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, 1996
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 -------------------
$0.50 per share American Stock Exchange
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, 1996: $14,180,000
The aggregate market value of the voting stock held by non-affiliates of the
Registrant on December 2, 1996, based on the closing price on that date on the
American Stock Exchange, was 500,000 shares x $19.00 = $9,500,000.
As of December 2, 1996 there were 1,322,052 shares of common stock, par value
$.50, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
-----------------------------------
1. Proxy statement to be forwarded to shareholders on or about January 7,
1997 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
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,
contain forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934,
including various forecasts, projections of the Company's future performance,
statements of the Company 's plans and objectives or 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 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 effecting oil-
producing countries, including military conflict, embargoes, internal
instability or actions or reactions of the government of the United States in
anticipation of or in response to such developments. Domestic and international
economic conditions, such as recessionary trends, inflation, interest, monetary
exchange rates and labor costs, as well as changes in the availability and
market prices of crude oil, natural gas and petroleum products, can also
have a significant effect on the Company's oil and 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, price controls, tax increases and
retroactive tax claims, expropriation of property, cancellation of contract
rights, environmental protection controls 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. The
Hawaiian tourist industry is dependent to a large extent on Japanese tourists
and, therefore, is affected by the Japanese economy. A weakening in Japanese
tourism would likely harm Hawaii's tourist industry and depress real estate
prices in Hawaii. Any future cash flows from the Company's land development
activities are subject to, among other factors, the level of real estate prices,
the demand for new hotels and resorts on the Island of Hawaii, the rate of
increase in the cost of building materials and labor, the introductions of
building code modifications, changes to zoning laws, and the level of consumer
confidence in Hawaii's economy.
The Company's contract drilling operations, which are located in Hawaii,
are indirectly affected by the foregoing factors discussed in the preceding
paragraph as well. The Company's contract drilling operations are
materially dependent upon levels of activity in land development in Hawaii.
Such activity levels are affected by both short-term and long-term trends in
Hawaii's economy. In recent years, Hawaii's economy has been in a recession and
therefore the level of contract drilling activity has declined. As events
during recent years have demonstrated, any prolonged reduction or lack of growth
in Hawaii's economy will depress the demand for the Company's contract drilling
services. Such a decline could have a material adverse effect on the Company's
revenues and profitability.
Item 1. Description of Business
-----------------------
(a) General Development of Business
-------------------------------
Barnwell Industries, Inc. (referred to herein together with its
subsidiaries as "Barnwell" or the "Company") was incorporated in 1956. During
its last three completed fiscal years, the Company was engaged in oil and
natural gas exploration, development, production and sales in Canada and the
United States, investment in leasehold land in Hawaii, and water well drilling
and water pumping system installation and repair in Hawaii. The Company's oil
and natural gas activities comprise its largest business segment. Approximately
75% of the Company's revenues for the fiscal year ended September 30, 1996 were
attributable to its oil and natural gas activities. The Company's contract
drilling activities accounted for 19% of the Company's revenues in fiscal 1996,
with natural gas processing and other revenues comprising the remaining 6% of
fiscal 1996 revenues. Approximately 85% of the Company's capital expenditures
for the fiscal year ended September 30, 1996 were attributable to oil and
natural gas activities, 11% to land investment and 4% to other activities. The
Company had no land investment revenue in 1996; land investment revenues relate
to the sale 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.
In November 1996, the Company entered into a participation agreement with
KEP Energy Resources LLC and Presco Inc., to develop natural gas and oil
reserves in the Central Basin in Michigan. The Company raised $1,575,000 from
participants (including certain officers, directors, and employees of the
Company) and then acquired a 12.5% interest in this development program that
encompasses approximately 220,000 net acres. Sixty percent (60%) of the
Company's 12.5% interest was allocated to the participants at the same price and
upon terms substantially the same and no more favorable than those under which
the Company acquired its interest. Under the terms of agreements with these
participants, 30% of the participants' 7.5% interest will revert to the Company
after the participants receive a return of their entire investment. The Company
expects to continue to utilize this source of financing in the future. Nine new
wells or re-entries are planned initially.
(ii) Contract Drilling.
-----------------
The Company's wholly-owned subsidiary, Water Resources International,Inc.
("WRI"), drills water wells and installs and repairs water pumping systems
in Hawaii. WRI owns and operates four rotary drill rigs, pump installation and
service equipment, and maintains drilling materials and pump inventory in
Hawaii. WRI contracts are usually fixed price contracts that are either
negotiated with private individuals or entities, or are obtained through
competitive bidding with various local, state and federal agencies.
(iii) Land Investment.
---------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments,
a Hawaii joint venture. Between 1986 and 1989, Kaupulehu Developments
successfully obtained the state and county zoning changes necessary to permit
development of the newly opened Four Seasons Resort Hualalai at Historic
Ka'upulehu and Hualalai Golf Course, a second golf course, and single and
multiple family residential units. Kaupulehu Developments currently owns
development rights in approximately 100 acres of residentially zoned leasehold
land and leasehold rights in approximately 2,180 acres of land located
approximately six miles north of the Keahole Airport in the North Kona District
of the Island of Hawaii.
(b) Financial Information about Industry Segments
---------------------------------------------
<TABLE>
<CAPTION>
Revenues of each industry segment for the fiscal years ended
September 30, 1996, 1995 and 1994 are summarized as follows (all revenues were
from unaffiliated customers with no intersegment sales or transfers):
1996 1995 1994
------------------- ------------------ -------------------
<S> <C> <C> <C>
Oil and natural gas $ 10,660,000 75% $ 10,520,000 70% $ 13,950,000 70%
Contract drilling 2,650,000 19% 3,770,000 25% 5,090,000 25%
Corporate and other 717,000 5% 420,000 3% 760,000 4%
------------ ---- ------------ ---- ------------ ----
Revenues for segments 14,027,000 99% 14,710,000 98% 19,800,000 99%
Interest income 153,000 1% 240,000 2% 200,000 1%
------------ ---- ------------ ---- ------------ ----
Total revenues $ 14,180,000 100% $ 14,950,000 100% $ 20,000,000 100%
============ ==== ============ ==== ============ ====
<FN>
For further discussion see Note 11 (Segment and Geographic Information) of
"Notes to Consolidated Financial Statements" in Item 7.
</TABLE>
(c) Narrative Description of Business
---------------------------------
See the table above in Item 1(b) detailing revenue of each industry segment
and description of each industry segment of the Company's business under Item 2.
As of September 30, 1996, Barnwell employed 38 full-time employees.
Thirteen (13) are employed in oil and natural gas activities, 14 are employed in
contract drilling, and 11 are members of the corporate and administrative staff.
(d) Financial Information about Foreign and Domestic Operations and
---------------------------------------------------------------
Export Sales
------------
Revenues, operating profit or loss and identifiable assets by geographic
area for the three years ended September 30, 1996, 1995 and 1994 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 oil and natural gas properties are located in Canada,
principally in the Province of Alberta, with the exception of the investment of
$828,000 in prospects in North Dakota and Louisiana. These property interests
are principally held under governmental leases or licenses. Under the typical
Canadian provincial governmental lease, Barnwell must perform exploratory
operations and comply with certain other conditions. Lease terms vary with each
province, but, in general, give Barnwell the right to remove oil, natural gas
and related substances subject to payment of specified royalties on production.
Barnwell participates in exploratory and developmental operations for oil
and natural gas on property in which it has an interest and evaluates proposals
by third parties with regard to participation in such exploratory and
developmental operations elsewhere. Exploratory and developmental operations on
property in which Barnwell has an interest and third party proposals for
exploratory and developmental operations on other property are evaluated by
Barnwell's Calgary, Alberta staff. Barnwell also relies on independent
consultants to aid in the evaluation of such exploration opportunities. In
fiscal 1996, Barnwell participated in exploratory and developmental operations
in the Canadian Province of Alberta, and the states of North Dakota and
Louisiana, although Barnwell does not limit its consideration of exploratory and
developmental operations to these areas.
Barnwell's producing natural gas properties are located principally in
Alberta. The Province of Alberta determines its royalty share of natural gas by
using a reference price which averages all natural gas sales in Alberta. In
fiscal 1996, the weighted average royalty paid on natural gas from the Dunvegan
Unit, Barnwell's principal oil and natural gas property, decreased to 17%, as
compared to 21% in fiscal 1995. The weighted average royalty paid on all of the
Company's natural gas was approximately 18% in fiscal 1996 and fiscal 1995.
In fiscal 1996, 95% of Barnwell's oil production was from properties
located in Alberta. Oil royalty rates under government leases in Alberta are
based on the selling price of oil. In fiscal 1996, the weighted average royalty
paid on oil was approximately 13%. The remaining 5% of Barnwell's oil
production came from properties located in North Dakota and Louisiana. The
weighted average royalty paid on oil produced in North Dakota was 12.5%; oil
revenue in North Dakota is subject to a 5% severance tax. The weighted average
royalty in Louisiana is 20% with severance tax rates of 12.5% on oil and $0.077
per 1,000 cubic feet ("MCF") on natural gas.
The Company's oil and natural gas segment derived 19% and 15% of its oil
and natural gas revenues in fiscal 1996 and 1995, respectively, from one
company. In fiscal 1994, the Company had one significant customer, which
accounted for 10% of the Company's oil and natural gas sales, exclusive of a
non-recurring $1,586,000 decontracting payment. At September 30, 1996, the
Company had a receivable from the aforementioned company of approximately
$140,000.
In fiscal 1996, the Company spent approximately $583,000 for land
acquisition and seismic costs in various areas of Alberta to be evaluated and
developed subsequent to fiscal 1996.
Typically, unit sales of natural gas are higher in the winter than at other
times due to demand for heating. Unit sales of oil are not subject to seasonal
fluctuations.
Well Drilling Activities
- ------------------------
During fiscal 1996, Barnwell participated in the drilling of 23 development
wells and 14 exploratory wells, of which 27 are capable of production. The
Company also acquired three natural gas wells, and participated in the
recompletion of nine wells. The most significant drilling operations took place
in the Gilby, Dunvegan, Worsely, Clear Hills and Thornbury areas of Alberta and
in North Dakota.
In fiscal year 1996, the Company continued to participate in the
development of oil reserves discovered in fiscal 1994 in the state of North
Dakota. Four oil wells were drilled in 1996, two of which are capable of
production and are producing. The Company now has six wells capable of producing
from four petroleum reservoirs. The Company's working interests in these wells
varies between 11.5% and 17.6%. The Company's portion of current production
from these wells is approximately 31 barrels per day.
The six successful wells and the four dry holes drilled in North Dakota
have enabled the Company to accumulate several potential drilling locations.
Additionally the Company's consultant geologist has identified several prospects
in which the Company is leasing mineral rights.
In fiscal 1996, the Company continued further development of a natural gas
project in the Thornbury area. The Company participated in the completion of
four natural gas wells. A total of 37 zones of production from 31 wells are now
contributing to an average daily production of approximately 10 MMCF ("MMCF"
means 1,000,000 cubic feet and "MCF" means 1,000 cubic feet) per day. The
Company's working interest in these wells varies between 11.25% and 22.5%.
Further activity in 1997 is planned in the Thornbury area.
The Company participated in the drilling of four successful wells in the
Worsely and Clear Hills areas of Northern Alberta in fiscal 1996. Further
development in these areas is planned for 1997. The Company's working interests
in these wells vary between 7.0% and 12.5%.
At September 30, 1996, the Company was participating in the drilling of two
wells in Alberta; one was subsequently completed as an oil well while the other
was completed as a natural gas well.
The following table sets forth more detailed information with respect to
the number of exploratory ("Exp.") and development ("Dev.") wells drilled and
acquired for the fiscal years ended September 30, 1996, 1995 and 1994 in which
Barnwell participated:
<TABLE>
<CAPTION>
Total
Productive Productive Acquired Productive
Oil Wells Gas Wells Wells Wells Dry Holes Total Wells
------------- ------------- ------------- ------------- ------------- -------------
Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev.
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
1996
- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Gross* 3.00 10.00 5.00 9.00 - 3.00 8.00 22.00 6.00 4.00 14.00 26.00
Net* 0.55 1.63 0.94 1.20 - 0.34 1.49 3.17 0.94 0.57 2.43 3.74
1995
- ----
Gross* 3.00 6.00 - 6.00 - 2.00 3.00 14.00 11.00 4.00 14.00 18.00
Net* 0.26 1.01 - 1.08 - 0.20 0.26 2.29 1.89 0.83 2.15 3.12
1994
- ----
Gross* 3.00 7.00 8.00 23.00 - - 11.00 30.00 9.00 2.00 20.00 32.00
Net* 0.64 1.60 1.26 3.20 - - 1.90 4.80 1.33 0.18 3.23 4.98
- --------------------------------
<FN>
* The term "Gross" refers to the total number of wells in which Barnwell owns
an interest, and "Net" refers to Barnwell's aggregate interest therein. For
example, a 50% interest in a well represents 1 gross well, but .50 net
well. The gross figure includes interests owned of record by Barnwell and,
in addition, the portion owned by others.
</TABLE>
The Dunvegan Unit, the Company's principal property located in Alberta,
Canada, has 137 natural gas wells comprising a total of 193 producing well
zones. In fiscal 1996 the Company expended $1,210,000 of which $918,000 was
spent on the construction of a sour gas plant. This facility will process
previously shut-in sour gas from the Unit. In addition, the Company
participated in the drilling of three successful natural gas wells, one of which
is also capable of producing oil, four recompletions of unit wells and one non-
unit oil well.
Oil and Natural Gas Production
- ------------------------------
In fiscal 1996, approximately 46%, 44% and 10% of the Company's oil and
natural gas revenues were from the sale of natural gas, sale of oil (including
liquids) and the royalty tax credit, respectively.
Barnwell's natural gas production in fiscal 1996 averaged net sales volume
after royalties of 11,900 MCF per day, a decrease of 12% from fiscal 1995. This
decrease was primarily attributable to decreased sales at Dunvegan due to
production declines at some Dunvegan wells and due to the process of tieing in
the new sour natural gas processing capacity. Increased Dunvegan gas plant
processing revenues, due to the processing of higher volumes of third party
natural gas, largely offset this decrease. Dunvegan provided 42% of the
Company's fiscal 1996 natural gas production compared to 46% for fiscal 1995.
In fiscal 1996, oil sales averaged net production of 563 barrels per day,
approximately the same volume as fiscal 1995. Production from the North Dakota
project contributed approximately 21 barrels per day. The Company's major oil
producing properties are the Red Earth, Chauvin, Gilby and Rainbow/Zama areas in
Canada.
In fiscal 1996, natural gas liquid sales averaged net production of 200
barrels per day, a decrease of 19% from the 246 barrels per day in fiscal 1995.
This decrease is the result of the aforementioned decrease in Dunvegan natural
gas production (natural gas liquids are extracted from the natural gas).
Besides Dunvegan, the Company's major natural gas liquids producing properties
are the Hillsdown, Pembina and Pouce Coupe areas in Alberta.
In fiscal 1995, approximately 49%, 40% and 11% of the Company's oil and
natural gas revenues were from the sale of natural gas, sale of oil (including
liquids) and the royalty tax credit, respectively.
