Edgar Filing: BARNWELL INDUSTRIES INC

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the fiscal year ended September 30, 2006

		or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-5103

BARNWELL INDUSTRIES, INC.
(Exact name of registrant as specified 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)

Registrant’s telephone number, including area code: (808) 531-8400

Securities registered pursuant to Section 12(b) of the Act:

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

o Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

o Yes x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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.		x Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not 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-K or any amendment to this Form 10-K.		o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes x No

The aggregate market value of the voting common stock held by non-affiliates of the registrant, computed by reference to the closing price of a share of common stock on March 31, 2006 (the last business day of the registrant’s most recently completed second fiscal quarter) was $70,195,000.

As of December 20, 2006 there were 8,169,060 shares of common stock outstanding.

Documents Incorporated by Reference

1. Proxy statement to be forwarded to shareholders on or about January 18, 2007 is incorporated by reference in Part III hereof.

TABLE OF CONTENTS

PART I
Discussion of Forward-Looking Statements
Item 1.	Business
Item 1A.	Risk Factors
Item 2.	Properties
Item 3.	Legal Proceedings

PART II
Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.	Controls and Procedures
Item 9B.	Other Information

PART III
Item 10.	Directors and Executive Officers of the Registrant
Item 11.	Executive Compensation
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.	Certain Relationships and Related Transactions
Item 14.	Principal Accounting Fees and Services

PART IV
Item 15.	Exhibits, Financial Statement Schedules

PART I

CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION

FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This Form 10-K, and the documents incorporated herein by reference, contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. A forward-looking statement is one which is based on current expectations of future events or conditions and does not relate to historical or current facts. These statements include various estimates, forecasts, projections of Barnwell Industries, Inc.’s (referred to herein together with its subsidiaries as “Barnwell,” “we,” “our,” “us” or “the Company”) future performance, statements of Barnwell’s plans and objectives and other similar statements. Forward-looking statements include phrases such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates,” “assumes,” “projects,” “may,” “will,” “will be,” “should,” or similar expressions. Although Barnwell believes that its current expectations are based on reasonable assumptions, it cannot assure that the expectations contained in such forward-looking statements will be achieved. Forward-looking statements involve risks, uncertainties and assumptions which could cause actual results to differ materially from those contained in such statements. Investors should not place undue reliance on these forward-looking statements, as they speak only as of the date hereof, and Barnwell expressly disclaims any obligation or undertaking to publicly release any updates or revisions to any forward-looking statements contained herein.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are domestic and international general economic conditions, such as recessionary trends and inflation; domestic and international political, legislative, economic, regulatory and legal actions, including changes in the policies of the Organization of Petroleum Exporting Countries or other developments involving or affecting oil-producing countries; 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; interest costs, restrictions on production, restrictions on imports and exports, the maintenance of specified reserves, tax increases and retroactive tax claims, expropriation of property, cancellation of contract rights, environmental protection controls, environmental compliance requirements and laws pertaining to workers’ health and safety; the condition of Hawaii’s real estate market, including 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, the condition of Hawaii’s tourism industry and the level of confidence in Hawaii’s economy; levels of land development activity in Hawaii; levels of demand for water well drilling and pump installation in Hawaii; the potential liability resulting from pending or future litigation; the company’s acquisition or disposition of assets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” in this Form 10-K, in other portions of this Form 10-K, in the Notes to Consolidated Financial Statements, and in other documents filed by Barnwell with the Securities and Exchange Commission (“SEC”). In addition, unpredictable or unknown factors not discussed in this report could also cause actual results to materially and adversely differ from those discussed in the forward-looking statements.

Unless otherwise indicated, all references to “dollars” in this Form 10-K are to United States dollars.

Item 1. Business

Overview

Barnwell enjoyed its 50th year of operations in fiscal 2006, having been incorporated in Delaware in 1956. Barnwell has the following three principal business segments:

· Oil and Natural Gas Segment. Barnwell engages in oil and natural gas exploration, development, production and sales, primarily in Canada.

· Land Investment Segment. Barnwell invests in leasehold interests in real estate in Hawaii.

· Contract Drilling Segment. Barnwell provides well drilling services, contract labor servicing for geothermal well drilling and workovers, and water pumping system installation and repair in Hawaii.

Barnwell’s oil and natural gas activities comprise its largest business segment. Approximately 66% of Barnwell’s revenues for the fiscal year ended September 30, 2006 was attributable to its oil and natural gas activities. Barnwell’s land investment segment revenues accounted for 21% of fiscal 2006 revenues; Barnwell’s contract drilling activities accounted for 10% of fiscal 2006 revenues; and other revenues comprised 3% of fiscal 2006 revenues. Approximately 98% of Barnwell’s capital expenditures for the fiscal year ended September 30, 2006 was attributable to oil and natural gas activities and 2% was applicable to its other activities.

Oil and Natural Gas Segment

Overview

Barnwell’s wholly-owned subsidiary, Barnwell of Canada, Limited (“Barnwell of Canada”), is involved in the acquisition, exploration and development of oil and natural gas properties. Barnwell of Canada 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.

Operations

Barnwell’s investments in oil and natural gas properties consist of investments in Canada, principally in the Province of Alberta, with minor holdings in the Provinces of 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 senior management and independent consultants as necessary. In fiscal 2006, Barnwell participated in exploratory and developmental operations in the Canadian Province of Alberta, although Barnwell does not limit its consideration of exploratory and developmental operations to this area.

The Province of Alberta determines its royalty share of natural gas and of oil by using reference prices that average all natural gas sales and oil sales, respectively, in Alberta. Royalty rates are calculated on a sliding scale basis, increasing as prices increase up to a maximum royalty rate of 35%. Additionally, Barnwell pays gross overriding royalties and leasehold royalties on a portion of its natural gas and oil sales to parties other than the Province of Alberta.

In fiscal 2006 and 2005, the weighted-average rate of all royalties paid on all of Barnwell’s natural gas was approximately 28% and 27%, respectively. 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, was approximately 30% and 31% in fiscal 2006 and 2005, respectively. The increase in royalty rate on all properties was primarily due to higher average natural gas prices. The increase was partially offset by the lower average royalty rate at Dunvegan in fiscal 2006 as compared to fiscal 2005 which was due to royalty credits received from the Alberta Department of Energy for prior year capital and operating expenditures incurred by Barnwell on the Dunvegan property for the processing of natural gas.

In fiscal 2006 and 2005, the weighted-average royalty rate paid on oil was approximately 23% and 24%, respectively. The decrease in the weighted-average royalty rate on oil was primarily due to a higher percentage of Barnwell’s fiscal 2006 production of oil coming from newer wells where royalties are assessed at a lower rate than on older wells.

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. 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 2006, Barnwell participated in the drilling of 40 gross development wells and seven gross exploratory wells, of which management believes 40 should be capable of production and seven are dry holes.

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, 2006, 2005, and 2004 in which Barnwell participated:

	Productive		Productive		Total Productive
	Oil Wells		Gas Wells		Wells		Dry Holes		Total Wells
	Exp.	Dev.	Exp.	Dev.	Exp.	Dev.	Exp.	Dev.	Exp.	Dev.
2006
Gross*	1.0	4.0	2.0	33.0	3.0	37.0	4.0	3.0	7.0	40.0
Net*	0.4	1.1	0.7	9.0	1.1	10.1	1.3	1.0	2.4	11.1

2005
Gross*	1.0	7.0	4.0	57.0	5.0	64.0	5.0	6.0	10.0	70.0
Net*	0.3	1.7	1.0	7.3	1.3	9.0	1.6	1.6	2.9	10.6

2004
Gross*	3.0	5.0	6.0	120.0	9.0	125.0	7.0	3.0	16.0	128.0
Net*	0.9	0.3	2.1	7.9	3.0	8.2	3.1	0.3	6.1	8.5

* 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 one 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.

Barnwell invested $25,949,000 in oil and natural gas properties during fiscal 2006, of which $3,273,000 (13%) was for acquisition of leases and lease rentals, $1,870,000 (7%) was for geological and geophysical costs, $15,878,000 (61%) was for intangible drilling costs, $4,328,000 (17%) was for production equipment, and $600,000 (2%) was for future site restoration and abandonment and other costs. The major areas of investments in fiscal 2006 were in the Progress, Pouce Coupe South, Simonette, Dunvegan, Swalwell, Josephine, Bonanza/Balsam, and Doris areas of Alberta.

The Dunvegan Unit, in which Barnwell holds an 8.9% working interest, is Barnwell’s principal oil and natural gas property and is located in Alberta, Canada. At September 30, 2006, the Dunvegan Unit had 197 producing natural gas wells. In fiscal 2006, Barnwell participated in the drilling of 12 gross (1.1 net) development gas wells in the Dunvegan area, all of which were successful. Total capital expenditures at Dunvegan were $1,781,000 in fiscal 2006 as compared to $4,299,000 and $3,670,000 in fiscal 2005 and 2004, respectively. Barnwell expects that fiscal 2007 capital expenditures at Dunvegan will decline slightly from fiscal 2006’s level with the anticipated drilling of 10 gross (0.9 net) development gas wells.

Capital expenditures totaled $917,000 in the Doris area in fiscal 2006 as compared to $2,023,000 in fiscal 2005. One gross (0.5 net) well was drilled in fiscal 2006 which is currently considered successful. In the Doris area Barnwell acquired oil and natural gas rights in 3,840 gross (2,240 net) acres of undeveloped land in fiscal 2006. At September 30, 2006 Barnwell’s average working interest in its productive wells in the Doris area was 46%. Barnwell expects to drill two to four gross wells in the Doris area in fiscal 2007.

Capital expenditures totaled $850,000 in the Bonanza/Balsam area in fiscal 2006 as compared to $1,987,000 in fiscal 2005. Two gross (0.6 net) wells were drilled in fiscal 2006 which were

successful and tied in and producing at September 30, 2006. In the Bonanza/Balsam area Barnwell acquired oil and natural gas rights in 1,920 gross (940 net) acres of undeveloped land in fiscal 2006. At September 30, 2006 Barnwell’s average working interest in its productive wells in the Bonanza/Balsam area was 31%.

Capital expenditures totaled $6,094,000 in the Progress area in fiscal 2006 as compared to $1,670,000 in fiscal 2005. Three gross (1.7 net) wells were drilled in fiscal 2006 of which one gross (0.4 net) well was successful and tied in and producing at September 30, 2006 and two gross (1.3 net) wells were successful but awaiting tie-in. In the Progress area Barnwell acquired oil and natural gas rights in 640 gross (420 net) acres of undeveloped land in fiscal 2006. At September 30, 2006 Barnwell’s average working interest in its productive wells in the Progress area was 37%. Barnwell plans on drilling four to six gross wells in the Progress area in fiscal 2007.

Capital expenditures totaled $867,000 in the Wood River area in fiscal 2006 as compared to $531,000 in fiscal 2005. Two gross (0.3 net) wells were successfully drilled in fiscal 2006. At September 30, 2006 Barnwell’s average working interest in its productive wells in the Wood River area was 13%. Barnwell expects to drill three gross wells in the Wood River area in fiscal 2007.

Capital expenditures totaled $2,101,000 in the Pouce Coupe South area in fiscal 2006 as compared to $173,000 in fiscal 2005. Two gross (0.9 net) wells were successfully drilled in fiscal 2006. At September 30, 2006 Barnwell’s average working interest in its productive wells in the Pouce Coupe South area was 53%. Barnwell plans on drilling two gross wells in the Pouce Coupe South area in fiscal 2007.

Capital expenditures totaled $1,890,000 in the Simonette area in fiscal 2006. One gross (0.1 net) well was successful and one gross (0.5 net) well drilled in fiscal 2005 initially estimated to be productive was determined to be unsuccessful.

Capital expenditures totaled $1,102,000 in the Swalwell area in fiscal 2006 where oil and natural gas rights in 3,360 gross (3,350 net) acres of undeveloped land were acquired and where one gross (0.3 net) unsuccessful well was drilled.

Capital expenditures totaled $1,101,000 in the Josephine area in fiscal 2006, a new area for Barnwell, where oil and natural gas rights in 640 gross (420 net) acres of undeveloped land were acquired and where one gross (0.5 net) successful well was drilled.

Barnwell’s average working interest in wells drilled in fiscal 2006 was approximately 29%, as compared to 17% in fiscal 2005 and 10% in fiscal 2004. The increase in fiscal 2006, as compared to fiscal 2005 was due to Barnwell taking a higher working interest in projects that were internally developed and initiated. In fiscal 2006, Barnwell initiated 28 gross (11.7 net) wells as compared to 27 gross (8.8 net) wells in fiscal 2005. The increase in fiscal 2005, as compared to fiscal 2004, was principally due to an 81 gross (2.7 net) well shallow gas drilling program in fiscal 2004 in the Hilda area, where Barnwell’s interest averaged 3.3%, reducing Barnwell’s average net interest in fiscal 2004.

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 2006, 2005, and 2004 was derived primarily from the Province of Alberta.

	Year Ended September 30,
	2006		2005		2004
Annual net production:
Natural gas liquids (BBLS)*	115,000		114,000		105,000
Oil (BBLS)*	145,000		139,000		154,000
Natural gas (MCF)*	3,629,000		3,621,000		3,383,000

Annual average sale price per unit of production:
BBL of natural gas liquids**	$	40.18	$	31.84	$	24.18
BBL of oil**	$	56.85	$	48.11	$	33.24
MCF of natural gas***	$	6.67	$	5.93	$	4.60

Annual average production cost per MCFE produced****	$	1.45	$	1.20	$	1.11

Annual average depletion cost per MCFE produced*****	$	2.17	$	1.66	$	1.31

* 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 Alberta Royalty Tax Credit divided by gross production.

*** Calculated on revenues net of pipeline charges before royalty expense and Alberta 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. Excludes natural gas pipeline charges.

***** 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 2006, approximately 66%, 22% and 12% of Barnwell’s oil and natural gas revenues were from the sale of natural gas, oil and natural gas liquids, respectively.

In fiscal 2006, Barnwell’s net production after royalties for natural gas averaged 9,940 MCF per day, a slight increase from 9,920 MCF per day in fiscal 2005. Gross natural gas production also increased 1% in fiscal 2006, as compared to fiscal 2005. Dunvegan contributed approximately 50% of Barnwell’s net natural gas production in fiscal 2006, an increase from 48% in fiscal 2005 due to the new wells drilled at Dunvegan.

Barnwell’s major oil producing properties are the Red Earth, Chauvin and Bonanza/Balsam areas in Canada. In fiscal 2006, net production after royalties for oil averaged 400 barrels per day, an

increase of 5% from 380 barrels per day in fiscal 2005. This increase was principally due to the addition of new wells in the Wood River and Progress areas which offset decreased production from the Bonanza/Balsam and Red Earth areas caused by natural declines from existing wells.

In fiscal 2006, net production after royalties for natural gas liquids averaged 320 barrels per day, an increase of 3% from 310 barrels per day in fiscal 2005. This increase was due to higher Dunvegan production which increased 8% or 19 barrels per day. Dunvegan contributed approximately 87% of Barnwell’s net natural gas liquids production in fiscal 2006.

The average production cost per MCFE was $1.45 for fiscal 2006, a 21% increase from $1.20 for fiscal 2005. Actual field costs increased by 12% due to industry-wide increases in costs for oilfield services and utilities in Canada and a 7% increase in the average exchange rate of the Canadian dollar to the U.S. dollar in fiscal 2006, as compared to fiscal 2005.

The average depletion cost per MCFE was $2.17 for fiscal 2006, a 31% increase from $1.66 for fiscal 2005. The increase was due to a 22% increase in the depletion rate and a 7% increase in the average exchange rate of the Canadian dollar to the U.S. dollar. The 22% increase in the depletion rate was due to an increase in Barnwell’s costs of finding and developing new proven reserves, and costs that are incurred to maintain production from existing reserves. Barnwell’s cost of finding and developing proven reserves has increased as the costs of oil and natural gas exploration and development has increased in Canada, and increased capital costs attributed to existing reserves.

In fiscal 2005, approximately 68%, 21% and 11% of Barnwell’s oil and natural gas revenues were from the sale of natural gas, oil and natural gas liquids, respectively.

In fiscal 2005, Barnwell’s net production after royalties for natural gas averaged 9,920 MCF per day, an increase of 7% from 9,240 MCF per day in fiscal 2004. Gross natural gas production also increased 7% in fiscal 2005, as compared to fiscal 2004. Dunvegan contributed approximately 48% of Barnwell’s net natural gas production in fiscal 2005, an increase from 44% in fiscal 2004 due to the new well drilling at Dunvegan.

In fiscal 2005, net production after royalties for oil averaged 380 barrels per day, a decrease of 10% from 420 barrels per day in fiscal 2004. This decrease was principally due to natural production declines at Red Earth.

In fiscal 2005, net production after royalties for natural gas liquids averaged 310 barrels per day, an increase of 7% from 290 barrels per day in fiscal 2004. This increase was due to higher Dunvegan production which increased 12% or 29 barrels per day. Dunvegan contributed approximately 82% of Barnwell’s net natural gas liquids production in fiscal 2005.

The average production cost per MCFE was $1.20 for fiscal 2005, an 8% increase from $1.11 for fiscal 2004. The increase was due to an 8% increase in the average exchange rate of the Canadian dollar to the U.S. dollar in fiscal 2005, as compared to fiscal 2004.

The average depletion cost per MCFE was $1.66 for fiscal 2005, a 27% increase from $1.31 for fiscal 2004. The increase was due to a 17% increase in the depletion rate and an 8% increase in the average exchange rate of the Canadian dollar to the U.S. dollar.

Productive Wells

The following table sets forth the gross and net number of productive wells Barnwell has an interest in as of September 30, 2006.

	Productive Wells*
	Gross**		Net**
Location	Oil	Gas	Oil	Gas
Canada
Alberta	152	577	26.4	64.2
Saskatchewan	7	30	0.3	5.0
British Columbia	2	1	0.5	—
Total	161	608	27.2	69.2

* Twenty-four natural gas wells have dual or multiple 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, 2006.

					Developed and
	Developed		Undeveloped		Undeveloped
	Acreage(1)		Acreage(1)		Acreage(1)
Location	Gross(2)	Net(2)	Gross(2)	Net(2)	Gross(2)	Net(2)
Canada
Alberta	237,226	36,150	244,767	114,575	481,993	150,725
British Columbia	1,597	476	3,490	1,115	5,087	1,591
Saskatchewan	3,140	426	—	—	3,140	426
Total	241,963	37,052	248,257	115,690	490,220	152,742

(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 or wells 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 and well 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 fiscal years, if not developed, as follows: 7% expire during fiscal 2007; 14% expire during fiscal 2008; 28% expire during fiscal 2009; 25% expire during fiscal 2010; and 15% expire during fiscal 2011. Eleven percent of Barnwell’s undeveloped acreage is related to heavy oil and therefore not subject to expiration. 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 Bremner (8,640 net acres), Doris (7,392 net acres), Bonanza/Balsam (6,960 net acres), Boundary Lake (6,656 net acres), Swalwell (6,316 net acres), Thornbury (6,261 net acres), Mulligan (5,236 net acres), and Paddle River (5,184 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 producing reserves and proved reserves of crude oil (including condensate and natural gas liquids) and natural gas as of September 30, 2006, 2005, and 2004 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, other than the United States Securities and Exchange Commission, since October 1, 2004.

Proved Producing Reserves

	September 30,
	2006	2005	2004
Oil – barrels (BBLS) (including natural gas liquids):
Dunvegan	404,000	456,000	446,000
All other properties	665,000	646,000	689,000
Total	1,069,000	1,102,000	1,135,000

Natural gas – thousand cubic feet (MCF):
Dunvegan	11,503,000	12,947,000	13,796,000
All other properties	7,055,000	8,895,000	7,818,000
Total	18,558,000	21,842,000	21,614,000

Total Proved Reserves
(Includes Proved Producing Reserves)

	September 30,
	2006	2005	2004
Oil – barrels (BBLS) (including natural gas liquids):
Dunvegan	426,000	489,000	524,000
All other properties	877,000	817,000	780,000
Total	1,303,000	1,306,000	1,304,000

Natural gas – thousand cubic feet (MCF):
Dunvegan	12,074,000	13,858,000	15,975,000
All other properties	12,752,000	11,376,000	10,850,000
Total	24,826,000	25,234,000	26,825,000

As of September 30, 2006, 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 2006, Barnwell’s total net proved reserves, including proved producing reserves, of oil, condensate and natural gas liquids decreased by 3,000 barrels, and total net proved reserves of natural gas decreased by 408,000 MCF.

