U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-KSB
X ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE
--- SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1999
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
--- SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-5103
BARNWELL INDUSTRIES, INC.
(Name of small business issuer in its charter)
DELAWARE 72-0496921
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1100 ALAKEA STREET, SUITE 2900, HONOLULU, HAWAII 96813-2833
(Address of principal executive offices) (Zip code)
(808) 531-8400
(Issuer's telephone number)
Securities registered under Section 12(b) of the Exchange Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common Stock, par value American Stock Exchange
$0.50 per share Toronto Stock Exchange
Securities registered under Section 12(g) of the Exchange Act: None
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes X No
--- ---
Check if there is no disclosure of delinquent filers in response to Item 405
of Regulation S-B, and no disclosure will be contained, to the best of
registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB. [X]
Issuer's revenues for the fiscal year ended September 30, 1999: $15,160,000
The aggregate market value of the voting stock held by non-affiliates (566,097
shares) of the Registrant on December 3, 1999, based on the closing price of
$11.875 on that date on the American Stock Exchange, was $6,722,000.
As of December 3, 1999 there were 1,316,952 shares of common stock, par value
$.50, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
-----------------------------------
1. Proxy statement to be forwarded to shareholders on or about January 20,
2000 is incorporated by reference in Part III hereof.
Transitional Small Business Disclosure Format Yes No X
----- -----
TABLE OF CONTENTS
PART I
Discussion of Forward-Looking Statements
Item 1. Description of Business
General Development of Business
Financial Information about Industry Segments
Narrative Description of Business
Financial Information about Foreign and
Domestic Operations and Export Sales
Item 2. Description of Property
Oil and Natural Gas Operations
General
Well Drilling Activities
Oil and Natural Gas Production
Productive Wells
Developed Acreage and Undeveloped Acreage
Reserves
Estimated Future Net Revenues
Marketing of Oil and Natural Gas
Governmental Regulation
Competition
Contract Drilling Operations
Activity
Competition
Land Investment Operations
Activity
Competition
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market For Common Equity and Related Stockholder Matters
Item 6. Management's Discussion and Analysis or Plan of Operation
Liquidity and Capital Resources
Year 2000 Compliance
Results of Operations
Item 7. Financial Statements
Item 8. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons,
Compliance With Section 16(a) of the Exchange Act
Item 10. Executive Compensation
Item 11. Security Ownership of Certain Beneficial Owners and Management
Item 12. Certain Relationships and Related Transactions
Item 13. Exhibits and Reports on Form 8-K
PART I
Forward-Looking Statements
- --------------------------
This Form 10-KSB, and the documents incorporated herein by reference,
contains forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended, including various forecasts, projections of Barnwell
Industries, Inc.'s (referred to herein together with its subsidiaries as
"Barnwell" or the "Company") future performance, statements of the Company's
plans and objectives and other similar types of information. Although the
Company believes that its expectations are based on reasonable assumptions, it
cannot assure that the expectations contained in such forward-looking statements
will be achieved. Such statements involve risks, uncertainties and assumptions,
including, but not limited to, those relating to the factors discussed below, in
other portions of this Form 10-KSB, in the Notes to Consolidated Financial
Statements, and in other documents filed by the Company with the Securities and
Exchange Commission from time to time, which could cause actual results to
differ materially from those contained in such statements. These forward-looking
statements speak only as of the date of filing of this Form 10-KSB, and the
Company expressly disclaims any obligation or undertaking to publicly release
any updates or revisions to any forward-looking statements contained herein.
The Company's oil and natural gas operations are affected by domestic and
international political, legislative, regulatory and legal actions. Such actions
may include changes in the policies of the Organization of Petroleum Exporting
Countries ("OPEC") or other developments involving or affecting oil-producing
countries, including military conflict, embargoes, internal instability or
actions or reactions of the government of the United States in anticipation of
or in response to such developments. Domestic and international economic
conditions, such as recessionary trends, inflation, interest costs, monetary
exchange rates and labor costs, as well as changes in the availability and
market prices of crude oil, natural gas and petroleum products, may also have a
significant effect on the Company's oil and natural gas operations. While the
Company maintains reserves for anticipated liabilities and carries various
levels of insurance, the Company could be affected by civil, criminal,
regulatory or administrative actions, claims or proceedings. In addition,
climate and weather can significantly affect the Company in several of its
operations. The Company's oil and gas operations are also affected by political
developments and laws and regulations, particularly in the United States and
Canada, such as restrictions on production, restrictions on imports and exports,
the maintenance of specified reserves, tax increases and retroactive tax claims,
expropriation of property, cancellation of contract rights, environmental
protection controls, environmental compliance requirements and laws pertaining
to workers' health and safety.
The Company's land investment business segment is affected by the
condition of Hawaii's real estate market. The Hawaii real estate market is
affected by Hawaii's economy in general and Hawaii's tourism industry in
particular. Any future cash flows from the Company's land development activities
are subject to, among other factors, the level of real estate activity and
prices, the demand for new housing and second homes on the Island of Hawaii, the
rate of increase in the cost of building materials and labor, the introduction
of building code modifications, changes to zoning laws, and the level of
consumer confidence in Hawaii's economy.
The Company's contract drilling operations, which are located in Hawaii,
are also indirectly affected by the factors discussed in the preceding
paragraph. The Company's contract drilling operations are materially dependent
upon levels of activity in land development in Hawaii. Such activity levels are
affected by both short-term and long-term trends in Hawaii's economy. In prior
years, Hawaii's economy has experienced very slow growth, and as events during
previous years have demonstrated, any prolonged reduction or lack of growth in
Hawaii's economy will depress the demand for the Company's contract drilling
services. Such a decline could have a material adverse effect on the Company's
revenues and profitability.
Item 1. Description of Business
-----------------------
(a) General Development of Business
-------------------------------
Barnwell was incorporated in 1956. During its last three completed fiscal
years, the Company was engaged in oil and natural gas exploration, development,
production and sales primarily in Canada, investment in leasehold land in
Hawaii, and water and exploratory well drilling and water pumping system
installation and repair in Hawaii. Additionally, in fiscal 1999, the Company
started providing contract labor for the drilling and workovers of geothermal
wells; this work is continuing into fiscal 2000. The Company's oil and natural
gas activities comprise its largest business segment. Approximately 67% of the
Company's revenues for the fiscal year ended September 30, 1999 were
attributable to its oil and natural gas activities. The Company's contract
drilling activities accounted for 28% of the Company's revenues in fiscal 1999,
with natural gas processing and other revenues comprising the remaining 5% of
fiscal 1999 revenues. Approximately 62% of the Company's capital expenditures
for the fiscal year ended September 30, 1999 were attributable to oil and
natural gas activities, 29% to land investment, 4% to contract drilling
activities and 5% to other activities. The Company had no land investment
revenue in 1999; land investment revenues relate to sales of leasehold interests
and development rights, which do not occur every year.
(i) Oil and Natural Gas Activities.
------------------------------
The Company's wholly-owned subsidiary, Barnwell of Canada, Limited ("BOC"),
is involved in the acquisition, exploration and development of oil and natural
gas properties, principally in Alberta, Canada. BOC participates in exploratory
and developmental operations for oil and natural gas on property in which it has
an interest and evaluates proposals by third parties with regard to
participation in such exploratory and developmental operations elsewhere.
(ii) Contract Drilling.
-------------------
The Company's wholly-owned subsidiary, Water Resources International, Inc.
("WRI"), drills water, geothermal and exploratory wells and installs and repairs
water pumping systems in Hawaii. WRI owns and operates four rotary drill rigs,
one rotary drill/workover rig, and pump installation and service equipment, and
maintains drilling materials and pump inventory in Hawaii. WRI's contracts are
usually fixed price or day rate contracts that are either negotiated with
private individuals or entities, or are obtained through competitive bidding
with various private entities or local, state and federal agencies.
(iii) Land Investment.
----------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii general partnership. Between 1986 and 1989, Kaupulehu Developments
obtained the state and county zoning changes necessary to permit development of
the Four Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club,
a planned second golf course, and single and multiple family residential units
on land acquired from Kaupulehu Developments. Kaupulehu Developments currently
owns development rights in approximately 100 acres of residentially zoned
leasehold land and leasehold rights in approximately 2,100 acres of land located
in the North Kona District of the Island of Hawaii.
(b) Financial Information about Industry Segments
---------------------------------------------
Revenues of each industry segment for the fiscal years ended September 30,
1999, 1998 and 1997 are summarized as follows (all revenues were from
unaffiliated customers with no intersegment sales or transfers):
1999 1998 1997
---------------- ---------------- ----------------
Oil and natural gas $10,130,000 67% $ 9,400,000 79% $11,520,000 78%
Contract drilling 4,230,000 28% 1,510,000 13% 2,160,000 14%
Other 668,000 4% 920,000 7% 873,000 6%
----------- ---- ----------- ---- ----------- ----
Revenues from
segments 15,028,000 99% 11,830,000 99% 14,553,000 98%
Interest income 132,000 1% 90,000 1% 277,000 2%
----------- ---- ----------- ---- ----------- ----
Total revenues $15,160,000 100% $11,920,000 100% $14,830,000 100%
=========== ==== =========== ==== =========== ====
For further discussion see Note 11 (Segment and Geographic Information)
and Note 13 (Concentrations of Credit Risk) of "Notes to Consolidated Financial
Statements" in Item 7.
(c) Narrative Description of Business
---------------------------------
See the table above in Item 1(b) detailing revenue of each industry
segment and description of each industry segment of the Company's business under
Item 2.
As of September 30, 1999, Barnwell employed 71 employees, all on a
full-time basis. Fifty are employed in contract drilling activities, ten are
employed in oil and natural gas activities, and 11 are members of the corporate
and administrative staff. This is an increase of 34 employees, all contract
drilling employees, as compared to 37 employees as of September 30, 1998.
For further discussion see "Governmental Regulation" and "Competition"
sections in Item 2 hereof.
(d) Financial Information about Foreign and Domestic Operations and
---------------------------------------------------------------
Export Sales
------------
Revenues and long-lived assets by geographic area for the three years
ended and as of September 30, 1999, 1998 and 1997 are set forth in Note 11
(Segment and Geographic Information) of "Notes to Consolidated Financial
Statements" in Item 7.
Item 2. Description of Property
-----------------------
OIL AND NATURAL GAS OPERATIONS
------------------------------
General
- -------
Barnwell's investments in oil and natural gas properties consist of
investments in Canada, principally in the Province of Alberta, with minor
holdings in Saskatchewan and North Dakota. These property interests are
principally held under governmental leases or licenses. Under the typical
Canadian provincial governmental lease, Barnwell must perform exploratory
operations and comply with certain other conditions. Lease terms vary with each
province, but, in general, the terms grant Barnwell the right to remove oil,
natural gas and related substances subject to payment of specified royalties on
production.
Barnwell participates in exploratory and developmental operations for oil
and natural gas on property in which it has an interest. The Company also
evaluates proposals by third parties for participation in other exploratory and
developmental opportunities. All exploratory and developmental operations are
overseen by Barnwell's Calgary, Alberta staff along with independent consultants
as necessary. In fiscal 1999, Barnwell participated in exploratory and
developmental operations in the Canadian Province of Alberta, although Barnwell
does not limit its consideration of exploratory and developmental operations to
this area.
Barnwell's producing natural gas properties are located principally in
Alberta. The Province of Alberta determines its royalty share of natural gas by
using a reference price that averages all natural gas sales in Alberta. Royalty
rates are calculated on a sliding scale basis, increasing as prices increase.
Additionally, Barnwell pays gross overriding royalties on a portion of its
natural gas sales to other parties.
In fiscal 1999, the weighted average of royalties paid on natural gas from
the Dunvegan Unit, Barnwell's principal oil and natural gas property, was 26%.
The weighted average of royalties paid on all of the Company's natural gas was
approximately 26% in fiscal 1999 versus 21% in fiscal 1998. The increase in the
weighted average royalty rate was primarily due to higher gas prices in fiscal
1999.
In fiscal 1999, virtually all of Barnwell's oil production was from
properties located in Alberta. Royalty rates under government leases in Alberta
are based on the selling price of oil and production volumes. In fiscal 1999,
the weighted average royalty paid on oil was approximately 20%. In fiscal 1998,
the weighted average royalty paid on oil was approximately 19%.
Unit sales and prices of natural gas are typically higher in the winter
than at other times due to demand for heating. Unit sales and prices of oil are
also subject to seasonal fluctuations, but to a lesser degree.
Well Drilling Activities
- ------------------------
During fiscal 1999, the Company participated in the drilling of 13
development wells and two exploratory wells, of which, in the Company's view, 13
are capable of production. The Company also participated in the recompletion of
15 wells. The most significant drilling and recompletion operations took place
in the Dunvegan and Red Earth areas of Alberta.
The Dunvegan Unit, which is the Company's principal oil and natural gas
property and is located in Alberta, Canada, has over 140 natural gas wells
producing from over 200 well zones. The Company holds an 8.9% interest in the
Dunvegan Unit. In fiscal 1999, the Company spent over $700,000 to further
develop the property through drilling, recompletions and optimizing the
gathering system. Specifically, the Company participated in the drilling of two
natural gas wells and the recompletion of ten natural gas wells. The results of
the 1999 program were positive, demonstrating new potential in an area of the
unit and with the majority of the recompletions contributing to natural gas
production.
The following table sets forth more detailed information with respect to
the number of exploratory ("Exp.") and development ("Dev.") wells drilled for
the fiscal years ended September 30, 1999, 1998 and 1997 in which the Company
participated:
Total
Productive Productive Productive
Oil Wells Gas Wells Wells Dry Holes Total Wells
----------- ----------- ----------- ----------- ------------
Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev.
---- ---- ---- ---- ---- ---- ---- ---- ---- -----
1999
- ----
Gross* - 3.00 2.00 8.00 2.00 11.00 - 2.00 2.00 13.00
Net* - 0.25 0.35 0.62 0.35 0.87 - 0.14 0.35 1.01
1998
Gross* 1.00 20.00 - 24.00 1.00 44.00 8.00 6.00 9.00 50.00
Net* 0.18 3.36 - 1.51 0.18 4.87 1.20 0.37 1.38 5.24
1997
Gross* 4.00 25.00 3.00 21.00 7.00 46.00 10.00 9.00 17.00 55.00
Net* 0.72 2.92 0.14 2.27 0.86 5.19 0.80 1.13 1.66 6.32
- ----------------------------------
* The term "Gross" refers to the total number of wells in which Barnwell owns
an interest, and "Net" refers to Barnwell's aggregate interest therein. For
example, a 50% interest in a well represents 1 gross well, but .50 net well.
The gross figure includes interests owned of record by Barnwell and, in
addition, the portion owned by others.
Oil and Natural Gas Production
- ------------------------------
In fiscal 1999, approximately 57%, 34% and 9% of the Company's oil and
natural gas revenues were from the sale of natural gas, the sale of oil
(including natural gas liquids) and the Alberta royalty tax credit,
respectively.
In fiscal 1999, the Company's natural gas production in fiscal 1999
averaged net sales volume after royalties of 9,000 MCF per day, a decrease of
11% from 10,100 MCF per day in fiscal 1998. This decrease was due to expected
natural declines in production from some of the Company's mature properties
(Dunvegan, Hillsdown, Charlotte Lake, Thornbury, and Pouce Coupe) and higher
royalty rates. Dunvegan continues to contribute approximately 47% of the
Company's natural gas production.
In fiscal 1999, oil sales averaged net production of 526 barrels per day,
a decrease of 9% from fiscal 1998. The Company's major oil producing properties
are the Red Earth, Chauvin and Manyberries areas in Canada.
In fiscal 1999, natural gas liquid sales averaged net production of 200
barrels per day, an increase of 12% from fiscal 1998. This increase was due to
the construction of a liquids extraction plant at Dunvegan that was completed in
late fiscal 1998. Dunvegan provided 75% of the Company's fiscal 1999 natural gas
liquids production. Other major natural gas liquids producing properties are the
Hillsdown, Pembina and Pouce Coupe areas in Alberta.
In fiscal 1998, approximately 54%, 36% and 10% of the Company's oil and
natural gas revenues were from the sale of natural gas, the sale of oil
(including liquids) and the Alberta royalty tax credit, respectively.
The following table summarizes (a) Barnwell's net production for the last
three fiscal years, based on sales of crude oil, natural gas, condensate and
other natural gas liquids, from all wells in which Barnwell has or had an
interest, and (b) the average sales prices and average production costs for such
production during the same periods. Barnwell's net production in fiscal 1999 was
derived primarily from the Province of Alberta. All dollar amounts in this table
are in U.S. dollars.
Year Ended September 30,
------------------------------------------
1999 1998 1997
------------- ------------- ------------
Annual net production:
Natural gas liquids (BBLS)* 73,000 65,000 65,000
Oil (BBLS)* 192,000 210,000 199,000
Natural gas (MCF)* 3,295,000 3,684,000 3,852,000
Annual average sale price
per unit of production:
BBL of liquids** $ 9.78 $11.36 $17.55
BBL of oil** $14.08 $13.02 $19.55
MCF of natural gas** $ 1.57 $ 1.38 $ 1.45
Annual average production cost
per MCFE produced*** $ 0.70 $ 0.61 $ 0.62
The following table sets forth the gross and net number of productive wells
Barnwell has an interest in as of September 30, 1999.