Barnwell's natural gas production in fiscal 1995 averaged net sales volume
after royalties of 13,500 MCF per day, an increase of 5% over fiscal 1994. This
increase was primarily attributable to production from new areas.
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 1996
was derived primarily from the Province of Alberta. Other producing areas are
as follows: 500 barrels of oil and 107,000 MCF of natural gas were derived from
the Province of Saskatchewan, 7,500 barrels of oil were derived from the state
of North Dakota, and 270 barrels of oil, 17,100 MCF of natural gas and 3,580
barrels of natural gas liquids were derived from the state of Louisiana. All
dollar amounts in this table are in U.S. dollars.
Year Ended September 30,
---------------------------------------
1996 1995 1994
------------ ------------ ------------
Annual net production:
Natural gas liquids (BBLS)* 73,000 90,000 90,000
Oil (BBLS)* 206,000 206,000 182,000
Natural gas (MCF)* 4,347,000 4,916,000 4,679,000
Annual average sale price
per unit of production:
BBL of liquids** $13.40 $10.98 $ 9.48
BBL of oil** $17.38 $15.71 $14.06
MCF of natural gas** $ 1.14 $ 1.03 $ 1.57
Annual average production cost
per unit of gross production:
BBL of oil or liquids $ 3.91 $ 3.79 $ 3.49
MCF of natural gas $ 0.35 $ 0.30 $ 0.30
Productive Wells
- ----------------
Productive Wells***
-----------------------------
Gross**** Net****
---------- -------------
Oil Gas Oil Gas
Canada --- --- ----- -----
- ------
Alberta 177 355 56.38 48.29
British Columbia - - - -
Saskatchewan 3 21 0.25 3.48
USA
- ---
North Dakota 6 - 0.76 -
Louisiana 1 - 0.02 -
--- --- ----- -----
Total 187 376 57.41 51.77
=== === ===== =====
- ------------------------------
* When used in this report, "MCF" means 1,000 cubic feet of natural gas at
14.65 psia and 60 degrees F and the term "BBLS" means stock tank barrels of
oil equivalent to 42 U.S. gallons.
** Calculated on revenues before royalty expense and royalty tax credit
divided by gross production.
*** Seventy-two natural gas wells have dual or multiple completions and six oil
wells have dual completions.
**** Please see note (2) on the following table.
Developed Acreage and Undeveloped Acreage
- -----------------------------------------
<TABLE>
<CAPTION>
The following table sets forth certain information with respect to oil and
natural gas properties of Barnwell as of September 30, 1996:
Developed and
Developed Undeveloped Undeveloped
Acreage(1) Acreage(1) Acreage(1)
------------------ ----------------- ------------------
Location Gross(2) Net(2) Gross(2) Net(2) Gross(2) Net(2)
- ---------------- -------- ------ ------- ------ ------- ------
<S> <C> <C> <C> <C> <C> <C>
Canada
- ------
Alberta 232,759 37,573 149,259 29,608 382,018 67,181
British Columbia 483 40 2,789 284 3,272 324
Saskatchewan 3,696 543 200 11 3,896 554
USA
- ---
North Dakota 880 103 6,356 2,106 7,236 2,209
Louisiana 640 13 2,880 58 3,520 71
------- ------ ------- ------ ------- ------
Total 238,458 38,272 161,484 32,067 399,942 70,339
======= ====== ======= ====== ======= ======
Barnwell's leasehold interests in its undeveloped acreage, if not
developed, expire over the next five fiscal years as follows: 6% expire during
fiscal 1997; 10% expire during fiscal 1998; 21% expire during fiscal 1999; 25%
expire during fiscal 2000 and 4% expire during fiscal 2001. 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
Red Earth (3,563 net acres), Thornbury (4,996 net acres), Foley Lake (1,633 net
acres), Sutton (3,952 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 analysts, summarize the
estimated net quantities of proved developed producing reserves and proved
developed reserves of crude oil (including condensate and natural gas liquids)
and natural gas as of September 30, 1996, 1995 and 1994 on all properties in
which Barnwell has an interest. These reserves are before deductions for
indebtedness secured by the properties and are based on constant dollars. No
estimates of total proved net oil or natural gas reserves have been filed with
or included in reports to any other federal authority or agency since October 1,
1980.
<FN>
(1) "Developed Acreage" includes the acres covered by leases upon which there
are one or more producing wells. "Undeveloped Acreage" includes acres
covered by leases upon which there are no producing wells and which are
maintained in effect by the payment of delay rentals or the commencement of
drilling thereon.
(2) "Gross" refers to the total number of wells or acres in which Barnwell owns
an interest, and "Net" refers to Barnwell's aggregate interest therein. For
example, a 50% interest in a well represents 1 Gross Well, but .50 Net
Well, and similarly, a 50% interest in a 320 acre lease represents 320
Gross Acres and 160 Net Acres. The gross wells and gross acreage figures
include interests owned of record by Barnwell and, in addition, the portion
owned by others.
</TABLE>
Proved Developed Producing Reserves September 30,
- ----------------------------------- ---------------------------------------
1996 1995 1994
----------- ----------- -----------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 2,108,000 2,025,000 2,133,000
Natural gas - thousand
cubic feet (MCF) 33,096,000 31,700,000 34,624,000
Total Proved Developed Reserves
(Includes Proved
Developed Producing Reserves) September 30,
- ----------------------------------- ---------------------------------------
1996 1995 1994
----------- ----------- ------------
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 2,374,000 2,296,000 2,427,000
Natural gas - thousand
cubic feet (MCF) 46,252,000 46,746,000 51,850,000
As of September 30, 1996, all of Barnwell's proved developed producing and
total proved developed reserves were located in the Province of Alberta, with
the exception of 5,000 proved developed producing barrels of oil and 382,000
proved developed producing MCF of natural gas located in the Province of
Saskatchewan, 9,000 proved developed producing barrels of oil and 39,000 proved
developed producing MCF of natural gas located in the state of Louisiana and
41,000 proved developed producing barrels of oil located in the state of North
Dakota.
During fiscal 1996, Barnwell's total net proved developed reserves of oil,
condensate and natural gas liquids increased by 78,000 barrels, and total net
proved developed reserves of natural gas decreased by 494,000 MCF. The
increase in oil, condensate and natural gas liquids reserves was the net
result of (a) production during the year of 279,000 barrels, (b) the addition
of 116,000 barrels from the drilling of productive oil wells, (c) the
independent engineer's 252,000 barrel upward revision of the Company's oil
reserves and (d) the sale of reserves in place of 11,000 barrels.
Barnwell's natural gas reserves decreased as a net result of (a) production
during the year of 4,347,000 MCF, (b) the addition of 2,852,000 MCF from the
drilling of productive natural gas wells, (c) the sale of reserves in place of
356,000 MCF and (d) the independent engineer's 1,357,000 MCF upward revision
of the Company's natural gas reserves.
Barnwell's working interest in the Dunvegan Unit accounted for
approximately 56% of its total proven natural gas reserves at September 30, 1996
and 1995, and approximately 32% of proven oil and condensate reserves at
September 30, 1996 compared to approximately 35% of proven oil and condensate
reserves at September 30, 1995.
The following table sets forth the Company's oil and natural gas reserves
at September 30, 1996, by property name, based on information prepared by
Paddock Lindstrom and Associates, Ltd., Barnwell's independent reservoir
analysts. Gross reserves are before the deduction of royalties; net reserves
are after the deduction of royalties net of the Alberta Royalty Tax Credit.
This table is based on constant dollars where reserve estimates are based on
sales prices, costs and statutory tax rates in existence at the date of the
projection. Oil, which includes natural gas liquids, is shown in thousands of
barrels ("MBBLS") and natural gas is shown in millions of cubic feet ("MMCF").
OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 1996
Proved Producing Total Proved
----------------------------- -----------------------------
Oil Gas Oil Gas
-------------- -------------- -------------- --------------
Property Name GROSS NET GROSS NET GROSS NET GROSS NET
- -------------
(MBBLS) (MMCF) (MBBLS) (MMCF)
------------- -------------- -------------- --------------
Dunvegan Unit 768 656 23,936 22,348 884 754 27,534 26,092
Manyberries 83 81 81 74 83 82 761 712
Ardley (Alix) 10 9 8 8 10 9 8 8
Barrhead - - 383 330 7 7 861 789
Bashaw - - - - 8 6 295 235
Belloy - - 95 72 - - 95 72
Brooks - - 65 57 - - 65 57
Cessford 1 1 - - 1 1 - -
Charlotte Lake - - 779 697 - - 1,237 1,109
Chauvin 109 107 - - 109 108 - -
Clear Hills - - - - 2 1 378 342
Coyote - - 5 5 - - 5 5
Donalda - - - - - - 118 108
Dunvegan Non-Unit 10 8 32 31 14 11 834 804
Faith - - - - - - 1,026 891
Fenn Big Valley - - 16 14 - - 16 14
Gilby 33 29 317 239 33 29 618 451
Gilwood 1 1 - - - - 96 72
Halkirk - - - - 1 1 - -
Highvale 17 16 - - 25 24 81 71
Hillsdown 95 82 3,276 3,034 163 138 3,594 3,383
Joffre - - 1 1 - - 1 1
Lanaway - - - - - - 230 178
Lacombe 1 1 45 39 1 1 45 39
Leduc 4 3 212 167 4 3 416 357
Majeau Lake - - 26 23 - - 26 23
Medicine River 56 41 234 177 62 45 356 270
Mikwan - - 179 160 - - 179 160
Mitsue - - 44 40 - - 49 44
Morinville - - - - - - 447 391
Pembina 25 22 634 548 27 23 837 713
Pouce Coupe 8 6 1,477 1,395 9 7 2,201 2,108
Provost 9 8 - - 9 8 - -
Rainbow 33 27 - - 33 27 - -
Red Earth 914 905 - - 954 948 - -
Richdale - - - - - - 178 162
Staplehurst 11 10 - - 18 16 - -
Thornbury - - 2,852 2,723 - - 4,116 3,956
Wood River Unit 3 2 275 240 20 17 297 259
Wood River Non Unit - - 3 2 - - 3 2
Worsley 9 6 283 221 9 6 283 221
Zama 36 32 41 30 56 47 2,088 1,732
Hatton, Sask. - - 532 382 - - 532 382
Webb, Sask. 5 5 - - 5 5 - -
Coastal, ND 12 9 - - 12 9 - -
Wapiti, ND 6 5 - - 6 5 - -
West Greene, ND 34 27 - - 34 27 - -
Blind River, LA 15 9 59 39 15 9 59 39
------ ----- ------ ------ ------ ------ ------ ------
TOTAL 2,308 2,108 35,890 33,096 2,614 2,374 49,965 46,252
====== ===== ====== ====== ====== ====== ====== ======
Properties are located in Alberta, Canada unless otherwise noted.
Estimated Future Net Revenues
- -----------------------------
The following table sets forth Barnwell's "Estimated Future Net Revenues"
from proved producing reserves and total proved oil, natural gas and condensate
reserves and the present value of Barnwell's "Estimated Future Net Revenues"
(discounted at 10%). Estimated future net revenues for total proved reserves
are net of estimated development costs. Net revenues have been calculated using
current sales prices and costs, after deducting all royalties, operating costs,
future estimated capital expenditures, and income taxes.
Proved Total
Producing Proved
Reserves Reserves
------------- ------------
Year ending September 30,
1997 $ 5,707,000 $ 5,712,000
1998 4,494,000 4,992,000
1999 3,824,000 4,733,000
Thereafter 23,421,000 30,142,000
----------- -----------
$37,446,000 $45,579,000
=========== ===========
Present value (discounted at 10%)
at September 30, 1996 $22,195,000 $27,094,000
=========== ===========
Marketing of Oil and Natural Gas
- --------------------------------
Barnwell sells substantially all of its oil and condensate production under
short-term contracts between the operator of the property and marketers of oil.
The price of oil is determined by negotiation between the parties.
In fiscal 1996, natural gas production from the Dunvegan Unit was
responsible for approximately 42% of the Company's natural gas revenues. In
fiscal 1996, the Company had only one significant customer, ProGas Limited,
which accounted for 19% of the Company's oil and natural gas revenues.
In compliance with certain regulatory events and orders in the U.S. and
Canada affecting the sale and delivery of Canadian natural gas supplies to the
California market, the natural gas purchase, sales and transportation
agreements, under which Barnwell's Dunvegan natural gas was previously sold to
Alberta and Southern Gas Co., Ltd., were terminated, effective November 1993.
New marketing arrangements were made for the sale of Dunvegan natural gas
for fiscal 1994 and future years. Essentially all of Barnwell's Dunvegan
production and a significant portion of its natural gas production from other
properties is sold to several aggregators and marketers under various short-term
and long-term contracts, with the price of natural gas determined by
negotiations between the aggregators and the final purchasers.
Governmental Regulation
- -----------------------
General
-------
The jurisdictions in which the oil and natural gas properties of Barnwell
are located have regulatory provisions relating to permits for the drilling of
wells, the spacing of wells, the prevention of waste of oil and natural gas,
allowable rates of production and other matters. The amount of oil and natural
gas produced is subject to control by regulatory agencies in each province and
state which periodically assign allowable rates of production. The Province of
Alberta also regulates the volume of natural gas which may be removed from the
province and the conditions of removal.
There is no current government regulation of the price that may be charged
on the sale of Canadian oil or natural gas production. Canadian natural gas
production destined for export is, as of November 1, 1988, priced by market
forces subject to export contracts meeting certain criteria prescribed by
Canada's National Energy Board and the government of Canada.
The right to explore for and develop oil and natural gas on lands in
Alberta and Saskatchewan is controlled by the Governments of each of those
provinces. Changes in royalties and other terms of provincial leases, permits
and reservations may have a substantial effect on the Company's operations.
In addition to the foregoing, Barnwell's Canadian operations may be affected in
the future, from time to time, by political developments in Canada and by
Canadian Federal, provincial and local laws and regulations, such as
restrictions on production and export, oil and natural gas allocation and
rationing, price controls, tax increases, expropriation of property,
modification or cancellation of contract rights, and environmental protection
controls. Furthermore, operations may also be affected by United States import
fees and restrictions.
Different royalty rates are imposed by the producing provinces, the
Government of Canada and private interests with respect to the production and
sale of crude oil, natural gas and liquids. In addition, some producing
provinces receive additional revenue through the imposition of taxes on crude
oil and natural gas owned by private interests within the province.
Essentially, provincial royalties are calculated as a percentage of revenue, and
vary depending on production volumes, selling prices and the date of discovery.
Canadian taxpayers are not permitted to deduct royalties, taxes, rentals
and similar levies paid to the Federal or provincial governments in connection
with oil and natural gas production in computing income for purposes of Canadian
Federal income tax. However, they are allowed to deduct a "Resource Allowance"
which is 25% of the taxpayer's "Resource Profits for the Year" (essentially,
income from the production of oil, natural gas or minerals) in computing their
taxable income. The resource properties located in the United States are
freehold mineral interests leased under market conditions, subject to extraction
and severance taxes imposed according to state regulations.
