-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, GuayHt2Ot4b/Umy0BkAIRyilsu7bxubUz2abAx4kyJMjXvvp5ie4VlJmqt+WfjVt 2eLvodEX5uPj/I9myq5DUg== 0000010048-00-000011.txt : 20001220 0000010048-00-000011.hdr.sgml : 20001220 ACCESSION NUMBER: 0000010048-00-000011 CONFORMED SUBMISSION TYPE: 10KSB PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20000930 FILED AS OF DATE: 20001219 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BARNWELL INDUSTRIES INC CENTRAL INDEX KEY: 0000010048 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 720496921 STATE OF INCORPORATION: DE FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10KSB SEC ACT: SEC FILE NUMBER: 001-05103 FILM NUMBER: 791784 BUSINESS ADDRESS: STREET 1: 1100 ALAKEA ST. STREET 2: SUITE 2900 CITY: HONOLULU STATE: HI ZIP: 96813 BUSINESS PHONE: 808-531-8400 MAIL ADDRESS: STREET 1: 1100 ALAKEA ST. STREET 2: SUITE 2900 CITY: HONOLULU STATE: HI ZIP: 96813 FORMER COMPANY: FORMER CONFORMED NAME: BMA CORP/TN DATE OF NAME CHANGE: 19770324 FORMER COMPANY: FORMER CONFORMED NAME: BARNWELL OFFSHORE INC DATE OF NAME CHANGE: 19671101 10KSB 1 0001.txt BARNWELL INDUSTRIES, INC. 9/30/2000 10KSB U.S. SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-KSB X ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE --- SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 2000 TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE --- SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-5103 BARNWELL INDUSTRIES, INC. (Name of small business issuer in its charter) DELAWARE 72-0496921 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1100 Alakea Street, Suite 2900, Honolulu, Hawaii 96813-2833 (Address of principal executive offices) (Zip code) (808) 531-8400 (Issuer's telephone number) Securities registered under Section 12(b) of the Exchange Act: Title of each class Name of each exchange on which registered ------------------- ----------------------------------------- Common Stock, par value American Stock Exchange $0.50 per share Toronto Stock Exchange Securities registered under Section 12(g) of the Exchange Act: None Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ----- ----- Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B, and no disclosure will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. [X] Issuer's revenues for the fiscal year ended September 30, 2000: $26,570,000 The aggregate market value of the voting stock held by non-affiliates (590,797 shares) of the Registrant on December 15, 2000, based on the closing price of $18.50 on that date on the American Stock Exchange, was $10,930,000. As of December 15, 2000 there were 1,310,952 shares of common stock, par value $.50, outstanding. Documents Incorporated by Reference ----------------------------------- 1. Proxy statement to be forwarded to shareholders on or about January 18, 2001 is incorporated by reference in Part III hereof. Transitional Small Business Disclosure Format Yes No X ----- ----- 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, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including various forecasts, projections of Barnwell Industries, Inc.'s (referred to herein together with its subsidiaries as "Barnwell" or the "Company") future performance, statements of the Company's plans and objectives and other similar types of information. Although the Company believes that its expectations are based on reasonable assumptions, it cannot assure that the expectations contained in such forward-looking statements will be achieved. Such statements involve risks, uncertainties and assumptions, including, but not limited to, those relating to the factors discussed below, in other portions of this Form 10-KSB, in the Notes to Consolidated Financial Statements, and in other documents filed by the Company with the Securities and Exchange Commission from time to time, which could cause actual results to differ materially from those contained in such statements. These forward-looking statements speak only as of the date of filing of this Form 10-KSB, and the Company expressly disclaims any obligation or undertaking to publicly release any updates or revisions to any forward-looking statements contained herein. The Company's oil and natural gas operations are affected by domestic and international political, legislative, regulatory and legal actions. Such actions may include changes in the policies of the Organization of Petroleum Exporting Countries ("OPEC") or other developments involving or affecting oil-producing countries, including military conflict, embargoes, internal instability or actions or reactions of the government of the United States in anticipation of or in response to such developments. Domestic and international economic conditions, such as recessionary trends, inflation, interest costs, monetary exchange rates and labor costs, as well as changes in the availability and market prices of crude oil, natural gas and petroleum products, may also have a significant effect on the Company's oil and natural gas operations. While the Company maintains reserves for anticipated liabilities and carries various levels of insurance, the Company could be affected by civil, criminal, regulatory or administrative actions, claims or proceedings. In addition, climate and weather can significantly affect the Company in several of its operations. The Company's oil and gas operations are also affected by political developments and laws and regulations, particularly in the United States and Canada, such as restrictions on production, restrictions on imports and exports, the maintenance of specified reserves, tax increases and retroactive tax claims, expropriation of property, cancellation of contract rights, environmental protection controls, environmental compliance requirements and laws pertaining to workers' health and safety. The Company's land investment business segment is affected by the condition of Hawaii's real estate market. The Hawaii real estate market is affected by Hawaii's economy in general and Hawaii's tourism industry in particular. Any future cash flows from the Company's land development activities are subject to, among other factors, the level of real estate activity and prices, the demand for new housing and second homes on the Island of Hawaii, the rate of increase in the cost of building materials and labor, the introduction of building code modifications, changes to zoning laws, and the level of consumer confidence in Hawaii's economy. The Company's contract drilling operations, which are located in Hawaii, are also indirectly affected by the factors discussed in the preceding paragraph. The Company's contract drilling operations are materially dependent upon levels of activity in land development in Hawaii. Such activity levels are affected by both short-term and long-term trends in Hawaii's economy. In prior years, Hawaii's economy has experienced very slow growth, and as events during previous years have demonstrated, any prolonged reduction or lack of growth in Hawaii's economy will depress the demand for the Company's contract drilling services. Such a decline could have a material adverse effect on the Company's contract drilling revenues and profitability. Item 1. Description of Business ----------------------- (a) General Development of Business ------------------------------- Barnwell was incorporated in 1956. During its last three fiscal years, the Company was engaged in oil and natural gas exploration, development, production and sales primarily in Canada, investment in leasehold land in Hawaii, and water and exploratory well drilling and water pumping system installation and repair in Hawaii. Additionally, the Company has provided contract labor for the drilling and workovers of geothermal wells. The Company's oil and natural gas activities comprise its largest business segment. Approximately 57% of the Company's revenues for the fiscal year ended September 30, 2000 were attributable to its oil and natural gas activities. The Company's land investment activity accounted for 25% of the Company's revenues in fiscal 2000. The Company's contract drilling activities accounted for 13% of the Company's revenues in fiscal 2000, with natural gas processing and other revenues comprising the remaining 5% of fiscal 2000 revenues. Approximately 80% of the Company's capital expenditures for the fiscal year ended September 30, 2000, were attributable to oil and natural gas activities, 10% to land investment, 6% to contract drilling activities and 4% to other activities. (i) Oil and Natural Gas Activities. ----------------------------------- The Company's wholly-owned subsidiary, Barnwell of Canada, Limited ("BOC"), is involved in the acquisition, exploration and development of oil and natural gas properties, principally in Alberta, Canada. BOC participates in exploratory and developmental operations for oil and natural gas on property in which it has an interest and evaluates proposals by third parties with regard to participation in such exploratory and developmental operations elsewhere. (ii) Contract Drilling. ------------------ The Company's wholly-owned subsidiary, Water Resources International, Inc. ("WRI"), drills water, geothermal and exploratory wells and installs and repairs water pumping systems in Hawaii. WRI owns and operates four rotary drill rigs, one rotary drill/workover rig, and pump installation and service equipment, and maintains drilling materials and pump inventory in Hawaii. WRI's contracts are usually fixed price per lineal foot drilled or day rate contracts that are either negotiated with private individuals or entities, or are obtained through competitive bidding with various private entities or local, state and federal agencies. (iii) Land Investment. ---------------- The Company owns a 50.1% controlling interest in Kaupulehu Developments, a Hawaii general partnership. Between 1986 and 1989, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of the Four Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club, a second golf course (currently under construction), and single and multiple family residential units on land acquired from Kaupulehu Developments. Kaupulehu Developments currently owns development rights in approximately 80 acres of residentially zoned leasehold land and leasehold rights in approximately 2,100 acres of land located in the North Kona District of the Island of Hawaii. (b) Financial Information about Industry Segments --------------------------------------------- Revenues of each industry segment for the fiscal years ended September 30, 2000, 1999 and 1998 are summarized as follows (all revenues were from unaffiliated customers with no intersegment sales or transfers): 2000 1999 1998 ---------------- ---------------- ---------------- Oil and natural gas $15,270,000 57% $10,130,000 67% $ 9,400,000 79% Contract drilling 3,520,000 13% 4,230,000 28% 1,510,000 13% Land investment 6,540,000 25% - - - - Other 891,000 4% 668,000 4% 920,000 7% ----------- ---- ----------- ---- ----------- ---- Revenues from segments 26,221,000 99% 15,028,000 99% 11,830,000 99% Interest income 349,000 1% 132,000 1% 90,000 1% ----------- ---- ----------- ---- ----------- ---- Total revenues $26,570,000 100% $15,160,000 100% $11,920,000 100% =========== ==== =========== ==== =========== ==== For further discussion see Note 11 (Segment and Geographic Information) and Note 13 (Concentrations of Credit Risk) of "Notes to Consolidated Financial Statements" in Item 7. (c) Narrative Description of Business --------------------------------- See the table above in Item 1(b) detailing revenue of each industry segment and description of each industry segment of the Company's business under Item 2. As of September 30, 2000, Barnwell employed 44 employees, all on a full-time basis. Twenty are employed in contract drilling activities, 13 are employed in oil and natural gas activities, and 11 are members of the corporate and administrative staff. This is a decrease of 27 employees, all contract drilling employees temporarily hired for coring and geothermal drilling projects, as compared to 71 employees at September 30, 1999. For further discussion see "Governmental Regulation" and "Competition" sections in Item 2 hereof. (d) Financial Information about Foreign and Domestic Operations and ------------------------------------------------------------------- Export Sales ------------ Revenues and long-lived assets by geographic area for the three years ended and as of September 30, 2000, 1999 and 1998 are set forth in Note 11 (Segment and Geographic Information) of "Notes to Consolidated Financial Statements" in Item 7. Item 2. Description of Property ----------------------- OIL AND NATURAL GAS OPERATIONS ------------------------------ General - ------- Barnwell's investments in oil and natural gas properties consist of investments in Canada, principally in the Province of Alberta, with minor holdings in Saskatchewan, British Columbia and North Dakota. These property interests are principally held under governmental leases or licenses. Under the typical Canadian provincial governmental lease, Barnwell must perform exploratory operations and comply with certain other conditions. Lease terms vary with each province, but, in general, the terms grant Barnwell the right to remove oil, natural gas and related substances subject to payment of specified royalties on production. Barnwell participates in exploratory and developmental operations for oil and natural gas on property in which it has an interest. The Company also evaluates proposals by third parties for participation in other exploratory and developmental opportunities. All exploratory and developmental operations are overseen by Barnwell's Calgary, Alberta staff along with independent consultants as necessary. In fiscal 2000, Barnwell participated in exploratory and developmental operations in the Canadian Provinces of Alberta and British Columbia, although Barnwell does not limit its consideration of exploratory and developmental operations to these areas. Barnwell's producing natural gas properties are located principally in Alberta. A small amount of producing properties are located in British Columbia and Saskatchewan. The Province of Alberta determines its royalty share of natural gas by using a reference price that averages all natural gas sales in Alberta. Royalty rates are calculated on a sliding scale basis, increasing as prices increase. Additionally, Barnwell pays gross overriding royalties on a portion of its natural gas sales to other parties. In fiscal 2000, the weighted average rate of royalties paid on natural gas from the Dunvegan Unit, Barnwell's principal oil and natural gas property, before the Alberta Royalty Tax Credit, was approximately 30%. The weighted average rate of royalties paid on all of the Company's natural gas was approximately 15% in fiscal 2000, versus approximately 12% in fiscal 1999. The increase in the weighted average royalty rate was primarily due to higher gas prices in fiscal 2000. In fiscal 2000, virtually all of Barnwell's oil production was from properties located in Alberta. A small amount of producing properties are located in North Dakota. Royalty rates under government leases in Alberta are based on the selling price of oil and production volumes. In fiscal 2000, the weighted average royalty rate paid on oil was approximately 27%. In fiscal 1999, the weighted average royalty rate paid on oil was approximately 20%. Unit sales and prices of natural gas are typically higher in the winter than at other times due to demand for heating. Unit sales and prices of oil are also subject to seasonal fluctuations, but to a lesser degree. Well Drilling Activities - ------------------------ During fiscal 2000, the Company participated in the drilling of 32 development wells and eight exploratory wells, of which, in the Company's view, 34 are capable of production. The Company also participated in the recompletion of 13 wells. The most significant drilling and recompletion operations took place in the Dunvegan area; see paragraph below. Additionally, the Company participated in drilling seven gross, 0.71 net, new development wells at Manyberries, and four gross, 0.22 net, new development wells at Red Earth/Loon. These three areas are all in Alberta. The Dunvegan Unit, which is the Company's principal oil and natural gas property and is located in Alberta, Canada, has over 140 natural gas wells producing from over 200 well zones. The Company holds an 8.9% interest in the Dunvegan Unit. In fiscal 2000, the Company spent approximately $460,000 to further develop the property through drilling and recompletions and $170,000 on production equipment. Specifically, the Company participated in the drilling of two natural gas wells and the recompletion of eight natural gas wells. The results of the 2000 program were positive with the majority of the recompletions contributing to natural gas production. The following table sets forth more detailed information with respect to the number of exploratory ("Exp.") and development ("Dev.") wells drilled for the fiscal years ended September 30, 2000, 1999 and 1998 in which the Company participated: Total Productive Productive Productive Oil Wells Gas Wells Wells Dry Holes Total Wells ----------- ----------- ----------- ----------- ------------ Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- 2000 - ---- Gross* 1.00 16.00 5.00 12.00 6.00 28.00 2.00 4.00 8.00 32.00 Net* 0.50 1.60 1.30 2.20 1.80 3.80 0.80 1.30 2.60 5.10 1999 - ---- Gross* - 3.00 2.00 8.00 2.00 11.00 - 2.00 2.00 13.00 Net* - 0.25 0.35 0.62 0.35 0.87 - 0.14 0.35 1.01 1998 - ---- Gross* 1.00 20.00 - 24.00 1.00 44.00 8.00 6.00 9.00 50.00 Net* 0.18 3.36 - 1.51 0.18 4.87 1.20 0.37 1.38 5.24 - ------------------------------------ * The term "Gross" refers to the total number of wells in which Barnwell owns an interest, and "Net" refers to Barnwell's aggregate interest therein. For example, a 50% interest in a well represents 1 gross well, but .50 net well. The gross figure includes interests owned of record by Barnwell and, in addition, the portion owned by others. Oil and Natural Gas Production - ------------------------------ The following table summarizes (a) Barnwell's net production for the last three fiscal years, based on sales of crude oil, natural gas, condensate and other natural gas liquids, from all wells in which Barnwell has or had an interest, and (b) the average sales prices and average production costs for such production during the same periods. Production amounts reported are net of royalties and the Alberta Royalty Tax Credit; production reported in prior years has been restated to include units attributable to the Alberta Royalty Tax Credit. Barnwell's net production in fiscal 2000, 1999 and 1998 was derived primarily from the Province of Alberta. All dollar amounts in this table are in U.S. dollars. Year Ended September 30, ------------------------------------- 2000 1999 1998 ---------- ---------- --------- Annual net production Natural gas liquids (BBLS)* 104,000 89,000 66,000 Oil (BBLS)* 187,000 211,000 225,000 Natural gas (MCF)* 3,501,000 3,634,000 4,145,000 Annual average sale price per unit of production: BBL of liquids** $16.91 $ 9.78 $11.36 BBL of oil** $26.15 $14.08 $13.02 MCF of natural gas** $ 2.41 $ 1.57 $ 1.38 Annual average production cost per MCFE produced*** $ 0.60 $ 0.63 $ 0.55 In fiscal 2000, approximately 56%, 32% and 12% of the Company's oil and natural gas revenues were from the sale of natural gas, the sale of oil and the sale of natural gas liquids, respectively. In