC AREA:
---------------------------
<TABLE>
<CAPTION>
Year ended September 30,
--------------------------------------------
2000 1999 1998
----------- ----------- -----------
<S> <C> <C> <C>
United States $10,175,000 $ 4,237,000 $ 1,690,000
Canada 16,046,000 10,791,000 10,140,000
----------- ----------- -----------
Total (excluding interest income) $26,221,000 $15,028,000 $11,830,000
=========== =========== ===========
</TABLE>
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
-----------------------------------
The carrying amounts of cash and cash equivalents, accounts receivable and
accounts payable approximate fair value because of the short maturity of these
instruments. The fair values of investment securities included in other assets
are estimated based on quoted market prices for those or similar investments.
The fair values of the Company's long-term debt are estimated based on the
current terms offered for debt of the same or similar remaining maturities.
The differences between the estimated fair values and carrying values of
the Company's financial instruments are not material.
<PAGE>
13. CONCENTRATIONS OF CREDIT RISK
-----------------------------
The Company's oil and natural gas segment derived 63% of its oil and
natural gas revenues in fiscal 2000 from three individually significant
customers. At September 30, 2000, the Company had a total of $855,000 in
receivables from three customers. In fiscal 1999, the Company derived 48% of its
oil and natural gas revenues from three individually significant customers. In
fiscal 1998, the Company derived 23% of its oil and natural gas revenues from
one individually significant customer.
The Company's contract drilling subsidiary derived 70%, 43%, and 42% of
its contract drilling revenues in fiscal 2000, 1999, and 1998, respectively,
pursuant to federal, State of Hawaii and local county contracts. At September
30, 2000, the Company had accounts receivables from the federal, State of Hawaii
and local county entities totaling approximately $277,000. The Company has lien
rights on contracts with the federal, State of Hawaii, local county and private
entities.
Historically, the Company has not incurred significant credit related
losses on its trade receivables, and management does not believe significant
credit risk related to these trade receivables exists at September 30, 2000.
14. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
-------------------------------------------------
The following details the effect of changes in current assets and
liabilities on the consolidated statements of cash flows, and presents
supplemental cash flow information:
<TABLE>
<CAPTION>
Year ended September 30,
-------------------------------------
2000 1999 1998
---------- ---------- ---------
Increase (decrease) from changes in:
<S> <C> <C> <C>
Receivables $ 82,000 $ (140,000) $ 29,000
Costs and estimated earnings in excess
of billings on uncompleted contracts (324,000) (60,000) (82,000)
Inventories 25,000 (30,000) (6,000)
Other current assets (233,000) (277,000) 223,000
Accounts payable (42,000) (1,017,000) (88,000)
Accrued expenses 1,454,000 (25,000) 833,000
Billings in excess of costs and
estimated earnings on uncompleted
contracts 211,000 (62,000) 170,000
Payable to joint interest owners 148,000 384,000 (642,000)
Income taxes payable 305,000 298,000 (3,000)
---------- ---------- ---------
Increase (decrease) from changes
in current assets and liabilities $1,626,000 $ (929,000) $ 434,000
========== ========== =========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 848,000 $ 870,000 $ 616,000
========== ========== =========
Income taxes $2,817,000 $ 497,000 $ 540,000
========== ========== =========
</TABLE>
<PAGE>
15. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)
---------------------------------------------------------
The following tables summarize information relative to the Company's oil
and natural gas operations, which are substantially conducted in Canada. Proved
reserves are the estimated quantities of crude oil, condensate and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed producing oil and natural gas reserves
are reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. The estimated net interests in total
proved developed and proved developed producing reserves are based upon
subjective engineering judgments and may be affected by the limitations inherent
in such estimations. The process of estimating reserves is subject to continual
revision as additional information becomes available as a result of drilling,
testing, reservoir studies and production history. There can be no assurance
that such estimates will not be materially revised in subsequent periods.
