U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-KSB

ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended September 30, 2003

o		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 incorporation or organization)		(I.R.S. Employer Identification No.)

1100 Alakea Street, Suite 2900, Honolulu, Hawaii 96813-2833
(Address of principal executive offices)		(Zip code)

(808) 531-8400
(Issuer’s telephone number)

Securities registered under Section 12(b) of the Exchange Act:

Title of each class		Name of each exchange on which registered
Common Stock, par value $0.50 per share		American Stock Exchange Toronto Stock Exchange

Securities registered under Section 12(g) of the Exchange Act: None

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ý No o

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. ý

Issuer’s revenues for the fiscal year ended September 30, 2003: $23,680,000

The aggregate market value of the voting stock held by non-affiliates (640,797 shares) of the Registrant on December 23, 2003, based on the closing price of $32.00 on that date on the American Stock Exchange, was $20,506,000.

As of December 23, 2003 there were 1,314,510 shares of common stock, par value $0.50, outstanding.

Documents Incorporated by Reference

1. Proxy statement to be forwarded to shareholders on or about January 22, 2004 is incorporated by reference in Part III hereof.

Transitional Small Business Disclosure Format Yes o No ý

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
	Corporate Office
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
	Results of Operations
	Liquidity and Capital Resources
Item 7.	Financial Statements
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 8A.	Controls and Procedures
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
Item 14.	Principal Accountant Fees and Services

PART I

Forward-Looking Statements

This Form 10-KSB, and the documents incorporated herein by reference, contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, 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”) future performance, statements of Barnwell’s plans and objectives and other similar types of information. Although Barnwell 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 Barnwell 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 Barnwell expressly disclaims any obligation or undertaking to publicly release any updates or revisions to any forward-looking statements contained herein.

Barnwell’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 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 other petroleum products, may also have a significant effect on Barnwell’s oil and natural gas operations. While Barnwell maintains reserves for anticipated liabilities and carries various levels of insurance, Barnwell could be affected by civil, criminal, regulatory or administrative actions, claims or proceedings. In addition, climate and weather can significantly affect Barnwell in several of its operations. Barnwell’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. Costs of compliance with environmental laws are ingrained in Barnwell’s expenses and not distinguished from other costs and expenses.

Barnwell’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 Barnwell’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 confidence in Hawaii’s economy.

Barnwell’s contract drilling operations, which are located in Hawaii, are also indirectly affected by the factors discussed in the preceding paragraph. Barnwell’s contract drilling operations are

materially dependent upon levels of land development activity 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 Barnwell’s contract drilling services. Such a decline could have a material adverse effect on Barnwell’s contract drilling revenues and profitability.

Item 1. Description of Business

(a) General Development of Business

Barnwell was incorporated in Delaware in 1956. During its last three fiscal years, Barnwell was engaged in 1) oil and natural gas exploration, development, production and sales primarily in Canada (oil and natural gas segment), 2) investment in leasehold land in Hawaii (land investment segment), and 3) water and exploratory well drilling, contract labor servicing for geothermal well drilling and workovers, and water pumping system installation and repair in Hawaii (contract drilling segment).

Barnwell’s oil and natural gas activities comprise its largest business segment. Approximately 82% of Barnwell’s revenues for the fiscal year ended September 30, 2003 were attributable to its oil and natural gas activities. Barnwell’s contract drilling activities accounted for 9% of Barnwell’s revenues in fiscal 2003, land investment activities comprised 5% of fiscal 2003 revenues, and gas processing and other revenues comprised 4% of fiscal 2003 revenues. Approximately 98% of Barnwell’s capital expenditures for the fiscal year ended September 30, 2003 were attributable to oil and natural gas activities and 2% were applicable to other activities.

(i) Oil and Natural Gas Activities. Barnwell’s wholly-owned subsidiary, Barnwell of Canada, Limited, is involved in the acquisition, exploration and development of oil and natural gas properties, principally in Alberta, Canada. Barnwell of Canada, Limited initiates and 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. Barnwell’s oil and natural gas segment received 64% of its oil and natural gas revenues in fiscal 2003 from four individually significant customers, ProGas Limited, Coral Energy Canada Inc., Plains Marketing Canada, L.P., and Petrogas Marketing Ltd.

(ii) Contract Drilling. Barnwell’s wholly-owned subsidiary, Water Resources International, Inc., drills water, geothermal and exploratory wells and installs and repairs water pumping systems in Hawaii. Water Resources International, Inc. owns and operates four rotary drill rigs, pump installation and service equipment, leases one rotary drill/workover rig to an oil company, and maintains drilling materials and pump inventory in Hawaii. Water Resources International, Inc.’s contracts are usually fixed price per lineal foot drilled or day rate contracts that are either negotiated with private entities or are obtained through competitive bidding with various private entities or local, state and federal agencies. Barnwell’s contract drilling subsidiary derived 66%, 70% and 49% of its contract drilling revenues in fiscal 2003, 2002 and 2001, respectively, pursuant to Federal, State of Hawaii and county contracts.

(iii) Land Investment. Barnwell owns a 77.6% controlling interest in Kaupulehu Developments, a Hawaii general partnership which owns interests in leasehold land and development rights for property located approximately six miles north of the Kona International Airport in the North

Kona District of the Island of Hawaii. 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, and single and multiple family residential units. These projects were developed on leasehold land acquired from Kaupulehu Developments by Kaupulehu Makai Venture, an unrelated entity that is an affiliate of Kajima Corporation of Japan. Kaupulehu Developments later obtained the state and county zoning changes necessary to permit development of single and multi-family residential units, a golf course and a limited commercial area on approximately 870 leasehold acres located adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka’upulehu.

Kaupulehu Developments currently owns the leasehold rights in these approximately 870 acres and leasehold rights in another approximately 1,000 acres of conservation-zoned land, located adjacent to and contiguous with the 870 acres. Kaupulehu Developments also owns development rights in residentially zoned leasehold land adjacent to and interspersed within the Hualalai Golf Club golf course and the second golf course currently under construction. The development rights are under option to Kaupulehu Makai Venture, the owner of the Four Seasons Resort Hualalai at Historic Ka’upulehu.

(b) Financial Information about Industry Segments

Revenues of each industry segment for the fiscal years ended September 30, 2003, 2002 and 2001 are summarized as follows (all revenues were from unaffiliated customers with no intersegment sales or transfers):

	2003				2002				2001
Oil and natural gas	$	19,350,000	82	%	$	11,320,000	71	%	$	19,870,000	82	%
Contract drilling	2,050,000		9	%	3,480,000		22	%	3,290,000		14	%
Land investment	1,220,000		5	%	220,000		1	%	—		—
Other	720,000		3	%	598,000		4	%	601,000		3	%
Revenues from segments	23,340,000		99	%	15,618,000		98	%	23,761,000		99	%
Interest income	340,000		1	%	262,000		2	%	329,000		1	%
Total revenues	$	23,680,000	100	%	$	15,880,000	100	%	$	24,090,000	100	%

For further discussion see Note 12 (SEGMENT AND GEOGRAPHIC INFORMATION) and Note 14 (CONCENTRATIONS OF CREDIT RISK) of “Notes to Consolidated Financial Statements” in Item 7.

See the table above in Item 1(b) detailing revenue of each industry segment and description of each industry segment of Barnwell’s business under Item 2.

As of September 30, 2003, Barnwell employed 37 employees, 35 of which are on a full-time basis. Ten are employed in contract drilling activities, 16 are employed in oil and natural gas activities, and 11 are members of the corporate and administrative staff.

For further discussion see the “Governmental Regulation” section and the “Competition” section 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, 2003, 2002 and 2001 are set forth in Note 12 (SEGMENT AND GEOGRAPHIC INFORMATION) of “Notes to Consolidated Financial Statements” in Item 7.

Item 2. Description of Property

OIL AND NATURAL GAS OPERATIONS

General

Barnwell’s investments in oil and natural gas properties consist of investments in Canada, principally in the Province of Alberta, with minor holdings in Saskatchewan and British Columbia. 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 initiates and participates in exploratory and developmental operations for oil and natural gas on property in which it has an interest. Barnwell 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 2003, Barnwell participated in exploratory and developmental operations in the Canadian Provinces of Alberta and Saskatchewan, 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 number 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 2003, the weighted average rate of all royalties paid to governments and others on natural gas from the Dunvegan Unit, Barnwell’s principal oil and natural gas property, before the Alberta Royalty Tax Credit, was approximately 31%. The weighted average rate of royalties paid on all of Barnwell’s natural gas was approximately 28% in fiscal 2003, versus approximately 26% in fiscal 2002. The increase in the weighted average royalty rate was primarily due to higher average annual gas prices in fiscal 2003, as compared to fiscal 2002.

In fiscal 2003, virtually all of Barnwell’s oil production was from properties located in Alberta. The Province of Alberta determines its royalty share of oil by using a reference price that averages all oil sales in Alberta. Royalty rates are calculated on a sliding scale basis, increasing as prices increase. Additionally, Barnwell pays gross overriding royalties and leasehold royalties on a portion of its oil sales to parties other than the Province of Alberta. In fiscal 2003 and 2002, the weighted average royalty rate paid on oil was approximately 24% and 25%, respectively. The decrease in the weighted average royalty rate on oil was primarily due to lower royalty rates on new oil production.

Prices of natural gas are typically higher in the winter than at other times due to demand for heating. Prices of oil are also subject to seasonal fluctuations, but to a lesser degree. Unit sales of oil and natural gas are based on the quantity produced from the properties by the operator based on sound petroleum practices and applicable rules and regulations. During periods of low demand for natural gas, the operator of the Dunvegan property may re-inject natural gas into underground storage facilities for delivery at a future date.

Well Drilling Activities

During fiscal 2003, Barnwell participated in the drilling of 52 gross development wells and 13 gross exploratory wells, of which management believes 53 should be capable of production. Barnwell also participated in the recompletion of ten gross wells. The most significant drilling operations took place in the Bonanza, Leduc, Dunvegan, Progress, Pouce Coupe South and Bashaw areas. New drilling operations took place in the Armada, Bashaw, Bonanza, Doris, Pine Creek, and Pouce Coupe South areas.

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, 2003, 2002 and 2001 in which Barnwell participated:

	Productive Oil Wells		Productive Gas Wells		Total Productive Wells		Dry Holes		Total Wells
	Exp.	Dev.	Exp.	Dev.	Exp.	Dev.	Exp.	Dev.	Exp.	Dev.
2003
Gross*	—	5.0	8.0	40.0	8.0	45.0	5.0	7.0	13.0	52.0
Net*	—	1.5	2.1	7.5	2.1	9.0	1.5	2.1	3.6	11.1

2002
Gross*	3.0	3.0	1.0	5.0	4.0	8.0	1.0	3.0	5.0	11.0
Net*	0.6	1.1	0.2	2.3	0.8	3.4	0.1	1.1	0.9	4.5

2001
Gross*	—	11.0	1.0	11.0	1.0	22.0	3.0	4.0	4.0	26.0
Net*	—	1.5	0.2	1.5	0.2	3.0	1.2	1.4	1.4	4.4

* 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 0.5 net well. The gross figure includes interests owned of record by Barnwell and, in addition, the portion owned by others.

The Dunvegan Unit, in which Barnwell holds an 8.9% interest, is Barnwell’s principal oil and natural gas property and is located in Alberta, Canada. The Dunvegan Unit has 130 natural gas wells producing from 130 well zones. In fiscal 2003, Barnwell participated in the drilling of twelve gross (1.1 net) development gas wells and recompletion of 5 gas wells (0.4 net wells) in the Dunvegan area. While these new wells did not add to Barnwell’s proved reserves, they are expected to increase the rate of future production from the area. Total capital expenditures at Dunvegan were $1,223,000 in fiscal 2003 as compared to $325,000 and $696,000 in fiscal 2002 and 2001, respectively.

Capital expenditures totaled $1,552,000 in the Bonanza area, a new area for Barnwell, where three gross wells (1.4 net wells) were drilled in fiscal 2003. All three wells were tied in and producing at September 30, 2003.

In the Leduc area, Barnwell drilled three gross successful wells (0.8 net wells) and acquired one gross (0.3 net) well, all of which were producing at September 30, 2003. Capital expenditures in the Leduc area totaled $1,483,000 in fiscal 2003.

In the Progress area, where capital expenditures totaled $1,069,000 in fiscal 2003, one unsuccessful well was drilled and Barnwell made significant investments in acquiring leases and seismic data.

In the Pouce Coupe South area, where capital expenditures totaled $692,000 in fiscal 2003, Barnwell drilled two successful gross wells (one net well), one of which was producing as of September 30, 2003; the other is expected to be placed in production in early fiscal 2004.

Capital expenditures totaled $409,000 in fiscal 2003 in the Bashaw area, a new area. Barnwell participated in drilling one gross (0.4 net) well, a successful gas well which began producing in March 2003, and one gross (0.4 net) well which was dry and abandoned.

Barnwell’s average net interest in wells drilled in fiscal 2003 was approximately 23%, as compared to 34% in fiscal 2002 and 19% in fiscal 2001. The decrease in fiscal 2003, as compared to fiscal 2002, was due principally to drilling programs at Dunvegan, 12 gross (1.1 net) wells, and Hatton, Saskatchewan, 13 gross (2.0 net) wells, for a total of 25 gross (3.1 net) wells or an average net well interest of 12.4% for these two drilling programs. The average net interest in all other wells drilled in fiscal 2003 was 29%. Of the wells drilled in fiscal 2003, 32 were on prospects developed by Barnwell.

Oil and Natural Gas Production

The following table summarizes (a) Barnwell’s net unit 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. Barnwell’s net production in fiscal 2003, 2002 and 2001 was derived primarily from the Province of Alberta. All dollar amounts in this table are in U.S. dollars.

	Year Ended September 30,
	2003		2002		2001
Annual net production:
Natural gas liquids (BBLS)*	85,000		94,000		98,000
Oil (BBLS)*	142,000		148,000		174,000
Natural gas (MCF)*	3,175,000		3,277,000		3,269,000

Annual average sale price per unit of production:
BBL of liquids**	$	21.50	$	12.46	$	22.60
BBL of oil**	$	27.69	$	21.28	$	25.44
MCF of natural gas**	$	4.27	$	2.12	$	4.02

Annual average production cost per MCFE produced***	$	0.93	$	0.66	$	0.72

Annual average depletion cost per MCFE produced***	$	0.90	$	0.71	$	0.70

* When used in this report, the term “BBL(S)” means stock tank barrel(s) of oil equivalent to 42 U.S. gallons and the term “MCF” means 1,000 cubic feet of natural gas at 14.65 pounds per square inch absolute and 60 degrees F.

** 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 1 BBL = 5.8 MCF.

In fiscal 2003, approximately 71%, 20% and 9% of Barnwell’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 2003, Barnwell’s net production after royalties for natural gas averaged 8,700 MCF per day, a decrease of 3% from 8,980 MCF per day in fiscal 2002. Gross natural gas production remained constant, while, on a net basis, natural gas production decreased due to an increase in royalty rates attributable to increased natural gas prices. Dunvegan contributed approximately 43% of Barnwell’s net natural gas production in fiscal 2003.

Barnwell’s major oil producing properties are the Red Earth, Chauvin and Manyberries areas in Canada. In fiscal 2003, net production after royalties for oil averaged 390 barrels per day, a decrease of 3% from 400 barrels per day in fiscal 2002. This decrease was due to natural declines in production from certain of Barnwell’s older oil properties, which was partially offset by new production at Wizard Lake, Bonanza and Boundary Lake.