The change in oil, condensate and natural gas liquids reserves during fiscal 2006 was the net result of production during the year of 260,000 barrels, the addition of 190,000 barrels from the drilling of wells, the independent engineer’s 91,000 upward revision of Barnwell’s oil reserves and a decrease of 24,000 barrels due to elimination of the Alberta Royalty Tax Credit program effective January 1, 2007. See the “Governmental Regulation” section herewith for further discussion on the Alberta Royalty Tax Credit program.

The change in natural gas reserves during fiscal 2006 was the net result of production during the year of 3,629,000 MCF, the addition of 4,464,000 MCF from the drilling of natural gas wells, the independent engineer’s 865,000 MCF downward revision of Barnwell’s natural gas reserves and a decrease of 378,000 MCF due to the elimination of the Alberta Royalty Tax Credit program.

Barnwell’s working interest in the Dunvegan area accounted for approximately 49% and 55% of its total proved natural gas reserves at September 30, 2006 and 2005, respectively, and approximately 33% and 37% of total proved oil and natural gas liquids reserves at September 30, 2006 and 2005, respectively.

The following table sets forth Barnwell’s oil and natural gas reserves at September 30, 2006, 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. 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 (“NGL”), 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, 2006

	Total Proved Producing				Total Proved
	Oil & NGL		Gas		Oil & NGL		Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Property Name	(MBBLS)		(MMCF)		(MBBLS)		(MMCF)
Dunvegan	578	404	14,455	11,503	610	426	15,190	12,074
Red Earth	280	242	—	—	280	242	—	—
Bonanza/Balsam	107	87	411	329	111	90	1,018	826
Pouce Coupe South	7	5	866	695	70	57	2,000	1,603
Medicine River	33	25	783	576	33	25	783	576
Doris	—	—	1,273	1,034	—	—	1,491	1,221
Faith South	—	—	—	—	—	—	1,011	857
Wood River	40	34	451	387	40	34	689	589
Progress	78	74	418	347	203	179	2,395	1,866
Pouce Coupe	4	4	302	256	4	4	302	256
Other properties	230	194	4,036	3,431	289	246	5,827	4,958
TOTAL	1,357	1,069	22,995	18,558	1,640	1,303	30,706	24,826

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, operating costs, future estimated capital expenditures, and income taxes.

	Proved Producing			Total Proved
	Reserves			Reserves
Year ending September 30,

2007	$	11,490,000		$	13,078,000
2008	9,770,000			13,368,000
2009	7,660,000			10,239,000
Thereafter	23,283,000			31,024,000
	$	52,203,000		$	67,709,000

Present value (discounted at 10%) at September 30, 2006	$	38,489,000	*	$	49,923,000	*

* These amounts do not purport to represent, nor should they be interpreted as, the fair value of Barnwell’s natural gas and oil reserves. An estimate of fair value would also consider, among other items, the value of Barnwell’s undeveloped land position, the recovery of reserves not presently classified as proved, anticipated future changes in oil and natural gas prices (these amounts were based on a natural gas price of $3.34 per 1,000 cubic feet as of September 30, 2006) and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Marketing of Oil and Natural Gas

Barnwell sells substantially all of its oil and natural gas liquids production under short-term contracts between itself and marketers of oil. The price of oil and natural gas liquids is freely negotiated between the buyers and sellers and is largely determined by the world price for oil, which is principally denominated in U.S. dollars.

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 and is principally determined for Barnwell by the North American price for natural gas, which is principally denominated in U.S. dollars. In fiscal 2006, 2005, and 2004, 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 2006, natural gas production from the Dunvegan Unit was responsible for approximately 50% of Barnwell’s natural gas revenues, as compared to 46% in fiscal 2005. In fiscal 2006, Barnwell had four individually significant marketers that accounted for 69% 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 2006, over 90% of Barnwell’s oil and natural gas revenues were from products sold at spot 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 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.

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 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 Canadian federal income tax purposes. 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 November 2003, Royal Assent was received on a bill passed by the Parliament of Canada, which was then enacted into law, 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% with the 21% tax rate commencing on 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. Accordingly, during fiscal 2004, Barnwell’s Canadian net deferred income tax liabilities were reduced by approximately $1,440,000 due to the reduction in Canada’s federal corporate tax rate. Barnwell’s Canadian net deferred income tax liabilities were also reduced by approximately $300,000 in fiscal 2004 as a result of the Province of Alberta’s reduction of the province’s corporate tax rate from 13.0% to 12.5%, effective April 1, 2003 (enacted into law in December 2003), and from 12.5% to 11.5%, effective April 1, 2004 (enacted into law in May 2004).

In May 2006, a bill reducing the Province of Alberta’s corporate tax rate from 11.5% to 10.0% effective April 1, 2006 received Royal Assent and was passed into law. In June 2006, Royal Assent was received on a bill passed by the Parliament of Canada which reduces the federal corporate income tax rate to 19% from 21% by 2010 starting January 1, 2008. The federal corporate surtax will also be eliminated effective January 1, 2008. During the year ended September 30, 2006, Barnwell’s Canadian net deferred income tax liabilities were reduced by approximately $1,094,000 as a result of these reductions in Canadian tax rates.

In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to Alberta called the Alberta Royalty Tax Credit (“ARTC”). The ARTC has been discontinued by the Alberta government effective January 1, 2007. Barnwell received ARTC payments of $438,000, $409,000 and $377,000 in fiscal years 2006, 2005 and 2004, respectively. The ARTC payments were recorded as a credit against oil and natural gas royalties and reported in oil and natural gas revenues. In fiscal 2007, Barnwell expects to receive ARTC payments of approximately $100,000, representing the ARTC for the period from October 1, 2006 to December 31, 2006. Beginning January 1, 2007, Barnwell will no longer receive ARTC payments.

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, technical and other resources.

Land Investment Segment

Overview

Operations

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-family and multi-family residential units. These projects were developed on leasehold land acquired from Kaupulehu Developments by Kaupulehu Makai Venture, an unrelated entity. The development rights held by Kaupulehu Developments are for residentially-zoned leasehold land within and adjacent to the two golf courses and are under option to Kaupulehu Makai Venture.

Kaupulehu Developments later obtained the state and county zoning changes necessary to permit development of single-family 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.

In February 2004, Kaupulehu Developments entered into a Purchase and Sale Agreement with WB KD Acquisition, LLC (“WB”) by which Kaupulehu Developments transferred its leasehold interest in the aforementioned 870 acres zoned for resort/residential development, in two increments, to WB. There is no affiliation between Kaupulehu Developments and WB. WB is affiliated with Westbrook Partners, the developers of the nearby Kuki’o Resort. The first increment (“Increment I”) is an area planned for approximately 80 single-family lots and a beach club on the portion of the property bordering the Pacific Ocean. The purchasers of the 80 single-family lots will have the right to apply for membership in the Kuki’o Resort Golf and Beach Club, which is located adjacent to and south of the Four Seasons Resort Hualalai at Historic Ka’upulehu. The second increment (“Increment II”) is the remaining portion of the approximately 870-acre property and is zoned for single-family and multi-family residential units and a golf course and clubhouse.

WB also agreed to pay Kaupulehu Developments subsequent to February 2004 interim payments of $50,000 per month (“Interim Payments”) up to a total of $900,000. Kaupulehu Developments received the $900,000 in full as of August 2005.

Activity

WB sold the first of the 80 single-family lots under development in Increment I in January 2006. Two additional lots were sold by WB in February 2006 and another two lots were sold in April 2006, bringing total lot sales in fiscal 2006 to five lots. Kaupulehu Developments received Percentage Payments totaling $3,660,000 for these five lot sales. Revenue from the Percentage Payments was reduced by $220,000 of fees related to the sales, resulting in net revenues of $3,440,000 and a $2,688,000 operating profit, after minority interest. There is no assurance that any future payments will be received.

In June 2006, Kaupulehu Developments entered into an Agreement (“Increment II Agreement”) with WB and WB KD Acquisition II, LLC (“WBKD”) by which Kaupulehu Developments sold its interest in Increment II, representing the remainder of the approximately 870 acres, to WBKD. There is no affiliation between Kaupulehu Developments and WB or WBKD. WB and WBKD are both affiliates of Westbrook Partners, developers of the nearby Kuki’o Resort. Pursuant to the Increment II Agreement, Kaupulehu Developments received a $10,000,000 payment and is entitled to receive future payments from WBKD based on a percentage of the sales prices of the residential lots, ranging from 3.25% to 14%, to be determined in the future depending upon a number of variables, including whether the lots are sold prior to improvement. The revenue from the $10,000,000 payment was reduced by $600,000 of fees related to the sale, $220,000 in other costs related to the sale, and approximately $2,983,000 of previously capitalized costs relating to Increment II, resulting in net revenues of $6,197,000 and a $4,621,000 operating profit, after minority interest. There is no assurance that any future payments will be received.

In addition, under the terms of the Increment II Agreement, WBKD has the exclusive right to negotiate with Kaupulehu Developments with respect to Lot 4C, which is comprised of approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Increment II. This right expires in June 2009 or, if before such date WBKD completes any and all environmental assessments and surveys reasonably required to support a petition to the Hawaii State Land Use Commission for reclassification of Lot 4C zoning, in June 2012.

In November 2005, Kaupulehu Makai Venture paid Kaupulehu Developments a non-refundable payment of $2,875,000, consisting of $2,656,250 for the exercise of its development rights option due on December 31, 2005 and $218,750 for a portion of its development rights option due on December 31, 2006. The $2,875,000 of option proceeds was reduced by $173,000 of fees related to the sale, resulting in net revenues of $2,702,000 and a $2,111,000 operating profit, after minority interest. There were no other costs deducted from revenues from the sale of development rights in fiscal 2006 as all capitalized costs associated with the development rights were expensed in previous years.

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 interests held by Kaupulehu Developments at September 30, 2006 include the development rights under option, the rights to receive percentage of sales payments, and approximately 1,000 acres of vacant leasehold land zoned conservation, which is under a right of negotiation with WBKD.

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 few years, Hawaii’s economy has experienced positive growth and 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. This trend continued through fiscal 2006, but at a diminished rate, and, although we cannot be certain, it is not expected to decline significantly in the near term, although there can be no assurance this trend will in fact continue. The price and market for real estate in the South Kohala/North Kona area of the island of Hawaii has historically been cyclical and if the demand for real estate in the area Kaupulehu Developments’ interests are located were to decrease, Barnwell’s operating results could be negatively affected. During periods when demand for real estate is low, inventory may turn at slower rates than expected or may be sold at prices lower than anticipated. This could potentially impair Barnwell’s liquidity and impede its ability to proceed with other planned projects or activities.

Contract Drilling Segment

Overview

Barnwell’s wholly-owned subsidiary, Water Resources International, Inc. (“Water Resources”), drills water, water monitoring and geothermal wells of varying depths in Hawaii, installs and repairs water pumping systems, and is the state of Hawaii’s distributor for Floway pumps and equipment.

Operations

Water Resources owns and operates three Spencer-Harris portable rotary drill rigs ranging in drilling capacity from 3,500 feet to 7,000 feet, an IDECO H-35 rotary drill/workover rig and pump installation and service equipment. Additionally, Water Resources leases a three-quarter of an acre maintenance facility in Honolulu, Hawaii 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 materials and

pump supplies. As of September 30, 2006, Water Resources employed 21 drilling, pump and administrative employees, none of whom are union members.

The demand for Water Resources’ services is primarily dependent upon land development activities in Hawaii. Water Resources 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 drilled or day rate contracts and are negotiated with private entities or obtained through competitive bidding with private entities or 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.

Water Resources derived 37%, 63%, and 70% of its contract drilling revenues in fiscal 2006, 2005, and 2004, respectively, pursuant to federal, State of Hawaii and county contracts. At September 30, 2006, Barnwell had accounts receivable from the State of Hawaii and county entities totaling approximately $754,000. Barnwell has lien rights on wells drilled and pumps installed for federal, State of Hawaii, county and private entities.

Water Resources currently operates in Hawaii and is not subject to seasonal fluctuations.

Activity

In fiscal 2006, Water Resources started six well drilling contracts and four pump installation contracts and completed 11 well drilling contracts and six pump installation contracts. Seven of the completed well drilling contracts and three of the completed pump installation contracts were started in the prior year. Fifty-two percent (52%) of well drilling and pump installation jobs, representing 37% of total contract drilling revenues in fiscal 2006, have been pursuant to government contracts.

At September 30, 2006, Water Resources had a backlog of four well drilling contracts and nine pump installation and repair contracts, of which four, two well drilling and two pump installation and repair, were in progress as of September 30, 2006.

The dollar amount of Water Resources’ backlog of firm well drilling and pump installation and repair contracts at November 30, 2006 and 2005 was as follows:

	2006		2005
Well drilling	$	3,760,000	$	2,000,000
Pump installation and repair	1,140,000		1,500,000
	$	4,900,000	$	3,500,000

All of the contracts in backlog at November 30, 2006 are expected to be completed within fiscal year 2007.

Competition

Water Resources utilizes rotary drill rigs and competes with other drilling contractors in Hawaii which use drill rigs similar to Water Resources’ drilling rigs or drilling rigs that drill as quickly as Water Resources’ 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 for government and private contracts. Pricing is Water Resources’ major method of competition; reliability of service is also a significant factor.

Competitive pressures are expected to remain high, thus there is no assurance that the quantity of available or awarded jobs which occurred in fiscal 2006 will continue.

Summary Financial Information For all Industry Segments

Revenues of each industry segment for the fiscal years ended September 30, 2006, 2005, and 2004 are summarized as follows (all revenues were from unaffiliated customers with no intersegment sales or transfers):

	2006				2005				2004
Oil and natural gas	$	37,904,000	66	%	$	32,724,000	74	%	$	23,840,000	62	%
Contract drilling	5,866,000		10	%	7,644,000		17	%	3,690,000		10	%
Land investment	12,339,000		21	%	3,047,000		7	%	10,077,000		26	%
Other	765,000		1	%	652,000		2	%	827,000		2	%

Revenues from segments	56,874,000		98	%	44,067,000		100	%	38,434,000		100	%
Interest income	386,000		1	%	143,000		0	%	106,000		0	%
Gain on sale of drill rig	700,000		1	%	—		0	%	—		0	%

Total revenues	$	57,960,000	100	%	$	44,210,000	100	%	$	38,540,000	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 8.

Employees

As of September 30, 2006, Barnwell employed 55 employees, 52 of which are on a full-time basis. Twenty-one are employed in contract drilling activities, 20 are employed in oil and natural gas activities, and 14 are members of the corporate and administrative staff.

Financial Information about geographic areas

Revenues and long-lived assets by geographic area for the three years ended and as of September 30, 2006, 2005 and 2004 are set forth in Note 12 (SEGMENT AND GEOGRAPHIC INFORMATION) of “Notes to Consolidated Financial Statements” in Item 8.

Available Information

We are required to file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. These filings are not deemed to be incorporated by reference in this report. You may read and copy any documents filed by us at the Public Reference Section of the SEC, 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public through the SEC’s website at http://www.sec.gov. We also maintain an Internet site at www.brninc.com. We make available on our Internet website free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K as soon as practicable after we electronically file such reports with the SEC.

ITEM 1A. RISK FACTORS

The business of Barnwell and its subsidiaries face numerous risks, including those set forth below or those described elsewhere in this Form 10-K or in Barnwell’s other filings with the SEC. The risks described below are not the only risks that Barnwell faces, nor are they necessarily listed in order of significance.

Risks Related to Oil and Gas Segment

The oil and natural gas industry is highly competitive.

We compete for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and refining capacity and in many other respects with a substantial number of other organizations, many of which may have greater technical and financial resources than we do. Some of these organizations explore for, develop and produce oil and natural gas, carry on refining operations and market oil and other products on a worldwide basis. As a result of these complementary activities, some of our competitors may have competitive resources that are greater and more diverse than ours. Furthermore, many of our competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices and production levels, the cost and availability of alternative fuels and the application of government regulations. If our competitors are able to capitalize on these competitive resources, it could adversely affect our revenues.

Our results of operations and financial condition are dependent on the prices received for our oil and natural gas production.

Oil and natural gas prices are volatile and have fluctuated widely during recent years in response to many factors that are beyond our control. These factors include, but are not limited to, minor changes in supply and demand, market uncertainty, worldwide political instability, foreign supply of oil and natural gas, the level of consumer product demand, government regulations and taxes,

the price and availability of alternative fuels and the overall economic environment. Any decline in crude oil or natural gas prices may have a material adverse effect on our operations, financial condition, borrowing ability, reserves and amount of capital that we are able to allocate for the development of oil and natural gas reserves.

Energy prices are also subject to other political and regulatory actions outside our control, which may include changes in the policies of the Organization of Petroleum Exporting Countries or other developments involving or affecting oil-producing countries, or actions or reactions of the government of the United States in anticipation of or in response to such developments.

An increase in operating costs or a decline in our production level could have a material adverse effect on our results of operations and financial condition.

Higher operating costs for our underlying properties will directly decrease the amount of cash flow received by us and, therefore, may reduce the price of our common stock. Electricity, supplies, and labor costs are a few of the operating costs that are susceptible to material fluctuation.

The level of production from our existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond our control. A significant decline in our production could result in materially lower revenues and cash flow.

Our operating results are affected by our ability to market the oil and natural gas that we produce.

Our business depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. Canadian federal and provincial, as well as United States federal and state, regulation of oil and gas production, processing and transportation, tax and energy policies, general economic conditions, and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors change and inhibit the marketing of our production, overall production or realized prices may decline.

Our operations are subject to domestic and foreign government regulation and other risks, particularly in the United States and Canada.

Barnwell’s oil and gas operations are 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. Further, 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. We derive a significant portion of our revenues from our operations in Canada. In fiscal 2006, we derived approximately 66% of our operating revenues from operations in Canada.

Additionally, our ability to compete in the Canadian oil and natural gas industry may be adversely affected by governmental regulations or other policies that favor the awarding of contracts to

contractors in which Canadian nationals have substantial ownership interests. Furthermore, we may face governmentally imposed restrictions or fees from time to time on the transfer of funds to the U.S.

Government regulations control and often limit access to potential markets and impose extensive requirements concerning employee safety, environmental protection, pollution control and remediation of environmental contamination. Environmental regulations, in particular, prohibit access to some markets and make others less economical, increase equipment and personnel costs and often impose liability without regard to negligence or fault. In addition, governmental regulations may discourage our customers’ activities, reducing demand for our products and services.

Compliance with foreign tax and other laws may adversely affect our operations.

Tax and other laws and regulations are not always interpreted consistently among local, regional and national authorities. It is also possible that in the future we will be subject to disputes concerning taxation and other matters in Canada, and these disputes could have a material adverse effect on our financial performance.

We are dependent upon future discoveries or acquisitions of oil and gas to maintain our reserves.

We actively explore for oil and natural gas reserves. However, future exploration and drilling results are uncertain and may involve substantial costs. Despite this uncertainty or potential cost, discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production. As a result, future oil and natural gas reserves may be dependent on our success in exploiting existing properties and acquiring additional reserves. If our access to capital becomes limited or unavailable, our ability to make the necessary capital investments to maintain or expand our oil and gas reserves will be impaired. Additionally, we cannot guarantee that we will be successful in developing additional reserves or acquiring additional reserves on terms that meet our investment objectives. Without these reserve additions, our reserves will deplete and as a consequence, either production from, or the average reserve life of, our properties will decline.

Actual reserves will vary from reserve estimates.

The value of our common stock depends upon, among other things, the level of reserves of oil and gas. Estimating reserves is inherently uncertain, and the figures herein are only estimates. Ultimately, actual reserves attributable to our properties will vary from estimates, and those variations may be material. The estimation of reserves involves a number of factors and assumptions, including, among others:

· historical production in the area compared with production rates from similar producing areas;

· future commodity prices, production and development costs, royalties and capital expenditures;

· initial production rates;

· production decline rates;

· ultimate recovery of reserves;

· success of future development activities;

· marketability of production;

· effects of government regulation; and

· other government levies that may be imposed over the producing life of reserves.

