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, 1997
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, 1997: $14,830,000
The aggregate market value of the voting stock held by non-affiliates (508,555
shares) of the Registrant on December 5, 1997, based on the closing price of
$18.00 on that date on the American Stock Exchange, was $9,154,000.
As of December 5, 1997 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
22, 1998 is incorporated by reference in Part III hereof.
Transitional Small Business Disclosure Format Yes No X
----- -----
TABLE OF CONTENTS
PART I
Discussion of Forward-Looking Statements
Item 1. Description of Business
General Development of Business
Financial Information about Industry Segments
Narrative Description of Business
Financial Information about Foreign and
Domestic Operations and Export Sales
Item 2. Description of Property
Oil and Natural Gas Operations
General
Well Drilling Activities
Oil and Natural Gas Production
Productive Wells
Developed Acreage and Undeveloped Acreage
Reserves
Estimated Future Net Revenues
Marketing of Oil and Natural Gas
Governmental Regulation
Competition
Contract Drilling Operations
Activity
Competition
Land Investment Operations
Activity
Competition
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market For Common Equity and Related Stockholder Matters
Item 6. Management's Discussion and Analysis or Plan of Operation
Liquidity and Capital Resources
Results of Operations
Item 7. Financial Statements
Item 8. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
Part III
Item 9. Directors, Executive Officers, Promoters and Control Persons,
Compliance With Section 16(a) of the Exchange Act
Item 10. Executive Compensation
Item 11. Security Ownership of Certain Beneficial Owners and Management
Item 12. Certain Relationships and Related Transactions
Item 13. Exhibits and Reports on Form 8-K
PART I
Forward-Looking Statements
- --------------------------
This Form 10-KSB, and the documents incorporated herein by reference,
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 Barnwell Industries, Inc.'s
(referred to herein together with its subsidiaries as "Barnwell" or the
"Company") future performance, statements of the Company's plans and objectives
and other similar types of information. Although the Company believes that its
expectations are based on reasonable assumptions, it cannot assure that the
expectations contained in such forward-looking statements will be achieved. Such
statements involve risks, uncertainties and assumptions, including, but not
limited to, those relating to the factors discussed below, in other portions of
this Form 10-KSB, in the Notes to Consolidated Financial Statements, and in
other documents filed by the Company with the Securities and Exchange Commission
from time to time, which could cause actual results to differ materially from
those contained in such statements. These forward-looking statements speak only
as of the date of filing of this Form 10-KSB, and the Company expressly
disclaims any obligation or undertaking to publicly release any updates or
revisions to any forward-looking statements contained herein.
The Company's oil and 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, may 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, environmental compliance requirements and laws pertaining
to workers' health and safety.
The Company's land investment business segment is affected by the
condition of Hawaii's real estate market. The Hawaii real estate market is
affected by Hawaii's economy in general, and Hawaii's tourism industry in
particular. 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 also indirectly affected by the foregoing factors discussed in the
preceding paragraph. The Company's contract drilling operations are materially
dependent upon levels of activity in land development in Hawaii. Such activity
levels are affected by both short-term and long-term trends in Hawaii's economy.
In recent years, Hawaii's economy has experienced very slow growth and therefore
the level of contract drilling activity has declined. As events during recent
years have demonstrated, any prolonged reduction or lack of growth in Hawaii's
economy will depress the demand for the Company's contract drilling services.
Such a decline could have a material adverse effect on the Company's revenues
and profitability.
Item 1. Description of Business
-----------------------
(a) General Development of Business
-------------------------------
Barnwell was incorporated in 1956. During its last three completed
fiscal years, the Company was engaged in oil and natural gas exploration,
development, production and sales in Canada and the United States, investment in
leasehold land in Hawaii, and water well drilling and water pumping system
installation and repair in Hawaii. The Company's oil and natural gas activities
comprise its largest business segment. Approximately 78% of the Company's
revenues for the fiscal year ended September 30, 1997 were attributable to its
oil and natural gas activities. The Company's contract drilling activities
accounted for 14% of the Company's revenues in fiscal 1997, with natural gas
processing and other revenues comprising the remaining 8% of fiscal 1997
revenues. Approximately 86% of the Company's capital expenditures for the fiscal
year ended September 30, 1997 were attributable to oil and natural gas
activities, 10% to land investment and 4% to other activities. The Company had
no land investment revenue in 1997; land investment revenues relate to sales of
leasehold interests and development rights, which do not occur every year.
(i) Oil and Natural Gas Activities.
----------------------------------
The Company's wholly-owned subsidiary, Barnwell of Canada, Limited
("BOC"), is involved in the acquisition, exploration and development of oil and
natural gas properties, principally in Alberta, Canada. BOC participates in
exploratory and developmental operations for oil and natural gas on property in
which it has an interest and evaluates proposals by third parties with regard to
participation in such exploratory and developmental operations elsewhere.
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 together with those participants then acquired a 12.5% interest in
this development program that encompasses approximately 200,000 gross acres for
a total investment of approximately $2,625,000. 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
raised an additional $522,000 from these participants in September 1997 for
additional drilling activities.
(ii) Contract Drilling.
-----------------
The Company's wholly-owned subsidiary, Water Resources International,
Inc. ("WRI"), drills water wells and installs and repairs water pumping systems
in Hawaii. WRI owns and operates four rotary drill rigs, one rotary
drill/workover rig, 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 on land acquired from Kaupulehu
Developments, a planned 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 2,100 acres of land located approximately six miles
north of the Kona International Airport in the North Kona District of the Island
of Hawaii.
(b) Financial Information about Industry Segments
---------------------------------------------
Revenues of each industry segment for the fiscal years ended September
30, 1997, 1996 and 1995 are summarized as follows (all revenues were from
unaffiliated customers with no intersegment sales or transfers):
1997 1996 1995
----------------- ----------------- -----------------
Oil and natural gas $ 11,520,000 78% $ 10,660,000 75% $ 10,520,000 70%
Contract drilling 2,160,000 14% 2,650,000 19% 3,770,000 25%
Other 873,000 6% 717,000 5% 420,000 3%
------------ ---- ------------ ---- ------------ ----
Revenues from segments 14,553,000 98% 14,027,000 99% 14,710,000 98%
Interest income 277,000 2% 153,000 1% 240,000 2%
------------ ---- ------------ ---- ------------ ----
Total revenues $ 14,830,000 100% $ 14,180,000 100% $ 14,950,000 100%
============ ==== ============ ==== ============ ====
For further discussion see Note 11 (Segment and Geographic Information)
of "Notes to Consolidated Financial Statements" in Item 7.
(c) Narrative Description of Business
---------------------------------
See the table above in Item 1(b) detailing revenue of each industry
segment and description of each industry segment of the Company's business under
Item 2.
As of September 30, 1997, Barnwell employed 32 full-time employees.
Thirteen (13) are employed in oil and natural gas activities, 9 are employed in
contract drilling, and 10 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 and as of September 30, 1997, 1996 and
1995 are set forth in Note 11 (Segment and Geographic Information) of "Notes to
Consolidated Financial Statements" in Item 7.
Item 2. Description of Property
-----------------------
OIL AND NATURAL GAS OPERATIONS
------------------------------
General
- -------
Barnwell's investments in oil and natural gas properties consist of
investments in Canada, principally in the Province of Alberta, with the
exception of the investment of $1,250,000 in prospects in Michigan and
$1,297,000 in prospects in North Dakota, Louisiana and Nebraska. These property
interests are principally held under governmental leases or licenses. Under the
typical Canadian provincial governmental lease, Barnwell must perform
exploratory operations and comply with certain other conditions. Lease terms
vary with each province, but, in general, grant Barnwell the right to remove
oil, natural gas and related substances subject to payment of specified
royalties on production.
Barnwell participates in exploratory and developmental operations for
oil and natural gas on property in which it has an interest 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 1997, Barnwell participated in exploratory and developmental operations
in the Canadian Province of Alberta, and the states of Michigan, North Dakota,
Louisiana and Nebraska, 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 1997, the weighted average royalty paid on natural gas from the Dunvegan
Unit, Barnwell's principal oil and natural gas property, increased to 19%, as
compared to 17% in fiscal 1996. The weighted average royalty paid on all of the
Company's natural gas was approximately 18% in both fiscal 1997 and fiscal 1996.
In fiscal 1997, 96% of Barnwell's oil production was from properties
located in Alberta. Royalty rates under government leases in Alberta are based
on the selling price of oil. In fiscal 1997, the weighted average royalty paid
on oil was approximately 21%. The remaining 4% 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 17.5%; oil revenue in North
Dakota is subject to a 6.5% severance tax. The weighted average royalty in
Louisiana is 30% with severance tax rates of 12.3% on oil and $0.077 per 1,000
cubic feet ("MCF") on natural gas. For gas revenue in Michigan, the weighted
average royalty rate was 18% in fiscal 1997 with a severance tax of 6%.
Barnwell's oil and natural gas segment derived 19% of its oil and
natural gas revenues in both fiscal 1997 and 1996 from one company. At September
30, 1997, Barnwell had a receivable from this company of approximately $177,000.
In fiscal 1997, Barnwell spent approximately $509,000 in various areas
of Alberta and $1,134,000 primarily in the state of Michigan for land
acquisition and seismic costs to be evaluated and developed subsequent to fiscal
1997.
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 1997, Barnwell participated in the drilling of 55
development wells and 17 exploratory wells, of which 53 are capable of
production. The Company also participated in the recompletion of 20 wells. The
most significant drilling operations took place in the Thornbury, Wood River,
Hillsdown, Manyberries, and Red Earth areas of Alberta and in the state of
Michigan.
The initial drilling program in Michigan included one new well, and
seven existing well bores which were re-entered with the goal of producing
natural gas. One is a commercial well producing at the rate of approximately
seven hundred thousand cubic feet per day, one is a commercial well awaiting
tie-in, and six are non-commercial wells.
While the results of the initial program have been disappointing,
Barnwell and the other working interest owners have commenced a second drilling
program in order to more fully evaluate the extensive land position acquired in
the Michigan Basin. Approximately 70% of the $1,250,000 of oil and gas capital
expenditures by the Company in Michigan in fiscal 1997 were used to acquire this
land position which encompasses approximately 200,000 gross acres. The second
drilling program in Michigan is comprised of seven wells. The target for four of
the wells is the deep natural gas targeted in the initial program, with the
other three wells targeting shallower oil formations.
In fiscal year 1997, the Company continued to participate in the
development of oil reserves discovered in fiscal 1994 in the state of North
Dakota. Three oil wells were drilled in 1997, one of which is capable of
production. One previous well was converted to a water disposal well. The
Company currently has seven oil wells capable of producing from four petroleum
reservoirs. The Company's working interests in these wells varies between 11.7%
and 23.1%. The Company's portion of current production from these wells is
approximately 20 barrels of oil per day.
The Company wrote down $270,000 of costs incurred in developing U.S.
oil and natural gas properties. This write-down was largely related to
activities in North Dakota where one dry well was drilled, a producing oil well
watered out and the independent engineer revised downward the estimate of
reserves in the remaining North Dakota wells. Additionally, the disappointing
results from the initial drilling program in the Michigan Basin prospect (8
wells were drilled, 2 of which are commercial), and a dry hole in Louisiana
contributed to the write-down.
In fiscal 1997, the Company continued further development of a natural
gas project in the Thornbury area. The Company participated in the completion of
eleven natural gas wells and seven recompletions. A total of 55 zones of
production from 42 wells are now contributing to an average daily production of
approximately 13.5 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 was
rationalized effective January 1, 1997 to 12.5% from a previous average of
approximately 17.5% in order to acquire an interest in adjacent undeveloped land
purchased by the operator. Production was restored to pre-rationalization levels
by April 1997 when the new wells drilled on the land that was rationalized were
brought on line. Further activity in the Thornbury area is planned for 1998.
In fiscal 1997, the Company participated in the drilling of six
commercial oil wells and two recompletions in the Wood River Unit of Central
Alberta. The Company's average working interest in Wood River is 7.87%. The
Company also participated in the further development of the Hillsdown area with
the drilling of six wells and two recompletions. This area has both oil and gas
reserves and the Company's working interests range from 11.25% to 18.75%.
The Company participated in the drilling of seven commercial wells and
one recompletion in the Manyberries area of southern Alberta in fiscal 1997. The
Company's working interests in these wells range between 9.7% and 12.5%. The
Company also participated in the drilling of five oil wells and two
recompletions in the Red Earth area. The Company's interests in Red Earth ranges
from 4.52% to 24.69%.
At September 30, 1997, 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.
<TABLE>
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, 1997, 1996 and 1995 in which
Barnwell participated:
<CAPTION>
Total
Productive Productive Acquired Productive
Oil Wells Gas Wells Wells Wells Dry Holes Total Wells
------------ ----------- --------- ---------- ----------- ------------
Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev.