fiscal 2000, the Company's natural gas production averaged net sales volume after royalties of 9,560 MCF per day, a decrease of 4% from 9,960 MCF per day in fiscal 1999. This decrease was due to natural declines in production from some of the Company's mature properties (Hillsdown, Charlotte Lake, Thornbury, and Pouce Coupe) and higher royalty percentage rates due to higher prices. Dunvegan continues to contribute approximately 51% of the Company's natural gas production. In fiscal 2000, oil sales averaged net production of 510 barrels per day, a decrease of 12% from 580 barrels per day in fiscal 1999. The Company's major oil producing properties are the Red Earth, Chauvin and Manyberries areas in Canada. This decrease was due to higher royalty percentage rates due to higher prices and natural declines in production from some of the Company's mature properties (Red Earth, Chauvin and Manyberries). In fiscal 2000, natural gas liquid sales averaged net production of 280 barrels per day, an increase of 17% from 240 barrels per day in fiscal 1999. This increase was due to increased liquids production at Dunvegan. Dunvegan provided 83% of the Company's fiscal 2000 natural gas liquids production. Other major natural gas liquids producing properties are the Hillsdown, Pembina and Pouce Coupe areas in Alberta. In fiscal 1999, approximately 60%, 31% and 9% of the Company's oil and natural gas revenues were from the sale of natural gas, the sale of oil and the sale of natural gas liquids, respectively. The following table sets forth the gross and net number of productive wells Barnwell has an interest in as of September 30, 2000. Productive Wells - ---------------- Productive Wells**** ------------------------- Gross***** Net***** ---------- ----------- Location Oil Gas Oil Gas - -------- --- --- ---- ---- Canada Alberta 151 418 23.3 40.8 Saskatchewan 2 14 0.2 2.4 British Columbia - 1 - 0.5 --- --- ---- ---- Total 153 433 23.5 43.7 === === ==== ==== - -------------------------------- * When used in this report, "MCF" means 1,000 cubic feet of natural gas at 14.65 psia and 60 degrees F and the term "BBLS" means stock tank barrels of oil equivalent to 42 U.S. gallons. ** Calculated on revenues before royalty expense and royalty tax credit divided by gross production. *** Natural gas liquids, oil and natural gas units were combined by converting barrels of natural gas liquids and oil to an MCF equivalent ("MCFE") on the basis of 5.8 MCF = 1 BBL. **** Seventy-two gross natural gas wells have dual or multiple completions and six gross oil wells have dual completions. ***** Please see note (2) on the following table. Developed Acreage and Undeveloped Acreage - ----------------------------------------- The following table sets forth certain information with respect to oil and natural gas properties of Barnwell as of September 30, 2000: Developed and Developed Undeveloped Undeveloped Acreage(1) Acreage(1) Acreage(1) ---------------- ---------------- ---------------- Location Gross(2) Net(2) Gross(2) Net(2) Gross(2) Net(2) - ------------------ -------- ------ -------- ------ -------- ------ Canada - ------ Alberta 247,907 29,814 146,469 31,445 394,376 61,259 British Columbia 1,193 395 4,931 1,355 6,124 1,750 Saskatchewan 3,696 543 200 11 3,896 554 U.S. - ---- North Dakota 1,520 264 22,039 10,008 23,559 10,272 ------- ------ ------- ------ -------- ------ Total 254,316 31,016 173,639 42,819 427,955 73,835 ======= ====== ======== ====== ======== ====== - --------------------------------- (1) "Developed Acreage" includes the acres covered by leases upon which there are one or more producing wells. "Undeveloped Acreage" includes acres covered by leases upon which there are no producing wells and which are maintained in effect by the payment of delay rentals or the commencement of drilling thereon. (2) "Gross" refers to the total number of wells or acres in which Barnwell owns an interest, and "Net" refers to Barnwell's aggregate interest therein. For example, a 50% interest in a well represents one Gross Well, but .50 Net Well, and similarly, a 50% interest in a 320 acre lease represents 320 Gross Acres and 160 Net Acres. The gross wells and gross acreage figures include interests owned of record by Barnwell and, in addition, the portion owned by others. Barnwell's leasehold interests in its undeveloped acreage, if not developed, expire over the next five fiscal years as follows: 28% expire during fiscal 2001; 18% expire during fiscal 2002; 13% expire during fiscal 2003; 7% expire during fiscal 2004 and 34% expire during fiscal 2005. There can be no assurance that the Company will be successful in renewing its leasehold interests in the event of expiration. Barnwell's undeveloped acreage includes major concentrations in Alberta at Thornbury (6,360 net acres), Archie (4,000 net acres), Red Earth (2,220 net acres) and Gere (2,100 net acres). Reserves - -------- The amounts set forth in the table below, prepared by Paddock Lindstrom Associates Ltd., Barnwell's independent reservoir engineering consultants, summarize the estimated net quantities of proved developed producing reserves and proved developed reserves of crude oil (including condensate and natural gas liquids) and natural gas as of September 30, 2000, 1999 and 1998 on all properties in which Barnwell has an interest. These reserves are before deductions for indebtedness secured by the properties and are based on constant dollars. No estimates of total proved net oil or natural gas reserves have been filed with or included in reports to any federal authority or agency since October 1, 1980. Proved Producing Reserves - ------------------------- September 30, -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Oil - barrels (BBLS) (including condensate and natural gas liquids) 1,508,000 1,759,000 2,109,000 Natural gas - thousand cubic feet (MCF) 20,594,000 25,908,000 28,306,000 Total Proved Reserves (Includes Proved Producing Reserves) - -------------------------------------- September 30, -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Oil - barrels (BBLS) (including condensate and natural gas liquids) 1,781,000 2,138,000 2,413,000 Natural gas - thousand cubic feet (MCF) 29,796,000 36,879,000 40,561,000 As of September 30, 2000, essentially all of Barnwell's proved producing and total proved reserves were located in the Province of Alberta, with minor volumes located in the Provinces of Saskatchewan and British Columbia. During fiscal 2000, Barnwell's total net proved reserves, including proved producing reserves, of oil, condensate and natural gas liquids decreased by 357,000 barrels, and total net proved reserves of natural gas decreased by 7,083,000 MCF. The change in oil, condensate and natural gas liquids reserves was the net result of production during the year of 291,000 barrels, the addition of 72,000 barrels from the drilling of productive wells, the deduction of 131,000 barrels due to higher royalty rates, and the independent engineer's 7,000 barrel downward revision of the Company's oil reserves. Barnwell's proved natural gas reserves decreased as a net result of production during the year of 3,501,000 MCF, the addition of 2,417,000 MCF from the drilling of productive natural gas wells, the deduction of 5,699,000 MCF due to higher royalty rates, and the independent engineer's 300,000 MCF downward revision of the Company's natural gas reserves. The deduction of reserve units due to higher royalty rates is the result of Alberta's royalties being calculated on a sliding scale basis, with the royalty percentage increasing as prices increase. The Province of Alberta takes its royalty share of production based on commodity prices; as all commodity prices were significantly higher at September 30, 2000, as compared to September 30, 1999, significantly more reserves were deducted for royalty volumes at September 30, 2000, as compared to September 30, 1999. Barnwell's working interest in the Dunvegan Unit accounted for approximately 64% and 65% of its total proved natural gas reserves at September 30, 2000 and 1999, respectively, and approximately 35% of proved developed oil and condensate reserves at September 30, 2000, as compared to approximately 32% of proved developed oil and condensate reserves at September 30, 1999. The following table sets forth the Company's oil and natural gas reserves at September 30, 2000, by property name, based on information prepared by Paddock Lindstrom and Associates, Ltd., Barnwell's independent reservoir engineering consultant. Gross reserves are before the deduction of royalties; net reserves are after the deduction of royalties net of the Alberta Royalty Tax Credit. This table is based on constant dollars where reserve estimates are based on sales prices, costs and statutory tax rates in existence at the date of the projection. Oil, which includes natural gas liquids, is shown in thousands of barrels ("MBBLS") and natural gas is shown in millions of cubic feet ("MMCF").
OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 2000 Total Proved Producing Total Proved --------------------------- --------------------------- Oil & NGL's Gas Oil & NGL's Gas ------------- ------------- ------------- ------------- Property Name Gross Net Gross Net Gross Net Gross Net (MBBLS) (MMCF) (MBBLS) (MMCF) ------------- ------------- ------------- ------------- Dunvegan 674 471 19,175 14,483 883 621 25,099 19,185 Dunvegan Non-Unit 113 86 248 181 124 93 556 393 Hillsdown 35 26 1,489 1,172 55 42 1,654 1,304 Thornbury -- -- 1,460 1,184 -- -- 1,724 1,408 Manyberries 108 90 19 12 124 103 23 14 Pouce Coupe 3 2 680 474 36 25 1,899 1,297 Red Earth/Loon 680 593 -- -- 701 606 -- -- Barrhead 3 3 267 234 3 3 383 315 Bashaw -- -- 20 17 -- -- 20 17 Belloy 1 1 291 205 1 1 437 317 Cessford 6 5 -- -- 6 5 -- -- Charlotte Lake 18 15 420 365 18 15 857 712 Chauvin 84 71 -- -- 84 71 -- -- Chigwell -- -- 9 9 -- -- 9 9 Coyote 1 1 22 22 1 1 22 22 Cynthia-Pembina 35 29 505 355 35 29 505 355 Drumheller 15 10 370 236 15 10 370 236 Faith South -- -- -- -- -- -- 1,011 701 Fenn-Big Valley -- -- 3 2 -- -- 3 2 Gilby 1 1 38 28 1 1 38 28 Gilwood -- -- -- -- -- -- 82 51 Heathdale -- -- 286 219 -- -- 286 219 Hilda -- -- 44 41 -- -- 44 41 Killam -- -- 1 1 -- -- 1 1 Leduc 14 11 61 48 14 11 265 199 Majeau Lake -- -- 19 16 -- -- 19 16 Medicine River 50 38 137 103 76 56 1,074 693 Mikwan -- -- 21 19 -- -- 21 19 Mitsue -- -- 25 19 -- -- 25 19 Pembina 3 2 71 48 3 2 71 48 Rainbow 1 -- -- -- 1 -- -- -- Richdale -- -- -- -- -- -- 178 136 Staplehurst 10 9 -- -- 23 20 -- -- Sunnynook 4 3 770 541 4 3 770 541 Tomahawk -- -- -- -- 14 12 285 185 Wood River 13 11 280 208 13 11 280 208 Worsley 1 1 1 1 1 1 1 1 Zama 29 26 202 119 31 27 575 350 Rigel, British Columbia -- -- -- -- 12 9 732 522 Hatton, Saskatchewan -- -- 329 232 -- -- 329 232 Webb-Beverley, Saskatchewan 3 3 -- -- 3 3 -- -- ------ ------ ------ ------ ------ ------ ------ ------ TOTAL 1,905 1,508 27,263 20,594 2,282 1,781 39,648 29,796 ====== ====== ====== ====== ====== ====== ====== ====== Properties are located in Alberta, Canada unless otherwise noted.
Estimated Future Net Revenues - ----------------------------- The following table sets forth Barnwell's "Estimated Future Net Revenues" from total proved oil, natural gas and condensate reserves and the present value of Barnwell's "Estimated Future Net Revenues" (discounted at 10%). Estimated future net revenues for total proved reserves are net of estimated development costs. Net revenues have been calculated using current sales prices and costs, after deducting all royalties net of the Alberta Royalty Tax Credit, operating costs, future estimated capital expenditures, and income taxes. Proved Producing Total Proved Reserves Reserves ---------------- ------------ Year ending September 30, 2001 $ 7,208,000 $ 7,488,000 2002 6,924,000 8,321,000 2003 5,714,000 7,502,000 Thereafter 35,999,000 50,795,000 ----------- ----------- $55,845,000 $74,106,000 =========== =========== Present value (discounted at 10%) at September 30, 2000 $32,026,000 $42,500,000 =========== =========== Marketing of Oil and Natural Gas - -------------------------------- Barnwell sells substantially all of its oil and condensate production under short-term contracts between itself or the operator of the property and marketers of oil. The price of oil is freely negotiated between the buyers and sellers. Natural gas sold by the Company is generally sold under both long-term and short-term contracts with prices indexed to market prices. The price of natural gas and natural gas liquids is freely negotiated between buyers and sellers. In 2000, 1999 and 1998, the Company took most of its oil and natural gas "in kind" where the Company markets the products instead of having the operator of a producing property market the products on the Company's behalf. In fiscal 2000, natural gas production from the Dunvegan Unit was responsible for approximately 49% of the Company's natural gas revenues. In fiscal 2000, the Company had three individually significant customers that accounted for 63% of the Company's oil and natural gas revenues. A substantial portion of Barnwell's Dunvegan natural gas production and natural gas production from other properties is sold to aggregators and marketers under various short-term and long-term contracts, with the price of natural gas determined by negotiations between the aggregators and the final purchasers. In fiscal 2000, Barnwell continued to increase the volumes of natural gas sold into spot markets to take advantage of new pipeline access to premium markets and higher prices. Governmental Regulation - ----------------------- The jurisdictions in which the oil and natural gas properties of Barnwell are located have regulatory provisions relating to permits for the drilling of wells, the spacing of wells, the prevention of oil and natural gas waste, allowable rates of production and other matters. The amount of oil and natural gas produced is subject to control by regulatory agencies in each province and state that periodically assign allowable rates of production. The Province of Alberta and Government of Canada also monitor and regulate the volume of natural gas that may be removed from the province and the conditions of removal. There is no current government regulation of the price that may be charged on the sale of Canadian oil or natural gas production. Canadian natural gas production destined for export is priced by market forces subject to export contracts meeting certain criteria prescribed by Canada's National Energy Board and the Government of Canada. The right to explore for and develop oil and natural gas on lands in Alberta, Saskatchewan and British Columbia is controlled by the governments of each of those provinces. Changes in royalties and other terms of provincial leases, permits and reservations may have a substantial effect on the Company's operations. In addition to the foregoing, in the future, Barnwell's Canadian operations may be affected from time to time by political developments in Canada and by Canadian Federal, provincial and local laws and regulations, such as restrictions on production and export, oil and natural gas allocation and rationing, price controls, tax increases, expropriation of property, modification or cancellation of contract rights, and environmental protection controls. Furthermore, operations may also be affected by United States import fees and restrictions. Different royalty rates are imposed by the producing provinces, the Government of Canada and private interests with respect to the production and sale of crude oil, natural gas and liquids. In addition, some producing provinces receive additional revenue through the imposition of taxes on crude oil and natural gas owned by private interests within the province. Essentially, provincial royalties are calculated as a percentage of revenue, and vary depending on production volumes, selling prices and the date of discovery. Canadian taxpayers are not permitted to deduct royalties, taxes, rentals and similar levies paid to the Federal or provincial governments in connection with oil and natural gas production in computing income for purposes of Canadian Federal income tax. However, they are allowed to deduct a "Resource Allowance" which is 25% of the taxpayer's "Resource Profits for the Year" (essentially, income from the production of oil, natural gas or minerals) in computing their taxable income. In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit ("ARTC") program. The ARTC rate is based on a price-sensitive formula and varies between 75% at prices below a specified royalty tax credit reference price decreasing to 25% at prices above a specified royalty tax credit reference price. The ARTC will be applied to a maximum annual amount of $2,000,000 Canadian dollars of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlements to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on the average royalty tax credit reference price, as determined by the Alberta Department of Energy. The royalty tax credit reference price is based on a weighted average oil and gas price. The Province of Alberta has stated that changes in the ARTC will be announced three years in advance. In 1999, the Alberta government announced that it would introduce new rules to preclude companies that pay less than approximately $6,500 in royalties per year from qualifying for the program; this change will not impact the Company. The ARTC program has been in effect in various forms since 1974 and the Company anticipates that it will be continued in some form for the foreseeable future. In fiscal 2000, the Company's ARTC totaled approximately $450,000. If the ARTC is not continued, it will have an adverse effect on the Company. The resource properties located in the United States are freehold mineral interests leased under market conditions, subject to extraction and severance taxes imposed according to state regulations. Competition - ----------- The majority of Barnwell's natural gas sales take place in Alberta, Canada. Natural gas prices in Alberta are generally competitive with other major North American areas due to increased pipeline capacity into the United States. Barnwell's oil and natural gas liquids are sold in Alberta with prices determined by the world price for oil. The Company competes in the sale of oil and natural gas on the basis of price, and on the ability to deliver products. The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and reserves and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. Barnwell is a minor participant in the industry and competes in its oil and natural gas activities with many other companies having far greater financial and other resources. CONTRACT DRILLING OPERATIONS ---------------------------- Barnwell owns 100% of Water Resources International, Inc. ("WRI"). WRI drills water and exploratory wells and installs and repairs water pumping systems in Hawaii. Additionally, in fiscal 1999, the Company started providing contract labor for the drilling and workovers of geothermal wells; this work continued into and was completed during fiscal 2000. WRI owns and operates four Spencer-Harris portable rotary drill rigs ranging in drilling capacity from 3,500 feet to 7,000 feet, and one IDECO H-35 rotary drill/workover rig. Additionally, WRI owns a two acre parcel of real estate in an industrial park 11 miles south of Hilo, Hawaii. WRI also leases a three-quarter of an acre maintenance facility in Honolulu and a one acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii, and maintains an