Reserve estimates are based on the relevant factors, assumptions and prices as of the date on which the evaluations are prepared. Many of these factors are subject to change and are beyond our control. If these factors, assumptions and prices prove to be inaccurate, actual results may vary materially from reserve estimates.

Delays in business operations could adversely affect our distributions.

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of our properties, and the delays of those operators in remitting payment to us, payments between any of these parties may also be delayed by:

· restrictions imposed by lenders;

· accounting delays;

· delays in the sale or delivery of products;

· delays in the connection of wells to a gathering system;

· blowouts or other accidents;

· adjustments for prior periods;

· recovery by the operator of expenses incurred in the operation of the properties; or

· the establishment by the operator of reserves for these expenses.

Any of these delays could expose us to additional third party credit risks.

The industry in which we operate exposes us to potential liabilities that may not be covered by insurance.

Our operations are subject to all of the risks associated with the operation and development of oil and natural gas properties, including the drilling of oil and natural gas wells, and the production and transportation of oil and natural gas. These risks include encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, cratering, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution, other environmental risks, fires and spills. A number of these risks could result in personal injury, loss of life, or environmental and other damage to our property or the property of others.

While we maintain reserves for anticipated liabilities and carry various levels of insurance, we could be affected by civil, criminal, regulatory or administrative actions, claims or proceedings. We cannot fully protect against all of the risks listed above, nor are all of these risks insurable. There is no assurance that any applicable insurance or indemnification agreements will adequately protect us against liability for the risks listed above. We could face substantial losses, if an event occurs for which we are not fully insured or are not indemnified against, or a customer or insurer fails to meet its indemnification or insurance obligations. In addition, there can be no assurance that insurance will continue to be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive.

We may incur material costs to comply with or as a result of health, safety, and environmental laws and regulations.

The oil and natural gas industry is subject to extensive environmental regulation pursuant to local, provincial and federal legislation. A violation of that legislation may result in the imposition of fines or the issuance of “clean up” orders. Legislation regulating the oil and natural gas industry may be changed to impose higher standards and potentially more costly obligations. For example, the 1997 Kyoto Protocol to the United Nation’s Framework Convention on Climate Change, known as the Kyoto Protocol, was ratified by the Canadian government in December 2002 and will require, among other things, significant reductions in greenhouse gases. The impact of the Kyoto Protocol on us is uncertain and may result in significant additional costs for our future operations. Although we record a provision in our financial statements relating to our estimated future environmental and reclamation obligations, we cannot guarantee that we will be able to satisfy our actual future environmental and reclamation obligations.

We are not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms. Accordingly, any site reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period could negatively impact our cash flow. Should we be unable to fully fund the cost of remedying an environmental problem, we might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

We may have difficulty financing our planned capital expenditures, which could have an adverse affect on our business.

We make and will continue to make substantial capital expenditures in our exploration and development projects. Without additional capital resources, our drilling and other activities may be limited and our business, financial condition and results of operations may suffer. We may not be able to secure additional financing on reasonable terms or at all and financing may not continue to be available to us under our existing financing arrangements. If additional capital resources are unavailable, we may curtail our drilling, development and other activities or be forced to sell some of our assets under untimely or unfavorable terms. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operation.

Unforeseen title defects may result in a loss of entitlement to production and reserves.

Although we conduct title reviews in accordance with industry practice prior to any purchase of resource assets or property, such reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat our title to the purchased assets. If such a defect were to occur, our entitlement to the production from such purchased assets could be jeopardized.

Changes in tax and other legislation may adversely affect shareholders.

Income tax laws, other legislation or government incentive programs relating to the oil and gas industry may in the future be changed or interpreted in a manner that adversely affects us and our shareholders. Tax authorities having jurisdiction over us may disagree with the manner in which we calculate our income for tax purposes or could change their administrative practices to our detriment.

Risks Related to Real Estate Investment Segment

Significant competition in the real estate industry could have an adverse effect on our business.

We face competition from other developers on the island of Hawaii, and from other luxury residential properties in Hawaii and the mainland United States. In many cases, our competitors have greater financial and other resources than us. If we are unable to compete with these larger competitors, our financial results could be adversely affected.

A downturn in economic conditions and demand for real estate could adversely affect our business.

The real estate investment industry is cyclical in nature and is particularly vulnerable to shifts in local, regional, and national economic conditions outside of our control such as interest rates, housing demand, population growth, employment levels and job growth and property taxes. As a result, revenues and operating results may fluctuate significantly.

Considerable economic and political uncertainties currently exist that could have adverse effects on consumer buying habits, construction costs, availability of labor and materials and other factors affecting us and the real estate industry in general. Significant expenditures associated with investment in real estate, such as real estate taxes, insurance, maintenance costs and debt payments, cannot generally be reduced even though changes in Hawaii’s or the nation’s economy may cause a decrease in revenues from our properties.

Our real estate business is primarily concentrated in the state of Hawaii. As a result, our financial results are dependent on the economic growth and health of Hawaii, particularly the island of Hawaii.

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 and Hawaii’s tourism industry, as well as the United States’ economy in general. 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. The future economic growth in certain portions of the island of Hawaii may be adversely affected if its infrastructure, such as roads, airports, medical facilities and schools, are not improved to meet increased demand. There can be no assurance that these improvements will occur.

The occurrence of natural disasters in Hawaii could adversely affect our business.

The occurrence of natural disasters in Hawaii could have a material adverse effect on our ability to develop and sell properties or realize income from our projects. The occurrence of natural disasters could also cause increases in property and flood insurance rates and deductibles, which could reduce demand for our properties.

Increases in interest rates could reduce demand for our real estate.

Continued increases in interest rates could reduce the demand for development, particularly land. Increased interest rates could also negatively impact pricing for our products. A reduction in demand or pricing would materially adversely affect our profitability.

Our business is subject to extensive regulation which makes it difficult and expensive for us to conduct our operations.

We are subject to a wide variety of federal, state and local laws and regulations relating to land use and development and to environmental compliance and permitting obligations, including those related to the use, storage, discharge, emission, and disposal of hazardous materials. Any failure to comply with these laws could result in capital or operating expenditures or the imposition of severe penalties or restrictions on operations that could adversely affect present and future operations, or jeopardize our ability to sell the leasehold interest currently held.

A portion of future percentage of sales payments could be impaired if the developer of the property is unable to negotiate fee simple interests.

In 2006 we sold our leasehold interest in the second of two increments of resort/residential zoned property to an unrelated developer. As a part of the sale, we are entitled to receive future payments based on a percentage of the sales prices of residential lots sold in this second increment. Receipt of these percentage of sales payments will be contingent upon the ability of the developer of the leasehold interest in the resort/residential zoned property to successfully negotiate fee simple prices within this second increment. If the developer is unsuccessful in such negotiations, our ability to receive percentage of sales payments on the sales of those lots would be impaired.

If we are unable to obtain required land use entitlements at reasonable costs, or at all, our operating results could be adversely affected.

We hold the leasehold interest to approximately 1,000 acres of vacant land that is currently zoned conservation. Our success in selling this interest may be contingent upon obtaining the necessary reclassification from the State of Hawaii Land Use Commission and County of Hawaii. Obtaining the necessary reclassification and ministerial approvals is often difficult, costly and may take several years, or more, to complete. Delays or failures to obtain the necessary reclassification approvals may adversely affect our financial results.

Environmental and other regulations may have an adverse effect on our business.

Our properties are subject to federal, state and local environmental regulations and restrictions that may impose significant limitations. In most cases, approval to develop requires multiple permits which involve a long, uncertain and costly regulatory process.

We are involved in joint ventures and are subject to risks associated with joint venture partnerships.

We are involved in joint venture relationships and may initiate future joint venture projects. Entering into a joint venture involves certain risks which include:

· the inability to exercise voting control over the joint venture;

· economic or business interests which are not aligned with our venture partner; and

· the inability for the venture partner to fulfill its commitments and obligations due to financial or other difficulties.

Risks Related to Contract Drilling Segment

Demand for water well drilling and/or pump installation is volatile. A decrease in demand for our services would result in a decrease in our revenues.

Demand for services is highly dependent upon land development activities in the state of Hawaii. As also noted above, the real estate investment industry is cyclical in nature and is particularly vulnerable to shifts in local, regional, and national economic conditions outside of our control such as interest rates, housing demand, population growth, employment levels and job growth and property taxes. If we experience a decrease in water well drilling and/or pump installation contracts, we may experience decreased revenues and operating results.

A significant portion of our contract drilling business is dependent on municipalities and a decline in municipal spending could adversely impact our business.

A significant portion of our contract drilling water resources division revenues are derived from water and infrastructure contracts with governmental entities or agencies. Reduced tax revenues in certain regions may limit spending and new development by local municipalities which in turn will affect the demand for our services in these regions. Material reductions in spending by a significant number of municipalities or local governmental agencies could have a material adverse effect on our business, results of operations, liquidity and financial position.

Our contract drilling operations face significant competition from companies with greater financial resources.

We face competition for our services from a variety of competitors. Many of our competitors utilize drilling rigs that drill as quickly as our equipment but require less labor. Our strategy is to compete based on pricing and to a lesser degree, quality of service. If we are unable to compete effectively with our competitors, our financial results could be adversely affected.

The loss of or damage to key vendor, customer or sub-contractor relationships would adversely affect our operations.

Our business is dependent on our relationships with key vendors, customers and sub-contractors. The loss of or damage to any of our key relationships could negatively affect our business.

Entity-Wide Risks

The price of our common stock has been volatile and could continue to fluctuate substantially.

The market price of our common stock has been volatile and could fluctuate based on a variety of factors, including:

· fluctuations in commodity prices;

· variations in results of operations;

· announcements by us and our competitors;

· legislative or regulatory changes;

· general trends in the industry;

· general market conditions; and

· analysts’ estimates and other events in the oil and natural gas industry.

Failure to retain key personnel could hurt our operations.

We require highly skilled and experienced personnel to operate our business. In addition to competing in highly competitive industries, we compete in a highly competitive labor market. Our business could be adversely affected by an inability to retain personnel or upward pressure on wages as a result of the highly competitive labor market.

A small number of shareholders, including our executive officers, own a significant amount of our common stock and have influence over our business regardless of the opposition of other shareholders.

As of September 30, 2006, three of our investors and our executive officers held approximately 60% of our common stock. The interests of these shareholders may not always coincide with the interests of other shareholders. These shareholders, acting together, have significant influence over all matters submitted to our shareholders, including the election of our directors, and could accelerate, delay, deter or prevent a change of control of us. These shareholders are able to exercise significant control over our business, policies and affairs.

We may be required to comply with Section 404 of the Sarbanes-Oxley Act in 2007, which we believe will result in additional expenses and may divert management’s attention.

The Company may become an accelerated filer as defined in Rule 12b-2 of the Exchange Act, which would require the Company to comply with Section 404 of the Sarbanes-Oxley Act for fiscal 2007. In such event, management would be required to provide with the Company’s Annual Report on

Form 10-K for the year ending September 30, 2007, its assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2007 and our independent registered public accounting firm would be required to provide its attestation report on management’s assessment. If such compliance is required, the Company anticipates incurring additional general and administrative expenses and anticipates that its compliance efforts may divert management’s time and attention away from other aspects of our business.

Adverse changes in actuarial assumptions used to calculate retirement plan costs due to economic or other factors, or lower returns on plan assets could adversely affect Barnwell’s results and financial condition.

Retirement plan cash funding obligations and plan expenses and obligations are subject to a high degree of uncertainty and could increase in future years depending on numerous factors, including the performance of the financial markets, specifically the equity markets, and the levels of interest rates.

ITEM 2. PROPERTIES

Oil and Gas and Real Estate Investment Properties.

The location and character of Barnwell’s oil and natural gas properties, and its real estate investment properties, are described above under Item 1, “Business.”

Corporate Offices

Barnwell owns, and uses as its corporate office, 4,600 square feet on the 29th floor of an office building in downtown Honolulu located at 1100 Alakea Street, Suite 2900, Honolulu, Hawaii 96813.

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.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

In December 2004, Barnwell declared a two-for-one stock split in the form of a stock dividend. The new shares were distributed on January 28, 2005 to all shareholders of record as of January 11, 2005.

In October 2005, Barnwell declared a three-for-one stock split in the form of a stock dividend. The new shares were distributed on November 14, 2005 to all shareholders of record as of October 28, 2005. All information in this Form 10-K has been adjusted to reflect the stock splits for all periods presented.

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, 2004	$	12.36	$	7.67	December 31, 2005	$	28.25	$	19.50
March 31, 2005	18.62		12.08		March 31, 2006	25.68		20.71
June 30, 2005	24.21		17.73		June 30, 2006	24.45		18.75
September 30, 2005	22.92		18.17		September 30, 2006	24.30		18.45

Holders

As of December 20, 2006, there were 8,169,060 shares of common stock, par value $0.50, outstanding. There were approximately 1,500 holders of the common stock of the registrant as of December 20, 2006.

Dividends

On December 8, 2006, Barnwell declared a cash dividend of $0.10 per share payable January 15, 2007, to stockholders of record on December 28, 2006.

The table below sets forth the cash dividends paid per share of common stock for 2006 and 2005.

Record Date	Payable Date	Dividend Paid
September 1, 2006	September 15, 2006	$	0.05
June 1, 2006	June 15, 2006	$	0.05
March 1, 2006	March 15, 2006	$	0.05
December 20, 2005	January 4, 2006	$	0.025
September 1, 2005	September 15, 2005	$	0.02
June 1, 2005	June 15, 2005	$	0.02
March 1, 2005	March 15, 2005	$	0.02
December 20, 2004	January 5, 2005	$	0.04

Securities Authorized for Issuance Under Equity Compensation Plans

See the information included in Part III, Item 12, under the caption “Equity Compensation Plan Information.”

ITEM 6. SELECTED FINANCIAL DATA

The following financial data as of and for the years ended is derived from the Consolidated Financial Statements. The data should be read in conjunction with the Consolidated Financial Statements and related Notes to Consolidated Financial Statements, and other financial information included herein. See “Financial Statements and Supplementary Data” in Item 8 and “Management’s Discussion and Analysis of Financial Condition and Results of Operation” in Item 7.

FINANCIAL AND OPERATING HIGHLIGHTS

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

	Years ended September 30,
	2006		2005		2004		2003		2002
FINANCIAL:
Revenues	$	57,960,000	$	44,210,000	$	38,540,000	$	24,160,000	$	16,360,000

Net earnings	$	14,637,000	$	6,027,000	$	8,710,000	$	2,320,000	$	40,000

Net earnings per share - diluted	$	1.68	$	0.70	$	1.03	$	0.28	$	0.01

Total assets	$	104,555,000	$	84,977,000	$	65,087,000	$	52,337,000	$	40,674,000

Long-term obligations	$	15,797,000	$	16,063,000	$	14,770,000	$	15,067,000	$	12,967,000

Dividends declared per share	$	0.18	$	0.10	$	0.14	$	—	$	0.03

OPERATING:
Production -
Oil and natural gas liquids (barrels)	260,000		253,000		259,000		227,000		242,000

Natural gas (MCF)	3,629,000		3,621,000		3,383,000		3,175,000		3,277,000

Average price -
Oil and natural gas liquids, per barrel	$	49.48	$	40.78	$	29.57	$	25.37	$	17.85

Natural gas, per MCF	$	6.67	$	5.93	$	4.60	$	4.27	$	2.12

	At September 30,
	2006	2005	2004	2003	2002
RESERVES:
Proved reserves:
Oil and liquids-barrels	1,303,000	1,306,000	1,304,000	1,401,000	1,527,000

Natural gas – MCF*	24,826,000	25,234,000	26,825,000	27,639,000	27,166,000

Total natural gas and natural gas equivalent of oil and liquids**– MCF	32,383,000	32,809,000	34,388,000	35,765,000	36,023,000

* MCF means 1,000 cubic feet

** Oil and liquids are converted to natural gas equivalents on the basis of one barrel equals 5.8 MCF.

Reserves are calculated by an independent engineering firm based on estimated prices received by Barnwell at year end.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS 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, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended September 30, 2006. 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 costs related to unsuccessful wells and estimated future site restoration and abandonment, are capitalized until such time as the aggregate of such costs net of accumulated depletion and oil and gas related deferred income taxes, on a country-by-country basis, equals the sum of 1) the discounted present value (at 10%), using prices as of the end of the fiscal year on a constant basis, of Barnwell’s estimated future net cash flows from estimated production of proved oil and natural gas reserves as determined by independent petroleum engineers, less estimated future expenditures to be incurred in developing and producing the proved reserves but excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet; plus 2) the cost of major development projects and unproven properties not subject to depletion, if any; plus 3) the lower of cost or estimated fair value of unproven properties included in costs subject to depletion; less 4) related income tax effects. If net capitalized costs exceed this limit, the excess is expensed unless subsequent market price changes eliminate or reduce the indicated write-down in accordance with U.S. Securities and Exchange Commission Staff Accounting Bulletin Topic 12D. Depletion is computed using the units-of-production method whereby capitalized costs, net of salvage values, plus estimated future costs to develop proved reserves and satisfy asset retirement obligations, are amortized over the total estimated proved reserves on a country-by-country basis. Investments in major development projects are not depleted until either proved reserves are associated with the projects or impairment has been

determined. At September 30, 2006 and 2005, Barnwell had no investments in major oil and natural gas development projects that were not being depleted. General and administrative costs related to oil and natural gas operations are expensed as incurred. 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.

Based on a natural gas spot price of $3.34 per 1,000 cubic feet (“MCF”) as of September 30, 2006, the full cost pool exceeded the ceiling limitation by approximately $1,581,000. However, natural gas prices increased significantly subsequent to September 30, 2006, but prior to the filing of this annual report, such that Barnwell’s full cost pool would not have exceeded the ceiling limitation. The spot price of natural gas on December 18, 2006 was approximately $6.30 per MCF, which represents an 89% increase over the September 30, 2006 spot price of $3.34 per MCF. Accordingly, per U.S. Securities and Exchange Commission Staff Accounting Bulletin Topic 12D, Barnwell has not recorded an impairment write-down of its oil and natural gas properties at September 30, 2006.

Investment in land and revenue recognition

Barnwell’s investment in land is comprised of development rights under option, rights to receive percentage of sales payments, and approximately 1,000 acres of vacant leasehold land zoned conservation, which is under a right of negotiation. 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 sales of leasehold land interests, including capitalized interest, are included in the Consolidated Balance Sheets under the caption “Investment in Land.”

Sales of development rights under option and revenues from sales of leasehold land interests are accounted for pursuant to the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 66, “Accounting for Sales of Real Estate.” SFAS No. 66 provides specific sales recognition criteria to determine when land sale revenue can be recorded.

Investment in affiliate

In June 2006, Barnwell entered into an agreement with Nearco, Inc. (“Nearco”) to form Mauka 3K, LLC (“Mauka 3K”), for the purpose of providing real estate consulting services and investing in real estate. Barnwell and Nearco each have an equal 50% voting interest in Mauka 3K. Nearco is a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 20.6% owner of Kaupulehu Developments, a general partnership in which Barnwell owns a 77.6% controlling interest.

in determining whether or not Barnwell exercises control include rights of partners regarding significant strategic and operational decisions. As Barnwell does not exercise direct or indirect control over Mauka 3K, the investment is accounted for using the equity method of accounting.

Revenues from real estate consulting services are recognized when services have been rendered and the terms of the consulting agreement have been satisfied.

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 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 impacts of 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, 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.

Net deferred tax assets at September 30, 2006 of $5,429,000 consists of $3,293,000 related to expenses accrued for book purposes but not for tax purposes, $614,000 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, and $1,522,000 for foreign tax credit carryforwards. Canadian deferred tax assets related to expenses accrued for book purposes but not for tax purposes are estimated to be realized through future Canadian income tax deductions against future Canadian oil and natural gas earnings. U.S. deferred tax assets related to expenses accrued for book purposes but not for tax purposes and the excess of the cost basis of investment in land for tax purposes over the cost basis of investment in land for book purposes are estimated to be realized from deductions against future U.S. earnings from sales of interests in leasehold land and land development rights. Foreign tax credit carryforwards are estimated to be utilized when U.S. federal income taxes otherwise due on Canadian source income in a given

year exceeds the foreign tax credit generated in that year. The foreign tax credit carryforwards will expire if not utilized in fiscal years 2012 through 2013. The amount of deferred income tax assets considered realizable may be reduced if estimates of future taxable income are reduced.