In fiscal 2003, net production after royalties for natural gas liquids averaged 230 barrels per day, a decrease of 12% from 260 barrels per day in fiscal 2002. This decrease was due primarily to a fire in early October 2002 at a Dunvegan gas plant that prevented stripping of natural gas liquids from the natural gas, resulting in an approximately 6,000 barrel decline in liquids net production in fiscal 2003. Barnwell did, however, receive a higher price for its natural gas than it would have if the liquids had

been removed, thereby mitigating some of the impact of the liquids production decline. The damage to the gas plant was repaired and the plant resumed operations in late December 2002.

The average production cost per MCFE was $0.93 for fiscal 2003, a 41% increase from $0.66 for fiscal 2002. The increase is due partly to an oil and natural gas operating expense credit for overcharges of operating expenses for fiscal years 1998 through 2001 from the operator of the Dunvegan property totaling $470,000 which was received in fiscal 2002. The increase was also attributable to higher well repair and maintenance, electricity, fuel, insurance, and general maintenance costs.

In fiscal 2002, approximately 62%, 28% and 10% of Barnwell’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 2001, approximately 66%, 23% and 11% of Barnwell’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 2002, Barnwell’s net production after royalties for natural gas averaged 8,980 MCF per day, comparable to 8,950 MCF per day in fiscal 2001. Gross natural gas production declined 5% as natural declines in gas production at Barnwell’s more mature properties and the watering out of wells at Sunnynook and Pembina were only partially offset by recent development and new production from the Progress and Pollockville areas. However, natural gas production was relatively unchanged on a net basis due to a decrease in royalties attributable to decreased natural gas prices. Dunvegan contributed approximately 47% of Barnwell’s net natural gas production in fiscal 2002.

In fiscal 2002, net production after royalties for oil averaged 400 barrels per day, a decrease of 17% from 480 barrels per day in fiscal 2001. This decrease was due to natural declines in production from certain of Barnwell’s older oil properties.

In fiscal 2002, net production after royalties for natural gas liquids averaged 260 barrels per day, a decrease of 4% from 270 barrels per day in fiscal 2001. This decrease was due to declines in production from the Dunvegan and Pembina areas.

The following table sets forth the gross and net number of productive wells Barnwell has an interest in as of September 30, 2003.

Productive Wells

	Productive Wells*
	Gross**		Net**
Location	Oil	Gas	Oil	Gas
Canada
Alberta	175	470	29.0	51.9
Saskatchewan	2	26	0.2	4.3
British Columbia	—	1	—	0.5
Total	177	497	29.2	56.7

* 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, 2003:

	Developed Acreage(1)		Undeveloped Acreage(1)		Developed and Undeveloped Acreage(1)
Location	Gross(2)	Net(2)	Gross(2)	Net(2)	Gross(2)	Net(2)
Canada
Alberta	250,832	35,670	152,831	39,717	403,663	75,387
British Columbia	1,753	555	4,401	1,653	6,154	2,208
Saskatchewan	3,336	530	—	—	3,336	530
Total	255,921	36,755	157,232	41,370	413,153	78,125

(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” also refers to the total number of acres in which Barnwell owns an interest, and “Net” refers to Barnwell’s aggregate interest therein. For example, a 50% interest in a 320 acre lease represents 320 Gross Acres and 160 Net Acres. The 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 expire over the next five fiscal years, if not developed, as follows: 18% expire during fiscal 2004; 5% expire during fiscal 2005; 11% expire during fiscal 2006; 15% expire during fiscal 2007 and 51% expire during fiscal 2008. There can be no assurance that Barnwell will be successful in renewing its leasehold interests in the event of expiration.

Barnwell’s undeveloped acreage includes major concentrations in Alberta, at Thornbury (5,842 net acres), Swalwell (4,045 net acres), Red Earth (2,411 net acres), Pouce Coupe South (1,920 net acres), Gere (1,676 net acres), Bonanza (1,520 net acres), Foley Lake (1,200 net acres), and Progress (1,120 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, 2003, 2002 and 2001 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, 2001.

Proved Producing Reserves

	September 30,
	2003	2002	2001
Oil – barrels (BBLS) (including condensate and natural gas liquids)	1,262,000	1,303,000	1,327,000
Natural gas – thousand cubic feet (MCF)	21,463,000	19,612,000	21,847,000

Total Proved Reserves

(Includes Proved Producing Reserves)

	September 30,
	2003	2002	2001
Oil – barrels (BBLS) (including condensate and natural gas liquids)	1,401,000	1,527,000	1,536,000
Natural gas – thousand cubic feet (MCF)	27,639,000	27,166,000	28,371,000

As of September 30, 2003, 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 2003, Barnwell’s total net proved reserves, including proved producing reserves, of oil, condensate and natural gas liquids decreased by 126,000 barrels, and total net proved reserves of natural gas increased by 473,000 MCF. The change in oil, condensate and natural gas liquids reserves was the net result of production during the year of 227,000 barrels, the addition of 136,000 barrels from the drilling of productive wells, and the independent engineer’s 35,000 barrel downward revision of Barnwell’s oil reserves. The change in natural gas reserves was the net result of production during the year of 3,175,000 MCF, the addition of 4,683,000 MCF from the drilling of productive natural gas wells, and the independent engineer’s 1,035,000 MCF downward revision of Barnwell’s natural gas reserves.

Barnwell’s working interest in the Dunvegan area accounted for approximately 58% and 66% of its total proved natural gas reserves at September 30, 2003 and 2002, respectively, and approximately 40% and 41% of total proved oil and condensate reserves at September 30, 2003 and 2002, respectively.

The following table sets forth Barnwell’s oil and natural gas reserves at September 30, 2003, by property name, based on information prepared by Paddock Lindstrom & Associates Ltd. 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, 2003

	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	663	479	16,980	13,598	784	559	20,171	16,095
Red Earth	446	393	30	30	469	412	30	30
Pouce Coupe	14	11	1,537	1,221	18	14	2,578	2,030
Thornbury	—	—	1,249	1,041	—	—	1,496	1,254
Hillsdown	18	13	738	589	36	28	904	724
Medicine River	58	42	1,192	750	58	42	1,192	750
Armada	—	—	—	—	—	—	48	45
Barrhead	—	—	237	268	—	—	237	268
Bashaw	2	1	79	52	2	1	79	52
Belloy	—	—	102	78	—	—	153	119
Bonanza	53	42	813	624	53	42	813	624
Charlotte Lake	—	—	302	275	—	—	703	619
Chauvin	153	135	15	13	153	135	15	13
Clive	—	—	7	7	—	—	7	7
Coyote	—	—	—	11	—	—	—	11
Doris	—	—	—	—	—	—	442	340
Drumheller	—	—	59	49	—	—	59	49
Faith South	—	—	—	—	—	—	1,011	792
Gilby	7	5	121	105	7	5	121	105
Highvale	6	5	2	2	6	5	2	2
Hilda	—	—	59	56	—	—	59	56
Leduc	24	17	1,036	800	24	17	1,092	850
Malmo	1	1	28	27	1	1	28	27
Manyberries	15	14	3	2	15	14	3	2
Mikwan	—	—	17	15	—	—	17	15
Mitsue	—	—	47	41	—	—	47	41
Pembina	36	28	370	312	36	28	370	312
Pine Creek, Alberta	—	—	218	154	—	—	218	154
Pollockville	—	—	244	151	—	—	244	151
Progress	10	7	1,036	768	10	7	1,036	768
Staplehurst	15	13	—	—	16	14	—	—
Wizard Lake	48	40	21	17	48	40	21	17
Wood River	7	7	233	205	7	7	1,008	819
Zama	8	7	120	81	10	9	404	275
Rigel, British Columbia	—	—	10	8	—	—	10	8
Boundary Lake, British Columbia	—	—	—	—	19	19	108	102
Hatton, Saskatchewan	—	—	158	113	—	—	158	113
Webb-Beverley, Saskatchewan	2	2	—	—	2	2	—	—
TOTAL	1,586	1,262	27,063	21,463	1,774	1,401	34,884	27,639

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 Reserves		Total Proved Reserves
Year ending September 30,

2004	$	9,978,000	$	10,582,000
2005	8,658,000		9,972,000
2006	7,250,000		8,358,000
Thereafter	34,320,000		41,623,000
	$	60,206,000	$	70,535,000

Present value (discounted at 10%) at September 30, 2003	$	42,282,000	$	49,537,000

Marketing of Oil and Natural Gas

Barnwell sells substantially all of its oil and condensate production under short-term contracts between itself and marketers of oil. The price of oil is freely negotiated between the buyers and sellers.

Natural gas sold by Barnwell 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 2003, 2002 and 2001, Barnwell took virtually all of its oil and natural gas “in kind” where Barnwell markets the products instead of having the operator of a producing property market the products on Barnwell’s behalf.

In fiscal 2003, natural gas production from the Dunvegan Unit was responsible for approximately 41% of Barnwell’s natural gas revenues, as compared to 45% in fiscal 2002. In fiscal 2003, Barnwell had four individually significant customers that accounted for 64% of Barnwell’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 2003, Barnwell continued to increase the volumes of natural gas sold into spot markets, reaching approximately 46% of natural gas volumes, 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 Barnwell’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 provincial governments, the Government of Canada and private interests with respect to the production and sale of crude oil, natural gas and liquids. In addition, provincial governments 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.

In fiscal 2001 and 2002, Canadian taxpayers were 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 were allowed to deduct a “Resource Allowance” which is 25% of the taxpayer’s “Resource Profits for the Year” (essentially, net income from the production of oil, natural gas or minerals) in computing their taxable income.

In October 2003, the Parliament of Canada held first and second readings on a bill to reduce Canada’s corporate tax rate on “resource” income (income derived from oil and natural gas operations) over a four-year period beginning January 1, 2003 from 29% to 21% beginning January 1, 2007. Additionally, the bill phases in over the same four-year period tax deductions for royalties, which previously were not tax deductible, and phases out the Resource Allowance deduction along with other changes. In November 2003, the bill passed on third reading, received Royal Assent and was enacted into law. The reduction in the tax will reduce Barnwell’s deferred income tax liabilities by approximately $1,500,000 in the quarter ending December 31, 2003, Barnwell’s fiscal 2004 first quarter.

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 program. The Alberta Royalty Tax Credit rate is based on a price-sensitive formula and varies between 75% at prices below a specified royalty tax credit reference price and 25% at prices above a specified royalty tax credit reference price. The Alberta

Royalty Tax Credit 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 Alberta Royalty Tax Credit will generally not be eligible for Alberta Royalty Tax Credit. 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 Alberta Royalty Tax Credit will be announced three years in advance. The government of Alberta has considered limiting the Alberta Royalty Tax Credit on some basis, as yet undetermined, to entities that invest in oil and natural gas in Alberta. Barnwell currently does such investing. The Alberta Royalty Tax Credit program has been in effect in various forms since 1974 and Barnwell anticipates that it will be continued in some form for the foreseeable future. In fiscal 2003, Barnwell’s Alberta Royalty Tax Credit totaled approximately $342,000. If the Alberta Royalty Tax Credit is not continued, it will have an adverse effect on Barnwell.

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.

Barnwell 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. which drills water and exploratory wells and installs and repairs water pumping systems in Hawaii. Water Resources International, Inc. owns and operates four Spencer-Harris portable rotary drill rigs ranging in drilling capacity from 3,500 feet to 7,000 feet, and leases an IDECO H-35 rotary drill/workover rig to an oil company. Additionally, Water Resources International, Inc. owns a two acre parcel of real estate in an industrial park 11 miles south of Hilo, Hawaii, leases a three-quarter of an acre maintenance facility in Honolulu and a one acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii, and maintains an inventory of drilling and pump supplies. As of September 30, 2003, Water Resources International, Inc. employed ten drilling, pump and administrative employees, none of whom are union members.

Water Resources International, Inc. drills water, water monitoring and geothermal wells of varying depths in Hawaii and also installs and repairs water pumps and is the State of Hawaii’s

distributor for Floway pumps and equipment. The demand for Water Resources International, Inc.’s services is primarily dependent upon land development activities in Hawaii. Water Resources International, Inc. 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.

Barnwell’s contract drilling subsidiary derived 66%, 70% and 49% of its contract drilling revenues in fiscal 2003, 2002 and 2001, respectively, pursuant to Federal, State of Hawaii and county contracts. At September 30, 2003, Barnwell had accounts receivable from the State of Hawaii and county entities totaling approximately $177,000. Barnwell has lien rights on wells drilled and pumps installed for Federal, State of Hawaii, county and private entities.

Barnwell’s contract drilling segment currently operates in Hawaii and is not subject to seasonal fluctuations.

Activity

In fiscal 2003, Water Resources International, Inc. started five well drilling contracts and five pump installation contracts and completed six well drilling contracts and nine pump installation contracts. Two of the six completed well contracts and four of the nine completed pump contracts were started in the prior year. Eighty-two percent (82%) of well drilling and pump installation jobs, representing 66% of total contract drilling revenues in fiscal 2003, have been pursuant to government contracts.

At September 30, 2003, Water Resources International, Inc. had a backlog of two well drilling contracts and three pump installation and repair contracts, one of which was in progress as of September 30, 2003.

The dollar amount of Barnwell’s backlog of firm well drilling and pump installation and repair contracts at November 30, 2003 and 2002 is as follows:

	2003		2002
Well drilling	$	1,470,000	$	1,700,000
Pump installation and repair	880,000		100,000
	$	2,350,000	$	1,800,000

All of the contracts in backlog at November 30, 2003 are expected to be completed within fiscal year 2004.

Competition

Water Resources International, Inc. utilizes rotary drill rigs and competes with other drilling contractors in Hawaii which use cable tool rigs, which require less labor to operate but generally drill slower, rotary drill rigs similar to Water Resources International, Inc.’s drilling rigs, and top head rotary drilling rigs that drill as quickly as Water Resources International, Inc.’s equipment but require less labor. These competitors are also capable of installing and repairing vertical turbine and submersible water pumping systems in Hawaii. These contractors compete actively with Water Resources International, Inc. for government and private contracts. Pricing is Barnwell’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. Barnwell expects competitive pressures within the industry to remain high as demand for well drilling and pump installation in Hawaii is not expected to increase in fiscal year 2004 and may decrease.

LAND INVESTMENT OPERATIONS

Barnwell owns a 77.6% controlling interest in Kaupulehu Developments, a Hawaii general partnership which owns interests in leasehold land and development rights for property located approximately six miles north of the Kona International Airport in the North Kona District of the Island of Hawaii. In previous years, 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, and single and multiple family residential units. These projects were developed on land acquired from Kaupulehu Developments by Kaupulehu Makai Venture, an unrelated entity that is an affiliate of Kajima Corporation of Japan.

Activity

The leasehold land interests held by Kaupulehu Developments are for approximately 870 acres of land zoned for resort/residential development and another approximately 1,000 acres of land zoned conservation district. These approximately 1,870 acres are located adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka’upulehu, between the Queen Kaahumanu Highway and the Pacific Ocean.

Kaupulehu Developments is negotiating with an independent third party interested in developing the approximately 870 leasehold acres zoned for resort/residential development, of which approximately 186 acres were designated by the State Land Use Commission as preservation areas with no residential or golf course development. The independent third party and Kaupulehu Developments have made significant progress in negotiation of a revised development agreement and residential fee simple purchase prices with the lessor of the 870 acres. Management cannot predict the outcome of these negotiations.