----- ---- ---- ---- ---- ---- ---- ---- ----- ---- ----- -----
<S> <C> <C> <C> <C> <C><C> <C> <C> <C> <C> <C> <C>
1997
- ----
Gross* 4.00 25.00 3.00 21.00 - - 7.00 46.00 10.00 9.00 17.00 55.00
Net* 0.72 2.92 0.14 2.27 - - 0.86 5.19 0.80 1.13 1.66 6.32
1996
- ----
Gross* 3.00 10.00 5.00 9.00 - 3.00 8.00 22.00 6.00 4.00 14.00 26.00
Net* 0.55 1.63 0.94 1.20 - 0.34 1.49 3.17 0.94 0.57 2.43 3.74
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
<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.
</FN>
</TABLE>
The Dunvegan Unit, the Company's principal property located in Alberta,
Canada, has 139 natural gas wells comprising a total of 195 producing well
zones. In fiscal 1997 the Company expended $414,000 to further develop the
property. The 1996 sour gas facility was completed to process previously shut-in
sour gas from the Unit.
Oil and Natural Gas Production
- ------------------------------
In fiscal 1997, approximately 49%, 43% and 8% 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 1997 averaged net sales
volume after royalties of 10,600 MCF per day, a decrease of 11% from 11,900 MCF
per day in fiscal 1996. The decreases in volumes sold were due to expected
decreases in production from some of the Company's mature properties (Hillsdown,
Charlotte Lake, Thornbury, and Pouce Coupe). Dunvegan provided 48% of the
Company's fiscal 1997 natural gas production compared to 42% for fiscal 1996.
In fiscal 1997, oil sales averaged net production of 545 barrels per
day, a decrease of 3% from fiscal 1996. The Company's major oil producing
properties are the Red Earth, Chauvin, Manyberries and Rainbow/Zama areas in
Canada.
In fiscal 1997, natural gas liquid sales averaged net production of 178
barrels per day, a decrease of 11% from the 200 barrels per day in fiscal 1996.
Dunvegan provided 62% of the Company's fiscal 1997 natural gas liquids
production. Other major natural gas liquids producing properties are the
Hillsdown and Pouce Coupe areas in Alberta.
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.
<TABLE>
<CAPTION>
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 1997 was
derived primarily from the Province of Alberta. Other producing areas are as
follows: 500 barrels of oil and 88,000 MCF of natural gas were derived from the
Province of Saskatchewan, 7,500 barrels of oil were derived from the state of
North Dakota, 7,700 MCF of natural gas and 2,000 barrels of natural gas liquids
were derived from the state of Louisiana, and 6,000 MCF of natural gas was
derived from the state of Michigan. All dollar amounts in this table are in U.S.
dollars.
Year Ended September 30,
-------------------------------------------------
1997 1996 1995
-------------- ---------------- ---------------
<S> <C> <C> <C>
Annual net production:
Natural gas liquids (BBLS)* 65,000 73,000 90,000
Oil (BBLS)* 199,000 206,000 206,000
Natural gas (MCF)* 3,852,000 4,347,000 4,916,000
Annual average sale price per unit of production:
BBL of liquids** $17.55 $13.40 $10.98
BBL of oil** $19.55 $17.38 $15.71
MCF of natural gas** $ 1.45 $ 1.14 $ 1.03
Annual average production cost
per MCFE produced***** $ 0.62 $ 0.57 $ 0.51
</TABLE>
The following table sets forth the gross and net number of productive
wells Barnwell has an interest in as of September 30, 1997.
Productive Wells
- ----------------
Productive Wells***
--------------------------------
Gross**** Net****
-------------- -------------
Location Oil Gas Oil Gas
- ------------------------------- ------ ------ ------ -----
Canada
Alberta 195 365 59.08 49.73
Saskatchewan 3 21 0.25 3.48
USA
North Dakota 7 - 0.99 -
Louisiana 1 - 0.02 -
Michigan - 2 - 0.10
----- ----- ------ ------
Total 206 388 60.34 53.31
===== ===== ====== ======
- --------------------------------------
* When used in this report, "MCF" means 1,000 cubic feet of natural
gas at 14.65 psia and 60 degrees F and the term "BBLS" means stock tank
barrels of oil equivalent to 42 U.S. gallons.
** Calculated on revenues before royalty expense and royalty tax credit
divided by gross production.
*** Seventy-two gross natural gas wells have dual or multiple completions
and six gross oil wells have dual completions.
**** Please see note (2) on the following table.
***** Natural gas liquids, oil and natural gas units were combined by
converting barrels of natural gas liquids and oil to an MCF equivalent
("MCFE") on the basis of 5.8 MCF = 1 BBL.
Developed Acreage and Undeveloped Acreage
- -----------------------------------------
<TABLE>
The following table sets forth certain information with respect to oil
and natural gas properties of Barnwell as of September 30, 1997:
<CAPTION>
Developed and
Developed Undeveloped Undeveloped
Acreage(1) Acreage(1) Acreage(1)
------------------- ------------------ --------------------
Location Gross(2) Net(2) Gross(2) Net(2) Gross(2) Net(2)
- ---------------- -------- ------- -------- ------ -------- -------
Canada
- ------
<S> <C> <C> <C> <C> <C> <C>
Alberta 247,076 36,394 187,275 39,294 434,351 75,688
British Columbia 483 40 2,789 284 3,272 324
Saskatchewan 3,696 543 200 11 3,896 554
USA
- ---
North Dakota 1,200 151 21,459 9,838 22,659 9,989
Louisiana 640 13 3,440 69 4,080 82
Michigan 5,120 256 214,676 10,734 219,796 10,990
------- ------ ------- ------ ------- -------
Total 258,215 37,397 429,839 60,230 688,054 97,627
======= ====== ======= ====== ======= =======
</TABLE>
Barnwell's leasehold interests in its undeveloped acreage, if not
developed, expire over the next five fiscal years as follows: 7% expire during
fiscal 1998; 12% expire during fiscal 1999; 31% expire during fiscal 2000, 20%
expire during fiscal 2001 and 9% expire during fiscal 2002. 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 (3,403 net acres), Thornbury (7,040 net acres), Archie (4,000 net
acres), and Boulder (2,880 net acres), and in the states of North Dakota (9,838
net acres) and Michigan (10,734 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, 1997, 1996 and 1995 on all properties in
which Barnwell has an interest. These reserves are before deductions for
indebtedness secured by the properties and are based on constant dollars. No
estimates of total proved net oil or natural gas reserves have been filed with
or included in reports to any other federal authority or agency since October 1,
1980.
- ---------------------------------
(1) "Developed Acreage" includes the acres covered by leases upon which
there are one or more producing wells. "Undeveloped Acreage" includes
acres covered by leases upon which there are no producing wells and
which are maintained in effect by the payment of delay rentals or the
commencement of drilling thereon.
(2) "Gross" refers to the total number of wells or acres in which Barnwell
owns an interest, and "Net" refers to Barnwell's aggregate interest
therein. For example, a 50% interest in a well represents 1 Gross Well,
but .50 Net Well, and similarly, a 50% interest in a 320 acre lease
represents 320 Gross Acres and 160 Net Acres. The gross wells and gross
acreage figures include interests owned of record by Barnwell and, in
addition, the portion owned by others.
Proved Developed Producing Reserves September 30,
- ----------------------------------- ----------------------------------------
1997 1996 1995
------ ------ -----
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 2,087,000 2,108,000 2,025,000
Natural gas - thousand
cubic feet (MCF) 29,483,000 33,096,000 31,700,000
Total Proved Developed Reserves
(Includes Proved
Developed Producing Reserves) September 30,
- ----------------------------------- ----------------------------------------
1997 1996 1995
------ ------ -----
Oil - barrels (BBLS)
(including condensate and
natural gas liquids) 2,613,000 2,374,000 2,296,000
Natural gas - thousand
cubic feet (MCF) 43,951,000 46,252,000 46,746,000
As of September 30, 1997, all of Barnwell's proved developed producing
and total proved developed reserves were located in the Province of Alberta,
with the exception of 1,000 proved developed producing barrels of oil and
366,000 proved developed producing MCF of natural gas located in the Province of
Saskatchewan, 5,000 proved developed producing barrels of oil and 20,000 proved
developed producing MCF of natural gas located in the state of Louisiana, 28,000
proved developed producing barrels of oil located in the state of North Dakota
and 100,000 proved developed producing MCF of natural gas in the state of
Michigan.
During fiscal 1997, Barnwell's total net proved developed reserves,
including proved developed producing reserves, of oil, condensate and natural
gas liquids increased by 239,000 barrels, and total net proved developed
reserves of natural gas decreased by 2,301,000 MCF. The increase in oil,
condensate and natural gas liquids reserves was the net result of (a) production
during the year of 264,000 barrels, (b) the addition of 339,000 barrels from the
drilling of productive oil wells, (c) the independent engineer's 169,000 barrel
upward revision of the Company's oil reserves, and (d) the sale of reserves of
5,000 barrels. Barnwell's proved developed natural gas reserves decreased as a
net result of (a) production during the year of 3,852,000 MCF, (b) the addition
of 1,786,000 MCF from the drilling of productive natural gas wells, (c) the sale
of reserves of 996,000 MCF and (d) the independent engineer's 761,000 MCF upward
revision of the Company's natural gas reserves.
Barnwell's working interest in the Dunvegan Unit accounted for
approximately 62% and 56% of its total proved developed natural gas reserves at
September 30, 1997 and 1996 respectively, and approximately 31% of proved
developed oil and condensate reserves at September 30, 1997 compared to
approximately 32% of proved developed oil and condensate reserves at September
30, 1996.
The following table sets forth the Company's oil and natural gas
reserves at September 30, 1997, 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").
<TABLE>
OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 1997
<CAPTION>
Total Producing Total Proved
--------------------------------------- ---------------------------------------
Oil Gas Oil Gas
---------------- ------------------- ---------------- -------------------
GROSS NET GROSS NET GROSS NET GROSS NET
(MBBLS) (MMCF) (MBBLS) (MMCF)
---------------- ------------------- ---------------- -------------------
Property Name
- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dunvegan Unit 552 458 21,253 19,620 935 797 29,247 27,168
Hillsdown 98 83 2,349 2,146 223 188 3,434 3,148
Thornbury - - 2,480 2,326 - - 2,775 2,616
Manyberries 107 103 140 124 137 131 673 599
Pouce Coupe 7 5 1,331 1,219 13 9 2,054 1,897
Red Earth 938 908 - - 959 930 - -
Pembina 25 21 634 528 30 25 875 718
Barrhead 4 4 595 571 5 5 695 673
Bashaw - - 103 84 1 - 103 84
Belloy - - 73 55 - - 318 263
Brooks - - 53 47 - - 53 47
Cessford 3 3 - - 3 3 - -
Charlotte Lake - - 631 598 - - 1,024 972
Chauvin 111 105 - - 111 105 - -
Clear Hills 9 8 337 284 9 8 337 284
Coyote - - 9 9 - - 9 9
Faith - - - - - - 1,026 856
Fenn Big Valley - - 30 28 - - 30 28
Gilby 6 6 315 258 6 6 315 258
Gilwood - - - - - - 96 69
Highvale 15 14 - - 15 14 - -
Hilda - - 24 23 - - 24 23
Lanaway - - - - - - 212 163
Lacombe - - 12 11 - - 12 11
Leduc 1 1 62 49 1 1 266 244
Majeau Lake - - 35 32 - - 35 32
Medicine River 50 37 225 164 56 41 348 253
Mikwan - - 15 14 - - 15 14
Mitsue - - 11 10 - - 15 13
Morinville - - 447 365 - - 447 365
Peace River 41 34 154 143 44 36 747 696
Rainbow 92 87 - - 92 87 - -
Richdale - - - - - - 178 157
Staplehurst 12 11 - - 18 16 - -
Swalwell 103 96 - - 103 96 - -
Wood River 44 39 283 243 44 39 283 243
Worsley 6 4 - - 6 4 65 61
Zama 29 26 60 46 46 38 1,867 1,501
Hatton, Saskatchewan - - 513 366 - - 513 366
Webb, Saskatchewan 1 1 - - 1 1 - -
Coastal, North Dakota 3 2 - - 3 2 - -
SW Smith, North Dakota 3 3 - - 3 3 - -
Wapiti, North Dakota 4 4 - - 4 4 - -
West Greene, North Dakota 24 19 - - 24 19 - -
Blind River, Louisiana 8 5 30 20 8 5 30 20
Michigan - - 130 100 - - 130 100
----- ----- ------ ------ ----- ----- ------ ------
TOTAL 2,296 2,087 32,334 29,483 2,900 2,613 48,251 43,951
===== ===== ====== ====== ===== ===== ====== ======
<FN>
Properties are located in Alberta, Canada unless otherwise noted.
</FN>
</TABLE>
Estimated Future Net Revenues
- -----------------------------
The following table sets forth Barnwell's "Estimated Future Net
Revenues" from 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 Developed Total
Producing Proved Developed
Reserves Reserves
----------- ---------------
Year ending September 30,
1998 $ 5,703,000 $ 5,792,000
1999 4,700,000 5,187,000
2000 3,973,000 4,998,000
Thereafter 20,366,000 29,795,000
----------- -----------
$34,742,000 $45,772,000
=========== ===========
Present value (discounted at 10%)
at September 30, 1997 $21,217,000 $27,982,000
=========== ===========
Marketing of Oil and Natural Gas
- --------------------------------
Barnwell sells substantially all of its oil and condensate production
under short-term contracts between itself or the operator of the property and
marketers of oil. The price of oil is freely negotiated between the buyers and
sellers.