inventory of drilling and pump supplies. As of September 30, 2000, WRI employed 20 drilling, pump and administrative employees, none of whom are union members. WRI drills water, geothermal and exploratory wells of varying depths in Hawaii. In fiscal 1999, in addition to drilling water wells and drilling and plugging geothermal wells, WRI drilled a 10,370 feet deep exploratory core-sampling well for the Hawaii Scientific Drilling Project, in which an almost continuous two mile core of the earth's crust was extracted for scientific research purposes. This project was completed fiscal 2000. WRI also installs and repairs water pumps and is the state of Hawaii's distributor for Floway pumps and equipment. The demand for WRI's services is primarily dependent upon land development activities in Hawaii. WRI markets its services to land developers and government agencies, and identifies potential contracts through public notices, its officers' involvement in community activities and referrals. Contracts are usually fixed price per lineal foot or day rate contracts and are negotiated with private entities or obtained through competitive bidding with private entities or with local, state and Federal agencies. Contract revenues are not dependent upon the discovery of water, geothermal production zones or other, similar targets, and contracts are not subject to renegotiation of profits or termination at the election of the governmental entities involved. Contracts provide for arbitration in the event of disputes. The Company's contract drilling subsidiary derived 70%, 43% and 42% of its contract drilling revenues in fiscal 2000, 1999 and 1998, respectively, pursuant to federal, State of Hawaii and local county contracts. At September 30, 2000, the Company had accounts receivable from the State of Hawaii and local county entities totaling approximately $277,000. The Company has lien rights on contracts with federal, State of Hawaii, local county and private entities. The Company's contract drilling segment currently operates in Hawaii and is not subject to seasonal fluctuations. Activity - -------- In fiscal 2000, WRI started six well drilling contracts and three pump installation contracts and completed seven well drilling contracts and five pump installation contracts. Four of the seven completed well contracts and three of the five completed pump installation contracts were started in the prior year. Ninety percent (90%) of such well drilling and pump installation jobs, representing 70% of total contract drilling revenues in fiscal 2000, have been pursuant to government contracts. At September 30, 2000, WRI had a backlog of eight well drilling contracts and six pump installation and repair contracts, three and one of which, respectively, were in progress as of September 30, 2000. The dollar amount of the Company's backlog of firm well drilling and pump installation and repair contracts at November 30, 2000 and 1999 is as follows: 2000 1999 ---------- ---------- Well drilling $2,700,000 $2,000,000 Pump installation and repair 900,000 300,000 ---------- ---------- $3,600,000 $2,300,000 ========== ========== All but two of the contracts in backlog at November 30, 2000 are expected to be completed within fiscal year 2001. Competition - ----------- WRI utilizes rotary drill rigs that have the capability of drilling wells faster than cable tool rigs. There are seven other drilling contractors in Hawaii which use cable tool or rotary drill rigs that are capable of drilling wells, and six other Hawaii contractors who are capable of installing and repairing vertical turbine and submersible water pumping systems in Hawaii. These contractors compete actively with WRI for government and private contracts. Pricing is the Company's major method of competition; reliability of service is also a significant factor. The number of available water well drilling jobs has not changed significantly from the prior year. However, the Company was able to bid successfully and obtain significant drilling contracts for scientific and geothermal work. The Company expects competitive pressures within the industry to remain high as demand for well drilling and pump installation in Hawaii is not expected to increase significantly in fiscal year 2001. LAND INVESTMENT OPERATIONS -------------------------- The Company owns a 50.1% controlling interest in Kaupulehu Developments, a Hawaii general partnership. Between 1986 and 1989, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of the Four Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club, which opened in 1996, a second golf course (currently under construction), and single and multiple family residential units on land acquired from Kaupulehu Developments, located approximately six miles north of the Kona International Airport in the North Kona District of the Island of Hawaii. At September 30, 2000, Kaupulehu Developments owns residential development rights in approximately 80 acres which are under option to Kaupulehu Makai Venture, an affiliate of Kajima Corporation of Japan. If Kaupulehu Makai Venture fully exercises this option applicable to these approximately 80 acres, Kaupulehu Developments will receive a total of $25,500,000. The option expires on April 30, 2003 unless 50% of the option proceeds are received on or before April 30, 2003. The remainder of the option would then expire on April 30, 2007. There is no assurance that this option or any portion of it will be exercised. At September 30, 2000, Kaupulehu Developments also holds leasehold rights in approximately 2,100 acres of land located adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka'upulehu. These approximately 2,100 acres are located between the Queen Kaahumanu Highway and the Pacific Ocean. In June 1996, the State Land Use Commission ("LUC") approved Kaupulehu Developments' petition for reclassification of approximately 1,000 acres of these 2,100 acres of land into the Urban District for resort/residential development. Subsequent to the LUC's approval, a notice of appeal was filed with the Third Circuit Court of the State of Hawaii by parties seeking to reverse the LUC's decision. The Third Circuit Court of the State of Hawaii upheld the LUC's approval of Kaupulehu Developments' rezoning request in all respects in a Decision and Order issued in August 1997. In November 1997, a notice of appeal was filed with the Supreme Court of the State of Hawaii by parties seeking to reverse the Third Circuit Court's decision. In June 1998, Kaupulehu Developments filed an Application for a Project District zoning ordinance and a Special Management Area ("SMA") Use Permit Petition with the County of Hawaii, requesting changes in zoning and use of approximately 1,000 of the 2,100 acres of land to allow residential, resort and commercial development. Both the County zoning ordinance and the SMA Use Permit are required for development of the property. In December 1998, following a contested case hearing conducted in November 1998, the Planning Commission of the County of Hawaii granted the requested SMA Use Permit to Kaupulehu Developments to be effective when the zoning ordinance is adopted. Subsequent to the Planning Commission's approval, in January 1999, a notice of appeal was filed with the Third Circuit Court of the State of Hawaii by parties seeking to reverse the Planning Commission's decision. In April 1999, the County of Hawaii adopted an ordinance granting zoning approval of Kaupulehu Developments' Application for a Project District zoning ordinance, which requested changes in zoning and use of the aforementioned 1,000 acres of land to allow residential, resort and commercial development. Activity - -------- In January 2000, Kaupulehu Makai Venture exercised a portion of the option granted in 1990 by Kaupulehu Developments for the development of residential parcels within the Four Seasons Resort Hualalai at Historic Ka'upulehu on the Island of Hawaii. The Company recognized revenues of $6,540,000, net of costs associated with the transaction, from the receipt of the option monies. $1,300,000 of the proceeds were used to repay Kaupulehu Developments' borrowings from a Hawaii bank, and $873,000 were distributed to Kaupulehu Developments' minority interest partner, Cambridge Hawaii Limited Partnership ("CHLP"), which holds the remaining 49.9% interest in Kaupulehu Developments. CHLP is a Hawaii limited partnership comprised of three Canadian limited partnerships, comprised of individuals, one of whom is Mr. Terry Johnston. Mr. Johnston was elected to the Board of Directors of the Company in March 2000. In December 1999, the Third Circuit Court of the County of Hawaii remanded Kaupulehu Developments' SMA Use Permit Petition back to the County of Hawaii Planning Commission for further review due to procedural issues. In late December 1999, the County of Hawaii Planning Commission reaffirmed their approval of the SMA Use Permit Petition. In September 2000, the Supreme Court of the State of Hawaii ruled on the appeal of the LUC's decision, finding in favor of Kaupulehu Developments on three of the issues on appeal, but on the fourth issue, the court remanded the matter to the LUC for the limited purpose of entering specific findings and conclusions, with further hearing if necessary, regarding: (1) the identity and scope of "valued cultural, historical, or natural resources" in the petition area, including the extent to which traditional and customary native Hawaiian rights are exercised in the petition area; (2) the extent to which those resources - including traditional and customary native Hawaiian rights - will be affected or impaired by the proposed action; and (3) the feasible action, if any, to be taken by the LUC to reasonably protect native Hawaiian rights if they are found to exist. In October 2000, Kaupulehu Developments filed a motion with the LUC to bring the matter in front of the LUC. Management cannot predict the timing or outcome of the LUC's procedures or findings and, accordingly, there is no assurance that State of Hawaii zoning approval will be forthcoming at any time. If the Company is unable to obtain the LUC's approval, there will be a materially adverse impairment of the value of the Company's leasehold rights in this approximately 1,000 acres. Kaupulehu Developments continues to negotiate a revised development agreement and residential fee purchase prices with the lessor of the 2,100 acre parcel. Management cannot predict the outcome of these negotiations. The Company did not receive any revenues in fiscal 1999 and 1998 related to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments' revenues specifically relate to sales of leasehold interests and development rights, which do not occur every year. Competition - ----------- The Company's land investment segment is subject to intense competition in all phases of its operations including the acquisition of new properties, the securing of approvals necessary for land rezoning, and the search for potential buyers of property interests presently owned. The competition comes from numerous independent land development companies and other industries involved in land investment activities. The principal methods of competition are the location of the project and pricing. Kaupulehu Developments is a minor participant in the land development industry and competes in its land investment activities with many other entities having far greater financial and other resources. For the past several years, Hawaii's economy has experienced little or no growth and the real estate market has been slow. However, the South Kohala/North Kona area of the island of Hawaii, the area in which Kaupulehu Developments' property is located, has experienced strong demand in recent years. This trend continued through fiscal 2000 and is not expected to decline significantly in the near term, although there can be no assurance this trend will in fact continue. Item 3. Legal Proceedings ----------------- In June 1996, the State Land Use Commission ("LUC") approved Kaupulehu Developments' petition for reclassification of approximately 1,000 acres of these 2,100 acres of land into the Urban District for resort/residential development. Subsequent to the LUC's approval, a notice of appeal was filed with the Third Circuit Court of the State of Hawaii by parties seeking to reverse the LUC's decision. The Third Circuit Court of the State of Hawaii upheld the Land Use Commission's approval of Kaupulehu Developments' rezoning request in all respects in a Decision and Order issued in August 1997. In November 1997, a notice of appeal was filed with the Supreme Court of the State of Hawaii by parties seeking to reverse the Third Circuit Court's decision. In September 2000, the Supreme Court of the State of Hawaii ruled on the appeal of the LUC's decision, finding in favor of Kaupulehu Developments on three of the issues on appeal, but on the fourth issue, the court remanded the matter to the LUC for the limited purpose of entering specific findings and conclusions, with further hearing if necessary, regarding: (1) the identity and scope of "valued cultural, historical, or natural resources" in the petition area, including the extent to which traditional and customary native Hawaiian rights are exercised in the petition area; (2) the extent to which those resources - including traditional and customary native Hawaiian rights - will be affected or impaired by the proposed action; and (3) the feasible action, if any, to be taken by the LUC to reasonably protect native Hawaiian rights if they are found to exist. In October 2000, Kaupulehu Developments filed a motion with the LUC to bring the matter in front of the LUC. Management cannot predict the timing or outcome of the LUC's procedures or findings and, accordingly, there is no assurance that State of Hawaii zoning approval will be forthcoming at any time. If the Company is unable to obtain the LUC's approval, there will be a materially adverse impairment of the value of the Company's leasehold rights in this approximately 1,000 acres. The Company is involved in routine litigation and is subject to governmental and regulatory controls that are incidental to the business. The Company's management believes that routine claims and litigation involving the Company are not likely to have a material adverse effect on its financial position, results of operations or liquidity. Item 4. Submission of Matters to a Vote of Security Holders --------------------------------------------------- None. PART II Item 5. Market For Common Equity and Related Stockholder Matters -------------------------------------------------------- The principal market on which the Company's common stock is being traded is the American Stock Exchange. The following tables present the quarterly high and low closing prices, on the American Stock Exchange, for the registrant's common stock during the periods indicated: Quarter Ended High Low Quarter Ended High Low - ------------- ------ ------ ------------------ ------ ------ December 31, 1998 12-7/16 11-1/8 December 31, 1999 12-3/4 9-3/4 March 31, 1999 12-1/8 11 March 31, 2000 14-3/4 12-3/4 June 30, 1999 11-3/4 10-7/8 June 30, 2000 15-3/4 13-3/8 September 30, 1999 13-1/4 10-3/8 September 30, 2000 18-7/8 14-3/4 As of November 30, 2000, there were 1,310,952 shares of common stock, par value $.50, outstanding. There were approximately 400 holders of the common stock of the registrant as of November 30, 2000. The Company declared and paid $131,000 in dividends ($0.10 per share) in the fourth quarter of fiscal 2000. In December 2000, the Company declared a dividend of $0.15 per share payable January 3, 2001, to stockholders of record December 12, 2000. Item 6. Management's Discussion and Analysis or Plan of Operation --------------------------------------------------------- The following section contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including various forecasts, projections of Barnwell's future performance, statements of the Company's plans and objectives and other similar types of information. Although the Company believes that its expectations are based on reasonable assumptions, it cannot assure that the expectations contained in such forward-looking statements will be achieved. Such statements involve risks, uncertainties and assumptions, including, but not limited to, those relating to the factors discussed below, in other portions of this Form 10-KSB, in the Notes to Consolidated Financial Statements, and in other documents filed by the Company with the Securities and Exchange Commission from time to time, which could cause actual results to differ materially from those contained in such statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed under Part I, "Forward-Looking Statements," as well as those discussed elsewhere in this Form 10-KSB. All forward-looking statements contained in this Form 10-KSB are qualified in their entirety by this statement and speak only as of the date of filing of this Form 10-KSB, and the Company expressly disclaims any obligation or undertaking to publicly release any updates or revisions to any forward-looking statements contained herein. LIQUIDITY AND CAPITAL RESOURCES - ------------------------------- Cash flows from operations were $8,194,000 in fiscal 2000, as compared to $2,725,000 in fiscal 1999, an increase of $5,469,000 (201%). The increase was due to higher operating profit generated by the Company's oil and natural gas segment and differences in the timing of accounts payable and accrued expense disbursements in fiscal 2000, as compared to fiscal 1999. In January 2000, Kaupulehu Makai Venture, an affiliate of Kajima Corporation of Japan, exercised a portion of the option granted in 1990 by Kaupulehu Developments, a 50.1%-owned general partnership, for the development of residential parcels within the Four Seasons Resort Hualalai at Historic Ka'upulehu on the Island of Hawaii. The Company received $6,540,000 in cash, net of costs associated with the transaction, from this partial exercise of the option. $1,300,000 of the proceeds were used to repay borrowings, and $873,000 were distributed to Kaupulehu Developments' minority interest partner, Cambridge Hawaii Limited Partnership ("CHLP"), which holds the remaining 49.9% interest in Kaupulehu Developments. During fiscal 2000, the Company repaid $3,066,000 of its borrowings under a revolving credit facility with the Royal Bank of Canada. The facility is for $17,000,000 Canadian dollars or its U.S. dollar equivalent of approximately $11,300,000 at September 30, 2000. The facility is reviewed annually with a primary focus on the future cash flows generated by the Company's oil and natural gas properties. The next review is planned for April 2001. Subject to that review, the facility may be extended one year with no required debt repayments for one year, or converted to a five-year term loan by the bank. If the facility is converted to a five-year term loan, the Company has agreed to the following repayment schedule of the then outstanding balance: year 1 - 30%; year 2 - 27%; year 3 - 16%; year 4 - 14%; year 5 - 13%. The facility is collateralized by the Company's interests in its major oil and natural gas properties and a negative pledge on its remaining oil and natural gas properties. No compensating bank balances are required on any of the Company's indebtedness under the facility. The Canadian bank has represented that it will not require any repayments under the facility before September 30, 2001. Accordingly, the Company has classified outstanding