(A) Oil and Natural Gas Reserves
----------------------------
The following table, based on information prepared by independent
petroleum engineers, Paddock Lindstrom and Associates, Ltd., summarizes changes
in the estimates of the Company's net interests in total proved reserves of
crude oil and condensate and natural gas ("MCF" means 1,000 cubic feet of
natural gas) which are substantially all in Canada:
OIL GAS
Proved reserves: (Barrels) (MCF)
--------- ----------
Balance at September 30, 1997 2,613,000 43,951,000
Revisions of previous estimates (100,000) (909,000)
Extensions, discoveries and other additions 191,000 1,710,000
Less production (291,000) (4,145,000)
Sales of reserves in place - (46,000)
--------- ----------
Balance at September 30, 1998 2,413,000 40,561,000
Revisions of previous estimates 16,000 (550,000)
Extensions, discoveries and other additions 9,000 502,000
Less production (300,000) (3,634,000)
--------- ----------
Balance at September 30, 1999 2,138,000 36,879,000
Revisions of previous estimates (7,000) (300,000)
Increase in royalty rates* (131,000) (5,699,000)
Extensions, discoveries and other additions 72,000 2,417,000
Less production (291,000) (3,501,000)
--------- ----------
Balance at September 30, 2000 1,781,000 29,796,000
========= ==========
<PAGE>
* The deduction of reserve units due to higher royalty rates is the result of
Alberta's royalties being calculated on a sliding scale basis, with the royalty
percentage increasing as prices increase. The Province of Alberta takes its
royalty share of production based on commodity prices; as all commodity prices
were significantly higher at September 30, 2000, as compared to September 30,
1999, significantly more reserves were deducted for royalty volumes at September
30, 2000, as compared to September 30, 1999.
OIL GAS
Proved producing reserves at: (Barrels) (MCF)
--------- ----------
September 30, 1997 2,087,000 29,483,000
========= ==========
September 30, 1998 2,109,000 28,306,000
========= ==========
September 30, 1999 1,759,000 25,908,000
========= ==========
September 30, 2000 1,508,000 20,594,000
========= ==========
(B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities
-----------------------------------------------------------------------
2000 1999 1998
----------- ----------- -----------
Proved properties $50,271,000 $46,966,000 $43,265,000
Unproved properties 2,191,000 1,968,000 2,205,000
----------- ----------- -----------
Total capitalized costs 52,462,000 48,934,000 45,470,000
Accumulated depletion
and depreciation 28,945,000 26,678,000 23,041,000
----------- ----------- -----------
Net capitalized costs $23,517,000 $22,256,000 $22,429,000
=========== =========== ===========
<PAGE>
(C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration
-----------------------------------------------------------------------
and Development
---------------
Year ended September 30,
----------------------------------------
2000 1999 1998
---------- ---------- ----------
Acquisition of properties:
Unproved -
Canadian $ 540,000 $ 125,000 $ 184,000
United States - - 85,000
---------- ---------- ----------
$ 540,000 $ 125,000 $ 269,000
========== ========== ==========
Proved - Canadian $ - $ - $ 48,000
========== ========== ==========
Exploration costs:
Canadian $ 813,000 $ 189,000 $1,299,000
United States 167,000 - 493,000
---------- ---------- ----------
$ 980,000 $ 189,000 $1,792,000
========== ========== ==========
Development costs:
Canadian $3,483,000 $1,439,000 $4,478,000
United States - - 382,000
---------- ---------- ----------
$3,483,000 $1,439,000 $4,860,000
========== ========== ==========
(D) The Results of Operations of Barnwell's Oil and Natural Gas Producing
---------------------------------------------------------------------
Activities
----------
Year ended September 30,
-------------------------------------------
2000 1999 1998
----------- ----------- -----------
Gross revenues:
Canada $18,022,000 $11,231,000 $10,626,000
United States 103,000 - 132,000
----------- ----------- -----------
Total gross revenues 18,125,000 11,231,000 10,758,000
Royalties, net of credit 2,855,000 1,101,000 1,358,000
----------- ----------- -----------
Net revenues 15,270,000 10,130,000 9,400,000
Production costs 3,128,000 3,368,000 3,223,000
Depletion and depreciation 3,121,000 2,574,000 2,698,000
Write-down - - 2,730,000
----------- ----------- -----------
Pre-tax results of operations* 9,021,000 4,188,000 749,000
Estimated income tax expense 4,271,000 2,124,000 1,886,000
----------- ----------- -----------
Results of operations* $ 4,750,000 $ 2,064,000 $(1,137,000)
=========== =========== ===========
* Before general and administrative expenses, interest expense, and foreign
exchange losses.