The Province of Alberta has a "Royalty Tax Rebate" in its Income Tax Act
which eliminates the provincial share of income tax attributable to the
inability to deduct such royalties, rentals and similar levies. In addition,
the Alberta Income Tax Act provides for a royalty tax credit to taxpayers
calculated as a percentage of the taxpayer's "Attributed Alberta Royalty Income"
(being that portion of the royalties paid to the Province of Alberta which have
been disallowed as a deduction or added back in computing income for tax
purposes) subject to an annual limitation of the credit. In effect, this
returns to the taxpayer a portion of the royalties paid to the Province of
Alberta. The royalty tax credit is determined according to the prevailing price
of both oil and natural gas. Under this program, the total royalty tax credit
the Company receives declines as oil and natural gas prices rise and increases
as oil and natural gas prices decline. The maximum credit is equal to the
applicable percentage multiplied by the Crown Royalty Shelter, which is
$2,000,000 Canadian (referred to herein as "C"). The higher petroleum prices
are, the lower the applicable percentage; the lower petroleum prices are, the
higher the applicable percentage with the maximum percentage set at 75%.
In 1994, the Province of Alberta extended the royalty tax credit program to
December 31, 1997 and stated that changes in the Royalty Tax Rebate would be
announced three years in advance. The royalty tax credit program has been in
effect in various forms since 1974 and the Company anticipates that it will be
continued in some form for the foreseeable future. If the Alberta Royalty Tax
Credit is not continued, it will have a material adverse effect on the Company.
Natural Gas Pricing
-------------------
The price of natural gas is freely negotiated between buyers and sellers.
Natural gas sold by the Company is generally sold under both long-term and
short-term contracts with prices indexed to market prices and renegotiated
annually.
Oil Pricing
-----------
The price of oil is freely negotiated between buyers and sellers.
Competition
- -----------
The majority of Barnwell's natural gas sales take place in Alberta, Canada
and the 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
with shut-in capacity. Northern California prices are also competitive and are
influenced by competition from producers in the southwestern United States
(Texas, etc.). Barnwell's oil and natural gas liquids are sold in Alberta,
North Dakota and Louisiana 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 product currently. The oil and natural gas
industry is intensely competitive in all phases, including the exploration for
new production and reserves and the acquisition of equipment and labor necessary
to conduct drilling activities. The competition comes from numerous major oil
companies as well as numerous other independent operators. There is also
competition between the oil and natural gas industry and other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers. Barnwell is a minor factor in the industry and competes in
its oil and natural gas activities with many other companies having far greater
financial and other resources.
CONTRACT DRILLING OPERATIONS
- ----------------------------
Barnwell owns 100% of Water Resources International, Inc. ("WRI"). WRI
drills water wells and installs and repairs water pumping systems in Hawaii, and
has also drilled geothermal wells in Hawaii in previous years. WRI owns and
operates four rotary drill rigs, owns a two acre storage and maintenance yard
near Hilo, Hawaii, leases a three-quarter of an acre maintenance facility in
Honolulu and a one acre maintenance and storage facility with 2,800 square feet
of interior space in Kawaihae, Hawaii, and maintains drill and pump inventory.
As of September 30, 1996, WRI employed 14 drilling, pump and administrative
employees, none of whom are union members.
WRI drills both shallow and deep water wells in Hawaii, and has drilled the
deepest water well in the State. WRI also installs and repairs water pumps
after wells are completed. Pump installation and maintenance contracts are
primarily obtained from municipal water utilities. The demand for WRI's
services is dependent upon land development activities in Hawaii, which has
decreased from prior years' levels. WRI markets its services to land developers
and government agencies, and identifies potential contracts through public
notices and referrals. Contracts are usually fixed price contracts and are
negotiated with private entities or obtained through competitive bidding with
various local, state and Federal agencies. Contract revenues are not dependent
upon the discovery of water, and contracts are not subject to renegotiation of
profits or termination at the election of the governmental entities involved.
Contracts provide for arbitration in the event of disputes.
The Company's contract drilling subsidiary derived 42%, 28% and 40% of its
contract drilling revenues in fiscal 1996, 1995, and 1994, respectively,
pursuant to state of Hawaii and local county contracts. At September 30, 1996,
the Company had accounts receivable from the state of Hawaii and local county
entities totaling approximately $280,000. The Company has lien rights on
contracts with the state of Hawaii and local county entities.
The Company's contract drilling segment currently operates in Hawaii and is
not subject to seasonal fluctuations.
Activity
- --------
In fiscal 1996, WRI started two water well and three water well pump
installation contracts and completed three water well and six pump installation
contracts. One of the three completed water wells was started in the current
fiscal year and all six of the completed water well pump installations were
started in the prior year. Sixty-seven percent (67%) of such well drilling and
pump installation jobs, representing 42% of total contract drilling revenues in
fiscal 1996, have been pursuant to government contracts. At September 30, 1996,
WRI had a backlog of one water well contract, which was in progress as of
September 30, 1996, and nine pump installation contracts, four of which were in
progress as of September 30, 1996. These ten contracts represent a backlog of
contract drilling revenues of approximately $1,057,000 as of September 30, 1996.
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 water
wells, and six other Hawaii contractors who are capable of installing and
repairing vertical turbine and submersible water pumping systems in Hawaii.
These contractors compete actively with WRI for government and private
contracts. Pricing is the Company's major method of competition; reliability of
service is also a major factor.
LAND INVESTMENT OPERATIONS
- --------------------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii joint venture. Between 1986 and 1989, Kaupulehu Developments
successfully obtained the state and county zoning changes necessary to permit
development of the newly opened Four Seasons Resort Hualalai at Historic
Ka'upulehu and Hualalai Golf Course, a second golf course, and single and
multiple family residential units. Kaupulehu Developments currently owns
development rights in approximately 100 acres of residentially zoned leasehold
land and leasehold rights in approximately 2,180 acres of land located
approximately six miles north of the Keahole Airport in the North Kona District
of the Island of Hawaii.
The approximately 100 acres zoned for residential development are in the
vicinity of and adjacent to the newly opened Hualalai Golf Course. Kaupulehu
Developments' residential development rights in these approximately 100 acres
are under option to Hualalai Development Company (formerly Kaupulehu Makai
Venture), an affiliate of Kajima Corporation of Japan. If Hualalai Development
Company exercises this option, the Company will receive $16,157,000 in
connection with its 50.1% interest in Kaupulehu Developments. The option
expires on December 31, 1999, unless 20% of the consideration is received on or
before December 31, 1999; on April 30, 2003 unless 50% of the then remaining
consideration is received on or before April 30, 2003 and the remainder of the
option would then expire on April 30, 2007. There is no assurance that this
option or any portion of it will be exercised.
The 2,180 acres of land in which Kaupulehu Developments holds leasehold
rights is located adjacent to and north of the Four Seasons Resort Hualalai.
Kaupulehu Developments is in the process of negotiating a new development
agreement and residential fee purchase prices with the lessor. Management
cannot predict the ultimate outcome of these negotiations.
In 1993, Kaupulehu Developments submitted a rezoning petition to the State
Land Use Commission to reclassify approximately 1,000 of the 2,180 acres to
allow for the development of a residential community with recreational and
commercial areas, in conformance with the Hawaii County General Plan designation
for the area. The proposed developments include 500 multi-family units, 530
residential single-family home sites, a commercial center and two 18-hole golf
courses. The remaining 1,180 acres, located in the eastern portion of the
property, is classified within the State Land Use Conservation District and
unplanned by the County.
Activity
- --------
In June 1996, the State Land Use Commission (LUC) approved the Company's
petition for reclassification of the approximately 1,000 acres of conservation
zoned 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. If the LUC's decision is upheld, Kaupulehu Developments must then
obtain an additional series of approvals from various state and county agencies;
there is no assurance that these approvals will be forthcoming at any time.
Competition
- -----------
The Company's land investment segment is subject to intense competition in
all phases of its operations including the acquisition of new properties, the
securing of approvals necessary for land rezoning, and the search for potential
buyers of property interests presently owned. The competition comes from
numerous independent land development companies and other industries involved in
land investment activities. The principal methods of competition are the
location of the project and pricing. Kaupulehu Developments is a minor factor
in the land development industry and competes in its land investment activities
with many other entities having far greater financial and other resources.
For the past four years Hawaii's economy has been in a recession. While
the current outlook is for moderate economic growth of 2% to 3%, the real estate
market is not expected to experience a measurable improvement in the near term.
Item 3. Legal Proceedings
-----------------
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 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.
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, 1994 19-1/2 19 December 31, 1995 18-3/4 15-3/4
March 31, 1995 20 19 March 31, 1996 17-7/8 15-1/2
June 30, 1995 20 18-1/8 June 30, 1996 17-1/4 15-1/4
September 30, 1995 19-1/8 18-1/8 September 30, 1996 16-7/8 14-7/8
As of December 2, 1996, there were 1,322,052 shares of common stock, par
value $.50, outstanding. There were approximately 400 holders of the common
stock of the registrant as of December 2, 1996.
The Company declared four quarterly dividends of $0.05 per share in fiscal
1994 and two quarterly dividends of $0.075 per share in fiscal 1995. In May
1995, quarterly dividend payments were suspended and remain suspended to date.
Item 6. Management's Discussion and Analysis or Plan of Operation
---------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Cash flows from operations continue to be the Company's primary source of
liquidity. Cash flows from operations in fiscal 1996 increased $3,776,000 to
$5,700,000. This increase was largely because fiscal 1995's cash flows from
operations were reduced by tax payments of $2,120,000 related to two special
events. In fiscal 1995, a tax payment of $700,000 was applicable to the receipt
of a $1,586,000 decontracting payment received by the Company in fiscal 1994,
and a tax payment of $1,420,000 was applicable to the April 1995 expiration of
the option under which Hualalai Development Company (formerly Kaupulehu Makai
Venture) could have acquired Kaupulehu Developments' leasehold interest in
property in Hawaii. Also contributing to the increase was a $1,102,000 decrease
in working capital due to the timing of the payment of payables; this was
principally due to the timing of oil and gas capital expenditure payments at the
end of fiscal 1996 as compared to the end of fiscal 1995. The remaining
increase was due to the expensing in 1995 of $438,000 of costs applicable to the
rezoning of conservation leasehold land in Hawaii which was under option; in
fiscal 1996 rezoning costs related to land no longer under option and were
accordingly capitalized and classified as cash flows from investing activities.
The Company's revolving credit facility is with the Royal Bank of Canada, a
Canadian bank, for $15,000,000 Canadian dollars or its U.S. dollar equivalent of
approximately $11,000,000 at September 30, 1996. The facility is reviewed
annually with a primary focus on the future cash flows that will be generated by
the Company's oil and natural gas properties. The next review is planned for
February 1997. Subject to that review, the facility may be extended one year
with no required debt repayments for one year, or converted to a 5-year term
loan by the bank. If the facility is converted to a 5-year term loan, the
Company has agreed to the following repayment schedule of the then outstanding
balance: year 1 - 30%; year 2 - 27%; year 3 - 16%; year 4 - 14%; year 5 - 13%.
The facility is collateralized by the Company's interests in its major oil and
natural gas properties and a negative pledge on its remaining oil and natural
gas properties. No compensating bank balances are required on any of the
Company's indebtedness under the facility.
At September 30, 1996, the Company's consolidated cash and working capital
was $3,553,000 and $3,364,000, respectively. Available credit under the Royal
Bank of Canada's revolving credit facility was approximately $1,900,000 at
September 30, 1996.
In fiscal 1996, the Company expended a total of $5,049,000 towards the
development of its oil and natural gas properties. $3,751,000 was spent through
participation in the drilling of 23 development and 14 exploratory wells, 27 of
which are capable of production, participation in 3 oil and 6 natural gas well
recompletions, and the purchase of interests in 3 gas wells. Two successful and
2 dry and abandoned wells were drilled in North Dakota, where the Company spent
$380,000 in fiscal 1996. Additionally, the Dunvegan Unit owners approved the
construction of a sour natural gas plant to enable the Company to process and
sell production from currently shut-in sour gas wells. The plant was completed
at a cost to the Company of $918,000, and commenced operations in October 1996.
Also in fiscal 1996, the Dunvegan Unit owners negotiated a new natural gas
processing agreement with non-unit owners whereby the non-unit owners paid for a
$2,500,000 Dunvegan natural gas plant expansion in return for the right to have
their gas processed by the plant at a reduced tariff. This has increased the
natural gas plant's capacity to 200,000 MCF per day and has resulted in
increased natural gas processing revenues for the Company.
$646,000 was expended in the rezoning of leasehold land in North Kona,
Hawaii, from conservation to urban, in fiscal 1996. These expenditures
encompass legal, consulting and planning fees as well as capitalized interest.
The Company also spent $192,000 on its Stolberg natural gas processing
facilities, $53,000 on contract drilling assets and $27,000 on other property
and equipment.
The following table sets forth the Company's capital expenditures for each
of the last three fiscal years:
1996 1995 1994
---------- ----------- ----------
Contract drilling $ 53,000 $ 83,000 $ 94,000
Gas processing and other 219,000 120,000 293,000
Land investment 646,000 293,000 -
Oil and natural gas - U.S. 380,000 336,000 112,000
Oil and natural gas - Canada 4,669,000 3,098,000 5,238,000
---------- ----------- ----------
Total capital expenditures $5,967,000 $ 3,930,000 $5,737,000
========== =========== ==========
Increase (decrease)
in total oil and natural
gas capital expenditures $1,615,000 $(1,916,000) $2,157,000
========== =========== ==========
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:
1996 1995 1994
---------- ---------- ----------
Development oil and
natural gas wells drilled 23 16 32
Exploratory oil and
natural gas wells drilled 14 14 20
Development oil and
natural gas wells purchased 3 2 -
Successful oil and natural
wells drilled and purchased 30 17 41
In fiscal 1996, the Company sold non-producing natural gas rights in one of
its Red Earth properties for $368,000. This sales price significantly exceeded
the estimated present value, after deduction of development costs, of the
reserves held by the Company. The purchaser of these Red Earth rights holds a
significant amount of petroleum properties in the area. Additionally the
Company sold one minor property for $46,000. No revenue or income was
recognized as these proceeds were credited to the full cost pool.
It is anticipated that Barnwell's total fiscal 1997 capital expenditures
will increase approximately 10% above that of fiscal 1996, even though fiscal
1996's capital expenditures included $918,000 for the construction of the
recently completed Dunvegan sour natural gas plant. This estimated increase is
due to a significant drilling program at Thornbury and a significant investment
in a Michigan oil and natural gas prospect, both discussed below, as well as
drilling activities planned for North Dakota where the Company has participated
in prospects that now have several potential development drilling locations.
Capital expenditures for the contract drilling segment have totaled less
than $400,000 over the last five years and management estimates that in the next
two years contract drilling capital expenditures will increase, perhaps doubling
from the prior five year average. Additionally, the Company has a $200,000
commitment to construct improvements at its contract drilling yard at Sand
Island on Oahu, Hawaii, by June 1997.
The Company believes current cash balances and future cash flows from
operations will be sufficient to fund its estimated capital expenditures, make
the scheduled repayments on its convertible notes, and repay the outstanding
balance on its credit facility, should the Company or the Royal Bank of Canada
elect to convert the facility to a term loan.