Natural gas sold by the Company is generally sold under both long-term
and short-term contracts with prices indexed to market prices and renegotiated
annually. The price of natural gas and natural gas liquids is freely negotiated
between buyers and sellers. In 1997, the Company elected to take more of its oil
and natural gas "in kind" where the Company markets the products instead of
having the operator of a producing property market the products on the Company's
behalf.
In fiscal 1997, natural gas production from the Dunvegan Unit was
responsible for approximately 50% of the Company's natural gas revenues. In
fiscal 1997, the Company had one significant customer which accounted for 19% of
the Company's oil and natural gas revenues. A portion of Barnwell's Dunvegan
natural gas production and natural gas production from other properties are sold
to aggregators and marketers under various short-term and long-term contracts,
with the price of natural gas determined by negotiations between the aggregators
and the final purchasers.
Governmental Regulation
- -----------------------
The jurisdictions in which the oil and natural gas properties of
Barnwell are located have regulatory provisions relating to permits for the
drilling of wells, the spacing of wells, the prevention of 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
dollars (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%.
The Province of Alberta has stated that changes in the royalty tax
credit will 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 royalty tax
credit is not continued, it will have a material adverse effect on the Company.
Competition
- -----------
The majority of Barnwell's natural gas sales take place in Alberta,
Canada and the remainder is sold in the mid-continental United States,
northeastern United States and the northern California area. Natural gas prices
in Alberta are generally very competitive as there is a significant supply of
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 participant in the industry and
competes in its oil and natural gas activities with many other companies having
far greater financial and other resources.
CONTRACT DRILLING OPERATIONS
- ----------------------------
Barnwell owns 100% of Water Resources International, Inc. ("WRI"). WRI
drills water wells and installs and repairs water pumping systems in Hawaii, and
has also drilled geothermal wells in Hawaii in previous years. WRI owns and
operates four rotary drill rigs, one rotary drill/workover rig and a two acre
storage and maintenance yard near Hilo, Hawaii. WRI also leases a three-quarter
of an acre maintenance facility in Honolulu and a one acre maintenance and
storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii,
and maintains drill and pump inventory. As of September 30, 1997, WRI employed 9
drilling, pump and administrative employees, none of whom are union members.
WRI drills both shallow and deep water wells in Hawaii. WRI also
installs and repairs water pumps after wells are completed. Additionally, WRI is
a distributor, in the state of Hawaii, for Centrilift pumps and equipment. Pump
installation and maintenance contracts are primarily obtained from municipal
water utilities. The demand for WRI's services is dependent upon land
development activities in Hawaii, which has decreased from prior years' levels.
WRI markets its services to land developers and government agencies, and
identifies potential contracts through public notices and referrals. Contracts
are usually fixed price contracts and are negotiated with private entities or
obtained through competitive bidding with various local, state and Federal
agencies. Contract revenues are not dependent upon the discovery of water, and
contracts are not subject to renegotiation of profits or termination at the
election of the governmental entities involved. Contracts provide for
arbitration in the event of disputes.
The Company's contract drilling subsidiary derived 73%, 42% and 28% of
its contract drilling revenues in fiscal 1997, 1996, and 1995, respectively,
pursuant to State of Hawaii and local county contracts. At September 30, 1997,
the Company had accounts receivable from the State of Hawaii and local county
entities totaling approximately $396,000. 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 1997, WRI started one water well and eight water well pump
installation contracts and completed two water well and six pump installation
contracts. One of the two completed water wells was started in the current
fiscal year and three of the six completed water well pump installations were
started in the prior year. Sixty-seven percent (67%) of such well drilling and
pump installation jobs, representing 73% of total contract drilling revenues in
fiscal 1997, have been pursuant to government contracts. At September 30, 1997,
WRI had a backlog of eight pump installation and repair contracts, five of which
were in progress as of September 30, 1997. These eight contracts represent a
backlog of contract drilling revenues of approximately $1,000,000 as of December
1, 1997.
Competition
- -----------
WRI utilizes rotary drill rigs which have the capability of drilling
wells faster than cable tool rigs. There are seven other drilling contractors in
Hawaii which use cable tool or rotary drill rigs that are capable of drilling
water wells, and seven other Hawaii contractors who are capable of installing
and repairing vertical turbine and submersible water pumping systems in Hawaii.
These contractors compete actively with WRI for government and private
contracts. Pricing is the Company's major method of competition; reliability of
service is also a major factor.
The Company expects competitive pressures within the industry to
continue and potentially increase as demand for water well drilling and pump
installation in Hawaii is not expected to increase in the 1998 fiscal year. In
an effort to obtain drilling contracts, management is considering relocating one
drilling rig to the continental U.S. to drill for oil and natural gas.
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 on land acquired from Kaupulehu
Developments, a planned 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 2,100 acres of land located approximately six miles
north of the Kona International Airport in the North Kona District of the Island
of Hawaii.
Kaupulehu Developments currently owns development rights in
approximately 100 acres of leasehold land zoned for residential development in
the vicinity of the Hualalai Golf Course. Kaupulehu Developments' residential
development rights in these approximately 100 acres are under option to Hualalai
Development Company, an affiliate of Kajima Corporation of Japan. If Hualalai
Development Company exercises this option, the Company will receive $16,157,000
from 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.
Kaupulehu Developments also holds leasehold rights in approximately
2,100 acres of land located adjacent to and north of the Four Seasons Resort
Hualalai at Historic Ka'upulehu. Kaupulehu Developments is in the process of
negotiating a revised development agreement and residential fee purchase prices
with the lessor. Management cannot predict the outcome of these negotiations.
In 1993, Kaupulehu Developments submitted a rezoning petition to the
State Land Use Commission to reclassify approximately 1,000 of the 2,100 acres
to allow for the development of a residential community with recreational and
commercial areas, in conformity 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 1,100 acres, located in the eastern portion of the
property, are classified within the State Land Use Conservation District and
zoned unplanned by the County. In June 1996, the State Land Use Commission
approved Kaupulehu Developments' petition for reclassification of approximately
1,000 acres of the 2,100 acres of land into the Urban District for
resort/residential development. Subsequent to the Land Use Commission's
approval, a notice of appeal was filed with the Third Circuit Court of the State
of Hawaii by parties seeking to reverse the Land Use Commission's decision.
Activity
- --------
The Third Circuit Court of the State of Hawaii upheld the Land Use
Commission's approval of Kaupulehu Developments' rezoning request in all
respects in a Decision and Order issued in August 1997. In November 1997, a
notice of appeal was filed with the Supreme Court of the State of Hawaii by
parties seeking to reverse the Third Circuit Court's decision. In addition to
the State of Hawaii approvals, Kaupulehu Developments must also obtain an
additional series of approvals from the County of Hawaii; there is no assurance
that these approvals will be forthcoming at any time.
Competition
- -----------
The Company's land investment segment is subject to intense competition
in all phases of its operations including the acquisition of new properties, the
securing of approvals necessary for land rezoning, and the search for potential
buyers of property interests presently owned. The competition comes from
numerous independent land development companies and other industries involved in
land investment activities. The principal methods of competition are the
location of the project and pricing. Kaupulehu Developments is a minor
participant in the land development industry and competes in its land investment
activities with many other entities having far greater financial and other
resources.
For the past several years Hawaii's economy has experienced little or
no growth and the real estate market has grown slowly. However, the South
Kohala/North Kona area of the island of Hawaii, the area in which Kaupulehu
Developments' property is located, has experienced a significant increase over
recent years in the number of and the median price of real estate sales. The
Hualalai Resort itself has sold, since its opening in late 1996, 45 of the first
50 properties it has offered for sale. Additionally, the general economy in this
area has been impacted favorably by direct flights from Japan to Kona
International Airport, which commenced in 1996 and then increased to a daily
basis.
Item 3. Legal Proceedings
-----------------
In June 1996, the State Land Use Commission approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of land
into the Urban District for resort/residential development. Subsequent to the
Land Use Commission's approval, a notice of appeal was filed in the Third
Circuit Court of the State of Hawaii by Ka Lahui Hawai'i, Kona Hawaiian Civic
Club, Protect Kohanaiki Ohana and Plan to Protect (collectively, the
"Appellants") against the Land Use Commission, State of Hawaii; Office of State
Planning, State of Hawaii; County of Hawaii Planning Department; and Kaupulehu
Developments seeking to reverse the Land Use Commission's decision. The Third
Circuit Court of the State of Hawaii upheld the Land Use Commission's approval
of Kaupulehu Developments' rezoning request in all respects in a Decision and
Order issued in August 1997. In November 1997, the Appellants filed a notice of
appeal in the Supreme Court of the State of Hawaii seeking to reverse the Third
Circuit Court's decision.
The Company 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, 1995 18-3/4 15-3/4 December 31, 1996 19 15-1/2
March 31, 1996 17-7/8 15-1/2 March 31, 1997 20-7/8 18
June 30, 1996 17-1/4 15-1/4 June 30, 1997 19-3/4 17
September 30, 1996 16-7/8 14-7/8 September 30, 1997 22-1/2 18
As of December 5, 1997, 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 5, 1997.
The Company declared 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 1997 increased $1,749,000 to
$7,449,000. The increase was due partially to higher earnings generated by the
Company's oil and natural gas segment due to higher average prices received for
all petroleum products. Also contributing to the increase was an increase in oil
and gas royalties payable at the end of fiscal 1997 of $977,000 as compared to
royalties payable at the end of fiscal 1996.
The Company's revolving credit facility is with the Royal Bank of
Canada, a Canadian bank, for $19,000,000 Canadian dollars or its U.S. dollar
equivalent of approximately $13,800,000 at September 30, 1997. 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 1998. 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, 1997, the Company's consolidated cash and working
capital was $4,402,000 and $1,605,000, respectively. Available credit under the
Royal Bank of Canada's revolving credit facility was approximately $4,700,000 at
September 30, 1997. In June 1995, the Company issued $2,000,000 of convertible
notes due July 1, 2003. The convertible notes are payable in 20 consecutive
equal quarterly installments beginning in October 1998. Interest is payable
quarterly at a 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 notes at
the rate of 10% per annum throughout fiscal 1997. For more information on the
convertible notes, see Note 6 of "Notes to the Consolidated Financial
Statements" in Item 7.
The Company, for the second consecutive year, significantly increased
its oil and natural gas capital expenditures. In fiscal 1997, the Company
expended a total of $6,477,000 towards the development of its oil and natural
gas properties, an increase of $1,428,000 or 28% from the prior fiscal year. In
fiscal 1997, the Company participated in the drilling of 55 development and 17
exploratory wells, 53 of which are capable of production, 20 successful
recompletions, and the expansion of compressor facilities in the Thornbury area.
$1,250,000 of the oil and natural gas investments for fiscal 1997 were
for the Company's natural gas and oil exploration program in the Central Basin
in Michigan. The Company has a 5% working interest in this prospect.
Additionally, the Company raised $2,097,000 from participants who purchased a
7.5% working interest in this prospect. Under the terms of the agreements with
the participants, 30% of the participants' interest will revert to the Company
after the participants receive a return of their entire investment.
The initial drilling program in Michigan included one new well and
seven existing well bores which were re-entered with the goal of producing
natural gas. One is a commercial well producing at the rate of approximately
seven hundred thousand cubic feet per day, one is a commercial well awaiting
tie-in, and six are non-commercial wells.
While the results of the initial program in Michigan have been
disappointing, Barnwell and the other working interest owners have commenced a
second drilling program in order to more fully evaluate the extensive land
position acquired in the Michigan Basin. Approximately 70% of the $1,250,000 of
oil and gas capital expenditures by the Company in Michigan in fiscal 1997 were
used to acquire this land position which encompasses approximately 200,000 gross
acres. The second drilling program in Michigan is comprised of seven wells. The
target for four of the wells is the deep natural gas targeted in the initial
program, with the other three wells targeting shallower oil formations.
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:
1997 1996 1995
---------- ---------- -------
Development oil and
natural gas wells drilled 55 23 16
Exploratory oil and
natural gas wells drilled 17 14 14
Development oil and
natural gas wells purchased - 3 2
Successful oil and natural
wells drilled and purchased 53 30 17
In January 1997, the Company exchanged a portion of its approximately
17.5% working interest in a developed natural gas property and a gas plant in
the Thornbury area for a working interest in undeveloped lands in the Thornbury
area plus approximately $810,000 in cash. As a result, the Company's interest in
both the developed and undeveloped properties in the Thornbury area is now
12.5%. No revenue or gain was recognized from this transaction; proceeds were
credited against the full cost pool. The Company spent approximately $870,000 in
fiscal 1997 towards the development of 11 commercial wells (1.38 net wells), the
recompletion of 7 wells (0.88 net wells), and the expansion of compressor
facilities at Thornbury.