The development rights held by Kaupulehu Developments are for residentially zoned leasehold land within and adjacent to the Hualalai Golf Club and are under option to Kaupulehu Makai Venture. On December 31, 2002, Kaupulehu Makai Venture exercised the portion of its development rights option due on that date and paid Kaupulehu Developments $2,125,000, reducing the amount of acreage

originally under option to approximately 110 acres at September 30, 2003. Barnwell accounts for sales of development rights under option by use of the cost recovery method. Under the cost recovery method, no operating profit is recognized until cash received exceeds the cost and the estimated future costs related to development rights sold. Accordingly, in consolidation, $1,277,000 of the proceeds from the sales of development rights were applied to reduce the carrying value of the underlying development rights recorded on the Condensed Consolidated Balance Sheets under the caption “Investment in land” to zero. Additionally, sales of development rights were further reduced by $128,000 representing fees paid to Nearco, Inc., (a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 21.8% owner of Kaupulehu Developments) related to the sale. The remaining $720,000 of sales proceeds is recorded in the Consolidated Statements of Operations for fiscal 2003 as “Sale of development rights, net.” The total amount of the remaining option proceeds, if fully exercised, was $21,250,000 at September 30, 2003, comprised of eight payments of $2,656,250 due on each December 31 of years 2003 to 2010. If any annual option payment is not made, the then remaining development right options will expire. There is no assurance that any portion of the remaining options will be exercised.

Competition

Barnwell’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 factors affecting 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. 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 for residential real estate in recent years. This trend continued through fiscal 2003 and is not expected to decline significantly in the near term, although there can be no assurance this trend will in fact continue.

CORPORATE OFFICE

In December 2003, Barnwell purchased the space it was leasing for its corporate offices located at 1100 Alakea Street, Suite 2900, Honolulu, Hawaii 96813 for $1,104,000. The seller was A&B Alakea LLC, an independent third party. This purchase was funded by $221,000 of cash and long-term debt of $883,000. The long-term debt was financed by First Hawaiian Bank and is payable in monthly principal payments of approximately $3,000, plus interest at the three-month London Interbank Offer Rate, 1.25% at the time of closing, plus 2%, and is due in full in December 2006. The space purchased has 4,662 useable square feet on the 28th floor of a 31-story office building built in 1993 in downtown Honolulu.

Item 3. Legal Proceedings

Barnwell is occasionally involved in routine litigation and is subject to governmental and regulatory controls that are incidental to the business. Barnwell’s management believes that routine claims and litigation involving Barnwell 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 Barnwell’s common stock is being traded is the American Stock Exchange. The following tables present the quarterly high and low sales prices, on the American Stock Exchange, for Barnwell’s common stock during the periods indicated:

Quarter Ended	High		Low		Quarter Ended	High		Low
December 31, 2001	$	20.75	$	17.90	December 31, 2002	$	20.45	$	19.75
March 31, 2002	20.60		19.75		March 31, 2003	22.80		20.01
June 30, 2002	20.75		20.00		June 30, 2003	25.05		22.25
September 30, 2002	20.05		19.40		September 30, 2003	25.15		24.00

As of December 2, 2003, there were 1,314,510 shares of common stock, par value $0.50, outstanding. There were approximately 400 holders of the common stock of the registrant as of December 2, 2003.

In March 2001, Barnwell declared a dividend of $0.20 per share payable March 30, 2001, to stockholders of record as of March 16, 2001.

In September 2001, Barnwell declared a dividend of $0.15 per share payable October 17, 2001, to stockholders of record as of October 2, 2001.

In November 2001, Barnwell declared a dividend of $0.15 per share payable January 2, 2002, to stockholders of record as of December 17, 2001.

In December 2003, Barnwell declared a dividend of $0.20 per share payable January 6, 2004 to stockholders of record as of December 22, 2003.

Item 6. MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

The following discussion is intended to assist in the understanding of the consolidated balance sheets of Barnwell Industries, Inc. and subsidiaries (collectively referred to herein as “Barnwell”) as of September 30, 2003 and 2002, 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, 2003. This discussion should be read in conjunction with the Consolidated Financial Statements and related Notes To Consolidated Financial Statements included in this report.

USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In response to U.S. Securities and Exchange Commission Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” Barnwell has identified certain of its policies as being of particular importance to the understanding of its financial position and results of operations and which require the application of significant judgment by management.

Oil and natural gas properties

Barnwell 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 Barnwell’s estimated future net cash flows from estimated production of proved oil and natural gas reserves, from such country, as determined by independent petroleum engineers, less related income tax effects. Any capitalized costs, net of oil and gas related deferred income taxes, in excess of the discounted present value of proved properties and the lower of cost or estimated fair value of unproved properties 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 either proved reserves are associated with the projects or impairment has been determined. At September 30, 2003, Barnwell had no investments in major oil and natural gas development projects that were not being amortized. General and administrative costs related to oil and natural gas operations are expensed as incurred. Estimated future site restoration and abandonment costs are capitalized as part of the carrying amount of oil and natural gas properties and depleted over the life of the related reserves. 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.

Investment in land and revenue recognition

Barnwell’s investment in land is comprised of development rights under option and leasehold land interests in land zoned resort/residential and land zoned conservation, both of which are not under

option. Investment in land is reported at the lower of the asset carrying value or fair value, less costs to sell, and is evaluated for impairment whenever events or changes in circumstances indicate that the recorded investment balance may not be fully recoverable.

Costs incurred for the acquisition and improvement of leasehold land interests, including capitalized interest, and the acquisition of interests in development rights under option are included in the consolidated balance sheets under the caption “Investment in Land.”

Sales of development rights under option are accounted for under the cost recovery method. Under the cost recovery method, no operating profit is recognized until cash received exceeds the cost and the estimated future costs related to the development rights sold.

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 period 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.

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.

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. Barnwell has established a valuation allowance primarily for the U.S. tax effect of deferred Canadian taxes, foreign tax credits, accrued expenses 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.

At September 30, 2003, net deferred tax assets of $2,865,000 consisted primarily of $1,535,000 of deferred tax assets related to the excess of the cost basis of investment in land for tax purposes over the cost basis of investment in land for book purposes. This deferred tax asset will be realized through the deduction of the cost basis of investment in land for tax purposes against future proceeds from sales of interests in leasehold land and development rights under option. The amount of deferred income tax assets considered realizable may be reduced if estimates of future taxable income are reduced.

Pension Plan

Barnwell sponsors a noncontributory defined benefit pension plan covering substantially all of its U.S. employees, with benefits based on years of service and the employee’s highest consecutive five-year average earnings. Barnwell accounts for its defined benefit pension plan in accordance with Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions,” which requires that amounts recognized in financial statements be determined on an actuarial basis. Statement of Financial Accounting Standards No. 87 requires that the effects of the performance of the pension plan’s assets and changes in pension liability discount rates on Barnwell’s computation of pension income (expense) be amortized over future periods. Any variances in the future between the assumed rates utilized for actuarial purposes and the actual rates experienced by the plan may materially affect Barnwell’s results of operations or financial condition.

During and as of the end of fiscal 2003 and fiscal 2002, Barnwell assumed an expected long-term rate of return on plan assets of 8%. The expected rate of future annual compensation increases utilized during and as of the end of fiscal 2003 was 5%.

At the end of each year, Barnwell determines the discount rate to be used to calculate the present value of plan liabilities. The discount rate is an estimate of the current interest rate at which the pension liabilities could be effectively settled at the end of the year. In estimating this rate, Barnwell looks to rates of return on high-quality, fixed-income investments. At September 30, 2003, Barnwell determined this rate to be 6%.

At September 30, 2003, Barnwell’s accrued benefit cost was $324,000. For the year ended September 30, 2003, Barnwell recognized a net periodic benefit cost of $172,000.

CONTRACTUAL OBLIGATIONS

The following table lists the scheduled maturities of long-term debt, estimating that Barnwell’s credit facility with the Royal Bank of Canada will be renewed on each annual renewal date, currently April 29, and scheduled minimum rental payments of non-cancelable operating leases for office space and leasehold land:

	Payments Due by Fiscal Year
Contractual Obligations	2004		2005-2006		2007-2008		After 2008		Total
Long-term debt	$	—	$	—	$	—	$	10,477,000	$	10,477,000
Operating leases	443,000		726,000		743,000		2,678,000		4,590,000

Total	$	443,000	$	726,000	$	743,000	$	13,155,000	$	15,067,000

There is no assurance that the bank will in fact extend the term of the facility on each renewal date or that the facility will be renewed at its current amount. The following table lists the scheduled maturities of long-term debt assuming that the facility will not be renewed on the next renewal date and that Barnwell then elects to convert the revolving facility to term status, and scheduled minimum rental payments of non-cancelable operating leases for office space and leasehold land:

	Payments Due by Fiscal Year
Contractual Obligations	2004		2005-2006		2007-2008		After 2008		Total
Long-term debt	$	524,000	$	9,953,000	$	—	$	—	$	10,477,000
Operating leases	443,000		726,000		743,000		2,678,000		4,590,000

Total	$	967,000	$	10,679,000	$	743,000	$	2,678,000	$	15,067,000

The lease payments for land are subject to renegotiation after December 31, 2005; the future rental payment disclosures above assume the minimum lease payments for land in effect at December 31, 2005 remain unchanged through 2025, the end of the lease term. In December 2003, Barnwell purchased the space it was leasing for its corporate office in Honolulu, Hawaii. The future minimum rental payments reflected above have been adjusted accordingly.

RESULTS OF OPERATIONS

Summary

Barnwell had net earnings of $2,320,000 in fiscal 2003, a $2,280,000 increase from net earnings of $40,000 in fiscal 2002. The increase is largely attributable to significant increases in petroleum prices. In addition, land segment operating profit increased in fiscal 2003, as compared to fiscal 2002, as revenues from the sale of development rights in fiscal 2003 (accounted for under the cost recovery method) exceeded associated costs, whereas revenues from the sale of development rights in fiscal 2002 were fully offset by associated costs (after consideration of minority interest in earnings).

Barnwell had net earnings of $40,000 in fiscal 2002, a $3,790,000 (99%) decrease from net earnings of $3,830,000 in fiscal 2001. The decrease is largely attributable to significant decreases in petroleum prices and lower oil production in fiscal 2002, as compared to fiscal 2001. Net earnings for fiscal 2002 includes an oil and natural gas operating expense credit recorded in the fourth quarter for the settlement of overcharges of operating expenses for fiscal years 1998 through 2001 from the operator of the Dunvegan property that contributed $250,000, net of income taxes, to operations. There were no significant operating expense credits recorded in fiscal 2003 or 2001.

Oil and Natural Gas Revenues

Selected Operating Statistics

The following tables set forth Barnwell’s annual net production and annual average price per unit of production for fiscal 2003 as compared to fiscal 2002, and fiscal 2002 as compared to fiscal 2001. Production amounts reported are net of royalties and the Alberta Royalty Tax Credit.

Fiscal 2003 - Fiscal 2002

	Annual Net Production
			Decrease
	2003	2002	Units		%
Liquids (Bbl)*	85,000	94,000	(9,000	)	(10	)%
Oil (Bbl)*	142,000	148,000	(6,000	)	(4	)%
Natural gas (MCF)**	3,175,000	3,277,000	(102,000	)	(3	)%

	Annual Average Price Per Unit
					Increase
	2003		2002		$		%
Liquids (Bbl)*	$	21.50	$	12.46	$	9.04	73	%
Oil (Bbl)*	$	27.69	$	21.28	$	6.41	30	%
Natural gas (MCF)**	$	4.27	$	2.12	$	2.15	101	%

Fiscal 2002 - Fiscal 2001

	Annual Net Production
			Increase (Decrease)
	2002	2001	Units		%
Liquids (Bbl)*	94,000	98,000	(4,000	)	(4	)%
Oil (Bbl)*	148,000	174,000	(26,000	)	(15	)%
Natural gas (MCF)**	3,277,000	3,269,000	8,000		—

	Annual Average Price Per Unit
					Decrease
	2002		2001		$			%
Liquids (Bbl)*	$	12.46	$	22.60	$	(10.14	)	(45	)%
Oil (Bbl)*	$	21.28	$	25.44	$	(4.16	)	(16	)%
Natural gas (MCF)**	$	2.12	$	4.02	$	(1.90	)	(47	)%

*Bbl = stock tank barrel equivalent to 42 U.S. gallons

**MCF = 1,000 cubic feet

Oil and natural gas revenues increased $8,030,000 (71%) from $11,320,000 in fiscal 2002 to $19,350,000 in fiscal 2003, due to 101%, 30%, and 73% increases in natural gas, oil, and natural gas liquids prices, respectively. The increase was partially offset by 3%, 4%, and 10% declines in net natural gas, oil, and natural gas liquids production, respectively, due to natural declines in production from some of Barnwell’s more mature properties, which were partially offset by an increase in production from new wells. In addition, natural gas liquids production decreased due to a fire in early October 2002 at a Dunvegan gas plant that prevented stripping of natural gas liquids from the natural gas, resulting in an approximately 6,000 barrel decline in liquids net production in fiscal 2003. Barnwell did, however, receive a higher price for its natural gas than it would have if the liquids had been

removed, thereby mitigating some of the impact of the liquids production decline. The damage to the gas plant was repaired and the plant resumed operations in late December 2002.

Oil and natural gas revenues decreased $8,550,000 (43%) from $19,870,000 in fiscal 2001 to $11,320,000 in fiscal 2002, due primarily to 47%, 45%, and 16% decreases in natural gas, natural gas liquids, and oil prices, respectively. Net natural gas production increased less than one percent, however gross natural gas production declined 6% as gas production declines at Barnwell’s more mature properties were only partially offset by production from recent development. However, a decrease in royalty rates, due to decreased natural gas prices, mitigated this decline and left natural gas production relatively unchanged on a net basis. Net oil production decreased 15% due to declines in production from some of Barnwell’s more mature oil properties.

Oil and Natural Gas Operating Expenses

Operating expenses increased $1,084,000 (35%) to $4,192,000 in fiscal 2003, as compared to $3,108,000 in fiscal 2002. The increase is partly attributable to an oil and natural gas operating expense credit recorded in the fourth quarter of fiscal 2002 for the settlement of overcharges of operating expenses for fiscal years 1998 through 2001 from the operator of the Dunvegan property that reduced fiscal 2002 operating expenses by approximately $470,000. Also contributing to the increase were increases in well repair and maintenance, electricity, fuel, insurance, and general maintenance costs. Operating expenses in fiscal 2003 also include $85,000 of accretion of the asset retirement obligation due to implementation of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” on October 1, 2002 (see Note 6 “Property and Equipment and Asset Retirement Obligation” in the Notes to Consolidated Financial Statements).

Operating expenses decreased to $3,108,000 in fiscal 2002, a $401,000 (11%) decrease from $3,509,000 in fiscal 2001, due to an oil and natural gas operating expense credit recorded in the fourth quarter of fiscal 2002 for the settlement of overcharges of operating expenses for fiscal years 1998 through 2001 from the operator of the Dunvegan property totaling $470,000. Partially offsetting this credit were higher gathering and processing fees in fiscal 2002.

Sale of Development Rights and Minority Interest in Earnings

The development rights held by Kaupulehu Developments are for residentially zoned leasehold land within and adjacent to the Hualalai Golf Club and are under option to Kaupulehu Makai Venture, an unrelated entity that is an affiliate of Kajima Corporation of Japan. On December 31, 2002, Kaupulehu Makai Venture exercised the portion of its development rights option due on that date and paid Kaupulehu Developments $2,125,000, reducing the amount of acreage originally under option to approximately 110 acres. Barnwell accounts for sales of development rights under option by use of the cost recovery method. Under the cost recovery method, no operating profit is recognized until cash received exceeds the cost and the estimated future costs related to development rights sold. Accordingly, in consolidation, $1,277,000 of the proceeds from the sales of development rights were applied to reduce the carrying value of the underlying development rights recorded on the Consolidated Balance Sheets under the caption “Investment in land” to zero. Additionally, sales of development rights were further reduced by $128,000 of fees related to the sale. The remaining $720,000 of sales proceeds is recorded in the Consolidated Statements of Operations for fiscal 2003 as “Sale of development rights, net.” The total amount of the remaining option proceeds, if fully exercised, was $21,250,000 at September 30, 2003, comprised of eight payments of $2,656,250 due on each December

31 of years 2003 to 2010. If any annual option payment is not made, the then remaining development right options will expire. There is no assurance that any portion of the remaining options will be exercised.