In November 1996, the Company entered into a participation agreement with
KEP Energy Resources LLC and Presco Inc., to develop natural gas and oil
reserves in the Central Basin in Michigan. The Company raised $1,575,000 from
participants (including certain officers, directors, and employees of the
Company) and then acquired a 12.5% interest in this development program that
encompasses approximately 220,000 net acres. Sixty percent (60%) of the
Company's 12.5% interest was allocated to the participants at the same price
and upon terms substantially the same and no more favorable than those under
which the Company acquired its interest. Under the terms of agreements with
these participants, 30% of the participants' 7.5% interest will revert to the
Company after the participants receive a return of their entire investment.
The Company expects to continue to utilize this source of financing in the
future. Nine new wells or re-entries are planned initially.
The Company has agreed to a unitization of its approximately 17.5% working
interest in its Thornbury natural gas property with working interest owners in
lands surrounding the Thornbury property effective January 1, 1997. The Company
will obtain an interest in these undeveloped lands by exchanging an interest in
its currently developed property and a gas plant at Thornbury. As a result, the
Company's new interest in the Thornbury property, inclusive of the current
property plus the new undeveloped land, will be 12.5%. Additionally, the
Company's interest in the current Thornbury property is currently valued at
$830,000 more than its interest in the new combined property and therefore the
Company expects to receive approximately $830,000 in cash as a result of the
unitization. No revenue or gain will be recognized from this transaction. The
Company expects to spend approximately $850,000 developing a portion of the
newly added undeveloped lands, with a drilling program of 18 wells, and a new
compressor station.
The Company did not receive any revenues in fiscal 1996, 1995, and 1994
related to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments
internally funded 45% of its fiscal 1996 capital expenditures, the minority
interest partner funded 32% and the Company funded the remaining 23%.
Kaupulehu Developments' revenues specifically relate to the sale of leasehold
interests, which do not occur every year.
In fiscal 1994, the Company declared regular quarterly dividends on its
common stock at the rate of $0.05 per share. The Company also declared and paid
dividends totaling $198,000 during the first half of fiscal 1995. In May 1995,
the Company elected to suspend the payment of dividends pending further review
of investment opportunities. Dividends were neither declared nor paid in fiscal
1996.
RESULTS OF OPERATIONS
- ---------------------
Summary
-------
Barnwell reported net earnings of $1,230,000 in fiscal 1996, an increase of
$580,000 from net earnings of $650,000 in fiscal 1995. This increase was due
primarily to higher natural gas processing revenues, a $290,000 deferred income
tax benefit resulting from a decrease in the Canadian Branch tax rate and 11%
higher prices for both natural gas and oil and 22% higher prices for natural gas
liquids, partially offset by lower natural gas production. Additionally,
rezoning costs applicable to the leasehold land in Hawaii were capitalized in
fiscal 1996; such costs incurred during the first seven months of fiscal 1995
were related to land under option and accordingly expensed in fiscal 1995; such
expenses, net of minority interest in losses, amounted to approximately $220,000
before income taxes.
Barnwell reported net earnings of $650,000 in fiscal 1995, a decrease of
$1,870,000 from net earnings of $2,520,000 in fiscal 1994. This decrease was
due in part to net earnings of $880,000 recognized in fiscal 1994 as a result of
cash received for the termination of natural gas purchases, sales and
transportation agreements with Alberta and Southern Gas Co., Ltd. No such
payment was received in fiscal 1995. In addition, fiscal 1995 earnings were
reduced by a 34% decrease in natural gas prices, partially offset by a 5%
increase in natural gas production and 13% and 12% increases in oil production
and prices, respectively.
Barnwell reported net earnings of $2,520,000 in fiscal 1994, an increase of
$406,000 (19%) over the $2,114,000 of earnings from continuing operations
reported in fiscal 1993. This increase was due to an $880,000 oil and natural
gas decontracting payment, net of income taxes, received in November 1993, and
18% higher natural gas prices, which contributed to a $205,000 after-tax
increase in the Company's oil and natural gas operating profit. The increase in
earnings from continuing operations was partially offset by a decrease in
contract drilling profits due to lower demand for water well drilling work and
an increase in Canadian taxes due to higher Canadian income.
Oil and Natural Gas
- -------------------
Selected Operating Statistics
The following tables set forth the Company's annual net production and
annual average price per unit of production for fiscal 1996 as compared to
fiscal 1995 and fiscal 1995 as compared to fiscal 1994.
Fiscal 1996 - Fiscal 1995
-------------------------
Annual Net Production
---------------------------------------------
Increase
(Decrease)
------------------
1996 1995 Units %
--------- --------- --------- -----
Liquids (barrels) 73,000 90,000 (17,000) (19%)
Oil (barrels) 206,000 206,000 - -
Natural Gas (MCF) 4,347,000 4,916,000 (569,000) (12%)
Annual Average Price Per Unit
---------------------------------------------
Increase
(Decrease)
------------------
1996 1995 $ %
--------- --------- --------- -----
Liquids (barrels) $13.40 $10.98 $ 2.42 22%
Oil (barrels) $17.38 $15.71 $ 1.67 11%
Natural Gas (MCF) $ 1.14 $ 1.03 $ 0.11 11%
Fiscal 1995 - Fiscal 1994
-------------------------
Annual Net Production
---------------------------------------------
Increase
(Decrease)
-----------------
1995 1994 Units %
--------- --------- -------- -----
Liquids (barrels) 90,000 90,000 - -
Oil (barrels) 206,000 182,000 24,000 13%
Natural Gas (MCF) 4,916,000 4,679,000 237,000 5%
Annual Average Price Per Unit
---------------------------------------------
Increase
(Decrease)
-----------------
1995 1994 $ %
--------- --------- -------- -----
Liquids (barrels) $10.98 $ 9.48 $ 1.50 16%
Oil (barrels) $15.71 $14.06 $ 1.65 12%
Natural Gas (MCF) $ 1.03 $ 1.57 $(0.54) (34%)
Revenues were relatively unchanged (increasing $140,000 or 1%) in fiscal
1996 as compared to fiscal 1995 due to 12% and 19% declines in natural gas and
natural gas liquids unit sales, respectively, offset by price increases for
natural gas (11%), oil (11%) and natural gas liquids (22%). The declines in
natural gas and natural gas liquids volumes were due to production declines at
some Dunvegan wells and due to the process of tieing in the new sour natural gas
processing capacity. As a result, decreased natural gas sales were supplanted
with gas processing revenues of an almost equal amount. Additionally, these
non-unit holders spent approximately $2,500,000 increasing the Dunvegan gas
plant capacity so that the plant can now process 200,000 MCF per day. These
non-unit holders did not earn an interest in the gas plant with these
expenditures but will be charged a lower processing tariff. As a result of the
completion of the new sour gas plant at Dunvegan in October 1996, the Company
estimates that production at Dunvegan will increase next year and gas processing
fees are also expected to increase.
Marketing arrangements for the majority of the Company's natural gas
production are handled on an individual contract basis with many agreements
renegotiated annually. The Dunvegan natural gas production is sold to
aggregators under various short and long-term contracts. A minimal amount of
all production is sold on the spot market at the current market price.
Operating expenses were relatively unchanged, increasing $33,000 (1%) in
fiscal 1996 as compared to fiscal 1995, as costs remained relatively constant
and natural gas production declined 12%. The Company expects oil and natural
gas operating expenses to increase at a rate higher than inflation due to higher
costs of acquiring and developing new properties and higher costs associated
with certain older properties.
In fiscal 1995, oil and natural gas revenues decreased $3,430,000 (25%), as
compared to fiscal 1994. A $1,586,000 decontracting payment from Alberta and
Southern Gas Co., Ltd. in November 1993 was included in oil and natural gas
revenues for fiscal 1994. There was no such payment received in fiscal 1995.
This decontracting payment was the result of the termination of the Company's
Dunvegan natural gas purchase, sales and transportation agreements with Alberta
and Southern Gas Co., Ltd., effective November 1, 1993.
The remaining $1,844,000 decrease was due to a 34% decrease in natural gas
prices, partially offset by a 5% increase in natural gas production and 13% and
12% increases in oil production and prices, respectively. Additionally, the
Province of Alberta changed its royalty tax credit program effective January 1,
1995, which reduced the amount of the credit Barnwell received. The royalty tax
credit program changes resulted in a $230,000 reduction of fiscal 1995 net
earnings, as compared to fiscal 1994.
Oil and natural gas operating expenses increased $185,000 (6%) in fiscal
1995, as compared to fiscal 1994, due to new production at the Pembina, Lacombe
and Barrhead areas, and due to increased repairs and maintenance in the older
areas of the Dunvegan, Provost and Red Earth properties.
In fiscal 1994, oil and natural gas revenues increased $2,700,000 (24%) as
compared to fiscal 1993, due to 18% higher natural gas prices, partially offset
by a 12% decrease in oil prices and a 24% decrease in liquids prices. Natural
gas production increased 4% and oil production decreased 1% as compared to
fiscal 1993. Additionally, the natural gas sales contracts involving the sale
of the Company's Dunvegan natural gas were terminated effective
November 1, 1993. As a result of these contract terminations, the Company
received a compensatory payment of $1,586,000, which was recognized as income in
fiscal 1994.
Oil and natural gas operating expenses increased $365,000 (13%) for fiscal
1994, as compared to fiscal 1993, due to new production at the Hillsdown and
Thornbury areas.
Contract Drilling
- -----------------
Contract drilling revenues and operating costs are associated with water
well drilling and water pump installation in Hawaii. Overall land development
activity in Hawaii in recent years has declined, therefore demand for water well
drilling and pump installation has declined accordingly.
Contract drilling revenues and operating costs decreased $1,120,000 (30%)
and $1,005,000 (35%), respectively, in fiscal 1996 as compared to fiscal 1995,
due to lower water well drilling activity in the current fiscal year. As a
result of the lower activity, operating profit before depreciation decreased
$115,000 (13%) in fiscal 1996, as compared to fiscal 1995. Operating profit
before depreciation as a percentage of revenues increased to 29%, as compared to
23% in fiscal 1995, as the Company was able to reduce operating costs in fiscal
1996 by a higher percentage than the decrease in revenues as a result of
operational efficiencies due to all contract drilling jobs during 1996 being in
the same area; this savings is not expected to recur in the future.
The Company expects competitive pressures within the industry to continue
and potentially grow as demand for water well drilling in Hawaii is not expected
to increase in the 1997 fiscal year.
Contract drilling revenues and operating costs decreased $1,320,000 (26%)
and $1,251,000 (30%), respectively, in fiscal 1995 as compared to fiscal 1994,
due to decreased pump installation activity, partially offset by higher water
well drilling activity. Combined operating profit before depreciation decreased
$69,000 (7%) in fiscal 1995, as compared to fiscal 1994, due to less cost
efficiencies in fiscal 1995 brought on by the lower overall work performed by
the contract drilling segment.
Contract drilling revenues and operating costs increased $520,000 (11%) and
$1,035,000 (33%), respectively, in fiscal 1994 as compared to fiscal 1993, due
to higher pump installation activity, partially offset by lower water well
drilling activity. Pump installation revenues and operating costs increased
$3,010,000 (702%) and $2,311,000 (739%), respectively, in fiscal 1994, whereas
water well drilling revenues and operating costs decreased $2,446,000 (60%) and
$1,205,000 (53%), respectively, in fiscal 1994, as compared to fiscal 1993.
Combined operating profit before depreciation decreased $515,000 (35%) in fiscal
1994 primarily due to the fact that gross margins on pump installation contracts
are lower than gross margins for well drilling contracts. Additionally, water
well drilling operations were at full capacity during part of fiscal 1993,
enabling operations to be completed more efficiently.
At September 30, 1996, WRI had a backlog of one water well contract which
was in progress as of September 30, 1996, and nine pump installation contracts,
four of which were in progress as of September 30, 1996. These ten contracts
represent a backlog of contract drilling revenues of approximately $1,057,000 as
of September 30, 1996.
Investment in Land
- ------------------
In fiscal 1996, 1995, and 1994, Kaupulehu Developments entered into no land
transactions.
Expenditures applicable to the rezoning of approximately 1,000 acres of the
2,180 acres incurred subsequent to April 1995 are being capitalized. Such
costs, comprised of legal, consulting and planning fees as well as capitalized
interest, amounted to $646,000 and $293,000 for the years ended
September 30, 1996 and September 30, 1995, respectively.
In April 1995, the option under which Hualalai Development Company could
have acquired Kaupulehu Developments' leasehold interest in approximately 2,180
acres of conservation zoned property in North Kona, Hawaii, expired,
unexercised.
For three of the past four years Hawaii's economy has been in a recession.
While the current outlook is for moderate economic growth of 2% to 3%, the real
estate market is not expected to experience a measurable improvement in the near
term.
Gas Processing and Other Income
- -------------------------------
Gas processing and other income increased $210,000 (32%) in fiscal 1996, as
compared to fiscal 1995, due primarily to increased non-unit gas processed at
the Dunvegan gas plant, partially offset by a decrease in interest income as a
result of lower average cash balances and interest rates. The Company estimates
that gas revenues will continue to grow in fiscal 1997 as additional non-unit
owners tie their natural gas production into the Dunvegan gas plants.
Gas processing and other income decreased $300,000 (31%) in fiscal 1995, as
compared to fiscal 1994, due to lower average cash balances and reduced dividend
income as a result of the sale of investments in preferred stocks.
Gas processing and other income increased $60,000 (7%) in fiscal 1994, as
compared to fiscal 1993, due to increased dividend income as a result of the
Company's investments in preferred stocks.
General and Administrative Expenses
- -----------------------------------
General and administrative expenses decreased $658,000 (17%) in fiscal
1996, as compared to fiscal 1995. This decrease was due to decreased outside
services, decreased foreign currency transaction losses, and rezoning costs.
Foreign currency transaction losses were immaterial in fiscal 1996 while foreign
currency transaction losses of $176,000 were included in general and
administrative expenses in fiscal 1995. $438,000 of costs incurred by Kaupulehu
Developments for the rezoning of leasehold property under option were included
in general and administrative expenses in fiscal 1995. In fiscal 1996, rezoning
costs incurred by Kaupulehu Developments were related to leasehold property no
longer under option and were accordingly capitalized and included in investment
in land.
General and administrative expenses decreased $236,000 (6%) in fiscal 1995,
as compared to fiscal 1994, due to decreased personnel costs, decreases in
certain rezoning costs incurred by Kaupulehu Developments and non-recurring
costs related to the relocation of the corporate office in Honolulu, Hawaii.
These decreases were partially offset by $176,000 of foreign currency
transaction losses in fiscal 1995; there were no material foreign currency
transaction losses in fiscal 1994.
General and administrative expenses increased $198,000 (5%) in fiscal 1994,
as compared to fiscal 1993, due to increases in salaries, pension costs and
costs related to the relocation of the corporate office in Honolulu, Hawaii.