Productive Wells
- ----------------
Productive Wells****
----------------------------------
Gross***** Net*****
---------------- ----------------
Location Oil Gas Oil Gas
- --------------------- ------- ------- ------- -------
Canada
- ------
Alberta 189 356 48.7 42.1
Saskatchewan 3 21 0.3 3.6
------- ------- ------- -------
Total 192 377 49.0 45.7
======= ======= ======= =======
- -----------------------------
* When used in this report, "MCF" means 1,000 cubic feet of natural gas at
14.65 psia and 60 degrees F and the term "BBLS" means stock tank barrels
of oil equivalent to 42 U.S. gallons.
** Calculated on revenues before royalty expense and royalty tax credit
divided by gross production.
*** Natural gas liquids, oil and natural gas units were combined by converting
barrels of natural gas liquids and oil to an MCF equivalent ("MCFE") on
the basis of 5.8 MCF = 1 BBL.
**** Seventy-two gross natural gas wells have dual or multiple completions and
six gross oil wells have dual completions.
***** Please see note (2) on the following table.
Developed Acreage and Undeveloped Acreage
- -----------------------------------------
The following table sets forth certain information with respect to oil and
natural gas properties of Barnwell as of September 30, 1999:
Developed and
Developed Undeveloped Undeveloped
Acreage(1) Acreage(1) Acreage(1)
-------------------- ------------------- -------------------
Location Gross(2) Net(2) Gross(2) Net(2) Gross(2) Net(2)
- ------------------- ---------- --------- --------- ---------- ---------- -------
Canada
- ------
Alberta 252,424 37,089 167,420 37,056 419,844 74,145
British Columbia - - 2,789 284 2,789 284
Saskatchewan 3,696 543 200 11 3,896 554
U.S.
- ----
North Dakota 1,520 264 22,779 10,535 24,299 10,799
------- ------ ------- ------ ------- ------
Total 257,640 37,896 193,188 47,886 450,828 85,782
======= ====== ======= ====== ======= ======
- ------------------------------
(1) "Developed Acreage" includes the acres covered by leases upon which there
are one or more producing wells. "Undeveloped Acreage" includes acres
covered by leases upon which there are no producing wells and which are
maintained in effect by the payment of delay rentals or the commencement
of drilling thereon.
(2) "Gross" refers to the total number of wells or acres in which Barnwell
owns an interest, and "Net" refers to Barnwell's aggregate interest
therein. For example, a 50% interest in a well represents one Gross Well,
but .50 Net Well, and similarly, a 50% interest in a 320 acre lease
represents 320 Gross Acres and 160 Net Acres. The gross wells and gross
acreage figures include interests owned of record by Barnwell and, in
addition, the portion owned by others.
Barnwell's leasehold interests in its undeveloped acreage, if not
developed, expire over the next five fiscal years as follows: 25% expire during
fiscal 2000; 19% expire during fiscal 2001; 20% expire during fiscal 2002; 21%
expire during fiscal 2003 and 15% expire during fiscal 2004. There can be no
assurance that the Company will be successful in renewing its leasehold
interests in the event of expiration.
Barnwell's undeveloped acreage includes major concentrations in Alberta at
Thornbury (6,604 net acres), Archie (4,000 net acres) and Boulder (2,880 net
acres).
Reserves
- --------
The amounts set forth in the table below, prepared by Paddock Lindstrom
and Associates, Ltd., Barnwell's independent reservoir engineering consultants,
summarize the estimated net quantities of proved developed producing reserves
and proved developed reserves of crude oil (including condensate and natural gas
liquids) and natural gas as of September 30, 1999, 1998 and 1997 on all
properties in which Barnwell has an interest. These reserves are before
deductions for indebtedness secured by the properties and are based on constant
dollars. No estimates of total proved net oil or natural gas reserves have been
filed with or included in reports to any federal authority or agency since
October 1, 1980.
Proved Developed Producing Reserves
- -----------------------------------
September 30,
-------------------------------------------
1999 1998 1997
------------- ------------- -------------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 1,759,000 2,109,000 2,087,000
Natural gas - thousand
cubic feet (MCF) 25,908,000 28,306,000 29,483,000
Total Proved Developed Reserves
(Includes Proved
Developed Producing Reserves)
- -----------------------------
September 30,
-------------------------------------------
1999 1998 1997
------------- ------------- -------------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 2,138,000 2,413,000 2,613,000
Natural gas - thousand
cubic feet (MCF) 36,879,000 40,561,000 43,951,000
As of September 30, 1999, essentially all of Barnwell's proved developed
producing and total proved developed reserves were located in the Province of
Alberta, with minor volumes located in the Province of Saskatchewan.
During fiscal 1999, Barnwell's total net proved developed reserves,
including proved developed producing reserves, of oil, condensate and natural
gas liquids decreased by 275,000 barrels, and total net proved developed
reserves of natural gas decreased by 3,682,000 MCF. The change in oil,
condensate and natural gas liquids reserves was the net result of production
during the year of 265,000 barrels, the addition of 9,000 barrels from the
drilling of productive oil wells, and the independent engineer's 19,000 barrel
downward revision of the Company's oil reserves. The Company's oil reserves were
negatively impacted by a 59,000 barrel downward revision in reserves associated
with an older well in the Red Earth area of Alberta due to production problems.
Barnwell's proved developed natural gas reserves decreased as a net result of
production during the year of 3,295,000 MCF, the independent engineer's 889,000
MCF downward revision of the Company's natural gas reserves, and the addition of
502,000 MCF from the drilling of productive natural gas wells. The independent
engineer's downward revision of the Company's net proved developed natural gas
reserves was primarily the result of the engineer's use of higher royalty rates
due to his use of higher prices as of September 30, 1999, as compared to
September 30, 1998.
Barnwell's working interest in the Dunvegan Unit accounted for
approximately 65% and 62% of its total proved developed natural gas reserves at
September 30, 1999 and 1998, respectively, and approximately 32% of proved
developed oil and condensate reserves at September 30, 1999, as compared to
approximately 28% of proved developed oil and condensate reserves at September
30, 1998.
The following table sets forth the Company's oil and natural gas reserves
at September 30, 1999, by property name, based on information prepared by
Paddock Lindstrom and Associates, Ltd., Barnwell's independent reservoir
engineering consultant. Gross reserves are before the deduction of royalties;
net reserves are after the deduction of royalties net of the Alberta Royalty Tax
Credit. This table is based on constant dollars where reserve estimates are
based on sales prices, costs and statutory tax rates in existence at the date of
the projection. Oil, which includes natural gas liquids, is shown in thousands
of barrels ("MBBLS") and natural gas is shown in millions of cubic feet
("MMCF").
<TABLE>
OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 1999
<CAPTION>
Total Producing Total Proved
------------------------------- -------------------------------
Oil Gas Oil Gas
--------------- -------------- ------------- ---------------
Property Name GROSS NET GROSS NET GROSS NET GROSS NET
(MBBLS) (MMCF) (MBBLS) (MMCF)
--------------- -------------- ------------- ---------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dunvegan Unit 697 510 19,815 17,705 933 678 26,512 23,832
Dunvegan Non-Unit 124 112 293 261 142 125 805 708
Hillsdown 52 41 1,933 1,724 71 58 2,103 1,877
Thornbury - - 1,753 1,647 - - 2,043 1,923
Manyberries 112 103 39 32 127 118 56 46
Pouce Coupe 5 4 838 764 6 5 1,034 948
Red Earth 752 707 - - 860 809 - -
Pembina 36 32 272 233 36 32 272 232
Barrhead 2 2 315 297 2 2 315 296
Bashaw - - 31 28 - - 31 28
Belloy - - 256 229 - - 487 433
Cessford 6 6 - - 6 6 - -
Charlotte Lake 28 26 569 544 28 26 1,006 958
Chauvin 92 85 - - 92 85 - -
Chigwell - - 12 12 - - 12 12
Coyote - - 24 24 - - 24 24
Drumheller 15 9 471 352 15 9 471 352
Faith - - - - - - 1,011 902
Fenn-Big Valley - - 4 3 - - 4 3
Gilby 2 2 12 11 2 2 12 10
Gilwood - - - - - - 96 80
Highvale - - - - 18 18 67 59
Hilda - - 41 39 - - 41 39
Lanaway - - - - - - 183 161
Leduc - - - - - - 204 189
Majeau Lake 1 1 23 22 1 1 23 22
Medicine River 42 38 135 123 84 70 1,269 1,090
Mikwan 1 1 31 29 1 1 31 29
Mitsue - - 30 27 - - 30 27
Rainbow 2 2 - - 2 2 - -
Richdale - - - - - - 178 164
Staplehurst 9 8 - - 17 16 - -
Sunnynook 3 3 882 780 3 3 882 779
Wood River 23 22 216 197 23 22 216 197
Worsley 2 2 - - 2 2 - -
Zama 43 40 619 527 48 45 1,330 1,161
Hatton, Saskatchewan - - 418 298 - - 418 298
Webb, Saskatchewan 3 3 - - 3 3 - -
----- ----- ------ ------ ----- ----- ------ ------
TOTAL 2,052 1,759 29,032 25,908 2,522 2,138 41,166 36,879
===== ===== ====== ====== ===== ===== ====== ======
<FN>
Properties are located in Alberta, Canada unless otherwise noted.
</FN>
</TABLE>
Estimated Future Net Revenues
- -----------------------------
The following table sets forth Barnwell's "Estimated Future Net Revenues"
from total proved oil, natural gas and condensate reserves and the present value
of Barnwell's "Estimated Future Net Revenues" (discounted at 10%). Estimated
future net revenues for total proved developed reserves are net of estimated
development costs. Net revenues have been calculated using current sales prices
and costs, after deducting all royalties net of the Alberta Royalty Tax Credit,
operating costs, future estimated capital expenditures, and income taxes.
Proved Developed Total
Producing Proved Developed
Reserves Reserves
---------------- ----------------
Year ending September 30,
2000 $ 5,810,000 $ 5,543,000
2001 4,812,000 5,353,000
2002 4,118,000 5,205,000
Thereafter 22,219,000 32,500,000
----------- -----------
$36,959,000 $48,601,000
=========== ===========
Present value (discounted at 10%)
at September 30, 1999 $21,868,000 $28,757,000
=========== ===========
Marketing of Oil and Natural Gas
- --------------------------------
Barnwell sells substantially all of its oil and condensate production
under short-term contracts between itself or the operator of the property and
marketers of oil. The price of oil is freely negotiated between the buyers and
sellers.
Natural gas sold by the Company is generally sold under both long-term and
short-term contracts with prices indexed to market prices. The price of natural
gas and natural gas liquids is freely negotiated between buyers and sellers. In
1999 and 1998, the Company took most of its oil and natural gas "in kind" where
the Company markets the products instead of having the operator of a producing
property market the products on the Company's behalf.
In fiscal 1999, natural gas production from the Dunvegan Unit was
responsible for approximately 44% of the Company's natural gas revenues. In
fiscal 1999, the Company had three individually significant customers that
accounted for 48% of the Company's oil and natural gas revenues. A substantial
portion of Barnwell's Dunvegan natural gas production and natural gas production
from other properties is sold to aggregators and marketers under various
short-term and long-term contracts, with the price of natural gas determined by
negotiations between the aggregators and the final purchasers. In fiscal 1999,
Barnwell delivered significantly larger volumes of natural gas into spot markets
to take advantage of new pipeline access to premium markets.
Governmental Regulation
- -----------------------
The jurisdictions in which the oil and natural gas properties of Barnwell
are located have regulatory provisions relating to permits for the drilling of
wells, the spacing of wells, the prevention of oil and natural gas waste,
allowable rates of production and other matters. The amount of oil and natural
gas produced is subject to control by regulatory agencies in each province and
state that periodically assign allowable rates of production. The Province of
Alberta and Government of Canada also monitor and regulate the volume of natural
gas that may be removed from the province and the conditions of removal.
There is no current government regulation of the price that may be charged
on the sale of Canadian oil or natural gas production. Canadian natural gas
production destined for export is priced by market forces subject to export
contracts meeting certain criteria prescribed by Canada's National Energy Board
and the Government of Canada.
The right to explore for and develop oil and natural gas on lands in
Alberta and Saskatchewan is controlled by the governments of each of those
provinces. Changes in royalties and other terms of provincial leases, permits
and reservations may have a substantial effect on the Company's operations. In
addition to the foregoing, in the future, Barnwell's Canadian operations may be
affected from time to time by political developments in Canada and by Canadian
Federal, provincial and local laws and regulations, such as restrictions on
production and export, oil and natural gas allocation and rationing, price
controls, tax increases, expropriation of property, modification or cancellation
of contract rights, and environmental protection controls. Furthermore,
operations may also be affected by United States import fees and restrictions.
Different royalty rates are imposed by the producing provinces, the
Government of Canada and private interests with respect to the production and
sale of crude oil, natural gas and liquids. In addition, some producing
provinces receive additional revenue through the imposition of taxes on crude
oil and natural gas owned by private interests within the province. Essentially,
provincial royalties are calculated as a percentage of revenue, and vary
depending on production volumes, selling prices and the date of discovery.
Canadian taxpayers are not permitted to deduct royalties, taxes, rentals
and similar levies paid to the Federal or provincial governments in connection
with oil and natural gas production in computing income for purposes of Canadian
Federal income tax. However, they are allowed to deduct a "Resource Allowance"
which is 25% of the taxpayer's "Resource Profits for the Year" (essentially,
income from the production of oil, natural gas or minerals) in computing their
taxable income.
In Alberta, a producer of oil or natural gas is entitled to a credit
against the royalties payable to the Crown by virtue of the Alberta Royalty Tax
Credit ("ARTC") program. The ARTC rate is based on a price-sensitive formula and
varies between 75% at prices below a specified royalty tax credit reference
price decreasing to 25% at prices above a specified royalty tax credit reference
price. The ARTC will be applied to a maximum annual amount of $2,000,000
Canadian dollars of Alberta Crown royalties payable for each producer or
associated group of producers. Crown royalties on production from producing
properties acquired from corporations claiming maximum entitlements to ARTC will
generally not be eligible for ARTC. The rate is established quarterly based on
the average royalty tax credit reference price, as determined by the Alberta
Department of Energy. The royalty tax credit reference price is based on a
weighted average oil and gas price.
The Province of Alberta has stated that changes in the ARTC will be
announced three years in advance. In December 1997, the Government of Alberta
gave notice that they intended to review the ARTC program with changes expected
to be effective prior to 2001. The ARTC program has been in effect in various
forms since 1974 and the Company anticipates that it will be continued in some
form for the foreseeable future. If the ARTC is not continued, it will have a
material adverse effect on the Company.
The resource properties located in the United States are freehold mineral
interests leased under market conditions, subject to extraction and severance
taxes imposed according to state regulations.
Competition
- -----------
The majority of Barnwell's natural gas sales take place in Alberta, Canada
and the remainder is sold in the mid-continental United States, northeastern
United States and the northern California area. Natural gas prices in Alberta
are generally very competitive as there is a significant supply of natural gas.
Northern California prices are also competitive and are influenced by
competition from producers in the southwestern United States (Texas, etc.).
Barnwell's oil and natural gas liquids are sold in Alberta with prices
determined by the world price for oil.
The Company competes in the sale of oil and natural gas on the basis of
price, and on the ability to deliver products. The oil and natural gas industry
is intensely competitive in all phases, including the exploration for new
production and reserves and the acquisition of equipment and labor necessary to
conduct drilling activities. The competition comes from numerous major oil
companies as well as numerous other independent operators. There is also
competition between the oil and natural gas industry and other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers. Barnwell is a minor participant in the industry and
competes in its oil and natural gas activities with many other companies having
far greater financial and other resources.
CONTRACT DRILLING OPERATIONS
----------------------------
Barnwell owns 100% of Water Resources International, Inc. ("WRI"). WRI
drills water and exploratory wells and installs and repairs water pumping
systems in Hawaii. Additionally, in fiscal 1999, the Company started providing
contract labor for the drilling and workovers of geothermal wells; this work is
continuing into fiscal 2000. WRI owns and operates four Spencer-Harris portable
rotary drill rigs ranging in drilling capacity from 3,500 feet to 7,000 feet,
and one IDECO H-35 rotary drill/workover rig. Additionally, WRI owns a two acre
parcel of real estate in an industrial park 11 miles south of Hilo, Hawaii that
is currently held for sale. WRI also leases a three-quarter of an acre
maintenance facility in Honolulu and a one acre maintenance and storage facility
with 2,800 square feet of interior space in Kawaihae, Hawaii, and maintains an
inventory of drilling and pump supplies. As of September 30, 1999, WRI employed
50 drilling, pump and administrative employees, none of whom are union members.
WRI drills water, geothermal and exploratory wells of varying depths in
Hawaii. In fiscal 1999, in addition to drilling water wells and drilling and
plugging geothermal wells, WRI drilled a 10,370 feet deep exploratory
core-sampling well for the Hawaii Scientific Drilling Project, in which an
almost continuous two mile core of the earth's crust was extracted for
scientific research purposes. WRI also installs and repairs water pumps and is
the state of Hawaii's distributor for Floway Pumps and Centrilift Industrial
Mining and Water pumps and equipment. The demand for WRI's services is primarily
dependent upon land development activities in Hawaii. WRI markets its services
to land developers and government agencies, and identifies potential contracts
through public notices, its officers' involvement in community activities and
referrals. Contracts are usually fixed price or day rate contracts and are
negotiated with private entities or obtained through competitive bidding with
private entities or with local, state and Federal agencies. Contract revenues
are not dependent upon the discovery of water, geothermal production zones or
other, similar targets, and contracts are not subject to renegotiation of
profits or termination at the election of the governmental entities involved.