The aforementioned $128,000 in fees ($89,000, net of minority interest) on the $2,125,000 development rights proceeds were paid in January 2003 to Nearco, Inc., a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 21.8% owner of Kaupulehu Developments. Under an agreement entered into in 1987, prior to Mr. Johnston’s election to Barnwell’s Board of Directors, Barnwell is obligated to pay Nearco, Inc. 2% of Kaupulehu Developments’ gross receipts from the sale of real estate interests. In addition, Cambridge Hawaii Limited Partnership, a 49.9% owner of Kaupulehu Developments, in which Barnwell purchased a 55.2% interest in April 2001, is obligated under an agreement entered into in 1987 to pay Nearco, Inc. 4% of Kaupulehu Developments’ gross receipts from the sale of real estate interests. The fees represent compensation for promotion and marketing of Kaupulehu Developments’ property and were determined based on the estimated fair value of such services. Barnwell believes the fees are fair and reasonable compensation for such services.

Fees were also paid to Nearco, Inc. for consulting services related to Kaupulehu Developments’ leasehold land. For fiscal 2003 and fiscal 2002, such fees totaled $218,000 and $95,000, respectively, and were included in general and administrative expenses. Barnwell believes the fees are fair and reasonable compensation for such services.

On December 31, 2001 Kaupulehu Makai Venture exercised the portion of its development rights option due on that date and paid Kaupulehu Developments $2,125,000. Under the cost recovery method, $1,877,000 of investment in land was expensed as a result of this option exercise in fiscal 2002, reducing operating profit, after minority interest, to zero.

Kaupulehu Developments is negotiating with an independent party interested in developing the approximately 870 acres of resort/residential leasehold acreage (of which approximately 186 acres were designated by the State Land Use Commission as preservation areas with no residential or golf course development). The independent third party and Kaupulehu Developments have made significant progress in negotiation of a revised development agreement and residential fee simple purchase prices with the lessor. Management cannot predict the outcome of these negotiations.

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 $1,430,000 (41%) to $2,050,000 in fiscal 2003, as compared to $3,480,000 in fiscal 2002, and contract drilling operating expenses decreased $893,000 (32%) to $1,928,000 in fiscal 2003, as compared to $2,821,000 in fiscal 2002. Operating profit before depreciation decreased $537,000 (81%) from $659,000 in fiscal 2002 to $122,000 in fiscal 2003. The decreases were due to a decreased number of available water well drilling and pump installation contracts and lower contract margins resulting from higher competition for those contracts.

At September 30, 2003, Water Resources International, Inc., a wholly-owned subsidiary of Barnwell, had a backlog of two well drilling contracts and three pump installation and repair contracts,

one of which was in progress as of September 30, 2003. The backlog of contract drilling revenues as of November 30, 2003 was approximately $2,350,000.

Contract drilling revenues and operating expenses remained relatively constant in fiscal 2002, as compared to fiscal 2001. Contract drilling revenues increased $190,000 (6%) to $3,480,000 in fiscal 2002, as compared to $3,290,000 in fiscal 2001, and contract drilling operating expenses decreased $85,000 (3%) to $2,821,000 in fiscal 2002, as compared to $2,906,000 in fiscal 2001. Operating profit before depreciation increased $275,000 (72%) from $384,000 in fiscal 2001 to $659,000 in fiscal 2002 due to an increase in well drilling activity, partially offset by a decrease in pump installation activity; well drilling contracts generally have higher margins than pump installation contracts.

Gas Processing and Other Income

Gas processing and other income increased $600,000 (63%) to $1,560,000 in fiscal 2003, as compared to $960,000 in fiscal 2002, due principally to the receipt by Kaupulehu Developments of $500,000 in income related to negotiations on the development of Kaupulehu Developments’ resort/residential acreage during fiscal 2003, as compared to $100,000 in fiscal 2002. Interest income in fiscal 2003 also increased due to $102,000 of interest on an income tax refund from the Canadian government relating to Barnwell’s fiscal 1994 tax return and a $61,000 increase in interest income on a note receivable (interest on the note began in February 2002, therefore there were only eight months of interest earned in fiscal 2002, as compared to a full twelve months of interest earned in fiscal 2003).

Gas processing and other income was relatively unchanged in fiscal 2002 (increased $30,000 or 3%), as compared to fiscal 2001.

General and Administrative Expenses

General and administrative expenses increased $1,627,000 (37%) to $5,971,000 in fiscal 2003, as compared to $4,344,000 in fiscal 2002, due primarily to costs incurred related to sales negotiations with interested parties and other costs related to maintaining Kaupulehu Developments’ leasehold land. Such costs, totaling approximately $887,000, consisted of legal, consulting, travel and other costs; in fiscal 2002 these costs totaled $1,066,000, of which $324,000 was expensed and $742,000 of which was capitalized. Attainment of zoning and development entitlements for Kaupulehu Developments’ leasehold land interests in approximately 870 acres of land zoned for resort/residential development was determined to be substantially complete in December 2002. Accordingly, effective January 1, 2003, Barnwell no longer capitalizes expenditures related to the 870 acres. The increase was also attributable to increases in personnel and pension plan costs of $495,000, increased oil and natural gas segment incentive plan costs for the Vice President of Canadian Operations of $214,000, increased stock appreciation rights expense of $177,000, and increases in professional services of approximately $121,000 (primarily related to compliance with the Sarbanes-Oxley Act of 2002 and restatement of the Barnwell Industries, Inc. Employees’ Pension Plan to comply with Internal Revenue Service rulings), as compared to fiscal 2002. Additionally, other general and administrative costs increased by a net of $57,000.

General and administrative expenses include fees paid to Nearco, Inc., an entity controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 21.8% owner of Kaupulehu Developments, for consulting services related to Kaupulehu Developments’ leasehold land. In fiscal 2003 and 2002,

fees paid to Nearco, Inc. totaled $218,000 and $95,000, respectively. Barnwell believes the fees are fair and reasonable compensation for such services.

General and administrative expenses increased $223,000 (5%) to $4,344,000 in fiscal 2002, as compared to $4,121,000 in fiscal 2001, due to legal and consulting costs related to land segment sales negotiations in fiscal 2002; there were no such costs in fiscal 2001.

Depreciation, Depletion and Amortization

Depletion, depreciation and amortization increased $685,000 (19%) to $4,333,000 in fiscal 2003, as compared to $3,648,000 in fiscal 2002, due to an 18% increase in the depletion rate and an 8% increase in the fiscal year average exchange rate of the Canadian dollar to the U.S. dollar, partially offset by a 4% decrease in production (in MCF equivalents where one barrel of oil and natural gas liquids are converted to 5.8 MCF equivalents). The higher depletion rate is the result of increased costs of finding and developing proven reserves in fiscal 2003, as compared fiscal 2002.

Depreciation, depletion and amortization expense decreased $106,000 (3%) to $3,648,000 in fiscal 2002, as compared to $3,754,000 in fiscal 2001, due to decreased production, partially offset by a slightly higher depletion rate per MCF equivalent in fiscal 2002, as compared to fiscal 2001.

Interest Expense

Interest expense increased $146,000 (49%) to $442,000 in fiscal 2003, as compared to interest expense of $296,000 in fiscal 2002. The increase was due primarily to decreased capitalized interest. Attainment of zoning and development entitlements for Kaupulehu Developments’ leasehold land interests in approximately 870 acres of land zoned for resort/residential development was substantially complete as of the end of December 2002. Accordingly, effective January 1, 2003, Barnwell no longer capitalizes interest on the accumulated development costs of the property.

Interest costs for the years ended September 30, 2003, 2002 and 2001 are summarized as follows:

	2003		2002		2001
Interest costs incurred	$	487,000	$	498,000	$	665,000
Less interest costs capitalized on investment in land	45,000		202,000		278,000
Interest expense	$	442,000	$	296,000	$	387,000

The average interest rate incurred during fiscal 2003 on Barnwell’s borrowings from the Royal Bank of Canada decreased to 3.84%, as compared to 4.24% in fiscal 2002, and the weighted average balance of outstanding borrowings from the Royal Bank of Canada decreased from approximately $10,300,000 in fiscal 2002 to approximately $10,100,000 in fiscal 2003. The convertible debentures, which bore interest at 10% per annum in fiscal 2002 and the nine months ended June 30, 2003, were fully repaid in June 2003.

Interest expense decreased $91,000 (24%) to $296,000 in fiscal 2002, as compared to interest expense of $387,000 in fiscal 2001. The decrease was due to lower average interest rates, partially offset by higher average outstanding borrowings and a decrease in capitalized interest. The average interest rate incurred during fiscal 2002 on Barnwell’s borrowings from the Royal Bank of Canada decreased to

4.24%, as compared to 6.62% in fiscal 2001, whereas the weighted average balance of outstanding borrowings from the Royal Bank of Canada increased from approximately $8,300,000 in fiscal 2001 to approximately $10,300,000 in fiscal 2002. The average outstanding debentures balance decreased from $950,000 in fiscal 2001 to $507,000 in fiscal 2002 while the average interest rate on the debentures remained essentially unchanged. Capitalized interest decreased $76,000 from $278,000 in fiscal 2001 to $202,000 in fiscal 2002 primarily due to lower interest rates, partially offset by an increase in the capitalization base as Barnwell carried a 77.6% interest in Kaupulehu Developments’ leasehold interest in land under development for a full year in fiscal 2002, as compared to approximately one-half year in fiscal 2001 (the additional 27.5% interest in Kaupulehu Developments was purchased in April 2001).

Foreign Currency Fluctuations

In addition to U.S. operations, Barnwell conducts foreign operations in Canada. Consequently, Barnwell is subject to foreign currency translation and transaction gains and losses due to fluctuations of the exchange rates between the Canadian dollar and the U.S. dollar.

The fiscal year average exchange rate of the Canadian dollar to the U.S. dollar increased 8% in fiscal 2003, as compared to fiscal 2002, and the exchange rate of the Canadian dollar to the U.S. dollar increased 17% at September 30, 2003, as compared to September 30, 2002. Accordingly, the assets, liabilities, stockholders’ equity and revenues and expenses of Barnwell’s subsidiaries operating in Canada have increased. Barnwell’s Canadian dollar assets are greater than its Canadian dollar liabilities; therefore, increases in value of the Canadian dollar to the U.S. dollar generate other comprehensive income. Other comprehensive income due to foreign currency translation adjustments for fiscal 2003 was $2,392,000, a $2,478,000 increase from an other comprehensive loss of $86,000, due to foreign currency translation adjustments, in fiscal 2002.

Foreign currency transaction gains and losses were not material in fiscal 2003, 2002 and 2001 and are reflected in general and administrative expenses.

The impact of fluctuations of the exchange rates between the Canadian dollar and the U.S. dollar may be material from period to period. Barnwell cannot accurately predict future fluctuations between the Canadian and U.S. dollars.

Income Taxes

Included in the provision for deferred income taxes for the years ended September 30, 2003 and 2002 is a U.S. deferred tax benefit of $320,000 and $376,000, respectively, related to the sale of land development rights in December 2002 and 2001, respectively. The sales of land development rights created temporary differences due to the excess of expenses recognized under the cost recovery method for books over expenses deductible for tax purposes. There was no deferred income tax benefit related to land sales in the year ended September 30, 2001.

into law. The reduction in the tax will reduce Barnwell’s deferred income tax liabilities by approximately $1,500,000 in the quarter ending December 31, 2003, Barnwell’s fiscal 2004 first quarter.

In May 2003, the legislative assembly of the Province of Alberta held a first reading on a bill to reduce the province’s corporate tax rate from 13.0% to 12.5%, effective April 1, 2003. On November 20, 2003, the bill passed on third reading and will become law upon Royal Assent. If enacted into law the reduction in the tax rate would reduce Barnwell’s current income tax liabilities by approximately $20,000 and Barnwell’s deferred income taxes liabilities by approximately $100,000.

In April 2002, the legislative assembly of the Province of Alberta passed a bill to reduce the province’s corporate tax rate from 13.5% to 13.0%, effective April 1, 2002. The bill was enacted into law in December 2002. The reduction in the tax rate reduced Canadian deferred income tax liabilities by approximately $75,000 in the year ended September 30, 2003. There was no such reduction recorded in the year ended September 30, 2002. During fiscal 2001, the Province of Alberta reduced the province’s corporate tax rate from 15.5% to 13.5% effective April 1, 2001. As a result of this reduction, Barnwell recorded an approximately $300,000 deferred income tax benefit in fiscal 2001.

In fiscal 2003, 2002 and 2001, 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 Barnwell and could have a material adverse effect upon the earnings or competitive position of Barnwell. 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 Barnwell has generally been to increase its cost of operations, interest cost (as a substantial portion of Barnwell’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, Barnwell 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 Barnwell are essentially determined by world prices for oil and western Canadian/Midwestern U.S. prices for natural gas.

Recent Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are to be capitalized as part of the carrying amount of the long-lived asset and depreciated over the

life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, Barnwell will recognize a gain or loss on settlement. The provisions of SFAS No. 143 are effective for fiscal years beginning after June 15, 2002. Barnwell adopted SFAS No. 143 on October 1, 2002. Adoption of SFAS No. 143 increased gross oil and natural gas properties by $564,000, decreased accumulated depletion by $546,000, and increased the asset retirement obligation by $1,110,000 on October 1, 2002. Prior to the adoption of SFAS No. 143, obligations for asset retirements were charged to earnings at the rate of depletion and were included in accumulated depletion. The impact of applying SFAS No. 143 on fiscal 2002 and 2001 net earnings would not have resulted in a material difference, and the asset retirement obligation would not have been materially different from the amount reported at September 30, 2003.

In November 2002, the FASB issued FASB Interpretation (“FIN”) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN No. 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of FIN No. 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The adoption of FIN No. 45 did not have a material effect on Barnwell’s financial condition, results of operations or liquidity.

In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities,” which addresses the consolidation of variable interest entities (“VIE”) as defined. FIN No. 46 applies immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in VIEs obtained after January 31, 2003. For a variable interest in a VIE acquired before February 1, 2003, FIN No. 46 can be applied no later than the beginning of the first interim or annual reporting period beginning after June 15, 2003. The application of FIN No. 46 did not have a material effect on Barnwell’s financial condition, results of operations or liquidity.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The amendments to SFAS No. 123 are effective for financial statements for fiscal years ending after December 15, 2002. The required disclosures for interim financial statements are effective for financial reports containing condensed financial statements for interim periods beginning after December 15, 2002. The adoption of SFAS No. 148 did not have a material effect on Barnwell’s financial condition, results of operations or liquidity.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. In particular, SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative and when a derivative

contains a financing component that warrants special reporting in the statement of cash flows. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact on Barnwell’s financial condition, results of operations or liquidity.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 clarifies the accounting for certain financial instruments with characteristics of both liabilities and equity and requires that those instruments be classified as liabilities in statements of financial position. Previously, many of those financial instruments were classified as equity. SFAS No. 150 is generally effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 did not have a material impact on Barnwell’s financial condition, results of operations or liquidity.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows, Debt and Available Credit

Cash flows from operations were $8,515,000 in fiscal 2003, as compared to $1,448,000 in fiscal 2002, an increase of $7,067,000. This increase was primarily due to $6,235,000 of higher operating profit generated by Barnwell’s oil and natural gas segment as a result of higher petroleum prices, and a decrease in income taxes paid in fiscal 2003, as compared to fiscal 2002. Income taxes of $3,812,000 were paid in fiscal 2002 (primarily related to Canadian income taxes for the year ended September 30, 2001, which were paid, when due, in the first quarter of fiscal 2002), as compared to $2,961,000 in fiscal 2003.