Depreciation, Depletion and Amortization
- ----------------------------------------
Depreciation, depletion and amortization expense decreased $143,000 (5%) to
$2,960,000 in fiscal 1996, as compared to $3,103,000 in fiscal 1995, due to
certain contract drilling assets having been fully depreciated in fiscal 1995
and a 12% decline in natural gas production, partially offset by a 10% higher
depletion rate per MCF equivalent. The depletion rate per MCF equivalent
increased to $0.44 per MCF equivalent in fiscal 1996 from $0.40 per MCF
equivalent in fiscal 1995 due to higher finding costs for proven reserve
additions in 1996 as compared to earlier years. The increase in the rate of
depletion reflects the Company's larger cost base, including estimated future
costs to complete development and process proven reserves and estimated future
site restoration expenses. Included in depreciation, depletion and amortization
is $90,000 and $85,000 in fiscal 1996 and 1995, respectively, for the
amortization of estimated future site restoration costs.
Depreciation, depletion and amortization increased $206,000 (7%) in fiscal
1995, as compared to fiscal 1994, due to a $297,000 increase in depletion,
partially offset by a $91,000 decrease in depreciation. Depletion increased due
to a 5% increase in natural gas production and an increase in the depletion rate
of $.02 per MCF equivalent (5%). The depletion rate increased due to higher
finding costs in fiscal 1995. Depreciation decreased because certain well
drilling assets were fully depreciated in fiscal 1994.
Depreciation, depletion and amortization increased $270,000 (10%) in fiscal
1994, as compared to fiscal 1993, due to a $347,000 increase in depletion,
partially offset by a $62,000 decrease in depreciation. Depletion increased due
to a 4% increase in natural gas production and an increase in the depletion rate
of $.04 per MCF equivalent (12%). The Company's depletion rate increased as a
result of the Company's capital expenditures on natural gas plants and natural
gas gathering systems. Depreciation decreased because certain corporate and
well drilling assets were fully depreciated in fiscal 1993.
Interest Expense
- ----------------
Interest expense decreased $49,000 (6%) in fiscal 1996, as compared to
fiscal 1995, due to lower average interest rates and average loan balances on
the Company's credit facility borrowings with the Royal Bank of Canada, and a
$74,000 increase in capitalization of interest costs related to the Company's
investment in land. This was partially offset by higher interest expense
attributable to the convertible notes that were issued in June 1995 and thus
outstanding for only four months in fiscal 1995. The average interest rate paid
during fiscal 1996 on the Company's debt with the Royal Bank of Canada decreased
from an average of 6.47% in fiscal 1995 to 6.33% in fiscal 1996. The interest
rate on the convertible notes was 10% per annum during both fiscal 1996 and the
last four months of fiscal 1995.
Interest expense increased $263,000 (53%) in fiscal 1995, as compared to
fiscal 1994, due to higher average interest rates on the Company's credit
facility borrowings with the Royal Bank of Canada and interest on the
convertible notes issued in June 1995. The average interest rate incurred
during fiscal 1995 on the Company's total outstanding debt was 6.67%, an
increase of 41% from fiscal 1994's average of 4.73%. The average interest rate
paid during fiscal 1995 on the Company's debt with the Royal Bank of Canada
increased 37% from an average of 4.73% in fiscal 1994 to 6.47% in fiscal 1995.
The interest rate on the convertible notes issued in June 1995 was 10% per annum
for the period June through September 1995.
Interest expense decreased $140,000 (22%) in fiscal 1994, as compared to
fiscal 1993, due to a lower average outstanding debt balance under the Company's
credit facility with the Royal Bank of Canada in fiscal 1994, as compared to
fiscal 1993. The effect of the lower outstanding debt was partially offset by
higher interest rates; the average interest rate paid during fiscal 1994 on the
Company's debt with the Royal Bank of Canada increased 20% from an average of
3.94% in fiscal 1993 to 4.73% in fiscal 1994.
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 immaterial in fiscal
1996 and 1994. During fiscal 1995, the Company realized foreign currency
transaction losses of $176,000; this amount is reflected in general and
administrative expenses in the consolidated statement of operations for fiscal
1995. The Company cannot accurately predict future fluctuations between the
Canadian and U.S. dollars.
Taxes
- -----
In November 1995, officials of the U.S. and Canada formally ratified a new
agreement amending the Canada-U.S. Tax Treaty reducing the Canadian Branch tax,
effective January 1, 1996, from 10% to 6% and, effective January 1, 1997, to 5%.
This change decreased current tax expense and deferred tax expense by
approximately $20,000 and $290,000, respectively, in fiscal 1996, as compared to
fiscal 1995.
In fiscal 1996, 1995, and 1994, 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
- ---------------------
The application of Federal, state, and Canadian regulations to protect the
environment, particularly in regard to the discharge of materials into the
environment, may increase the cost of operations for the Company's oil and
natural gas and contract drilling operations. The Company presently spends
certain non-material amounts, from time to time, to comply with environmental
regulations. Although the Company is not aware of any specific problems, recent
history may not be indicative of the amounts of expenditures that the Company
may be required to expend for these purposes in subsequent years.
Inflation
- ---------
The effect of inflation on the Company has generally been to increase its
cost of operations, interest cost (as essentially all of the Company's debt is
at variable short-term rates of interest which tend to increase as inflation
increases), general and administrative costs and direct costs associated with
oil and natural gas production and contract drilling operations. In the case of
contract drilling, the Company has not been able to increase its contract
revenues to fully compensate for increased costs. In the case of oil and
natural gas, prices realized by the Company are essentially determined by world
prices for oil and western Canadian/California/southwest U.S. prices for natural
gas.
New Statement of Financial Accounting Standards
- -----------------------------------------------
In October 1995, the Financial Accounting Standards Board issued SFAS 123,
"Accounting for Stock-Based Compensation." SFAS 123 provides an option to adopt
a new, fair value based method of measuring stock-based compensation, or to
disclose in the footnotes proforma net earnings and earnings per share
information as if the fair value based method had been adopted. The Company has
determined that it will make the required disclosures in the footnotes to its
financial statements beginning in fiscal 1997.
Item 7. FINANCIAL STATEMENTS
--------------------
Independent Auditors' Report
----------------------------
The Board of Directors
Barnwell Industries, Inc.:
We have audited the consolidated financial statements of Barnwell Industries,
Inc. and subsidiaries as listed in the index at Part III, Item 13. In
connection with our audits of the consolidated financial statements, we also
have audited the financial statement schedule as listed in the index at Part
III, Item 13. These consolidated financial statements and financial statement
schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Barnwell
Industries, Inc. and subsidiaries as of September 30, 1996 and 1995, and the
results of their operations and their cash flows for each of the years in the
three-year period ended September 30, 1996, in conformity with generally
accepted accounting principles. Also in our opinion, the related financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly, in all material
respects, the information set forth therein.
/s/ KPMG Peat Marwick LLP
Honolulu, Hawaii
November 27, 1996
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS September 30,
- ------ --------------------------
CURRENT ASSETS: 1996 1995
----------- -----------
<S> <C> <C>
Cash, interest bearing of $3,552,000 in 1996
and $2,976,000 in 1995 $ 3,553,000 $ 2,976,000
Accounts receivable (Notes 3 and 13) 2,288,000 2,485,000
Royalty tax credit and taxes receivable 181,000 215,000
Costs and estimated earnings in excess of
billings on uncompleted contracts (Note 3) 136,000 113,000
Deferred income tax assets (Note 7) 200,000 120,000
Inventories and other current assets 193,000 215,000
----------- -----------
TOTAL CURRENT ASSETS 6,551,000 6,124,000
----------- -----------
INVESTMENT IN LAND (Notes 5 and 6) 1,115,000 648,000
----------- -----------
OTHER ASSETS (Notes 3 and 4) 445,000 1,011,000
----------- -----------
PROPERTY AND EQUIPMENT (Note 6):
Land 631,000 631,000
Oil and natural gas properties
(full cost accounting) 41,897,000 37,799,000
Drilling rigs and equipment 7,911,000 7,879,000
Other property and equipment 2,646,000 2,445,000
----------- -----------
53,085,000 48,754,000
Accumulated depreciation, depletion
and amortization 30,416,000 27,757,000
----------- -----------
TOTAL PROPERTY AND EQUIPMENT 22,669,000 20,997,000
----------- -----------
TOTAL ASSETS $30,780,000 $28,780,000
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable $ 1,694,000 $ 1,065,000
Accrued expenses 678,000 523,000
Billings in excess of costs and estimated
earnings on uncompleted contracts (Note 3) 20,000 436,000
Payable to joint interest owners 637,000 457,000
Income taxes payable (Note 7) 158,000 -
----------- -----------
TOTAL CURRENT LIABILITIES 3,187,000 2,481,000
----------- -----------
LONG-TERM DEBT (Note 6) 11,100,000 11,100,000
----------- -----------
DEFERRED INCOME TAXES (Note 7) 5,090,000 4,837,000
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 8 and 10)
STOCKHOLDERS' EQUITY (Notes 6 and 9):
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 14,121,000 12,891,000
Foreign currency translation adjustments (1,925,000) (1,683,000)
Unrealized holding losses
on securities (Notes 4 and 7) (12,000) (65,000)
Treasury stock, at cost, 320,745 shares (4,705,000) (4,705,000)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY 11,403,000 10,362,000
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $30,780,000 $28,780,000
=========== ===========
<FN>
See Notes to Consolidated Financial Statements
</TABLE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended September 30,
---------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Revenues:
Oil and natural gas (Note 14) $10,660,000 $10,520,000 $13,950,000
Contract drilling 2,650,000 3,770,000 5,090,000
Gas processing and other 870,000 660,000 960,000
----------- ----------- -----------
14,180,000 14,950,000 20,000,000
----------- ----------- -----------
Costs and expenses:
Oil and natural gas operating 3,406,000 3,373,000 3,188,000
Contract drilling operating 1,885,000 2,890,000 4,141,000
General and administrative 3,114,000 3,772,000 4,008,000
Depreciation, depletion and amortization 2,960,000 3,103,000 2,897,000
Interest expense, net (Note 6) 707,000 756,000 493,000
Minority interest in losses (Note 5) - (286,000) (250,000)
----------- ----------- -----------
12,072,000 13,608,000 14,477,000
----------- ----------- -----------
Earnings before income taxes 2,108,000 1,342,000 5,523,000
Provision for income taxes (Note 7) 878,000 692,000 3,003,000
----------- ----------- -----------
NET EARNINGS $ 1,230,000 $ 650,000 $ 2,520,000
=========== =========== ===========
NET EARNINGS PER SHARE $0.93 $0.49 $1.90
=========== =========== ===========
WEIGHTED AVERAGE SHARES OUTSTANDING 1,324,400 1,326,100 1,326,500
========== ========== ==========
<FN>
See Notes to Consolidated Financial Statements
</TABLE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended September 30,
------------------------------------
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $1,230,000 $ 650,000 $2,520,000
Adjustments to reconcile
net earnings to net cash
provided by operating activities:
Depreciation, depletion and amortization 2,960,000 3,103,000 2,897,000
Deferred income taxes 237,000 (1,522,000) 564,000
Minority interest in losses - (286,000) (250,000)
---------- ---------- ----------
4,427,000 1,945,000 5,731,000
Increase (decrease) from changes in
current assets and liabilities (Note 15) 1,273,000 (21,000) (1,395,000)
---------- ---------- ----------
Net cash provided by operating activities 5,700,000 1,924,000 4,336,000
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (5,967,000) (3,930,000) (5,737,000)
Decrease (increase) in other assets 285,000 (300,000) (84,000)
Proceeds from sale of oil and natural
gas properties and other equipment 414,000 613,000 254,000
---------- ---------- ----------
Net cash used in investing activities (5,268,000) (3,617,000) (5,567,000)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net contributions from joint
venture minority interest owner 180,000 - -
Long-term debt borrowings (including
$1,900,000 from affiliates (Note 6)) - 2,000,000 -
Payment of dividends - (198,000) (396,000)
Repayment of long-term debt - (1,500,000) -
---------- ---------- ----------
Net cash provided by
(used in) financing activities 180,000 302,000 (396,000)
---------- ---------- ----------
Effect of exchange rate changes on cash (35,000) 169,000 (10,000)
---------- ---------- ----------
Net increase (decrease) in cash 577,000 (1,222,000) (1,637,000)
Cash at beginning of year 2,976,000 4,198,000 5,835,000
---------- ---------- ----------
Cash at end of year $3,553,000 $2,976,000 $4,198,000
========== ========== ==========
<FN>
See Notes to Consolidated Financial Statements
</TABLE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Foreign Unrealized
Common Stock Additional Currency Holding
------------------- Paid-In Retained Translation Gains/ Treasury
Shares Amount Capital Earnings Adjustments (Losses) Stock
--------- --------- ---------- ----------- ----------- -------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Balances at September 30, 1993 1,642,797 $ 821,000 $3,103,000 $10,183,000 $(1,777,000) $ - $(4,705,000)
Net earnings - - - 2,520,000 - - -
Dividends declared ($.20 per share) - - - (264,000) - - -
Foreign currency
translation adjustments - - - - (114,000) - -
Unrealized holding
gain on securities - - - - - 15,000 -
--------- --------- ---------- ----------- ----------- -------- -----------
Balances at September 30, 1994 1,642,797 821,000 3,103,000 12,439,000 (1,891,000) 15,000 (4,705,000)
Net earnings - - - 650,000 - - -
Dividends declared ($.15 per share) - - - (198,000) - - -
Foreign currency
translation adjustments - - - - 208,000 - -
Unrealized holding
loss on securities - - - - - (80,000) -
--------- --------- ---------- ----------- ----------- -------- -----------
Balances at September 30, 1995 1,642,797 821,000 3,103,000 12,891,000 (1,683,000) (65,000) (4,705,000)
Net earnings - - - 1,230,000 - - -
Foreign currency
translation adjustments - - - - (242,000) - -
Unrealized holding
gain on securities - - - - - 53,000 -
--------- --------- ---------- ----------- ----------- -------- -----------
Balances at September 30, 1996 1,642,797 $ 821,000 $3,103,000 $14,121,000 $(1,925,000) $(12,000) $(4,705,000)
========= ========= ========== =========== =========== ======== ===========
<FN>
See Notes to Consolidated Financial Statements
</TABLE>
BARNWELL INDUSTRIES, INC.
-------------------------
AND SUBSIDIARIES
----------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
YEARS ENDED SEPTEMBER 30, 1996, 1995, AND 1994
----------------------------------------------
1. DESCRIPTION OF THE REPORTING ENTITY AND BUSINESS
------------------------------------------------
The consolidated financial statements include the accounts of Barnwell
Industries, Inc. and all majority-owned subsidiaries, including a land
development joint venture (collectively referred to herein as "Company"). All
significant intercompany accounts and transactions have been eliminated.
During its last three completed fiscal years, the Company was engaged in
exploring for, developing, producing and selling oil and natural gas in Canada
and the United States, investing in leasehold land in Hawaii, and drilling water
wells and installing and repairing water pumping systems in Hawaii. The
Company's oil and natural gas activities comprise its largest business segment.
Approximately 75% of the Company's revenues and 85% of the Company's capital
expenditures for the fiscal year ended September 30, 1996 were attributable to
its oil and natural gas activities. The Company's contract drilling activities
accounted for 19% of the Company's revenues in fiscal 1996 with corporate and
other revenues comprising the remaining 6%. The Company had no land investment
revenue in 1996; land investment revenues relate to the sale of leasehold
interests and development rights, which do not occur every year.