Retirement plans

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. Additionally, Barnwell sponsors a Supplemental Employee Retirement Plan, a noncontributory supplemental retirement benefit plan which covers certain current and former employees of Barnwell for amounts exceeding the limits allowed under the pension plan. Barnwell accounts for its retirement plans in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” which requires that amounts recognized in financial statements be determined on an actuarial basis. SFAS 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 2006 and fiscal 2005, Barnwell assumed an expected long-term rate of return on plan assets of 8% and an expected rate of future annual compensation increases of 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, 2006, Barnwell determined this rate to be 5.50% as compared to a discount rate of 5.25% used at September 30, 2005.

Barnwell made cash contributions to the defined benefit pension plan of $1,050,000, $150,000 and $74,000 in fiscal 2006, 2005 and 2004, respectively. The contribution in fiscal 2006 resulted in a prepaid pension cost of $234,000 at September 30, 2006. Barnwell recognized net periodic benefit costs of $299,000, $249,000 and $168,000 during fiscal 2006, 2005 and 2004, respectively, and Barnwell recorded an additional minimum pension liability of $132,000 in fiscal 2005. Barnwell’s accrued benefit cost at September 30, 2005 and 2004 was $517,000 and $418,000, respectively.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106 and 132(R).” SFAS No. 158 requires an employer to recognize the over-funded or under-funded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS No. 158 also requires the measurement of defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position (with limited exceptions). Under SFAS No. 158, Barnwell will be required to recognize the funded status of its defined benefit postretirement plan and supplemental employee retirement plan and to provide the required disclosures. SFAS No. 158 is effective for fiscal years ending after December 15, 2006. If SFAS No. 158 were applied as of September 30, 2006, Barnwell

would have recognized an additional pension and other postretirement benefit obligation of approximately $1,500,000 along with a corresponding decrease in accumulated other comprehensive income of approximately $990,000, net of $510,000 of deferred income tax benefits associated with the temporary difference between pension and postretirement liabilities recognized for book versus tax purposes.

Asset retirement obligation

Barnwell accounts for asset retirement obligations in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143,” 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 asset retirement obligation reflects Barnwell’s obligation to plug and abandon natural gas and oil wells, dismantle and remove related equipment and plants, and restore the properties to a suitable condition at the end of oil and gas operations based on Barnwell’s net ownership interest in the properties. The asset retirement obligation is recorded at fair value in the period in which it is incurred along with a corresponding increase in the carrying amount of the related asset. Barnwell has estimated fair value by discounting the estimated future cash outflows required to settle abandonment and restoration liabilities. The present value calculation includes numerous estimates, assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political environments. 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. The liability is accreted at the end of each period through charges to oil and natural gas operating expense. Abandonment and restoration cost estimates are determined in conjunction with Barnwell’s reserve engineers based on historical information regarding costs incurred to abandon and restore similar well sites, information regarding current market conditions and costs, and knowledge of subject well sites and properties.

Share-based payments

Effective October 1, 2005, Barnwell adopted the provisions of SFAS No. 123(R), “Share-Based Payment,” for its share-based compensation plans. Barnwell previously accounted for these plans under the recognition and measurement principles of Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations and disclosure requirements established by SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.”

Under APB No. 25, no compensation expense was recorded for Barnwell’s stock options issued under the qualified plan. The pro forma effects on net earnings and earnings per share for qualified stock options were instead disclosed in a footnote to the financial statements. Under APB No. 25, compensation expense for non-qualified stock options with stock appreciation rights features were recorded utilizing the market price of Barnwell’s stock at each period-end to determine the vested intrinsic value of the stock appreciation rights.

Barnwell elected to use the modified prospective transition method to adopt SFAS No. 123(R). Under SFAS No. 123(R), share-based compensation cost is measured at fair value. Barnwell utilizes a closed-form valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of Barnwell’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Barnwell’s stock price, and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

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, premises and other property and equipment are depreciated using the straight-line method based on estimated useful lives.

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.

Contractual Obligations

The following table lists the scheduled maturities of long-term debt, estimating that Barnwell’s credit facility with Royal Bank of Canada will be renewed on each annual renewal date, currently April 30, and scheduled minimum rental payments of non-cancelable operating leases for office space and leasehold land:

	Payments Due by Fiscal Year
Contractual Obligations	Total		2007		2008-2009		2010-2011		After 2011
Long-term debt	$	11,735,000	$	—	$	—	$	—	$	11,735,000
Operating leases	4,062,000		571,000		939,000		867,000		1,685,000

Total	$	15,797,000	$	571,000	$	939,000	$	867,000	$	13,420,000

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, April 30, 2007 (for which repayment, if any, has been deferred until no sooner than October 1, 2007), 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	Total		2007		2008-2009		2010-2011		After 2011
Long-term debt	$	11,735,000	$	—	$	11,735,000	$	—	$	—
Operating leases	4,062,000		571,000		939,000		867,000		1,685,000

Total	$	15,797,000	$	571,000	$	12,674,000	$	867,000	$	1,685,000

The lease payments for land were subject to renegotiation as of January 1, 2006. Per the lease agreement, the lease payments will remain unchanged pending an appraisal, whereupon the lease rent will be adjusted to fair market value. Barnwell does not know the amount of the new lease payments which could be effective upon performance of the appraisal; they may remain unchanged or increase, and Barnwell currently expects the adjustment, if any, to not be material. The future rental payment disclosures above assume the minimum lease payments for land in effect at December 31, 2005 remain unchanged through December 2025, the end of the lease term.

Overview

Barnwell is engaged in the following lines of business: 1) oil and natural gas exploration, development, production and sales essentially all in Canada (oil and natural gas segment), 2) investment in leasehold land in Hawaii (land investment segment), and 3) drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling segment).

Oil and Natural Gas Segment

Barnwell sells substantially all of its oil and condensate production under short-term contracts with marketers of oil. 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, oil and natural gas liquids is freely negotiated between the buyers and sellers. Market prices for petroleum products are dependent upon factors such as, but not limited to, changes in weather, storage levels, and output. Petroleum and natural gas prices are very difficult to predict and fluctuate significantly. For example, natural gas prices for Barnwell, based on quarterly averages during the three years ended September 30, 2006, have ranged from a low of $4.08 per thousand cubic feet to a high of $9.76 per thousand cubic feet, and tend to be higher in the winter than in the summer due to increased demand. Oil and natural gas exploration, development and operating costs generally follow trends in product market prices, thus

in times of higher product prices the cost of exploration, development and operation of oil and natural gas properties will tend to escalate as well. Barnwell’s oil and natural gas operations make capital expenditures in the exploration, development, and production of oil and natural gas. Cash outlays for capital expenditures are largely discretionary, however, a minimum level of capital expenditures is required to replace depleting reserves. Due to the nature of oil and natural gas exploration and development, significant uncertainty exists as to the ultimate success of any drilling effort.

Land Investment Segment

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, within and adjacent to the Hualalai Resort at Historic Ka’upulehu, between the Queen Kaahumanu Highway and the Pacific Ocean. Kaupulehu Developments’ development rights are under option to a developer and revenues are recognized when options are exercised.

In February 2004, Kaupulehu Developments entered into a Purchase and Sale Agreement with an independent buyer whereby Kaupulehu Developments transferred its leasehold interest in approximately 870 acres zoned for resort/residential development, in two increments, to the buyer. For the first increment (“Increment I”), Kaupulehu Developments received an $11,550,000 cash closing payment in February 2004 and is also entitled to receive future payments from the buyer based on the following percentages of gross receipts from the developer’s sales of single-family residential lots in Increment I: 9% of the gross proceeds from single-family lot sales up to aggregate gross proceeds of $100,000,000; 10% of such aggregate gross proceeds greater than $100,000,000 but less than $300,000,000; and 14% of such aggregate gross proceeds in excess of $300,000,000.

In June 2006, Kaupulehu Developments entered into an agreement whereby Kaupulehu Developments sold its interest in the second increment (“Increment II”), representing the remainder of the aforementioned approximately 870 acres. Pursuant to this Agreement, Kaupulehu Developments received $10,000,000 and is entitled to receive future payments from the buyer based on a percentage of the sales prices of the residential lots, ranging from 3.25% to 14%, to be determined in the future depending upon a number of variables, including whether the lots are sold prior to improvement. This Agreement also provides the buyer with the exclusive right to negotiate with Kaupulehu Developments with respect to Lot 4C, which is comprised of approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Increment II. This right expires in June 2009 or, if the buyer completes any and all environmental assessments and surveys reasonably required to support a petition to the Hawaii State Land Use Commission for reclassification of Lot 4C zoning, in June 2012.

The area in which Kaupulehu Developments’ interests are located has experienced demand for premium residential real estate in recent years, however there is no assurance that any future development rights or percentage of sales payments will be received.

Contract Drilling Segment

Barnwell also drills water, water monitoring and geothermal wells and installs and repairs water pumping systems in Hawaii. Contract drilling results are highly dependent upon the quantity, dollar value and timing of contracts awarded by governmental and private entities and can fluctuate

significantly. Water well drilling and pump installation activity decreased during fiscal 2006 as compared to the prior year, and management expects these activities to decrease similarly in fiscal 2007, as compared to fiscal 2006.

Results of Operation

Summary

Barnwell generated net earnings of $14,637,000 in fiscal 2006, an $8,610,000 increase from net earnings of $6,027,000 in fiscal 2005. The increase was due in part to the receipt of a payment from the sale of Increment II of Kaupulehu Developments’ leasehold land interests which generated an operating profit, after minority interest and before taxes, of approximately $4,621,000, higher prices received by Barnwell for all petroleum products, the receipt of Percentage Payments from the sale of lots in Increment I of the leasehold land interest previously held by Kaupulehu Developments, and proceeds from real estate consulting services rendered. The increase was also due in part to the recognition of $4,130,000 of deferred tax benefits due to a reduction in the valuation allowance for foreign tax credit carryforwards and $1,094,000 of deferred tax benefits due to a reduction in Canadian income tax rates. There were no Increment II receipts, Percentage Payments, or real estate consulting proceeds received in fiscal 2005, nor were there reductions in the valuation allowance for foreign tax credit carryforwards or Canadian tax rates in fiscal 2005.

Barnwell generated net earnings of $6,027,000 in fiscal 2005, a $2,683,000 decrease from net earnings of $8,710,000 in fiscal 2004. The decrease was the result of fiscal 2004 net earnings including the receipt of a closing payment from the sale of an interest in leasehold land in February 2004 which generated an operating profit, after minority interest and before taxes, of approximately $5,200,000, and deferred income tax benefits of $1,740,000 resulting from the enactment of reductions in Canadian federal and Alberta income tax rates; there were no such items in fiscal 2005. Additionally, earnings decreased due to an increase in stock appreciation rights expense, after income taxes, of $1,608,000 in fiscal 2005 resulting from an increase in the market price of Barnwell’s stock and the issuance of additional stock options that have stock appreciation rights. These decreases in net earnings were partially offset by increases in operating profits generated by Barnwell’s oil and natural gas and contract drilling segments.

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 2006 as compared to fiscal 2005, and fiscal 2005 as compared to fiscal 2004. Production amounts reported are net of royalties and the Alberta Royalty Tax Credit.

Fiscal 2006 - Fiscal 2005

	Annual Net Production
			Increase
	2006	2005	Units	%
Natural gas (MCF)*	3,629,000	3,621,000	8,000	0	%
Oil (Bbl)**	145,000	139,000	6,000	4	%
Liquids (Bbl)**	115,000	114,000	1,000	1	%

	Annual Average Price Per Unit
					Increase
	2006		2005		$		%
Natural gas (MCF)*	$	6.67	$	5.93	$	0.74	12	%
Oil (Bbl)**	$	56.85	$	48.11	$	8.74	18	%
Liquids (Bbl)**	$	40.18	$	31.84	$	8.34	26	%

Fiscal 2005 - Fiscal 2004

	Annual Net Production
			Increase (Decrease)
	2005	2004	Units		%
Natural gas (MCF)*	3,621,000	3,383,000	238,000		7	%
Oil (Bbl)**	139,000	154,000	(15,000	)	(10	)%
Liquids (Bbl)**	114,000	105,000	9,000		9	%

	Annual Average Price Per Unit
					Increase
	2005		2004		$		%
Natural gas (MCF)*	$	5.93	$	4.60	$	1.33	29	%
Oil (Bbl)**	$	48.11	$	33.24	$	14.87	45	%
Liquids (Bbl)**	$	31.84	$	24.18	$	7.66	32	%

* MCF = 1,000 cubic feet. Natural gas price per unit is net of pipeline charges.

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

Oil and natural gas revenues increased $5,180,000 (16%) from $32,724,000 in fiscal 2005 to $37,904,000 in fiscal 2006, due to increases in prices for all petroleum products. Natural gas production increased 99,000 MCF at Dunvegan, Barnwell’s principal oil and gas property, and where Barnwell has invested approximately $9,750,000 in fiscal 2004 through fiscal 2006. Natural gas production also increased at Barnwell’s newer properties at Doris, Boundary Lake, Wood River and Bonanza/Balsam, but was more than offset by declines at Progress, Leduc, Malmo and Pouce Coupe South, which are also newer properties.

Oil production increased 6,000 barrels (4%) due to increased production from the Progress and Wood River areas. The increase was partially offset by declines in oil production from the Bonanza/Balsam area and the Red Earth area, which is Barnwell’s largest oil producing property and an older property.

The Alberta Royalty Tax Credit (“ARTC”) program has been discontinued by the Alberta government, effective January 1, 2007. In fiscal years 2006, 2005 and 2004, Barnwell received $438,000, $409,000 and $377,000, respectively, under the ARTC program. The ARTC payments were recorded as a credit against oil and natural gas royalties and reported in oil and natural gas revenues. In fiscal 2007, Barnwell expects to receive approximately $100,000 under the ARTC program, representing the ARTC for the period from October 1, 2006 to December 31, 2006. Beginning January 1, 2007, Barnwell will no longer receive ARTC payments.

Oil and natural gas revenues increased $8,884,000 (37%) from $23,840,000 in fiscal 2004 to $32,724,000 in fiscal 2005, due to increases in prices for all petroleum products and increases in natural gas production, partially offset by a decrease in net oil production. Natural gas production increased principally due to an increase in production at Dunvegan. Net natural gas production at Dunvegan increased 227,000 MCF or 15% and net natural gas liquids and oil production at Dunvegan increased 10,000 barrels or 12%. Natural gas production also increased at Barnwell’s newer properties at Doris, Malmo and Armada, but declined at Bonanza/Balsam, Leduc and Progress, which are also newer properties, and at other older properties which largely offset the net increase in production at the newer properties. Additionally, natural gas and natural gas liquids production at Dunvegan was reduced by approximately 30,000 MCF and 3,000 barrels, respectively, in fiscal 2005 as compared to fiscal 2004 due to plant maintenance in fiscal 2005. There was no such plant maintenance program in fiscal 2004.

Oil production declined in fiscal 2005 due to a 12,000 barrel (15%) decline in production at Barnwell’s largest oil producing property, Red Earth, principally due to the natural aging of the property. Oil production also declined at other mature properties but these declines were offset by increases in production at Bonanza/Balsam, one of Barnwell’s newer properties.

Oil and natural gas operating expenses

Operating expenses increased $1,318,000 (19%) to $8,217,000 in fiscal 2006, as compared to $6,899,000 in fiscal 2005. The increase was due to higher fuel, utilities and oilfield services costs at all properties, and higher repairs and maintenance costs at older properties and to a 7% increase in the average exchange rate of the Canadian dollar to the U.S. dollar that increased oil and natural gas operating expenses $535,000 in fiscal 2006 as compared to the prior year.

Operating expenses increased $926,000 (16%) to $6,899,000 in fiscal 2005, as compared to $5,973,000 in fiscal 2004. The increase was primarily due to an 8% increase in the average exchange rate of the Canadian dollar to the U.S. dollar that increased oil and natural gas operating expenses $546,000 in fiscal 2005 as compared to the prior year. Also contributing to the increase were operating expenses on new wells.

Sale of interest in leasehold land, Sale of development rights and Minority interest in earnings

In February 2004, Kaupulehu Developments, a land development general partnership in which Barnwell owns a 77.6% controlling interest, entered into a Purchase and Sale Agreement with WB KD Acquisition, LLC (“WB”) by which Kaupulehu Developments transferred its leasehold interest in approximately 870 acres zoned for resort/residential development, in two increments, to WB. There is

no affiliation between Kaupulehu Developments and WB. WB is affiliated with Westbrook Partners, the developers of the Kuki’o Resort located adjacent to the Hualalai Resort at Historic Ka’upulehu. The first increment (“Increment I”) is an area planned for approximately 80 single-family lots and a beach club on the portion of the property bordering the Pacific Ocean. The purchasers of the 80 single-family lots will have the right to apply for membership in the Kuki’o Resort Golf and Beach Club, which is located adjacent to and south of the Four Seasons Resort Hualalai at Historic Ka’upulehu. The second increment (“Increment II”) is the remaining portion of the approximately 870-acre property and is zoned for single-family and multi-family residential units and a golf course and clubhouse.

With respect to Increment I, Kaupulehu Developments received an $11,550,000 payment in February 2004 and is entitled to receive payment of the following percentages of the gross proceeds generated from the sale by WB of single-family lots in Increment I (“Percentage Payments”): 9% of the gross proceeds from single-family lot sales up to aggregate gross proceeds of $100,000,000; 10% of such aggregate gross proceeds greater than $100,000,000 but less than $300,000,000; and 14% of such aggregate gross proceeds in excess of $300,000,000. Minimum amounts of these Percentage Payments are due by certain dates. WB sold a total of five single-family lots and paid Kaupulehu Developments $3,660,000 in Percentage Payments during the year ended September 30, 2006. Revenue from the Percentage Payments was reduced by $220,000 of fees related to the sales, resulting in net revenues of $3,440,000 and a $2,688,000 operating profit, after minority interest. There were no lot sales, and therefore, no Percentage Payments received during fiscal 2005. There is no assurance that any future payments will be received.

In June 2006, Kaupulehu Developments entered into an Agreement (“Increment II Agreement”) with WB and WB KD Acquisition II, LLC (“WBKD”) by which Kaupulehu Developments sold its interest in Increment II, representing the remainder of the approximately 870 acres, to WBKD. There is no affiliation between Kaupulehu Developments and WB or WBKD. WB and WBKD are both affiliates of Westbrook Partners, developers of the nearby Kuki’o Resort. Pursuant to the Increment II Agreement, Kaupulehu Developments received a $10,000,000 payment and is entitled to receive future payments from WBKD based on a percentage of the sales prices of the residential lots, ranging from 3.25% to 14%, to be determined in the future depending upon a number of variables, including whether the lots are sold prior to improvement. The revenue from the $10,000,000 payment received in fiscal 2006 was reduced by $600,000 of fees related to the sale, $220,000 in other costs related to the sale, and approximately $2,983,000 of previously capitalized costs relating to Increment II, resulting in net revenues of $6,197,000 and a $4,621,000 operating profit, after minority interest. There were no Increment II Percentage Payments received during the year ended September 30, 2006. There is no assurance that any future payments will be received.

In addition, under the terms of the Increment II Agreement, WBKD has the exclusive right to negotiate with Kaupulehu Developments with respect to Lot 4C, which is comprised of approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Increment II. This right expires in June 2009 or, if WBKD completes any and all environmental assessments and surveys reasonably required to support a petition to the Hawaii State Land Use Commission for reclassification of Lot 4C zoning, in June 2012.