Cash flows used in investing activities totaled $7,749,000 in fiscal 2003, a $4,202,000 increase from $3,547,000 of cash flows used in investing activities in fiscal 2002. The increase is due primarily to higher oil and natural gas capital expenditures in fiscal 2003, as compared to fiscal 2002. Payments for such capital expenditures increased $4,960,000 (108%) to $9,541,000 in fiscal 2003, as compared to $4,581,000 in fiscal 2002. The increase was partially offset by an $899,000 decrease in capital expenditures for investment in land project planning and development. In fiscal 2002, $944,000 of costs were capitalized for land planning and development, as compared to $45,000 in fiscal 2003. Attainment of zoning and development entitlements for Kaupulehu Developments’ leasehold land interests in approximately 870 acres of land zoned for resort/residential development was substantially complete as of the end of December 2002. Accordingly, Barnwell capitalized $45,000 of interest during the quarter ended December 31, 2002 and, effective January 1, 2003, Barnwell no longer capitalizes Kaupulehu Developments’ expenditures.

Cash flows used in financing activities amounted to $635,000 in fiscal 2003, a $905,000 decrease from $1,540,000 of cash flows used in fiscal 2002. In fiscal 2002, Barnwell paid the $2,209,000 of notes payable due on the acquisition of an additional 27.5% interest in Kaupulehu Developments, borrowed $1,711,000 under the Royal Bank of Canada facility, paid $394,000 in dividends, paid $370,000 on its convertible debentures, and distributed $278,000 to Kaupulehu Developments’ minority interest partners. In fiscal 2003, Barnwell repaid in full the remaining $360,000 of its convertible debentures and distributed $275,000 to Kaupulehu Developments’ minority interest partners; there were

no note payments related to the acquisition of an additional 27.5% interest in Kaupulehu Developments, long-term debt borrowings or dividend payments in fiscal 2003.

While Barnwell had no long-term debt borrowings in fiscal 2003, a 17% increase in the exchange rate of the Canadian dollar to the U.S. dollar increased the amount of Canadian dollar denominated debt by U.S. $516,000 at September 30, 2003, as compared to September 30, 2002.

At September 30, 2003, Barnwell had consolidated cash and cash equivalents of $1,648,000, a working capital deficit of $3,637,000, and available credit under the Royal Bank of Canada’s revolving credit facility of approximately $3,500,000.

The Royal Bank of Canada renewed Barnwell’s credit facility unchanged at $19,000,000 Canadian dollars, or approximately $14,000,000 U.S. dollars at September 30, 2003, and extended the revolving period one year to April 29, 2004. If the loan is converted to a term loan, the term period payments are as follows: first year of the term period – 20% (5% per quarter), and in the second year of the term period – 80% (5% per quarter for the first three quarters and 65% in the final quarter). Outstanding borrowings under this facility were $10,477,000 and $9,961,000 at September 30, 2003 and 2002, respectively, and are included in long-term debt.

The bank represented that it will not require any repayments under the facility before October 1, 2004. Accordingly, Barnwell has classified outstanding borrowings under the facility as long-term debt.

Barnwell believes its current cash balances, future cash flows from operations, land segment sales, collection of receivables, and available credit will be sufficient to fund its estimated capital expenditures and meet the repayment schedule on its long-term debt. However, if oil and natural gas production remains at or declines from current levels or oil and natural gas prices decline from current levels, current working capital balances and cash flows generated by operations may not be sufficient to fund Barnwell’s current projected level of oil and natural gas capital expenditures, in which case Barnwell may fund capital expenditures with funds generated by land segment sales, long-term debt borrowings, or it may reduce future oil and natural gas capital expenditures. Additionally, if Barnwell’s credit facility with a Canadian bank is reduced below the current level of borrowings under the facility after the April 2004 review, Barnwell may be required to reduce expenditures or seek alternative sources of financing to make any required payments under the facility.

Partial Exercise of Development Rights Option

On December 31, 2002 and 2001, Kaupulehu Makai Venture exercised the portion of its development rights option due on those dates and paid Kaupulehu Developments $2,125,000 on each date. Barnwell accounts for sales of development rights under option under the cost recovery method where no operating profit is recognized until cash received exceeds costs and estimated future costs associated with the development rights. In fiscal 2003, the remaining $1,277,000 balance of investment in land associated with development rights was reduced to zero and net revenues from the sale of development rights exceeded the amount of investment in land expensed and resulted in $280,000 of operating profit, after minority interest, as a result of the option exercise. In fiscal 2002, $1,877,000 of investment in land was expensed as a result of this option exercise, reducing operating profit, after minority interest, to zero.

The total amount of the remaining option proceeds, if fully exercised, was $21,250,000 at September 30, 2003, comprised of eight payments of $2,656,250 due on each December 31 of years 2003 to 2010. If any annual option payment is not made, the then remaining development right options will expire. There is no assurance that any portion of the remaining options will be exercised.

Leasehold Land Interests

Acquisition of Additional Interest In Kaupulehu Developments

On January 31, 2002, Barnwell paid the remaining $2,209,000 due on the April 2001 purchase of the additional 27.5% interest in Kaupulehu Developments. Also, on January 31, 2002, Nearco, Inc. repaid $100,000 of its notes payable to Barnwell and Barnwell extended the due date of the $1,381,000 balance of its original $1,481,000 receivable to December 31, 2002. Nearco, Inc. paid all interest due and payable at December 31, 2002 of $58,000 and repaid approximately $70,000 of principal on its note payable to Barnwell in January 2003 leaving an unpaid principal balance of approximately $1,311,000, which is outstanding as of the date of this filing. Under the terms of the note, the note is in default and the rate of interest increased from 10% to 12% on January 1, 2003. Nearco, Inc. has paid interest on the note through September 30, 2003. Management believes that Nearco, Inc. will repay its note and any interest due in full. The note is secured by Nearco, Inc.’s entire interest in Cambridge Hawaii Limited Partnership, with its principal asset being a 49.9% interest in Kaupulehu Developments. Management estimates that the current value of Nearco, Inc.’s pledged interest in Kaupulehu Developments is significantly in excess of the combined value of its note to Barnwell and Nearco, Inc.’s $450,000 note to a third party to which Barnwell’s note is subordinated.

Capital Expenditures

The following table sets forth Barnwell’s capital expenditures, including accrued capital expenditure commitments, for each of the last three fiscal years:

	2003		2002		2001
Oil and natural gas	$	11,059,000	$	4,581,000	$	4,240,000
Land investment	45,000		944,000		5,954,000
Contract drilling	72,000		77,000		84,000
Other	158,000		42,000		180,000
Total capital expenditures	$	11,334,000	$	5,644,000	$	10,458,000

Increase (decrease) in oil and natural gas capital expenditures from prior year	$	6,478,000	$	341,000	$	(763,000	)

Oil and natural gas properties also increased $648,000 in fiscal 2003 due to the adoption of SFAS No. 143 effective October 1, 2002. The effect of adoption of SFAS No. 143 is not included in the $11,059,000 of fiscal 2003 oil and natural gas capital expenditures shown above.

Land investment capital expenditures in 2001 include $5,000,000 for the purchase of the additional 27.5% interest in Kaupulehu Developments. Barnwell paid $2,791,000 in cash and issued $2,209,000 in non-interest bearing promissory notes.

In fiscal 2003, Barnwell’s oil and natural gas capital expenditures increased $6,478,000 (141%) from $4,581,000 in fiscal 2002 to $11,059,000 in fiscal 2003. Barnwell participated in drilling 65 (14.7 net) wells, 53 (11.1 net) of which were successful, and the recompletion of 10 wells (1.8 net wells), and replaced 44% of oil production (including natural gas liquids) and 115% of natural gas production. The major areas of investments and commitments in fiscal 2003 were in the Leduc, Bonanza, Dunvegan, Progress, Pouce Coupe South, and Bashaw areas of Alberta. In these areas, Barnwell drilled successful wells that have been tied in and commenced production during the year ended September 30, 2003. In the Dunvegan area, Barnwell participated in the drilling of 12 gross development wells (one net development well) as part of the operator’s objective of increasing production from the area. Barnwell operated and supervised the drilling of six wells in 2003 and six wells in 2002. Of the $11,059,000 total oil and natural gas properties investments and commitments for fiscal 2003, $1,390,000 was for acquisition of leases and lease rentals, $917,000 was for geological and geophysical costs, $5,857,000 was for intangible drilling costs, and $2,895,000 was for well equipment.

The following table sets forth the gross and net numbers of oil and natural gas wells Barnwell participated in drilling and purchased for each of the last three fiscal years:

	2003		2002		2001
	Gross	Net	Gross	Net	Gross	Net
Exploratory oil and natural gas wells drilled	13	3.60	5	0.94	4	1.40

Development oil and natural gas wells drilled	52	11.10	11	4.52	26	4.40

Successful oil and natural gas wells drilled	53	11.10	12	4.19	23	3.20

Barnwell estimates that oil and natural gas capital expenditures for fiscal 2004 will range from $9,500,000 to $12,500,000. This estimated amount may increase or decrease as dictated by management’s assessment of the oil and gas environment and prospects.

In fiscal 2003, $45,000 of Barnwell’s capital expenditures were applicable to capitalized interest on development of Kaupulehu Developments’ leasehold land interests in approximately 870 acres of land zoned for resort/residential development. Attainment of zoning and development entitlements for the approximately 870 acres was substantially complete as of the end of December 2002, therefore, effective January 1, 2003, Barnwell no longer capitalizes Kaupulehu Developments’ expenditures and no longer capitalizes interest on the accumulated development costs of the property. In fiscal 2002, $944,000 of Barnwell’s capital expenditures were applicable to investment in land project planning and development. These expenditures were primarily comprised of legal, consulting, and planning fees and capitalized interest.

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, 2003 and 2002, 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, 2003. 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, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended September 30, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in note 2 to the consolidated financial statements, effective October 1, 2002, the Company changed its method of accounting for asset retirement obligations.

/s/KPMG LLP

Honolulu, Hawaii
December 2, 2003, except as to notes 11 and 16
which are as of December 23, 2003

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

	September 30,
	2003			2002
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,648,000		$	1,489,000
Accounts receivable, net (Notes 3 and 14)	2,866,000			3,031,000
Note receivable (Note 4)	1,311,000			1,381,000
Costs and estimated earnings in excess of billings on uncompleted contracts (Note 3)	166,000			174,000
Deferred income taxes (Note 8)	215,000			210,000
Prepaid expenses and other current assets	675,000			821,000
TOTAL CURRENT ASSETS	6,881,000			7,106,000

INVESTMENT IN LAND (Notes 5 and 7)	6,508,000			7,740,000

PROPERTY AND EQUIPMENT, NET (Notes 6, 7 and 16)	38,948,000			25,828,000

TOTAL ASSETS	$	52,337,000		$	40,674,000

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,357,000		$	2,995,000
Accrued liabilities	6,082,000			3,367,000
Billings in excess of costs and estimated earnings on uncompleted contracts (Note 3)	29,000			114,000
Payable to joint interest owners	608,000			727,000
Income taxes payable (Note 8)	442,000			—
Current portion of long-term debt (Note 7)	—			360,000
TOTAL CURRENT LIABILITIES	10,518,000			7,563,000

LONG-TERM DEBT (Notes 7 and 16)	10,477,000			9,961,000

ASSET RETIREMENT OBLIGATION	1,432,000			—

DEFERRED INCOME TAXES (Notes 8 and 16)	9,443,000			7,429,000

MINORITY INTEREST (Note 5)	834,000			800,000

COMMITMENTS AND CONTINGENCIES
(Notes 5, 9, 10, 11 and 16)

STOCKHOLDERS’ EQUITY (Notes 7, 10 and 16):
Common stock, par value $0.50 per share:
Authorized, 4,000,000 shares; issued, 1,642,797 shares; outstanding, 1,314,510 shares	821,000			821,000
Additional paid-in capital	3,139,000			3,139,000
Retained earnings	22,018,000			19,698,000
Accumulated other comprehensive loss - foreign currency translation adjustments	(1,491,000		)	(3,883,000		)
Treasury stock, at cost, 328,287 shares	(4,854,000		)	(4,854,000		)
TOTAL STOCKHOLDERS’ EQUITY	19,633,000			14,921,000

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	52,337,000		$	40,674,000

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended September 30,
	2003		2002		2001
Revenues:
Oil and natural gas	$	19,350,000	$	11,320,000	$	19,870,000
Contract drilling	2,050,000		3,480,000		3,290,000
Gas processing and other	1,560,000		960,000		930,000
Sale of development rights, net (Note 5)	720,000		120,000		—
	23,680,000		15,880,000		24,090,000

Costs and expenses:
Oil and natural gas operating	4,192,000		3,108,000		3,509,000
Contract drilling operating	1,928,000		2,821,000		2,906,000
General and administrative	5,971,000		4,344,000		4,121,000
Depreciation, depletion and amortization	4,333,000		3,648,000		3,754,000
Interest expense, net (Note 7)	442,000		296,000		387,000
Minority interest in earnings (Note 5)	309,000		62,000		8,000

	17,175,000		14,279,000		14,685,000

Earnings before income taxes	6,505,000		1,601,000		9,405,000

Provision for income taxes (Note 8)	4,185,000		1,561,000		5,575,000

NET EARNINGS	$	2,320,000	$	40,000	$	3,830,000

BASIC EARNINGS PER COMMON SHARE	$	1.76	$	0.03	$	2.92
DILUTED EARNINGS PER COMMON SHARE	$	1.69	$	0.03	$	2.82

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC	1,314,510		1,313,915		1,310,952

DILUTED	1,369,595		1,357,181		1,390,798

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended September 30,
	2003			2002			2001
Cash flows from operating activities:
Net earnings	$	2,320,000		$	40,000		$	3,830,000
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation, depletion and amortization	4,333,000			3,648,000			3,754,000
Deferred income taxes	709,000			405,000			154,000
Minority interest in earnings	309,000			62,000			8,000
Accretion of asset retirement obligation	85,000			—			—
Sale of development rights, net	(720,000		)	(120,000		)	—

	7,036,000			4,035,000			7,746,000

Increase (decrease) from changes in current assets and liabilities (Note 15)	1,479,000			(2,587,000		)	2,412,000

Net cash provided by operating activities	8,515,000			1,448,000			10,158,000

Cash flows from investing activities:
Proceeds from sale of development rights, net	1,997,000			1,997,000			—
Proceeds from collection of notes receivable	70,000			100,000			—
Capital expenditures	(9,816,000		)	(5,644,000		)	(5,458,000		)
Investment in Cambridge Hawaii Limited Partnership	—			—			(2,791,000		)
Cash advanced in exchange for notes receivable	—			—			(1,481,000		)
Proceeds from sale of property and equipment	—			—			8,000
Decrease in other assets	—			—			57,000

Net cash used in investing activities	(7,749,000		)	(3,547,000		)	(9,665,000		)