Barnwell's current plans for fiscal 1998 oil and natural gas capital
expenditures are lower than the actual capital expenditures of fiscal 1997. This
estimated decrease will largely be due to the fact that capital expenditures in
1997 included $850,000 for oil and gas lease acquisition costs in Michigan which
will not recur in 1998. The Company, however, may learn of additional new
investment opportunities which may result in capital expenditures increasing.
The following table sets forth the Company's capital expenditures for
each of the last three fiscal years:
1997 1996 1995
---------- ---------- -----------
Oil and natural gas - U.S. $1,750,000 $ 380,000 $ 336,000
Oil and natural gas - Canada 4,727,000 4,669,000 3,098,000
---------- ---------- -----------
Total oil and natural gas 6,477,000 5,049,000 3,434,000
Land investment 733,000 646,000 293,000
Contract drilling 189,000 53,000 83,000
Other 97,000 219,000 120,000
---------- ---------- -----------
Total capital expenditures $7,496,000 $5,967,000 $ 3,930,000
========== ========== ===========
Increase (decrease) in total
oil and natural gas capital
expenditures from prior year $1,428,000 $1,615,000 $(1,916,000)
========== ========== ===========
In fiscal 1997, $733,000 of the Company's capital expenditures were
applicable to the rezoning of leasehold land in North Kona, Hawaii, from
conservation to urban. These expenditures encompass legal, consulting and
planning fees as well as capitalized interest and were funded entirely by the
Company. As of September 30, 1997, the Company has advanced $1,200,000 to
Kaupulehu Developments. Kaupulehu Developments is negotiating a two year term
loan with a bank for $1,500,000 to provide funding for estimated future capital
expenditures over the next two years.
Capital expenditures for the contract drilling segment have totaled
approximately $470,000 over the last five years. Management is considering
relocating one drilling rig to the continental U.S. to drill for oil and natural
gas, which would increase contract drilling capital expenditures in the next
year by approximately $400,000. Additionally, the Company has a $200,000
commitment to construct improvements at its contract drilling yard at Sand
Island on Oahu, Hawaii, by September 1998.
In 1994, the Province of Alberta simplified the process of paying
natural gas royalties by allowing companies to use estimates. In 1997, the
Province of Alberta completed its final royalty calculations for calendar years
1994, 1995, 1996 and a portion of 1997. As a result of its initial calculations,
the Province remitted $630,000 to the Company in August 1997 for estimated
overpaid royalties. In October 1997, after completion of its final calculations,
the Province submitted a $900,000 invoice for underpaid royalties which the
Company paid at the end of October. These transactions had no impact on the
Company's 1997 consolidated statement of operations as the final royalty amounts
had been accrued in the proper periods. However, these transactions did have the
effect of increasing both cash and accounts payable at September 30, 1997 by
$630,000, thereby artificially increasing cash flow generated by operations by
$630,000.
In 1997, the Company elected to take more of its oil and natural gas
"in kind" where the Company markets the products instead of having the operator
of a producing property market the products on the Company's behalf. This has
shortened the length of time that the Company's receivables are outstanding as
Barnwell gets paid directly, instead of by the operator for the property.
The Company believes 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.
The Company did not receive any revenues in fiscal 1997, 1996, and 1995
related to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments'
revenues specifically relate to sales of leasehold interests and development
rights, which do not occur every year.
The Company 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 1997 and 1996.
The Company's internally and externally supported computer systems are
currently being modified to correct for the "Year 2000" problem. Management
believes that with these modifications to existing software, the "Year 2000"
problem will not pose significant operational problems for the Company's
computer systems. The Company does not expect estimated costs associated with
these modifications to have a material effect on its financial position or
results of operations. The amount expensed in fiscal 1997 was immaterial.
RESULTS OF OPERATIONS
- ---------------------
Summary
-------
Barnwell reported net earnings of $1,050,000 in fiscal 1997, a decrease
of $180,000 from net earnings of $1,230,000 in fiscal 1996. This decrease was
due to (i) the fact that fiscal 1996 earnings included a $290,000 deferred
income tax benefit resulting from a decrease in the Canadian Branch tax rate;
there was no such benefit in fiscal 1997; (ii) a write-down of U.S. oil and gas
properties of $270,000 in fiscal 1997; and (iii) decreases in the volumes of
natural gas liquids, oil and natural gas sold in fiscal 1997 as compared to
fiscal 1996 of 11%, 3% and 11%, respectively. These decreases were partially
offset by 31%, 12% and 27% increases in natural gas liquids, oil and natural gas
prices, respectively, in fiscal 1997, as compared to fiscal 1996.
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.
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 1997 as compared to
fiscal 1996, and fiscal 1996 as compared to fiscal 1995.
Fiscal 1997 - Fiscal 1996
- -------------------------
Annual Net Production
-------------------------------------------
Increase
(Decrease)
-----------------
1997 1996 Units %
--------- --------- -------- -----
Liquids (Bbl)* 65,000 73,000 (8,000) (11%)
Oil (Bbl)* 199,000 206,000 (7,000) (3%)
Natural gas (MCF)** 3,852,000 4,347,000 (495,000) (11%)
Annual Average Price Per Unit
-------------------------------------------
Increase
(Decrease)
-----------------
1997 1996 $ %
--------- --------- -------- -----
Liquids (Bbl)* $17.55 $13.40 $ 4.15 31%
Oil (Bbl)* $19.55 $17.38 $ 2.17 12%
Natural gas (MCF)** $ 1.45 $ 1.14 $ 0.31 27%
Fiscal 1996 - Fiscal 1995
- -------------------------
Annual Net Production
-------------------------------------------
Increase
(Decrease)
-----------------
1996 1995 Units %
--------- --------- -------- -----
Liquids (Bbl)* 73,000 90,000 (17,000) (19%)
Oil (Bbl)* 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 (Bbl)* $13.40 $10.98 $ 2.42 22%
Oil (Bbl)* $17.38 $15.71 $ 1.67 11%
Natural gas (MCF)** $ 1.14 $ 1.03 $ 0.11 11%
*Bbl = stock tank barrel equivalent to 42 U.S. gallons
**MCF = 1,000 cubic feet
Revenues increased $860,000 or 8% in fiscal 1997, as compared to fiscal
1996, due to price increases for natural gas liquids (31%), natural gas (27%),
and oil (12%), partially offset by 11% declines in both natural gas and natural
gas liquids production and a 3% decline in oil production. The decline in
production was due to production declines in the Company's more mature
properties and to the reduction of its interest in producing gas reserves in the
Thornbury property due to the rationalization of the Company's Thornbury
property, discussed in "Liquidity and Capital Resources" above, with surrounding
undeveloped land. The Company anticipates that development of these undeveloped
lands will replace the Thornbury producing natural gas reserves sold.
Operating expenses were relatively unchanged, decreasing $80,000 (2%)
in fiscal 1997, as compared to fiscal 1996. The Company expects oil and natural
gas operating expenses to increase at a rate higher than inflation due to the
high level of demand for services in the oil industry and higher costs
associated with certain older properties.
Revenues were relatively unchanged, increasing $140,000 (1%) in fiscal
1996 as compared to fiscal 1995 due to price increases for natural gas (11%),
oil (11%) and natural gas liquids (22%), offset by 12% and 19% declines in
natural gas and natural gas liquids production, respectively. The declines in
natural gas and natural gas liquids production were due to production declines
at some Dunvegan wells. Decreased natural gas sales were supplanted with gas
processing revenues of an almost equal amount. Additionally, third parties spent
approximately $2,500,000 increasing the Dunvegan gas plant capacity so that the
plant can now process 200,000 MCF per day. These third parties did not earn an
interest in the gas plant with these expenditures but will be charged a lower
processing tariff.
Operating expenses were relatively unchanged, increasing $33,000 (1%)
in fiscal 1996, as compared to fiscal 1995, as costs remained relatively
constant and natural gas production declined 12%.
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.
Contract Drilling
- -----------------
Contract drilling revenues and costs are associated with water well
drilling and water pump installation, replacement and repair in Hawaii. Demand
for well drilling and pump installation services is dependent upon land
development activities in Hawaii, which has decreased significantly from prior
years' levels. Demand for water pump replacement and repair is primarily
dependent upon the timing of water system renovations and replacements by water
utilities and other entities.
Contract drilling revenues and operating costs decreased $490,000 (18%)
and $35,000 (2%), respectively, in fiscal 1997 as compared to fiscal 1996. As a
result, operating profit before depreciation decreased $455,000 (59%) in fiscal
1997, as compared to fiscal 1996. Operating profit before depreciation as a
percentage of revenues decreased to 14%, as compared to 29% in fiscal 1996.
These decreases were due to lower demand for water well drilling work and to
increased competition for well drilling and pump installation and repair jobs.
The Company expects competitive pressures within the industry to
continue and potentially grow as demand for water well drilling and pump
installation in Hawaii is not expected to increase in the 1998 fiscal year. In
an effort to obtain drilling contracts, management is considering relocating one
drilling rig to the continental U.S. to drill for oil and natural gas.
Contract drilling revenues and operating costs decreased $1,120,000
(30%) and $1,005,000 (35%), respectively, in fiscal 1996 as compared to fiscal
1995, due to lower water well drilling activity in fiscal 1996. As a result of
the lower activity, operating profit before depreciation decreased $115,000
(13%) in fiscal 1996, as compared to fiscal 1995. Operating profit before
depreciation as a percentage of revenues increased to 29%, as compared to 23% in
fiscal 1995, as the Company was able to reduce operating costs in fiscal 1996 by
a higher percentage than the decrease in revenues as a result of operational
efficiencies due to all contract drilling jobs during 1996 being in the same
area.
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.
At September 30, 1997, WRI had a backlog of eight pump installation and
repair contracts, five of which were in progress as of September 30, 1997. These
eight contracts represent a backlog of contract drilling revenues of
approximately $1,000,000 as of December 1, 1997.
Investment in Land
- ------------------
In fiscal 1997, 1996, and 1995, Kaupulehu Developments entered into no
land transactions.
In April 1995, the option under which Hualalai Development Company
could have acquired Kaupulehu Developments' leasehold interest in approximately
2,100 acres of conservation zoned property in North Kona, Hawaii, expired,
unexercised. Expenditures applicable to the rezoning of approximately 1,000
acres of the 2,100 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 $733,000, $646,000 and $293,000 for
fiscal 1997, 1996 and 1995, respectively. For additional information regarding
Investment in Land, refer to Note 5 in the Notes to Consolidated Financial
Statements.
For the past several years Hawaii's economy has experienced little or
no growth and the real estate market has been slow. However, the South
Kohala/North Kona area of the island of Hawaii, the area in which Kaupulehu
Developments' property is located, has experienced a significant increase over
recent years in the number of and the median price of real estate sales. The
Hualalai Resort itself has sold, since its opening in late 1996, 45 of the first
50 properties it has offered for sale. Additionally, the general economy in this
area has been impacted favorably by direct flights from Japan to Kona
International Airport, which commenced in 1996 and then increased to a daily
basis.
Gas Processing and Other Income
- -------------------------------
Gas processing and other income increased $280,000 (32%) in fiscal
1997, as compared to fiscal 1996, due to an increase in the amount of gas
processed for third parties at the Dunvegan gas plants and an increase in
interest income as a result of higher average cash balances.
Gas processing and other income increased $210,000 (32%) in fiscal
1996, as compared to fiscal 1995, due primarily to increased non-unit gas
processed at the Dunvegan gas plant, partially offset by a decrease in interest
income as a result of lower average cash balances and interest rates.
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.
General and Administrative Expenses
- -----------------------------------
General and administrative expenses increased $94,000 (3%) in fiscal
1997, as compared to fiscal 1996, due to general inflationary increases.
General and administrative expenses decreased $658,000 (17%) in fiscal
1996, as compared to fiscal 1995. This decrease was due to decreased outside
services, decreased foreign currency transaction losses, and rezoning costs.
Foreign currency transaction losses were immaterial in fiscal 1996 while foreign
currency transaction losses of $176,000 were included in general and
administrative expenses in fiscal 1995. $438,000 of costs incurred by Kaupulehu
Developments for the rezoning of leasehold property under option were included
in general and administrative expenses in fiscal 1995. In fiscal 1996, rezoning
costs incurred by Kaupulehu Developments were related to leasehold property no
longer under option and were accordingly capitalized and included in investment
in land.
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.
Depreciation, Depletion and Amortization
- ----------------------------------------
Depreciation, depletion and amortization expense increased $84,000 (3%)
to $3,044,000 in fiscal 1997, as compared to $2,960,000 in fiscal 1996, due to a
5% higher depletion rate per MCF equivalent and a $270,000 write-down of costs
incurred in developing U.S. oil and natural gas properties. These items were
partially offset by an 11% decline in natural gas production and a 5% decline in
combined oil and liquids production, and decreased depreciation expense
resulting from certain water well drilling assets becoming fully depreciated in
fiscal 1996.