The sales of Kaupulehu Developments’ Increment I and Increment II leasehold land interests in fiscal 2004 and fiscal 2006, respectively, were accounted for pursuant to the provisions of SFAS No. 66 which provides specific sales recognition criteria to determine when land sale revenue can be recorded. The revenue recognized in fiscal 2004 from the $11,550,000 payment plus $350,000 of post-closing Interim Payments, was reduced by $693,000 of fees related to the sale, approximately $402,000 in other costs related to the sale, and $3,475,000 of previously capitalized costs relating to Increment I resulting in net revenues of $7,330,000 and an operating profit, after minority interest, of approximately $5,470,000. During fiscal 2005, Kaupulehu Developments received additional Interim Payments, before minority interest, totaling $550,000. The revenue recognized in fiscal 2006 from the $10,000,000 Increment II payment and the $3,660,000 of Percentage Payments received on the Increment I lot sales was reduced by $820,000 of fees related to the sale, $220,000 in other costs related to the sales, and approximately $2,983,000 of previously capitalized costs relating to Increment II resulting in net revenues of $9,637,000 and an operating profit, after minority interest, of approximately $7,309,000. The Increment I, Increment II and Interim Payment revenues, net of related fees and other costs, are recorded in the Consolidated Statements of Operations as “Sale of interest in leasehold land, net.”

The development rights held by Kaupulehu Developments are for residentially-zoned leasehold land within and adjacent to the Hualalai Golf Club and the second golf course and are under option to Kaupulehu Makai Venture, an unrelated entity. Sales of Kaupulehu Developments’ development rights are accounted for pursuant to the provisions of SFAS No. 66 which provides specific sales recognition criteria to determine when land sale revenue can be recorded. Net revenues from the sale of development rights were $2,702,000 in fiscal 2006 and $2,497,000 in fiscal years 2005 and 2004. In November 2005, Kaupulehu Makai Venture, an unrelated entity, paid Kaupulehu Developments a non-refundable payment of $2,875,000 upon exercising the portion of its development rights option due on December 31, 2005 of $2,656,250 and a $218,750 portion of its development rights option due on December 31, 2006. Revenue from the development rights sale was reduced by $173,000 of fees related to the sale, resulting in net revenues of $2,702,000 and a $2,111,000 operating profit, after minority interest, on the transaction. In December 2004 and 2003, Kaupulehu Makai Venture exercised the portion of its development rights option that was to expire and paid Kaupulehu Developments $2,656,000. Revenues from these development rights sales were reduced by $159,000 of fees related to the sale, resulting in net revenues of $2,497,000 and a $1,950,000 operating profit, after minority interest, on the transaction during each of fiscal years 2005 and 2004. There were no other costs deducted from revenues from the sale of development rights in the years ended September 30, 2006, 2005 and 2004 as all capitalized costs associated with the development rights were expensed in previous years. The development rights option revenues, net of related fees, are recorded in the Consolidated Statements of Operations as “Sale of development rights, net.”

The total amount of remaining future development rights option receipts at September 30, 2006, if all options are fully exercised, is $13,062,500, comprised of the balance of $2,437,500 due on December 31, 2006 and four payments of $2,656,250 due on each December 31 of years 2007 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 $173,000 in fees ($121,000 net of minority interest) on the $2,875,000 development rights proceeds and the $820,000 in fees ($575,000 net of minority interest) on the

Percentage Payments and Increment II payment proceeds received in fiscal 2006, as well as the $159,000 in fees ($112,000, net of minority interest) on the proceeds from the sale of development rights in fiscal 2005 and 2004, and the $693,000 in fees ($486,000, net of minority interest) on the proceeds from the closing and Interim Payments received for the sale of interest in leasehold land in the year ended September 30, 2004 were paid to Nearco, Inc. (“Nearco”), a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 20.6% 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 2% of Kaupulehu Developments’ gross receipts from real estate transactions, and Cambridge Hawaii Limited Partnership, a 49.9% partner 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 4% of Kaupulehu Developments’ gross receipts from real estate transactions. 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 for consulting services related to Kaupulehu Developments’ leasehold land. In fiscal 2006, 2005 and 2004, consulting service fees paid to Nearco totaled $76,000, $268,000 and $273,000, respectively, and were included in general and administrative expenses. In addition, $52,000 of fees was paid to Nearco in fiscal 2004 for services related to the closing of the February 2004 sale of an interest in leasehold land. These fees were a direct cost of the sale and accordingly reduced the revenues recognized from the sale. Barnwell believes the fees are fair and reasonable compensation for such services.

Contract drilling

Contract drilling revenues and costs are associated with well drilling and water pump installation, replacement and repair in Hawaii.

Contract drilling revenues decreased $1,778,000 (23%) to $5,866,000 in fiscal 2006, as compared to $7,644,000 in fiscal 2005, and contract drilling operating expenses decreased $1,056,000 (18%) to $4,709,000 in fiscal 2006, as compared to $5,765,000 in fiscal 2005. Operating profit before general and administrative expenses decreased $786,000 (45%) from $1,754,000 in fiscal 2005 to $968,000 in fiscal 2006 due to a decrease in well drilling work coupled with a decrease in the values and margins of contracts performed in fiscal 2006, as compared to fiscal 2005. Contract drilling revenues and costs are not seasonal in nature but can fluctuate significantly based on the awarding and timing of contracts, which are determined by contract drilling customer demand. Management currently estimates that operating profit will be lower in fiscal 2007 due to lower estimated margins on contracts in backlog.

At September 30, 2006, there was a backlog of four well drilling contracts and nine pump installation and repair contracts, of which four, two well drilling and two pump installation and repair, were in progress as of September 30, 2006. The backlog of contract drilling revenues as of November 30, 2006 was approximately $4,900,000.

Contract drilling revenues increased $3,954,000 (107%) to $7,644,000 in fiscal 2005, as compared to $3,690,000 in fiscal 2004, and contract drilling operating expenses increased $2,581,000 (81%) to $5,765,000 in fiscal 2005, as compared to $3,184,000 in fiscal 2004. Operating profit before

general and administrative expenses increased $1,346,000 (330%) from $408,000 in fiscal 2004 to $1,754,000 in fiscal 2005 due to an increase in water well drilling activity and higher margins on contracts performed throughout most of fiscal 2005, as compared to fiscal 2004.

Gain on sale of drill rig

Barnwell sold a drill rig in fiscal 2006 for $712,000, net of costs associated with the sale, and recognized a gain of $700,000; there was no such sale in fiscal 2005. The drill rig was identical to one of Barnwell’s other drill rigs and was originally purchased to drill geothermal wells. The sale brings Barnwell’s drilling rig count to four rigs.

Gas processing and other income

Gas processing and other income increased $356,000 (45%) to $1,151,000 in fiscal 2006 as compared to $795,000 in fiscal 2005. The increase was primarily due to a $243,000 increase in interest income received from certificates of deposit and cash management funds, gains on sales of other assets of $73,000, and a $42,000 increase in gas processing revenues during fiscal 2006, as compared to fiscal 2005.

Gas processing and other income decreased $388,000 (33%) to $795,000 in fiscal 2005 as compared to $1,183,000 in fiscal 2004. In fiscal 2004, Kaupulehu Developments received $250,000 in income related to negotiations on the development of Kaupulehu Developments’ resort/residential acreage; such negotiation revenues discontinued with the consummation of Kaupulehu Developments’ sale of an interest in leasehold land in February 2004, therefore there were no such revenues in fiscal 2005. In addition, fiscal 2004 gas processing and other income included a $139,000 gain from the sale of a parcel of vacant land formerly used as a storage and maintenance yard by Barnwell’s contract drilling segment; there was no such sale in fiscal 2005.

General and administrative expenses

General and administrative expenses decreased $87,000 (1%) to $11,644,000 in fiscal 2006, as compared to $11,731,000 in fiscal 2005. The decrease was primarily due to a $3,061,000 decrease in stock appreciation rights expense for the year ended September 30, 2006 due to fluctuations in Barnwell’s stock price, partially offset by an increase in the number of shares vested. This decrease was partially offset by increased personnel costs of $1,323,000; increased professional services incurred in connection with the preparation for future requirements to comply with the Sarbanes-Oxley Act, legal fees related to the land segment, audit fees and actuarial fees for a total of $1,000,000; decreased administrative expense reimbursements from oil and natural gas joint venture partners of $523,000; and an increase in share-based compensation of $144,000 due to implementation of SFAS No. 123(R) during the year ended September 30, 2006.

General and administrative expenses increased $3,820,000 (48%) to $11,731,000 in fiscal 2005, as compared to $7,911,000 in fiscal 2004. The increase was due in part to a $2,509,000 increase in stock appreciation rights expense resulting from an increase in Barnwell’s stock price and the issuance of additional stock options with stock appreciation rights in fiscal 2005, as compared to the prior year. Personnel costs also increased by $1,192,000 in fiscal 2005 as a result of the addition of new personnel in the oil and natural gas operations and increased compensation costs. In addition, professional fees

increased $215,000 in fiscal 2005 due to higher legal and audit fees, as a result of increased costs of regulatory compliance, and consulting services related to Barnwell’s oil and natural gas leases.

General and administrative expenses also includes fees paid to Nearco, an entity controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 20.6% owner of Kaupulehu Developments, for consulting services related to Kaupulehu Developments’ leasehold land. Fees paid to Nearco totaled $76,000, $268,000 and $273,000 in fiscal 2006, 2005 and 2004, respectively. Barnwell believes the fees are fair and reasonable compensation for such services.

Depletion, depreciation and amortization

Depletion, depreciation and amortization increased $2,789,000 (32%) to $11,577,000 in fiscal 2006, as compared to $8,788,000 in fiscal 2005, due to a 22% increase in the depletion rate, a 1% increase in production (in MCF equivalents where one barrel of oil and natural gas liquids are converted to 5.8 MCF equivalents) and a 7% increase in the average exchange rate of the Canadian dollar to the U.S. dollar.

The higher depletion rate is due to increases in Barnwell’s costs of finding and developing proven reserves, and costs that are incurred to decrease the rate of production declines or maintain or increase rates of production from reserves found in previous years. Barnwell’s cost of finding and developing proven reserves has increased due to the cost of oil and natural gas exploration and development having increased along with product prices and the drilling of unsuccessful wells.

Depletion, depreciation and amortization increased $2,027,000 (30%) to $8,788,000 in fiscal 2005, as compared to $6,761,000 in fiscal 2004, due to a 17% increase in the depletion rate, a 4% increase in production (in MCF equivalents where one barrel of oil and natural gas liquids are converted to 5.8 MCF equivalents) and an 8% increase in the average exchange rate of the Canadian dollar to the U.S. dollar.

Interest expense

Interest expense increased $217,000 (35%) to $833,000 in fiscal 2006, as compared to $616,000 in fiscal 2005, due to higher average interest rates and, to a lesser degree, higher average loan balances during fiscal 2006 as compared to fiscal 2005. The average interest rate incurred during fiscal 2006 on Barnwell’s borrowings from Royal Bank of Canada increased to 6.67%, as compared to 4.82% in fiscal 2005. The weighted-average balance of outstanding borrowings from Royal Bank of Canada increased to $11,640,000 in fiscal 2006 as compared to $10,300,000 in fiscal 2005.

Interest expense increased $129,000 (26%) to $616,000 in fiscal 2005, as compared to $487,000 in fiscal 2004, due to higher average interest rates during fiscal 2005 as compared to fiscal 2004. The average interest rate incurred during fiscal 2005 on Barnwell’s borrowings from Royal Bank of Canada increased to 4.82%, as compared to 3.67% in fiscal 2004. The weighted-average balance of outstanding borrowings from Royal Bank of Canada remained relatively unchanged at approximately $10,300,000 in fiscal 2005 and 2004.

The majority of Barnwell’s debt is denominated in U.S. dollars. Therefore, the increase in the average exchange rate of the Canadian dollar to the U.S. dollar had a minimal impact on interest expense.

Foreign currency fluctuations

In addition to U.S. operations, Barnwell conducts 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 7% in fiscal 2006, as compared to fiscal 2005, and the exchange rate of the Canadian dollar to the U.S. dollar increased 4% at September 30, 2006, as compared to September 30, 2005. Accordingly, the revenues and expenses and assets, liabilities and stockholders’ equity 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. The fiscal year average exchange rate of the Canadian dollar to the U.S. dollar increased 8% in fiscal 2005, as compared to fiscal 2004, and the exchange rate of the Canadian dollar to the U.S. dollar increased 9% at September 30, 2005, as compared to September 30, 2004. Other comprehensive income due to foreign currency translation adjustments for fiscal 2006 was $1,140,000, a $403,000 decrease from other comprehensive income of $1,543,000 in fiscal 2005.

Foreign currency transaction gains and losses were not material in fiscal 2006, 2005, and 2004 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

In May 2006, a bill reducing the Province of Alberta’s corporate tax rate from 11.5% to 10.0% effective April 1, 2006 received Royal Assent and was passed into law. In June 2006, Royal Assent was received on a bill passed by the Parliament of Canada which reduces the federal corporate income tax rate to 19% from 21% by 2010 starting January 1, 2008. The federal corporate surtax will also be eliminated effective January 1, 2008. Accordingly, during the year ended September 30, 2006, Barnwell’s Canadian net deferred income tax liabilities were reduced by approximately $1,094,000 as a result of these reductions in Canadian tax rates. There was no benefit attributable to changes in Canada’s federal or Alberta’s provincial corporate tax rates in the year ended September 30, 2005.

Also included in the provision for income taxes for the year ended September 30, 2006 is the recognition of a deferred income tax benefit of $4,130,000 due to a reduction in the valuation allowance for foreign tax credit carryforwards. The acceleration of Barnwell’s investments in Canadian oil and natural gas properties beginning in the first quarter of fiscal 2006 resulted in the determination that it was more likely than not that fiscal 2006 and future years’ taxable income from Canadian operations under U.S. tax law will exceed taxable income from Canadian operations under Canadian tax law to a degree that will result in the utilization of foreign tax credit carryforwards to

reduce U.S. taxes. This is primarily attributable to differences in the statutory deduction rates for Barnwell’s Canadian oil and natural gas capital expenditures under Canadian tax law as compared to such deductions under U.S. tax law. There was no reduction in the valuation allowance for foreign tax credit carryforwards in the year ended September 30, 2005. Barnwell’s estimates of the tax effects of temporary differences under both Canadian tax jurisdiction and U.S. tax jurisdiction that give rise to deferred tax assets and liabilities and estimates of deferred tax asset valuation allowances require subjective assumptions including, among others, estimates of Canadian taxable income, U.S. taxable income and Canadian capital expenditures in future years.

In November 2003, Royal Assent was received on a bill passed by the Parliament of Canada, which was then enacted into law, 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. Accordingly, during fiscal 2004, Barnwell’s Canadian net deferred income tax liabilities were reduced by approximately $1,440,000 due to the reduction in Canada’s federal corporate tax rate. There was no benefit attributable to changes in Canada’s corporate tax rate on “resource” income in fiscal 2005. Barnwell’s Canadian net deferred income tax liabilities were also reduced by approximately $300,000 in fiscal 2004 as a result of the Province of Alberta’s reduction of the province’s corporate tax rate from 13.0% to 12.5%, effective April 1, 2003 (enacted into law in December 2003), and from 12.5% to 11.5%, effective April 1, 2004 (enacted into law in May 2004).

Equity in earnings of real estate affiliate

In June 2006, Barnwell entered into an agreement with Nearco to form Mauka 3K for the purpose of providing real estate consulting services and investing in real estate. Barnwell and Nearco each have an equal 50% voting interest in Mauka 3K. Nearco is a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 20.6% owner of Kaupulehu Developments, a general partnership in which Barnwell owns a 77.6% controlling interest. Barnwell does not have a controlling interest in Mauka 3K and thus accounts for its investment utilizing the equity method of accounting. Under the equity method of accounting, Barnwell’s proportionate share of its affiliate’s income is included in equity in earnings of real estate affiliate.

In September 2006 Barnwell received net proceeds of $1,440,000 representing its share of real estate consulting revenues, less related expenses. The net proceeds are reflected in the Consolidated Statements of Operations as “Equity in earnings of real estate affiliate, net of tax.”

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. 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 May 2005, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 154, “Accounting Changes and Error Correction — a replacement of APB Opinion No. 20 and FASB Statement No. 3.” This statement changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. Accounting Principal Board (“APB”) No. 20 required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This statement requires retrospective application to prior period financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The provisions of SFAS No. 154 are effective for fiscal years beginning after December 15, 2005.

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 is aimed at improving the financial reporting of certain hybrid financial instruments by requiring more consistent accounting that eliminates exemptions and provides a means to simplify the accounting for these instruments. SFAS No. 155 is applicable to new or modified financial instruments in fiscal years beginning after September 15, 2006, though the provisions related to fair value accounting for hybrid financial instruments can also be applied to existing instruments. Early adoption, as of the beginning of an entity’s fiscal year, is also permitted, provided interim financial statements have not yet been issued. Adoption of the provisions of SFAS No. 155 is not expected to have a material impact on Barnwell’s financial condition, results of operations, or liquidity.

In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets,” which provides an approach to simplify efforts to obtain hedge-like (offset) accounting. SFAS No. 156 amends FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” with respect to the accounting for separately recognized servicing assets and servicing liabilities. SFAS No. 156 i) requires an entity to recognize a servicing asset or servicing liability each time it undertakes an obligation to service a financial asset by entering into a servicing contract in certain situations; ii) requires that a separately recognized servicing asset or servicing liability be initially measured at fair value, if practicable; iii) permits an entity to choose

either the amortization method or the fair value method for subsequent measurement for each class of separately recognized servicing assets or servicing liabilities; iv) permits at initial adoption a one-time reclassification of available-for-sale securities to trading securities by an entity with recognized servicing rights, provided the securities reclassified offset the entity’s exposure to changes in the fair value of the servicing assets or liabilities; and v) requires separate presentation of servicing assets and servicing liabilities subsequently measured at fair value in the balance sheet and additional disclosures for all separately recognized servicing assets and servicing liabilities. SFAS No. 156 is effective for all separately recognized servicing assets and liabilities as of the beginning of an entity’s fiscal year that begins after September 15, 2006, with earlier adoption permitted in certain circumstances. SFAS No. 156 also describes the manner in which it should be initially applied. Adoption of the provisions of SFAS No. 156 is not expected to have a material impact on Barnwell’s financial condition, results of operations, or liquidity.

In June 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109.” This interpretation prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement with tax authorities) for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. Barnwell’s management is currently evaluating the effect of these provisions on Barnwell’s results of operations, financial condition and liquidity.

In June 2006, the FASB ratified the consensus on Emerging Issues Task Force (“EITF”) Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement.” The scope of EITF 06-3 includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, Universal Service Fund contributions and some excise taxes. The Task Force affirmed its conclusion that entities should present these taxes in the income statement on either a gross or a net basis, based on their accounting policy, which should be disclosed pursuant to APB Opinion No. 22, “Disclosure of Accounting Policies.” If such taxes are significant and are presented on a gross basis, the amounts of those taxes should be disclosed. The consensus on EITF 06-3 will be effective for interim and annual reporting periods beginning after December 15, 2006. Barnwell’s management is currently evaluating the effect of these provisions on Barnwell’s results of operations, financial condition and liquidity.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, however, for some entities, the application of SFAS No. 157 will change current practice. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. Barnwell’s management is currently evaluating the effect of these provisions on Barnwell’s results of operations, financial condition and liquidity.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS No. 158 requires an employer to recognize the over-funded or under-funded status

of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS No. 158 also requires the measurement of defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position (with limited exceptions). Under SFAS No. 158, Barnwell will be required to recognize the funded status of its defined benefit postretirement plan and supplemental employee retirement plan and to provide the required disclosures. SFAS No. 158 is effective for fiscal years ending after December 15, 2006. If SFAS No. 158 were applied as of September 30, 2006, Barnwell would have recognized an additional pension and other postretirement benefit obligation of approximately $1,500,000 along with a corresponding decrease in accumulated other comprehensive income of approximately $990,000, net of $510,000 of deferred income tax benefits associated with the temporary difference between pension and postretirement liabilities recognized for book versus tax purposes.

In September 2006, the United States Securities and Exchange Commission issued Staff Accounting Bulletin (“SAB”) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB No. 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB No. 108 establishes an approach that requires quantification of financial statement errors based on the effects of each of the company’s balance sheet and statement of operations financial statements and the related financial statement disclosures. SAB No. 108 permits existing public companies to record the cumulative effect of initially applying this approach in the first year ending after November 15, 2006 by recording the necessary correcting adjustments to the carrying values of assets and liabilities as of the beginning of that year with the offsetting adjustment recorded to the opening balance of retained earnings. Additionally, the use of the cumulative effect transition method requires detailed disclosure of the nature and amount of each individual error being corrected through the cumulative adjustment and how and when it arose. Barnwell’s management is currently evaluating the effect of these provisions on Barnwell’s results of operations, financial condition and liquidity.