Contracts provide for arbitration in the event of disputes.
The Company's contract drilling subsidiary derived 43%, 42% and 73% of its
contract drilling revenues in fiscal 1999, 1998 and 1997, respectively, pursuant
to State of Hawaii and local county contracts. At September 30, 1999, the
Company had accounts receivable from the State of Hawaii and local county
entities totaling approximately $352,000. Additionally, the Company's contract
drilling segment had receivables from two private entities totaling
approximately $553,000. The Company has lien rights on contracts with the State
of Hawaii and local county entities and with the aforementioned private
entities.
The Company's contract drilling segment currently operates in Hawaii and
is not subject to seasonal fluctuations.
Activity
- --------
In fiscal 1999, WRI started five well drilling contracts and three pump
installation contracts and completed three well drilling contracts and two pump
installation contracts. Two of the three completed well contracts and one of the
two completed pump installation contracts were started in the prior year.
Sixty-three percent (63%) of such well drilling and pump installation jobs,
representing 43% of total contract drilling revenues in fiscal 1999, have been
pursuant to government contracts. Additionally, in fiscal 1999, WRI was involved
in a rather unique Hawaii Scientific Drilling Project. This project took a
continuous core to a depth of 10,370 feet. This is the deepest hole drilled in
Hawaii.
At September 30, 1999, WRI had a backlog of eight well drilling contracts
and five pump installation and repair contracts, four and three of which,
respectively, were in progress as of September 30, 1999.
The dollar amount of the Company's backlog of firm well drilling and pump
installation and repair contracts at December 1, 1999 and 1998 is as follows:
1999 1998
---------- ----------
Well drilling $2,000,000 $1,500,000
Pump installation and repair 300,000 500,000
---------- ----------
$2,300,000 $2,000,000
========== ==========
All but one of the contracts in backlog at December 1, 1999 is expected to
be completed within fiscal year 2000.
Competition
- -----------
WRI utilizes rotary drill rigs which have the capability of drilling wells
faster than cable tool rigs. There are six other drilling contractors in Hawaii
which use cable tool or rotary drill rigs that are capable of drilling wells,
and six other Hawaii contractors who are capable of installing and repairing
vertical turbine and submersible water pumping systems in Hawaii. One drilling
contractor sold its assets and discontinued business in 1999. These contractors
compete actively with WRI for government and private contracts. Pricing is the
Company's major method of competition; reliability of service is also a
significant factor.
In fiscal 1999, one of WRI's two main competitors was sold to a California
drilling company. The Company cannot predict the impact that this will have on
the Hawaii contract drilling market.
The number of available water well drilling jobs has not changed
significantly from the prior year. However, the Company was able to bid
successfully and obtain significant drilling contracts for scientific and
geothermal work. The Company expects competitive pressures within the industry
to remain high as demand for well drilling and pump installation in Hawaii is
not expected to increase significantly in fiscal year 2000.
LAND INVESTMENT OPERATIONS
--------------------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii joint venture. Between 1986 and 1989, Kaupulehu Developments obtained the
state and county zoning changes necessary to permit development of the Four
Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club, a planned
second golf course, and single and multiple family residential units on land
acquired from Kaupulehu Developments. Kaupulehu Developments currently owns
development rights in approximately 100 acres of residentially zoned leasehold
land and leasehold rights in approximately 2,100 acres of land located
approximately six miles north of the Kona International Airport in the North
Kona District of the Island of Hawaii.
Kaupulehu Developments' residential development rights in the
approximately 100 acres are under option to Hualalai Development Company, an
affiliate of Kajima Corporation of Japan. If Hualalai Development Company
exercises this option, Kaupulehu Developments will receive a total of
$32,250,000. The option expires on January 3, 2000 unless Kaupulehu Developments
receives $6,750,000 of the total consideration on or before January 3, 2000; on
April 30, 2003 unless 50% of the then remaining consideration is received on or
before April 30, 2003; and the remainder of the option would then expire on
April 30, 2007. If the option is partially exercised on or before January 3,
2000 for the required minimum consideration, the Company expects to receive
approximately $3,000,000 in fiscal 2000 in connection with its 50.1% interest in
Kaupulehu Developments in the way of loan repayments and cash distributions.
There is no assurance that this option or any portion of it will be exercised.
Kaupulehu Developments also holds leasehold rights in approximately 2,100
acres of land located adjacent to and north of the Four Seasons Resort Hualalai
at Historic Ka'upulehu. Kaupulehu Developments is in the process of negotiating
a revised development agreement and residential fee purchase prices with the
lessor of the 2,100 acre parcel. Management cannot predict the outcome of these
negotiations.
In June 1996, the State Land Use Commission ("LUC") approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of the
2,100 acres of land into the Urban District for resort/residential development.
Subsequent to the LUC's approval, a notice of appeal was filed with the Third
Circuit Court of the State of Hawaii by parties seeking to reverse the LUC's
decision. The Third Circuit Court of the State of Hawaii upheld the Land Use
Commission's approval of Kaupulehu Developments' rezoning request in all
respects in a Decision and Order issued in August 1997. In November 1997, a
notice of appeal was filed with the Supreme Court of the State of Hawaii by
parties seeking to reverse the Third Circuit Court's decision. The Company
anticipates that the Supreme Court of the State of Hawaii will rule on the
appeal in 2000; management cannot predict the outcome of the appeal.
If the Supreme Court of the State of Hawaii vacates the LUC's approval,
and if the Company is subsequently unable to obtain the LUC's approval after
making additional efforts with the modifications it believes are necessary to
obtain the approval, there will be a materially adverse impairment of the value
of the Company's leasehold rights.
Activity
- --------
In June 1998, Kaupulehu Developments filed an Application for a Project
District zoning ordinance and a Special Management Area ("SMA") Use Permit
Petition with the County of Hawaii, requesting changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential, resort and
commercial development. Both the County zoning ordinance and the SMA Use Permit
are required for development of the property. In December 1998, following a
contested case hearing conducted in November, the Planning Commission of the
County of Hawaii granted the requested SMA Use Permit to Kaupulehu Developments
to be effective when the zoning ordinance is adopted. Subsequent to the Planning
Commission's approval, in January 1999, a notice of appeal was filed with the
Third Circuit Court of the State of Hawaii by parties seeking to reverse the
Planning Commission's approval of the SMA use permit. In April 1999, the County
of Hawaii adopted an ordinance granting approval of Kaupulehu Developments'
Application for a Project District zoning ordinance, which requested changes in
zoning and use of the aforementioned 1,000 acres of land to allow residential,
resort and commercial development. The Company believes the Third Circuit Court
of the County of Hawaii will remand the SMA Use Permit back to the County of
Hawaii Planning Commission for the further review due to procedural issues. The
County of Hawaii Planning Commission has scheduled a hearing on Kaupulehu
Developments' application for the SMA Use Permit for late December 1999.
Management cannot predict the outcome of the County of Hawaii Planning
Commission's review and there is no assurance that an approval will be
forthcoming at any time.
If the County of Hawaii Planning Commission does not grant the SMA use
permit, and if the Company is subsequently unable to obtain the County of Hawaii
Planning Commission's approval of the SMA Use Permit after making additional
efforts with the modifications it believes are necessary to obtain the approval,
there will be a materially adverse impairment of the value of the Company's
leasehold rights.
Competition
- -----------
The Company's land investment segment is subject to intense competition in
all phases of its operations including the acquisition of new properties, the
securing of approvals necessary for land rezoning, and the search for potential
buyers of property interests presently owned. The competition comes from
numerous independent land development companies and other industries involved in
land investment activities. The principal methods of competition are the
location of the project and pricing. Kaupulehu Developments is a minor
participant in the land development industry and competes in its land investment
activities with many other entities having far greater financial and other
resources.
For the past several years, Hawaii's economy has experienced little or no
growth and the real estate market has been slow. However, the South Kohala/North
Kona area of the island of Hawaii, the area in which Kaupulehu Developments'
property is located, has experienced strong demand in recent years. This trend
continued through fiscal 1999 and is not expected to decline significantly in
the near term, although there can be no assurance this trend will in fact
continue.
Item 3. Legal Proceedings
-----------------
In June 1996, the State Land Use Commission approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of land
into the Urban District for resort/residential development. Subsequent to the
Land Use Commission's approval, a notice of appeal was filed in the Third
Circuit Court of the State of Hawaii by Ka Lahui Hawai'i, Kona Hawaiian Civic
Club, Protect Kohanaiki Ohana and Plan to Protect (collectively, the
"Appellants") against the Land Use Commission, State of Hawaii; Office of State
Planning, State of Hawaii; County of Hawaii Planning Department; and Kaupulehu
Developments seeking to reverse the Land Use Commission's decision. The Third
Circuit Court of the State of Hawaii upheld the Land Use Commission's approval
of Kaupulehu Developments' rezoning request in all respects in a Decision and
Order issued in August 1997. In November 1997, the Appellants filed a notice of
appeal in the Supreme Court of the State of Hawaii seeking to reverse the Third
Circuit Court's decision. The Company anticipates that the Supreme Court of the
State of Hawaii will rule on the appeal in 2000 and management cannot predict
the outcome of such appeal.
In June 1998, Kaupulehu Developments filed an Application for a Project
District zoning ordinance and a Special Management Area ("SMA") Use Permit
Petition with the County of Hawaii, requesting changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential, resort and
commercial development. Both the County zoning ordinance and the SMA Use Permit
are required for development of the property. In December 1998, following a
contested case hearing conducted in November, the Planning Commission of the
County of Hawaii granted the requested SMA Use Permit to Kaupulehu Developments
to be effective when the zoning ordinance is adopted. Subsequent to the Planning
Commission's approval, in January 1999, a notice of appeal was filed with the
Third Circuit Court of the State of Hawaii by Ka Lahui Hawai'i and Protect
Kohanaiki Ohana seeking to reverse the Planning Commission's approval of the SMA
use permit. In April 1999, the County of Hawaii adopted an ordinance granting
approval of Kaupulehu Developments' Application for a Project District zoning
ordinance, which requested changes in zoning and use of the aforementioned 1,000
acres of land to allow residential, resort and commercial development. The
Company believes the Third Circuit Court of the County of Hawaii will remand the
SMA Use Permit back to the County of Hawaii Planning Commission for further
review due to procedural issues. The County of Hawaii Planning Commission has
scheduled a hearing on Kaupulehu Developments' application for the SMA Use
Permit for late December 1999. Management cannot predict the outcome of the
County of Hawaii Planning Commission's decision and there is no assurance that
an approval will be forthcoming at any time.
If the Supreme Court of the State of Hawaii vacates the LUC's approval,
and if the Company is subsequently unable to obtain the LUC's approval after
making additional efforts with the modifications it believes are necessary to
obtain the approval, there will be a materially adverse impairment of the value
of the Company's leasehold rights. Similarly, if the County of Hawaii Planning
Commission does not grant the SMA use permit, and if the Company is subsequently
unable to obtain the County of Hawaii Planning Commission's approval of the SMA
Use Permit after making additional efforts with the modifications it believes
are necessary to obtain the approval, there will be a materially adverse
impairment of the value of the Company's leasehold rights.
The Company is involved in routine litigation and is subject to
governmental and regulatory controls that are incidental to the business. The
Company's management believes that routine claims and litigation involving the
Company are not likely to have a material adverse effect on its financial
position, results of operations or liquidity.
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
None.
PART II
Item 5. Market For Common Equity and Related Stockholder Matters
--------------------------------------------------------
The principal market on which the Company's common stock is being traded
is the American Stock Exchange. The following tables present the quarterly high
and low closing prices, on the American Stock Exchange, for the registrant's
common stock during the periods indicated:
Quarter Ended High Low Quarter Ended High Low
- ------------- ---- --- ------------- ---- ---
December 31, 1997 20 16-1/4 December 31, 1998 12-7/16 11-1/8
March 31, 1998 17-5/8 16-1/4 March 31, 1999 12-1/8 11
June 30, 1998 16-7/8 14 June 30, 1999 11-3/4 10-7/8
September 30, 1998 14-3/8 12-3/8 September 30, 1999 13-1/4 10-3/8
As of December 3, 1999, there were 1,316,952 shares of common stock, par
value $.50, outstanding. There were approximately 400 holders of the common
stock of the registrant as of December 3, 1999.
In May 1995, quarterly dividend payments were suspended and remain
suspended to date.
Item 6. Management's Discussion and Analysis or Plan of Operation
---------------------------------------------------------
The following section contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended, including various
forecasts, projections of Barnwell's future performance, statements of the
Company's plans and objectives and other similar types of information. Although
the Company believes that its expectations are based on reasonable assumptions,
it cannot assure that the expectations contained in such forward-looking
statements will be achieved. Such statements involve risks, uncertainties and
assumptions, including, but not limited to, those relating to the factors
discussed below, in other portions of this Form 10-KSB, in the Notes to
Consolidated Financial Statements, and in other documents filed by the Company
with the Securities and Exchange Commission from time to time, which could cause
actual results to differ materially from those contained in such statements.
Factors that could cause or contribute to such differences include, but are not
limited to, those discussed under Part I, "Forward-Looking Statements," as well
as those discussed elsewhere in this Form 10-KSB. All forward-looking statements
contained in this Form 10-KSB are qualified in their entirety by this statement
and speak only as of the date of filing of this Form 10-KSB, and the Company
expressly disclaims any obligation or undertaking to publicly release any
updates or revisions to any forward-looking statements contained herein.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Cash flows from operations before changes in current assets and
liabilities increased $1,127,000 (45%) in fiscal 1999, as compared to fiscal
1998, due to increases in operating profit generated by both the Company's oil
and natural gas and contract drilling segments in fiscal 1999, as compared to
fiscal 1998. The increase in the contract drilling segment's operating profit
was due primarily to a substantial increase in revenue from the prior year due
to the Company's obtainment and performance thereunder of a large scientific
drilling and coring project and a geothermal well contract in fiscal 1999. These
jobs were operated seven days a week, 24 hours per day, as opposed to water well
contracts, which are typically operated five days a week, eight hours per day.
As a result, contract drilling revenues increased $2,720,000 (180%) in fiscal
1999, as compared to fiscal 1998. The increase in the oil and gas segment's
operating profit from the prior year, excluding the prior year's non-cash
write-downs, was due primarily to 14% and 8% increases in natural gas and oil
prices, respectively. Cash flows from operations after changes in current assets
and liabilities were $2,725,000 in fiscal 1999, as compared to $2,961,000 in
fiscal 1998, a decrease of $236,000; the decrease was due to the reduction of
over $1,000,000 of accounts payables in fiscal 1999.
The Company's revolving credit facility is with the Royal Bank of Canada
for $19,000,000 Canadian dollars or its U.S. dollar equivalent of approximately
$12,900,000 at September 30, 1999. The facility is reviewed annually with a
primary focus on the future cash flows generated by the Company's oil and
natural gas properties. The next review is planned for February 2000. Subject to
that review, the facility may be extended one year with no required debt
repayments for one year, or converted to a five-year term loan by the bank. If
the facility is converted to a five-year term loan, the Company has agreed to
the following repayment schedule of the then outstanding balance: year 1 - 30%;
year 2 - 27%; year 3 - 16%; year 4 - 14%; year 5 - 13%. The facility is
collateralized by the Company's interests in its major oil and natural gas
properties and a negative pledge on its remaining oil and natural gas
properties. No compensating bank balances are required on any of the Company's
indebtedness under the facility.
The Canadian bank has represented that it will not require any repayments
under the facility before September 30, 2000. Accordingly, the Company has
classified outstanding borrowings under the facility as long-term debt.
The Company believes its current cash balances, future cash flows from
operations, capability to provide additional collateral, and available credit
will be sufficient to fund its estimated capital expenditures, make the
scheduled repayments on its convertible notes and land investment borrowings,
and meet the repayment schedule on its Royal Bank of Canada facility, should the
Company or the Royal Bank of Canada elect to convert the facility to a term
loan.
The Company has $1,600,000 of convertible notes outstanding at September
30, 1999 that are payable in 16 consecutive, equal quarterly installments.
Interest is payable quarterly at a rate to be adjusted each quarter to the
greater of 10% per annum or 1% over the prime rate of interest. The Company paid
interest on these notes at the rate of 10% per annum throughout fiscal 1999.
Additionally, Kaupulehu Developments, a 50.1%-owned joint venture, has a
$1,500,000 credit facility with a Hawaii bank to finance the land investment
segment's rezoning expenditures. Total available credit and outstanding
borrowings under the land investment facility at September 30, 1999 amounted to
$250,000 and $1,250,000, respectively. For more information on the Company's
credit facilities, see Note 5 of "Notes to the Consolidated Financial
Statements" in Item 7.
At September 30, 1999, the Company's consolidated cash and cash
equivalents amounted to $2,577,000 and available credit under the Royal Bank of
Canada's revolving credit facility was approximately $1,469,000. The Company has
a $960,000 deficit in working capital due partially to the classification of the
$1,250,000 of outstanding borrowings under the land investment facility as
current portion of long-term debt as it is due March 31, 2000. Management
anticipates that the repayment of this note will be funded by the receipt of
monies from the exercise of a portion of the option held on Kaupulehu
Developments' land position in early fiscal 2000. Nevertheless, if no option
proceeds are received, the Company's current cash position and available credit,
as well as future cash flows from operations and potential cash flows from land
sales, will enable the Company to repay the debt.