The write-down of costs incurred in developing U.S. oil and natural gas
properties largely related to activities in North Dakota where one dry well was
drilled, a producing oil well watered out and the independent engineer revised
downward the estimate of reserves in the remaining North Dakota wells.
Additionally, the disappointing results from the initial drilling program in the
Michigan Basin prospect (8 wells were drilled, 2 of which are commercial), and a
dry hole in Louisiana contributed to the write-down.
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.
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.
Interest Expense
- ----------------
Interest expense decreased $83,000 (12%) in fiscal 1997, as compared to
fiscal 1996, due to an $82,000 increase in capitalization of interest costs
related to the Company's investments in land in Hawaii and unproven undeveloped
oil and natural gas properties in Michigan. The average interest rate incurred
during fiscal 1997 on the Company's $9,100,000 of debt with the Royal Bank of
Canada remained essentially unchanged at 6.35% from 6.33% in fiscal 1996, and
the interest rate on the $2,000,000 of convertible notes in fiscal 1997 was
unchanged at 10% per annum from fiscal 1996.
Interest expense decreased $49,000 (6%) in fiscal 1996, as compared to
fiscal 1995, due to lower average interest rates and average loan balances on
the Company's credit facility borrowings with the Royal Bank of Canada, and a
$74,000 increase in capitalization of interest costs related to the Company's
investment in land. This was partially offset by higher interest expense
attributable to the convertible notes that were issued in June 1995 and thus
outstanding for only four months in fiscal 1995. The average interest rate paid
during fiscal 1996 on the Company's debt with the Royal Bank of Canada decreased
from an average of 6.47% in fiscal 1995 to 6.33% in fiscal 1996. The interest
rate on the convertible notes was 10% per annum during both fiscal 1996 and the
last four months of fiscal 1995.
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.
Foreign Currency Fluctuations
- -----------------------------
The Company conducts foreign operations in Canada. Consequently, the
Company is subject to foreign currency transaction gains and losses due to
fluctuations of the exchange rates between the Canadian dollar and the U.S.
dollar. Foreign currency transaction gains and losses were not material in
fiscal 1997 and 1996. 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 fiscal 1997, 1996, and 1995, the provision for income taxes does not
bear a normal relationship to earnings because Canadian taxes were payable on
the Canadian operations and losses from U.S. operations provide no foreign tax
benefits.
In November 1995, officials of the U.S. and Canada ratified a new
agreement amending the Canada-U.S. Tax Treaty that reduced the Canadian Branch
tax. This change resulted in the recognition of a deferred Canadian income tax
benefit of $290,000 in fiscal 1996.
Environmental Matters
- ---------------------
Federal, state, and Canadian governmental agencies issue rules and
regulations and enforce laws to protect the environment which are often
difficult and costly to comply with and which carry substantial penalties for
failure to comply, particularly in regard to the discharge of materials into the
environment. The regulatory burden on the oil and gas industry increases its
cost of doing business. These laws, rules and regulations affect the operations
of the Company and could have a material adverse effect upon the capital
expenditures, earnings or competitive position of the Company. Although
Barnwell's experience has been to the contrary, there is no assurance that this
will continue to be the case.
Inflation
- ---------
The effect of inflation on the Company has generally been to increase
its cost of operations, interest cost (as a substantial portion of the Company's
debt is at variable short-term rates of interest which tend to increase as
inflation increases), general and administrative costs and direct costs
associated with oil and natural gas production and contract drilling operations.
In the case of contract drilling, the Company has not been able to increase its
contract revenues to fully compensate for increased costs. In the case of oil
and natural gas, prices realized by the Company are essentially determined by
world prices for oil and western Canadian/California/southwest U.S. prices for
natural gas.
New Statements of Financial Accounting Standards
- ------------------------------------------------
The Company applies the provisions of APB Opinion No. 25 in accounting
for stock-based compensation and adopted the disclosure-only provisions of
Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for
Stock-Based Compensation", effective October 1, 1996. Adoption of the fair value
method of measuring stock-based compensation provisions of SFAS No. 123 would
have had no impact on the Company's net earnings or earnings per share for the
years ended September 30, 1997 and 1996.
In February 1997, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 128, "Earnings Per Share." SFAS No. 128 is effective for both
interim and annual periods ending after December 15, 1997. Earlier application
is not permitted. SFAS No. 128 requires the presentation of "Basic" earnings per
share, representing income available to common shareholders divided by the
weighted average number of common shares outstanding for the period, and
"Diluted" earnings per share, which is similar to the current presentation of
fully diluted earnings per share. SFAS No. 128 requires restatement of all prior
period earnings per share data presented. The Company will adopt SFAS No. 128 in
the first quarter of fiscal 1998. Management does not expect adoption of SFAS
No. 128 to have a material impact on the Company's previously or currently
reported earnings per share.
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income." SFAS No. 130 establishes standards for reporting and display of
comprehensive income and its components (revenues, expenses, gains and losses)
in a full set of general-purpose financial statements. This statement requires
that all items currently recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements and is effective for fiscal
years beginning after December 15, 1997. SFAS No. 130 requires reclassification
of financial statements presented for earlier periods. The Company will adopt
the provisions of SFAS No. 130 in the first quarter of fiscal 1999. The Company
conducts operations in Canada and the assets and liabilities and income and
expense items of the foreign operations are translated at exchange rates in
effect as of and for the period ending on the financial statement date. The
resulting translation gains and losses are accounted for in a stockholders'
equity account entitled "Foreign currency translation adjustments." Under SFAS
No. 130, these foreign currency translation gains and losses will be included as
a component of comprehensive income. Foreign currency fluctuations can occur
rapidly and management expects that quarterly fluctuations will at times be
material to comprehensive income. The Company cannot accurately predict future
fluctuations between the Canadian and U.S. dollars.
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This statement provides
guidance for public business enterprises in reporting information about
operating segments in annual financial statements and requires that those
enterprises report selected information about operating segments in interim
financial reports to shareholders. This statement also establishes standards for
related disclosures about products and services, geographic areas and major
customers. This statement is effective for financial statements for periods
beginning after December 15, 1997. The Company will adopt the provisions of SFAS
No. 131 in the first quarter of fiscal 1999. SFAS No. 131 requires restatement
of comparative information presented for earlier periods.
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, 1997 and 1996, and the results of
their operations and their cash flows for each of the years in the three-year
period ended September 30, 1997, 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 28, 1997
<TABLE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<CAPTION>
ASSETS September 30,
- ------ -------------------------
CURRENT ASSETS: 1997 1996
----------- -----------
<S> <C> <C>
Cash, interest bearing of $4,384,000 in 1997
and $3,552,000 in 1996 $ 4,402,000 $ 3,553,000
Accounts receivable (Notes 3 and 13) 2,065,000 2,288,000
Royalty tax credit and taxes receivable 223,000 181,000
Costs and estimated earnings in excess of
billings on uncompleted contracts (Note 3) 30,000 136,000
Deferred income tax assets (Note 7) 100,000 200,000
Inventories and other current assets 132,000 193,000
----------- -----------
TOTAL CURRENT ASSETS 6,952,000 6,551,000
----------- -----------
INVESTMENT IN LAND (Notes 5 and 6) 1,848,000 1,115,000
----------- -----------
OTHER ASSETS (Note 4) 491,000 445,000
----------- -----------
PROPERTY AND EQUIPMENT (Note 6):
Land 631,000 631,000
Oil and natural gas properties (full cost accounting):
Properties being amortized 44,369,000 40,776,000
Properties not subject to amortization 2,405,000 1,121,000
Drilling rigs and equipment 8,104,000 7,911,000
Other property and equipment 2,682,000 2,646,000
----------- -----------
58,191,000 53,085,000
Accumulated depreciation, depletion and amortization 33,084,000 30,416,000
----------- -----------
TOTAL PROPERTY AND EQUIPMENT 25,107,000 22,669,000
----------- -----------
TOTAL ASSETS $34,398,000 $30,780,000
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable $ 3,180,000 $ 1,694,000
Accrued expenses 1,213,000 678,000
Billings in excess of costs and estimated
earnings on uncompleted contracts (Note 3) 31,000 20,000
Payable to joint interest owners 920,000 637,000
Income taxes payable (Note 7) 3,000 158,000
----------- -----------
TOTAL CURRENT LIABILITIES 5,347,000 3,187,000
----------- -----------
LONG-TERM DEBT (Note 6) 11,100,000 11,100,000
----------- -----------
DEFERRED INCOME TAXES (Note 7) 5,801,000 5,090,000
----------- -----------
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 15,171,000 14,121,000
Foreign currency translation adjustments (2,251,000) (1,925,000)
Unrealized holding gains (losses)
on securities (Notes 4 and 7) 11,000 (12,000)
Treasury stock, at cost, 320,745 shares (4,705,000) (4,705,000)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY 12,150,000 11,403,000
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $34,398,000 $30,780,000
=========== ===========
<FN>
See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<TABLE>
<CAPTION>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended September 30,
---------------------------------------
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Revenues:
Oil and natural gas $11,520,000 $10,660,000 $10,520,000
Contract drilling 2,160,000 2,650,000 3,770,000
Gas processing and other 1,150,000 870,000 660,000
----------- ----------- -----------
14,830,000 14,180,000 14,950,000
----------- ----------- -----------
Costs and expenses:
Oil and natural gas operating 3,326,000 3,406,000 3,373,000
Contract drilling operating 1,850,000 1,885,000 2,890,000
General and administrative 3,208,000 3,114,000 3,772,000
Depreciation, depletion and amortization 3,044,000 2,960,000 3,103,000
Interest expense, net (Note 6) 624,000 707,000 756,000
Minority interest in losses (Note 5) - - (286,000)
----------- ----------- -----------
12,052,000 12,072,000 13,608,000
----------- ----------- -----------
Earnings before income taxes 2,778,000 2,108,000 1,342,000
Provision for income taxes (Note 7) 1,728,000 878,000 692,000
----------- ---------- ----------
NET EARNINGS $ 1,050,000 $ 1,230,000 $ 650,000
=========== =========== ===========
NET EARNINGS PER SHARE $0.79 $0.93 $0.49
=========== =========== ===========
WEIGHTED AVERAGE SHARES OUTSTANDING 1,326,000 1,324,400 1,326,100
=========== =========== ===========
<FN>
See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<TABLE>
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Year ended September 30,
---------------------------------------
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Cash flows from operating activities:
Net earnings $1,050,000 $1,230,000 $ 650,000
Adjustments to reconcile
net earnings to net cash
provided by operating activities:
Depreciation, depletion and amortization 3,044,000 2,960,000 3,103,000
Deferred income taxes 886,000 237,000 (1,522,000)
Minority interest in losses - - (286,000)
---------- ---------- ----------
4,980,000 4,427,000 1,945,000
Increase (decrease) from changes in
current assets and liabilities (Note 14) 2,469,000 1,273,000 (21,000)
---------- ---------- ----------
Net cash provided by operating activities 7,449,000 5,700,000 1,924,000
---------- ---------- ----------
Cash flows from investing activities:
Capital expenditures (7,496,000) (5,967,000) (3,930,000)
(Increase) decrease in other assets (17,000) 285,000 (300,000)
Proceeds from sale of oil and natural
gas properties and other equipment 977,000 414,000 613,000
---------- ---------- ----------
Net cash used in investing activities (6,536,000) (5,268,000) (3,617,000)
---------- ---------- ----------
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)
Repayment of long-term debt - - (1,500,000)
---------- ---------- ----------
Net cash provided by financing activities - 180,000 302,000
---------- ---------- ----------
Effect of exchange rate changes on cash (64,000) (35,000) 169,000
---------- ---------- ----------
Net increase (decrease) in cash 849,000 577,000 (1,222,000)
Cash at beginning of year 3,553,000 2,976,000 4,198,000
---------- ---------- ----------
Cash at end of year $4,402,000 $3,553,000 $2,976,000
========== ========== ==========
<FN>
See Notes to Consolidated Financial Statements
</FN>
</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, 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
($0.15 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)
Net earnings - - - 1,050,000 - - -
Foreign currency
translation adjustments - - - - (326,000) - -
Unrealized holding
gain on securities - - - - - 23,000 -
--------- -------- ---------- ----------- ------------ ---------- -----------
Balances at September 30, 1997 1,642,797 $821,000 $3,103,000 $15,171,000 $(2,251,000) $ 11,000 $(4,705,000)
========= ======== ========== =========== ============ ========== ===========
<FN>
See Notes to Consolidated Financial Statements
</FN>2
</TABLE>
BARNWELL INDUSTRIES, INC.
-------------------------
AND SUBSIDIARIES
----------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
YEARS ENDED SEPTEMBER 30, 1997, 1996, AND 1995
----------------------------------------------
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 78% of the Company's revenues and 86% of the
Company's capital expenditures for the fiscal year ended September 30, 1997 were
attributable to its oil and natural gas activities. The Company's contract
drilling activities accounted for 14% of the Company's revenues in fiscal 1997
with gas processing and other revenues comprising the remaining 8%. The Company
had no land investment revenue in 1997; land investment revenues relate to sales
of leasehold interests and development rights, which do not occur every year.