Liquidity and Capital Resources

Cash Flows, Debt and Available Credit

Cash flows provided by operations totaled $18,129,000 for fiscal 2006, an increase of $3,916,000 as compared to $14,213,000 of cash flows provided by operations for the same period in the prior year. The increase was due to higher operating cash flow generated by Barnwell’s oil and natural gas segment and to fluctuations in current assets and liabilities.

Cash flows used in investing activities totaled $7,304,000 for fiscal 2006, a decrease of $6,119,000 from cash flows used in investing activities of $13,423,000 in fiscal 2005. Cash inflows from investing activities increased during fiscal 2006, as compared to fiscal 2005, due primarily to Kaupulehu Developments’ receipt of a closing payment from the sale of its interest in Increment II which generated $9,180,000 of proceeds, net of expenses, in fiscal 2006; there were no sales related to Increment II in the prior year. The increase was also due to $3,440,000 of Percentage Payments, net of expenses, received from WB for WB’s Lot 4A Increment I sales; there were no such proceeds received

in fiscal 2005. Barnwell also received $2,702,000 of proceeds, net of expenses, from the sale of development rights during fiscal 2006, as compared to $2,497,000 of proceeds, net of expenses, received during fiscal 2005. Investing cash flows for the current year also include $1,700,000 of proceeds from the maturity of certificates of deposit, as compared to net investments in certificates of deposit of $313,000 in the prior year, and $712,000 of proceeds, net of associated costs, from the sale of a drill rig; there were no such fixed asset sales proceeds received in fiscal 2005. The increase in cash flows from investing activities was partially offset by an $8,670,000 increase in capital expenditures, primarily attributable to the oil and natural gas segment, to $25,385,000 in fiscal 2006, as compared to $16,715,000 in fiscal 2005.

Cash flows used in financing activities totaled $4,525,000 for the year ended September 30, 2006, a $4,523,000 increase from $2,000 of cash used in financing activities in fiscal 2005. This increase was primarily due to $3,095,000 of distributions made to minority interest partners in the current year, as compared to $513,000 of distributions in the prior year, and dividend payments totaling $1,430,000 in fiscal 2006, as compared to $802,000 in the prior year. Additionally, Barnwell borrowed $1,116,000 in long-term debt and received $197,000 in proceeds from the exercise of stock options in fiscal 2005; there were no long-term debt borrowings or proceeds from the exercise of stock options in fiscal 2006.

In December 2005, Barnwell declared a cash dividend of $0.025 per share payable January 4, 2006 to stockholders of record on December 20, 2005.

In February 2006, Barnwell declared a cash dividend of $0.05 per share payable March 15, 2006 to stockholders of record on March 1, 2006.

In May 2006, Barnwell declared a cash dividend of $0.05 per share payable June 15, 2006 to stockholders of record on June 1, 2006.

In August 2006, Barnwell declared a cash dividend of $0.05 per share, payable September 15, 2006, to stockholders of record on September 1, 2006.

Royal Bank of Canada has renewed Barnwell’s credit facility through April 2007 at $20,000,000 Canadian dollars, approximately US$17,932,000, at September 30, 2006. All other terms of the credit facility remained unchanged upon renewal. The bank affirmed that it will not require any repayments under the facility before October 1, 2007. Accordingly, Barnwell has classified outstanding borrowings under the facility as long-term debt.

At September 30, 2006, Barnwell had $11,972,000 in cash and cash equivalents, $3,226,000 in working capital, and approximately $6,197,000 of available credit under its credit facility with Royal Bank of Canada. Barnwell believes its current cash balances, future cash flows from operations, land segment proceeds from the sale of development rights and percentage of sales payments, and available credit will be sufficient to fund its estimated capital expenditures and operations for at least the next 12 months and settle incentive compensation liabilities in cash if necessary. However, if oil and natural gas

production 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 2007 review, Barnwell may be required to reduce expenditures or seek alternative sources of financing to make any required payments under the facility.

Oil and Natural Gas Capital Expenditures

Barnwell’s oil and natural gas capital expenditures, including accrued capital expenditures, increased $7,720,000 (42%) from $18,229,000 in fiscal 2005 to $25,949,000 in fiscal 2006. Barnwell participated in drilling 47 gross (13.5 net) wells, of which 40 gross (11.2 net) wells were initially deemed by management to be successful, and replaced 73% of oil production (including natural gas liquids) and 123% of natural gas production. Of these 47 gross wells in fiscal 2006, Barnwell initiated 28 gross (11.7 net) wells. Of the $25,949,000 total oil and natural gas properties investments for fiscal 2006, $3,273,000 (13%) was for acquisition of leases and lease rentals, $1,870,000 (7%) was for geological and geophysical costs, $15,878,000 (61%) was for intangible drilling costs, $4,328,000 (17%) was for production equipment, and $600,000 (2%) was for future site restoration and abandonment and other costs. The major areas of investments in fiscal 2006 were in the Progress, Pouce Coupe South, Simonette, Dunvegan, Swalwell, Josephine, Bonanza/Balsam, and Doris areas of Alberta.

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

	2006		2005		2004
	Gross	Net	Gross	Net	Gross	Net

Exploratory oil and natural gas wells	7	2.4	10	2.9	16	6.1

Development oil and natural gas wells	40	11.1	70	10.6	128	8.5

Successful oil and natural gas wells	40	11.2	69	10.3	134	11.2

Unsuccessful oil and natural gas wells	7	2.3	11	3.2	10	3.4

Barnwell estimates that oil and natural gas capital expenditures for fiscal 2007 will range from $13,500,000 to $16,000,000. This estimated amount may increase or decrease as dictated by management’s assessment of the oil and natural gas environment and prospects.

Subsequent Events

In December 2006, Barnwell declared a cash dividend of $0.10 per share payable January 15, 2007, to stockholders of record on December 28, 2006.

In November 2006, Kaupulehu Investors, LLC, a limited liability company wholly-owned by Barnwell, invested $3,000,000 in two unrelated limited liability companies to acquire a passive minority interest in Hualalai Resort, located at Kaupulehu, North Kona, Hawaii, which includes the Four Seasons Resort Hualalai at Historic Ka’upulehu, two golf courses and undeveloped residential property. Barnwell’s internal cash flows are expected to be sufficient to finance this investment.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse fluctuations in commodity prices, interest rates and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our most significant exposure in market risk is in the pricing of our oil, natural gas and natural gas liquids (“NGL”) production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our Canadian natural gas and NGL production. Pricing for oil, natural gas and NGL production has historically been volatile and unpredictable.

Currently, Barnwell accepts the volatility risk that oil and natural gas prices present as Barnwell has not entered into transactions utilizing derivative financial instruments or derivative commodity instruments. In addition, virtually none of Barnwell’s estimated 2007 oil or natural gas production is subject to fixed-price physical delivery contracts.

Interest Rate Risk

Barnwell is exposed to changes in U.S. and Canadian interest rates, primarily resulting from its borrowing and investing activities used to fund operations and maintain liquidity. Barnwell has a revolving credit facility which carries a variable interest rate that is tied to market indices. The credit facility is available in U.S. dollars at the London Interbank Offer Rate plus 2%, at U.S. prime plus 1%, or in Canadian dollars at Canadian prime plus 1%.

Foreign Currency Exchange Risk

Barnwell’s oil and natural gas operations are conducted in Canada and accordingly, Barnwell is subject to foreign currency risk. Barnwell’s net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Barnwell Industries, Inc.:

We have audited the accompanying consolidated balance sheets of Barnwell Industries, Inc. and subsidiaries as of September 30, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended September 30, 2006. 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 the standards of the Public Company Accounting Oversight Board (United States). 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended September 30, 2006, in conformity with U.S. generally accepted accounting principles. As discussed in note 10 to the consolidated financial statements, effective October 1, 2005, the Company changed its method of accounting for share-based payments.

/s/KPMG LLP

Honolulu, Hawaii
December 20, 2006

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

	September 30,
	2006		2005
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,972,000	$	5,492,000
Certificates of deposit	—		1,700,000
Accounts receivable, net	5,965,000		8,279,000
Deferred income taxes	4,173,000		3,030,000
Current taxes receivable	1,787,000		384,000
Other current assets	1,441,000		1,198,000
TOTAL CURRENT ASSETS	25,338,000		20,083,000

INVESTMENT IN LAND	50,000		3,033,000

PROPERTY AND EQUIPMENT, NET	79,167,000		61,861,000

TOTAL ASSETS	$	104,555,000	$	84,977,000

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,628,000	$	5,653,000
Accrued capital expenditures	4,832,000		4,462,000
Accrued stock appreciation rights	3,326,000		4,371,000
Accrued incentive plan costs	1,650,000		1,249,000
Other accrued compensation costs	4,096,000		3,828,000
Drilling advances	1,971,000		—
Other current liabilities	2,609,000		1,720,000
TOTAL CURRENT LIABILITIES	22,112,000		21,283,000

LONG-TERM DEBT	11,735,000		11,576,000

ASSET RETIREMENT OBLIGATION	3,753,000		2,845,000

DEFERRED INCOME TAXES	16,350,000		12,935,000

MINORITY INTEREST	—		312,000

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY:
Common stock, par value $0.50 per share: Authorized, 20,000,000 shares; 8,169,060 issued and outstanding	4,085,000		4,085,000
Additional paid-in capital	144,000		—
Retained earnings	43,524,000		30,317,000
Accumulated other comprehensive income, net	2,852,000		1,624,000
TOTAL STOCKHOLDERS’ EQUITY	50,605,000		36,026,000

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	104,555,000	$	84,977,000

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended September 30,
	2006			2005			2004
Revenues:
Oil and natural gas	$	37,904,000		$	32,724,000		$	23,840,000
Contract drilling	5,866,000			7,644,000			3,690,000
Sale of interest in leasehold land, net	9,637,000			550,000			7,330,000
Sale of development rights, net	2,702,000			2,497,000			2,497,000
Gain on sale of drill rig	700,000			—			—
Gas processing and other	1,151,000			795,000			1,183,000

	57,960,000			44,210,000			38,540,000

Costs and expenses:
Oil and natural gas operating	8,217,000			6,899,000			5,973,000
Contract drilling operating	4,709,000			5,765,000			3,184,000
General and administrative	11,644,000			11,731,000			7,911,000
Depletion, depreciation and amortization	11,577,000			8,788,000			6,761,000
Interest expense, net	833,000			616,000			487,000
Minority interest in earnings	2,783,000			417,000			2,207,000

	39,763,000			34,216,000			26,523,000

Earnings before income taxes and equity in earnings of real estate affiliate	18,197,000			9,994,000			12,017,000

Provision for income taxes	(4,455,000		)	(3,967,000		)	(3,307,000		)

Equity in earnings of real estate affiliate, net of tax	895,000			—			—

NET EARNINGS	$	14,637,000		$	6,027,000		$	8,710,000

BASIC EARNINGS PER COMMON SHARE	$	1.79		$	0.74		$	1.10
DILUTED EARNINGS PER COMMON SHARE	$	1.68		$	0.70		$	1.03

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC	8,169,060			8,152,531			7,943,682

DILUTED	8,698,405			8,643,032			8,441,372

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended September 30,
	2006			2005			2004
Cash flows from operating activities:
Net earnings	$	14,637,000		$	6,027,000		$	8,710,000
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation, depletion and amortization	11,577,000			8,788,000			6,761,000
Minority interest in earnings	2,783,000			417,000			2,207,000
Deferred income taxes	1,162,000			(1,587,000		)	(307,000		)
Accretion of asset retirement obligation	199,000			140,000			100,000
Asset retirement obligation payments	(20,000		)	—			—
Gain on sale of drill rig	(700,000		)	—			—
Share-based compensation	(1,066,000		)	3,036,000			680,000
Sale of development rights, net	(2,702,000		)	(2,497,000		)	(2,497,000		)
Sale of interest in leasehold land, net	(9,637,000		)	(550,000		)	(7,330,000		)
Gain on sale of contract drilling yard	—			—			(139,000		)
Increase (decrease) from changes in current assets and liabilities	1,896,000			439,000			(2,037,000		)

Net cash provided by operating activities	18,129,000			14,213,000			6,148,000

Cash flows from investing activities:
Proceeds from sale of interest in leasehold land, net	12,620,000			550,000			10,805,000
Proceeds from sale of development rights, net	2,702,000			2,497,000			2,497,000
Proceeds from matured certificates of deposit	1,700,000			3,087,000			595,000
Proceeds from sale of drill rig	712,000			—			—
Proceeds from gas over bitumen royalty adjustments	347,000			558,000			—
Proceeds from collection of note receivable	—			—			1,311,000
Proceeds from sale of contract drilling yard, net	—			—			440,000
Investments in certificates of deposit	—			(3,400,000		)	(1,982,000		)
Capital expenditures	(25,385,000		)	(16,715,000		)	(12,109,000		)

Net cash (used in) provided by investing activities	(7,304,000		)	(13,423,000		)	1,557,000

Cash flows from financing activities:
Distributions to minority interest partners	(3,095,000		)	(513,000		)	(2,633,000		)
Payment of dividends	(1,430,000		)	(802,000		)	(1,123,000		)
Long-term debt borrowings (repayments)	—			1,116,000			(1,408,000		)
Proceeds from exercise of stock options	—			197,000			218,000

Net cash used in financing activities	(4,525,000		)	(2,000		)	(4,946,000		)

Effect of exchange rate changes on cash and cash equivalents	180,000			207,000			90,000

Net increase in cash and cash equivalents	6,480,000			995,000			2,849,000

Cash and cash equivalents at beginning of year	5,492,000			4,497,000			1,648,000

Cash and cash equivalents at end of year	$	11,972,000		$	5,492,000		$	4,497,000

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
Years ended September 30, 2004, 2005 and 2006

												Accumulated
				Additional								Other					Total
		Common		Paid-In			Comprehensive		Retained			Comprehensive			Treasury		Stockholders’
	Shares	Stock		Capital			Income		Earnings			Income			Stock		Equity

Balance at September 30, 2003	7,887,060	$	3,944,000	$	—				$	17,180,000		$	(1,491,000	)	$	—	$	19,633,000

Exercise of stock options, 105,000 shares	105,000	52,000		166,000													218,000

Tax benefit from employee stock option transactions				51,000													51,000

Effect on current period activity of stock dividends issued to effect stock split				(217,000		)			217,000								—

Dividends declared ($0.14 per share)									(1,123,000		)						(1,123,000		)

Comprehensive income:
Net earnings							$	8,710,000	8,710,000								8,710,000
Other comprehensive income, net of income taxes – foreign currency translation adjustments							1,660,000					1,660,000					1,660,000
Total comprehensive income							$	10,370,000

At September 30, 2004	7,992,060	$	3,996,000	$	—				$	24,984,000		$	169,000		$	—	$	29,149,000

(continued on next page)

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
Years ended September 30, 2004, 2005 and 2006

(continued from previous page)

													Accumulated
				Additional									Other						Total
		Common		Paid-In			Comprehensive			Retained			Comprehensive			Treasury			Stockholders’
	Shares	Stock		Capital			Income			Earnings			Income			Stock			Equity

Balance at September 30, 2004	7,992,060	$	3,996,000	$	—					$	24,984,000		$	169,000		$	—		$	29,149,000

Exercise of stock options, 177,000 shares net of 30,000 tendered and placed in treasury	177,000	89,000		345,000												(237,000		)	197,000

Effect on current period activity of stock dividends issued to effect stock split				(345,000		)				108,000						237,000			—

Dividends declared ($0.10 per share)										(802,000		)							(802,000		)

Comprehensive income:
Net earnings							$	6,027,000		6,027,000									6,027,000
Other comprehensive income (loss):
Foreign currency translation adjustments, net of $1,277,000 of taxes							1,543,000						1,543,000						1,543,000
Minimum pension liability adjustment, net of $44,000 tax benefit							(88,000		)				(88,000		)				(88,000		)
Total comprehensive income							$	7,482,000

At September 30, 2005	8,169,060	$	4,085,000	$	—					$	30,317,000		$	1,624,000		$	—		$	36,026,000

(continued on next page)

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
Years ended September 30, 2004, 2005 and 2006

(continued from previous page)

											Accumulated
				Additional							Other				Total
		Common		Paid-In		Comprehensive		Retained			Comprehensive		Treasury		Stockholders’
	Shares	Stock		Capital		Income		Earnings			Income		Stock		Equity

Balance at September 30, 2005	8,169,060	$	4,085,000	$	—			$	30,317,000		$	1,624,000	$	—	$	36,026,000

Share-based compensation costs				144,000											144,000

Dividends declared, $0.175 per share								(1,430,000		)					(1,430,000		)

Comprehensive income:
Net earnings						$	14,637,000	14,637,000							14,637,000
Other comprehensive income:
Foreign currency translation adjustments, net of $641,000 of taxes						1,140,000					1,140,000				1,140,000
Minimum pension liability adjustment, net of $44,000 of taxes						88,000					88,000				88,000
Total comprehensive income						$	15,865,000

At September 30, 2006	8,169,060	$	4,085,000	$	144,000			$	43,524,000		$	2,852,000	$	—	$	50,605,000

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2006, 2005 AND 2004

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. Investments in companies over which Barnwell has the ability to exercise significant influence, but not control, are accounted for using the equity method.

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 66% of Barnwell’s revenues and 98% of Barnwell’s capital expenditures for the fiscal year ended September 30, 2006 were attributable to its oil and natural gas activities. Barnwell’s land investment segment revenues accounted for 21% of fiscal 2006 revenues; Barnwell’s contract drilling activities accounted for 10% of fiscal 2006 revenues; and other revenues comprised 3% of fiscal 2006 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

Revenues associated with the sale of oil, natural gas and natural gas liquids are recognized in the Consolidated Statements of Operations when the oil, natural gas and natural gas liquids are delivered and title has passed to the customer.

Investment in Land and Revenue Recognition

Costs incurred for the acquisition and improvement of leasehold land interests, including capitalized interest, are included in the Consolidated Balance Sheets under the caption “Investment in Land.”

Investment in Affiliate

owner of Kaupulehu Developments, a general partnership in which Barnwell owns a 77.6% controlling interest.

Barnwell has evaluated the aforementioned investment in accordance with FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” as revised, as well as other applicable authoritative accounting literature, and has determined that the investment in Mauka 3K does not meet the requirements for consolidation. Barnwell accounts for its investment in unconsolidated affiliates under the equity method when Barnwell’s ownership interest is more than 20% but no more than 50% and Barnwell does not exercise direct or indirect control over the investee. Factors that are considered in determining whether or not Barnwell exercises control include rights of partners regarding significant strategic and operational decisions. As Barnwell does not exercise direct or indirect control over Mauka 3K, the investment is accounted for using the equity method of accounting.

Revenues from real estate consulting services are recognized when services have been rendered and the terms of the consulting agreement have been satisfied.

Contract Drilling

Income Taxes

Retirement Plans

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. Additionally, Barnwell sponsors a Supplemental Employee Retirement Plan, a noncontributory supplemental retirement benefit plan which covers certain current and former employees of Barnwell for amounts exceeding the limits allowed under the pension plan. Barnwell accounts for its retirement plans in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” which requires that amounts recognized in financial statements be determined on an actuarial basis. SFAS 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 2006 and fiscal 2005, Barnwell assumed an expected long-term rate of return on plan assets of 8% and an expected rate of future annual compensation increases of 5%.

Long-lived Assets

Drilling rigs, premises and other property and equipment are depreciated using the straight-line method based on estimated useful lives.

Inventories

Inventories are comprised of drilling materials and are valued at the lower of weighted-average cost or market value.