The following table sets forth the Company's capital expenditures for each
of the last three fiscal years:
1999 1998 1997
-------- -------- ---------
Oil and natural gas - Canada $ 1,753,000 $ 6,009,000 $ 4,727,000
Oil and natural gas - U.S. - 960,000 1,750,000
----------- ----------- -----------
Total oil and natural gas 1,753,000 6,969,000 6,477,000
Land investment 809,000 862,000 733,000
Contract drilling 121,000 91,000 189,000
Other 148,000 205,000 97,000
----------- ----------- -----------
Total capital expenditures $ 2,831,000 $ 8,127,000 $ 7,496,000
=========== =========== ===========
Increase (decrease) in total
oil and natural gas capital
expenditures from prior year $(5,216,000) $ 492,000 $ 1,428,000
=========== =========== ===========
The Company's oil and natural gas capital expenditures in fiscal 1999
totaled $1,753,000. The Company participated in drilling 15 wells, 13 of which
were successful, and the recompletion of 15 wells. Capital expenditures were
reduced in 1999 as the Company responded to poor commodity price levels for the
first half of fiscal 1999 by reducing its capital expense budget and as there
were no capital expenditures in the U.S. in fiscal 1999.
The following table sets forth the gross number of oil and natural gas
wells the Company participated in drilling and purchased for each of the last
three fiscal years:
1999 1998 1997
-------- -------- --------
Development oil and natural
gas wells drilled 13 50 55
Exploratory oil and natural
gas wells drilled 2 9 17
Successful oil and natural
wells drilled and purchased 13 45 53
Additionally, in 1999 the Company has built a technical team to internally
generate oil and gas exploration projects. The team is initially focusing on an
area encompassing Southeast and Central Alberta.
As a result, the Company has increased its oil and natural gas capital
expenditures budget for fiscal 2000, as compared to the level of capital
expenditures for fiscal 1999. The Company's current estimate of fiscal 2000
capital expenditures is $3,000,000. This number may increase or decrease as
dictated by management's assessment of the oil and gas environment and
prospects.
In fiscal 1999, $809,000 of the Company's capital expenditures were
applicable to the rezoning of leasehold land in North Kona, Hawaii, from
conservation to urban, as compared to $862,000 in fiscal 1998. These
expenditures were comprised of legal, consulting and planning fees incurred to
process Kaupulehu Developments' applications through the entitlement and
judiciary processes, as well as capitalized interest. They were funded through
borrowings under Kaupulehu Developments' $1,500,000 land rezoning credit
facility; available credit under the facility was $250,000 at September 30,
1999.
The Company did not receive any revenues in fiscal 1999, 1998, and 1997
related to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments'
revenues specifically relate to sales of leasehold interests and development
rights, which do not occur every year. Kaupulehu Developments' residential
development rights in the approximately 100 acres are currently under option to
Hualalai Development Company, an affiliate of Kajima Corporation of Japan. If
Hualalai Development Company fully exercises this option, Kaupulehu Developments
will receive a total of $32,250,000. The option expires on January 3, 2000,
unless Kaupulehu Developments receives $6,750,000 of the total consideration on
or before January 3, 2000; on April 30, 2003 unless 50% of the then remaining
consideration is received on or before April 30, 2003; and the remainder of the
option would then expire on April 30, 2007. If the option is partially exercised
on or before January 3, 2000 for the required minimum consideration, the Company
expects to receive approximately $3,000,000 in pre-tax cash flow in fiscal 2000
in connection with its 50.1% interest in Kaupulehu Developments in the way of
loan repayments and cash distributions. There is no assurance that this option
or any portion of it will be exercised.
In fiscal 1999, the Company spent $121,000 in capital expenditures
applicable to contract drilling activities, as compared to $91,000 in fiscal
1998. These capital expenditures were funded by cash flows generated by contract
drilling operations.
YEAR 2000 COMPLIANCE
- --------------------
The Company's administrative and accounting computer systems have been
upgraded to systems that are represented to be Year 2000 compliant by respective
vendors. Analysis of embedded technology issues, including, but not limited to,
such items as microprocessors in petroleum and water pump controls, and
potential impacts relating to third parties with which the Company has a
material relationship is ongoing and to date has not brought to light evidence
of potential negative impacts. Expenditures related to Year 2000 compliance in
fiscal years 1999, 1998 and 1997 were not significant and were expensed as
incurred.
No amount of preparation and testing can guarantee Year 2000 compliance.
Accordingly, the Company has developed contingency plans to overcome the most
reasonably likely worst case scenarios which may result from failure by the
Company or third parties to complete their Year 2000 initiatives on a timely
basis. The Company's contingency plans include using alternative processes, such
as manual procedures or work-around applications to substitute for non-compliant
systems; arranging for alternate marketers, operators, and suppliers and service
providers; and developing procedures internally and in collaboration with
significant third parties to address compliance issues as they arise. There is
particular difficulty in the assessment of Year 2000 compliance of third
parties. Accordingly, the Company considers the potential disruptions caused by
such parties to present the most reasonably likely worst case scenarios. Adverse
effects on the Company could include business disruption, increased costs,
delays of sales and other similar ramifications.
The Company's state of readiness and the impact of any Year 2000 issues
are estimates and subject to change. Actual results could differ from those
currently anticipated. Factors that could cause such differences include, but
are not limited to, the availability of key Year 2000 project personnel, the
accuracy of system vendors' represented specifications, the Company's ability to
respond to unforeseen Year 2000 complications, the readiness of third parties,
the accuracy of third party assurances regarding Year 2000 compliance and
similar uncertainties.
RESULTS OF OPERATIONS
- ---------------------
Summary
-------
Barnwell reported net earnings of $520,000 in fiscal 1999, an increase of
$4,410,000 over fiscal 1998, due to significant increases in operating profit
generated by both its oil and natural gas and contract drilling segments, and to
the absence of write-downs in fiscal 1999. Operating profits generated by the
Company's contract drilling segment increased $1,292,000 from an operating loss
of $550,000 in fiscal 1998 to an operating profit of $742,000 in fiscal 1999,
due primarily to an increased number of drilling contracts and due to the fact
the scientific coring and geothermal well contracts performed in fiscal 1999
were operated on a 24 hour basis; the prior years' revenues were generated by
water well contracts which typically operate during daylight only. Operating
profit generated by the Company's oil and gas segment, excluding the 1998
non-cash write-downs, increased $709,000 from $3,479,000 in fiscal 1998 to
$4,188,000 in fiscal 1999 due primarily to 14% and 8% increases in natural gas
and oil prices, respectively.
Barnwell reported a net loss of $3,890,000 in fiscal 1998, principally due
to non-cash write-downs of $2,995,000. Due to unsuccessful drilling results in
the Michigan Basin prospect, the Company and its joint venture partners
discontinued development of the prospect. Accordingly, the Company wrote off its
entire investment in the prospect, including additional costs for estimated site
restoration and abandonment. This write-off totaled $1,600,000. In addition, due
to unfavorable drilling results and a significant decline in oil prices, the
Company abandoned its remaining U.S. oil and gas prospects during fiscal 1998
and recorded a write-off of such properties of $1,130,000. The Company also
wrote down available-for-sale investment securities amounting to $95,000 and
contract drilling land and land improvements held for sale amounting to $170,000
as a result of declines in the market values of these assets. The aforementioned
write-downs, coupled with decreases of 33%, 35% and 5% in oil, liquids and
natural gas prices, respectively, and negative contract drilling margins,
resulted in the net loss for the Company of $3,890,000 in fiscal 1998, a
decrease of $4,940,000 from net earnings of $1,050,000 in fiscal 1997.
Oil and Natural Gas Revenues
- ----------------------------
Selected Operating Statistics
The following tables set forth the Company's annual net production and
annual average price per unit of production for fiscal 1999 as compared to
fiscal 1998, and fiscal 1998 as compared to fiscal 1997.
Fiscal 1999 - Fiscal 1998
- -------------------------
Annual Net Production
-------------------------------------------------------
Increase
(Decrease)
--------------------------
1999 1998 Units %
----------- ----------- ----------- ------------
Liquids (Bbl)* 73,000 65,000 8,000 12%
Oil (Bbl)* 192,000 210,000 (18,000) (9%)
Natural gas (MCF)** 3,295,000 3,684,000 (389,000) (11%)
Annual Average Price Per Unit
-------------------------------------------------------
Increase
(Decrease)
--------------------------
1999 1998 $ %
----------- ----------- ----------- ------------
Liquids (Bbl)* $ 9.78 $11.36 $(1.58) (14%)
Oil (Bbl)* $14.08 $13.02 $ 1.06 8%
Natural gas (MCF)** $ 1.57 $ 1.38 $ 0.19 14%
Fiscal 1998 - Fiscal 1997
- -------------------------
Annual Net Production
-------------------------------------------------------
Increase
(Decrease)
--------------------------
1998 1997 Units %
----------- ----------- ----------- ------------
Liquids (Bbl)* 65,000 65,000 - -
Oil (Bbl)* 210,000 199,000 11,000 6%
Natural gas (MCF)** 3,684,000 3,852,000 (168,000) (4%)
Annual Average Price Per Unit
-------------------------------------------------------
Increase
(Decrease)
--------------------------
1998 1997 $ %
----------- ----------- ----------- ------------
Liquids (Bbl)* $11.36 $17.55 $(6.19) (35%)
Oil (Bbl)* $13.02 $19.55 $(6.53) (33%)
Natural gas (MCF)** $ 1.38 $ 1.45 $(0.07) (5%)
*Bbl = stock tank barrel equivalent to 42 U.S. gallons
**MCF = 1,000 cubic feet
Oil and natural gas revenues increased $730,000 or 8% in fiscal 1999 to
$10,130,000, as compared to $9,400,000 in fiscal 1998, due to 14% and 8%
increases in the average price received for natural gas and oil, respectively,
and a 12% increase in natural gas liquids volumes. The increase was partially
offset by decreases in natural gas and oil volumes of 11% and 9%, respectively,
and a 14% decrease in natural gas liquids prices. The decrease in natural gas
and oil production was due to projected production declines at the Company's
principal natural gas and oil properties.
The Company participated in the construction of a deep cut gas plant at
Dunvegan in fiscal 1998, which enhances the separation of lighter end natural
gas liquids from natural gas. This gas plant commenced operations in November
1998, and as a result, natural gas liquid production increased in fiscal 1999.
These liquids were of a lower energy value than that of the average natural gas
liquids produced by the Company in fiscal 1998, resulting in a lower average
price for natural gas liquids in fiscal 1999. The separation of the natural gas
liquids from the natural gas results in natural gas with a lower energy content,
which in turn results in a lower natural gas price. As such, while the new deep
cut plant has resulted in higher revenues from the sale of natural gas liquids,
the Company has experienced a decrease, although a smaller one, in revenues from
the sale of natural gas.
In late December 1998 the Northern Border natural gas pipeline,
transporting natural gas from Alberta to Chicago, commenced operations. This new
pipeline, which is capable of delivering over 700 million cubic feet of natural
gas per day, has had a significant positive impact on the natural gas price
received by Alberta producers. The pipeline has increased accessibility to U.S.
markets and reduced the amount of natural gas available for the intra Alberta
market. As a result, Alberta spot natural gas prices have increased and the
basis differential between NYMEX and Alberta natural gas prices has decreased
significantly. The Company has directed substantially more of its gas volumes to
the Alberta spot market.
Oil and natural gas revenues decreased $2,120,000 or 18% in fiscal 1998 to
$9,400,000, as compared to $11,520,000 in fiscal 1997, due to significant
decreases in the average price received for oil and natural gas liquids, and a
5% decrease in average gas prices received. In addition, gas volumes decreased
slightly, 4%, as compared to fiscal 1997. This production decline was the result
of normal production declines at the Company's mature properties exceeding new
production coming on line. The decreases were partially offset by a 6% increase
in oil volumes brought about by new oil wells.
Oil and Natural Gas Operating Expenses
- --------------------------------------
Operating expenses were relatively unchanged from fiscal 1997 through
fiscal 1999. Operating expenses increased $145,000 (4%) in fiscal 1999 to
$3,368,000, as compared to $3,223,000 in fiscal 1998, and decreased $103,000
(3%) in fiscal 1998 to $3,223,000, as compared to $3,326,000 in fiscal 1997.
Contract Drilling
- -----------------
Contract drilling revenues and costs are associated with water well,
geothermal well and exploratory well drilling, and water pump installation,
replacement and repair in Hawaii. The Company has benefited in fiscal 1999 from
the availability and successful bidding of geothermal and exploratory well work.
The number of available water well drilling jobs has not changed significantly
from the prior year and competition for such jobs remains high. The Company
anticipates that contract drilling revenues in fiscal 2000 will decrease
approximately $900,000 from fiscal 1999 revenues.
Contract drilling revenues increased $2,720,000 (180%) to $4,230,000 in
fiscal 1999, as compared to $1,510,000 in fiscal 1998, and contract drilling
operating expenses increased $1,556,000 (85%) to $3,378,000 in fiscal 1999, as
compared to $1,822,000 in fiscal 1998, due primarily to the Company's obtainment
and performance thereunder of contracts for the Hawaii Scientific Drilling
Project and a geothermal well. These jobs were operated seven days a week, 24
hours per day, as opposed to water well contracts, which are typically operated
five days a week, eight hours per day. As a result of the significant increase
in activity, operating profit before depreciation increased to $852,000 for
fiscal 1999, as compared to an operating loss before depreciation of $482,000 in
fiscal 1998.
At September 30, 1999 the Company had a backlog of five pump installation
and repair contracts and eight well drilling contracts. Three pump installation
contracts and four well drilling contracts were in progress as of September 30,
1999. These thirteen contracts represent a backlog of contract drilling revenues
of approximately $2,300,000 as of December 1, 1999.
Contract drilling revenues decreased $650,000 (30%) in fiscal 1998 to
$1,510,000, as compared to $2,160,000 in fiscal 1997, due primarily to lower
demand for both water well drilling work and pump installation and to increased
competition for these fewer jobs. The increase in competition has driven
contract bid prices down, resulting in lower revenues and contract margins.
Contract drilling operating costs remained fairly constant (decreased $28,000 or
2% from $1,850,000 in fiscal 1997 to $1,822,000 in fiscal 1998). As a result of
the decrease in contract prices, contract drilling operating results before
depreciation decreased to a loss of $482,000 in fiscal 1998, as compared to an
operating profit before depreciation of $310,000 in fiscal 1997. Included in
fiscal 1998's operating results is a $170,000 write-down of a contract drilling
yard held for sale.
Gas Processing and Other Income
- -------------------------------
Gas processing and other income decreased $210,000 (21%) in fiscal 1999 to
$800,000, as compared to $1,010,000 in fiscal 1998, due primarily to a decrease
in the amount of gas processed by the Company's interest in the Stolberg
pipeline.
Gas processing and other income decreased $140,000 (12%) in fiscal 1998 to
$1,010,000, as compared to $1,150,000 in fiscal 1997, due to a decrease in
interest income as a result of lower average cash balances.
General and Administrative Expenses
- -----------------------------------
General and administrative expenses remained relatively constant from
fiscal 1997 through fiscal 1999. General and administrative expenses decreased
$105,000 (3%) in fiscal 1999 to $3,187,000, as compared to $3,292,000 in fiscal
1998 and increased $84,000 (3%) in fiscal 1998 to $3,292,000, as compared to
$3,208,000 in fiscal 1997.
Depreciation, Depletion and Amortization
- ----------------------------------------
Depreciation, depletion and amortization expense decreased $78,000 (3%) to
$2,820,000 in fiscal 1999, as compared to $2,898,000 in fiscal 1998, due
primarily a decline in production volumes, partially offset by a 4% increase in
the depletion rate per MCF equivalent and a $42,000 increase in contract
drilling depreciation. The higher depletion rate is the result of increased cost
of finding and developing proven reserves. The increase in contract drilling
depreciation is attributable to the addition of equipment as a result of the
increase in contract drilling activity.
Depreciation, depletion and amortization expense increased $124,000 (4%)
to $2,898,000 in fiscal 1998, as compared to $2,774,000 in fiscal 1997, due to
an 11% increase in the depletion rate per MCF equivalent, partially offset by a
decline in production volumes. The higher depletion rate is the result of
increased cost of finding and developing proven reserves. The increase in
depletion was also partially offset by decreased depreciation expense resulting
from certain water well drilling assets becoming fully depreciated in fiscal
1997.
Interest Expense
- ----------------
Interest expense increased $87,000 (12%) in fiscal 1999 to $809,000, as
compared to $722,000 in fiscal 1998, due to higher average loan balances. The
weighted average balance of the outstanding borrowings from the Royal Bank of
Canada increased from approximately $10,300,000 in fiscal 1998 to approximately
$11,700,000 in fiscal 1999 as borrowings made in the latter half of fiscal 1998
were outstanding for ostensibly all of fiscal 1999. Partially offsetting the
increase were lower average interest rates. The average interest rate incurred
during fiscal 1999 on the Company's borrowings from the Royal Bank of Canada
decreased to 6.18% as compared to 6.67% in fiscal 1998, and the average interest
rate on Kaupulehu Developments' borrowings was 9.40% in fiscal 1999 as compared
to 10.00% in fiscal 1998. The interest rate on the convertible notes in fiscal
1999 was unchanged at 10.00% per annum.