2. SIGNIFICANT ACCOUNTING POLICIES
-------------------------------
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 unproven
properties, is provided by the unit-of-production method based upon proved oil
and natural gas reserves of all properties on a country by country basis.
General and administrative costs related to oil and natural gas operations are
expensed as incurred. Estimated future site restoration and abandonment costs
are charged to earnings at the rate of depletion and are included in accumulated
depreciation, depletion and amortization. Proceeds from the disposition of
minor producing oil and natural gas properties are credited to the cost of oil
and natural gas properties. Gains or losses are recognized on the disposition
of significant oil and natural gas properties.
Contract drilling
- -----------------
Revenues, costs and profits applicable to contract drilling contracts are
included in the consolidated statements of operations using the percentage of
completion method, principally measured by the percentage of labor dollars
incurred to date for each contract to total estimated labor dollars for each
contract. Contract losses are recognized in full in the year the losses are
identified. The performance of drilling contracts may extend over more than one
year and, in the interim periods, estimates of total contract costs and profits
are used to determine revenues and profits earned for reporting the results of
the contract drilling operations. Revisions in the estimates required by
subsequent performance and final contract settlements are included as
adjustments to the results of operations in the period such revisions and
settlements occur. Contracts are normally less than one year in duration.
Investment in land and revenue recognition
- ------------------------------------------
The Company accounts for its investment in land at cost plus capitalized
interest on its investment. Land sales for real estate under option as of
September 30, 1996 are accounted for under the cost recovery method. Under the
cost recovery method, no gain is recognized until cash received exceeds the cost
and the estimated future costs related to the land sold. The balance sheet
includes no cost for lands under option and, accordingly, cash receipts, if any,
in excess of costs will be reported as revenues. The Company's cost and
capitalized interest for the land not under option is included in the balance
sheet under the caption "Investment in Land."
Other Long-Term Assets
- ----------------------
Included in other assets are investments in equity securities which are
classified as available-for-sale and are reported at fair value, with unrealized
gains and losses, net of related tax effect, excluded from earnings and reported
as a separate component of stockholders' equity. A decline in the market value
of any available-for-sale security below cost that is deemed other than
temporary is charged to earnings, resulting in the establishment of a new cost
basis for the security. Cost in computing realized gains and losses is
determined using the specific identification method.
Long-Lived Assets
- -----------------
Long-lived assets other than oil and natural gas properties are evaluated
for impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be fully recoverable. If the future cash
flows expected to result from use of the asset (undiscounted and without
interest charges) are less than the carrying amount of the asset, an impairment
loss is recognized. Such impairment loss is measured as the amount by which the
carrying amount of the asset exceeds the fair value of the asset. Long-lived
assets to be disposed of are reported at the lower of the asset carrying value
or fair value, less cost to sell.
Drilling rigs and other equipment
- ---------------------------------
Drilling rigs and other equipment are stated at cost. Depreciation is
computed using the straight-line method based on estimated useful lives.
Inventories
- -----------
Inventories are comprised of drilling materials and are valued at the lower
of weighted average cost or net realizable 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
- ------------------
Primary earnings per share are based on the weighted average number of
outstanding common shares during the year after consideration of the dilutive
effect of outstanding stock options and convertible securities. Fully diluted
earnings per share is not materially different from primary earnings per share.
Foreign currency translation
- ----------------------------
Assets and liabilities of foreign operations and subsidiaries are
translated at the year-end exchange rate and resulting translation gains or
losses are accounted for in a stockholders' equity account entitled "foreign
currency translation adjustments." Operating results of foreign subsidiaries
are translated at average exchange rates during the period. Foreign currency
transaction losses amounting to $176,000 for fiscal 1995 are reflected in
general and administrative expenses in the accompanying consolidated statements
of operations; there were immaterial foreign currency transaction gains or
losses in fiscal years 1996 and 1994.
New Statement of Financial Accounting Standards
- -----------------------------------------------
In October 1995, the Financial Accounting Standards Board issued SFAS 123,
"Accounting for Stock-Based Compensation." SFAS 123 provides an option to adopt
a new, fair value based method of measuring stock-based compensation, or to
disclose in the footnotes proforma net earnings and earnings per share
information as if the fair value based method had been adopted. The Company has
determined that it will make the required disclosures in the footnotes to its
financial statements beginning in fiscal 1997.
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.
3. RECEIVABLES AND CONTRACT COSTS
------------------------------
Accounts receivable, current, are net of allowances for doubtful accounts
of $10,000 and $64,000 as of September 30, 1996 and 1995, respectively.
Included in accounts receivable are contract retainage balances of $440,000 and
$546,000 as of September 30, 1996 and 1995, respectively. These balances are
expected to be collected within one year, specifically within 45 days after the
related contracts have received final acceptance and approval.
At September 30, 1995, long-term notes and other receivables amounted to
$642,000, net of an allowance for doubtful accounts of $267,000, and are
included in other assets.
Costs and estimated earnings on uncompleted contracts are as follows:
September 30,
-----------------------
1996 1995
---------- ----------
Costs incurred on uncompleted contracts $2,385,000 $3,950,000
Estimated earnings 1,192,000 1,723,000
---------- ----------
3,577,000 5,673,000
Less billings to date 3,461,000 5,996,000
---------- ----------
$ 116,000 $ (323,000)
========== ==========
Costs and estimated earnings on uncompleted contracts are included in the
consolidated balance sheets under the following captions:
September 30,
-----------------------
1996 1995
---------- ----------
Costs and estimated earnings
in excess of billings on uncompleted contracts $ 136,000 $ 113,000
Billings in excess of costs
and estimated earnings on uncompleted contracts (20,000) (436,000)
---------- ---------
$ 116,000 $(323,000)
========== =========
4. INVESTMENTS IN EQUITY SECURITIES
--------------------------------
Included in other assets are available-for-sale equity securities. The
following summarizes the aggregate market value, cost, gross unrealized holding
gains and losses and income tax effect of available-for-sale securities:
September 30,
------------------
1996 1995
-------- --------
Market value $240,000 $163,000
Cost 258,000 261,000
-------- --------
Gross unrealized holding
losses before income tax effect (18,000) (98,000)
Income tax effect 6,000 33,000
-------- --------
Unrealized holding losses, net of
income tax effect, included in stockholders' equity $(12,000) $(65,000)
======== ========
There were no realized losses in fiscal 1996. Realized losses on trading
securities amounted to $68,000 in fiscal 1995, $58,000 of which was recognized
as unrealized holding losses in fiscal 1994.
5. INVESTMENT IN LAND
------------------
The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii joint venture. Between 1986 and 1989, Kaupulehu Developments
successfully obtained the state and county zoning changes necessary to permit
development of the newly opened Four Seasons Resort Hualalai at Historic
Ka'upulehu and Hualalai Golf Course, a second golf course, and single and
multiple family residential units. Kaupulehu Developments currently owns
development rights in approximately 100 acres of residentially zoned leasehold
land and leasehold rights in approximately 2,180 acres of land located
approximately six miles north of the Keahole Airport in the North Kona District
of the Island of Hawaii.
The approximately 100 acres zoned for residential development are in the
vicinity of and adjacent to the newly opened Hualalai Golf Course. Kaupulehu
Developments' residential development rights in these approximately 100 acres
are under option to Hualalai Development Company (formerly Kaupulehu Makai
Venture), an affiliate of Kajima Corporation of Japan. If Hualalai Development
Company exercises this option, the Company will receive $16,157,000 in
connection with its 50.1% interest in Kaupulehu Developments. The option
expires on December 31, 1999, unless 20% of the consideration is received on or
before December 31, 1999; on April 30, 2003 unless 50% of the then remaining
consideration is received on or before April 30, 2003 and the remainder of the
option would then expire on April 30, 2007. There is no assurance that this
option or any portion of it will be exercised.
The 2,180 acres of land in which Kaupulehu Developments holds leasehold
rights is located adjacent to and north of the Four Seasons Resort Hualalai.
Kaupulehu Developments is in the process of negotiating a new development
agreement and residential fee purchase prices with the lessor. Management
cannot predict the ultimate outcome of these negotiations.
In 1993, Kaupulehu Developments submitted a rezoning petition to the State
Land Use Commission to reclassify approximately 1,000 of the 2,180 acres to
allow for the development of a residential community with recreational and
commercial areas, in conformance with the Hawaii County General Plan designation
for the area. The proposed developments include 500 multi-family units, 530
residential single-family home sites, a commercial center and two 18-hole golf
courses. The remaining 1,180 acres, located in the eastern portion of the
property, is classified within the State Land Use Conservation District and
zoned unplanned by the County.
In June 1996, the State Land Use Commission (LUC) approved the Company's
petition for reclassification of the approximately 1,000 acres of conservation
zoned 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. If the LUC's decision is upheld, Kaupulehu Developments must then
obtain an additional series of approvals from various state and county agencies;
there is no assurance that these approvals will be forthcoming at any time.
Costs related to the rezoning of the conservation land are capitalized and
included in investment in land.
6. LONG-TERM DEBT
--------------
The Company has a credit facility at the Royal Bank of Canada, a Canadian
bank, for $15,000,000 Canadian dollars, or its U.S. dollar equivalent of
approximately $11,000,000 at September 30, 1996. Borrowings under this facility
were $9,100,000 at September 30, 1996 and 1995, and are included in long-term
debt.
The facility is available in U.S. dollars at the London Interbank Offer
Rate ("LIBOR") plus 3/4%, at U.S. prime plus 1/2%, or in Canadian dollars at
Canadian prime plus 1/2%. Under the financing agreement, the facility is
reviewed annually, with the next review planned for February 1997. 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, 1996, the Company paid interest at rates
ranging from 6.063% to 6.625%. At September 30, 1996, the rate was 6.188%. 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 on any of
the Company's indebtedness. At September 30, 1996, the Company had unused
credit available under this facility of approximately $1,900,000.
In June 1995, the Company issued $2,000,000 of convertible notes due
July 1, 2003. $400,000 of such notes were purchased by Mr. Morton H. Kinzler,
President, Chief Executive Officer and Chairman of the Board of Directors of the
Company, $200,000 were purchased by Mr. Martin Anderson, a director, $200,000
were purchased by Dr. Joseph E. Magaro, a 15.9% shareholder of the Company,
$100,000 were purchased by Dr. R. David Sudarsky, a 9.2% shareholder of the
Company, and $1,000,000 were purchased by Ingalls and Snyder Value Partners,
L.P., an affiliate of a 7.5% shareholder of the Company. The notes are payable
in 20 consecutive equal quarterly installments beginning in October 1998.
Interest is payable quarterly at an interest rate to be adjusted quarterly 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 1996. The notes are unsecured and convertible at any time at the
holder's option into shares of the Company's common stock at a price of $20.00
per share, subject to adjustment for certain events including a stock split of,
or stock dividend on, the Company's common stock. The notes are redeemable, at
the option of the Company, at any time after July 1, 1997, at premiums declining
1% annually from 5% to 0% of the principal amount of the notes. These notes,
amounting to $2,000,000 at September 30, 1996 and 1995, are included in
long-term debt.
At September 30, 1996, the maturities of long-term debt, exclusive of the
credit facility with the Canadian bank, are as follows:
1997 $ -
1998 -
1999 400,000
2000 400,000
2001 400,000
Thereafter 800,000
----------
$2,000,000
==========
The Company capitalized interest related to its investment in land.
Interest expense for the years ended September 30, 1996, 1995 and 1994 are as
follows:
1996 1995 1994
--------- --------- ---------
Interest costs incurred $ 794,000 $ 769,000 $ 493,000
Less interest costs
capitalized on investment in land 87,000 13,000 -
--------- --------- ---------
Interest expense $ 707,000 $ 756,000 $ 493,000
========= ========= =========
7. TAXES ON INCOME
---------------
The components of earnings/(loss) before income taxes are as follows:
Year ended September 30,
----------------------------------------
1996 1995 1994
------------ ----------- -----------
United States $ (1,200,000) $(1,444,000) $(1,446,000)
Canadian 3,308,000 2,786,000 6,969,000
------------ ----------- -----------
$ 2,108,000 $ 1,342,000 $ 5,523,000
============ =========== ===========
The components of the provision for income taxes related to the above
earnings/(loss) are as follows:
Year ended September 30,
------------------------------------
1996 1995 1994
---------- ---------- ----------
Current:
United States - Federal $ (67,000) $1,069,000 $ 170,000
United States - State and local (51,000) 241,000 -
---------- ---------- ----------
United States - total (118,000) 1,310,000 170,000
Canadian 759,000 904,000 2,269,000
---------- ---------- ----------
Total current 641,000 2,214,000 2,439,000
---------- ---------- ----------
Deferred:
United States 56,000 (1,420,000) (60,000)
Canadian 181,000 (102,000) 624,000
---------- ---------- ----------
Total deferred 237,000 (1,522,000) 564,000
---------- ---------- ----------
$ 878,000 $ 692,000 $3,003,000
========== ========== ==========
In November 1995, officials of the U.S. and Canada formally ratified a new
agreement amending the Canada-U.S. Tax Treaty that reduced the Canadian Branch
tax, effective January 1, 1996, from 10% to 6% and, effective January 1, 1997,
to 5%. This change resulted in the recognition of a deferred Canadian income
tax benefit of $290,000 in the year ended September 30, 1996.
For fiscal 1996 and 1994, $27,000 and $9,000, respectively, of deferred
income taxes related to changes in the unrealized holding gain or loss on
available for sale securities were reflected as a charge to stockholders'
equity. For fiscal 1995, $42,000 of deferred income taxes related to changes in
the unrealized holding loss on available for sale securities was reflected as a
credit to stockholders' equity.
A reconciliation between the reported provision for income taxes and the
amount computed by multiplying the earnings before income taxes by the United
States federal tax rate is as follows:
Year ended September 30,
-----------------------------------
1996 1995 1994
---------- ---------- ----------
Tax computed by applying statutory rate $ 738,000 $ 470,000 $1,933,000
Effect of foreign tax
provision on the total tax provision 492,000 206,000 960,000
Effect on deferred income
tax assets and liabilities of
reduction in Canadian Branch tax rate (290,000) - -
Other (62,000) 16,000 110,000
---------- ---------- ----------
$ 878,000 $ 692,000 $3,003,000
========== ========== ==========
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at
September 30, 1996 and 1995 are as follows:
Deferred income tax assets: 1996 1995
----------- -----------
Tax basis in land in excess of book basis $ 1,092,000 $ 1,106,000
Write-off of asset not deducted for tax 148,000 148,000
U.S. tax effect of deferred Canadian taxes 2,073,000 2,049,000
Foreign tax credit carryforward 214,000 319,000
Other 601,000 520,000
----------- -----------
Total gross deferred tax assets 4,128,000 4,142,000
Less-valuation allowance (2,408,000) (2,368,000)
----------- -----------
Net deferred income tax assets 1,720,000 1,774,000
----------- -----------
Deferred income tax liabilities:
Property and equipment tax depreciation
and depletion in excess of book (6,098,000) (6,028,000)
Other (512,000) (463,000)
----------- -----------
Total deferred income tax liabilities (6,610,000) (6,491,000)
----------- -----------
Net deferred income tax liability $(4,890,000) $(4,717,000)
=========== ===========
The net change in the total valuation allowance for the years ended
September 30, 1996 and 1995 was a $40,000 increase and $10,000 decrease,
respectively. The increase for the year ended September 30, 1996 relates
primarily to state of Hawaii net operating loss carryforwards which are more
likely than not to expire before utilization. Net operating loss carryforwards
for state of Hawaii tax purposes were approximately $2,900,000 at September 30,
1996, expiring between fiscal years 2000 and 2011.