Environmental

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

In September 2004, the U.S. Securities and Exchange Commission (“SEC”) released Staff Accounting Bulletin (“SAB”) No. 106 which expresses the SEC’s views regarding the application of SFAS No. 143, “Accounting for Asset Retirement Obligations,” by oil and gas producing companies following the full cost accounting method. SAB No. 106 addresses the calculation of ceiling tests for full-cost oil and gas companies, depreciation, depletion and amortization as affected by the adoption of SFAS No. 143, as well as the related required disclosures. Barnwell adopted the provisions of SAB No. 106 during the year ended September 30, 2004. The adoption of SAB No. 106 had no material impact on Barnwell’s financial condition, results of operations or liquidity.

Earnings Per Common Share

In December 2004, Barnwell’s Board of Directors declared a two-for-one stock split in the form of a 100% stock dividend. The shares were distributed on January 28, 2005 to all shareholders of record as of January 11, 2005. There were 1,361,510 shares outstanding on January 11, 2005 before the split. Barnwell issued 1,028,223 of new shares and utilized 333,287 shares of treasury stock to execute the stock dividend, resulting in outstanding shares of 2,723,020 following the split. Barnwell’s common stock began trading on a split-adjusted basis on January 31, 2005.

In October 2005, Barnwell’s Board of Directors declared a three-for-one stock split in the form of a 200% stock dividend. The shares were distributed on November 14, 2005 to all shareholders of record as of October 28, 2005. There were 2,723,020 shares outstanding on October 28, 2005. Barnwell issued 5,446,040 of new shares to execute the stock dividend, resulting in outstanding shares of 8,169,060 following the split. Barnwell’s common stock began trading on a split-adjusted basis on November 15, 2005.

All information in this Form 10-K has been adjusted where necessary to reflect the stock splits for all periods presented.

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, 2006, 2005 and 2004 are as follows:

	September 30, 2006
	Net Earnings		Shares	Per-Share
	(Numerator)		(Denominator)	Amount
Basic earnings per share	$	14,637,000	8,169,060	$	1.79
Effect of dilutive securities - common stock options	—		529,345
Diluted earnings per share	$	14,637,000	8,698,405	$	1.68

	September 30, 2005
	Net Earnings		Shares	Per-Share
	(Numerator)		(Denominator)	Amount
Basic earnings per share	$	6,027,000	8,152,531	$	0.74
Effect of dilutive securities - common stock options	—		490,501
Diluted earnings per share	$	6,027,000	8,643,032	$	0.70

	September 30, 2004
	Net Earnings		Shares	Per-Share
	(Numerator)		(Denominator)	Amount
Basic earnings per share	$	8,710,000	7,943,682	$	1.10
Effect of dilutive securities - common stock options	—		497,690
Diluted earnings per share	$	8,710,000	8,441,372	$	1.03

Share-Based Compensation

Effective October 1, 2005, Barnwell adopted the provisions of SFAS No. 123(R), “Share-Based Payment,” for its share-based compensation plans, using the modified prospective transition method. Barnwell previously accounted for these plans under the recognition and measurement principles of Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations and disclosure requirements established by SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.”

Under SFAS No. 123(R), share-based compensation cost is measured at fair value. Barnwell utilizes a closed-form valuation model to determine the fair value of each option award. Expected

volatilities are based on the historical volatility of Barnwell’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Barnwell’s stock price, and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

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 income, net.” 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 2006, 2005, and 2004.

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, asset retirement obligations, share-based payment arrangements, obligations for retirement plans, contract drilling estimated costs to complete, 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 are net of allowances for doubtful accounts of $10,000 as of September 30, 2006 and 2005. Included in accounts receivable are contract retainage balances of $298,000 and $531,000 as of September 30, 2006 and 2005, 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,
	2006		2005
Costs incurred on uncompleted contracts	$	10,616,000	$	8,854,000
Estimated earnings	1,963,000		1,760,000
	12,579,000		10,614,000
Less billings to date	12,179,000		10,228,000
	$	400,000	$	386,000

Costs and estimated earnings on uncompleted contracts are included in the Consolidated Balance Sheets as follows:

	September 30,
	2006			2005
Costs and estimated earnings in excess of billings on uncompleted contracts (included in other current assets)	$	783,000		$	758,000
Billings in excess of costs and estimated earnings on uncompleted contracts (included in other current liabilities)	(383,000		)	(372,000		)
	$	400,000		$	386,000

4. INVESTMENT IN LAND

Background

Barnwell owns a 77.6% controlling interest in Kaupulehu Developments, a Hawaii general partnership that 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 1993 and 2001, Kaupulehu Developments obtained the state and county zoning changes necessary to permit resort/residential development of approximately 870 acres.

Sale of Interest in Leasehold Land

In February 2004, Kaupulehu Developments entered into a Purchase and Sale Agreement with WB KD Acquisition, LLC (“WB”) by which Kaupulehu Developments transferred its leasehold interest in the aforementioned 870 acres zoned for resort/residential development, in two increments, to WB. There is no affiliation between Kaupulehu Developments and WB. WB is affiliated with Westbrook Partners, the developers of the Kuki’o Resort located adjacent to the Hualalai Resort at Historic Ka’upulehu. The first increment (“Increment I”) is an area planned for approximately 80 single-family lots and a beach club on the portion of the property bordering the Pacific Ocean. The purchasers of the 80 single-family lots will have the right to apply for membership in the Kuki’o Resort Golf and Beach Club, which is located adjacent to and south of the Four Seasons Resort Hualalai at Historic Ka’upulehu. The second increment (“Increment II”) is the remaining portion of the approximately 870-acre property and is zoned for single-family and multi-family residential units and a golf course and clubhouse.

the gross proceeds from single-family lot sales up to aggregate gross proceeds of $100,000,000; 10% of such aggregate gross proceeds greater than $100,000,000 but less than $300,000,000; and 14% of such aggregate gross proceeds in excess of $300,000,000. Minimum amounts of these Percentage Payments are due by certain dates. WB sold a total of five single-family lots and paid Kaupulehu Developments $3,660,000 in Percentage Payments during the year ended September 30, 2006. Revenue from the Percentage Payments was reduced by $220,000 of fees related to the sales resulting in net revenues of $3,440,000 and a $2,688,000 operating profit, after minority interest. There were no lot sales, and therefore, no Percentage Payments received during fiscal 2005. There is no assurance that any future payments will be received.

In June 2006, Kaupulehu Developments entered into an Agreement (“Increment II Agreement”) with WB and WB KD Acquisition II, LLC (“WBKD”) by which Kaupulehu Developments sold its interest in Increment II, representing the remainder of the approximately 870 acres, to WBKD. There is no affiliation between Kaupulehu Developments and WB or WBKD. WB and WBKD are both affiliates of Westbrook Partners, developers of the nearby Kuki’o Resort. Pursuant to the Increment II Agreement, Kaupulehu Developments received a $10,000,000 payment and is entitled to receive future payments from WBKD based on a percentage of the sales prices of the residential lots, ranging from 3.25% to 14%, to be determined in the future depending upon a number of variables, including whether the lots are sold prior to improvement. The revenue from the $10,000,000 payment received in fiscal 2006 was reduced by $600,000 of fees related to the sale, $220,000 in other costs related to the sale, and approximately $2,983,000 of previously capitalized costs relating to Increment II, resulting in net revenues of $6,197,000 and a $4,621,000 operating profit, after minority interest. There were no Increment II Percentage Payments received during the year ended September 30, 2006. There is no assurance that any future payments will be received.

In addition, under the terms of the Increment II Agreement, WBKD has the exclusive right to negotiate with Kaupulehu Developments with respect to Lot 4C, which is comprised of approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Increment II. This right expires in June 2009 or, if WBKD completes any and all environmental assessments and surveys reasonably required to support a petition to the Hawaii State Land Use Commission for reclassification of Lot 4C zoning, in June 2012.

approximately $7,309,000. The Increment I, Increment II and Interim Payment revenues, net of related fees and other costs, are recorded in the Consolidated Statements of Operations as “Sale of interest in leasehold land, net.”

Development Rights Under Option

The development rights held by Kaupulehu Developments are for residentially-zoned leasehold land within and adjacent to the Hualalai Golf Club and the second golf course and are under option to Kaupulehu Makai Venture, an unrelated entity. Sales of Kaupulehu Developments’ development rights are accounted for pursuant to the provisions of SFAS No. 66 which provides specific sales recognition criteria to determine when land sale revenue can be recorded. In December 2003 and 2004, Kaupulehu Makai Venture exercised the portion of its development rights option then due and paid Kaupulehu Developments non-refundable payments of $2,656,000 in both fiscal 2005 and 2004. In November 2005, Kaupulehu Makai Venture paid Kaupulehu Developments a non-refundable payment of $2,875,000 upon exercising its development rights option due on December 31, 2005 of $2,656,250 and a $218,750 portion of its development rights option due on December 31, 2006. In each of fiscal years 2005 and 2004, $2,656,000 of revenues attributable to the development rights sale were reduced by $159,000 of fees related to the sale, resulting in net revenues of $2,497,000 and a $1,950,000 operating profit, after minority interest, on the transactions. In fiscal 2006, the $2,875,000 development rights option revenues was reduced by $173,000 of fees related to the sale, resulting in net revenues of $2,702,000 and an operating profit, after minority interest, of $2,111,000. There were no other costs deducted from revenues from the sale of development rights in fiscal 2006, 2005 and 2004 as all capitalized costs associated with the development rights were expensed in previous years. The development rights option revenues, net of related fees, are recorded in the Consolidated Statements of Operations as “Sale of development rights, net.”

Fees

The aforementioned $173,000 in fees ($121,000 net of minority interest) on the $2,875,000 development rights proceeds and the $820,000 in fees ($575,000 net of minority interest) on the Percentage Payments and Increment II payment proceeds received in fiscal 2006, as well as the $159,000 in fees ($112,000, net of minority interest) on the proceeds from the sale of development rights in fiscal 2005 and 2004, and the $693,000 in fees ($486,000, net of minority interest) on the proceeds from the closing and Interim Payments received for the sale of interest in leasehold land in the year ended September 30, 2004 were paid to Nearco, Inc. (“Nearco”), a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 20.6% 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 2% of Kaupulehu Developments’ gross receipts from real estate transactions, and Cambridge Hawaii Limited Partnership, a 49.9% partner 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 4% of Kaupulehu Developments’ gross receipts from real estate transactions. The fees represent compensation for promotion and marketing of Kaupulehu Developments’ property and were determined based on the estimated fair value of such services.

Interests at September 30, 2006

The interests held by Kaupulehu Developments at September 30, 2006 include the development rights under option, the rights to receive percentage of sales payments on Increment I and Increment II of the two increments of the 870 acres, and approximately 1,000 acres of vacant leasehold land zoned conservation, which is under a right of negotiation with WBKD. There is no assurance that any future development rights option payments or percentage of sales payments will be received, nor is there any assurance that WBKD will enter into an agreement with Kaupulehu Developments regarding Lot 4C. These interests relate to land within and adjacent to the Hualalai Resort at Historic Ka’upulehu, between the Queen Kaahumanu Highway and the Pacific Ocean. Barnwell’s cost of Kaupulehu Developments’ interests is included in the September 30, 2006 and 2005 Consolidated Balance Sheets under the caption “Investment in Land” and consists of the following amounts:

	September 30,
	2006		2005
Leasehold land interests:
Zoned for resort/residential development – Increment I	$	—	$	—
Zoned for resort/residential development – Increment II	—		2,983,000
Zoned conservation	50,000		50,000
	50,000		3,033,000
Development rights under option	—		—
Total investment in land	$	50,000	$	3,033,000

5. INVESTMENT IN AFFILIATE

In June 2006, Barnwell entered into an agreement with Nearco to form Mauka 3K, LLC (“Mauka 3K”), for the purpose of providing real estate consulting services and investing in real estate. Barnwell and Nearco each have an equal 50% voting interest in Mauka 3K. Nearco is a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 20.6% owner of Kaupulehu Developments, a general partnership in which Barnwell owns a 77.6% controlling interest. Barnwell does not have a controlling interest in Mauka 3K and thus accounts for its investment utilizing the equity method of accounting. Under the equity method of accounting, Barnwell’s proportionate share of its affiliate’s income is included in equity in earnings of real estate affiliate.

Revenues from real estate consulting services are recognized when services have been rendered and the terms of the consulting agreement have been satisfied.

6. PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION

Barnwell’s property and equipment is detailed as follows:

	Estimated Useful Lives	Gross Property and Equipment		Accumulated Depreciation, Depletion and Amortization			Net Property and Equipment
At September 30, 2006:
Land		$	365,000	$	—		$	365,000
Oil and natural gas properties (full cost accounting)		157,562,000		(80,823,000		)	76,739,000
Drilling rigs and equipment	3 – 7 years	4,043,000		(3,606,000		)	437,000
Premises	40 years	857,000		(59,000		)	798,000
Other property and equipment	3 – 17 years	3,587,000		(2,759,000		)	828,000
Total		$	166,414,000	$	(87,247,000	)	$	79,167,000

				Accumulated
	Estimated	Gross		Depreciation,			Net
	Useful	Property and		Depletion and			Property and
	Lives	Equipment		Amortization			Equipment
At September 30, 2005:
Land		$	365,000	$	—		$	365,000
Oil and natural gas properties (full cost accounting)		126,105,000		(66,705,000		)	59,400,000
Drilling rigs and equipment	3 – 7 years	4,303,000		(3,951,000		)	352,000
Premises	40 years	857,000		(38,000		)	819,000
Other property and equipment	3 – 17 years	3,399,000		(2,474,000		)	925,000
Total		$	135,029,000	$	(73,168,000	)	$	61,861,000

In October 2004, the Government of Alberta enacted amendments to the Natural Gas Royalty Regulation which provide a mechanism to reduce royalties calculated through the Crown royalty system for operators of gas wells which have been denied the right to produce by the Alberta Energy Utilities Board as a result of recent bitumen conservation decisions. In December 2004, royalty reductions were effected by the Alberta Department of Energy’s Information Letter 2004-36 which

sets out the details of the royalty adjustment, the impact on the existing temporary assistance received to date by affected gas well operators, the provisions for potential recapture of the royalty adjustments, and continuation of impacted petroleum and natural gas agreements. Barnwell received a total of approximately $347,000 and $558,000 related to the aforementioned royalty adjustments for wells in the Thornbury area in fiscal years 2006 and 2005, respectively. It is Barnwell’s estimation that the subject Thornbury wells will not recommence production, thus no returns to the Government of Alberta of the royalty adjustments received would be required under the recapture provisions. Accordingly, the receipts are payments for deemed production by the Government of Alberta to Barnwell for condemnation of the wells, and such receipts were credited to oil and natural gas properties for book purposes.

On October 1, 2002, Barnwell adopted 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. 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. 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. During the year ended September 30, 2004, the asset retirement obligation was increased by $133,000 to reflect obligations incurred on new wells drilled and changes in the timing and amount of estimated future expenditures, by $100,000 for accretion of the asset retirement obligation, and by $110,000 for changes in foreign currency translation rates. During the year ended September 30, 2005, the asset retirement obligation was increased by $221,000 to reflect obligations incurred on new wells drilled, $545,000 for changes in the timing and amount of estimated future expenditures, $140,000 for accretion of the asset retirement obligation, and by $164,000 for changes in foreign currency translation rates. The changes due to the timing and amount of estimated future expenditures primarily resulted from an increase in the inflation-adjusted cost of abandonment and restoration services, due in part to recent rises in oil and natural gas prices.

During the year ended September 30, 2006, the asset retirement obligation was increased by $303,000 to reflect obligations incurred on new wells drilled, $302,000 for changes in the timing and amount of estimated future expenditures, $199,000 for accretion of the asset retirement obligation, and by $124,000 for changes in foreign currency translation rates. The changes due to the timing and amount of estimated future expenditures primarily resulted from an increase in the inflation-adjusted cost of abandonment and restoration services, due in part to recent rises in oil and natural gas prices. The increase was partially offset by $20,000 in abandonment and restoration disbursements in fiscal 2006.

7. LONG-TERM DEBT

Barnwell has a credit facility at Royal Bank of Canada, a Canadian bank, for approximately $17,932,000 at September 30, 2006. Borrowings under this facility were $11,735,000 and $11,576,000 at September 30, 2006 and 2005, respectively, and are included in long-term debt. At September 30, 2006, Barnwell had unused credit available under this facility of approximately $6,197,000.

The facility is available in U.S. dollars at the London Interbank Offer Rate plus 2%, at U.S. prime plus 1%, or in Canadian dollars at Canadian prime plus 1%. A standby fee of 0.5% 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 2007. Subject to that review, the facility may be extended one year with no required debt repayments for one year or converted to a two-year term loan by the bank. The primary focus of the annual review is on the future cash flows that will be generated by Barnwell’s Canadian oil and natural gas properties. Additionally, Royal Bank of Canada may adjust the total amount of the credit facility during its next review. If the facility is converted to a two-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, 2006, Barnwell paid interest at rates ranging from 5.841% to 7.400%. The weighted-average interest rate on the facility at September 30, 2006 was 7.217%. The facility is collateralized by Barnwell’s interests in its major oil and natural gas properties and a pledge not to otherwise pledge on its remaining oil and natural gas properties. The facility is guaranteed by Barnwell Industries, Inc. No compensating bank balances are required for this facility.

The bank affirmed that it will not require any repayments under the facility before October 1, 2007. Accordingly, Barnwell has classified outstanding borrowings under the facility as long-term debt.

Interest costs amounted to $833,000, $616,000 and $487,000 for the years ended September 30, 2006, 2005 and 2004, respectively.

8. TAXES ON INCOME

The components of earnings before income taxes are as follows:

	Year ended September 30,
	2006		2005			2004
Earnings (loss) before income taxes in:
United States	$	4,008,000	$	(2,091,000	)	$	3,592,000
Canada	14,189,000		12,085,000			8,425,000
	$	18,197,000	$	9,994,000		$	12,017,000

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

	Year ended September 30,
	2006			2005			2004
Current provision:
United States – Federal	$	723,000		$	310,000		$	594,000
United States – State	235,000			—			28,000
	958,000			310,000			622,000
Canadian	2,335,000			5,244,000			2,992,000
Total current	3,293,000			5,554,000			3,614,000

Deferred (benefit) provision:
United States	(555,000		)	(1,338,000		)	608,000
Canadian	1,717,000			(249,000		)	(915,000		)
Total deferred	1,162,000			(1,587,000		)	(307,000		)
	$	4,455,000		$	3,967,000		$	3,307,000

Included in the provision for income taxes for fiscal 2006 is a Canadian deferred tax benefit of $1,094,000 resulting from a reduction in Canadian tax rates. In May 2006, a bill reducing the Province of Alberta’s corporate tax rate from 11.5% to 10.0% effective April 1, 2006 received Royal Assent and was passed into law. In June 2006, Royal Assent was received on a bill passed by the Parliament of Canada which reduces the federal corporate income tax rate to 19% from 21% by 2010 starting January 1, 2008. The federal corporate surtax will also be eliminated effective January 1, 2008. Accordingly, Barnwell’s Canadian net deferred income tax liabilities were reduced in fiscal 2006 as a result of these reductions in Canadian tax rates.

Also included in the provision for income taxes for fiscal 2006 is the recognition of a deferred income tax benefit of $4,130,000 due to a reduction in the valuation allowance for foreign tax credit carryforwards. The acceleration of Barnwell’s investments in Canadian oil and natural gas properties beginning in the first quarter of fiscal 2006, coupled with Kaupulehu Developments’ receipt of proceeds related to Increment I, resulted in the determination that it was more likely than not that fiscal 2006 and future years’ taxable income from Canadian operations under U.S. tax law will exceed taxable income from Canadian operations under Canadian tax law to a degree that will result in the utilization of foreign tax credit carryforwards to reduce U.S. taxes. This is primarily attributable to differences in the statutory deduction rates for Barnwell’s Canadian oil and natural gas capital expenditures under Canadian tax law as compared to such deductions under U.S. tax law. There were no reductions in the valuation allowance for foreign tax credit carryforwards in the years ended September 30, 2005 or 2004. Approximately $2,600,000 of foreign tax credit carryforwards will be utilized to reduce U.S. income taxes for fiscal 2006. Barnwell’s estimates of the tax effects of temporary differences under both Canadian tax jurisdiction and U.S. tax jurisdiction that give rise to deferred tax assets and liabilities and estimates of deferred tax asset valuation allowances require subjective assumptions including, among others, estimates of Canadian taxable income, U.S. taxable income and Canadian capital expenditures in future years.