Interest expense increased $98,000 (16%) in fiscal 1998 to $722,000, as
compared to $624,000 in fiscal 1997, due primarily to higher average loan
balances and interest rates. The average interest rate incurred during fiscal
1998 on the Company's $11,665,000 of debt with the Royal Bank of Canada
increased to 6.67% as compared to 6.35% in fiscal 1997, the interest rate on the
$2,000,000 of convertible notes in fiscal 1998 was unchanged at 10.00% per
annum, and the average interest rate on Kaupulehu Developments' $365,000 of
borrowings was 10.00% in fiscal 1998.
Write-down of Oil and Natural Gas Properties and Other Assets
- -------------------------------------------------------------
Under the full cost method of accounting, the amount of oil and natural
gas properties' capitalized costs less accumulated depletion (on a country by
country basis) is subject to a ceiling test limitation that requires any excess
of such costs over the present value of estimated future cash flows from proved
reserves to be expensed. As of March 31, 1998, the Company's investment in the
Michigan Basin prospect was determined to be impaired and was transferred to the
amortization base. Upon transfer, capitalized oil and natural gas properties'
costs in the United States exceeded the full cost ceiling test limitation and,
accordingly, the Company recorded a non-cash write-down of $2,070,000 in the
quarter ended March 31, 1998. Due to further declines in oil prices and
disappointing seismic and drilling results in North Dakota, the Company
abandoned its U.S. oil and natural gas prospects and recorded an additional U.S.
ceiling test write-down of $660,000 during the quarter ended June 30, 1998 to
fully write-off its investment in U.S. oil and natural gas properties.
In fiscal 1998, the Company also wrote down $170,000 of land and land
improvement costs related to a contract drilling yard held for sale due to a
decline in the market value of the property, and $95,000 of available-for-sale
securities due to a decline in market value deemed other than temporary.
In fiscal 1997, the Company recorded a U.S. oil and natural gas properties
ceiling test write-down of $270,000. This write-down was largely related to
activities in North Dakota where one dry well was drilled, a producing oil well
watered out and the independent engineer revised downward the estimate of
reserves in the remaining North Dakota wells. Additionally, the disappointing
results from the initial drilling program in the Michigan Basin prospect (eight
wells were drilled, one of which was commercial), and a dry hole in Louisiana
contributed to the write-down.
Foreign Currency Fluctuations
- -----------------------------
The Company conducts foreign operations in Canada. Consequently, the
Company is subject to foreign currency transaction gains and losses due to
fluctuations of the exchange rates between the Canadian dollar and the U.S.
dollar. Foreign currency transaction gains and losses were not material in
fiscal 1999, 1998 and 1997. The Company cannot accurately predict future
fluctuations between the Canadian and U.S. dollars.
Taxes
- -----
In fiscal 1999, 1998, and 1997, the provision for income taxes does not
bear a normal relationship to earnings because Canadian taxes were payable on
the Canadian operations and losses from U.S. operations provide no foreign tax
benefits.
Environmental Matters
- ---------------------
Federal, state, and Canadian governmental agencies issue rules and
regulations and enforce laws to protect the environment which are often
difficult and costly to comply with and which carry substantial penalties for
failure to comply, particularly in regard to the discharge of materials into the
environment. The regulatory burden on the oil and gas industry increases its
cost of doing business. These laws, rules and regulations affect the operations
of the Company and could have a material adverse effect upon the capital
expenditures, earnings or competitive position of the Company. Although
Barnwell's experience has been to the contrary, there is no assurance that this
will continue to be the case.
Inflation
- ---------
The effect of inflation on the Company has generally been to increase its
cost of operations, interest cost (as a substantial portion of the Company's
debt is at variable short-term rates of interest which tend to increase as
inflation increases), general and administrative costs and direct costs
associated with oil and natural gas production and contract drilling operations.
In the case of contract drilling, the Company has not been able to increase its
contract revenues to fully compensate for increased costs. In the case of oil
and natural gas, prices realized by the Company are essentially determined by
world prices for oil and western Canadian/California/Midwestern U.S. prices for
natural gas.
Future Accounting Changes
- -------------------------
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which establishes accounting and reporting
standards for derivative instruments and hedging activities and requires that an
entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value. The
provisions of SFAS No. 133 are effective for all fiscal quarters of fiscal years
beginning after June 15, 1999. In July 1999, the FASB issued SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities Deferral of the
Effective Date of FASB Statement No. 133, an Amendment of FASB Statement No.
133," which defers the effective date of SFAS No. 133 to be effective for all
fiscal quarters of fiscal years beginning after June 15, 2000. Management does
not expect adoption of SFAS No. 133 will have a material effect on the Company's
financial condition, results of operations or liquidity.
Item 7. FINANCIAL STATEMENTS
--------------------
Independent Auditors' Report
----------------------------
The Board of Directors
Barnwell Industries, Inc.:
We have audited the consolidated balance sheets of Barnwell Industries, Inc. and
subsidiaries as of September 30, 1999 and 1998, and the related consolidated
statements of operations, stockholders' equity and comprehensive income (loss),
and cash flows for each of the years in the three-year period ended September
30, 1999. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Barnwell Industries,
Inc. and subsidiaries as of September 30, 1999 and 1998, and the results of
their operations and their cash flows for each of the years in the three-year
period ended September 30, 1999, in conformity with generally accepted
accounting principles.
/s/ KPMG LLP
Honolulu, Hawaii
December 3, 1999
<TABLE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<CAPTION>
ASSETS September 30,
----------------------------
CURRENT ASSETS: 1999 1998
<S> <C> <C>
----------- -----------
Cash and cash equivalents $ 2,577,000 $ 2,178,000
Accounts receivable, net (Notes 3 and 13) 1,873,000 1,593,000
Royalty tax credit and taxes receivable 261,000 350,000
Costs and estimated earnings in excess of
billings on uncompleted contracts (Note 3) 172,000 112,000
Deferred income taxes (Note 6) 130,000 130,000
Prepaid royalties, inventories and other 584,000 263,000
----------- -----------
TOTAL CURRENT ASSETS 5,597,000 4,626,000
----------- -----------
INVESTMENT IN LAND (Notes 4 and 5) 3,519,000 2,710,000
----------- -----------
OTHER ASSETS 207,000 213,000
----------- -----------
PROPERTY AND EQUIPMENT (Notes 5 and 10):
Land 465,000 478,000
Oil and natural gas properties (full cost accounting):
Properties being amortized 48,934,000 44,842,000
Properties not subject to amortization - 628,000
Drilling rigs and equipment 8,043,000 7,934,000
Other property and equipment 2,539,000 2,335,000
----------- -----------
59,981,000 56,217,000
Accumulated depreciation, depletion and amortization 36,009,000 32,105,000
----------- -----------
TOTAL PROPERTY AND EQUIPMENT 23,972,000 24,112,000
----------- -----------
TOTAL ASSETS $33,295,000 $31,661,000
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable $ 1,894,000 $ 2,836,000
Accrued expenses 1,975,000 1,963,000
Billings in excess of costs and estimated
earnings on uncompleted contracts (Note 3) 139,000 201,000
Payable to joint interest owners 648,000 250,000
Current portion of long-term debt (Note 5) 1,650,000 400,000
Income taxes payable (Note 6) 251,000 -
----------- -----------
TOTAL CURRENT LIABILITIES 6,557,000 5,650,000
----------- -----------
LONG-TERM DEBT (Note 5) 12,631,000 13,630,000
----------- -----------
DEFERRED INCOME TAXES (Note 6) 6,301,000 5,637,000
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 7, 8 and 9)
STOCKHOLDERS' EQUITY (Notes 5 and 8):
Common stock, par value $.50 per share:
Authorized, 4,000,000 shares
Issued, 1,642,797 shares 821,000 821,000
Additional paid-in capital 3,103,000 3,103,000
Retained earnings 11,801,000 11,281,000
Accumulated other comprehensive loss -
foreign currency translation adjustments (3,130,000) (3,672,000)
Treasury stock, at cost, 325,845 shares (4,789,000) (4,789,000)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY 7,806,000 6,744,000
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $33,295,000 $31,661,000
=========== ===========
<FN>
See Notes to Consolidated Financial Statements
</FN>
</TABLE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended September 30,
-------------------------------------
1999 1998 1997
----------- ----------- -----------
Revenues:
Oil and natural gas $10,130,000 $ 9,400,000 $11,520,000
Contract drilling 4,230,000 1,510,000 2,160,000
Gas processing and other 800,000 1,010,000 1,150,000
----------- ----------- -----------
15,160,000 11,920,000 14,830,000
----------- ----------- -----------
Costs and expenses:
Oil and natural gas operating 3,368,000 3,223,000 3,326,000
Contract drilling operating 3,378,000 1,822,000 1,850,000
General and administrative 3,187,000 3,292,000 3,208,000
Depreciation, depletion
and amortization 2,820,000 2,898,000 2,774,000
Interest expense, net (Note 5) 809,000 722,000 624,000
Write-down of oil and natural gas
properties and other assets (Note 10) - 2,995,000 270,000
----------- ----------- -----------
13,562,000 14,952,000 12,052,000
----------- ----------- -----------
Earnings (loss) before income taxes 1,598,000 (3,032,000) 2,778,000
Provision for income taxes (Note 6) 1,078,000 858,000 1,728,000
----------- ----------- -----------
NET EARNINGS (LOSS) $ 520,000 $(3,890,000) $ 1,050,000
=========== =========== ===========
BASIC AND DILUTED
NET EARNINGS (LOSS) PER SHARE $0.39 $(2.95) $0.79
=========== =========== ===========
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING
BASIC 1,316,952 1,319,719 1,322,052
=========== =========== ===========
DILUTED 1,316,952 1,319,719 1,325,963
=========== =========== ===========
See Notes to Consolidated Financial Statements
<TABLE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Year ended September 30,
----------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 520,000 $(3,890,000) $ 1,050,000
Adjustments to reconcile net earnings (loss)
to net cash provided by operating activities:
Depreciation, depletion and amortization 2,820,000 2,898,000 2,774,000
Deferred income taxes 314,000 524,000 886,000
Write-down of assets - 2,995,000 270,000
----------- ----------- -----------
3,654,000 2,527,000 4,980,000
(Decrease) increase from changes in
current assets and liabilities (Note 14) (929,000) 434,000 2,469,000
------------ ----------- -----------
Net cash provided by operating activities 2,725,000 2,961,000 7,449,000
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (2,831,000) (8,127,000) (7,496,000)
Decrease (increase) in other assets 6,000 8,000 (17,000)
Proceeds from sale of property and equipment 309,000 93,000 977,000
----------- ----------- -----------
Net cash used in investing activities (2,516,000) (8,026,000) (6,536,000)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt borrowings 885,000 3,067,000 -
Repayments of long-term debt (739,000) - -
Purchases of common stock for treasury - (84,000) -
----------- ----------- -----------
Net cash provided by financing activities 146,000 2,983,000 -
----------- ----------- -----------
Effect of exchange rate changes
on cash and cash equivalents 44,000 (142,000) (64,000)
----------- ----------- -----------
Net increase (decrease) in
cash and cash equivalents 399,000 (2,224,000) 849,000
Cash and cash equivalents at beginning of year 2,178,000 4,402,000 3,553,000
----------- ----------- -----------
Cash and cash equivalents at end of year $ 2,577,000 $ 2,178,000 $ 4,402,000
=========== =========== ===========
<FN>
See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<TABLE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
Years ended September 30, 1999, 1998, and 1997
<CAPTION>
Accumulated
Additional Comprehensive Other Total
Common Paid-In Income Retained Comprehensive Treasury Stockholders'
Stock Capital (Loss) Earnings Loss Stock Equity
--------- ----------- ------------ ----------- ------------ ------------ -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balances at
September 30, 1996 $821,000 $3,103,000 $14,121,000 $ (1,937,000) $ (4,705,000) $ 11,403,000
Comprehensive income:
Net earnings $ 1,050,000 1,050,000 1,050,000
------------
Other comprehensive
loss, net of income taxes:
Foreign currency
translation adjustments (326,000)
Unrealized holding
gain on securities 23,000
------------
Other comprehensive loss (303,000) (303,000) (303,000)
------------
Total comprehensive income $ 747,000
--------- ----------- ============ ----------- ------------ ------------ -------------
Balances at
September 30, 1997 $ 821,000 $ 3,103,000 $15,171,000 $ (2,240,000) $ (4,705,000) $ 12,150,000
Comprehensive loss:
Net loss $ (3,890,000) (3,890,000) (3,890,000)
------------
Other comprehensive
loss, net of income taxes:
Foreign currency
translation adjustments (1,421,000)
Unrealized holding
loss on securities (11,000)
------------
Other comprehensive loss (1,432,000) (1,432,000) (1,432,000)
------------
Total comprehensive loss $ (5,322,000)
============
Purchases of 5,100 shares of
common stock for treasury (84,000) (84,000)
--------- ----------- ----------- ------------ ------------ -------------
Balances at
September 30, 1998 $ 821,000 $ 3,103,000 $11,281,000 $ (3,672,000) $ (4,789,000) $ 6,744,000
<FN>
(continued on next page)
</FN>
</TABLE>
<TABLE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
Years ended September 30, 1999, 1998, and 1997
(continued from previous page)
<CAPTION>
Accumulated
Additional Comprehensive Other Total
Common Paid-In Income Retained Comprehensive Treasury Stockholders'
Stock Capital (Loss) Earnings Loss Stock Equity
--------- ----------- ------------ ----------- ------------ ------------ -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balances at
September 30, 1998 $ 821,000 $ 3,103,000 $11,281,000 $ (3,672,000) $ (4,789,000) $ 6,744,000
Comprehensive income:
Net earnings $ 520,000 520,000 520,000
Other comprehensive income,
net of income taxes -
Foreign currency
translation adjustments 542,000 542,000 542,000
------------
Total comprehensive income $ 1,062,000
--------- ----------- ============ ----------- ------------ ------------ -------------
Balances at
September 30, 1999 $ 821,000 $ 3,103,000 $11,801,000 $ (3,130,000) $ (4,789,000) $ 7,806,000
========= =========== =========== ============ ============ =============
<FN>
See Notes to Condensed Consolidated Financial Statements
</FN>
</TABLE>
BARNWELL INDUSTRIES, INC.
-------------------------
AND SUBSIDIARIES
----------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
YEARS ENDED SEPTEMBER 30, 1999, 1998, AND 1997
----------------------------------------------
1. DESCRIPTION OF THE REPORTING ENTITY AND BUSINESS
------------------------------------------------
The consolidated financial statements include the accounts of Barnwell
Industries, Inc. and all majority-owned subsidiaries, including a land
development joint venture (collectively referred to herein as "Company"). All
significant intercompany accounts and transactions have been eliminated.
During its last three completed fiscal years, the Company was engaged in
exploring for, developing, producing and selling oil and natural gas in Canada,
investing in leasehold land in Hawaii, and drilling wells and installing and
repairing water pumping systems in Hawaii. The Company's oil and natural gas
activities comprise its largest business segment. Approximately 67% of the
Company's revenues and 62% of the Company's capital expenditures for the fiscal
year ended September 30, 1999 were attributable to its oil and natural gas
activities. The Company's contract drilling activities accounted for 28% of the
Company's revenues in fiscal 1999 with gas processing and other revenues
comprising the remaining 5%. The Company had no land investment revenue in 1999;
land investment revenues relate to sales of leasehold interests and development
rights, which do not occur every year. Changes in the marketplace of any of the
aforementioned industries may significantly affect management's estimates and
the Company's performance.
2. SIGNIFICANT ACCOUNTING POLICIES
-------------------------------
Cash and cash equivalents
- -------------------------
Cash and cash equivalents includes cash on hand, demand deposits and
short-term investments with maturities of three months or less.
Oil and natural gas properties
- ------------------------------
The Company uses the full cost method of accounting under which all costs
incurred in the acquisition, exploration and development of oil and natural gas
reserves, including unsuccessful wells, are capitalized until such time as the
aggregate of such costs, on a country by country basis, equals the discounted
present value (at 10%) of the Company's estimated future net cash flows from
estimated production of proved oil and natural gas reserves, as determined by
independent petroleum engineers, less related income tax effects. Any
capitalized costs in excess of the discounted present value are charged to
expense. Depletion of all such costs, except costs related to major development
projects, is provided by the unit-of-production method based upon proved oil and
natural gas reserves of all properties on a country by country basis.
Investments in major development projects are not amortized until proved
reserves associated with the projects can be determined or until impairment
occurs. If the results of an assessment indicate that the properties are
impaired, the amount of the impairment is added to the capitalized costs to be
amortized. General and administrative costs related to oil and natural gas
operations are expensed as incurred. Estimated future site restoration and
abandonment costs are charged to earnings at the rate of depletion and are
included in accumulated depreciation, depletion and amortization. Proceeds from
the disposition of minor producing oil and natural gas properties are credited
to the cost of oil and natural gas properties. Gains or losses are recognized on
the disposition of significant oil and natural gas properties.