Changes in the marketplace of any of the aforementioned industries may
significantly affect management's estimates and the Company's performance.
2. SIGNIFICANT ACCOUNTING POLICIES
-------------------------------
Oil and natural gas properties
- ------------------------------
The Company uses the full cost method of accounting under which all
costs incurred in the acquisition, exploration and development of oil and
natural gas reserves, including unsuccessful wells, are capitalized until such
time as the aggregate of such costs, on a country by country basis, equals the
discounted present value (at 10%) of the Company's estimated future net cash
flows from estimated production of proved oil and natural gas reserves, as
determined by independent petroleum engineers, less related income tax effects.
Any capitalized costs in excess of the discounted present value are charged to
expense. Depletion of all such costs, except costs related to major development
projects, is provided by the unit-of-production method based upon proved oil and
natural gas reserves of all properties on a country by country basis.
Investments in major development projects are not amortized until proven
reserves associated with the projects can be determined or until impairment
occurs. If the results of an assessment indicate that the properties are
impaired, the amount of the impairment is added to the capitalized costs to be
amortized. General and administrative costs related to oil and natural gas
operations are expensed as incurred. Estimated future site restoration and
abandonment costs are charged to earnings at the rate of depletion and are
included in accumulated depreciation, depletion and amortization. Proceeds from
the disposition of minor producing oil and natural gas properties are credited
to the cost of oil and natural gas properties. Gains or losses are recognized on
the disposition of significant oil and natural gas properties.
Contract drilling
- -----------------
Revenues, costs and profits applicable to contract drilling contracts
are included in the consolidated statements of operations using the percentage
of completion method, principally measured by the percentage of labor dollars
incurred to date for each contract to total estimated labor dollars for each
contract. Contract losses are recognized in full in the year the losses are
identified. The performance of drilling contracts may extend over more than one
year and, in the interim periods, estimates of total contract costs and profits
are used to determine revenues and profits earned for reporting the results of
the contract drilling operations. Revisions in the estimates required by
subsequent performance and final contract settlements are included as
adjustments to the results of operations in the period such revisions and
settlements occur. Contracts are normally less than one year in duration.
Investment in land and revenue recognition
- ------------------------------------------
The Company's investment in land is comprised of land under development
and development rights under option. Land under development is carried at cost
plus capitalized interest on its investment. Investment in land under
development is evaluated for impairment whenever events or changes in
circumstances indicate that the recorded investment balance may not be fully
recoverable. Development rights under option is reported at the lower of the
asset carrying value or fair value, less cost to sell.
Land sales for development rights under option as of September 30, 1997
are accounted for under the cost recovery method. Under the cost recovery
method, no gain is recognized until cash received exceeds the cost and the
estimated future costs related to the development rights sold. The balance sheet
includes no cost for development rights under option and, accordingly, cash
receipts, if any, in excess of costs will be reported as revenues. The Company's
cost and capitalized interest for the land under development is included in the
consolidated balance sheets 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 discounted future cash flow of the
asset. Long-lived assets to be disposed of are reported at the lower of the
asset carrying value or fair value, less cost to sell.
Drilling rigs and other equipment
- ---------------------------------
Drilling rigs and other equipment are stated at cost. Depreciation is
computed using the straight-line method based on estimated useful lives.
Inventories
- -----------
Inventories are comprised of drilling materials and are valued at the
lower of weighted average cost or market value.
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; foreign currency transaction gains or losses were not material in
fiscal years 1997 and 1996.
New Statements of Financial Accounting Standards
- ------------------------------------------------
The Company applies the provisions of APB Opinion No. 25 in accounting
for stock-based compensation and adopted the disclosure-only provisions of
Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for
Stock-Based Compensation", effective October 1, 1996. Adoption of the fair value
method of measuring stock-based compensation provisions of SFAS No. 123 would
have had no impact on the Company's net earnings or earnings per share for the
years ended September 30, 1997 and 1996.
In February 1997, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 128, "Earnings Per Share." SFAS No. 128 is effective for both
interim and annual periods ending after December 15, 1997. Earlier application
is not permitted. SFAS No. 128 requires the presentation of "Basic" earnings per
share, representing income available to common shareholders divided by the
weighted average number of common shares outstanding for the period, and
"Diluted" earnings per share, which is similar to the current presentation of
fully diluted earnings per share. SFAS No. 128 requires restatement of all prior
period earnings per share data presented. The Company will adopt SFAS No. 128 in
the first quarter of fiscal 1998. Management does not expect adoption of SFAS
No. 128 to have a material impact on the Company's previously or currently
reported earnings per share.
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income." SFAS No. 130 establishes standards for reporting and display of
comprehensive income and its components (revenues, expenses, gains and losses)
in a full set of general-purpose financial statements. This statement requires
that all items currently recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements and is effective for fiscal
years beginning after December 15, 1997. SFAS No. 130 requires reclassification
of financial statements presented for earlier periods. The Company will adopt
the provisions of SFAS No. 130 in the first quarter of fiscal 1999. The Company
conducts operations in Canada and the assets and liabilities and income and
expense items of the foreign operations are translated at exchange rates in
effect as of and for the period ending on the financial statement date. The
resulting translation gains and losses are accounted for in a stockholders'
equity account entitled "Foreign currency translation adjustments." Under SFAS
No. 130, these foreign currency translation gains and losses will be included as
a component of comprehensive income. Foreign currency fluctuations can occur
rapidly and management expects that quarterly fluctuations will at times be
material to comprehensive income. The Company cannot accurately predict future
fluctuations between the Canadian and U.S. dollars.
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This statement provides
guidance for public business enterprises in reporting information about
operating segments in annual financial statements and requires that those
enterprises report selected information about operating segments in interim
financial reports to shareholders. This statement also establishes standards for
related disclosures about products and services, geographic areas and major
customers. This statement is effective for financial statements for periods
beginning after December 15, 1997. The Company will adopt the provisions of SFAS
No. 131 in the first quarter of fiscal 1999. SFAS No. 131 requires restatement
of comparative information presented for earlier periods.
Use of Estimates in the Preparation of Financial Statements
- -----------------------------------------------------------
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and the disclosure of contingent assets and liabilities. Actual
results could differ significantly from those estimates. Significant assumptions
are required in the valuation of proved oil and natural gas reserves, and such
assumptions may impact the amount at which oil and natural gas properties are
recorded.
3. RECEIVABLES AND CONTRACT COSTS
------------------------------
Accounts receivable, current, are net of allowances for doubtful
accounts of $10,000 as of September 30, 1997 and 1996. Included in accounts
receivable are contract retainage balances of $136,000 and $440,000 as of
September 30, 1997 and 1996, 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.
Costs and estimated earnings on uncompleted contracts are as follows:
September 30,
----------------------------
1997 1996
---------- ----------
Costs incurred on uncompleted contracts $ 877,000 $2,385,000
Estimated earnings 405,000 1,192,000
---------- ----------
1,282,000 3,577,000
Less billings to date 1,283,000 3,461,000
---------- ----------
$ (1,000) $ 116,000
========== ==========
Costs and estimated earnings on uncompleted contracts are included in
the consolidated balance sheets under the following captions:
September 30,
----------------------------
1997 1996
---------- ----------
Costs and estimated earnings
in excess of billings on uncompleted contracts $ 30,000 $ 136,000
Billings in excess of costs
and estimated earnings on uncompleted contracts (31,000) (20,000)
---------- ----------
$ (1,000) $ 116,000
========== ==========
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,
------------------
1997 1996
-------- --------
Market value $270,000 $240,000
Cost 254,000 258,000
-------- --------
Gross unrealized holding
gains (losses) before income tax effect 16,000 (18,000)
Income tax effect (5,000) 6,000
-------- --------
Unrealized holding gains (losses), net of
income tax effect, included in stockholders' equity $ 11,000 $(12,000)
======== ========
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 on land acquired from Kaupulehu
Developments, a planned 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 2,100 acres of land located approximately six miles
north of the Kona International Airport in the North Kona District of the Island
of Hawaii.
Kaupulehu Developments currently owns development rights in
approximately 100 acres of leasehold land zoned for residential development in
the vicinity of the Hualalai Golf Course. Kaupulehu Developments' residential
development rights in these approximately 100 acres are under option to Hualalai
Development Company, an affiliate of Kajima Corporation of Japan. If Hualalai
Development Company 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.
Kaupulehu Developments also holds leasehold rights in approximately
2,100 acres of land located adjacent to and north of the Four Seasons Resort
Hualalai at Historic Ka'upulehu. Kaupulehu Developments is in the process of
negotiating a revised development agreement and residential fee purchase prices
with the lessor. Management cannot predict the outcome of these negotiations.
In June 1996, the State Land Use Commission ("LUC") approved Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of the
2,100 acres of land into the Urban District for resort/residential development.
Subsequent to the LUC's approval, a notice of appeal was filed with the Third
Circuit Court of the State of Hawaii by parties seeking to reverse the LUC's
decision. The Third Circuit Court of the State of Hawaii upheld the Land Use
Commission's approval of Kaupulehu Developments' rezoning request in all
respects in a Decision and Order issued in August 1997. In November 1997, a
notice of appeal was filed with the Supreme Court of the State of Hawaii by
parties seeking to reverse the Third Circuit Court's decision. In addition to
State of Hawaii approvals, Kaupulehu Developments must also obtain an additional
series of approvals from the County of Hawaii; there is no assurance that these
approvals will be forthcoming at any time.
Costs related to the rezoning of the conservation land are capitalized and
included in the consolidated balance sheets under the caption, "Investment in
land."
6. LONG-TERM DEBT
--------------
The Company has a credit facility at the Royal Bank of Canada, a
Canadian bank, for $19,000,000 Canadian dollars, or its U.S. dollar equivalent
of approximately $13,800,000 at September 30, 1997. Borrowings under this
facility were $9,100,000 at September 30, 1997 and 1996, and are included in
long-term debt. At September 30, 1997, the Company had unused credit available
under this facility of approximately $4,700,000.
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 1998. 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, 1997, the Company paid interest at
rates ranging from 6.13% to 6.44%. At September 30, 1997, the rate was 6.44%.
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.
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 a 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 1997 and 1996. The notes are unsecured and convertible at any time at the
holder's option into shares of the Company's common stock at a price of $20.00
per share, subject to adjustment for certain events including a stock split of,
or stock dividend on, the Company's common stock. The notes are redeemable, at
the option of the Company, at any time at premiums declining 1% annually from 5%
of the principal amount of the notes at July 1, 1997. These notes, amounting to
$2,000,000 at September 30, 1997 and 1996, are included in long-term debt.
At September 30, 1997, the maturities of long-term debt by fiscal year,
exclusive of the credit facility with the Canadian bank, are as follows:
1998 $ -
1999 400,000
2000 400,000
2001 400,000
2002 400,000
Thereafter 400,000
----------
$2,000,000
==========
The Company capitalizes interest costs related to its investment in
land and to its investment in undeveloped natural gas and oil leases in the
Central Basin in Michigan not subject to current amortization. Interest costs
for the years ended September 30, 1997, 1996 and 1995 are summarized as follows:
1997 1996 1995
--------- --------- ---------
Interest costs incurred $ 793,000 $ 794,000 $ 769,000
Less interest costs capitalized on:
Investment in land 120,000 87,000 13,000
Investment in natural gas and oil 49,000 - -
--------- --------- ---------
Interest expense $ 624,000 $ 707,000 $ 756,000
========= ========= =========
7. TAXES ON INCOME
---------------
The components of earnings/(loss) before income taxes are as follows:
Year ended September 30,
-----------------------------------------
1997 1996 1995
----------- ----------- -----------
United States $(1,662,000) $(1,200,000) $(1,444,000)
Canadian 4,440,000 3,308,000 2,786,000
----------- ----------- -----------
$ 2,778,000 $ 2,108,000 $ 1,342,000
=========== =========== ===========
The components of the provision for income taxes related to the above
earnings/(loss) are as follows:
Year ended September 30,
-----------------------------------------
1997 1996 1995
----------- ----------- ----------
Current:
United States - Federal $ 51,000 $ (67,000) $1,069,000
United States - State and local (51,000) (51,000) 241,000
---------- ----------- ----------
United States - total - (118,000) 1,310,000
Canadian 842,000 759,000 904,000
---------- ----------- ----------
Total current 842,000 641,000 2,214,000
---------- ----------- ----------
Deferred:
United States 40,000 56,000 (1,420,000)
Canadian 846,000 181,000 (102,000)
---------- ----------- ----------
Total deferred 886,000 237,000 (1,522,000)
---------- ----------- ----------
$1,728,000 $ 878,000 $ 692,000
========== =========== ===========
In November 1995, officials of the U.S. and Canada ratified a new
agreement amending the Canada-U.S. Tax Treaty that reduced the Canadian Branch
tax. This change resulted in the recognition of a deferred Canadian income tax
benefit of $290,000 in the year ended September 30, 1996.