Cash flows from financing activities:
Repayments of long-term debt	(360,000		)	(370,000		)	(400,000		)
Distribution to minority interest partners	(275,000		)	(278,000		)	—
Payment of dividends	—			(394,000		)	(459,000		)
Repayments of notes payable	—			(2,209,000		)	—
Long-term debt borrowings	—			1,711,000			—
Purchases of common stock for treasury	—			—			(20,000		)
Proceeds from exercise of stock options	—			—			13,000

Net cash used in financing activities	(635,000		)	(1,540,000		)	(866,000		)

Effect of exchange rate changes on cash and cash equivalents	28,000			(26,000		)	(174,000		)

Net increase (decrease) in cash and cash equivalents	159,000			(3,665,000		)	(547,000		)

Cash and cash equivalents at beginning of year	1,489,000			5,154,000			5,701,000

Cash and cash equivalents at end of year	$	1,648,000		$	1,489,000		$	5,154,000

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

Years ended September 30, 2003, 2002 and 2001

	Common Stock		Additional Paid-In Capital		Comprehensive Income			Retained Earnings			Accumulated Other Comprehensive Loss			Treasury Stock			Total Stockholders’ Equity
Balance at September 30, 2000	$	821,000	$	3,103,000				$	16,680,000		$	(3,048,000	)	$	(4,882,000	)	$	12,674,000


Exercise of stock options, 1,000 shares			2,000											11,000			13,000

Purchase of 1,000 common shares for treasury														(20,000		)	(20,000		)

Dividends declared ($0.50 per share)								(655,000		)							(655,000		)

Comprehensive income:
Net earnings					$	3,830,000		3,830,000									3,830,000
Other comprehensive loss, net of income taxes – foreign currency translation adjustments					(749,000		)				(749,000		)				(749,000		)
Total comprehensive income					$	3,081,000

At September 30, 2001	$	821,000	$	3,105,000				$	19,855,000		$	(3,797,000	)	$	(4,891,000	)	$	15,093,000

(Continued on next page)

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

Years ended September 30, 2003, 2002 and 2001

(Continued from previous page)

	Common Stock		Additional Paid-In Capital		Comprehensive Loss			Retained Earnings			Accumulated Other Comprehensive Loss			Treasury Stock			Total Stockholders’ Equity
Balance at September 30, 2001	$	821,000	$	3,105,000				$	19,855,000		$	(3,797,000	)	$	(4,891,000	)	$	15,093,000

Conversion of debentures to common stock at $20.00 per share			34,000											37,000			71,000

Dividends declared ($0.15 per share)								(197,000		)							(197,000		)

Comprehensive loss:
Net earnings					$	40,000		40,000									40,000
Other comprehensive loss, net of income taxes – foreign currency translation adjustments					(86,000		)				(86,000		)				(86,000		)
Total comprehensive loss					$	(46,000	)

At September 30, 2002	$	821,000	$	3,139,000				$	19,698,000		$	(3,883,000	)	$	(4,854,000	)	$	14,921,000

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

Years ended September 30, 2003, 2002 and 2001

(Continued from previous page)

	Common Stock		Additional Paid-In Capital		Comprehensive Income		Retained Earnings		Accumulated Other Comprehensive Loss			Treasury Stock			Total Stockholders’ Equity
Balance at September 30, 2002	$	821,000	$	3,139,000			$	19,698,000	$	(3,883,000	)	$	(4,854,000	)	$	14,921,000

Comprehensive income:
Net earnings					$	2,320,000	2,320,000								2,320,000
Other comprehensive income, net of income taxes – foreign currency translation adjustments					2,392,000				2,392,000						2,392,000
Total comprehensive income					$	4,712,000

At September 30, 2003	$	821,000	$	3,139,000			$	22,018,000	$	(1,491,000	)	$	(4,854,000	)	$	19,633,000

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001

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 an indirect 77.6%-owned land development general partnership, (collectively referred to herein as “Barnwell”). All significant intercompany accounts and transactions have been eliminated.

During its last three fiscal years, Barnwell 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. Barnwell’s oil and natural gas activities comprise its largest business segment. Approximately 82% of Barnwell’s revenues and 98% of Barnwell’s capital expenditures for the fiscal year ended September 30, 2003 were attributable to its oil and natural gas activities. Barnwell’s contract drilling activities accounted for 9% of Barnwell’s fiscal 2003 revenues, land investment activities comprised 5% of fiscal 2003 revenues, and gas processing and other revenues comprised 4% of fiscal 2003 revenues.

2. SIGNIFICANT ACCOUNTING POLICIES

Cash and cash equivalents

Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is Barnwell’s best estimate of the amount of probable credit losses in Barnwell’s existing accounts receivable and is based on historical write-off experience. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Barnwell does not have any off-balance sheet credit exposure related to its customers.

Oil and natural gas properties

in excess of the discounted present value of proved properties and the lower of cost or estimated fair value of unproved properties 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 either proved reserves are associated with the projects or impairment has been determined. At September 30, 2003, Barnwell had no investments in major oil and natural gas development projects that were not being amortized. General and administrative costs related to oil and natural gas operations are expensed as incurred. Estimated future site restoration and abandonment costs are capitalized as part of the carrying amount of oil and natural gas properties and depleted over the life of the related reserves. 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.

Investment in land and revenue recognition

Barnwell’s investment in land is comprised of development rights under option and leasehold land interests in land zoned resort/residential and land zoned conservation, both of which are not under option. Investment in land is reported at the lower of the asset carrying value or fair value, less costs to sell, and is evaluated for impairment whenever events or changes in circumstances indicate that the recorded investment balance may not be fully recoverable.

Contract drilling

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, other property and equipment

Drilling rigs, other property and 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

Barnwell 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 Barnwell 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.

Asset Retirement Obligation

On October 1, 2002, Barnwell adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Barnwell’s estimated site restoration and abandonment costs of its oil and natural gas properties are capitalized as part of the carrying amount of oil and natural gas properties and depleted over the life of the related reserves. Adoption of SFAS No. 143 increased gross oil and natural gas properties by $564,000, decreased accumulated depletion by $546,000, and increased the asset retirement obligation by $1,110,000 on October 1, 2002. The liability is accreted at the end of each period through charges to oil and natural gas operating expense. If the obligation is settled for other than the carrying amount of the liability, Barnwell will recognize a gain or loss on settlement.

Prior to the adoption of SFAS No. 143, obligations for asset retirements were charged to earnings at the rate of depletion and were included in accumulated depletion. The impact of applying SFAS No. 143 on fiscal 2002 and 2001 net earnings would not have resulted in a material difference, and the asset retirement obligation would not have been materially different from the amount reported at September 30, 2003.

Following the initial implementation of SFAS No. 143, the asset retirement obligation was increased during the year ended September 30, 2003 by $39,000 to reflect obligations incurred on new wells drilled, by $85,000 for accretion of the asset retirement obligation, and by $198,000 for changes in foreign currency translation rates.

Income taxes

Earnings per common share

Basic earnings per share excludes dilution and is computed by dividing net earnings 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 years ended September 30, 2003, 2002 and 2001 are as follows:

	September 30, 2003
	Net Earnings (Numerator)		Shares (Denominator)	Per-Share Amount
Basic earnings per share	$	2,320,000	1,314,510	$	1.76
Effect of dilutive securities – common stock options	—		55,085
Diluted earnings per share	$	2,320,000	1,369,595	$	1.69

	September 30, 2002
	Net Earnings (Numerator)		Shares (Denominator)	Per-Share Amount
Basic earnings per share	$	40,000	1,313,915	$	0.03
Effect of dilutive securities – common stock options	—		43,266
Diluted earnings per share	$	40,000	1,357,181	$	0.03

	September 30, 2001
	Net Earnings (Numerator)		Shares (Denominator)	Per-Share Amount
Basic earnings per share	$	3,830,000	1,310,952	$	2.92
Effect of dilutive securities:
Common stock options	—		39,846
Convertible debentures	98,000		40,000
Diluted earnings per share	$	3,928,000	1,390,798	$	2.82

Assumed conversion of convertible debentures to 6,750 shares of common stock was excluded from the computation of diluted EPS for the period that the debentures were outstanding during the year

ended September 30, 2003 because the effect would be antidilutive (the convertible debentures were repaid in full on June 30, 2003). Assumed conversion of convertible debentures to acquire 18,000 shares of common stock at September 30, 2002 and 20,000 shares of common stock at September 30, 2001 were excluded from the computation of diluted earnings per share for the years ended September 30, 2002 and 2001, respectively, because their inclusion would have been antidilutive.

Stock-Based Compensation

Barnwell applies the provisions of Accounting Principles Board 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,” as amended by Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” Had compensation cost for stock options granted since October 1, 1995 been determined based on the fair value method of measuring stock-based compensation provisions of Statement of Financial Accounting Standards No. 123, Barnwell’s net earnings (loss) and basic and diluted earnings (loss) per share would have been as follows:

	Year ended September 30,
	2003			2002			2001
Net earnings, as reported	$	2,320,000		$	40,000		$	3,830,000
Less stock-based employee compensation expense determined under the fair value based method, net of related income taxes	(44,000		)	(95,000		)	(185,000		)
Pro-forma net earnings (loss)	$	2,276,000		$	(55,000	)	$	3,645,000

Basic Earnings (Loss) Per Share:
As reported	$	1.76		$	0.03		$	2.92
Pro forma	$	1.73		$	(0.04	)	$	2.78

Diluted Earnings (Loss) Per Share:
As reported	$	1.69		$	0.03		$	2.82
Pro forma	$	1.66		$	(0.04	)	$	2.69

Fair value measurement of the 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 full impact of stock-based compensation is not reflected in the pro-forma information above because, under Statement of Financial Accounting Standards No. 123, compensation cost is reflected over the options’ vesting periods and compensation cost for options granted prior to October 1, 1995 is not considered.

Foreign currency translation

Assets and liabilities of foreign operations and subsidiaries are translated at the year-end exchange rate and resulting translation gains or losses are accounted for in a stockholders’ equity account entitled “accumulated other comprehensive loss - foreign currency translation adjustments.”

Operating results of foreign subsidiaries are translated at average exchange rates during the period. Realized foreign currency transaction gains or losses were not material in fiscal years 2003, 2002 and 2001.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. ACCOUNTS RECEIVABLE AND CONTRACT COSTS

Accounts receivable, current, are net of allowances for doubtful accounts of $10,000 and $17,000 as of September 30, 2003 and 2002, respectively. Included in accounts receivable are contract retainage balances of $96,000 and $129,000 as of September 30, 2003 and 2002, 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,
	2003		2002
Costs incurred on uncompleted contracts	$	1,667,000	$	2,200,000
Estimated earnings	109,000		309,000
	1,776,000		2,509,000
Less billings to date	1,639,000		2,449,000
	$	137,000	$	60,000

Costs and estimated earnings on uncompleted contracts are included in the consolidated balance sheets under the following captions:

	September 30,
	2003			2002

Costs and estimated earnings in excess of billings on uncompleted contracts	$	166,000		$	174,000
Billings in excess of costs and estimated earnings on uncompleted contracts	(29,000		)	(114,000		)
	$	137,000		$	60,000

4. NOTE RECEIVABLE

Nearco, Inc.’s note payable to Barnwell was due in full on December 31, 2002. Nearco, Inc. paid all interest due and payable at December 31, 2002 of $58,000 and repaid approximately $70,000 of principal on its note payable to Barnwell in January 2003 leaving an unpaid principal balance of

$1,311,000, which is outstanding as of the date of this filing. Under the terms of the note, the note is in default and the rate of interest increased from 10% to 12% on January 1, 2003. Nearco, Inc. has paid interest on the note through September 30, 2003. Management believes that Nearco, Inc. will repay its note and any interest due in full. The note is secured by Nearco, Inc.’s entire interest in Cambridge Hawaii Limited Partnership, with its principal asset being a 49.9% interest in Kaupulehu Developments. Management estimates that the current value of Nearco, Inc.’s pledged interest in Kaupulehu Developments is significantly in excess of the combined value of its note to Barnwell and Nearco, Inc.’s $450,000 note to a third party to which Barnwell’s note is subordinated.

5. INVESTMENT IN LAND

Barnwell owns a 77.6% controlling interest in Kaupulehu Developments, a Hawaii general partnership which owns interests in leasehold land and development rights for property located approximately six miles north of the Kona International Airport in the North Kona District of the Island of Hawaii. 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, and single and multiple family residential units. These projects were developed on leasehold land acquired from Kaupulehu Developments by Kaupulehu Makai Venture, an unrelated entity that is an affiliate of Kajima Corporation of Japan.

In 1993, Kaupulehu Developments submitted a rezoning petition to the State Land Use Commission and in 1998, filed an Application for a Project District zoning ordinance and a Special Management Area Use Permit Petition with the County of Hawaii to reclassify approximately 1,100 leasehold acres of its approximately 2,100 leasehold acres zoned conservation for resort/residential development. In October 2001, the 1,100 leasehold acres received final approval for reclassification for resort/residential development.

In November 2001, Kaupulehu Developments restructured the option held by Kaupulehu Makai Venture to acquire Kaupulehu Developments’ development rights and transferred approximately 230 leasehold acres of its 1,100 acres of resort/residential zoned land to Kaupulehu Makai Venture. The development rights held by Kaupulehu Developments are for residentially zoned leasehold land within and adjacent to the Hualalai Golf Club. On December 31, 2001 and 2002, Kaupulehu Makai Venture exercised the portion of its development rights option due on those dates and paid Kaupulehu Developments $2,125,000 on both December 31, 2001 and 2002, reducing the amount of acreage under option to approximately 110 acres at September 30, 2003. Barnwell accounts for sales of development rights under option by use of the cost recovery method. Under the cost recovery method, no operating profit is recognized until cash received exceeds the cost and the estimated future costs related to development rights sold. In fiscal 2002, approximately $1,877,000 of the proceeds from the sales of development rights were applied to reduce the carrying value of the underlying investment in land. Sales of development rights were further reduced in fiscal 2002 by $128,000 of fees related to the sale, and the remaining $120,000 of sales proceeds is recorded in the Consolidated Statements of Operations for fiscal 2002 as “Sale of development rights, net.” In fiscal 2003, $1,277,000 of the proceeds from the sales of development rights were applied to reduce the carrying value of the underlying development rights recorded on the Condensed Consolidated Balance Sheets under the caption “Investment in land” to zero. Sales of development rights were further reduced in fiscal 2003 by $128,000 of fees related to the sale and the remaining $720,000 of sales proceeds is recorded in the Consolidated Statements of Operations for fiscal 2003 as “Sale of development rights, net.”

Fees were also paid to Nearco, Inc. for consulting services related to Kaupulehu Developments’ leasehold land. In fiscal 2003 and 2002, fees paid to Nearco, Inc. totaled $218,000 and $95,000, respectively. Barnwell believes the fees are fair and reasonable compensation for such services.

The remaining leasehold land interests held by Kaupulehu Developments at September 30, 2003 are for approximately 870 acres of land zoned for resort/residential development and another approximately 1,000 acres of land zoned conservation. These approximately 1,870 acres are located adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka’upulehu, between the Queen Kaahumanu Highway and the Pacific Ocean.

Kaupulehu Developments is negotiating with an independent third party interested in developing the approximately 870 acres of resort/residential leasehold acreage, of which approximately 186 acres were designated by the State Land Use Commission as preservation areas with no residential or golf course development. The independent third party and Kaupulehu Developments have made significant progress in negotiation of a revised development agreement and residential fee simple purchase prices with the lessor. Management cannot predict the outcome of these negotiations.

Attainment of zoning and development entitlements for the approximately 870 acres of leasehold land zoned for resort/residential development was determined to be substantially complete in December 2002. Accordingly, effective January 1, 2003, Barnwell no longer capitalizes expenditures related to the 870 acres. Activities to improve the leasehold land interests in the approximately 1,000 acres of conservation-zoned land have not yet commenced.