Contract drilling
- -----------------
Revenues, costs and profits applicable to contract drilling contracts are
included in the consolidated statements of operations using the percentage of
completion method, principally measured by the percentage of labor dollars
incurred to date for each contract to total estimated labor dollars for each
contract. Contract losses are recognized in full in the year the losses are
identified. The performance of drilling contracts may extend over more than one
year and, in the interim periods, estimates of total contract costs and profits
are used to determine revenues and profits earned for reporting the results of
the contract drilling operations. Revisions in the estimates required by
subsequent performance and final contract settlements are included as
adjustments to the results of operations in the period such revisions and
settlements occur. Contracts are normally less than one year in duration.
Investment in land and revenue recognition
- ------------------------------------------
The Company's investment in land is comprised of land under development
and development rights under option. Investment in land under development is
evaluated for impairment whenever events or changes in circumstances indicate
that the recorded investment balance may not be fully recoverable. Development
rights under option is reported at the lower of the asset carrying value or fair
value, less cost to sell.
Land sales for development rights under option as of September 30, 1999
are accounted for under the cost recovery method. Under the cost recovery
method, no gain is recognized until cash received exceeds the cost and the
estimated future costs related to the development rights sold. The accompanying
consolidated balance sheets include no cost for development rights under option
and, accordingly, cash receipts, if any, in excess of costs will be reported as
revenues. The Company's cost, including capitalized interest, of the land under
development is included in the consolidated balance sheets under the caption
"Investment in Land."
Long-lived assets
- -----------------
Long-lived assets to be held and used, other than oil and natural gas
properties, are evaluated for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be fully
recoverable. If the future cash flows expected to result from use of the asset
(undiscounted and without interest charges) are less than the carrying amount of
the asset, an impairment loss is recognized. Such impairment loss is measured as
the amount by which the carrying amount of the asset exceeds the fair value of
the asset. Long-lived assets to be disposed of are reported at the lower of the
asset carrying value or fair value, less cost to sell.
Drilling rigs and other equipment
- ---------------------------------
Drilling rigs and other equipment are stated at cost. Depreciation is
computed using the straight-line method based on estimated useful lives ranging
from three to ten years.
Inventories
- -----------
Inventories are comprised of drilling materials and are valued at the
lower of weighted average cost or market value.
Environmental
- -------------
The Company is subject to extensive environmental laws and regulations.
These laws, which are constantly changing, regulate the discharge of materials
into the environment and maintenance of surface conditions and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are expensed. Liabilities
for expenditures of a noncapital nature are recorded when environmental
assessment and/or remediation is probable, and the costs can be reasonably
estimated.
Income taxes
- ------------
Deferred income taxes are determined using the asset and liability method.
Deferred tax assets and liabilities are recognized for the estimated future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
in effect for the year in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes the
enactment date.
Earnings per share
- ------------------
Basic earnings per share excludes dilution and is computed by dividing net
earnings (loss) by the weighted-average common shares outstanding for the
period. The weighted-average common shares outstanding for the years ended
September 30, 1999, 1998, and 1997 was 1,316,952, 1,319,719, and 1,322,052,
respectively.
Diluted earnings per share includes the potentially dilutive effect of
outstanding common stock options and securities which are convertible to common
shares. The weighted-average number of common and potentially dilutive common
shares for the years ended September 30, 1999, 1998, and 1997 was 1,316,952,
1,319,719, and 1,325,963, respectively. As of September 30, 1999 and 1998,
options to acquire 50,000 shares and 67,500 shares, respectively, of the
Company's common stock were outstanding. Assumed conversion of common stock
options is excluded from the computation of diluted earnings per share for the
years ended September 30, 1999 and 1998 because its effect would be
antidilutive.
Assumed conversion of the Company's convertible debentures to shares of
common stock was also excluded from the computation of diluted earnings per
share for all periods presented because its effect would be antidilutive. The
debentures were convertible into 80,000 common stock shares as of September 30,
1999 and 100,000 common stock shares as of September 30, 1998 and 1997.
Reconciliations between the numerator and denominator of the basic and
diluted earnings per share computations for the year ended September 30, 1997 is
as follows:
Year ended September 30, 1997
------------------------------------------
Net Earnings Shares Per-Share
(Numerator) (Denominator) Amount
------------ ------------- ---------
Basic earnings per share $1,050,000 1,322,052 $ 0.79
Effect of dilutive securities -
common stock options - 3,911 -
------------ ------------- ---------
Diluted earnings per share $1,050,000 1,325,963 $ 0.79
============ ============= =========
Foreign currency translation
- ----------------------------
Assets and liabilities of foreign operations and subsidiaries are
translated at the year-end exchange rate and resulting translation gains or
losses are accounted for in a stockholders' equity account entitled "accumulated
other comprehensive loss - foreign currency translation adjustments." Operating
results of foreign subsidiaries are translated at average exchange rates during
the period. Realized foreign currency transaction gains or losses were not
material in fiscal years 1999, 1998, and 1997.
New Statements of Financial Accounting Standards
- ------------------------------------------------
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 130, "Reporting
Comprehensive Income." SFAS No. 130 establishes standards for reporting and
display of comprehensive income and its components (revenues, expenses, gains
and losses) in a full set of general-purpose financial statements. This
statement requires that all items recognized under accounting standards as
components of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements and is
effective for fiscal years beginning after December 15, 1997. The Company
adopted the provisions of SFAS No. 130 in fiscal 1999. Financial statements
presented for earlier periods have been reclassified in accordance with the
requirements of SFAS No. 130.
In June 1997, the FASB issued SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related Information." This statement provides guidance for
public business enterprises in reporting information about operating segments in
annual financial statements and requires that those enterprises report selected
information about operating segments in interim financial reports to
shareholders. This statement also establishes standards for related disclosures
about products and services, geographic areas and major customers. This
statement is effective for fiscal years beginning after December 15, 1997. SFAS
No. 131 need not be applied to interim financial statements in the initial year
of its application. The Company adopted the provisions of SFAS No. 131 in fiscal
1999.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits," which amends the disclosure
requirements of SFAS No. 87, "Employers' Accounting for Pensions," SFAS No. 88,
"Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits," and SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." This statement
standardizes the disclosure requirements of SFAS No.'s 87 and 106 to the extent
practicable and recommends a parallel format for presenting information about
pensions and other postretirement benefits. SFAS No. 132 addresses disclosure
only and does not change any of the measurement or recognition provisions
provided for in SFAS No.'s 87, 88 or 106. This statement is effective for
financial statements for periods beginning after December 15, 1997. The Company
adopted the provisions of SFAS No. 132 in fiscal 1999.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which establishes accounting and reporting
standards for derivative instruments and hedging activities and requires that an
entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value. The
provisions of SFAS No. 133 are effective for all fiscal quarters of fiscal years
beginning after June 15, 1999. In July 1999, the FASB issued SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133, an Amendment of FASB Statement No.
133," which defers the effective date of SFAS No. 133 to be effective for all
fiscal quarters of fiscal years beginning after June 15, 2000. Management does
not expect adoption of SFAS No. 133 will have a material effect on the Company's
financial condition, results of operations or liquidity.
Use of Estimates in the Preparation of Financial Statements
- -----------------------------------------------------------
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and the disclosure of contingent assets and liabilities. Actual
results could differ significantly from those estimates. Significant assumptions
are required in the valuation of deferred tax assets and proved oil and natural
gas reserves, and such assumptions may impact the amount at which deferred tax
assets and oil and natural gas properties are recorded.
3. RECEIVABLES AND CONTRACT COSTS
------------------------------
Accounts receivable, current, are net of allowances for doubtful accounts
of $196,000 and $86,000 as of September 30, 1999 and 1998, respectively.
Included in accounts receivable are contract retainage balances of $274,000 and
$199,000 as of September 30, 1999 and 1998, respectively. These balances are
expected to be collected within one year, generally within 45 days after the
related contracts have received final acceptance and approval.
Costs and estimated earnings on uncompleted contracts are as follows:
September 30,
---------------------------
1999 1998
---------- ----------
Costs incurred on uncompleted contracts $3,211,000 $1,588,000
Estimated earnings 957,000 172,000
---------- ----------
4,168,000 1,760,000
Less billings to date 4,135,000 1,849,000
---------- ----------
$ 33,000 $ (89,000)
========== ==========
Costs and estimated earnings on uncompleted contracts are included in the
consolidated balance sheets under the following captions:
September 30,
---------------------------
1999 1998
---------- ----------
Costs and estimated earnings
in excess of billings on uncompleted contracts $ 172,000 $ 112,000
Billings in excess of costs
and estimated earnings on uncompleted contracts (139,000) (201,000)
---------- ----------
$ 33,000 $ (89,000)
========== ==========
4. INVESTMENT IN LAND
------------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii joint venture. Between 1986 and 1989, Kaupulehu Developments obtained the
state and county zoning changes necessary to permit development of the Four
Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club, a planned
second golf course, and single and multiple family residential units on land
acquired from Kaupulehu Developments, located approximately six miles north of
the Kona International Airport in the North Kona District of the Island of
Hawaii.
Kaupulehu Developments currently owns development rights in approximately
100 acres of residentially zoned leasehold land adjacent to the completed and
planned golf courses. The development rights in these approximately 100 acres
are under option to Hualalai Development Company, an affiliate of Kajima
Corporation of Japan. If Hualalai Development Company fully exercises this
option, Kaupulehu Developments will receive a total of $32,250,000. The option
expires on January 3, 2000, unless Kaupulehu Developments receives $6,750,000 of
the total consideration on or before January 3, 2000; on April 30, 2003 unless
50% of the then remaining consideration is received on or before April 30, 2003;
and the remainder of the option would then expire on April 30, 2007. There is no
assurance that this option or any portion of it will be exercised.
Kaupulehu Developments also holds leasehold rights in approximately 2,100
acres of land located adjacent to and north of the Four Seasons Resort Hualalai
at Historic Ka'upulehu. These approximately 2,100 acres are located between the
Queen Kaahumanu Highway and the Pacific Ocean. Kaupulehu Developments is in the
process of negotiating a revised development agreement and residential fee
purchase prices with the lessor of the 2,100 acre parcel. Management cannot
predict the outcome of these negotiations.
In June 1996, the State Land Use Commission ("LUC") approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of
these 2,100 acres of land into the Urban District for resort/residential
development. Subsequent to the LUC's approval, a notice of appeal was filed with
the Third Circuit Court of the State of Hawaii by parties seeking to reverse the
LUC's decision. The Third Circuit Court of the State of Hawaii upheld the Land
Use Commission's approval of Kaupulehu Developments' rezoning request in all
respects in a Decision and Order issued in August 1997. In November 1997, a
notice of appeal was filed with the Supreme Court of the State of Hawaii by
parties seeking to reverse the Third Circuit Court's decision. The Company
anticipates that the Supreme Court of the State of Hawaii will rule on the
appeal in 2000; management cannot predict the outcome of the appeal.
In June 1998, Kaupulehu Developments filed an Application for a Project
District zoning ordinance and a Special Management Area ("SMA") Use Permit
Petition with the County of Hawaii, requesting changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential, resort and
commercial development. Both the County zoning ordinance and the SMA Use Permit
are required for development of the property. In December 1998, following a
contested case hearing conducted in November, the Planning Commission of the
County of Hawaii granted the requested SMA Use Permit to Kaupulehu Developments
to be effective when the zoning ordinance is adopted. Subsequent to the Planning
Commission's approval, in January 1999, a notice of appeal was filed with the
Third Circuit Court of the State of Hawaii by parties seeking to reverse the
Planning Commission's decision. In April 1999, the County of Hawaii adopted an
ordinance granting zoning approval of Kaupulehu Developments' Application for a
Project District zoning ordinance, which requested changes in zoning and use of
the aforementioned 1,000 acres of land to allow residential, resort and
commercial development. The Company believes the Third Circuit Court of the
County of Hawaii will remand the SMA Use Permit back to the County of Hawaii
Planning Commission for further review due to procedural issues. The County of
Hawaii Planning Commission has scheduled a hearing on Kaupulehu Developments'
application for the SMA Use Permit for late December 1999. Management cannot
predict the outcome of the County of Hawaii Planning Commission's decision and
there is no assurance that an approval will be forthcoming at any time.
If the Supreme Court of the State of Hawaii vacates the LUC's approval,
and if the Company is subsequently unable to obtain the LUC's approval after
making additional efforts with the modifications it believes are necessary to
obtain the approval, there will be a materially adverse impairment of the value
of the Company's leasehold rights. Similarly, if the County of Hawaii Planning
Commission does not grant the SMA use permit, and if the Company is subsequently
unable to obtain the County of Hawaii Planning Commission's approval of the SMA
Use Permit after making additional efforts with the modifications it believes
are necessary to obtain the approval, there will be a materially adverse
impairment of the value of the Company's leasehold rights.
Costs related to the rezoning of the conservation land are capitalized and
included in the consolidated balance sheets under the caption, "Investment in
Land."
5. LONG-TERM DEBT
--------------
The Company has a credit facility at the Royal Bank of Canada, a Canadian
bank, for $19,000,000 Canadian dollars, or its U.S. dollar equivalent of
approximately $12,900,000 at September 30, 1999. Borrowings under this facility
were $11,431,000 and $11,665,000 at September 30, 1999 and 1998, respectively,
and are included in long-term debt. At September 30, 1999, the Company had
unused credit available under this facility of approximately $1,469,000.
The facility is available in U.S. dollars at the London Interbank Offer
Rate ("LIBOR") plus 3/4%, at U.S. prime, or in Canadian dollars at Canadian
prime. A standby fee of 1/2% per annum is charged on the unused facility
balance. Under the financing agreement, the facility is reviewed annually, with
the next review planned for February 2000. Subject to that review, the facility
may be extended one year with no required debt repayments for one year or
converted to a 5-year term loan by the bank. If the facility is converted to a
5-year term loan, the Company has agreed to the following repayment schedule of
the then outstanding loan balance: year 1-30%; year 2-27%; year 3-16%; year
4-14% and year 5-13%.
The Company has the option to change the currency denomination and
interest rate applicable to the loan at periodic intervals during the term of
the loan. During the year ended September 30, 1999, the Company paid interest at
rates ranging from 5.6875% to 7.25%. At September 30, 1999, $9,250,000 of the
loans were denominated in U.S. dollars at an interest rate of 6.00%, and
$2,181,000 of the loans were denominated in Canadian dollars (CDN $3,200,000) at
an interest rate of 6.25%. The facility is collateralized by the Company's
interests in its major oil and natural gas properties and a negative pledge on
its remaining oil and natural gas properties. The facility is reviewed annually
with a primary focus on the future cash flows that will be generated by the
Company's Canadian oil and natural gas properties. No compensating bank balances
are required for this facility.
The Canadian bank has represented that it will not require any repayments
under the facility before September 30, 2000. Accordingly, the Company has
classified outstanding borrowings under the facility as long-term debt.
In June 1995, the Company issued $2,000,000 of convertible notes due July
1, 2003. $1,950,000 of such notes were purchased by an officer/shareholder, a
director/shareholder, and certain other shareholders of the Company. The notes
are payable in 20 consecutive equal quarterly installments beginning in October
1998. Four quarterly installments aggregating $400,000 were paid during fiscal
year 1999. Interest is payable quarterly at a rate to be adjusted each quarter
to the greater of 10% per annum or 1% over the prime rate of interest. The
Company paid interest on these convertible notes at the rate of 10% per annum
throughout fiscal years 1999, 1998 and 1997. The notes are unsecured and
convertible at any time at the holder's option into shares of the Company's
common stock at a price of $20.00 per share, subject to adjustment for certain
events including a stock split of, or stock dividend on, the Company's common
stock. The notes are redeemable, at the option of the Company, at any time at
premiums declining 1% annually from 3% of the principal amount of the notes at
July 1, 1999. At September 30, 1999, $1,200,000 of these notes are included in
long-term debt and $400,000 of these notes are included in the current portion
of long-term debt.
In fiscal 1998, Kaupulehu Developments, a 50.1%-owned joint venture
obtained a $1,500,000 credit facility with a Hawaii bank. The facility is
secured by Kaupulehu Developments' assets and cash collateral and a personal
guaranty from an affiliate of Kaupulehu Developments' minority interest partner.
Interest on borrowings is guaranteed by the Company. Borrowings under the
facility are due in full on March 31, 2000, and interest is payable monthly at a
rate of 1.5% above the Hawaii bank's prime rate of interest (9.75% at September
30, 1999). Borrowings under the facility at September 30, 1999 and 1998
amounting to $1,250,000 and $365,000, respectively, are included in current
portion of long-term debt and long-term debt, respectively. The total available
credit under the facility at September 30, 1999 amounted to $250,000.