borrowings under the facility as long-term debt. The Company has $1,200,000 of convertible notes outstanding at September 30, 2000 that are payable in 12 consecutive, equal quarterly installments. Interest is payable quarterly at a rate to be adjusted each quarter to the greater of 10% per annum or 1% over the prime rate of interest. The Company paid interest on these notes at an average rate of 10.13% per annum in fiscal 2000. For more information on the Company's long-term debt, see Note 5 of "Notes to the Consolidated Financial Statements" in Item 7. During fiscal 2000, the Company repurchased 6,000 shares of its common stock on the open market for $93,000 (average price of $15.50 per share) under a March 2000 stock buyback plan authorizing the repurchase of up to 100,000 shares. The Company plans to repurchase additional shares from time to time in the open market or in privately negotiated transactions, depending on market conditions. The Company also declared and paid $131,000 in dividends ($0.10 per share) in the fourth quarter of fiscal 2000. At September 30, 2000, the Company's consolidated cash and cash equivalents amounted to $5,701,000, working capital was $1,734,000, and available credit under the Royal Bank of Canada's revolving credit facility was approximately $2,960,000. The Company believes its current cash balances, future cash flows from operations, and available credit will be sufficient to fund its estimated capital expenditures, make the scheduled repayments on its convertible notes, and meet the repayment schedule on its Royal Bank of Canada facility, should the Company or the Royal Bank of Canada elect to convert the facility to a term loan. The following table sets forth the Company's capital expenditures for each of the last three fiscal years: 2000 1999 1998 ----------- ----------- ------------ Oil and natural gas $ 5,003,000 $ 1,753,000 $ 6,969,000 Land investment 631,000 809,000 862,000 Contract drilling 393,000 121,000 91,000 Other 222,000 148,000 205,000 ----------- ----------- ----------- Total capital expenditures $ 6,249,000 $ 2,831,000 $ 8,127,000 =========== =========== =========== Increase (decrease) in oil and natural gas capital expenditures from prior year $ 3,250,000 $(5,216,000) $ 492,000 =========== =========== =========== The Company increased its capital expenditures in fiscal 2000, as compared to fiscal 1999, in response to the upturn in petroleum prices in fiscal 2000. The Company participated in drilling 40 wells, 34 of which were successful, and the recompletion of 13 wells (1.2 net wells). The following table sets forth the gross and net numbers of oil and natural gas wells the Company participated in drilling and purchased for each of the last three fiscal years: 2000 1999 1998 ------------ ------------ ------------ Gross Net Gross Net Gross Net ----- ---- ----- ---- ----- ---- Exploratory oil and natural gas wells drilled 8 2.60 2 0.35 9 1.38 Development oil and natural gas wells drilled 32 5.10 13 1.01 50 5.24 Successful oil and natural Wells drilled 34 5.60 13 1.22 45 5.05 In fiscal 1999 and continuing in fiscal 2000, the Company built a technical team to internally generate oil and gas exploration projects. The team is focused on areas encompassing Northwest and Central Alberta. The Company estimates that oil and natural gas capital expenditures for fiscal 2001 will increase significantly to between $7,500,000 and $9,000,000. This estimated amount may increase or decrease as dictated by management's assessment of the oil and gas environment and prospects. In fiscal 2000, $631,000 of the Company's capital expenditures were applicable to the rezoning of leasehold land in North Kona, Hawaii, from conservation to urban, as compared to $809,000 in fiscal 1999. These expenditures were comprised of legal, consulting and planning fees incurred to process Kaupulehu Developments' applications through the entitlement and judiciary processes, as well as capitalized interest. The fiscal 2000 rezoning expenditures were funded by cash generated from the sale of development rights. In fiscal 2000, the Company invested $393,000 in capital expenditures applicable to contract drilling operations, an increase from $121,000 in fiscal 1999. $288,000 of the contract drilling capital expenditures in fiscal 2000 were for the improvement of the contract drilling storage and maintenance yard at Sand Island, Oahu, Hawaii. These improvements were made to satisfy the Company's obligation to improve the property, located between downtown Honolulu and the Honolulu airport, under the terms of the 55 year property lease. All of these capital expenditures were funded by cash flows generated by contract drilling operations. RESULTS OF OPERATIONS - --------------------- Summary - ------- Barnwell reported net earnings of $5,010,000 in fiscal 2000, an increase of $4,490,000 (863%) over fiscal 1999, due to significant increases in operating profits generated by its land investment and oil and natural gas segments. Additionally, the Company's contract drilling operations generated an operating profit of $603,000 in fiscal 2000. Oil and natural gas segment operating profit increased $4,833,000 (115%) from $4,188,000 in fiscal 1999 to $9,021,000 in fiscal 2000 due primarily to 86% and 54% increases in oil and natural gas prices, respectively. The land investment segment generated an operating profit of $3,232,000 in fiscal 2000 due to the exercise of a portion of an outstanding option to purchase development rights for certain residential parcels within the Four Seasons Resort Hualalai at Historic Ka'upulehu on the Island of Hawaii. The Company recognized revenues of $6,540,000, net of costs associated with the transaction, from the receipt of the option monies. Barnwell reported net earnings of $520,000 in fiscal 1999, an increase of $4,410,000 over fiscal 1998, due to significant increases in operating profit generated by both its oil and natural gas and contract drilling segments, and to the absence of write-downs in fiscal 1999. Operating profits generated by the Company's contract drilling segment increased $1,292,000 from an operating loss of $550,000 in fiscal 1998 to an operating profit of $742,000 in fiscal 1999, due primarily to an increased number of drilling contracts and due to the fact that the scientific coring and geothermal well contracts performed in fiscal 1999 were operated on a 24 hour basis; the prior years' revenues were generated by water well contracts which typically operate during daylight only. Operating profit generated by the Company's oil and gas segment, excluding the 1998 non-cash write-downs, increased $709,000 from $3,479,000 in fiscal 1998 to $4,188,000 in fiscal 1999 due primarily to 14% and 8% increases in natural gas and oil prices, respectively. Oil and Natural Gas Revenues - ---------------------------- Selected Operating Statistics The following tables set forth the Company's annual net production and annual average price per unit of production for fiscal 2000 as compared to fiscal 1999, and fiscal 1999 as compared to fiscal 1998. Production amounts reported are net of royalties and the Alberta Royalty Tax Credit; production reported in prior years has been restated to include units attributable to the Alberta Royalty Tax Credit. Fiscal 2000 - Fiscal 1999 - ------------------------- Annual Net Production --------------------------------------------------- Increase (Decrease) --------------------- 2000 1999 Units % ---------- ---------- --------- ----- Liquids (Bbl)* 104,000 89,000 15,000 17% Oil (Bbl)* 187,000 211,000 (24,000) (11%) Natural gas (MCF)** 3,501,000 3,634,000 (133,000) (4%) Annual Average Price Per Unit --------------------------------------------------- Increase --------------------- 2000 1999 $ % ---------- ---------- --------- ----- Liquids (Bbl)* $16.91 $ 9.78 $ 7.13 73% Oil (Bbl)* $26.15 $14.08 $12.07 86% Natural gas (MCF)** $ 2.41 $ 1.57 $ 0.84 54% Fiscal 1999 - Fiscal 1998 - ------------------------- Annual Net Production --------------------------------------------------- Increase (Decrease) --------------------- 1999 1998 Units % ---------- ---------- --------- ----- Liquids (Bbl)* 89,000 66,000 23,000 35% Oil (Bbl)* 211,000 225,000 (14,000) (6%) Natural gas (MCF)** 3,634,000 4,145,000 (511,000) (12%) Annual Average Price Per Unit --------------------------------------------------- Increase (Decrease) --------------------- 1999 1998 $ % ---------- ---------- --------- ----- Liquids (Bbl)* $ 9.78 $11.36 $(1.58) (14%) Oil (Bbl)* $14.08 $13.02 $ 1.06 8% Natural gas (MCF)** $ 1.57 $ 1.38 $ 0.19 14% *Bbl = stock tank barrel equivalent to 42 U.S. gallons **MCF = 1,000 cubic feet Oil and natural gas revenues increased $5,140,000 or 51% in fiscal 2000 to $15,270,000, as compared to $10,130,000 in fiscal 1999, due to 86%, 54%, and 73% increases in the average price received for oil, natural gas, and natural gas liquids, respectively, and a 17% increase in natural gas liquids volumes. The increase was partially offset by decreases in natural gas and oil volumes of 4% and 11%, respectively. The decrease in natural gas and oil production was due to higher royalty percentage rates due to higher prices in fiscal 2000, as compared to fiscal 1999, and production declines at the Company's non-principal more mature natural gas and oil properties. Oil and natural gas revenues increased $730,000 or 8% in fiscal 1999 to $10,130,000, as compared to $9,400,000 in fiscal 1998, due to 14% and 8% increases in the average price received for natural gas and oil, respectively, and a 35% increase in natural gas liquids volumes. The increase was partially offset by decreases in natural gas and oil volumes of 12% and 6%, respectively, and a 14% decrease in natural gas liquids prices. The decrease in natural gas and oil production was due to projected production declines at the Company's principal natural gas and oil properties. Oil and Natural Gas Operating Expenses - -------------------------------------- Operating expenses decreased to $3,128,000 in fiscal 2000, a $240,000 (7%) decrease from $3,368,000 in fiscal 1999. The decrease is due to significantly lower turnaround costs at the Dunvegan area and the sale of non-performing properties in the Provost and Rainbow areas. Operating expenses were $3,368,000 in fiscal 1999, relatively unchanged from $3,223,000 in fiscal 1998 (increased $145,000 or 4%). Contract Drilling - ----------------- Contract drilling revenues and costs are associated with water well, geothermal well and exploratory well drilling, and water pump installation, replacement and repair in Hawaii. Contract drilling revenues decreased $710,000 (17%) to $3,520,000 in fiscal 2000, as compared to $4,230,000 in fiscal 1999, and contract drilling operating expenses decreased $637,000 (19%) to $2,741,000 in fiscal 2000, as compared to $3,378,000 in fiscal 1999, as revenues and operating expenses for the prior year period included work under a contract that required around-the-clock operations, 24 hours per day, seven days a week; all of the revenues for the current year period were under daylight-only contracts. As a result of the decrease in activity, operating profit before depreciation decreased $73,000 to $779,000 for fiscal 2000, as compared to an operating profit before depreciation of $852,000 for fiscal 1999. At September 30, 2000, WRI had a backlog of eight well drilling contracts and six pump installation and repair contracts, three and one of which, respectively, were in progress as of September 30, 2000. These 14 contracts represent a backlog of contract drilling revenues of approximately $3,600,000 as of November 30, 2000. Contract drilling revenues increased $2,720,000 (180%) to $4,230,000 in fiscal 1999, as compared to $1,510,000 in fiscal 1998, and contract drilling operating expenses increased $1,556,000 (85%) to $3,378,000 in fiscal 1999, as compared to $1,822,000 in fiscal 1998, due primarily to the Company's performance on contracts for the Hawaii Scientific Drilling Project and a geothermal well. These jobs were operated seven days a week, 24 hours per day, as opposed to water well contracts, which are typically operated five days a week, eight hours per day. As a result of the significant increase in activity, operating profit before depreciation increased to $852,000 for fiscal 1999, as compared to an operating loss before depreciation of $482,000 in fiscal 1998. Gas Processing and Other Income - ------------------------------- Gas processing and other income increased $440,000 (55%) to $1,240,000 in fiscal 2000, as compared to $800,000 in fiscal 1999, due primarily to a $238,000 gain on the sale of marketable securities and interest and dividends earned on higher average cash and cash equivalents balances. Gas processing and other income decreased $210,000 (21%) to $800,000 in fiscal 1999, as compared to $1,010,000 in fiscal 1998, due primarily to a decrease in the amount of gas processed by the Company's interest in the Stolberg pipeline. Sale of Development Rights and Minority Interest in Earnings - ------------------------------------------------------------ In January 2000, Kaupulehu Makai Venture exercised a portion of the option granted in 1990 by Kaupulehu Developments, a 50.1%-owned general partnership, for the development of residential parcels within the Four Seasons Resort Hualalai at Historic Ka'upulehu on the Island of Hawaii. The Company recognized $6,540,000 of revenues, net of costs associated with the transaction, and $3,293,000 of minority interest in earnings from this partial exercise of the option in fiscal 2000. The Company did not receive any revenues in fiscal 1999 and 1998 related to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments' revenues specifically relate to sales of leasehold interests and development rights, which do not occur every year. General and Administrative Expenses - ----------------------------------- General and administrative expenses increased $283,000 (9%) to $3,470,000 in fiscal 2000, as compared to $3,187,000 in fiscal 1999, due to higher personnel costs due to an increase in the number of oil and natural gas segment personnel and costs associated with an incentive compensation plan for the Vice President of Canadian Operations. General and administrative expenses were $3,187,000 in fiscal 1999, relatively unchanged from $3,292,000 in fiscal 1998 (decreased $105,000 or 3%). Depreciation, Depletion and Amortization - ---------------------------------------- Depreciation, depletion and amortization expense increased $752,000 (27%) to $3,572,000 in fiscal 2000, as compared to $2,820,000 in fiscal 1999, due primarily to a 25% increase in the depletion rate per MCF equivalent. The higher depletion rate is the result of increased capital expenditures, an increase in the cost of finding and developing proven reserves and a decrease in net proved reserves due to higher royalty deductions due to higher product prices. Depreciation, depletion and amortization expense decreased $78,000 (3%) to $2,820,000 in fiscal 1999, as compared to $2,898,000 in fiscal 1998, due primarily to a decline in production volumes, partially offset by a 4% increase in the depletion rate per MCF equivalent and a $42,000 increase in contract drilling depreciation. The higher depletion rate is the result of increased cost of finding and developing proven reserves. The increase in contract drilling depreciation is attributable to the addition of equipment as a result of the increase in contract drilling activity. Interest Expense - ---------------- Interest expense was $813,000 in fiscal 2000, relatively unchanged from interest expense of $809,000 in fiscal 1999. The weighted average balance of the outstanding borrowings from the Royal Bank of Canada decreased from approximately $11,700,000 in fiscal 1999 to approximately $10,076,000 in fiscal 2000 due to repayment of $3,066,000 of debt during fiscal 2000. In addition, the borrowings on Kaupulehu Developments' credit facility, $1,250,000 at September 30, 1999, were fully repaid in January 2000, and $400,000 of the convertible notes were repaid during fiscal 2000. Partially offsetting these decreases were higher average interest rates and a decrease in interest capitalized on costs related to its investment in land. The average interest rate incurred during fiscal 2000 on the Company's borrowings from the Royal Bank of Canada increased to 7.00%, as compared to 6.18% in fiscal 1999. The average interest rate on the convertible notes in fiscal 2000 was marginally higher at 10.13% per annum, as compared to 10.00% per annum in fiscal 1999. Capitalized interest costs decreased from $201,000 in fiscal 1999 to $93,000 in fiscal 2000, due to the repayment of a portion of debt associated with the Company's investment in land. Interest expense increased $87,000 (12%) in fiscal 1999 to $809,000, as compared to $722,000 in fiscal 1998, due to higher average loan balances. The weighted average balance of the outstanding borrowings from the Royal Bank of Canada increased from approximately $10,300,000 in fiscal 1998 to approximately $11,700,000 in fiscal 1999 as borrowings made in the latter half of fiscal 1998 were outstanding for ostensibly all of fiscal 1999. Partially offsetting the increase were lower average interest rates. The average interest rate incurred during fiscal 1999 on the Company's borrowings from the Royal Bank of Canada decreased to 6.18% as compared to 6.67% in fiscal 1998, and the average interest rate on Kaupulehu Developments' borrowings was 9.40% in fiscal 1999 as compared to 10.00% in fiscal 1998. The interest rate on the convertible notes in fiscal 1999 was unchanged at 10.00% per annum. Write-down of Assets - -------------------- Under the full cost method of accounting, the amount of oil and natural gas properties' capitalized costs less accumulated depletion (on a country by country basis) is subject to a ceiling test limitation that requires any excess of such costs over the present value of estimated future cash flows from proved reserves to be expensed. As of March 31, 1998, the Company's investment in the Michigan Basin prospect was determined to be impaired and was transferred to the amortization base. Upon transfer, capitalized oil and natural gas properties' costs in the United States exceeded the full cost ceiling test limitation and, accordingly, the Company recorded a non-cash write-down of $2,070,000 in the quarter ended March 31, 1998. Due to further declines in oil prices and disappointing seismic and drilling results in North Dakota, the Company abandoned its U.S. oil and natural gas prospects and recorded an additional U.S. ceiling test write-down of $660,000 during the quarter ended June 30, 1998 to fully write-off its investment in U.S. oil and natural gas properties. In fiscal 1998, the Company also wrote down $170,000 of land and land improvement costs related to a contract drilling yard held for sale due to a decline in the market value of the property, and $95,000 of available-for-sale securities due to a decline in market value deemed other than temporary. There were no write-downs of oil and natural gas properties and other assets in fiscal years 2000 or 1999. Foreign Currency Fluctuations - ----------------------------- The Company conducts foreign operations in Canada. Consequently, the Company is subject to foreign currency transaction gains and losses due to fluctuations of the exchange rates between the Canadian dollar and the U.S. dollar. The Company incurred realized foreign currency transaction losses amounting to $420,000 in fiscal 