A valuation allowance is provided when it is more likely than not that some
portion of the deferred tax asset will not be realized. The Company has
established a valuation allowance for Canadian tax deductions, foreign tax
credits 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 for U.S. tax
purposes. Net deferred tax assets will primarily be realized through the
deduction of the cost basis in investment in land against proceeds from
investment in land for tax purposes. Under the cost recovery accounting method,
this cost basis has already been expensed for book purposes. The amount of
deferred income tax assets considered realizable may be reduced in the near term
if estimates of future taxable income are reduced.
8. 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, 1996 are invested as follows: 75% listed government
mortgages, 20% common stocks and 5% cash.
The funded status of the pension plan and the amounts recognized in the
consolidated financial statements is as follows:
September 30,
--------------------------
1996 1995
----------- -----------
Accumulated benefit obligation, including
vested benefits of $1,369,000 and
$1,482,000, respectively $ 1,422,000 $ 1,530,000
=========== ===========
Projected benefit obligation for service
rendered to date $(1,812,000) $(1,925,000)
Plan assets at fair market value 1,928,000 1,815,000
----------- -----------
Plan assets greater (less) than
projected benefit obligation 116,000 (110,000)
Unrecognized net gain from past
experience different from that assumed
and effects of changes in assumptions (175,000) (7,000)
Unrecognized prior service cost 51,000 57,000
Unrecognized net asset at
October 1, 1988 being recognized over 12.3 years (5,000) (5,000)
----------- -----------
Accrued pension cost $ (13,000) $ (65,000)
=========== ===========
As of September 30, 1996 and 1995, the discount rate assumed in determining
the actuarial present value of the projected benefit obligation was 7.5%.
Net pension cost includes the following components:
Year ended September 30,
-------------------------------
1996 1995 1994
-------- -------- --------
Service cost, benefits earned during the year $ 61,000 $ 38,000 $138,000
Interest cost on projected benefit obligation 130,000 126,000 135,000
Actual return on plan assets, (gain) loss (151,000) (217,000) 8,000
Net amortization and deferral 13,000 90,000 (122,000)
-------- -------- --------
Net pension cost $ 53,000 $ 37,000 $159,000
======== ======== ========
Year ended September 30,
-------------------------------
1996 1995 1994
---------- -------- ---------
Assumed rate of increase in future
compensation levels 6.0% 6.0% 6.0%
==== ==== ====
Expected long-term rate of return on assets 8.0% 8.0% 9.0%
==== ==== ====
9. COMMON STOCK
------------
In March 1995, the Company granted 20,000 non-qualified stock options to an
officer of the Company at a purchase price of $19.625 per share (market price on
date of grant), with 4,000 of such options vesting annually commencing one year
from the date of grant. These options have stock appreciation rights which
permit the holder to receive stock, cash or a combination thereof equal to the
amount by which the fair market value, at the time of exercise of the option,
exceeds the option price. The options expire ten years from the date of grant.
The Company had a stock option plan ("Option Plan") which became effective
November 1981 and expired November 1991. Under the Option Plan, options to
purchase a maximum of 120,000 shares of the Company's common stock could be
granted to officers and key employees of the Company and its subsidiaries at
prices not less than 100% of the fair market value at the date of the option
grant. Options granted under this plan became exercisable 25% annually
beginning one year from the date of grant and expire five or ten years from the
date of grant.
Option transactions during fiscal 1996, 1995 and 1994 are as follows:
Options
------------------------
Outstanding Exercisable
----------- -----------
Balance at September 30, 1993 44,000 44,000
Canceled (20,000) (20,000)
--------- ---------
Balance at September 30, 1994 24,000 24,000
Issued ($19.625 per share) 20,000 -
--------- ---------
Balance at September 30, 1995 44,000 24,000
Became exercisable - 4,000
--------- ---------
Balance at September 30, 1996 44,000 28,000
========= =========
Exercisable options at September 30, 1996 are as follows:
Per share price Number of options
--------------- -----------------
$13.625 14,000
$19.625 4,000
$22.250 10,000
------
Total 28,000
======
Privately negotiated repurchases of common stock may be made if suitable
opportunities become available. At September 30, 1996, the Company could
purchase an additional 19,800 shares under a March 1991 stock repurchase
authorization.
10. 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
$750,000 loan facility, granted by a bank, to three participants in one of the
Company's oil and natural gas ventures. At September 30, 1996, the loan balance
was $386,000, $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 several operating leases for office space. Rental expense
was $398,000 in 1996, $392,000 in 1995, and $386,000 in 1994. The Company is
committed under several non-cancelable operating leases for office and other
space with minimum rental payments summarized by fiscal year period as follows:
1997 - $393,000, 1998 - $384,000, 1999 - $369,000, 2000 - $366,000, 2001 -
$318,000 and thereafter an aggregate of $1,800,000.
The Company has committed to construct $200,000 of improvements at its yard
at Sand Island on Oahu, Hawaii, by June 1997.
11. SEGMENT AND GEOGRAPHIC INFORMATION
----------------------------------
The Company operates in three industries: oil and natural gas exploration,
development and production, contract drilling and land investment.
<TABLE>
<CAPTION>
Segment information is as follows:
Depreciation,
YEAR ENDED depletion and Operating Capital
SEPTEMBER 30, 1996 Revenues amortization Profit/(loss) expenditures
- ------------------ ----------- ------------- ------------- ------------
<S> <C> <C> <C> <C>
Oil and natural gas $10,660,000 $ 2,658,000 $ 4,596,000 $ 5,049,000
Contract drilling 2,650,000 172,000 593,000 53,000
Land investment - - - 646,000
Corporate and other 717,000 130,000 587,000 219,000
----------- ------------- ------------ ------------
Total $14,027,000 $ 2,960,000 5,776,000 $ 5,967,000
=========== ============= ============
General and administrative expenses (3,114,000)
Interest expense (net of
interest income of $153,000) (554,000)
------------
Earnings before income taxes $ 2,108,000
============
Depreciation,
YEAR ENDED depletion and Operating Capital
SEPTEMBER 30, 1995 Revenues amortization Profit/(loss) expenditures
- ------------------ ----------- ------------- ------------- ------------
Oil and natural gas $10,520,000 $ 2,658,000 $ 4,489,000 $ 3,434,000
Contract drilling 3,770,000 317,000 563,000 83,000
Land investment - - - 293,000
Corporate and other 420,000 128,000 292,000 120,000
----------- ------------- ------------ ------------
Total $14,710,000 $ 3,103,000 5,344,000 $ 3,930,000
=========== ============= ============
General and administrative expenses (3,772,000)
Interest expense (net of
interest income of $240,000) (516,000)
Minority interest in losses 286,000
------------
Earnings before income taxes $ 1,342,000
============
Depreciation,
YEAR ENDED depletion and Operating Capital
SEPTEMBER 30, 1994 Revenues amortization Profit/(loss) expenditures
- ------------------ ----------- ------------- ------------- ------------
Oil and natural gas $13,950,000 $ 2,361,000 $ 8,401,000 $ 5,350,000
Contract drilling 5,090,000 441,000 508,000 94,000
Land investment - - - -
Corporate and other 760,000 95,000 665,000 293,000
----------- ------------- ------------ ------------
Total $19,800,000 $ 2,897,000 9,574,000 $ 5,737,000
=========== ============= ============
General and administrative expenses (4,008,000)
Interest expense (net of
interest income of $200,000) (293,000)
Minority interest in losses 250,000
------------
Earnings before income taxes $ 5,523,000
============
</TABLE>
<TABLE>
<CAPTION>
September 30,
----------------------------------------------------
ASSETS BY SEGMENT: 1996 1995 1994
- ------------------ ---------------- ----------------- ----------------
<S> <C> <C> <C>
Oil and natural gas (1) $22,622,000 73% $20,918,000 73% $21,555,000 70%
Contract drilling (2) 1,911,000 6% 2,461,000 9% 2,881,000 9%
Land investment (2) 1,115,000 4% 648,000 2% - -
Other:
Cash 3,553,000 12% 2,976,000 10% 4,198,000 14%
Corporate and other 1,579,000 5% 1,777,000 6% 1,988,000 7%
----------- ---- ----------- ---- ----------- ----
Total $30,780,000 100% $28,780,000 100% $30,622,000 100%
=========== ==== =========== ==== =========== ====
<FN>
(1) Primarily located in the Province of Alberta, Canada.
(2) Located in Hawaii.
</TABLE>
<TABLE>
<CAPTION>
Geographic information is as follows:
September 30,
------------------------------------------------------
ASSETS BY GEOGRAPHIC AREA: 1996 1995 1994
- -------------------------- ----------------- ----------------- ----------------
<S> <C> <C> <C>
United States $ 6,880,000 22% $ 6,308,000 22% $ 6,380,000 21%
Canada 23,900,000 78% 22,472,000 78% 24,242,000 79%
----------- ---- ----------- ---- ----------- ----
Total $30,780,000 100% $28,780,000 100% $30,622,000 100%
=========== ==== =========== ==== =========== ====
CAPITAL EXPENDITURES BY Year Ended September 30,
- ----------------------- ------------------------------------------------------
GEOGRAPHIC AREA: 1996 1995 1994
- ---------------- ----------------- ----------------- ----------------
United States $ 1,100,000 18% $ 780,000 20% $ 462,000 8%
Canada 4,867,000 82% 3,150,000 80% 5,275,000 92%
----------- ---- ----------- ---- ----------- ----
Total $ 5,967,000 100% $ 3,930,000 100% $ 5,737,000 100%
=========== ==== =========== ==== =========== ====
</TABLE>
OPERATIONS BY GEOGRAPHIC AREA:
- ------------------------------ Depreciation
depletion and Operating
Revenue amortization Profit
----------- ------------- ----------
YEAR ENDED
SEPTEMBER 30, 1996
- ------------------
United States $ 2,938,000 $ 404,000 $ 592,000
Canada 11,089,000 2,556,000 5,184,000
----------- ------------ ----------
Total $14,027,000 $ 2,960,000 $5,776,000
=========== ============ ==========
YEAR ENDED
SEPTEMBER 30, 1995
- ------------------
United States $ 3,965,000 $ 448,000 $ 613,000
Canada 10,745,000 2,655,000 4,731,000
----------- ------------ ----------
Total $14,710,000 $ 3,103,000 $5,344,000
=========== ============ ==========
YEAR ENDED
SEPTEMBER 30, 1994
- ------------------
United States $ 5,528,000 $ 489,000 $ 898,000
Canada 14,272,000 2,408,000 8,676,000
----------- ------------ ----------
Total $19,800,000 $ 2,897,000 $9,574,000
=========== ============ ==========
Depletion per 1,000 cubic feet of natural gas (MCF) and natural gas
equivalent was $0.44 in fiscal 1996, $0.40 in fiscal 1995 and $0.38 in fiscal
1994. The increases in the per unit rate were due to increasingly higher
finding costs.
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
-----------------------------------
The following methods and assumptions are used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value. The carrying amount of cash and short-term investments approximates
fair value because of the short maturity of these instruments. The fair values
of long-term investments are estimated based on quoted market prices for those
or similar investments. The fair value of the Company's long-term debt is
estimated based on the quoted price for the same or similar instruments.
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 19% and 15% of its oil
and natural gas revenues in fiscal 1996 and 1995, respectively, from one
company. In fiscal 1994, the Company had one significant customer, which
accounted for 10% of the Company's oil and natural gas sales, exclusive of the
$1,586,000 decontracting payment (See note 14). At September 30, 1996, the
Company had a receivable from the aforementioned company of approximately
$140,000.
The Company's contract drilling subsidiary derived 42%, 28% and 40% of its
contract drilling revenues in fiscal 1996, 1995, and 1994, respectively,
pursuant to state of Hawaii and local county contracts. At September 30, 1996,
the Company had accounts receivable from the state of Hawaii and local county
entities totaling approximately $280,000. The Company has lien rights on
contracts with the state of Hawaii and local county entities.
Historically, the Company has not incurred any significant credit related
losses on its trade receivables, and management does not believe significant
credit risk related to these trade receivables exists at September 30, 1996.
14. OIL AND NATURAL GAS REVENUES
----------------------------
In compliance with certain regulatory events and orders in the U.S. and
Canada affecting the sale and delivery of Canadian natural gas supplies to the
California market, the Company's Dunvegan natural gas purchase, sales and
transportation agreements with Alberta and Southern Gas Co., Ltd., were
terminated on November 1, 1993. As a result of these contract terminations, the
Company received a compensatory payment of U.S. $1,586,000 on November 1, 1993.
This payment is included in Revenues - oil and natural gas in the consolidated
statement of operations for the year ended September 30, 1994.
15. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
-------------------------------------------------
<TABLE>
<CAPTION>
The following details the effect of changes in current assets and
liabilities on the statements of cash flows, and presents supplemental cash flow
information:
Year ended September 30,
----------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Increase (decrease) from changes in:
Proceeds from sale
(purchases) of trading securities $ - $ 958,000 $ (978,000)
Receivables 593,000 131,000 (619,000)
Costs and estimated earnings in excess
of billings on uncompleted contracts (23,000) 85,000 (4,000)
Inventories 43,000 7,000 (24,000)
Other current assets (68,000) 62,000 (152,000)
Accounts payable 645,000 (457,000) 366,000
Accrued expenses 67,000 (272,000) 52,000
Billings in excess of costs and
estimated earnings on uncompleted
contracts (416,000) 185,000 (213,000)
Payable to joint interest owners 274,000 118,000 (315,000)
Income taxes payable 158,000 (838,000) 492,000
----------- ----------- -----------
Increase (decrease) from changes
in current assets and liabilities $ 1,273,000 $ (21,000) $(1,395,000)
=========== =========== ===========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 740,000 $ 764,000 $ 471,000
=========== =========== ===========
Income taxes $ 614,000 $ 3,288,000 $ 1,914,000
=========== =========== ===========
</TABLE>
16. SUBSEQUENT EVENT
----------------
In November 1996, the Company entered into a participation agreement with
KEP Energy Resources LLC and Presco Inc., to develop natural gas and oil
reserves in the Central Basin in Michigan. The Company raised $1,575,000 from
participants (including certain officers, directors, and employees of the
Company) and then acquired a 12.5% interest in this development program that
encompasses approximately 220,000 net acres. Sixty percent (60%) of the
Company's 12.5% interest was allocated to the participants at the same price and
upon terms substantially the same and no more favorable than those under which
the Company acquired its interest. Under the terms of agreements with these
participants, 30% of the participants' 7.5% interest will revert to the Company
after the participants receive a return of their entire investment.
17. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION
---------------------------------------------
The following tables summarize information relative to the Company's oil
and natural gas operations, which are substantially all conducted in Canada.