At September 30, 1999, the maturities of current and long-term debt by
fiscal year, exclusive of the credit facility with the Canadian bank, are as
follows:
2000 $1,650,000
2001 400,000
2002 400,000
2003 400,000
----------
$2,850,000
==========
The Company capitalizes interest on costs related to its investment in
land. The Company also capitalized interest on its investment in undeveloped
natural gas and oil leases in the Central Basin in Michigan during the year
ended September 30, 1997 and during the first quarter of the year ended
September 30, 1998. Interest costs for the years ended September 30, 1999, 1998
and 1997 are summarized as follows:
1999 1998 1997
---------- ---------- ----------
Interest costs incurred $1,010,000 $ 901,000 $ 793,000
Less interest costs capitalized on:
Investment in land 201,000 169,000 120,000
Investment in natural
gas and oil properties - 10,000 49,000
---------- ---------- ----------
Interest expense $ 809,000 $ 722,000 $ 624,000
========== ========== ==========
6. TAXES ON INCOME
---------------
The components of earnings (loss) before income taxes are as follows:
Year ended September 30,
---------------------------------------------
1999 1998 1997
----------- ----------- -----------
United States $(1,025,000) $(4,736,000) $(1,662,000)
Canadian 2,623,000 1,704,000 4,440,000
----------- ----------- -----------
$ 1,598,000 $(3,032,000) $ 2,778,000
=========== =========== ===========
The components of the provision for income taxes related to the above
earnings (loss) are as follows:
Year ended September 30,
---------------------------------------------
1999 1998 1997
----------- ----------- -----------
Current:
United States - Federal $ - $ - $ 51,000
United States - State and local - - (51,000)
----------- ----------- -----------
United States - total - - -
Canadian 764,000 334,000 842,000
----------- ----------- -----------
Total current 764,000 334,000 842,000
----------- ----------- -----------
Deferred:
United States 97,000 (23,000) 40,000
Canadian 217,000 547,000 846,000
----------- ----------- -----------
Total deferred 314,000 524,000 886,000
----------- ----------- -----------
$ 1,078,000 $ 858,000 $ 1,728,000
=========== =========== ===========
A reconciliation between the reported provision for income taxes and the
amount computed by multiplying the earnings (loss) before income taxes by the
United States federal tax rate is as follows:
Year ended September 30,
-------------------------------------------
1999 1998 1997
----------- ----------- -----------
Tax expense (benefit) computed
by applying statutory rate $ 559,000 $(1,061,000) $ 972,000
Change in the balance
of the valuation allowance 170,000 1,339,000 193,000
Effect of the foreign tax
provision on the
total tax provision 422,000 489,000 786,000
State net operating
losses generated (61,000) (70,000) (110,000)
Other (12,000) 161,000 (113,000)
----------- ----------- -----------
$ 1,078,000 $ 858,000 $ 1,728,000
=========== =========== ===========
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at September
30, 1999 and 1998 are as follows:
Deferred income tax assets: 1999 1998
----------- -----------
U.S. tax effect of deferred Canadian taxes $ 2,452,000 $ 2,278,000
Tax basis in land in excess of book basis 1,097,000 1,113,000
Foreign tax credit carryforwards 874,000 603,000
Write-down of assets not deducted for tax 355,000 741,000
U.S. federal net operating loss carryforwards 158,000 340,000
State of Hawaii net operating loss carryforwards 414,000 353,000
Expenses accrued for books but not for tax 261,000 213,000
Alternative minimum tax credit carryforwards 225,000 101,000
Other 118,000 32,000
----------- -----------
Total gross deferred tax assets 5,954,000 5,774,000
Less-valuation allowance (4,110,000) (3,940,000)
----------- -----------
Net deferred income tax assets 1,844,000 1,834,000
----------- -----------
Deferred income tax liabilities:
Property and equipment accumulated
tax depreciation and depletion
in excess of book under Canadian tax law (7,213,000) (6,699,000)
Property and equipment accumulated
tax depreciation and depletion
in excess of book under U.S. tax law (581,000) (444,000)
Other (221,000) (198,000)
----------- -----------
Total deferred income tax liabilities (8,015,000) (7,341,000)
----------- -----------
Net deferred income tax liability $(6,171,000) $(5,507,000)
=========== ===========
The total valuation allowance increased $170,000, $1,339,000, and $193,000
for the years ended September 30, 1999, 1998, and 1997, respectively. The
increase for the year ended September 30, 1998 relates primarily to foreign tax
credit carryforwards and U.S. federal net operating loss carryforwards for which
it is more likely than not that some portion of such carryforwards will not be
utilized to reduce the Company's U.S. tax obligation. Historically, the Company
has reduced U.S. regular taxes due on consolidated U.S. taxable income by
utilizing foreign tax credits. If the net operating loss is utilized to reduce
consolidated U.S. taxable income in a year in which the Company would normally
have utilized foreign tax credits to fully offset regular taxes, the net
operating loss will provide no incremental tax benefit; therefore a valuation
allowance has been provided.
A valuation allowance is provided when it is more likely than not that
some portion or all of the deferred tax asset will not be realized. The Company
has established a valuation allowance for Canadian tax deductions, foreign tax
credits, U.S. federal net operating loss carryforwards and state of Hawaii net
operating loss carryforwards which may not be realizable in future years as
there can be no assurance of any specific level of earnings or that the timing
of U.S. earnings will coincide with the payment of Canadian taxes to enable
Canadian taxes to be fully deducted (or recoverable) for U.S. tax purposes.
Additionally, utilization of U.S. federal net operating loss carryforwards will
provide no incremental tax benefit if foreign tax credits generated in future
years will be displaced by the net operating loss carryforwards as it is more
likely than not that the foreign tax credits will expire unused.
Net deferred tax assets will primarily be realized through the deduction
of the cost basis in investment in land against proceeds from investment in land
for tax purposes. Under the cost recovery accounting method, this cost basis has
already been expensed for book purposes. The amount of deferred income tax
assets considered realizable may be reduced in the near term if estimates of
future taxable income are reduced.
At September 30, 1999, the Company had net operating loss carryforwards
for U.S. federal income tax purposes of $464,000 which are available to offset
future U.S. federal taxable income, if any, through 2019. In addition, the
Company has alternative minimum tax credit carryforwards of $225,000 which are
available to reduce future U.S. federal regular income taxes, if any, over an
indefinite period.
7. PENSION PLAN
------------
The Company sponsors a noncontributory defined benefit pension plan
covering substantially all employees, with benefits based on years of service
and the employee's highest consecutive five-year average earnings. The Company's
funding policy is intended to provide for both benefits attributed to service
to-date and for those expected to be earned in the future. The plan assets at
September 30, 1999 were invested as follows: 43% listed government mortgages and
57% common stocks.
The funded status of the pension plan and the amounts recognized in the
consolidated financial statements are as follows:
September 30,
--------------------------
1999 1998
---------- ----------
Change in Benefit Obligation
Benefit obligation at beginning of year $1,966,000 $1,925,000
Service cost 77,000 66,000
Interest cost 139,000 139,000
Actuarial (gain)/loss (64,000) 3,000
Benefits paid (134,000) (167,000)
---------- ----------
Benefit obligation at end of year 1,984,000 1,966,000
---------- ----------
Change in Plan Assets
Fair value of plan assets at beginning of year 2,224,000 2,171,000
Actual return on plan assets 224,000 220,000
Employer contribution - -
Benefits paid (134,000) (167,000)
---------- ----------
Fair value of plan assets at end of year 2,314,000 2,224,000
---------- ----------
Funded status 330,000 258,000
Unrecognized net asset (2,000) (3,000)
Unrecognized prior service cost 34,000 40,000
Unrecognized actuarial gain (514,000) (398,000)
---------- ----------
Accrued benefit cost $ (152,000) $ (103,000)
========== ==========
Weighted-Average Assumptions as of September 30, 1999 1998
---------- ----------
Discount rate 7.50% 6.75%
Expected return on plan assets 8.00% 8.00%
Rate of compensation increase 5.00% 5.00%
Year ended September 30,
-----------------------------------
1999 1998 1997
--------- --------- ---------
Net Periodic Benefit Cost for the Year
Service cost $ 77,000 $ 66,000 $ 64,000
Interest cost 139,000 139,000 136,000
Expected return on plan assets (172,000) (168,000) (148,000)
Amortization of net asset (1,000) (1,000) (1,000)
Amortization of prior service cost 6,000 6,000 6,000
Amortization of net actuarial gain - (8,000) -
--------- --------- ---------
Net periodic benefit cost $ 49,000 $ 34,000 $ 57,000
========= ========= =========
8. STOCK OPTIONS
-------------
In March 1995, the Company granted 20,000 stock options to an officer of
the Company under a non-qualified plan at a purchase price of $19.625 per share
(market price on date of grant), with 4,000 of such options vesting annually
commencing one year from the date of grant. These options have stock
appreciation rights that permit the holder to receive stock, cash or a
combination thereof equal to the amount by which the fair market value, at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant.
In June 1998, the Company granted 30,000 stock options to an officer of
the Company's oil and gas segment under a non-qualified plan at a purchase price
of $15.625 per share (market price on date of grant), with 6,000 of such options
vesting annually commencing one year from the date of grant. These options have
stock appreciation rights that permit the holder to receive stock, cash or a
combination thereof equal to the amount by which the fair market value, at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant.
During the year ended September 30, 1999, options to acquire 12,500 shares
and 5,000 shares of the Company's common stock with an exercise price per share
of $13.625 and $22.250, respectively, expired. During the year ended September
30, 1998, options to acquire 1,500 shares and 5,000 shares of the Company's
common stock with an exercise price per share of $13.625 and $22.250,
respectively, were forfeited. There were no stock option transactions during the
year ended September 30, 1997.
The Company applies the provisions of APB Opinion No. 25 in accounting for
stock-based compensation and adopted the disclosure-only provisions of Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS No. 123"), effective October 1, 1996. No compensation cost
has been recognized for the aforementioned options for the years ended September
30, 1999, 1998 and 1997. Had compensation cost for the stock options granted in
June 1998 been determined based on the fair value method of measuring
stock-based compensation provisions of SFAS No. 123, the Company's net earnings
and basic and diluted earnings per share would have been $440,000 and $0.33,
respectively, for the year ended September 30, 1999, and the Company's net loss
and basic and diluted net loss per share would have been $3,920,000 and $2.97,
respectively, for the year ended September 30, 1998; fair value measurement of
these options was based on a Black Scholes option-pricing model which assumed an
expected life of seven years, expected volatility of 30%, a risk-free interest
rate of 5.5% and an expected dividend yield of 0%. The pro forma net earnings
(loss) reflects only options granted since October 1, 1995. Therefore, the full
impact of calculating compensation cost for stock options under SFAS No. 123 is
not reflected in the pro-forma earnings (loss) reported above because
compensation cost is reflected over the options' vesting periods and
compensation cost for options granted prior to October 1, 1995 is not
considered.
Stock options at September 30, 1999 were as follows:
Number of options
---------------------------
Per share price Outstanding Exercisable Expiration Date
--------------- ----------- ----------- ---------------
$15.625 30,000 6,000 May 2008
$19.625 20,000 16,000 March 2005
------ ------
Total 50,000 22,000
====== ======
Weighted average
exercise price $17.23 $18.53
====== ======
Stock options at September 30, 1998 were as follows:
Number of options
---------------------------
Per share price Outstanding Exercisable Expiration Date
--------------- ----------- ----------- ---------------
$13.625 12,500 12,500 December 1998
$15.625 30,000 - May 2008
$19.625 20,000 12,000 March 2005
$22.250 5,000 5,000 May 1999
------ ------
Total 67,500 29,500
====== ======
Weighted average
exercise price $16.93 $17.53
====== ======
Stock options at September 30, 1997 were as follows:
Number of options
---------------------------
Per share price Outstanding Exercisable Expiration Date
--------------- ----------- ----------- ---------------
$13.625 14,000 14,000 December 1998
$19.625 20,000 8,000 March 2005
$22.250 10,000 10,000 May 1999
------ ------
Total 44,000 32,000
====== ======
Weighted average
exercise price $18.31 $17.82
====== ======
Privately negotiated repurchases of common stock may be made if suitable
opportunities become available. At September 30, 1999, the Company could
purchase an additional 14,700 shares under a March 1991 stock repurchase
authorization.
9. COMMITMENTS AND CONTINGENCIES
-----------------------------
The Company is involved in routine litigation and is subject to
governmental and regulatory controls that are incidental to the ordinary course
of business. The Company's management believes that all claims and litigation
involving the Company are not likely to have a material adverse effect on its
financial position, results of operations, or liquidity.
The Company is contingently liable for the repayment of loans under a
$650,000 loan facility, granted by a bank, to three participants in one of the
Company's oil and natural gas ventures. At September 30, 1999, the loan balance
was $330,000, $100,000 of which is to an affiliate of the Company. The three
participants' interests in the venture are pledged as collateral to secure
repayment of the loans. The Company believes the value of the collateral is
significantly in excess of the loan balances.
The Company has committed to construct $200,000 of improvements at its
yard at Sand Island on Oahu, Hawaii, by the end of January 2000. Site
preparation commenced in October 1999.
The Company has several non-cancelable operating leases for office space
and land. Rental expense was $427,000 in 1999, $433,000 in 1998, and $397,000 in
1997. The Company is committed under these leases for minimum rental payments
summarized by fiscal year as follows: 2000 - $417,000, 2001 - $314,000, 2002 -
$314,000, 2003 - $295,000, 2004 - 180,000, and thereafter through 2026 an
aggregate of $1,415,000.
10. WRITE-DOWN OF OIL AND NATURAL GAS PROPERTIES AND OTHER ASSETS
-------------------------------------------------------------
Under the full cost method of accounting, the amount of oil and natural
gas properties' capitalized costs less accumulated depletion (on a country by
country basis) is subject to a ceiling test limitation that requires any excess
of such costs over the present value of estimated future cash flows from proved
reserves to be expensed. As of March 31, 1998, the Company's investment in the
development natural gas and oil reserves in the Central Basin in Michigan was
determined to be impaired and was transferred to the amortization base. Upon
transfer, capitalized oil and natural gas properties' costs in the United States
exceeded the full cost ceiling test limitation and, accordingly, the Company
recorded a non-cash write-down of $2,070,000 in the quarter ended March 31,
1998. Due to further declines in oil prices and disappointing seismic and
drilling results in North Dakota, the Company abandoned its U.S. oil and natural
gas prospects and recorded an additional U.S. ceiling test write-down of
$660,000 during the quarter ended June 30, 1998 to fully write-off its
investment in U.S. oil and natural gas properties.
In fiscal 1998, the Company also wrote down $170,000 of land and land
improvement costs related to a contract drilling yard held for sale due to a
decline in the market value of the property, and $95,000 of available-for-sale
securities due to a decline in market value deemed other than temporary.
In fiscal 1997, the Company recorded a U.S. oil and natural gas properties
ceiling test write-down of $270,000. This write-down was largely related to
downward revisions of proved oil and natural gas reserves.
11. SEGMENT AND GEOGRAPHIC INFORMATION
----------------------------------
The Company operates three segments: exploring for, developing, producing
and selling oil and natural gas in Canada; investing in leasehold land in
Hawaii; and drilling wells and installing and repairing water pumping systems in
Hawaii. The Company's reportable segments are strategic business units that
offer different products and services. They are managed separately as each
segment requires different operational methods, operational assets and marketing
strategies, and operate in different geographical locations.
The Company does not allocate general and administrative expenses,
interest expense, interest income or income taxes to segments, and there are no
transactions between segments that affect segment profit or loss.
Year ended September 30,
----------------------------------------
1999 1998 1997
----------- ----------- -----------
Revenues:
Oil and natural gas $10,130,000 $ 9,400,000 $11,520,000
Contract drilling 4,230,000 1,510,000 2,160,000
Other 668,000 920,000 873,000
----------- ----------- -----------
Total $15,028,000 $11,830,000 $14,553,000
=========== =========== ===========
Depreciation, depletion
and amortization:
Oil and natural gas $ 2,574,000 $ 2,698,000 $ 2,491,000
Contract drilling 110,000 68,000 93,000
Other 136,000 132,000 190,000
----------- ----------- -----------
Total $ 2,820,000 $ 2,898,000 $ 2,774,000
=========== =========== ===========
Write-downs of oil and natural gas
properties and other assets:
Oil and natural gas $ - $ 2,730,000 $ 270,000
Contract drilling - 170,000 -
Other - 95,000 -
----------- ----------- -----------
Total $ - $ 2,995,000 $ 270,000
=========== =========== ===========
Operating profit (loss)
(before general and
administrative expenses):
Oil and natural gas $ 4,188,000 $ 749,000 $ 5,433,000
Contract drilling 742,000 (550,000) 217,000
Other 532,000 693,000 683,000
----------- ----------- -----------
Total 5,462,000 892,000 6,333,000
General and
administrative expenses (3,187,000) (3,292,000) (3,208,000)
Interest expense (809,000) (722,000) (624,000)
Interest income 132,000 90,000 277,000
----------- ----------- -----------
Earnings (loss)
before income taxes $ 1,598,000 $(3,032,000) $ 2,778,000
=========== =========== ===========
Capital expenditures:
Oil and natural gas $ 1,753,000 $ 6,969,000 $ 6,477,000
Contract drilling 121,000 91,000 189,000
Land investment 809,000 862,000 733,000
Other 148,000 205,000 97,000
----------- ----------- -----------
Total $ 2,831,000 $ 8,127,000 $ 7,496,000
=========== =========== ===========
Depletion per 1,000 cubic feet of natural gas (MCF) and natural gas
equivalent was $0.53 in fiscal 1999, $0.51 in fiscal 1998, and $0.46 in fiscal
1997.
<TABLE>
ASSETS BY SEGMENT:
- ------------------
<CAPTION>
September 30,
------------------------------------------------------------
1999 1998 1997
------------------ ------------------ -----------------
<S> <C> <C> <C>
Oil and natural gas (1) $23,864,000 72% $23,959,000 76% $25,098,000 73%
Contract drilling (2) 2,091,000 6% 1,576,000 5% 1,700,000 5%
Land investment (2) 3,519,000 10% 2,710,000 8% 1,848,000 5%
Other:
Cash 2,577,000 8% 2,178,000 7% 4,402,000 13%
Corporate and other 1,244,000 4% 1,238,000 4% 1,350,000 4%
------------ ----- ------------ ----- ------------ -----
Total $33,295,000 100% $31,661,000 100% $34,398,000 100%
============ ===== ============ ===== ============ =====
<FN>
(1) Primarily located in the Province of Alberta, Canada.