2000. Foreign currency transaction gains and losses were not material in fiscal 1999 and 1998. The Company cannot accurately predict future fluctuations between the Canadian and U.S. dollars. Taxes - ----- The government of the Province of Alberta announced recently that they will propose significant decreases in corporate tax rates during the 2001 session of the legislative assembly. The proposal was to reduce the province's corporate tax rate from the current 15.5% rate to 13.5% effective April 1, 2001; to 11.5% effective April 1, 2002; to 10.0% effective April 1, 2003; and to 8.0% effective April 1, 2004. If enacted into law, each 1% reduction in the tax rates would reduce the Company's current tax provision by an estimated $60,000 (utilizing fiscal 2000's earnings before taxes) over a one year period and reduce the deferred income tax liability by an estimated $120,000. In fiscal 1999 and 1998, the provision for income taxes did not bear a normal relationship to earnings because Canadian taxes were payable on Canadian operations and losses from U.S. operations provide no foreign tax benefits. Environmental Matters - --------------------- Federal, state, and Canadian governmental agencies issue rules and regulations and enforce laws to protect the environment which are often difficult and costly to comply with and which carry substantial penalties for failure to comply, particularly in regard to the discharge of materials into the environment. The regulatory burden on the oil and gas industry increases its cost of doing business. These laws, rules and regulations affect the operations of the Company and could have a material adverse effect upon the earnings or competitive position of the Company. Although Barnwell's experience has been to the contrary, there is no assurance that this will continue to be the case. Inflation - --------- The effect of inflation on the Company has generally been to increase its cost of operations, interest cost (as a substantial portion of the Company's debt is at variable short-term rates of interest which tend to increase as inflation increases), general and administrative costs and direct costs associated with oil and natural gas production and contract drilling operations. In the case of contract drilling, the Company has not been able to increase its contract revenues to fully compensate for increased costs. In the case of oil and natural gas, prices realized by the Company are essentially determined by world prices for oil and western Canadian/Midwestern U.S. prices for natural gas. Recent Accounting Pronouncements - -------------------------------- In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," which establishes accounting and reporting standards for derivative instruments and hedging activities and requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. In July 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133, an Amendment of FASB Statement No. 133," which defers the effective date of SFAS No. 133 to be effective for all fiscal quarters of fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an Amendment of FASB Statement No. 133," which addresses a limited number of issues causing implementation difficulties for certain entities that apply SFAS No. 133. Management does not expect adoption of SFAS No. 133, as amended by SFAS No. 138, will have a material effect on the Company's financial condition, results of operations or liquidity. In March 2000, the FASB issued FASB Interpretation No. 44, "Accounting for Certain Transactions involving Stock Compensation, an interpretation of APB Opinion No. 25." Interpretation No. 44 clarifies the application of Accounting Principles Board ("APB") Opinion No. 25 for certain issues involving employee stock compensation and is generally effective July 1, 2000. Adoption of Interpretation No. 44 did not have a material effect on the Company's financial condition, results of operations or liquidity. In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement No. 125." SFAS No. 140 is effective for transfers and servicing of financial assets and extinguishments of liabilities occurring after March 31, 2001. SFAS No. 140 is effective for recognition and reclassification of collateral and for disclosures relating to securitization transactions and collateral for fiscal years ending after December 15, 2000. Management does not expect adoption of SFAS No. 140 will have a material effect on the Company's financial condition, results of operations or liquidity. In December 1999, the Securities and Exchange Commission ("SEC") issued Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial Statements." The SAB summarizes certain of the SEC staff's views in applying U.S. generally accepted accounting principles to revenue recognition in financial statements. In June 2000, the SEC issued SAB No. 101B, which delays the implementation date of SAB No. 101 until no later than the fourth quarter of fiscal years beginning after December 15, 1999. The adoption of SAB No. 101 is not expected to have a material effect on the Company's financial condition, results of operations or liquidity. Item 7. FINANCIAL STATEMENTS -------------------- Independent Auditors' Report ---------------------------- The Board of Directors Barnwell Industries, Inc.: We have audited the consolidated balance sheets of Barnwell Industries, Inc. and subsidiaries as of September 30, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended September 30, 2000. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Barnwell Industries, Inc. and subsidiaries as of September 30, 2000 and 1999, and the results of their operations and their cash flows for each of the years in the three-year period ended September 30, 2000, in conformity with accounting principles generally accepted in the United States of America. /s/ KPMG LLP Honolulu, Hawaii November 22, 2000
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS September 30, - ------ ---------------------------- CURRENT ASSETS: 2000 1999 ----------- ----------- Cash and cash equivalents $ 5,701,000 $ 2,577,000 Accounts receivable, net (Notes 3 and 13) 2,018,000 1,873,000 Royalty tax credit and taxes receivable 133,000 261,000 Costs and estimated earnings in excess of billings on uncompleted contracts (Note 3) 496,000 172,000 Deferred income taxes (Note 6) 160,000 130,000 Prepaid royalties, inventories and other 613,000 584,000 ----------- ----------- TOTAL CURRENT ASSETS 9,121,000 5,597,000 ----------- ----------- INVESTMENT IN LAND (Notes 4 and 5) 3,975,000 3,519,000 ----------- ----------- OTHER ASSETS 216,000 207,000 ----------- ----------- PROPERTY AND EQUIPMENT (Notes 5 and 10): Land 465,000 465,000 Oil and natural gas properties subject to amortization (full cost accounting) 52,462,000 48,934,000 Drilling rigs and equipment 5,135,000 8,043,000 Other property and equipment 2,820,000 2,539,000 ----------- ----------- 60,882,000 59,981,000 Accumulated depreciation, depletion and amortization 35,534,000 36,009,000 ----------- ----------- TOTAL PROPERTY AND EQUIPMENT 25,348,000 23,972,000 ----------- ----------- TOTAL ASSETS $38,660,000 $33,295,000 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY - ------------------------------------ CURRENT LIABILITIES: Accounts payable $ 1,821,000 $ 1,894,000 Accrued expenses 3,383,000 1,975,000 Billings in excess of costs and estimated earnings on uncompleted contracts (Note 3) 350,000 139,000 Payable to joint interest owners 783,000 648,000 Income taxes payable (Note 6) 650,000 251,000 Current portion of long-term debt (Note 5) 400,000 1,650,000 ----------- ----------- TOTAL CURRENT LIABILITIES 7,387,000 6,557,000 ----------- ----------- LONG-TERM DEBT (Note 5) 9,133,000 12,631,000 ----------- ----------- DEFERRED INCOME TAXES (Note 6) 7,206,000 6,301,000 ----------- ----------- MINORITY INTEREST 2,260,000 - ----------- ----------- COMMITMENTS AND CONTINGENCIES (Notes 4, 7, 8 and 9) STOCKHOLDERS' EQUITY (Notes 5 and 8): Common stock, par value $.50 per share: Authorized, 4,000,000 shares Issued, 1,642,797 shares 821,000 821,000 Additional paid-in capital 3,103,000 3,103,000 Retained earnings 16,680,000 11,801,000 Accumulated other comprehensive loss - foreign currency translation adjustments (3,048,000) (3,130,000) Treasury stock, at cost, 331,845 shares at September 30, 2000 and 325,845 shares at September 30, 1999 (4,882,000) (4,789,000) ----------- ----------- TOTAL STOCKHOLDERS' EQUITY 12,674,000 7,806,000 ----------- ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $38,660,000 $33,295,000 =========== =========== See Notes to Consolidated Financial Statements
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Year ended September 30, ------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Revenues: Oil and natural gas $15,270,000 $10,130,000 $ 9,400,000 Contract drilling 3,520,000 4,230,000 1,510,000 Gas processing and other 1,240,000 800,000 1,010,000 Sale of development rights, net (Note 4) 6,540,000 - - ----------- ----------- ----------- 26,570,000 15,160,000 11,920,000 ----------- ----------- ----------- Costs and expenses: Oil and natural gas operating 3,128,000 3,368,000 3,223,000 Contract drilling operating 2,741,000 3,378,000 1,822,000 General and administrative 3,470,000 3,187,000 3,292,000 Depreciation, depletion and amortization 3,572,000 2,820,000 2,898,000 Interest expense, net (Note 5) 813,000 809,000 722,000 Foreign exchange losses 420,000 - - Minority interest in earnings (Note 4) 3,308,000 - - Write-down of assets (Note 10) - - 2,995,000 ----------- ----------- ----------- 17,452,000 13,562,000 14,952,000 ----------- ----------- ----------- Earnings (loss) before income taxes 9,118,000 1,598,000 (3,032,000) Provision for income taxes (Note 6) 4,108,000 1,078,000 858,000 ----------- ----------- ----------- NET EARNINGS (LOSS) $ 5,010,000 $ 520,000 $(3,890,000) =========== =========== =========== BASIC EARNINGS PER COMMON SHARE $3.81 $0.39 $(2.95) =========== =========== =========== DILUTED EARNINGS PER COMMON SHARE $3.67 $0.39 $(2.95) =========== =========== =========== WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING BASIC 1,315,312 1,316,952 1,319,719 =========== =========== =========== DILUTED 1,388,540 1,316,952 1,319,719 =========== =========== =========== See Notes to Consolidated Financial Statements
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Year ended September 30, --------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Cash flows from operating activities: Net earnings (loss) $ 5,010,000 $ 520,000 $(3,890,000) Adjustments to reconcile net earnings (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 3,572,000 2,820,000 2,898,000 Minority interest in earnings 3,308,000 - - Deferred income taxes 1,036,000 314,000 524,000 Foreign exchange losses 420,000 - - Gain on sale of equity securities (238,000) - - Earnings on sale of development rights, net (6,540,000) - - Write-down of assets - - 2,995,000 ----------- ----------- ----------- 6,568,000 3,654,000 2,527,000 Increase (decrease) from changes in current assets and liabilities (Note 14) 1,626,000 (929,000) 434,000 ----------- ----------- ----------- Net cash provided by operating activities 8,194,000 2,725,000 2,961,000 ----------- ----------- ----------- Cash flows from investing activities: Proceeds from sale of development rights, net 6,540,000 - - Proceeds from sale of marketable securities 379,000 - - Proceeds from sale of property and equipment 142,000 309,000 93,000 Decrease (increase) in other assets (9,000) 6,000 8,000 Capital expenditures (6,249,000) (2,831,000) (8,127,000) ----------- ----------- ----------- Net cash provided by (used in) investing activities 803,000 (2,516,000) (8,026,000) ----------- ----------- ----------- Cash flows from financing activities: Long-term debt borrowings 50,000 885,000 3,067,000 Purchases of common stock for treasury (93,000) - (84,000) Payment of dividends (131,000) - - Distribution to minority interest partner (873,000) - - Repayments of long-term debt (4,766,000) (739,000) - ----------- ----------- ----------- Net cash (used in) provided by financing activities (5,813,000) 146,000 2,983,000 ----------- ----------- ----------- Effect of exchange rate changes on cash and cash equivalents (60,000) 44,000 (142,000) ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents 3,124,000 399,000 (2,224,000) Cash and cash equivalents at beginning of year 2,577,000 2,178,000 4,402,000 ----------- ----------- ----------- Cash and cash equivalents at end of year $ 5,701,000 $ 2,577,000 $ 2,178,000 =========== =========== =========== See Notes to Consolidated Financial Statements
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) Years ended September 30, 2000, 1999, and 1998 Accumulated Additional Comprehensive Other Total Common Paid-In Income Retained Comprehensive Treasury Stockholders' Stock Capital (Loss) Earnings Loss Stock Equity --------- ----------- ------------ ----------- ------------ ------------ ------------- Balances at September 30, 1997 $ 821,000 $ 3,103,000 $15,171,000 $ (2,240,000) $ (4,705,000) $ 12,150,000 Comprehensive loss: Net loss $ (3,890,000) (3,890,000) (3,890,000) ------------ Other comprehensive loss, net of income taxes: Foreign currency translation adjustments (1,421,000) Unrealized holding loss on securities (11,000) ------------ Other comprehensive loss (1,432,000) (1,432,000) (1,432,000) ------------ Total comprehensive loss $ (5,322,000) ============ Purchases of 5,100 shares of common stock for treasury (84,000) (84,000) --------- ----------- ----------- ------------ ------------ ------------- Balances at September 30, 1998 $ 821,000 $ 3,103,000 $11,281,000 $ (3,672,000) $ (4,789,000) $ 6,744,000 Comprehensive income: Net earnings $ 520,000 520,000 520,000 Other comprehensive income, net of income taxes - foreign currency translation adjustments 542,000 542,000 542,000 ------------ Total comprehensive income $ 1,062,000 --------- ----------- ============ ----------- ------------ ------------ ------------- Balances at September 30, 1999 $ 821,000 $ 3,103,000 $11,801,000 $ (3,130,000) $ (4,789,000) $ 7,806,000 ========= =========== =========== ============ ============ ============= (continued on next page)
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) Years ended September 30, 2000, 1999, and 1998 (continued from previous page) Accumulated Additional Comprehensive Other Total Common Paid-In Income Retained Comprehensive Treasury Stockholders' Stock Capital (Loss) Earnings Loss Stock Equity --------- ----------- ------------ ----------- ------------ ------------ ------------- Balances at September 30, 1999 $ 821,000 $ 3,103,000 $11,801,000 $ (3,130,000) $ (4,789,000) $ 7,806,000 Purchase of 6,000 common shares for treasury (93,000) (93,000) Dividends declared ($0.10 per share) (131,000) (131,000) Comprehensive income: Net earnings $ 5,010,000 5,010,000 5,010,000 Other comprehensive loss, net of income taxes - foreign currency translation adjustments (205,000) (205,000) (205,000) ------------ Total comprehensive income $ 4,805,000 ============ Foreign exchange losses realized - net of income taxes 287,000 287,000 --------- ----------- ----------- ------------ ------------ ------------- Balances at September 30, 2000 $ 821,000 $ 3,103,000 $16,680,000 $ (3,048,000) $ (4,882,000) $ 12,674,000 ========= =========== =========== ============ ============ ============= See Notes to Consolidated Financial Statements
BARNWELL INDUSTRIES, INC. ------------------------- AND SUBSIDIARIES ---------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ------------------------------------------ YEARS ENDED SEPTEMBER 30, 2000, 1999 AND 1998 --------------------------------------------- 1. DESCRIPTION OF THE REPORTING ENTITY AND BUSINESS ------------------------------------------------ The consolidated financial statements include the accounts of Barnwell Industries, Inc. and all majority-owned subsidiaries, including a land development joint venture (collectively referred to herein as "Company"). All significant intercompany accounts and transactions have been eliminated. During its last three fiscal years, the Company was engaged in exploring for, developing, producing and selling oil and natural gas in Canada, investing in leasehold land in Hawaii, and drilling wells and installing and repairing water pumping systems in Hawaii. The Company's oil and natural gas activities comprise its largest business segment. Approximately 57% of the Company's revenues and 80% of the Company's capital expenditures for the fiscal year ended September 30, 2000 were attributable to its oil and natural gas activities. The Company's land investment activities accounted for 25% of the Company's revenues, contract drilling activities accounted for 13% of the Company's revenues, and gas processing and other revenues comprised the remaining 5% of revenues for fiscal 2000. Land investment revenues relate to sales of leasehold interests and development rights, which do not occur every year. Changes in the marketplace of any of the aforementioned industries may significantly affect management's estimates and the Company's performance. 