Proved reserves are the estimated quantities of crude oil, condensate and
natural gas which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed producing oil and natural
gas reserves are reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods. The estimated net interests
in total proved developed and proved developed producing reserves are based upon
subjective engineering judgments and may be affected by the limitations inherent
in such estimations. The process of estimating reserves is subject to continual
revision as additional information becomes available as a result of drilling,
testing, reservoir studies and production history. There can be no assurance
that such estimates will not be materially revised in subsequent periods.
(A) Oil and Natural Gas Reserves (Unaudited)
----------------------------------------
The following table, based on information prepared by independent petroleum
engineers, Paddock Lindstrom and Associates, Ltd., summarizes changes in the
estimates of the Company's net interests in total proved developed reserves of
crude oil and condensate and natural gas ("MCF" means 1,000 cubic feet of
natural gas) which are substantially all in Canada:
OIL GAS
Proved developed reserves: (Barrels) (MCF)
--------- ----------
Balance at September 30, 1993 2,222,000 50,711,000
Revisions of previous estimates 132,000 (775,000)
Extensions, discoveries and other additions 366,000 6,890,000
Less production (272,000) (4,679,000)
Sales of reserves in place (21,000) (297,000)
--------- ----------
Balance at September 30, 1994 2,427,000 51,850,000
Revisions of previous estimates 101,000 1,356,000
Extensions, discoveries and other additions 97,000 1,041,000
Less production (296,000) (4,916,000)
Sales of reserves in place (33,000) (2,585,000)
--------- ----------
Balance at September 30, 1995 2,296,000 46,746,000
Revisions of previous estimates 252,000 1,357,000
Extensions, discoveries and other additions 116,000 2,852,000
Less production (279,000) (4,347,000)
Sales of reserves in place (11,000) (356,000)
--------- ----------
Balance at September 30, 1996 2,374,000 46,252,000
========= ==========
OIL GAS
Proved developed producing reserves at: (Barrels) (MCF)
--------- ----------
September 30, 1993 2,005,000 35,895,000
========= ==========
September 30, 1994 2,133,000 34,624,000
========= ==========
September 30, 1995 2,025,000 31,700,000
========= ==========
September 30, 1996 2,108,000 33,096,000
========= ==========
Included in the above tables are proved developed producing reserves in the
U.S. of 50,000 barrels of oil and 39,000 MCF of gas at September 30, 1996, and
59,000 barrels of oil and 40,000 MCF of gas at September 30, 1995.
(B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities
----------------------------------------------------------------------
September 30,
---------------------------------------
1996 1995 1994
----------- ----------- -----------
Proved properties $39,277,000 $35,438,000 $32,562,000
Unproved properties 2,401,000 2,361,000 2,279,000
----------- ----------- -----------
Total capitalized costs 41,678,000 37,799,000 34,841,000
Accumulated depletion
and depreciation 21,033,000 18,644,000 15,897,000
----------- ----------- -----------
Net capitalized costs $20,645,000 $19,155,000 $18,944,000
=========== =========== ===========
(C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and
---------------------------------------------------------------------------
Development
-----------
Year ended September 30,
-----------------------------------
1996 1995 1994
---------- ---------- ----------
Acquisition of properties:
Unproved $ 529,000 $ 176,000 $ 589,000
========== ========== ==========
Proved $ 124,000 $ 152,000 $ 292,000
========== ========== ==========
Exploration costs $1,057,000 $ 273,000 $1,662,000
========== ========== ==========
Development costs $3,339,000 $2,833,000 $2,807,000
========== ========== ==========
Included in the table above are capital expenditures of $380,000, $336,000
and $112,000 in fiscal 1996, 1995 and 1994, respectively, in the United States.
(D) The Results of Operations of Barnwell's Oil and Natural Gas Producing
----------------------------------------------------------------------
Activities, Which Exclude Corporate Overhead and Interest and, in Fiscal
------------------------------------------------------------------------
1994, Contract Termination Fees of $1,586,000
---------------------------------------------
Year ended September 30,
---------------------------------------
1996 1995 1994
----------- ----------- -----------
Gross revenues $11,801,000 $11,367,000 $14,321,000
Royalties, net of credit 1,141,000 847,000 1,957,000
----------- ----------- -----------
Net revenues 10,660,000 10,520,000 12,364,000
Production costs 3,406,000 3,373,000 3,188,000
Depletion and depreciation 2,658,000 2,658,000 2,361,000
----------- ----------- -----------
Pre-tax results of operations 4,596,000 4,489,000 6,815,000
Estimated income tax expense 2,441,000 2,338,000 3,634,000
----------- ----------- -----------
Results of operations $ 2,155,000 $ 2,151,000 $ 3,181,000
=========== =========== ===========
Revenues of $266,000 and $160,000 were received in fiscal 1996 and 1995,
respectively, from U.S. oil and natural gas properties; no revenues were
received in fiscal 1994 from U.S. oil and natural gas properties.
(E) Standardized Measure, Including Year-to-Year Changes Therein, of Discounted
---------------------------------------------------------------------------
Future Net Cash Flows (Unaudited)
---------------------------------
The following tables have been developed pursuant to procedures prescribed
by SFAS 69, and utilize reserve and production data estimated by petroleum
engineers. The information may be useful for certain comparison purposes but
should not be solely relied upon in evaluating the Company or its performance.
Moreover, the projections should not be construed as realistic estimates of
future cash flows, nor should the standardized measure be viewed as representing
current value.
The future cash flows are based on sales prices, costs, and statutory
income tax rates in existence at the dates of the projections. Material
revisions to reserve estimates may occur in the future, development and
production of the oil and natural gas reserves may not occur in the periods
assumed and actual prices realized and actual costs incurred are expected to
vary significantly from those used. Management does not rely upon this
information in making investment and operating decisions; rather, those
decisions are based upon a wide range of factors, including estimates of
probable reserves as well as proved reserves and price and cost assumptions
different than those reflected herein.
<TABLE>
<CAPTION>
Standardized Measure of Discounted Future Net Cash Flows
- --------------------------------------------------------
As of September 30,
--------------------------------------------
1996 1995 1994
------------ ------------ ------------
<S> <C> <C> <C>
Future cash inflows $ 91,916,000 $ 74,143,000 $107,440,000
Future production costs (24,466,000) (25,690,000) (30,147,000)
Future development costs (1,447,000) (2,289,000) (2,668,000)
------------ ------------ ------------
Future net cash
flows before income taxes 66,003,000 46,164,000 74,625,000
Future income tax expenses (20,424,000) (12,341,000) (22,677,000)
------------ ------------ ------------
Future net cash flows 45,579,000 33,823,000 51,948,000
10% annual discount
for timing of cash flows (18,485,000) (13,473,000) (20,686,000)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 27,094,000 $ 20,350,000 $ 31,262,000
============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
Changes in the Standardized Measure of Discounted Future Net Cash Flows
- -----------------------------------------------------------------------
Year ended September 30,
-------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Beginning of year $20,350,000 $31,262,000 $29,136,000
----------- ----------- -----------
Sales of oil and natural gas
produced, net of production costs (7,254,000) (7,147,000) (9,176,000)
Net changes in prices and
production costs, net of
royalties and wellhead taxes 15,257,000 (13,335,000) 3,214,000
Extensions and discoveries 2,173,000 941,000 5,306,000
Sales of reserves in place (415,000) (482,000) (161,000)
Revisions of previous quantity estimates 366,000 63,000 1,114,000
Net change in Canadian
dollar translation rate (290,000) (144,000) (287,000)
Changes in the timing of
future production and other (346,000) (604,000) (1,120,000)
Net change in income taxes (4,896,000) 6,413,000 (366,000)
Accretion of discount 2,149,000 3,383,000 3,602,000
----------- ----------- -----------
Net change 6,744,000 (10,912,000) 2,126,000
----------- ----------- -----------
End of year $27,094,000 $20,350,000 $31,262,000
=========== =========== ===========
</TABLE>
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 1997 Annual Meeting of Stockholders not later than 120 days after the
close of its fiscal year ended September 30, 1996, which proxy statement is
incorporated herein by reference.
Item 13. Exhibits and Reports on Form 8-K
(A) 1. Financial Statements
The following consolidated financial statements of Barnwell Industries,
Inc. and its subsidiaries are included in Part II, Item 7:
Independent Auditors' Report - KPMG Peat Marwick LLP
Consolidated Balance Sheets - September 30, 1996 and 1995
Consolidated Statements of Operations -
for the three years ended September 30, 1996
Consolidated Statements of Cash Flows -
for the three years ended September 30, 1996
Consolidated Statements of Stockholders' Equity -
for the three years ended September 30, 1996
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts and Reserves
All other schedules have been omitted because they were not applicable, not
required, or the information is included in the 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, 1996.
(C) Exhibits
No. 3.1 Certificate of Incorporation
No. 3.2 Amended and Restated By-Laws
No. 4.0 Form of the Registrant's certificate of common stock, par value
$.50 per share.
No. 10.4 The Barnwell Industries, Inc. Employees' Pension Plan (restated
as of October 1, 1989).
Exhibits 3.1 and 3.2 are incorporated by reference to the Exhibits 3.3
and 3.4, respectively, to the Registrant's Form S-8 dated November 8,
1991. Exhibit 4.0 is incorporated by reference to the registration
statement on Form S-1 originally filed by the Registrant January 29, 1957
and as amended February 15, 1957 and February 19, 1957. Exhibit 10.4 is
incorporated by reference to Form 10-K for the year ended September 30,
1989.
No. 10.17 Phase I Makai Development Agreement dated June 30, 1992, by and
between Kaupulehu Makai Venture and Kaupulehu Developments.
No. 10.18 KD/KMV Agreement dated June 30, 1992 by and between Kaupulehu
Makai Venture and Kaupulehu Developments.
Exhibits 10.17 and 10.18 are incorporated by reference to Form 10-K for
the year ended September 30, 1992.
No. 21 Subsidiaries of the Registrant.
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC.
AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Balance at Additions Balance
beginning charged to at end
of year expense Deductions of year
---------- ----------- ---------- --------
YEAR ENDED SEPTEMBER 30, 1996:
<S> <C> <C> <C> <C> <C>
Allowance for doubtful
accounts - accounts
receivable $ 64,000 $ - $ 54,000 (1) $ 10,000
Allowance for doubtful
accounts - long-term notes
receivable 267,000 - 267,000 (2) -
-------- -------- -------- --------
Total allowance for doubtful
accounts $331,000 $ - $321,000 $ 10,000
======== ======== ======== ========
YEAR ENDED SEPTEMBER 30, 1995:
Allowance for doubtful
accounts - accounts
receivable $ 26,000 $ 38,000 $ - $ 64,000
Allowance for doubtful
accounts - long-term notes
receivable 267,000 - - 267,000
-------- -------- -------- --------
Total allowance for doubtful
accounts $293,000 $ 38,000 $ - $331,000
======== ======== ======== ========
YEAR ENDED SEPTEMBER 30, 1994:
Allowance for doubtful
accounts - accounts
receivable $ 26,000 $ 34,000 $ 34,000 (2) $ 26,000
Allowance for doubtful
accounts - long-term notes
receivable 267,000 - - 267,000
-------- -------- -------- --------
Total allowance for doubtful
accounts $293,000 $ 34,000 $ 34,000 $293,000
======== ======== ======== ========
<FN>
(1) Collections.
(2) Accounts written off less recoveries.
</TABLE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BARNWELL INDUSTRIES, INC.
(Registrant)
/s/ Russell M. Gifford
-------------------------------
By: Russell M. Gifford
Chief Financial Officer,
Vice President and
Treasurer
Date: December 5, 1996
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, 1996
/s/ Martin Anderson /s/ Alan D. Hunter
- ---------------------------------------- --------------------------------------
MARTIN ANDERSON, Director ALAN D. HUNTER, Director
Date: December 6, 1996 Date: December 6, 1996
/s/ H. Whitney Boggs, Jr. /s/ Daniel Jacobson
- ---------------------------------------- --------------------------------------
H. WHITNEY BOGGS, JR., Director DANIEL JACOBSON, Director
Date: December 6, 1996 Date: December 5, 1996
/s/ Barry E. Emes /s/ William C. Warren
- ---------------------------------------- --------------------------------------
BARRY E. EMES, Director WILLIAM C. WARREN, Director
Date: December 5, 1996 Date: December 6, 1996
/s/ Erik Hazelhoff-Roelfzema /s/ Glenn Yago
- ---------------------------------------- --------------------------------------
ERIK HAZELHOFF-ROELFZEMA, Director GLENN YAGO, Director
Date: December 6, 1996 Date: December 5, 1996
/s/ Murray C. Gardner
- ---------------------------------------
MURRAY C. GARDNER, Director
Date: December 6, 1996
Exhibit 21 List of Subsidiaries
The subsidiaries of Barnwell Industries, Inc., at September 30, 1996 were:
Percentage Jurisdiction of
Name of Subsidiary of Ownership Incorporation
- ------------------ ------------ ---------------
Barnwell of Canada, Limited 100% Delaware
Barnwell Hawaiian Properties, Inc. 100% Delaware
Water Resources International, Inc. 100% Delaware
Barnwell Management Co., Inc. 100% Delaware
Barnwell Shallow Oil, Inc. 100% Delaware
Barnwell Geothermal Corporation 100% Delaware
Barnwell Mining Co. 100% Delaware
Barnwell Overseas, Inc. 100% Delaware
Victoria Properties, Inc. 100% Delaware
Barnwell Israel, Ltd. 100% Israel
Barnwell Oil & Gas, Ltd. 100% Israel
Bill Robbins Drilling, Ltd. 100% Alberta, Canada
Dartmouth Petroleum, Ltd. 100% Alberta, Canada
Gypsy Petroleums Ltd. 100% Alberta, Canada
J.H. Wilson Associates, Ltd. 100% Alberta, Canada
Salcona Gas, Ltd. 100% Alberta, Canada
Barnwell Investment Corporation 100% Hawaii
Barnwell Kona Corporation 100% Hawaii
Barnwell Financial Corporation 100% Delaware
NDTX, Inc. 100% Delaware
WRI Properties, Inc. 100% Hawaii
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from
Barnwell Industries, Inc.'s 1996 10-KSB and is qualified in its
entirety by reference to such 10-KSB filing.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1996
<PERIOD-END> SEP-30-1996
<CASH> 3553
<SECURITIES> 0
<RECEIVABLES> 2298
<ALLOWANCES> 10
<INVENTORY> 69
<CURRENT-ASSETS> 6551
<PP&E> 53085
<DEPRECIATION> 30416
<TOTAL-ASSETS> 30780
<CURRENT-LIABILITIES> 3187
<BONDS> 11100
0
0
<COMMON> 821
<OTHER-SE> 10582
<TOTAL-LIABILITY-AND-EQUITY> 30780
<SALES> 13310
<TOTAL-REVENUES> 14180
<CGS> 5291
<TOTAL-COSTS> 5291
<OTHER-EXPENSES> 2960
<LOSS-PROVISION> (54)
<INTEREST-EXPENSE> 707
<INCOME-PRETAX> 2108
<INCOME-TAX> 878
<INCOME-CONTINUING> 1230
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1230
<EPS-PRIMARY> .93
<EPS-DILUTED> 0
</TABLE>