<PAGE>
(E) Standardized Measure, Including Year-to-Year Changes Therein, of Estimated
--------------------------------------------------------------------------
Discounted Future Net Cash Flows
--------------------------------
The following tables have been developed pursuant to procedures prescribed
by SFAS 69, and utilize reserve and production data estimated by petroleum
engineers. The information may be useful for certain comparison purposes but
should not be solely relied upon in evaluating the Company or its performance.
Moreover, the projections should not be construed as realistic estimates of
future cash flows, nor should the standardized measure be viewed as representing
current value.
The estimated future cash flows are based on sales prices, costs, and
statutory income tax rates in existence at the dates of the projections.
Material revisions to reserve estimates may occur in the future, development and
production of the oil and natural gas reserves may not occur in the periods
assumed and actual prices realized and actual costs incurred are expected to
vary significantly from those used. Management does not rely upon this
information in making investment and operating decisions; rather, those
decisions are based upon a wide range of factors, including estimates of
probable reserves as well as proved reserves and price and cost assumptions
different than those reflected herein.
Standardized Measure of Estimated Discounted Future Net Cash Flows
------------------------------------------------------------------
As of September 30,
----------------------------------------------
2000 1999 1998
------------ ------------ ------------
Future cash inflows $159,328,000 $108,463,000 $ 83,827,000
Future production costs (32,309,000) (33,680,000) (30,052,000)
Future development costs (1,397,000) (1,268,000) (1,372,000)
------------ ------------ ------------
Future net cash
flows before income taxes 125,622,000 73,515,000 52,403,000
Future income tax expenses (51,516,000) (24,914,000) (15,379,000)
------------ ------------ ------------
Future net cash flows 74,106,000 48,601,000 37,024,000
10% annual discount
for timing of cash flows (31,606,000) (19,844,000) (14,351,000)
------------ ------------ ------------
Standardized measure of
estimated discounted
future net cash flows $ 42,500,000 $ 28,757,000 $ 22,673,000
============ ============ ============
<PAGE>
Changes in the Standardized Measure of Estimated Discounted Future Net Cash
---------------------------------------------------------------------------
Flows
-----
Year ended September 30,
---------------------------------------
2000 1999 1998
----------- ----------- -----------
Beginning of year $28,757,000 $22,673,000 $27,982,000
----------- ----------- -----------
Sales of oil and natural gas
produced, net of production costs (12,142,000) (6,762,000) (6,177,000)
Net changes in prices and
production costs, net of
royalties and wellhead taxes 33,265,000 13,452,000 (2,295,000)
Extensions and discoveries 6,132,000 561,000 1,650,000
Revisions of previous
quantity estimates 38,000 (52,000) (1,153,000)
Net change in Canadian
dollar translation rate (358,000) 864,000 (2,744,000)
Changes in the timing of
future production and other (1,755,000) (851,000) 447,000
Net change in income taxes (14,166,000) (3,465,000) 2,417,000
Accretion of discount 2,729,000 2,337,000 2,546,000
----------- ----------- -----------
Net change 13,743,000 6,084,000 (5,309,000)
----------- ----------- -----------
End of year $42,500,000 $28,757,000 $22,673,000
=========== =========== ===========
Item 8. Changes in and Disagreements with Accountants on Accounting and
----------------------------------------------------------------
Financial Disclosure
--------------------
None.
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons,
-------------------------------------------------------------
Compliance With Section 16(a) of the Exchange Act
-------------------------------------------------
Item 10. Executive Compensation
----------------------
Item 11. Security Ownership of Certain Beneficial Owners and Management
--------------------------------------------------------------
Item 12. Certain Relationships and Related Transactions
----------------------------------------------
Items 9, 10, 11, and 12 are omitted pursuant to General Instructions E.3.
of Form 10-KSB, since the Registrant will file its definitive proxy statement
for the 2001 Annual Meeting of Stockholders not later than 120 days after the
close of its fiscal year ended September 30, 2000, which proxy statement is
incorporated herein by reference.