2. SIGNIFICANT ACCOUNTING POLICIES ------------------------------- Cash and cash equivalents - ------------------------- Cash and cash equivalents includes cash on hand, demand deposits and short-term investments with original maturities of three months or less. Oil and natural gas properties - ------------------------------ The Company uses the full cost method of accounting under which all costs incurred in the acquisition, exploration and development of oil and natural gas reserves, including unsuccessful wells, are capitalized until such time as the aggregate of such costs, on a country by country basis, equals the discounted present value (at 10%) of the Company's estimated future net cash flows from estimated production of proved oil and natural gas reserves, as determined by independent petroleum engineers, less related income tax effects. Any capitalized costs in excess of the discounted present value are charged to expense. Depletion of all such costs, except costs related to major development projects, is provided by the unit-of-production method based upon proved oil and natural gas reserves of all properties on a country by country basis. Investments in major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. General and administrative costs related to oil and natural gas operations are expensed as incurred. Estimated future site restoration and abandonment costs are charged to earnings at the rate of depletion and are included in accumulated depreciation, depletion and amortization. Proceeds from the disposition of minor producing oil and natural gas properties are credited to the cost of oil and natural gas properties. Gains or losses are recognized on the disposition of significant oil and natural gas properties. Contract drilling - ----------------- Revenues, costs and profits applicable to contract drilling contracts are included in the consolidated statements of operations using the percentage of completion method, principally measured by the percentage of labor dollars incurred to date for each contract to total estimated labor dollars for each contract. Contract losses are recognized in full in the year the losses are identified. The performance of drilling contracts may extend over more than one year and, in the interim periods, estimates of total contract costs and profits are used to determine revenues and profits earned for reporting the results of the contract drilling operations. Revisions in the estimates required by subsequent performance and final contract settlements are included as adjustments to the results of operations in the period such revisions and settlements occur. Contracts are normally less than one year in duration. Investment in land and revenue recognition - ------------------------------------------ The Company's investment in land is comprised of land under development and development rights under option. Investment in land under development is evaluated for impairment whenever events or changes in circumstances indicate that the recorded investment balance may not be fully recoverable. The Company's cost, including capitalized interest, of the land under development is included in the consolidated balance sheets under the caption "Investment in Land." Development rights under option are reported at the lower of the asset carrying value or fair value, less costs to sell. Land sales for development rights under option are accounted for under the cost recovery method. Under the cost recovery method, no gain is recognized until cash received exceeds the cost and the estimated future costs related to the development rights sold. The accompanying consolidated balance sheets include no cost for development rights under option and, accordingly, cash receipts, if any, in excess of costs will be reported as revenues. Long-lived assets - ----------------- Long-lived assets to be held and used, other than oil and natural gas properties, are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable. If the future cash flows expected to result from use of the asset (undiscounted and without interest charges) are less than the carrying amount of the asset, an impairment loss is recognized. Such impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset. Long-lived assets to be disposed of are reported at the lower of the asset carrying value or fair value, less cost to sell. Drilling rigs and other equipment - --------------------------------- Drilling rigs and other equipment are stated at cost. Depreciation is computed using the straight-line method based on estimated useful lives ranging from three to ten years. Inventories - ----------- Inventories are comprised of drilling materials and are valued at the lower of weighted average cost or market value. Environmental - ------------- The Company is subject to extensive environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and maintenance of surface conditions and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Income taxes - ------------ Deferred income taxes are determined using the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Earnings per common share - ------------------------- Basic earnings per share excludes dilution and is computed by dividing net earnings (loss) by the weighted-average number of common shares outstanding for the period. Diluted earnings per share includes the potentially dilutive effect of outstanding common stock options and securities which are convertible to common shares. Reconciliations between the numerator and denominator of the basic and diluted earnings per share computations for the year ended September 30, 2000 are as follows (there were no differences in fiscal 1999 or 1998): September 30, 2000 ----------------------------------------- Net Earnings Shares Per-Share (Numerator) (Denominator) Amount ----------- ---------- ------ Basic earnings per share $ 5,010,000 1,315,312 $ 3.81 ====== Effect of dilutive securities - Common stock options - 13,228 Convertible debentures 90,000 60,000 ----------- ---------- Diluted earnings per share $ 5,100,000 1,388,540 $ 3.67 =========== ========== ====== Assumed conversion of common stock options to acquire 50,000, 50,000 and 67,500 shares of the Company's stock was excluded from the computation of diluted earnings per share for the years ended September 30, 2000, 1999 and 1998, respectively, because their inclusion would be antidilutive. Assumed conversion of convertible debentures to 80,000 and 100,000 shares of common stock was excluded from the computation of diluted earnings per share for the years ended September 30, 1999 and 1998, respectively, because their inclusion would be antidilutive. Foreign currency translation - ---------------------------- Assets and liabilities of foreign operations and subsidiaries are translated at the year-end exchange rate and resulting translation gains or losses are accounted for in a stockholders' equity account entitled "accumulated other comprehensive loss - foreign currency translation adjustments." Operating results of foreign subsidiaries are translated at average exchange rates during the period. Realized foreign currency transaction losses amounting to $420,000 for the fiscal year ended September 30, 2000 are reflected in the accompanying consolidated statements of operations. Realized foreign currency transaction gains or losses were not material in fiscal years 1999 and 1998. Use of Estimates in the Preparation of Financial Statements - ----------------------------------------------------------- The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ significantly from those estimates. Significant assumptions are required in the valuation of deferred tax assets and proved oil and natural gas reserves, and such assumptions may impact the amount at which deferred tax assets and oil and natural gas properties are recorded. 3. RECEIVABLES AND CONTRACT COSTS ------------------------------ Accounts receivable, current, are net of allowances for doubtful accounts of $154,000 and $196,000 as of September 30, 2000 and 1999, respectively. Included in accounts receivable are contract retainage balances of $208,000 and $274,000 as of September 30, 2000 and 1999, respectively. These balances are expected to be collected within one year, generally within 45 days after the related contracts have received final acceptance and approval. Costs and estimated earnings on uncompleted contracts are as follows: September 30, --------------------------- 2000 1999 ---------- ---------- Costs incurred on uncompleted contracts $1,390,000 $3,211,000 Estimated earnings 249,000 957,000 ---------- ---------- 1,639,000 4,168,000 Less billings to date 1,493,000 4,135,000 ---------- ---------- $ 146,000 $ 33,000 ========== ========== Costs and estimated earnings on uncompleted contracts are included in the consolidated balance sheets under the following captions: September 30, --------------------------- 2000 1999 ---------- ---------- Costs and estimated earnings in excess of billings on uncompleted contracts $ 496,000 $ 172,000 Billings in excess of costs and estimated earnings on uncompleted contracts (350,000) (139,000) ---------- ---------- $ 146,000 $ 33,000 ========== ========== 4. INVESTMENT IN LAND ------------------ The Company owns a 50.1% controlling interest in Kaupulehu Developments, a Hawaii general partnership. Between 1986 and 1989, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of the Four Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club, which opened in 1996, a second golf course (currently under construction), and single and multiple family residential units on land acquired from Kaupulehu Developments, located approximately six miles north of the Kona International Airport in the North Kona District of the Island of Hawaii. In January 2000, Kaupulehu Makai Venture, an affiliate of Kajima Corporation of Japan, exercised a portion of the option granted in 1990 by Kaupulehu Developments for the development of residential parcels within the Four Seasons Resort Hualalai at Historic Ka'upulehu on the Island of Hawaii. The Company recognized revenues of $6,540,000, net of costs associated with the transaction, from the receipt of the option monies. $1,300,000 of the proceeds were used to repay Kaupulehu Developments' borrowings from a Hawaii bank, and $873,000 were distributed to Kaupulehu Developments' minority interest partner, Cambridge Hawaii Limited Partnership ("CHLP"), which holds the remaining 49.9% interest in Kaupulehu Developments. CHLP is a Hawaii limited partnership comprised of three Canadian limited partnerships, comprised of individuals, one of whom is Mr. Terry Johnston. Mr. Johnston was elected to the Board of Directors of the Company in March 2000. The Company did not receive any revenues in fiscal 1999 and 1998 related to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments' revenues specifically relate to the sales of leasehold interests and development rights, which do not occur every year. At September 30, 2000, the remaining unexercised portion of the aforementioned option on residential development rights is for approximately 80 acres of residentially zoned leasehold land adjacent to the completed and currently under construction golf courses. If Kaupulehu Makai Venture fully exercises this option, Kaupulehu Developments will receive a total of $25,500,000. The option expires on April 30, 2003 unless 50% of the option proceeds are received on or before April 30, 2003. The remainder of the option would then expire on April 30, 2007. There is no assurance that this option or any portion of it will be exercised. Kaupulehu Developments also holds leasehold rights in approximately 2,100 acres of land located adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka'upulehu. These approximately 2,100 acres are located between the Queen Kaahumanu Highway and the Pacific Ocean. In June 1996, the State Land Use Commission ("LUC") approved Kaupulehu Developments' petition for reclassification of approximately 1,000 acres of these 2,100 acres of land into the Urban District for resort/residential development. Subsequent to the LUC's approval, a notice of appeal was filed with the Third Circuit Court of the State of Hawaii by parties seeking to reverse the LUC's decision. The Third Circuit Court of the State of Hawaii upheld the LUC's approval of Kaupulehu Developments' rezoning request in all respects in a Decision and Order issued in August 1997. In November 1997, a notice of appeal was filed with the Supreme Court of the State of Hawaii by parties seeking to reverse the Third Circuit Court's decision. In June 1998, Kaupulehu Developments filed an Application for a Project District zoning ordinance and a Special Management Area ("SMA") Use Permit Petition with the County of Hawaii, requesting changes in zoning and use of approximately 1,000 of the 2,100 acres of land to allow residential, resort and commercial development. Both the County zoning ordinance and the SMA Use Permit are required for development of the property. In December 1998, following a contested case hearing conducted in November 1998, the Planning Commission of the County of Hawaii granted the requested SMA Use Permit to Kaupulehu Developments to be effective when the zoning ordinance is adopted. Subsequent to the Planning Commission's approval, in January 1999, a notice of appeal was filed with the Third Circuit Court of the State of Hawaii by parties seeking to reverse the Planning Commission's decision. In April 1999, the County of Hawaii adopted an ordinance granting zoning approval of Kaupulehu Developments' Application for a Project District zoning ordinance, which requested changes in zoning and use of the aforementioned 1,000 acres of land to allow residential, resort and commercial development. In December 1999, the Third Circuit Court of the County of Hawaii remanded Kaupulehu Developments' SMA Use Permit Petition back to the County of Hawaii Planning Commission for further review due to procedural issues. In late December 1999, the County of Hawaii Planning Commission reaffirmed their approval of the SMA Use Permit Petition. In September 2000, the Supreme Court of the State of Hawaii ruled on the appeal of the LUC's decision, finding in favor of Kaupulehu Developments on three of the issues on appeal, but on the fourth issue, the court remanded the matter to the LUC for the limited purpose of entering specific findings and conclusions, with further hearing if necessary, regarding: (1) the identity and scope of "valued cultural, historical, or natural resources" in the petition area, including the extent to which traditional and customary native Hawaiian rights are exercised in the petition area; (2) the extent to which those resources - including traditional and customary native Hawaiian rights - will be affected or impaired by the proposed action; and (3) the feasible action, if any, to be taken by the LUC to reasonably protect native Hawaiian rights if they are found to exist. In October 2000, Kaupulehu Developments filed a motion with the LUC to bring the matter in front of the LUC. Management cannot predict the timing or outcome of the LUC's procedures or findings and, accordingly, there is no assurance that State of Hawaii zoning approval will be forthcoming at any time. If the Company is unable to obtain the LUC's approval, there will be a materially adverse impairment of the value of the Company's leasehold rights in this approximately 1,000 acres. Kaupulehu Developments continues to negotiate a revised development agreement and residential fee purchase prices with the lessor of the 2,100 acre parcel. Management cannot predict the outcome of these negotiations. Costs related to the rezoning of the conservation land are capitalized and included in the consolidated balance sheets under the caption, "Investment in Land." 5. LONG-TERM DEBT -------------- The Company has a credit facility at the Royal Bank of Canada, a Canadian bank, for $17,000,000 Canadian dollars, or its U.S. dollar equivalent of approximately $11,300,000 at September 30, 2000. Borrowings under this facility were $8,333,000 and $11,431,000 at September 30, 2000 and 1999, respectively, and are included in long-term debt. At September 30, 2000, the Company had unused credit available under this facility of approximately $2,960,000. The facility is available in U.S. dollars at the London Interbank Offer Rate ("LIBOR") plus 7/8%, at U.S. prime, or in Canadian dollars at Canadian prime. A standby fee of 1/2% per annum is charged on the unused facility balance. Under the financing agreement, the facility is reviewed annually, with the next review planned for April 2001. Subject to that review, the facility may be extended one year with no required debt repayments for one year or converted to a 5-year term loan by the bank. If the facility is converted to a 5-year term loan, the Company has agreed to the following repayment schedule of the then outstanding loan balance: year 1-30%; year 2-27%; year 3-16%; year 4-14% and year 5-13%. The Company has the option to change the currency denomination and interest rate applicable to the loan at periodic intervals during the term of the loan. During the year ended September 30, 2000, the Company paid interest at rates ranging from 6.13% to 7.54%. The interest rate on the facility at September 30, 2000 was 7.5%. The facility is collateralized by the Company's interests in its major oil and natural gas properties and a negative pledge on its remaining oil and natural gas properties. The facility is reviewed annually with a primary focus on the future cash flows that will be generated by the Company's Canadian oil and natural gas properties. No compensating bank balances are required for this facility. The Canadian bank has represented that it will not require any repayments under the facility before September 30, 2001. Accordingly, the Company has classified outstanding borrowings under the facility as long-term debt. At September 30, 1999, the Company had long-term debt with a Hawaii bank of $1,250,000. In the quarter ended December 31, 1999, the Company borrowed an additional $50,000, and in January 2000 repaid the entire $1,300,000 outstanding balance. In June 1995, the Company issued $2,000,000 of convertible notes due July 1, 2003. $1,950,000 of such notes were purchased by an officer/shareholder, a director/shareholder, and certain other shareholders of the Company. The notes are payable in 20 consecutive equal quarterly installments beginning in October 1998. Four quarterly installments aggregating $400,000 were paid during fiscal year 2000. Interest is payable quarterly at a rate to be adjusted each quarter to the greater of 10% per annum or 1% over the prime rate of interest. The Company paid interest on these convertible notes at an average rate of 10.13% per annum in 2000 and 10.00% per annum throughout fiscal years 1999 and 1998. The notes are unsecured and convertible at any time at the holder's option into shares of the Company's common stock at a price of $20.00 per share, subject to adjustment for certain events including a stock split of, or stock dividend on, the Company's common stock. The notes are redeemable, at the option of the Company, at any time at premiums declining 1% annually from 2% of the principal amount of the notes at July 1, 2000. At September 30, 2000, $800,000 of these notes are included in long-term debt and $400,000 of these notes are included in the current portion of long-term debt. At September 30, 2000, the maturities of current and long-term debt by fiscal year, exclusive of the credit facility with the Canadian bank, are as follows: 2001 400,000 2002 400,000 2003 400,000 ---------- $1,200,000 ========== The Company capitalizes interest on costs related to its investment in land. The Company also capitalized interest on its investment in undeveloped natural gas and oil leases in the Central Basin in Michigan during the first quarter of the year ended September 30, 1998. Interest costs for the years ended September 30, 2000, 1999, and 1998 are summarized as follows: 2000 1999 1998 ---------- ---------- ---------- Interest costs incurred $ 906,000 $1,010,000 $ 901,000 Less interest costs capitalized on: Investment in land 93,000 201,000 169,000 Investment in natural gas and oil properties - - 10,000 ---------- ---------- ---------- Interest expense $ 813,000 $ 809,000 $ 722,000 ========== ========== ========== 6. TAXES ON INCOME --------------- The components of earnings (loss) before income taxes are as follows: Year ended September 30, ----------------------------------------- 2000 1999 1998 ----------- ----------- ----------- United States $ 1,780,000 $(1,025,000) $(4,736,000) Canadian 7,338,000 2,623,000 1,704,000 ----------- ----------- ----------- $ 9,118,000 $ 1,598,000 $(3,032,000) =========== =========== =========== The components of the provision for income taxes related to the above earnings (loss) are as follows: Year ended September 30, ----------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Current: United States - Federal $ 50,000 $ - $ - Canadian 3,022,000 764,000 334,000 ----------- ----------- ----------- Total current 3,072,000 764,000 334,000 ----------- ----------- ----------- Deferred: United States 916,000 97,000 (23,000) Canadian 120,000 217,000 547,000 ----------- ----------- ----------- Total deferred 1,036,000 314,000 524,000 ----------- ----------- ----------- $ 4,108,000 $ 1,078,000 $ 858,000 =========== =========== =========== A reconciliation between the reported provision for income taxes and the amount computed by multiplying the earnings (loss) before income taxes by the United States federal tax rate is as follows: Year ended September 30, ----------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Tax expense (benefit) computed by applying statutory rate $ 3,191,000 $ 559,000 $(1,061,000) Change in the balance of the valuation allowance 906,000 170,000 1,339,000 Effect of the foreign tax provision on the total tax provision - 422,000 489,000 State net operating losses utilized (generated) 83,000 (61,000) (70,000) Other (72,000) (12,000) 161,000 ----------- ----------- ----------- $ 4,108,000 $ 1,078,000 $ 858,000 =========== =========== =========== The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at September 30, 2000 and 1999 are as follows: Deferred income tax assets: 2000 1999 ------------ ----------- U.S. tax effect of deferred Canadian taxes $ 2,439,000 $ 2,452,000 Foreign tax credit carryforwards 1,745,000 874,000 Tax basis in land in excess of book basis 908,000 1,097,000 Write-down of assets not deducted for tax 355,000 355,000 State of Hawaii net operating loss carryforwards 260,000 414,000 Expenses accrued for books but not for tax 274,000 261,000 Alternative minimum tax credit carryforwards 111,000 225,000 Other 106,000 118,000 U.S. federal net operating loss carryforwards - 158,000 ------------ ----------- Total gross deferred tax assets 6,198,000 5,954,000 Less-valuation allowance (5,016,000) (4,110,000) ------------ ----------- Net deferred income tax assets 1,182,000 1,844,000 ------------ ----------- Deferred income tax liabilities: Property and equipment accumulated tax depreciation and depletion in excess of book under Canadian tax law (7,172,000 (7,213,000) Property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law (1,056,000) (581,000) Other - (221,000) ------------ ----------- Total deferred income tax liabilities (8,228,000) (8,015,000) ------------ ----------- Net deferred income tax liability $ (7,046,000) $(6,171,000) ============ =========== The total valuation allowance increased $906,000, $170,000, and $1,339,000 for the years ended September 30, 2000, 1999, and 1998, respectively. The increase for the year ended September 30, 2000 relates primarily to foreign tax credit carryforwards for which it is more likely than not that such carryforwards will not be utilized to reduce the Company's U.S. tax obligation. The increase for the year ended September 30, 1998 relates primarily to foreign tax credit carryforwards and U.S. federal net operating loss carryforwards for which it is more likely than not that some portion of such carryforwards will not be utilized to reduce the Company's U.S. tax obligation. Historically, the Company has reduced U.S. regular taxes due on consolidated U.S. taxable income by utilizing foreign tax credits. If the net operating loss is utilized to reduce consolidated U.S. taxable income in a year in which the Company would normally have utilized foreign tax credits to fully offset regular taxes, the net operating loss will provide no incremental tax benefit; therefore a valuation allowance has been provided. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax asset will not be realized. The Company has established a valuation allowance for Canadian tax deductions, foreign tax credits, U.S. federal net operating loss carryforwards and state of Hawaii net operating loss carryforwards which may not be realizable in future years as there can be no assurance of any specific level of earnings or that the timing of U.S. earnings will coincide with the payment of Canadian taxes to enable Canadian taxes to be fully deducted (or recoverable) for U.S. tax purposes. Additionally, utilization of U.S. federal net operating loss carryforwards will provide no incremental tax benefit if foreign tax credits generated in future years will be displaced by the net operating loss carryforwards as it is more likely than not that the foreign tax credits will expire unused. Net deferred tax assets will primarily be realized through the deduction of the cost basis in investment in land against proceeds from investment in land for tax purposes. Under the cost recovery accounting method, this cost basis has already been expensed for book purposes. The amount of deferred income tax assets considered realizable may be reduced if estimates of future taxable income are reduced. At September 30, 2000, the Company had alternative minimum tax credit carryforwards of $111,000 which are available to reduce future U.S. federal regular income taxes, if any, over an indefinite period. 7. PENSION PLAN ------------ The Company sponsors a noncontributory defined benefit pension plan covering substantially all employees, with benefits based on years of service and the employee's highest consecutive five-year average earnings. The Company's funding policy is intended to provide for both benefits attributed to service to-date and for those expected to be earned in the future. The plan assets at September 30, 2000 were invested as follows: 8% in cash and cash equivalents, 31% listed government mortgages and 61% common stocks and equity mutual funds. The funded status of the pension plan and the amounts recognized in the consolidated financial statements are as follows: September 30, -------------------------- 2000 1999 ---------- ---------- Change in Benefit Obligation Benefit obligation at beginning of year $1,984,000 $1,966,000 Service cost 78,000 77,000 Interest cost 145,000 139,000 Actuarial (gain)/loss 16,000 (64,000) Benefits paid (129,000) (134,000) ---------- ---------- Benefit obligation at end of year 2,094,000 1,984,000 ---------- ---------- Change in Plan Assets Fair value of plan assets at beginning of year 2,314,000 2,224,000 Actual return on plan assets 235,000 224,000 Employer contribution 80,000 - Benefits paid (129,000) (134,000) ---------- ---------- Fair value of plan assets at end of year 2,500,000 2,314,000 ---------- ---------- Funded status 406,000 330,000 Unrecognized net asset (2,000) (2,000) Unrecognized prior service cost 29,000 34,000 Unrecognized actuarial gain (541,000) (514,000) ---------- ---------- Accrued benefit cost $ (108,000) $ (152,000) ========== ========== Weighted-Average Assumptions as of September 30, 2000 1999 ---------- ---------- Discount rate 7.50% 7.50% Expected return on plan assets 8.00% 8.00% Rate of compensation increase 5.00% 5.00% Year ended September 30, ------------------------------------- 2000 1999 1998 --------- --------- --------- Net Periodic Benefit Cost for the Year Service cost $ 78,000 $ 77,000 $ 66,000 Interest cost 145,000 139,000 139,000 Expected return on plan assets (180,000) (172,000) (168,000) Amortization of net asset (1,000) (1,000) (1,000) Amortization of prior service cost 6,000 6,000 6,000 Amortization of net actuarial gain (12,000) - (8,000) --------- --------- --------- Net periodic benefit cost $ 36,000 $ 49,000 $ 34,000 ========= ========= ========= 8. STOCK OPTIONS ------------- In March 1995, the Company granted 20,000 stock options to an officer of the Company under a non-qualified plan at a purchase price of $19.625 per share (market price on date of grant), with 4,000 of such options vesting annually commencing one year from the date of grant. These options have stock appreciation rights that permit the holder to receive stock, cash or a combination thereof equal to the amount by which the fair market value, at the time of exercise of the option, exceeds the option price. The options expire ten years from the date of grant. No compensation cost has been recognized for these options for the years ended September 30, 2000, 1999 and 1998. In June 1998, the Company granted 30,000 stock options to an officer of the Company's oil and gas segment under a non-qualified plan at a purchase price of $15.625 per share (market price on date of grant), with 6,000 of such options vesting annually commencing one year from the date of grant. These options have stock appreciation rights that permit the holder to receive stock, cash or a combination thereof equal to the amount by which the fair market value, at the time of exercise of the option, exceeds the option price. The options expire ten years from the date of grant. The Company recognized $46,000 of compensation costs relating to these options in the year ended September 30, 2000. In December 1999, the Company granted qualified stock options to certain employees of the Company to acquire 68,000 shares and 29,000 shares of the Company's common stock with an exercise price per share of $11.875 (market price at date of grant) and $13.063 (110% of market price at date of grant), respectively. These options vest annually over four years commencing one year from the date of grant. The $11.875 per share options expire ten years from the date of grant, and the $13.063 per share options expire five years from the date of grant. No compensation cost has been recognized for these options for the year ended September 30, 2000. The Company applies the provisions of APB Opinion No. 25 in accounting for stock-based compensation and adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS No. 123"), effective October 1, 1996. Had compensation cost for the stock options granted in June 1998 and December 1999 been determined based on the fair value method of measuring stock-based compensation provisions of SFAS No. 123, the Company's net earnings and basic and diluted earnings per share would have been as follows: Years ended September 30, ------------------------------------- 2000 1999 1998 ---- ---- ---- Pro-forma net earnings (loss) $ 4,750,000 $ 440,000 $(3,920,000) Pro-forma basic =========== =========== =========== earnings (loss) per share $ 3.61 $ 0.33 $ (2.97) Pro-forma diluted =========== =========== =========== earnings (loss) per share $ 3.49 $ 0.33 $ (2.97) =========== =========== =========== Fair value measurement of these options was based on a Black Scholes option-pricing model which included assumptions of a weighted average expected life of 5.97 years, expected volatility of 30%, weighted average risk-free interest rate of 6.12%, and an expected dividend yield of 0%. The pro-forma net earnings (loss) reflects only options granted since October 1, 1995. Therefore, the full impact of calculating compensation cost for stock options under SFAS No. 123 is not reflected in the pro-forma earnings (loss) reported above because compensation cost is reflected over the options' vesting periods and compensation cost for options granted prior to October 1, 1995 is not considered. During the year ended September 30, 1999, options to acquire 12,500 shares and 5,000 shares of the Company's common stock with an exercise price per share of $13.625 and $22.250, respectively, expired. During the year ended September 30, 1998, options to acquire 1,500 shares and 5,000 shares of the Company's common stock with an exercise price per share of $13.625 and $22.250, respectively, were forfeited. Stock options at September 30, 2000 were as follows: Number of options --------------------------- Per share price Outstanding Exercisable Expiration Date --------------- ----------- ----------- --------------- $11.875 68,000 - December 2009 $13.063 29,000 - December 2004 $15.625 30,000 12,000 May 2008 $19.625 20,000 20,000 March 2005 ------- ------ Total 147,000 32,000 ======= ====== Weighted average exercise price $13.93 $18.13 ======= ====== Stock options at September 30, 1999 were as follows: Number of options --------------------------- Per share price Outstanding Exercisable Expiration Date --------------- ----------- ----------- --------------- $15.625 30,000 6,000 May 2008 $19.625 20,000 16,000 March 2005 ------ ------ Total 50,000 22,000 ====== ====== Weighted average exercise price $17.23 $18.53 ====== ====== Stock options at September 30, 1998 were as follows: Number of options --------------------------- Per share price Outstanding Exercisable Expiration Date --------------- ----------- ----------- --------------- $13.625 12,500 12,500 December 1998 $15.625 30,000 - May 2008 $19.625 20,000 12,000 March 2005 $22.250 5,000 5,000 May 1999 ------ ------ Total 67,500 29,500 ====== ====== Weighted average exercise price $16.93 $17.53 ====== ====== During the year ended September 30, 2000, the Company repurchased 6,000 shares of its common stock on the open market for $93,000 (average price of $15.50 per share) under a March 2000 stock buyback plan authorizing the repurchase of up to 100,000 shares. The Company plans to repurchase additional shares from time to time in the open market or in privately negotiated transactions, depending on market conditions. At September 30, 2000, the Company could purchase an additional 94,000 shares under the March 2000 repurchase authorization. 9. COMMITMENTS AND CONTINGENCIES ----------------------------- The Company is involved in routine litigation and is subject to governmental and regulatory controls that are incidental to the ordinary course of business. The Company's management believes that all claims and litigation involving the Company are not likely to have a material adverse effect on its financial statements taken as a whole. See also Note 4 (Investment in Land) of "Notes to Consolidated Financial Statements". The Company has committed to compensate its Vice President of Canadian Operations pursuant to an incentive compensation plan, the value of which directly relates to the Company's oil and natural gas segment's net income and the change in the value of the Company's oil and gas reserves since 1998 with adjustments for changes in natural gas and oil prices and subject to other terms and conditions. The Company recognized $290,000 of compensation costs pursuant to this incentive plan in fiscal 2000. The Company has several non-cancelable operating leases for office space and leasehold land. Rental expense was $406,000 in 2000, $427,000 in 1999, and $433,000 in 1998. The Company is committed under these leases for minimum rental payments summarized by fiscal year as follows: 2001 - $472,000, 2002 - $457,000, 2003 - $408,000, 2004 - $293,000, 2005 - $179,000, and thereafter through 2026 an aggregate of $1,330,000. The Company is contingently liable for the repayment of loans under a $650,000 loan facility, granted by a bank, to three participants in one of the Company's oil and natural gas ventures. At September 30, 2000, the loan balance was $250,000, $100,000 of which is to an affiliate of the Company. The three participants' interests in the venture are pledged as collateral to secure repayment of the loans. The Company believes the value of the collateral is significantly in excess of the loan balances. 10. WRITE-DOWN OF ASSETS -------------------- Under the full cost method of accounting, the amount of oil and natural gas properties' capitalized costs less accumulated depletion (on a country by country basis) is subject to a ceiling test limitation that requires any excess of such costs over the present value of estimated future cash flows from proved reserves to be expensed. As of March 31, 1998, the Company's investment in the development of natural gas and oil reserves in the Central Basin in Michigan was determined to be impaired and was transferred to the amortization base. Upon transfer, capitalized oil and natural gas properties' costs in the United States exceeded the full cost ceiling test limitation and, accordingly, the Company recorded a non-cash write-down of $2,070,000 in the quarter ended March 31, 1998. Due to further declines in oil prices and disappointing seismic and drilling results in North Dakota, the Company decided to abandon its U.S. oil and natural gas prospects and recorded an additional U.S. ceiling test write-down of $660,000 during the quarter ended June 30, 1998 to fully write-off its investment in U.S. oil and natural gas properties. In fiscal 1998, the Company also wrote down $170,000 of land and land improvement costs related to a contract drilling yard held for sale due to a decline in the market value of the property, and $95,000 of available-for-sale securities due to a decline in market value deemed other than temporary. There were no write-downs of oil and natural gas properties and other assets in fiscal years 2000 and 1999. 11. SEGMENT AND GEOGRAPHIC INFORMATION ---------------------------------- The Company operates three segments: exploring for, developing, producing and selling oil and natural gas in Canada; investing in leasehold land in Hawaii; and drilling wells and installing and repairing water pumping systems in Hawaii. The Company's reportable segments are strategic business units that offer different products and services. They are managed separately as each segment requires different operational methods, operational assets and marketing strategies, and operate in different geographical locations. The Company does not allocate general and administrative expenses, interest expense, interest income or income taxes to segments, and there are no transactions between segments that affect segment profit or loss. Year ended September 30, ----------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Revenues: Oil and natural gas $15,270,000 $10,130,000 $ 9,400,000 Contract drilling 3,520,000 4,230,000 1,510,000 Land investment 6,540,000 - - Other 891,000 668,000 920,000 ----------- ----------- ----------- Total before interest income 26,221,000 15,028,000 11,830,000 Interest income 349,000 132,000 90,000 ----------- ----------- ----------- Total revenues $26,570,000 $15,160,000 $11,920,000 =========== =========== =========== Depreciation, depletion and amortization: Oil and natural gas $ 3,121,000 $ 2,574,000 $ 2,698,000 Contract drilling 176,000 110,000 68,000 Other 275,000 136,000 132,000 ----------- ----------- ----------- Total $ 3,572,000 $ 2,820,000 $ 2,898,000 =========== =========== =========== Write-downs of oil and natural gas properties and other assets: Oil and natural gas $ - $ - $ 2,730,000 Contract drilling - - 170,000 Other - - 95,000 ----------- ----------- ----------- Total $ - $ - $ 2,995,000 =========== =========== =========== Operating profit (loss) (before general and administrative expenses): Oil and natural gas $ 9,021,000 $ 4,188,000 $ 749,000 Contract drilling 603,000 742,000 (550,000) Land investment, net of minority interest 3,232,000 - - Other 616,000 532,000 693,000 ----------- ----------- ----------- Total 13,472,000 5,462,000 892,000 General and administrative expenses (3,470,000) (3,187,000) (3,292,000) Foreign exchange losses (420,000) - - Interest expense (813,000) (809,000) (722,000) Interest income 349,000 132,000 90,000 ----------- ----------- ----------- Earnings (loss) before income taxes $ 9,118,000 $ 1,598,000 $(3,032,000) =========== =========== =========== Capital expenditures: Oil and natural gas $ 5,003,000 $ 1,753,000 $ 6,969,000 Contract drilling 393,000 121,000 91,000 Land investment 631,000 809,000 862,000 Other 222,000 148,000 205,000 ----------- ----------- ----------- Total $ 6,249,000 $ 2,831,000 $ 8,127,000 =========== =========== =========== Depletion per 1,000 cubic feet ("MCF") of natural gas and natural gas equivalent ("MCFE"), converted at a rate of one barrel of oil and natural gas liquids to 5.8 MCFE, was $0.60 in fiscal 2000, $0.48 in fiscal 1999 and $0.45 in fiscal 1998.
ASSETS BY SEGMENT: - ------------------ September 30, ---------------------------------------------------------- 2000 1999 1998 ---------------- ----------------- ---------------- Oil and natural gas (1) $25,686,000 66% $23,864,000 72% $23,959,000 76% Contract drilling (2) 1,925,000 5% 2,091,000 6% 1,576,000 5% Land investment (2) 3,975,000 10% 3,519,000 10% 2,710,000 8% Other: Cash 5,701,000 15% 2,577,000 8% 2,178,000 7% Corporate and other 1,373,000 4% 1,244,000 4% 1,238,000 4% ----------- ---- ----------- ---- ----------- ---- Total $38,660,000 100% $33,295,000 100% $31,661,000 100% =========== ==== =========== ==== =========== ==== (1) Primarily located in the Province of Alberta, Canada. (2) Located in Hawaii.