(2) Located in Hawaii.
</FN>
</TABLE>
LONG-LIVED ASSETS BY GEOGRAPHIC AREA:
- -------------------------------------
September 30,
-----------------------------------------------------------
1999 1998 1997
----------------- ----------------- ------------------
United States $ 4,720,000 17% $ 3,861,000 14% $ 4,936,000 18%
Canada 22,771,000 83% 22,961,000 86% 22,019,000 82%
----------- ----- ----------- ----- ----------- ----
Total $27,491,000 100% $26,822,000 100% $26,955,000 100%
=========== ===== =========== ===== =========== ====
REVENUE BY GEOGRAPHIC AREA:
- ---------------------------
Year ended September 30,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
United States $ 4,237,000 $ 1,690,000 $ 2,373,000
Canada 10,791,000 10,140,000 12,180,000
----------- ----------- -----------
Total $15,028,000 $11,830,000 $14,553,000
=========== =========== ===========
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
-----------------------------------
The carrying amount of cash and cash equivalents approximates fair value
because of the short maturity of these instruments. The fair values of
investment securities included in other assets are estimated based on quoted
market prices for those or similar investments. The fair values of the Company's
long-term debt are estimated based on the current terms offered for debt of the
same or similar remaining maturities.
The differences between the estimated fair values and carrying values of
the Company's financial instruments are not material.
13. CONCENTRATIONS OF CREDIT RISK
-----------------------------
The Company's oil and natural gas segment derived 48% of its oil and
natural gas revenues in fiscal 1999 from three individually significant
customers. At September 30, 1999, the Company had a total of $626,000 in
receivables from these customers. In fiscal 1998 and 1997, the Company derived
23%, and 19%, respectively, of its oil and natural gas revenues from one
individually significant customer.
The Company's contract drilling subsidiary derived 43%, 42%, and 73% of
its contract drilling revenues in fiscal 1999, 1998, and 1997, respectively,
pursuant to State of Hawaii and local county contracts. At September 30, 1999,
the Company had accounts receivables from the State of Hawaii and local county
entities totaling approximately $352,000. Additionally, the Company's contract
drilling segment had net receivables from two private entities totaling
approximately $553,000. The Company has lien rights on contracts with the State
of Hawaii and local county entities and with the aforementioned private
entities.
Historically, the Company has not incurred significant credit related
losses on its trade receivables, and management does not believe significant
credit risk related to these trade receivables exists at September 30, 1999.
14. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
-------------------------------------------------
The following details the effect of changes in current assets and
liabilities on the consolidated statements of cash flows, and presents
supplemental cash flow information:
<TABLE>
<CAPTION>
Year ended September 30,
---------------------------------------
1999 1998 1997
---------- --------- ----------
Increase (decrease) from changes in:
<S> <C> <C> <C>
Receivables $ (140,000) $ 29,000 $ 167,000
Costs and estimated earnings in excess
of billings on uncompleted contracts (60,000) (82,000) 106,000
Inventories (30,000) (6,000) (15,000)
Other current assets (277,000) 223,000 17,000
Accounts payable (1,017,000) (88,000) 1,510,000
Accrued expenses (25,000) 833,000 539,000
Billings in excess of costs and
estimated earnings on uncompleted
contracts (62,000) 170,000 11,000
Payable to joint interest owners 384,000 (642,000) 289,000
Income taxes payable 298,000 (3,000) (155,000)
---------- --------- ---------
(Decrease) increase from changes
in current assets and liabilities $ (929,000) $ 434,000 $2,469,000
========== ========= ==========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 870,000 $ 616,000 $ 636,000
========== ========= ==========
Income taxes $ 497,000 $ 540,000 $1,146,000
========== ========= ==========
</TABLE>
15. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)
---------------------------------------------------------
The following tables summarize information relative to the Company's oil
and natural gas operations, which are substantially conducted in Canada. Proved
reserves are the estimated quantities of crude oil, condensate and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed producing oil and natural gas reserves
are reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. The estimated net interests in total
proved developed and proved developed producing reserves are based upon
subjective engineering judgments and may be affected by the limitations inherent
in such estimations. The process of estimating reserves is subject to continual
revision as additional information becomes available as a result of drilling,
testing, reservoir studies and production history. There can be no assurance
that such estimates will not be materially revised in subsequent periods.
(A) Oil and Natural Gas Reserves
----------------------------
The following table, based on information prepared by independent
petroleum engineers, Paddock Lindstrom and Associates, Ltd., summarizes changes
in the estimates of the Company's net interests in total proved developed
reserves of crude oil and condensate and natural gas ("MCF" means 1,000 cubic
feet of natural gas) which are substantially in Canada:
OIL GAS
Proved developed reserves: (Barrels) (MCF)
--------- ----------
Balance at September 30, 1996 2,374,000 46,252,000
Revisions of previous estimates 169,000 761,000
Extensions, discoveries and other additions 339,000 1,786,000
Less production (264,000) (3,852,000)
Sales of reserves in place (5,000) (996,000)
--------- ----------
Balance at September 30, 1997 2,613,000 43,951,000
Revisions of previous estimates (116,000) (1,370,000)
Extensions, discoveries and other additions 191,000 1,710,000
Less production (275,000) (3,684,000)
Sales of reserves in place - (46,000)
--------- ----------
Balance at September 30, 1998 2,413,000 40,561,000
Revisions of previous estimates (19,000) (889,000)
Extensions, discoveries and other additions 9,000 502,000
Less production (265,000) (3,295,000)
--------- ----------
BALANCE AT SEPTEMBER 30, 1999 2,138,000 36,879,000
========= ==========
OIL GAS
Proved developed producing reserves at: (Barrels) (MCF)
--------- ----------
September 30, 1996 2,108,000 33,096,000
========= ==========
September 30, 1997 2,087,000 29,483,000
========= ==========
September 30, 1998 2,109,000 28,306,000
========= ==========
SEPTEMBER 30, 1999 1,759,000 25,908,000
========= ==========
Included in the above tables are proved developed producing reserves in
the U.S. of 33,000 barrels of oil and 120,000 MCF of natural gas at September
30, 1997, and 50,000 barrels of oil and 39,000 MCF of natural gas at September
30, 1996.
(B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities
----------------------------------------------------------------------
1999 1998 1997
----------- ----------- -----------
Proved properties $48,809,000 $44,842,000 $44,369,000
Unproved properties 125,000 628,000 2,405,000
----------- ---------- -----------
Total capitalized costs 48,934,000 45,470,000 46,774,000
Accumulated depletion
and depreciation 26,678,000 23,041,000 23,481,000
----------- ----------- -----------
Net capitalized costs $22,256,000 $22,429,000 $23,293,000
=========== =========== ===========
U.S. capitalized costs totaled $1,903,000 as of September 30, 1997. U.S.
capitalized costs were fully written-off during the year ended September 30,
1998.
(C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration
--------------------------------------------------------------------------
and Development
---------------
Year ended September 30,
-----------------------------------------
1999 1998 1997
---------- ---------- -----------
Acquisition of properties:
Unproved -
Canadian $ 125,000 $ 184,000 $ 258,000
United States - 85,000 1,100,000
---------- ---------- -----------
$ 125,000 $ 269,000 $ 1,358,000
========== ========== ===========
Proved -
Canadian $ - $ 48,000 $ 316,000
United States - - -
---------- ---------- -----------
$ - $ 48,000 $ 316,000
========== ========== ===========
Exploration costs:
Canadian $ 189,000 $1,299,000 $ 936,000
United States - 493,000 279,000
---------- ---------- -----------
$ 189,000 $1,792,000 $ 1,215,000
========== ========== ===========
Development costs:
Canadian $1,439,000 $4,478,000 $ 3,217,000
United States - 382,000 371,000
---------- ---------- -----------
$1,439,000 $4,860,000 $ 3,588,000
========== ========== ===========
(D) The Results of Operations of Barnwell's Oil and Natural Gas Producing
---------------------------------------------------------------------
Activities
----------
Year ended September 30,
------------------------------------------
1999 1998 1997
----------- ----------- -----------
Gross revenues:
Canada $11,231,000 $10,626,000 $13,110,000
United States - 132,000 210,000
----------- ----------- -----------
Total gross revenues 11,231,000 10,758,000 13,320,000
Royalties, net of credit 1,101,000 1,358,000 1,800,000
----------- ----------- -----------
Net revenues 10,130,000 9,400,000 11,520,000
Production costs 3,368,000 3,223,000 3,326,000
Depletion and depreciation 2,574,000 2,698,000 2,491,000
Write-down - 2,730,000 270,000
----------- ----------- -----------
Pre-tax results of operations* 4,188,000 749,000 5,433,000
Estimated income tax expense 2,124,000 1,886,000 2,760,000
----------- ----------- -----------
Results of operations $ 2,064,000 $(1,137,000) $ 2,673,000
=========== =========== ===========
* Before general and administrative expenses.
(E) Standardized Measure, Including Year-to-Year Changes Therein, of Discounted
---------------------------------------------------------------------------
Future Net Cash Flows
---------------------
The following tables have been developed pursuant to procedures prescribed
by SFAS 69, and utilize reserve and production data estimated by petroleum
engineers. The information may be useful for certain comparison purposes but
should not be solely relied upon in evaluating the Company or its performance.
Moreover, the projections should not be construed as realistic estimates of
future cash flows, nor should the standardized measure be viewed as representing
current value.
The future cash flows are based on sales prices, costs, and statutory
income tax rates in existence at the dates of the projections. Material
revisions to reserve estimates may occur in the future, development and
production of the oil and natural gas reserves may not occur in the periods
assumed and actual prices realized and actual costs incurred are expected to
vary significantly from those used. Management does not rely upon this
information in making investment and operating decisions; rather, those
decisions are based upon a wide range of factors, including estimates of
probable reserves as well as proved reserves and price and cost assumptions
different than those reflected herein.
Standardized Measure of Discounted Future Net Cash Flows
- --------------------------------------------------------
As of September 30,
-----------------------------------------------
1999 1998 1997
------------ ------------ ------------
Future cash inflows $108,463,000 $ 83,827,000 $106,086,000
Future production costs (33,680,000) (30,052,000) (36,965,000)
Future development costs (1,268,000) (1,372,000) (1,980,000)
------------ ------------ ------------
Future net cash
flows before income taxes 73,515,000 52,403,000 67,141,000
Future income tax expenses (24,914,000) (15,379,000) (21,369,000)
------------ ------------ ------------
Future net cash flows 48,601,000 37,024,000 45,772,000
10% annual discount
for timing of cash flows (19,844,000) (14,351,000) (17,790,000)
------------ ------------ ------------
Standardized measure of
discounted future
net cash flows $ 28,757,000 $ 22,673,000 $ 27,982,000
============ ============ ============
Changes in the Standardized Measure of Discounted Future Net Cash Flows
- -----------------------------------------------------------------------
Year ended September 30,
---------------------------------------
1999 1998 1997
----------- ----------- -----------
Beginning of year $22,673,000 $27,982,000 $27,094,000
----------- ----------- -----------
Sales of oil and natural gas
produced, net of production costs (6,762,000) (6,177,000) (8,194,000)
Net changes in prices and
production costs, net of
royalties and wellhead taxes 13,452,000 (2,295,000) 3,233,000
Extensions and discoveries 561,000 1,650,000 3,921,000
Sales of reserves in place - (49,000) (970,000)
Revisions of previous
quantity estimates (52,000) (1,153,000) 1,937,000
Net change in Canadian
dollar translation rate 864,000 (2,744,000) (362,000)
Changes in the timing of
future production and other (851,000) 447,000 (860,000)
Net change in income taxes (3,465,000) 2,466,000 (491,000)
Accretion of discount 2,337,000 2,546,000 2,674,000
----------- ----------- -----------
Net change 6,084,000 (5,309,000) 888,000
----------- ----------- -----------
End of year $28,757,000 $22,673,000 $27,982,000
=========== =========== ===========
Item 8. Changes in and Disagreements with Accountants on Accounting and
---------------------------------------------------------------
Financial Disclosure
--------------------
None.
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons,
-------------------------------------------------------------
Compliance With Section 16(a) of the Exchange Act
-------------------------------------------------
Item 10. Executive Compensation
----------------------
Item 11. Security Ownership of Certain Beneficial Owners and Management
--------------------------------------------------------------
Item 12. Certain Relationships and Related Transactions
----------------------------------------------
Items 9, 10, 11, and 12 are omitted pursuant to General Instructions E.3.
of Form 10-KSB, since the Registrant will file its definitive proxy statement
for the 1999 Annual Meeting of Stockholders not later than 120 days after the
close of its fiscal year ended September 30, 1999, which proxy statement is
incorporated herein by reference.
Item 13. Exhibits, List and Reports on Form 8-K
--------------------------------------
(A) Financial Statements
The following consolidated financial statements of Barnwell Industries,
Inc. and its subsidiaries are included in Part II, Item 7:
Independent Auditors' Report - KPMG LLP
Consolidated Balance Sheets - September 30, 1999 and 1998
Consolidated Statements of Operations -
for the three years ended September 30, 1999
Consolidated Statements of Cash Flows -
for the three years ended September 30, 1999
Consolidated Statements of Stockholders' Equity and
Comprehensive Income (Loss) -
for the three years ended September 30, 1999
Notes to Consolidated Financial Statements
Schedules have been omitted because they were not applicable, not
required, or the information is included in the consolidated financial
statements or notes thereto.
(B) Reports on Form 8-K
There were no reports on Form 8-K filed during the three months ended
September 30, 1999.
(C) Exhibits
No. 3.1 Certificate of Incorporation (1)
No. 3.2 Amended and Restated By-Laws (1)
No. 4.0 Form of the Registrant's certificate of common stock, par value
$.50 per share. (2)
No. 10.1 The Barnwell Industries, Inc. Employees' Pension Plan (restated
as of October 1, 1989). (3)
No. 10.2 Phase I Makai Development Agreement dated June 30, 1992, by and
between Kaupulehu Makai Venture and Kaupulehu Developments. (4)
No. 10.3 KD/KMV Agreement dated June 30, 1992 by and between Kaupulehu
Makai Venture and Kaupulehu Developments. (4)
No. 21 List of Subsidiaries. (5)
No. 27 Financial Data Schedule (for SEC use only)
- -----------------------------
(1)Incorporated by reference to the Registrant's Form S-8 dated November 8,
1991.
(2)Incorporated by reference to the registration statement on Form S-1
originally filed by the Registrant January 29, 1957 an as amended February
15, 1957 and February 19, 1957.
(3)Incorporated by reference to Form 10-K for the year ended September 30, 1989.
(4)Incorporated by reference to Form 10-K for the year ended September 30, 1992.
(5)Incorporated by reference to Form 10-KSB for the year ended September 30,
1998.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BARNWELL INDUSTRIES, INC.
(Registrant)
/s/Russell M. Gifford
- ---------------------------------
By: Russell M. Gifford
Chief Financial Officer,
Executive Vice President and
Treasurer
Date: December 5, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, the
report has been signed below by the following persons on behalf of the
registrant in the capacities and on the dates indicated.
/s/Morton H. Kinzler
- ---------------------------------
MORTON H. KINZLER
Chief Executive Officer,
President and Director
Date: December 5, 1999
/s/Martin Anderson /s/Alan D. Hunter
- --------------------------------- ---------------------------
MARTIN ANDERSON, Director ALAN D. HUNTER, Director
Date: December 5, 1999 Date: December 5, 1999
/s/Daniel Jacobson
- --------------------------------- ---------------------------
H. WHITNEY BOGGS, JR., Director DANIEL JACOBSON, Director
Date: December 5, 1999
/s/Murray C. Gardner
- --------------------------------- ---------------------------
MURRAY C. GARDNER, Director WILLIAM C. WARREN, Director
Date: December 5, 1999
/s/Erik Hazelhoff-Roelfzema
- --------------------------------- ---------------------------
ERIK HAZELHOFF-ROELFZEMA, Director GLENN YAGO, Director
Date: December 5, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from
Barnwell Industries, Inc.'s 1999 10-KSB and is qualified in its entirety
by reference to such 10-KSB filing.
</LEGEND>
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-END> SEP-30-1999
<CASH> 2577
<SECURITIES> 0
<RECEIVABLES> 2069
<ALLOWANCES> 196
<INVENTORY> 106
<CURRENT-ASSETS> 5597
<PP&E> 59981
<DEPRECIATION> 36009
<TOTAL-ASSETS> 33295
<CURRENT-LIABILITIES> 6557
<BONDS> 12631
0
0
<COMMON> 821
<OTHER-SE> 6985
<TOTAL-LIABILITY-AND-EQUITY> 33295
<SALES> 14360
<TOTAL-REVENUES> 15160
<CGS> 6746
<TOTAL-COSTS> 6746
<OTHER-EXPENSES> 2820
<LOSS-PROVISION> 110
<INTEREST-EXPENSE> 809
<INCOME-PRETAX> 1598
<INCOME-TAX> 1078
<INCOME-CONTINUING> 520
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 520
<EPS-BASIC> .39
<EPS-DILUTED> .39
</TABLE>