Barnwell’s cost, including capitalized interest, of leasehold land interests and development rights under option is included in the consolidated balance sheets under the caption “Investment in Land” and consisted of the following amounts:

	September 30,
	2003		2002
Leasehold land interests:
Zoned for resort/residential development	$	6,458,000	$	6,413,000
Zoned conservation	50,000		50,000
	6,508,000		6,463,000
Development rights under option	—		1,277,000
Total investment in land	$	6,508,000	$	7,740,000

6. PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION

Barnwell’s property and equipment is detailed as follows:

	Gross Property and Equipment		Accumulated Depreciation, Depletion and Amortization			Net Property and Equipment
At September 30, 2003:
Land	$	465,000	$	—		$	465,000
Oil and natural gas properties (full cost accounting)	80,863,000		(43,404,000		)	37,459,000
Drilling rigs and equipment	4,094,000		(3,841,000		)	253,000
Other property and equipment	3,077,000		(2,306,000		)	771,000
Total	$	88,499,000	$	(49,551,000	)	$	38,948,000

At September 30, 2002:
Land	$	465,000	$	—		$	465,000
Oil and natural gas properties (full cost accounting)	58,108,000		(33,796,000		)	24,312,000
Drilling rigs and equipment	4,340,000		(4,081,000		)	259,000
Other property and equipment	2,783,000		(1,991,000		)	792,000
Total	$	65,696,000	$	(39,868,000	)	$	25,828,000

Adoption of SFAS No. 143 increased gross oil and natural gas properties by $564,000, decreased accumulated depletion by $546,000, and increased the asset retirement obligation by $1,110,000 on October 1, 2002. The liability is accreted at the end of each period through charges to oil and natural gas operating expense. If the obligation is settled for other than the carrying amount of the liability, Barnwell will recognize a gain or loss on settlement.

7. LONG-TERM DEBT

Barnwell has a credit facility at the Royal Bank of Canada, a Canadian bank, for approximately $14,000,000 at September 30, 2003. Borrowings under this facility were $10,477,000 and $9,961,000 at September 30, 2003 and 2002, respectively, and are included in long-term debt. At September 30, 2003, Barnwell had unused credit available under this facility of approximately $3,500,000.

The facility is available in U.S. dollars at the London Interbank Offer Rate plus 1-3/4%, at U.S. prime plus 1%, or in Canadian dollars at Canadian prime plus 1%. A standby fee of 1% 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 2004. Subject to that review, the facility may be extended one year with no required debt repayments for one year or converted to a 2-year term loan by the bank. If the facility is converted to a 2-year term loan, Barnwell has agreed to the following repayment schedule of the then outstanding loan balance: first year of the term period – 20% (5% per quarter), and in the second year of the term period – 80% (5% per quarter for the first three quarters and 65% in the final quarter).

Barnwell 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, 2003, Barnwell paid interest at rates ranging from 2.81% to 6.00%. The weighted average interest rate on the facility at September 30, 2003 was 3.74%. The facility is collateralized by Barnwell’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 Barnwell’s Canadian oil and natural gas properties. No compensating bank balances are required for this facility.

In June 1995, Barnwell 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 Barnwell. The notes were payable in 20 consecutive equal quarterly installments beginning October 1998. Interest was payable quarterly at a rate adjusted each quarter to the greater of 10% per annum or 1% over the prime rate of interest. Barnwell paid interest on these convertible notes at an average rate of 10.00% per annum in 2003, 10.00% per annum in 2002 and 10.28% per annum in 2001. The notes were unsecured and convertible at any time at the holder’s option into shares of Barnwell’s common stock at a price of $20.00 per share, subject to adjustment for certain events, and were redeemable, at the option of Barnwell, without premium. In December 2001, approximately $71,000 of convertible debentures, including accrued interest, were converted to 3,558 shares of Barnwell’s stock at $20 per share; these shares were issued from Barnwell’s treasury stock. The remaining convertible notes were repaid in full on June 30, 2003.

Barnwell capitalizes interest on costs related to its investment in land. Interest costs for the years ended September 30, 2003, 2002 and 2001 are summarized as follows:

	2003		2002		2001
Interest costs incurred	$	487,000	$	498,000	$	665,000
Less interest costs capitalized on investment in land	45,000		202,000		278,000
Interest expense	$	442,000	$	296,000	$	387,000

8. TAXES ON INCOME

The components of earnings before income taxes are as follows:

	Year ended September 30,
	2003			2002			2001
Earnings (loss) before income taxes in:
United States	$	(2,499,000	)	$	(1,811,000	)	$	(1,586,000	)
Canada	9,004,000			3,412,000			10,991,000
	$	6,505,000		$	1,601,000		$	9,405,000

The components of the provision for income taxes related to the above earnings are as follows:

	Year ended September 30,
	2003			2002		2001
Current provision:
United States – Federal	$	143,000		$	21,000	$	160,000
Canadian	3,333,000			1,135,000		5,261,000
Total current	3,476,000			1,156,000		5,421,000

Deferred provision:
United States	(191,000		)	42,000		44,000
Canadian	900,000			363,000		110,000
Total deferred	709,000			405,000		154,000
	$	4,185,000		$	1,561,000	$	5,575,000

Barnwell’s Canadian deferred tax provision for the years ended September 30, 2003, 2002 and 2001 were primarily due to Barnwell’s Canadian tax deductions related to its oil and natural gas properties exceeding Barnwell’s depletion of its oil and natural gas properties for book purposes.

A reconciliation between the reported provision for income taxes and the amount computed by multiplying the earnings before income taxes by the U.S. federal tax rate of 35% is as follows:

	Year ended September 30,
	2003			2002			2001
Tax expense computed by applying statutory rate	$	2,277,000		$	560,000		$	3,292,000

Effect of the foreign tax provision on the total tax provision	1,967,000			1,060,000			2,264,000
State net operating losses (generated) utilized	(39,000		)	(22,000		)	18,000
Other	(20,000		)	(37,000		)	1,000
	$	4,185,000		$	1,561,000		$	5,575,000

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at September 30, 2003 and 2002 are as follows:

	2003			2002
Deferred income tax assets:
U.S. tax effect of deferred Canadian taxes	$	3,139,000		$	2,391,000
Foreign tax credit carryforwards	5,286,000			4,313,000
Tax basis in investment in land in excess of book basis	1,535,000			1,263,000
Write-down of assets not deducted for tax	178,000			355,000
Alternative minimum tax credit carryforwards	514,000			372,000
State of Hawaii net operating loss carryforwards	304,000			264,000
Expenses accrued for books but not for tax	801,000			547,000
Asset retirement obligation	487,000			—
Other	6,000			—
Total gross deferred tax assets	12,250,000			9,505,000
Less-valuation allowance	(9,385,000		)	(7,595,000		)
Net deferred income tax assets	2,865,000			1,910,000

Deferred income tax liabilities:
Property and equipment accumulated tax depreciation and depletion in excess of book under Canadian tax law	(9,233,000		)	(7,033,000		)
Property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law	(2,524,000		)	(1,768,000		)
Other	(336,000		)	(328,000		)
Total deferred income tax liabilities	(12,093,000		)	(9,129,000		)

Net deferred income tax liability	$	(9,228,000	)	$	(7,219,000	)

The total valuation allowance increased $1,790,000, $730,000 and $1,849,000, for the years ended September 30, 2003, 2002 and 2001, respectively. The increases relate primarily to foreign tax credit carryforwards for which it is more likely than not that such carryforwards will not be utilized to reduce Barnwell’s U.S. tax obligation.

Net deferred tax assets of $2,865,000 consists primarily of $1,535,000 of deferred tax assets related to the excess of the cost basis of investment in land for tax purposes over the cost basis of investment in land for book purposes. This deferred tax asset will be realized through the deduction of the cost basis of investment in land for tax purposes against future proceeds from sales of interests in leasehold land and land development rights. The amount of deferred income tax assets considered realizable may be reduced if estimates of future taxable income are reduced.

At September 30, 2003, Barnwell had alternative minimum tax credit carryforwards of $514,000 which are available to reduce future U.S. federal regular income taxes, if any, over an indefinite period.

9. PENSION PLAN

Barnwell sponsors a noncontributory defined benefit pension plan covering substantially all of its U.S. employees, with benefits based on years of service and the employee’s highest consecutive five-year average earnings. Barnwell’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, 2003 were invested as follows: 7% in cash and cash equivalents, 34% listed government mortgages and 59% 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,
	2003			2002
Change in Benefit Obligation
Benefit obligation at beginning of year	$	2,753,000		$	2,197,000
Service cost	128,000			94,000
Interest cost	171,000			161,000
Actuarial loss	182,000			421,000
Benefits paid	(148,000		)	(120,000		)

Benefit obligation at end of year	3,086,000			2,753,000

Change in Plan Assets
Fair value of plan assets at beginning of year	1,855,000			2,146,000
Actual return on plan assets	228,000			(171,000		)
Employer contribution	92,000			—
Benefits paid	(148,000		)	(120,000		)

Fair value of plan assets at end of year	2,027,000			1,855,000

Funded status	(1,059,000		)	(898,000		)
Unrecognized prior service cost	12,000			18,000
Unrecognized actuarial loss	723,000			636,000

Accrued benefit cost	$	(324,000	)	$	(244,000	)

	2003		2002
Assumptions as of September 30,
Discount rate	6.00	%	6.50	%
Expected return on plan assets	8.00	%	8.00	%
Rate of compensation increase	5.00	%	5.00	%

	Year ended September 30,
	2003			2002			2001
Net Periodic Benefit Cost for the Year
Service cost	$	128,000		$	94,000		$	94,000
Interest cost	171,000			161,000			152,000
Expected return on plan assets	(144,000		)	(167,000		)	(195,000		)
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 loss (gain)	12,000			—			(13,000		)

Net periodic benefit cost	$	172,000		$	93,000		$	43,000

10. STOCK OPTIONS

In March 1995, Barnwell granted 20,000 stock options to an officer of Barnwell 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. Barnwell recognized $101,000 and $6,000 of compensation cost relating to these options in the years ended September 30, 2003 and 2002, respectively. No compensation cost was recognized for these options in the year ended September 30, 2001.

In June 1998, Barnwell granted 30,000 stock options to an officer of Barnwell’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. Barnwell recognized $125,000, $43,000 and $38,000 of compensation costs relating to these options in the years ended September 30, 2003, 2002 and 2001, respectively.

In December 1999, Barnwell granted qualified stock options to certain employees of Barnwell to acquire 68,000 shares and 29,000 shares of Barnwell’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 was recognized for these options for the years ended September 30, 2003, 2002 and 2001. 36,000 shares were available for grant under this plan at September 30, 2003.

During the year ended September 30, 2002, 3,000 options to acquire Barnwell’s stock at $11.875 per share were forfeited. During the year ended September 30, 2001, 1,000 options to acquire Barnwell’s stock at $11.875 per share were exercised.

Stock options at September 30, 2003 were as follows:

	Options outstanding				Options exercisable
Range of exercise prices	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number of Shares	Weighted Average Exercise Price
$11.875 - $15.625	123,000	4.6 years	$	13.07	99,750	$	13.26
$19.625	20,000	1.4 years	$	19.63	20,000	$	19.63

$11.875 - $19.625	143,000	4.2 years	$	13.99	119,750	$	14.32

Stock options at September 30, 2002 were as follows:

	Options outstanding				Options exercisable
Range of exercise prices	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number of Shares	Weighted Average Exercise Price
$11.875 - $15.625	123,000	5.6 years	$	13.07	70,500	$	13.40
$19.625	20,000	2.4 years	$	19.63	20,000	$	19.63

$11.875 - $19.625	143,000	5.2 years	$	13.99	90,500	$	14.77

Stock options at September 30, 2001 were as follows:

	Options outstanding				Options exercisable
Range of exercise prices	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number of Shares	Weighted Average Exercise Price
$11.875 - $15.625	126,000	6.7 years	$	13.04	41,250	$	13.72
$19.625	20,000	3.4 years	$	19.63	20,000	$	19.63

$11.875 - $19.625	146,000	6.2 years	$	13.94	61,250	$	15.65

In December 2001, approximately $71,000 of convertible debentures, including accrued interest, was converted to 3,558 shares of Barnwell’s stock at $20 per share; these shares were issued from Barnwell’s treasury stock. During the year ended September 30, 2001, Barnwell repurchased 1,000 shares of its common stock from an employee arising from the exercise of stock options for $19,750 at the then prevailing market price under a March 2000 stock buyback plan authorizing the repurchase of up to 100,000 shares. There were no conversions or repurchases of Barnwell’s stock in the year ended September 30, 2003. Barnwell 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, 2003, Barnwell could purchase an additional 93,000 shares under the March 2000 repurchase authorization.

11. COMMITMENTS AND CONTINGENCIES

Barnwell has committed to compensate its Vice President of Canadian Operations pursuant to an incentive compensation plan, the value of which directly relates to Barnwell’s oil and natural gas segment’s net income and the change in the value of Barnwell’s oil and gas reserves since 1998 with adjustments for changes in natural gas and oil prices and subject to other terms and conditions. Barnwell recognized $166,000 of compensation expense pursuant to this incentive plan in fiscal 2003. In fiscal 2002, Barnwell recognized a $48,000 benefit, a reduction in compensation expense, pursuant to this incentive plan; there was no compensation expense or benefit recognized in fiscal 2001.

Barnwell has also committed to compensate certain Canadian personnel pursuant to an incentive compensation plan, the value of which directly relates to Barnwell’s oil and natural gas segment’s net income and the value of Barnwell’s oil and gas reserves discovered, commencing in fiscal 2002, for projects developed by such personnel. Barnwell recognized approximately $80,000 of compensation costs pursuant to this plan in fiscal 2003, of which approximately $30,000 was expensed and approximately $50,000, the portion related to in-house geologists, was capitalized as oil and natural gas capital expenditures. Barnwell recognized no compensation expense pursuant to this plan in fiscal 2002.

Barnwell has several non-cancelable operating leases for office space and leasehold land. Rental expense was $474,000 in 2003, $467,000 in 2002 and $460,000 in 2001. Barnwell is committed under these leases for minimum rental payments summarized by fiscal year as follows: 2004 - $443,000, 2005 - $363,000, 2006 - $363,000, 2007 - $371,000, 2008 - $372,000 and thereafter through 2026 an aggregate of $2,678,000. The lease payments for land are subject to renegotiation after December 31, 2005; the future rental payment disclosures above assume the minimum lease payments for land in effect at December 31, 2005 remain unchanged through 2025, the end of the lease term. In December 2003, Barnwell purchased the space it was leasing for its corporate office in Honolulu, Hawaii. The future minimum rental payments reflected above have been adjusted accordingly.

Barnwell is occasionally involved in routine litigation and is subject to governmental and regulatory controls that are incidental to the ordinary course of business. Barnwell’s management believes that all claims and litigation involving Barnwell are not likely to have a material adverse effect on its financial statements taken as a whole.

12. SEGMENT AND GEOGRAPHIC INFORMATION

Barnwell operates three segments: exploring for, developing, producing and selling oil and natural gas (oil and natural gas); investing in leasehold land in Hawaii (land investment); and drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling). Barnwell’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.