LONG-LIVED ASSETS BY GEOGRAPHIC AREA: - -------------------------------------
September 30, ---------------------------------------------------------- 2000 1999 1998 ---------------- ----------------- ---------------- United States $ 5,383,000 18% $ 4,720,000 17% $ 3,861,000 14% Canada 23,940,000 82% 22,771,000 83% 22,961,000 86% ----------- ---- ----------- ---- ----------- ---- Total $29,323,000 100% $27,491,000 100% $26,822,000 100% =========== ==== =========== ==== =========== ====
REVENUE BY GEOGRAPHIC AREA: - ---------------------------
Year ended September 30, -------------------------------------------- 2000 1999 1998 ----------- ----------- ----------- United States $10,175,000 $ 4,237,000 $ 1,690,000 Canada 16,046,000 10,791,000 10,140,000 ----------- ----------- ----------- Total (excluding interest income) $26,221,000 $15,028,000 $11,830,000 =========== =========== ===========
12. FAIR VALUE OF FINANCIAL INSTRUMENTS ----------------------------------- The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the short maturity of these instruments. The fair values of investment securities included in other assets are estimated based on quoted market prices for those or similar investments. The fair values of the Company's long-term debt are estimated based on the current terms offered for debt of the same or similar remaining maturities. The differences between the estimated fair values and carrying values of the Company's financial instruments are not material. 13. CONCENTRATIONS OF CREDIT RISK ----------------------------- The Company's oil and natural gas segment derived 63% of its oil and natural gas revenues in fiscal 2000 from three individually significant customers. At September 30, 2000, the Company had a total of $855,000 in receivables from three customers. In fiscal 1999, the Company derived 48% of its oil and natural gas revenues from three individually significant customers. In fiscal 1998, the Company derived 23% of its oil and natural gas revenues from one individually significant customer. The Company's contract drilling subsidiary derived 70%, 43%, and 42% of its contract drilling revenues in fiscal 2000, 1999, and 1998, respectively, pursuant to federal, State of Hawaii and local county contracts. At September 30, 2000, the Company had accounts receivables from the federal, State of Hawaii and local county entities totaling approximately $277,000. The Company has lien rights on contracts with the federal, State of Hawaii, local county and private entities. Historically, the Company has not incurred significant credit related losses on its trade receivables, and management does not believe significant credit risk related to these trade receivables exists at September 30, 2000. 14. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION ------------------------------------------------- The following details the effect of changes in current assets and liabilities on the consolidated statements of cash flows, and presents supplemental cash flow information:
Year ended September 30, ------------------------------------- 2000 1999 1998 ---------- ---------- --------- Increase (decrease) from changes in: Receivables $ 82,000 $ (140,000) $ 29,000 Costs and estimated earnings in excess of billings on uncompleted contracts (324,000) (60,000) (82,000) Inventories 25,000 (30,000) (6,000) Other current assets (233,000) (277,000) 223,000 Accounts payable (42,000) (1,017,000) (88,000) Accrued expenses 1,454,000 (25,000) 833,000 Billings in excess of costs and estimated earnings on uncompleted contracts 211,000 (62,000) 170,000 Payable to joint interest owners 148,000 384,000 (642,000) Income taxes payable 305,000 298,000 (3,000) ---------- ---------- --------- Increase (decrease) from changes in current assets and liabilities $1,626,000 $ (929,000) $ 434,000 ========== ========== ========= Supplemental disclosure of cash flow information: Cash paid during the year for: Interest (net of amounts capitalized) $ 848,000 $ 870,000 $ 616,000 ========== ========== ========= Income taxes $2,817,000 $ 497,000 $ 540,000 ========== ========== =========
15. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) --------------------------------------------------------- The following tables summarize information relative to the Company's oil and natural gas operations, which are substantially conducted in Canada. Proved reserves are the estimated quantities of crude oil, condensate and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed producing oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The estimated net interests in total proved developed and proved developed producing reserves are based upon subjective engineering judgments and may be affected by the limitations inherent in such estimations. The process of estimating reserves is subject to continual revision as additional information becomes available as a result of drilling, testing, reservoir studies and production history. There can be no assurance that such estimates will not be materially revised in subsequent periods. (A) Oil and Natural Gas Reserves ---------------------------- The following table, based on information prepared by independent petroleum engineers, Paddock Lindstrom and Associates, Ltd., summarizes changes in the estimates of the Company's net interests in total proved reserves of crude oil and condensate and natural gas ("MCF" means 1,000 cubic feet of natural gas) which are substantially all in Canada: OIL GAS Proved reserves: (Barrels) (MCF) --------- ---------- Balance at September 30, 1997 2,613,000 43,951,000 Revisions of previous estimates (100,000) (909,000) Extensions, discoveries and other additions 191,000 1,710,000 Less production (291,000) (4,145,000) Sales of reserves in place - (46,000) --------- ---------- Balance at September 30, 1998 2,413,000 40,561,000 Revisions of previous estimates 16,000 (550,000) Extensions, discoveries and other additions 9,000 502,000 Less production (300,000) (3,634,000) --------- ---------- Balance at September 30, 1999 2,138,000 36,879,000 Revisions of previous estimates (7,000) (300,000) Increase in royalty rates* (131,000) (5,699,000) Extensions, discoveries and other additions 72,000 2,417,000 Less production (291,000) (3,501,000) --------- ---------- Balance at September 30, 2000 1,781,000 29,796,000 ========= ========== * The deduction of reserve units due to higher royalty rates is the result of Alberta's royalties being calculated on a sliding scale basis, with the royalty percentage increasing as prices increase. The Province of Alberta takes its royalty share of production based on commodity prices; as all commodity prices were significantly higher at September 30, 2000, as compared to September 30, 1999, significantly more reserves were deducted for royalty volumes at September 30, 2000, as compared to September 30, 1999. OIL GAS Proved producing reserves at: (Barrels) (MCF) --------- ---------- September 30, 1997 2,087,000 29,483,000 ========= ========== September 30, 1998 2,109,000 28,306,000 ========= ========== September 30, 1999 1,759,000 25,908,000 ========= ========== September 30, 2000 1,508,000 20,594,000 ========= ========== (B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities ----------------------------------------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Proved properties $50,271,000 $46,966,000 $43,265,000 Unproved properties 2,191,000 1,968,000 2,205,000 ----------- ----------- ----------- Total capitalized costs 52,462,000 48,934,000 45,470,000 Accumulated depletion and depreciation 28,945,000 26,678,000 23,041,000 ----------- ----------- ----------- Net capitalized costs $23,517,000 $22,256,000 $22,429,000 =========== =========== =========== (C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration ----------------------------------------------------------------------- and Development --------------- Year ended September 30, ---------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Acquisition of properties: Unproved - Canadian $ 540,000 $ 125,000 $ 184,000 United States - - 85,000 ---------- ---------- ---------- $ 540,000 $ 125,000 $ 269,000 ========== ========== ========== Proved - Canadian $ - $ - $ 48,000 ========== ========== ========== Exploration costs: Canadian $ 813,000 $ 189,000 $1,299,000 United States 167,000 - 493,000 ---------- ---------- ---------- $ 980,000 $ 189,000 $1,792,000 ========== ========== ========== Development costs: Canadian $3,483,000 $1,439,000 $4,478,000 United States - - 382,000 ---------- ---------- ---------- $3,483,000 $1,439,000 $4,860,000 ========== ========== ========== (D) The Results of Operations of Barnwell's Oil and Natural Gas Producing --------------------------------------------------------------------- Activities ---------- Year ended September 30, ------------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Gross revenues: Canada $18,022,000 $11,231,000 $10,626,000 United States 103,000 - 132,000 ----------- ----------- ----------- Total gross revenues 18,125,000 11,231,000 10,758,000 Royalties, net of credit 2,855,000 1,101,000 1,358,000 ----------- ----------- ----------- Net revenues 15,270,000 10,130,000 9,400,000 Production costs 3,128,000 3,368,000 3,223,000 Depletion and depreciation 3,121,000 2,574,000 2,698,000 Write-down - - 2,730,000 ----------- ----------- ----------- Pre-tax results of operations* 9,021,000 4,188,000 749,000 Estimated income tax expense 4,271,000 2,124,000 1,886,000 ----------- ----------- ----------- Results of operations* $ 4,750,000 $ 2,064,000 $(1,137,000) =========== =========== =========== * Before general and administrative expenses, interest expense, and foreign exchange losses. (E) Standardized Measure, Including Year-to-Year Changes Therein, of Estimated -------------------------------------------------------------------------- Discounted Future Net Cash Flows -------------------------------- The following tables have been developed pursuant to procedures prescribed by SFAS 69, and utilize reserve and production data estimated by petroleum engineers. The information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Moreover, the projections should not be construed as realistic estimates of future cash flows, nor should the standardized measure be viewed as representing current value. The estimated future cash flows are based on sales prices, costs, and statutory income tax rates in existence at the dates of the projections. Material revisions to reserve estimates may occur in the future, development and production of the oil and natural gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred are expected to vary significantly from those used. Management does not rely upon this information in making investment and operating decisions; rather, those decisions are based upon a wide range of factors, including estimates of probable reserves as well as proved reserves and price and cost assumptions different than those reflected herein. Standardized Measure of Estimated Discounted Future Net Cash Flows - ------------------------------------------------------------------ As of September 30, ---------------------------------------------- 2000 1999 1998 ------------ ------------ ------------ Future cash inflows $159,328,000 $108,463,000 $ 83,827,000 Future production costs (32,309,000) (33,680,000) (30,052,000) Future development costs (1,397,000) (1,268,000) (1,372,000) ------------ ------------ ------------ Future net cash flows before income taxes 125,622,000 73,515,000 52,403,000 Future income tax expenses (51,516,000) (24,914,000) (15,379,000) ------------ ------------ ------------ Future net cash flows 74,106,000 48,601,000 37,024,000 10% annual discount for timing of cash flows (31,606,000) (19,844,000) (14,351,000) ------------ ------------ ------------ Standardized measure of estimated discounted future net cash flows $ 42,500,000 $ 28,757,000 $ 22,673,000 ============ ============ ============ Changes in the Standardized Measure of Estimated Discounted Future Net Cash - --------------------------------------------------------------------------- Flows - ----- Year ended September 30, --------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Beginning of year $28,757,000 $22,673,000 $27,982,000 ----------- ----------- ----------- Sales of oil and natural gas produced, net of production costs (12,142,000) (6,762,000) (6,177,000) Net changes in prices and production costs, net of royalties and wellhead taxes 33,265,000 13,452,000 (2,295,000) Extensions and discoveries 6,132,000 561,000 1,650,000 Revisions of previous quantity estimates 38,000 (52,000) (1,153,000) Net change in Canadian dollar translation rate (358,000) 864,000 (2,744,000) Changes in the timing of future production and other (1,755,000) (851,000) 447,000 Net change in income taxes (14,166,000) (3,465,000) 2,417,000 Accretion of discount 2,729,000 2,337,000 2,546,000 ----------- ----------- ----------- Net change 13,743,000 6,084,000 (5,309,000) ----------- ----------- ----------- End of year $42,500,000 $28,757,000 $22,673,000 =========== =========== =========== Item 8. Changes in and Disagreements with Accountants on Accounting and ---------------------------------------------------------------- Financial Disclosure -------------------- None. PART III Item 9. Directors, Executive Officers, Promoters and Control Persons, ------------------------------------------------------------- Compliance With Section 16(a) of the Exchange Act ------------------------------------------------- Item 10. Executive Compensation ---------------------- Item 11. Security Ownership of Certain Beneficial Owners and Management -------------------------------------------------------------- Item 12. Certain Relationships and Related Transactions ---------------------------------------------- Items 9, 10, 11, and 12 are omitted pursuant to General Instructions E.3. of Form 10-KSB, since the Registrant will file its definitive proxy statement for the 2001 Annual Meeting of Stockholders not later than 120 days after the close of its fiscal year ended September 30, 2000, which proxy statement is incorporated herein by reference. Item 13. Exhibits, List and Reports on Form 8-K -------------------------------------- (A) Financial Statements The following consolidated financial statements of Barnwell Industries, Inc. and its subsidiaries are included in Part II, Item 7: Independent Auditors' Report - KPMG LLP Consolidated Balance Sheets - September 30, 2000 and 1999 Consolidated Statements of Operations - for the three years ended September 30, 2000 Consolidated Statements of Cash Flows - for the three years ended September 30, 2000 Consolidated Statements of Stockholders' Equity and Comprehensive Income (Loss) - for the three years ended September 30, 2000 Notes to Consolidated Financial Statements Schedules have been omitted because they were not applicable, not required, or the information is included in the consolidated financial statements or notes thereto. (B) Reports on Form 8-K There were no reports on Form 8-K filed during the three months ended September 30, 2000. (C) Exhibits No. 3.1 Certificate of Incorporation(1) No. 3.2 Amended and Restated By-Laws(1) No. 4.0 Form of the Registrant's certificate of common stock, par value $.50 per share.(2) No. 10.1 The Barnwell Industries, Inc. Employees' Pension Plan (restated as of October 1, 1989).(3) No. 10.2 Phase I Makai Development Agreement dated June 30, 1992, by and between Kaupulehu Makai Venture and Kaupulehu Developments. (4) No. 10.3 KD/KMV Agreement dated June 30, 1992 by and between Kaupulehu Makai Venture and Kaupulehu Developments.(4) No. 10.4 Barnwell Industries, Inc.'s letter to Warren D. Steckley dated May 6, 1998, regarding certain terms of employment. No. 21 List of Subsidiaries.(5) No. 27 Financial Data Schedule (for SEC use only) - ----------------------------- (1) Incorporated by reference to the Registrant's Form S-8 dated November 8, 1991. (2) Incorporated by reference to the registration statement on Form S-1 originally filed by the Registrant January 29, 1957 and as amended February 15, 1957 and February 19, 1957. (3) Incorporated by reference to Form 10-K for the year ended September 30, 1989. (4) Incorporated by reference to Form 10-K for the year ended September 30, 1992. (5) Incorporated by reference to Form 10-KSB for the year ended September 30, 1998. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BARNWELL INDUSTRIES, INC. (Registrant) /s/Russell M. Gifford - ----------------------------------- By: Russell M. Gifford Chief Financial Officer, Executive Vice President and Treasurer Date: December 1, 2000 Pursuant to the requirements of the Securities Exchange Act of 1934, the report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated. /s/Morton H. Kinzler - ------------------------ MORTON H. KINZLER Chief Executive Officer, President and Chairman of the Board Date: December 1, 2000 /s/Martin Anderson /s/Daniel Jacobson - ------------------------- ------------------------- MARTIN ANDERSON, Director DANIEL JACOBSON, Director Date: December 1, 2000 Date: December 1, 2000 /s/Murray C. Gardner /s/Terry Johnston - --------------------------- ------------------------ MURRAY C. GARDNER, Director TERRY JOHNSTON, Director Date: December 1, 2000 Date: December 1, 2000 /s/Erik Hazelhoff-Roelfzema /s/Alexander C. Kinzler - --------------------------------- ------------------------------ ERIK HAZELHOFF-ROELFZEMA, Director ALEXANDER C. KINZLER Date: December 1, 2000 Executive Vice President, Secretary and Director /s/Alan D. Hunter Date: December 1, 2000 - ------------------------ ALAN D. HUNTER, Director Date: December 1, 2000 /s/Glenn Yago ------------------- GLENN YAGO, Director Date: December 1, 2000 EX-10.4 2 0002.txt WARREN D. STECKLEY EMPLOYMENT TERMS May 6, 1998 Mr. Warren Steckley 216 Sunmount Bay S.E. Calgary, Alberta, Canada T2X 2M8 Dear Mr. Steckley: This letter will serve to memorialize our discussions regarding your acceptance of our offer to enter into the employment of Barnwell of Canada, Limited ("BOC"). The terms of your employment will be as follows, in accordance with our discussions; all dollar amounts in this letter are in Canadian dollars: Start: June 1, 1998 ("Start Date") Position: Executive Vice President and Chief Operating Officer of BOC Annual Salary: $150,000 Annual Bonus: A guaranteed minimum bonus of $30,000 for the first full fiscal year of employment. Stock Options: 1. 30,000 options to acquire Barnwell Industries, Inc. common stock to be granted at market price as of the Start Date pursuant to action by Barnwell Industries, Inc.'s Board of Directors. These options will be in the normal form used by Barnwell, have a ten year term and vest over a five year period at 6,000 shares per year on the anniversary of their grant date. 2. 30,000 "phantom" options in BOC common stock tied to BOC's book value in accordance with a summary sheet provided to you on April 30, 1998. The final terms of such phantom options will be agreed upon between you and BOC on or about your Start Date. These options will have a ten year term and vest over a five year period at 6,000 shares per year on the anniversary of their grant date. Other perquisites of your position, including the use of a company car, a Petroleum Club membership and basic terms of our vacation, medical and related employment policies will be discussed with you upon your entering into employment with BOC. We are very pleased that you have accepted our offer for employment and we have great confidence in your experience and abilities. We look forward to your having a long and successful career with us. Very truly yours, /s/ Morton H. Kinzler Morton H. Kinzler Chairman, President and CEO Barnwell of Canada, Limited Chairman, President and CEO Barnwell Industries, Inc. cc: Russell M. Gifford Alexander C. Kinzler EX-27 3 0003.txt BARNWELL INDUSTRIES, INC. 2000 10KSB EX-27
5 This schedule contains summary financial information extracted from Barnwell Industries, Inc.'s 9/30/2000 10-KSB and is qualified in its entirety by reference to such 10-KSB filing. 1000 YEAR SEP-30-2000 SEP-30-2000 5701 0 2172 154 81 9121 60882 35534 38660 7387 9133 0 0 821 11853 38660 25330 26570 5869 5869 3572 (42) 813 9118 4108 5010 0 0 0 5010 3.81 3.67
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