For fiscal 1997 and 1996, $11,000 and $27,000, 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 gain or loss on available for sale securities were
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,
--------------------------------------
1997 1996 1995
----------- --------- ----------
Tax computed by applying statutory rate $ 972,000 $ 738,000 $ 470,000
Effect of foreign tax
provision on the total tax provision 783,000 492,000 206,000
Effect on deferred income
tax assets and liabilities of
reduction in Canadian Branch tax rate - (290,000) -
Other (27,000) (62,000) 16,000
----------- --------- ----------
$ 1,728,000 $ 878,000 $ 692,000
=========== ========= ==========
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at September
30, 1997 and 1996 are as follows:
Deferred income tax assets: 1997 1996
----------- -----------
U.S. tax effect of deferred Canadian taxes $ 2,335,000 $ 2,073,000
Tax basis in land in excess of book basis 1,075,000 1,092,000
Foreign tax credit carryforward 211,000 214,000
Write-off of asset not deducted for tax 148,000 148,000
Other 616,000 601,000
----------- -----------
Total gross deferred tax assets 4,385,000 4,128,000
Less-valuation allowance (2,601,000) (2,408,000)
----------- -----------
Net deferred income tax assets 1,784,000 1,720,000
----------- -----------
Deferred income tax liabilities:
Property and equipment accumulated tax
depreciation and depletion in excess of book (6,869,000) (6,098,000)
Other (616,000) (512,000)
----------- -----------
Total deferred income tax liabilities (7,485,000) (6,610,000)
----------- -----------
Net deferred income tax liability $(5,701,000) $(4,890,000)
=========== ===========
The total valuation allowance increased $193,000 and $40,000 for the
years ended September 30, 1997 and 1996, respectively. The increase for the year
ended September 30, 1997 relates primarily to United States tax deductions for
the payment of deferred Canadian taxes for which it is more likely than not that
some portion or all of such Canadian taxes cannot be utilized to reduce the
Company's U.S. tax obligation. 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 $3,600,000 at
September 30, 1997, expiring between fiscal years 2000 and 2012.
A valuation allowance is provided when it is more likely than not that
some portion or all of the deferred tax asset will not be realized. The Company
has established a valuation allowance for Canadian tax deductions, foreign tax
credits and state of Hawaii net operating loss carryforwards which may not be
realizable in future years as there can be no assurance of any specific level of
earnings or that the timing of U.S. earnings will coincide with the payment of
Canadian taxes to enable Canadian taxes to be fully deducted (or recoverable)
for U.S. tax purposes. 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, 1997 are invested as follows: 56% listed government mortgages and
44% common stocks.
The funded status of the pension plan and the amounts recognized in the
consolidated financial statements are as follows:
September 30,
------------------------
1997 1996
----------- -----------
Actuarial present value of benefit obligations:
Vested $ 1,462,000 $ 1,369,000
=========== ===========
Accumulated benefit obligation $ 1,513,000 $ 1,422,000
=========== ===========
Projected benefit obligation $(1,950,000) $(1,812,000)
Plan assets at fair value 2,171,000 1,928,000
----------- -----------
Plan assets greater than projected benefit obligation 221,000 116,000
Unrecognized net gain (332,000) (175,000)
Unrecognized prior service cost 46,000 51,000
Unrecognized net transition asset (4,000) (5,000)
----------- -----------
Net pension liability $ (69,000) $ (13,000)
=========== ===========
As of September 30, 1997 and 1996, the discount rate utilized in
determining the actuarial present value of the projected benefit obligation was
7.5%.
Net pension cost is comprised of the following components and actuarial
assumptions:
Year ended September 30,
-------------------------------
1997 1996 1995
-------- -------- --------
Service cost, benefits earned during the year $ 64,000 $ 61,000 $ 38,000
Interest cost on projected benefit obligation 136,000 130,000 126,000
Actual return on plan assets (381,000) (151,000) (217,000)
Net amortization and deferral 238,000 13,000 90,000
-------- -------- --------
Net pension cost $ 57,000 $ 53,000 $ 37,000
======== ======== ========
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% 8.0%
===== ===== ====
9. STOCK OPTIONS
-------------
The Company has outstanding stock options under a qualified plan which
expired in November 1991. Under this plan, options to purchase a maximum of
120,000 shares of the Company's common stock could be granted to officers and
key employees of the Company and its subsidiaries at prices not less than 100%
of the fair market value at the date of the option grant. Options granted under
this plan became exercisable 25% annually beginning one year from the date of
grant and expire five or ten years from the date of grant.
In March 1995, the Company granted 20,000 stock options to an officer
of the Company under a non-qualified plan at a purchase price of $19.625 per
share (market price on date of grant), with 4,000 of such options vesting
annually commencing one year from the date of grant. These options have stock
appreciation rights 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 applies the provisions of APB Opinion No. 25 in accounting
for stock-based compensation and adopted the disclosure-only provisions of
Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS No. 123"), effective October 1, 1996. Adoption of the fair
value method of measuring stock-based compensation provisions of SFAS No. 123
would have had no impact on the Company's net earnings or earnings per share for
the years ended September 30, 1997 and 1996.
There were no stock option transactions during the years ended
September 30, 1997 and 1996.
Stock options at September 30, 1997 were as follows:
Number of options
---------------------------
Per share price Outstanding Exercisable Expiration Date
--------------- ----------- ----------- ---------------
$13.625 14,000 14,000 December 1998
$19.625 20,000 8,000 March 2000
$22.250 10,000 10,000 May 1999
------ ------
Total 44,000 32,000
====== ======
Weighted average
exercise price $18.31 $17.82
====== ======
Stock options at September 30, 1996 were as follows:
Number of options
---------------------------
Per share price Outstanding Exercisable Expiration Date
--------------- ----------- ----------- ---------------
$13.625 14,000 14,000 December 1998
$19.625 20,000 4,000 March 2000
$22.250 10,000 10,000 May 1999
------ ------
Total 44,000 28,000
====== ======
Weighted average
exercise price $18.31 $17.56
====== ======
Privately negotiated repurchases of common stock may be made if
suitable opportunities become available. At September 30, 1997, 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, 1997, the loan balance
was $337,000, $100,000 of which is to an affiliate of the Company. The three
participants' interests in the venture are pledged as collateral to secure
repayment of the loans. The Company believes the value of the collateral is
significantly in excess of the loan balances.
The Company has committed to construct $200,000 of improvements at its
yard at Sand Island on Oahu, Hawaii, by September 1998.
The Company has several operating leases for office space. Rental
expense was $397,000 in 1997, $398,000 in 1996, and $392,000 in 1995. The
Company is committed under several non-cancelable operating leases for office
and other space with minimum rental payments summarized by fiscal year as
follows: 1998 - $402,000, 1999 - $389,000, 2000 - $387,000, 2001 - $342,000,
2002 - $338,000 and thereafter an aggregate of $1,888,000.
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>
Year ended September 30,
---------------------------------------
1997 1996 1995
Revenues: ---------- ----------- -----------
<S> <C> <C> <C>
Oil and natural gas $11,520,000 $10,660,000 $10,520,000
Contract drilling 2,160,000 2,650,000 3,770,000
Other 873,000 717,000 420,000
----------- ----------- -----------
Total $14,553,000 $14,027,000 $14,710,000
=========== =========== ===========
Depreciation, depletion and amortization:
Oil and natural gas $ 2,761,000 $ 2,658,000 $ 2,658,000
Contract drilling 93,000 172,000 317,000
Other 190,000 130,000 128,000
----------- ----------- -----------
Total $ 3,044,000 $ 2,960,000 $ 3,103,000
=========== =========== ===========
Capital expenditures:
Oil and natural gas $ 6,477,000 $ 5,049,000 $ 3,434,000
Contract drilling 189,000 53,000 83,000
Land investment 733,000 646,000 293,000
Other 97,000 219,000 120,000
----------- ----------- -----------
Total $ 7,496,000 $ 5,967,000 $ 3,930,000
=========== =========== ===========
Operating profit (before general
and administrative expenses):
Oil and natural gas $ 5,433,000 $ 4,596,000 $ 4,489,000
Contract drilling 217,000 593,000 563,000
Other 683,000 587,000 292,000
----------- ----------- -----------
Total 6,333,000 5,776,000 5,344,000
General and administrative expenses (3,208,000) (3,114,000) (3,772,000)
Interest expense (624,000) (707,000) (756,000)
Interest income 277,000 153,000 240,000
Minority interest in losses - - 286,000
----------- ----------- -----------
Earnings before income taxes $ 2,778,000 $ 2,108,000 $ 1,342,000
=========== =========== ===========
</TABLE>
Depletion per 1,000 cubic feet of natural gas (MCF) and natural gas
equivalent was $0.46 in fiscal 1997, $0.44 in fiscal 1996 and $0.40 in fiscal
1995. The increases in the per unit rate were due to increasingly higher finding
costs.
<TABLE>
<CAPTION>
September 30,
------------------------------------------------------------
ASSETS BY SEGMENT: 1997 1996 1995
- ------------------ ------------------ ------------------ ------------------
<S> <C> <C> <C> <C> <C> <C>
Oil and natural gas:
Canada (1) $23,220,000 68% $22,003,000 71% $20,470,000 71%
United States (2) 1,878,000 5% 619,000 2% 448,000 2%
----------- ---- ----------- ---- ----------- ----
Total oil and natural gas 25,098,000 73% 22,622,000 73% 20,918,000 73%
Contract drilling (3) 1,700,000 5% 1,911,000 6% 2,461,000 9%
Land investment (3) 1,848,000 5% 1,115,000 4% 648,000 2%
Other:
Cash 4,402,000 13% 3,553,000 12% 2,976,000 10%
Corporate and other 1,350,000 4% 1,579,000 5% 1,777,000 6%
----------- ---- ----------- ---- ----------- ----
Total $34,398,000 100% $30,780,000 100% $28,780,000 100%
=========== ==== =========== ==== =========== ====
<FN>
(1) Primarily located in the Province of Alberta, Canada.
(2) Located in Michigan, North Dakota and Louisiana.
(3) Located in Hawaii.
</FN>
</TABLE>
<TABLE>
ASSETS BY GEOGRAPHIC AREA:
- --------------------------
<CAPTION>
September 30,
------------------------------------------------------------
1997 1996 1995
------------------ ------------------ ------------------
<S> <C> <C> <C> <C> <C> <C>
United States $ 9,166,000 27% $ 6,880,000 22% $ 6,308,000 22%
Canada 25,232,000 73% 23,900,000 78% 22,472,000 78%
----------- ---- ------------ ---- ----------- ----
Total $34,398,000 100% $30,780,000 100% $28,780,000 100%
=========== ==== ============ ==== =========== ====
CAPITAL EXPENDITURES BY GEOGRAPHIC AREA:
- ----------------------------------------
Year ended September 30,
------------------------------------------------------------
1997 1996 1995
------------------ ------------------ ------------------
United States $ 2,739,000 37% $ 1,100,000 18% $ 780,000 20%
Canada 4,757,000 63% 4,867,000 82% 3,150,000 80%
----------- ---- ----------- ---- ----------- ----
Total $ 7,496,000 100% $ 5,967,000 100% $ 3,930,000 100%
=========== ==== =========== ==== =========== ====
</TABLE>
OPERATIONS BY GEOGRAPHIC AREA:
- ------------------------------
Year ended September 30,
--------------------------------------
1997 1996 1995
---------- ----------- -----------
Revenue:
United States $ 2,373,000 $ 2,938,000 $ 3,965,000
Canada 12,180,000 11,089,000 10,745,000
----------- ----------- -----------
Total $14,553,000 $14,027,000 $14,710,000
=========== =========== ===========
Depreciation,
depletion, and amortization:
United States $ 703,000 $ 404,000 $ 448,000
Canada 2,341,000 2,556,000 2,655,000
----------- ----------- -----------
Total $ 3,044,000 $ 2,960,000 $ 3,103,000
=========== =========== ===========
Operating profit (loss)(before
general and administrative expenses):
United States $ (238,000) $ 592,000 $ 613,000
Canada 6,571,000 5,184,000 4,731,000
----------- ----------- -----------
Total $ 6,333,000 $ 5,776,000 $ 5,344,000
=========== =========== ===========
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
-----------------------------------
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%, 19% and 15% of
its oil and natural gas revenues in fiscal 1997, 1996 and 1995, respectively,
from one company. At September 30, 1997, the Company had a receivable from the
aforementioned company of approximately $177,000.
The Company's contract drilling subsidiary derived 73%, 42% and 28% of
its contract drilling revenues in fiscal 1997, 1996, and 1995, respectively,
pursuant to State of Hawaii and local county contracts. At September 30, 1997,
the Company had accounts receivable from the State of Hawaii and local county
entities totaling approximately $396,000. 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, 1997.
14. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
-------------------------------------------------
<TABLE>
The following details the effect of changes in current assets and
liabilities on the consolidated statements of cash flows, and presents
supplemental cash flow information:
<CAPTION>
Year ended September 30,
----------------------------------------
1997 1996 1995
----------- ----------- ----------
Increase (decrease) from changes in:
<S> <C> <C> <C>
Proceeds from sale of trading securities $ - $ - $ 958,000
Receivables 167,000 593,000 131,000
Costs and estimated earnings in excess
of billings on uncompleted contracts 106,000 (23,000) 85,000
Inventories (15,000) 43,000 7,000
Other current assets 17,000 (68,000) 62,000
Accounts payable 1,510,000 645,000 (457,000)
Accrued expenses 539,000 67,000 (272,000)
Billings in excess of costs and
estimated earnings on uncompleted
contracts 11,000 (416,000) 185,000
Payable to joint interest owners 289,000 274,000 118,000
Income taxes payable (155,000) 158,000 (838,000)
----------- ----------- ----------
Increase (decrease) from changes
in current assets and liabilities $ 2,469,000 $ 1,273,000 $ (21,000)
=========== =========== ==========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 636,000 $ 740,000 $ 764,000
=========== =========== ===========
Income taxes $ 1,146,000 $ 614,000 $ 3,288,000
=========== =========== ===========
</TABLE>
15. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)
---------------------------------------------------------
The following tables summarize information relative to the Company's
oil and natural gas operations, which are substantially 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
----------------------------
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, 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
Revisions of previous estimates 169,000 761,000
Extensions, discoveries and other additions 339,000 1,786,000
Less production (264,000) (3,852,000)
Sales of reserves in place (5,000) (996,000)
--------- ----------
Balance at September 30, 1997 2,613,000 43,951,000
========= ==========
OIL GAS
Proved developed producing reserves at: (Barrels) (MCF)
--------- ----------
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
========= ==========
September 30, 1997 2,087,000 29,483,000
========= ==========
Included in the above tables are proved developed producing reserves in the
U.S. of 33,000 barrels of oil and 120,000 MCF of natural gas at September 30,
1997, and 50,000 barrels of oil and 39,000 MCF of natural gas at September 30,
1996.
(B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities
----------------------------------------------------------------------
<TABLE>
September 30,
----------------------------------------------------------------------
1997 1996 1995
---------------------------------------- ----------- -----------
<CAPTION>
United
Canadian States Total
----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Proved properties $43,221,000 $ 1,148,000 $44,369,000 $39,496,000 $35,438,000
Unproved properties 1,006,000 1,399,000 2,405,000 2,401,000 2,361,000
----------- ----------- ----------- ----------- -----------
Total
capitalized costs 44,227,000 2,547,000 46,774,000 41,897,000 37,799,000
Accumulated depletion
and depreciation 22,837,000 644,000 23,481,000 21,033,000 18,644,000
----------- ----------- ----------- ----------- -----------
Net capitalized costs $21,390,000 $ 1,903,000 $23,293,000 $20,864,000 $19,155,000
=========== =========== =========== =========== ===========
<FN>
As of September 30, 1996 and 1995, U.S. capitalized costs totaled $823,000 and
$448,000, respectively.
</FN>
</TABLE>
(C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration
-----------------------------------------------------------------------
and Development
---------------
Year ended September 30,
-----------------------------------------------
1997 1996 1995
---------- ---------- ----------
Acquisition of properties:
Unproved -
Canadian $ 258,000 $ 414,000 $ 120,000
United States 1,100,000 115,000 56,000
---------- ---------- ----------
$1,358,000 $ 529,000 $ 176,000
========== ========== ==========
Proved -
Canadian $ 316,000 $ 94,000 $ 152,000
United States - 30,000 -
---------- ---------- ----------
$ 316,000 $ 124,000 $ 152,000
========== ========== ==========
Exploration costs:
Canadian $ 936,000 $ 972,000 $ 117,000
United States 279,000 85,000 156,000
---------- ---------- ----------
$1,215,000 $1,057,000 $ 273,000
========== ========== ==========
Development costs:
Canadian $3,217,000 $3,189,000 $2,699,000
United States 371,000 150,000 134,000
---------- ---------- ----------
$3,588,000 $3,339,000 $2,833,000
========== ========== ==========
(D) The Results of Operations of Barnwell's Oil and Natural Gas Producing
---------------------------------------------------------------------
Activities
----------
Year ended September 30,
-----------------------------------------
1997 1996 1995
----------- ----------- -----------
Gross revenues:
United States $ 210,000 $ 266,000 $ 160,000
Canada 13,110,000 11,535,000 11,207,000
---------- ----------- -----------
Total gross revenues 13,320,000 11,801,000 11,367,000
Royalties, net of credit 1,800,000 1,141,000 847,000
----------- ----------- -----------
Net revenues 11,520,000 10,660,000 10,520,000
Production costs 3,326,000 3,406,000 3,373,000
Depletion and depreciation 2,761,000 2,658,000 2,658,000
----------- ----------- -----------
Pre-tax results of operations 5,433,000 4,596,000 4,489,000
Estimated income tax expense 2,760,000 2,441,000 2,338,000
----------- ----------- -----------
Results of operations $ 2,673,000 $ 2,155,000 $ 2,151,000
=========== =========== ===========
(E) Standardized Measure, Including Year-to-Year Changes Therein, of
----------------------------------------------------------------
Discounted Future Net Cash Flows
--------------------------------
The following tables have been developed pursuant to procedures
prescribed by SFAS 69, and utilize reserve and production data estimated by
petroleum engineers. The information may be useful for certain comparison
purposes but should not be solely relied upon in evaluating the Company or its
performance. Moreover, the projections should not be construed as realistic
estimates of future cash flows, nor should the standardized measure be viewed as
representing current value.
The future cash flows are based on sales prices, costs, and statutory
income tax rates in existence at the dates of the projections. Material
revisions to reserve estimates may occur in the future, development and
production of the oil and natural gas reserves may not occur in the periods
assumed and actual prices realized and actual costs incurred are expected to
vary significantly from those used. Management does not rely upon this
information in making investment and operating decisions; rather, those
decisions are based upon a wide range of factors, including estimates of
probable reserves as well as proved reserves and price and cost assumptions
different than those reflected herein.
Standardized Measure of Discounted Future Net Cash Flows
- --------------------------------------------------------
As of September 30,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
Future cash inflows $106,086,000 $ 91,916,000 $ 74,143,000
Future production costs (36,965,000) (24,466,000) (25,690,000)
Future development costs (1,980,000) (1,447,000) (2,289,000)
------------ ------------ ------------
Future net cash
flows before income taxes 67,141,000 66,003,000 46,164,000
Future income tax expenses (21,369,000) (20,424,000) (12,341,000)
------------ ------------ ------------
Future net cash flows 45,772,000 45,579,000 33,823,000
10% annual discount
for timing of cash flows (17,790,000) (18,485,000) (13,473,000)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 27,982,000 $ 27,094,000 $ 20,350,000
============ ============ ============
Changes in the Standardized Measure of Discounted Future Net Cash Flows
- -----------------------------------------------------------------------
Year ended September 30,
---------------------------------------
1997 1996 1995
----------- ----------- -----------
Beginning of year $27,094,000 $20,350,000 $31,262,000
----------- ----------- -----------
Sales of oil and natural gas
produced, net of production costs (8,194,000) (7,254,000) (7,147,000)
Net changes in prices and
production costs, net of
royalties and wellhead taxes 3,233,000 15,257,000 (13,335,000)
Extensions and discoveries 3,921,000 2,173,000 941,000
Sales of reserves in place (970,000) (415,000) (482,000)
Revisions of previous
quantity estimates 1,937,000 366,000 63,000
Net change in Canadian
dollar translation rate (362,000) (290,000) (144,000)
Changes in the timing of
future production and other (860,000) (346,000) (604,000)
Net change in income taxes (491,000) (4,896,000) 6,413,000
Accretion of discount 2,674,000 2,149,000 3,383,000
----------- ----------- -----------
Net change 888,000 6,744,000 (10,912,000)
----------- ----------- -----------
End of year $27,982,000 $27,094,000 $20,350,000
=========== =========== ===========
Item 8. Changes in and Disagreements with Accountants on Accounting and
---------------------------------------------------------------
Financial Disclosure
--------------------
None.
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons,
-------------------------------------------------------------
Compliance With Section 16(a) of the Exchange Act
-------------------------------------------------
Item 10. Executive Compensation
----------------------
Item 11. Security Ownership of Certain Beneficial Owners and Management
--------------------------------------------------------------
Item 12. Certain Relationships and Related Transactions
----------------------------------------------
Items 9, 10, 11, and 12 are omitted pursuant to General Instructions
E(3) of Form 10-KSB, since the Registrant will file its definitive proxy
statement for the 1998 Annual Meeting of Stockholders not later than 120 days
after the close of its fiscal year ended September 30, 1997, 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, 1997 and 1996
Consolidated Statements of Operations -
for the three years ended September 30, 1997
Consolidated Statements of Cash Flows -
for the three years ended September 30, 1997
Consolidated Statements of Stockholders' Equity -
for the three years ended September 30, 1997
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, 1997.
(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>
BARNWELL INDUSTRIES, INC.
AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<CAPTION>
Balance at Additions Balance
beginning charged to at end
of year expense Deductions of year
---------- ---------- ---------- --------
<S> <C> <C> <C> <C>
YEAR ENDED SEPTEMBER 30, 1997:
Allowance for doubtful
accounts - accounts
receivable $ 10,000 $ - $ - $ 10,000
Allowance for doubtful
accounts - long-term notes
receivable - - - -
---------- ---------- ---------- --------
Total allowance for doubtful
accounts $ 10,000 $ - $ - $ 10,000
========== ========== ========== ========
YEAR ENDED SEPTEMBER 30, 1996:
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
========== ========== ========== ========
<FN>
(1) Collections.
(2) Accounts written off less recoveries.
</FN>
</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 4, 1997
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 4, 1997
/s/ Martin Anderson /s/ Alan D. Hunter
MARTIN ANDERSON, Director ALAN D. HUNTER, Director
Date: December 5, 1997 Date: December 5, 1997
/s/ Daniel Jacobson
H. WHITNEY BOGGS, JR., Director DANIEL JACOBSON, Director
Date: December 4, 1997
/s/ Barry E. Emes
BARRY E. EMES, Director WILLIAM C. WARREN, Director
Date: December 4, 1997
/s/ Erik Hazelhoff-Roelfzema /s/ Glenn Yago
ERIK HAZELHOFF-ROELFZEMA, Director GLENN YAGO, Director
Date: December 5, 1997 Date: December 4, 1997
/s/ Murray C. Gardner
MURRAY C. GARDNER, Director
Date: December 5, 1997
Exhibit 21 List of Subsidiaries
The subsidiaries of Barnwell Industries, Inc., at September 30, 1997 were:
Percentage Jurisdiction of
Name of Subsidiary of Ownership Incorporation
- ------------------ ------------ ---------------
Barnwell of Canada, Limited 100% Delaware
Barnwell Hawaiian Properties, Inc. 100% Delaware
Water Resources International, Inc. 100% Delaware
Barnwell Management Co., Inc. 100% Delaware
Barnwell Shallow Oil, Inc. 100% Delaware
Barnwell Geothermal Corporation 100% Delaware
Barnwell Mining Co. 100% Delaware
Barnwell Overseas, Inc. 100% Delaware
Geothermal Exploration and Development Corp. 100% Delaware
Victoria Properties, Inc. 100% Delaware
Barnwell Financial Corporation 100% Delaware
NDTX, Inc. 100% Delaware
Barnwell Investment Corporation 100% Hawaii
Barnwell Kona Corporation 100% Hawaii
WRI Properties, Inc. 100% Hawaii
Barnwell Israel, Ltd. 100% Israel
Barnwell Oil & Gas, Ltd. 100% Israel
Bill Robbins Drilling, Ltd. 100% Alberta, Canada
Gypsy Petroleums Ltd. 100% Alberta, Canada
Dartmouth Petroleum, Ltd. 100% Alberta, Canada
J.H. Wilson Associates, Ltd. 100% Alberta, Canada
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from
Barnwell Industries, Inc.'s 1997 10-KSB and is qualified in its
entirety by reference to such 10-KSB filing.
</LEGEND>
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1997
<PERIOD-END> SEP-30-1997
<CASH> 4402
<SECURITIES> 0
<RECEIVABLES> 2075
<ALLOWANCES> 10
<INVENTORY> 70
<CURRENT-ASSETS> 6952
<PP&E> 58191
<DEPRECIATION> 33084
<TOTAL-ASSETS> 34398
<CURRENT-LIABILITIES> 5347
<BONDS> 11100
0
0
<COMMON> 821
<OTHER-SE> 11329
<TOTAL-LIABILITY-AND-EQUITY> 34398
<SALES> 13680
<TOTAL-REVENUES> 14830
<CGS> 5176
<TOTAL-COSTS> 5176
<OTHER-EXPENSES> 3044
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 624
<INCOME-PRETAX> 2778
<INCOME-TAX> 1728
<INCOME-CONTINUING> 1050
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1050
<EPS-PRIMARY> .79
<EPS-DILUTED> 0
</TABLE>