Barnwell 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,
	2003			2002			2001
Revenues:
Oil and natural gas	$	19,350,000		$	11,320,000		$	19,870,000
Contract drilling	2,050,000			3,480,000			3,290,000
Land investment	1,220,000			220,000			—
Other	720,000			598,000			601,000
Total before interest income	23,340,000			15,618,000			23,761,000
Interest income	340,000			262,000			329,000
Total revenues	$	23,680,000		$	15,880,000		$	24,090,000

Depreciation, depletion and amortization:
Oil and natural gas	$	4,026,000		$	3,315,000		$	3,416,000
Contract drilling	88,000			118,000			116,000
Other	219,000			215,000			222,000
Total	$	4,333,000		$	3,648,000		$	3,754,000

Operating profit (loss) (before general and administrative expenses):
Oil and natural gas	$	11,132,000		$	4,897,000		$	12,945,000
Contract drilling	34,000			541,000			268,000
Land investment, net of minority interest	669,000			—			(8,000		)
Other	501,000			483,000			379,000
Total	12,336,000			5,921,000			13,584,000
General and administrative expenses, net of minority interest	(5,729,000		)	(4,286,000		)	(4,121,000		)
Interest income	340,000			262,000			329,000
Interest expense	(442,000		)	(296,000		)	(387,000		)
Earnings before income taxes	$	6,505,000		$	1,601,000		$	9,405,000

Capital expenditures:
Oil and natural gas	$	11,059,000		$	4,581,000		$	4,240,000
Land investment	45,000			944,000			5,954,000
Contract drilling	72,000			77,000			84,000
Other	158,000			42,000			180,000
Total	$	11,334,000		$	5,644,000		$	10,458,000

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 $0.90 in fiscal 2003, $0.71 in fiscal 2002 and $0.70 in fiscal 2001. The higher depletion rate in fiscal 2003 is the result of increased costs of finding and developing proven reserves, as compared to prior years.

ASSETS BY SEGMENT:

	September 30,
	2003				2002				2001
Oil and natural gas (1)	$	40,338,000	77	%	$	27,113,000	66	%	$	24,973,000	57	%
Contract drilling (2)	1,380,000		3	%	1,931,000		5	%	2,128,000		5	%
Land investment (2)	6,508,000		12	%	7,740,000		19	%	8,677,000		20	%
Other:
Cash and cash equivalents	1,648,000		3	%	1,489,000		4	%	5,154,000		12	%
Corporate and other	2,463,000		5	%	2,401,000		6	%	2,739,000		6	%
Total	$	52,337,000	100	%	$	40,674,000	100	%	$	43,671,000	100	%

(1) Primarily located in the Province of Alberta, Canada.
(2) Located in Hawaii.

LONG-LIVED ASSETS BY GEOGRAPHIC AREA:

	September 30,
	2003				2002				2001
United States	$	7,640,000	17	%	$	8,962,000	27	%	$	10,075,000	30	%
Canada	37,816,000		83	%	24,606,000		73	%	23,494,000		70	%
Total	$	45,456,000	100	%	$	33,568,000	100	%	$	33,569,000	100	%

REVENUE BY GEOGRAPHIC AREA:

	Year ended September 30,
	2003		2002		2001
United States	$	3,420,000	$	3,766,000	$	3,397,000
Canada	19,920,000		11,852,000		20,364,000
Total (excluding interest income)	$	23,340,000	$	15,618,000	$	23,761,000

13. FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts of cash and cash equivalents, accounts receivable, notes receivable, accounts payable and notes payable approximate fair value because of the short maturity of these instruments. The carrying value of long-term debt approximates fair value as the terms approximate current market terms for similar debt instruments of comparable risk and maturities.

The differences between the estimated fair values and carrying values of Barnwell’s financial instruments are not material.

14. CONCENTRATIONS OF CREDIT RISK

Barnwell’s oil and natural gas segment derived 64% of its oil and natural gas revenues in fiscal 2003 from four individually significant customers, ProGas Limited, Coral Energy Canada Inc., Plains Marketing Canada, L.P., and Petrogas Marketing Ltd. At September 30, 2003, Barnwell had a total of $1,100,000 in receivables from these four customers. In fiscal 2002 Barnwell derived 76% of its oil and natural gas revenues from five individually significant customers.

Barnwell’s contract drilling subsidiary derived 66%, 70% and 49% of its contract drilling revenues in fiscal 2003, 2002 and 2001, respectively, pursuant to Federal, State of Hawaii and county contracts. At September 30, 2003, Barnwell had accounts receivables from the Federal, State of Hawaii and county entities totaling approximately $177,000. Barnwell has lien rights on wells drilled and pumps installed for Federal, State of Hawaii, and county governments.

Historically, Barnwell 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, 2003.

15. 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,
	2003			2002			2001
Increase (decrease) from changes in:

Receivables	$	548,000		$	(622,000	)	$	80,000
Costs and estimated earnings in excess of billings on uncompleted contracts	8,000			206,000			116,000
Other current assets	210,000			(338,000		)	(214,000		)
Accounts payable	(84,000		)	148,000			551,000
Accrued liabilities	679,000			21,000			667,000
Billings in excess of costs and estimated earnings on uncompleted contracts	(85,000		)	(94,000		)	(142,000		)
Payable to joint interest owners	(198,000		)	403,000			(436,000		)
Income taxes payable	401,000			(2,311,000		)	1,790,000
Increase (decrease) from changes in current assets and liabilities	$	1,479,000		$	(2,587,000	)	$	2,412,000

Supplemental disclosure of cash flow information:

Cash paid during the year for:
Interest (net of amounts capitalized)	$	454,000		$	303,000		$	423,000

Income taxes	$	2,961,000		$	3,812,000		$	3,705,000

Supplemental disclosure of Non-cash Investing and Financing Activities:

Barnwell accrued an additional $1,518,000 in capital expenditures at September 30, 2003, as compared to September 30, 2002; accordingly, capital expenditures for fiscal 2003, including accrued capital expenditures, totaled $11,334,000. Incremental accrued capital expenditures in fiscal 2002 and 2001 were not material.

On October 1, 2002, net oil and natural gas properties and the asset retirement obligation increased $1,110,000 as a result of adoption of Statement of Financial Accounting Standards No. 143. During the remainder of fiscal 2003, net oil and natural gas properties increased $39,000 to reflect asset retirement obligations incurred on new wells drilled and by $191,000 for changes in foreign currency translation rates; the asset retirement obligation increased $39,000 to reflect asset retirement obligations incurred on new wells drilled, $85,000 for accretion of the asset retirement obligation, and by $198,000 for changes in foreign currency translation rates.

In April 2001, Barnwell purchased 55.2% of Cambridge Hawaii Limited Partnership for $5,000,000. $2,791,000 was paid upon closing, and the remaining balance of $2,209,000 was financed by non-interest bearing notes payable. The $2,209,000 of notes payable was paid in fiscal 2002.

16. SUBSEQUENT EVENTS

In December 2003, Barnwell declared a dividend of $0.20 per share payable January 6, 2004 to stockholders of record as of December 22, 2003.

In December 2003, Barnwell purchased the space it was leasing for its corporate offices in Honolulu, Hawaii for $1,104,000. This purchase was funded by $221,000 of cash and long-term debt of $883,000. The long-term debt is payable in monthly principal payments of approximately $3,000, plus interest at the three-month London Interbank Offer Rate, 1.25% at the time of closing, plus 2%, and is due in full in December 2006. The space purchased has 4,662 useable square feet on the 28th floor of a 31-story office building built in 1993 in downtown Honolulu.

As these transactions were effective in November or December 2003, their impact will be reflected in Barnwell’s quarterly financial statements for the period ended December 31, 2003.

17. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)

The following tables summarize information relative to Barnwell’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 & Associates Ltd., summarizes changes in the estimates of Barnwell’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 all in Canada:

	OIL (Barrels)		GAS (MCF)
Balance at September 30, 2000	1,781,000		29,796,000

Decrease in royalty rates*	104,000		2,482,000
Revisions of previous estimates	(111,000	)	(1,695,000	)
Extensions, discoveries and other additions	34,000		1,057,000
Less production	(272,000	)	(3,269,000	)
Balance at September 30, 2001	1,536,000		28,371,000

Revisions of previous estimates	184,000		985,000
Extensions, discoveries and other additions	49,000		1,087,000
Less production	(242,000	)	(3,277,000	)
Balance at September 30, 2002	1,527,000		27,166,000

Revisions of previous estimates	(35,000	)	(1,035,000	)
Extensions, discoveries and other additions	136,000		4,683,000
Less production	(227,000	)	(3,175,000	)
Balance at September 30, 2003	1,401,000		27,639,000

* The deduction or addition of reserve units due to 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 lower at September 30, 2001, as compared to September 30, 2000, significantly less reserves were deducted for royalty volumes at September 30, 2001, as compared to September 30, 2000.

	OIL (Barrels)	GAS (MCF)
Proved producing reserves at:
September 30, 2000	1,508,000	20,594,000
September 30, 2001	1,327,000	21,847,000
September 30, 2002	1,303,000	19,612,000
September 30, 2003	1,262,000	21,463,000

(B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities

	September 30,
	2003		2002		2001
Proved properties	$	77,913,000	$	56,959,000	$	51,668,000
Unproved properties	2,950,000		1,149,000		2,152,000
Total capitalized costs	80,863,000		58,108,000		53,820,000
Accumulated depletion and depreciation	43,404,000		33,796,000		30,663,000
Net capitalized costs	$	37,459,000	$	24,312,000	$	23,157,000

	Year ended September 30,
	2003		2002		2001
Acquisition of properties:
Unproved, Canadian	$	715,000	$	262,000	$	468,000
Proved, Canadian	$	635,000	—		—

Exploration costs:
Canadian	$	2,567,000	$	1,007,000	$	431,000
United States	—		—		172,000
	$	2,567,000	$	1,007,000	$	603,000

Development costs, Canadian	$	7,142,000	$	3,312,000	$	3,169,000

(D) The Results of Operations of Barnwell’s Oil and Natural Gas Producing Activities

	Year ended September 30,
	2003		2002		2001
Gross revenues	26,234,000		14,896,000		27,695,000
Royalties, net of credit	6,884,000		3,576,000		7,825,000
Net revenues	19,350,000		11,320,000		19,870,000
Production costs	4,192,000		3,108,000		3,509,000
Depletion and depreciation	4,026,000		3,315,000		3,416,000
Pre-tax results of operations*	11,132,000		4,897,000		12,945,000
Estimated income tax expense	5,665,000		2,450,000		6,398,000
Results of operations*	$	5,467,000	$	2,447,000	$	6,547,000

* 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 Statement of Financial Accounting Standards No. 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 Barnwell 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,
	2003			2002			2001
Future cash inflows	$	141,809,000		$	101,448,000		$	82,347,000

Future production costs	(37,439,000		)	(30,537,000		)	(28,883,000		)

Future development costs	(1,231,000		)	(1,263,000		)	(1,216,000		)
Future net cash flows before income taxes	103,139,000			69,648,000			52,248,000

Future income tax expenses	(32,604,000		)	(17,442,000		)	(18,783,000		)

Future net cash flows	70,535,000			52,206,000			33,465,000

10% annual discount for timing of cash flows	(20,998,000		)	(19,587,000		)	(12,192,000		)

Standardized measure of estimated discounted future net cash flows	$	49,537,000		$	32,619,000		$	21,273,000

Changes in the Standardized Measure of Estimated Discounted Future Net Cash Flows

	Year ended September 30,
	2003			2002			2001

Beginning of year	$	32,619,000		$	21,273,000		$	42,500,000

Sales of oil and natural gas produced, net of production costs	(15,107,000		)	(8,210,000		)	(16,281,000		)

Net changes in prices and production costs, net of royalties and wellhead taxes	18,878,000			12,469,000			(25,205,000		)

Extensions and discoveries	12,673,000			1,989,000			1,438,000

Purchases of properties	971,000			—			—

Revisions of previous quantity estimates	771,000			2,657,000			29,000

Net change in Canadian dollar translation rate	4,441,000			(41,000		)	(1,640,000		)

Changes in the timing of future production and other	(711,000		)	(1,224,000		)	(1,152,000		)

Net change in income taxes	(7,680,000		)	1,957,000			18,178,000

Accretion of discount	2,682,000			1,749,000			3,406,000

Net change	16,918,000			11,346,000			(21,227,000		)

End of year	$	49,537,000		$	32,619,000		$	21,273,000

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Barnwell’s primary market risk exposure is interest rate risk. Barnwell’s exposure to market risk for changes in interest rates relates to its debt obligations under a floating interest rate loan. Assuming variable rate debt at September 30, 2003, a change of one hundred basis points in interest rates would impact annual net interest payments by $105,000. Barnwell does not use derivative financial instruments to manage interest rate risk.

Item 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 8A. Controls and Procedures

As of September 30, 2003, an evaluation was carried out by Barnwell’s Chief Executive Officer and Chief Financial Officer of the effectiveness of Barnwell’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that Barnwell’s disclosure controls and procedures are effective to ensure that information required to be disclosed by Barnwell in reports that it files or submits under the Securities and Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Act of 1934 and the rules thereunder. Subsequent to the date of their evaluation, there were no significant changes in Barnwell’s internal controls or in other factors that could significantly affect the disclosure controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

PART III

Item 9. Directors, Executive Officers, Promoters and Control Persons, Compliance With Section 16(a) of the Exchange Act

The information required is omitted pursuant to General Instruction E.3. of Form 10-KSB, since the Registrant will file its definitive proxy statement for the 2003 Annual Meeting of Stockholder no later than 120 days after the close of its fiscal year ended September 30, 2003, which proxy statement is incorporated herein by reference.

Item 10. Executive Compensation

Item 11. Security Ownership of Certain Beneficial Owners and Management

Equity Compensation Plan Information

The following table provides information about Barnwell’s common stock that may be issued upon exercise of options and rights under all of Barnwell’s existing equity compensation plans as of September 30, 2003:

Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted- average price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	93,000	$	12.25	36,000
Equity compensation plans not approved by security holders	50,000	$	17.23	—
Total	143,000	$	13.99	36,000

Equity compensation plans not approved by security holders are comprised of the following plans:

Item 12. Certain Relationships and Related Transactions

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, 2003 and 2002

Consolidated Statements of Operations – for the three years ended September 30, 2003

Consolidated Statements of Cash Flows – for the three years ended September 30, 2003

Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the three years ended September 30, 2003

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

	None.

(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.(5)

	No. 21	List of Subsidiaries.(6)

	No. 31.1	Section 302 Certification by Morton H. Kinzler, Chief Executive Officer

	No. 31.2	Section 302 Certification by Russell M. Gifford, Chief Financial Officer

	No. 32	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

(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, 2000.

(6) Incorporated by reference to Form 10-KSB for the year ended September 30, 1998.

Item 14. Principal Accountant Fees and Services

SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Act, the registrant has 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,
	Treasurer and Secretary
Date:			December 23, 2003

In accordance with Exchange Act the report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/Morton H. Kinzler
MORTON H. KINZLER
Chief Executive Officer and
Chairman of the Board
Date: December 23, 2003

/s/Martin Anderson			/s/Daniel Jacobson
MARTIN ANDERSON, Director			DANIEL JACOBSON, Director
Date: December 23, 2003			Date: December 23, 2003

/s/Murray C. Gardner			/s/Terry Johnston
MURRAY C. GARDNER, Director			TERRY JOHNSTON, Director
Date: December 23, 2003			Date: December 23, 2003

			/s/Alexander C. Kinzler
ERIK HAZELHOFF-ROELFZEMA			ALEXANDER C. KINZLER
Director			President, Chief Operating Officer,
			General Counsel and Director
			Date: December 23, 2003

/s/Alan D. Hunter			/s/Russell M. Gifford
ALAN D. HUNTER, Director			RUSSELL M. GIFFORD
Date: December 23, 2003			Executive Vice President,
			Chief Financial Officer, Treasurer
			Secretary and Director
			Date: December 23, 2003