<PAGE>
Item 13. Exhibits, List and Reports on Form 8-K
--------------------------------------
(A) Financial Statements
The following consolidated financial statements of Barnwell Industries,
Inc. and its subsidiaries are included in Part II, Item 7:
Independent Auditors' Report - KPMG LLP
Consolidated Balance Sheets - September 30, 2000 and 1999
Consolidated Statements of Operations -
for the three years ended September 30, 2000
Consolidated Statements of Cash Flows -
for the three years ended September 30, 2000
Consolidated Statements of Stockholders' Equity and
Comprehensive Income (Loss) -
for the three years ended September 30, 2000
Notes to Consolidated Financial Statements
Schedules have been omitted because they were not applicable, not
required, or the information is included in the consolidated financial
statements or notes thereto.
(B) Reports on Form 8-K
There were no reports on Form 8-K filed during the three months ended
September 30, 2000.
(C) Exhibits
No. 3.1 Certificate of Incorporation(1)
No. 3.2 Amended and Restated By-Laws(1)
No. 4.0 Form of the Registrant's certificate of common stock, par value
$.50 per share.(2)
No. 10.1 The Barnwell Industries, Inc. Employees' Pension Plan (restated
as of October 1, 1989).(3)
No. 10.2 Phase I Makai Development Agreement dated June 30, 1992, by
and between Kaupulehu Makai Venture and Kaupulehu Developments.
(4)
No. 10.3 KD/KMV Agreement dated June 30, 1992 by and between Kaupulehu
Makai Venture and Kaupulehu Developments.(4)
No. 10.4 Barnwell Industries, Inc.'s letter to Warren D. Steckley dated
May 6, 1998, regarding certain terms of employment.
No. 21 List of Subsidiaries.(5)
No. 27 Financial Data Schedule (for SEC use only)
-----------------------------
(1) Incorporated by reference to the Registrant's Form S-8 dated November 8,
1991.
(2) Incorporated by reference to the registration statement on Form S-1
originally filed by the Registrant January 29, 1957 and as amended
February 15, 1957 and February 19, 1957.
(3) Incorporated by reference to Form 10-K for the year ended September 30,
1989.
(4) Incorporated by reference to Form 10-K for the year ended September 30,
1992.
(5) Incorporated by reference to Form 10-KSB for the year ended September
30, 1998.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BARNWELL INDUSTRIES, INC.
(Registrant)
/s/Russell M. Gifford
-----------------------------------
By: Russell M. Gifford
Chief Financial Officer,
Executive Vice President and
Treasurer
Date: December 1, 2000
<PAGE>
Pursuant to the requirements of the Securities Exchange Act of 1934,
the report has been signed below by the following persons on behalf of the
registrant in the capacities and on the dates indicated.
/s/Morton H. Kinzler
------------------------
MORTON H. KINZLER
Chief Executive Officer,
President and
Chairman of the Board
Date: December 1, 2000
/s/Martin Anderson /s/Daniel Jacobson
------------------------- -------------------------
MARTIN ANDERSON, Director DANIEL JACOBSON, Director
Date: December 1, 2000 Date: December 1, 2000
/s/Murray C. Gardner /s/Terry Johnston
--------------------------- ------------------------
MURRAY C. GARDNER, Director TERRY JOHNSTON, Director
Date: December 1, 2000 Date: December 1, 2000
/s/Erik Hazelhoff-Roelfzema /s/Alexander C. Kinzler
--------------------------------- ------------------------------
ERIK HAZELHOFF-ROELFZEMA, Director ALEXANDER C. KINZLER
Date: December 1, 2000 Executive Vice President,
Secretary and Director
/s/Alan D. Hunter Date: December 1, 2000
------------------------
ALAN D. HUNTER, Director
Date: December 1, 2000 /s/Glenn Yago
-------------------
GLENN YAGO, Director
Date: December 1, 2000