Effective for tax years beginning after December 31, 2004, the 90 percent limitation on using the alternative minimum tax foreign tax credit to offset alternative minimum taxes was repealed by the American Jobs Creation Act of 2004. Accordingly, beginning in fiscal 2006, Barnwell is permitted to

use the full alternative minimum tax foreign tax credit to offset alternative minimum taxes on foreign source income, notwithstanding any other limitations which may apply.

Barnwell’s U.S. deferred tax benefit of $1,338,000 for fiscal 2005 is primarily the result of increases in stock appreciation rights accruals, bonus accruals, the excess of depletion and depreciation for book purposes over tax, and alternative minimum tax credits generated during the year which are estimated to have future tax benefits.

Included in the provision for income taxes for fiscal 2004 is a $1,740,000 deferred tax benefit resulting from reductions in Canadian federal and provincial tax rates, partially offset by Barnwell’s $825,000 Canadian deferred tax provision resulting from changes in differences between Canadian assets and liabilities for book purposes versus Canadian assets and liabilities for Canadian tax purposes. In November 2003, Royal Assent was received on a bill passed by the Parliament of Canada, which was then enacted into law, 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. Accordingly, during fiscal 2004, Barnwell’s Canadian net deferred income tax liabilities were reduced by approximately $1,440,000 due to the reduction in Canada’s federal corporate tax rate. Barnwell’s Canadian net deferred income tax liabilities were also reduced by approximately $300,000 in fiscal 2004 as a result of the Province of Alberta’s reduction of the province’s corporate tax rate from 13.0% to 12.5%, effective April 1, 2003 (enacted into law in December 2003), and from 12.5% to 11.5%, effective April 1, 2004 (enacted into law in May 2004).

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,
	2006			2005			2004
Tax expense computed by applying statutory rate	$	6,369,000		$	3,498,000		$	4,206,000

Effect of reduction of Canadian tax rates on Canadian deferred taxes	(1,094,000		)	—			(1,740,000		)
Effect of reduction of the valuation allowance for foreign tax credit carryforwards	(4,130,000		)	—			—
Effect of foreign tax rate differential and valuation reserve	2,689,000			302,000			525,000
State net operating losses (generated) utilized	45,000			(45,000		)	83,000
State income taxes	235,000			—			28,000
Other	341,000			212,000			205,000
	$	4,455,000		$	3,967,000		$	3,307,000

Equity in earnings of real estate affiliate is shown net of income taxes in the Consolidated Statement of Operations for fiscal 2006. The tax provision relating to equity in earnings of real estate affiliate was $545,000 in fiscal 2006, representing a 38% effective tax rate.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at September 30, 2006 and 2005 are as follows:

	2006			2005
Deferred income tax assets:
U.S. tax effect of deferred Canadian taxes	$	3,934,000		$	3,206,000
Foreign tax credit carryforwards	1,522,000			4,130,000
Tax basis of investment in land in excess of book basis	614,000			972,000
Liabilities accrued for books but not for tax under U.S. tax law	3,245,000			3,296,000
Liabilities accrued for books but not for tax under Canadian tax law	1,704,000			1,874,000
Alternative minimum tax credit carryforwards	—			461,000
Other	569,000			564,000
Total gross deferred tax assets	11,588,000			14,503,000
Less-valuation allowance	(6,159,000		)	(9,703,000		)
Net deferred income tax assets	5,429,000			4,800,000

Deferred income tax liabilities:
Property and equipment accumulated tax depreciation and depletion in excess of book under Canadian tax law	(13,273,000		)	(11,303,000		)
Property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law	(3,918,000		)	(3,064,000		)
Other	(415,000		)	(338,000		)
Total deferred income tax liabilities	(17,606,000		)	(14,705,000		)

Net deferred income tax liability	$	(12,177,000	)	$	(9,905,000	)

The total valuation allowance decreased $3,544,000 and $929,000 for the years ended September 30, 2006 and 2004, respectively, and increased $1,247,000 for the year ended September 30, 2005. The change in the valuation allowance in fiscal 2006 relates primarily to the abovementioned reduction of the valuation allowance previously placed on foreign tax credit carryforwards, partially offset by an increase in the valuation allowance for the U.S. tax effect of deferred Canadian taxes. The change in the valuation allowance in fiscal 2005 was due to an increase in stock appreciation rights accruals for a Canadian employee for which it is more likely than not that such accruals will not be utilized in the future to reduce Barnwell’s U.S. tax obligation. The change in the valuation allowance in fiscal 2004 was due to a decrease in foreign tax credit carryforwards as a result of the expiration of a portion of the carryforwards.

level of earnings or that the timing of U.S. earnings will coincide with the payment of Canadian taxes to enable Canadian taxes to be fully deducted (or recoverable) for U.S. tax purposes.

Net deferred tax assets at September 30, 2006 of $5,429,000 consists of $3,293,000 related to expenses accrued for book purposes but not for tax purposes, $614,000 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, and $1,522,000 for foreign tax credit carryforwards. Canadian deferred tax assets related to expenses accrued for book purposes but not for tax purposes are estimated to be realized through future Canadian income tax deductions against future Canadian oil and natural gas earnings. U.S. deferred tax assets related to expenses accrued for book purposes but not for tax purposes and the excess of the cost basis of investment in land for tax purposes over the cost basis of investment in land for book purposes are estimated to be realized from deductions against future U.S. earnings from land sale Percentage Payments, sales of interests in leasehold land, and sales of land development rights. Foreign tax credit carryforwards are estimated to be utilized when U.S. federal income taxes otherwise due on Canadian source income in a given year exceeds the foreign tax credit generated in that year. The foreign tax credit carryforward expires if not utilized on or before September 30, 2011. The amount of deferred income tax assets considered realizable may be reduced if estimates of future taxable income are reduced.

9. RETIREMENT PLANS

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. In addition, Barnwell sponsors a Supplemental Employee Retirement Plan (“SERP”), a noncontributory supplemental retirement benefit plan which covers certain current and former employees of Barnwell for amounts exceeding the limits allowed under the defined benefit pension plan. Barnwell recorded $95,000, $85,000 and $64,000 in expense associated with the SERP for the years ended September 30, 2006, 2005 and 2004, respectively. The plan is unfunded and Barnwell will fund benefits when payments are made. The total liability for the SERP was $499,000 and $410,000 at September 30, 2006 and 2005, respectively.

The overall investment objective of the defined benefit pension plan is to provide growth in the assets of the plan to fund future benefit obligations while managing risk in order to meet current benefit obligations. Generally, principal repayments and interest received on government mortgage securities provide cash flows to fund current benefit obligations. Longer-term obligations are generally estimated to be provided for by growth in equity securities. The plan assets at September 30, 2006 were invested as follows: 1% in cash, 18% in certificates of deposit, 28% in debt securities, and 53% in equity securities. The plan assets at September 30, 2005 were invested as follows: 3% in cash, 3% in a certificate of deposit, 41% in debt securities, and 53% in equity securities. Target asset allocations are not used, and allocations are adjusted from time to time as dictated by current and anticipated market conditions and required cash flows.

Barnwell contributed $1,050,000 to the pension plan in fiscal 2006 resulting in a prepaid pension cost of $234,000 at September 30, 2006. For the year ended September 30, 2006, Barnwell recognized a net periodic benefit cost of $299,000. There was no additional minimum liability as of September 30, 2006. Fluctuations in actual equity market returns as well as changes in general interest

rates will result in changes in the market value of plan assets and may result in increased or decreased retirement benefits costs and contributions in future periods.

The measurement date used to determine pension measures for the pension plan is September 30.

The funded status of the pension plan and the amounts recognized in the consolidated financial statements are as follows:

	September 30,
	2006			2005
Change in Benefit Obligation:
Benefit obligation at beginning of year	$	4,412,000		$	3,392,000
Service cost	206,000			161,000
Interest cost	226,000			213,000
Actuarial (gain) loss	(244,000		)	767,000
Benefits paid	(166,000		)	(121,000		)
Administrative expenses paid	(1,000		)	—
Statutory change	125,000			—
Benefit obligation at end of year	4,558,000			4,412,000

Change in Plan Assets
Fair value of plan assets at beginning of year	2,329,000			2,114,000
Actual return on plan assets	203,000			186,000
Employer contribution	1,050,000			150,000
Benefits paid	(166,000		)	(121,000		)
Administrative expenses paid	(1,000		)	—
Fair value of plan assets at end of year	3,415,000			2,329,000

Funded status	(1,143,000		)	(2,083,000		)
Unrecognized prior service cost	125,000			—
Unrecognized actuarial loss	1,252,000			1,566,000
Prepaid (accrued) benefit cost	$	234,000		$	(517,000	)

The accumulated benefit obligation for the pension plan was $2,992,000 and $2,978,000 at September 30, 2006 and 2005, respectively. SFAS No. 132 requires the recognition of a minimum liability equal to the excess, if any, of the accumulated benefit obligation over plan assets. At September 30, 2005, Barnwell recognized an additional minimum liability of $132,000 as the accrued benefit cost was less than the minimum liability. The increase in the additional minimum liability during the year ended September 30, 2005 was included in other comprehensive income; there was no additional minimum liability as of September 30, 2006.

The actuarial gain of $244,000 reported above in the “Change in Benefit Obligation” for the year ended September 30, 2006 is principally due to an increase in the discount rate from 5.25% at September 30, 2005 to 5.50% September 30, 2006.

	September 30,
	2006			2005
Amounts recognized in the consolidated balance sheet consist of:
(Prepaid) accrued benefit cost, excluding minimum pension liability	$	(234,000	)	$	517,000
Accumulated other comprehensive loss	—			132,000
Net amount recognized	$	(234,000	)	$	649,000

Assumptions used to determine the fiscal year-end benefit obligations:
Discount rate	5.50	%	5.25	%
Rate of compensation increase	5.00	%	5.00	%

	Year ended September 30,
	2006			2005			2004
Net Periodic Benefit Cost for the Year:
Service cost	$	206,000		$	161,000		$	121,000
Interest cost	226,000			213,000			180,000
Expected return on plan assets	(182,000		)	(171,000		)	(157,000		)
Amortization of prior service cost	1,000			6,000			6,000
Amortization of net actuarial loss	48,000			40,000			18,000
Net periodic benefit cost	$	299,000		$	249,000		$	168,000

	Year ended September 30,
	2006		2005		2004
Assumptions used to determine the net periodic benefit cost:
Discount rate	5.25	%	5.75	%	6.00	%
Expected return on plan assets	8.00	%	8.00	%	8.00	%
Rate of compensation increase	5.00	%	5.00	%	5.00	%

To develop the expected long-term rate of return on assets assumption, historical returns and the future expectations for returns for each asset class were considered.

Expected Benefit Payments:
Fiscal year ending September 30, 2007	$	154,000
Fiscal year ending September 30, 2008	$	154,000
Fiscal year ending September 30, 2009	$	154,000
Fiscal year ending September 30, 2010	$	154,000
Fiscal year ending September 30, 2011	$	154,000
Fiscal years ending September 30, 2012 through 2016	$	850,000

Barnwell estimates that it will contribute approximately $500,000 to the plan during fiscal 2007.

10. SHARE-BASED PAYMENTS

Barnwell has outstanding stock options issued to certain employees under both a qualified plan approved by shareholders (the 1998 Stock Option Plan) and non-qualified plans. The qualified options were granted with an exercise price equal to the market price of Barnwell’s stock on the date of grant (110% of market price at date of grant for options granted to affiliates), vest annually over four years of continuous service, and expire ten years from the date of grant (five years from date of grant for options granted to affiliates). The qualified plan permits the grant of share options to employees for up to 780,000 shares of common stock. A total of 774,000 share options have been granted under this plan, leaving 6,000 option shares available for grant under the qualified plan at September 30, 2006. The non-qualified options were granted with an exercise price equal to the market price of Barnwell’s stock on the date of grant, vest annually over five years of continuous service, and expire ten years from the date of grant. The non-qualified options have stock appreciation rights features 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. Barnwell currently has a policy of issuing new shares to satisfy share option exercises under the qualified plan and under the non-qualified plans when the optionee requests shares.

Effective October 1, 2005, Barnwell adopted the provisions of SFAS No. 123(R), “Share-Based Payment,” for its share-based compensation plans. Barnwell previously accounted for these plans under the recognition and measurement principles of APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations and disclosure requirements established by SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.”

Under SFAS No. 123(R), share-based compensation cost is measured at fair value. Barnwell utilizes a closed-form valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of Barnwell’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Barnwell’s stock price, and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. Share-based compensation expense recognized in earnings for the year ended September 30, 2006 and 2005 are reflected in “General and administrative” expenses in the Consolidated Statements

of Operations.

Equity-classified Awards

Compensation cost for equity-classified awards, such as Barnwell’s stock options issued under the qualified plan, is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. Total share-based compensation expense for equity-classified awards vested in the year ended September 30, 2006 was $144,000. There was no impact on income taxes as the expense relates to qualified options. There were no qualified option grants, exercises, expirations, or forfeitures in the year ended September 30, 2006. There was no share-based compensation expense for equity-classified awards vested in the year ended September 30, 2005.

A summary of equity-classified share options as of the beginning and end of the year ended September 30, 2006 is presented below:

Options	Shares	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at October 1, 2005	456,000	$	5.32
Outstanding at September 30, 2006	456,000	$	5.32	3.8	$	6,466,000
Exercisable at September 30, 2006	298,500	$	3.25	3.4	$	4,849,000

Liability-classified Awards

The following assumptions were used in estimating fair value for all liability-classified share options previously granted prior to October 1, 2005 and outstanding during the year ended September 30, 2006 (there were no options granted in fiscal 2006):

Expected volatility range		28.4% to 42.0%
Weighted-average volatility		33.0%
Expected dividends		1.0%
Expected term (in years)		0.8 to 6.0
Risk-free rate		4.7% to 4.9%
Expected forfeitures		None

Compensation cost for liability-classified awards, such as Barnwell’s non-qualified stock options with stock appreciation rights features, is remeasured at each period-end using a closed-form valuation model based on current values and is recognized as an expense over the requisite service period. Total share-based compensation expense for liability-classified awards was $439,000 for the year ended September 30, 2006. The related income tax benefit was $146,000 for the year ended September 30, 2006. Included in share-based compensation expense for liability-classified awards for the year ended September 30, 2006 was $740,000 of compensation expense related to shares that vested during the year and $301,000 of compensation benefit due to remeasurement at September 30, 2006 of the fair value of previously vested shares.

During the year ended September 30, 2006, an officer and an officer/director exercised the stock appreciation rights feature of 60,000 and 30,000 shares, respectively, of non-qualified options and $1,160,000 and $489,000, respectively, representing the differences between the exercise prices and the closing prices per share on the days prior to the dates of exercise were paid to the officer and officer/director, respectively, in cash by Barnwell. The actual tax benefits realized for the tax deductions of these exercises were $406,000 and $171,000, respectively, for the year ended September 30, 2006. There were no other liability-classified share option grants, exercises, expirations, or forfeitures in the year ended September 30, 2006.

A summary of liability-classified share options as of the beginning and end of the year ended September 30, 2006 is presented below:

					Weighted-
			Weighted-		Average
			Average		Remaining	Aggregate
			Exercise		Contractual	Intrinsic
Options	Shares		Price		Term	Value
Outstanding at October 1, 2005	390,000		$	5.94
Exercised	(90,000	)	$	4.67
Outstanding at September 30, 2006	300,000		$	6.32	5.6	$	3,954,000

Exercisable at September 30, 2006	132,000		$	3.17	2.3	$	2,156,000

As of September 30, 2006, there was $944,000 of total unrecognized compensation cost related to nonvested equity-classified and liability-classified share options. That cost is expected to be recognized over a weighted-average period of 2.7 years. Total share-based compensation expense related to the vesting of awards in the year ended September 30, 2006 was $884,000. Total share-based compensation expense for all awards, including the impact of changes in fair values for liability-classified awards, and the income tax benefit on total compensation expense for all awards was $583,000 and $146,000, respectively, for the year ended September 30, 2006.

Barnwell adopted SFAS No. 123(R) using the modified prospective method. Under this transition method, compensation cost recognized in the year ended September 30, 2006 includes the cost for equity-classified share options vested during the period and all vested liability-classified share-based awards granted prior to October 1, 2005, as determined under the provisions of SFAS No. 123(R). Share-based compensation cost for the year ended September 30, 2006 is reported in “General and administrative” expenses in the Consolidated Statement of Operations. The cumulative effect, net of income taxes, of the impact of adoption of SFAS No. 123(R) on liability-classified awards was not material to the consolidated financial statements. Results for prior periods have not been restated.

The following table illustrates the effect on net earnings and earnings per share as if the fair-value recognition provisions of SFAS No. 123 were applied to all of its share-based compensation awards for the prior year periods:

	Year ended September 30,
	2005			2004
Net earnings, as reported	$	6,027,000		$	8,710,000

Add: Share-based employee compensation expense of $3,500,000, less $1,256,000 of related taxes, included in reported net earnings for the year ended September 30, 2005 and $990,000, less $354,000 of related taxes, for the year ended September 30, 2004	2,244,000			636,000

Deduct: Total share-based employee compensation expense determined under the fair-value based method for all awards of $3,697,000, less $1,323,000 of related taxes, for the year ended September 30, 2005 and $996,000, less $354,000 of related taxes, for the year ended September 30, 2004	(2,374,000		)	(642,000		)

Pro forma net earnings	$	5,897,000		$	8,704,000

Basic Earnings Per Share:
As reported	$	0.74		$	1.10
Pro forma	$	0.72		$	1.10

Diluted Earnings Per Share:
As reported	$	0.70		$	1.03
Pro forma	$	0.68		$	1.03

Fair value measurement of options without stock appreciation rights that are included in fiscal 2005 pro forma net earnings was based on an option-pricing model which included assumptions of a weighted-average expected life of 5.57 years, expected volatility of 25%, risk-free interest rate of 4%, and an expected dividend yield of 1%. Fair value measurement of options without stock appreciation rights that are included in fiscal 2004 pro forma net earnings was based on an option-pricing model which included assumptions of a weighted-average expected life of 6.40 years, expected volatility of 30%, risk-free interest rate of 6.3%, and an expected dividend yield of 0%.

In December 2004, 210,000 equity-classified option shares were granted at a weighted-average grant-date fair value of $2.18. The total intrinsic value of equity options exercised during the year ended September 30, 2005 was $1,384,000; there were no expirations or forfeitures of equity-classified options during the year ended September 30, 2005.

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.

In March 1995, Barnwell granted 120,000 stock options to an officer/director of Barnwell under a non-qualified plan at a purchase price of $3.27 per share (market price on date of grant). These options had stock appreciation rights that permitted 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. During the year ended September 30, 2004, the officer/director exercised the stock appreciation rights feature of 78,000 shares of these options and $310,000, representing the difference between the exercise price and the closing prices per share on the days prior to the dates of exercise was paid to this employee in cash by Barnwell. During the year ended September 30, 2005, the officer/director exercised the stock appreciation rights feature of 42,000 shares of these options and $463,000, representing the difference between the exercise price and the closing price per share on the day prior to the date of exercise was paid to this officer/director in cash by Barnwell. Barnwell recognized $275,000 and $392,000 of compensation cost relating to these options in the years ended September 30, 2005 and 2004, respectively.

In June 1998, Barnwell granted 180,000 stock options to an officer of Barnwell’s oil and gas segment under a non-qualified plan at a purchase price of $2.60 per share (market price on date of grant). These options are fully vested and 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. During the year ended September 30, 2006, the officer exercised the stock appreciation rights feature on 60,000 shares of these options and the difference between the exercise price and the closing price per share on the day prior to the date of exercise ($21.93 per share) was paid to this officer in cash by Barnwell. The remaining 120,000 options expire in May 2008. Barnwell recognized a compensation benefit of $359,000 relating to these options in fiscal 2006 and $2,223,000 and $599,000 of compensation costs in the years ended September 30, 2005 and 2004, respectively.

In December 1999, Barnwell granted qualified stock options to certain employees of Barnwell to acquire 408,000 shares and 174,000 shares of Barnwell’s common stock with an exercise price per share of $1.98 (market price at date of grant) and $2.18 (110% of market price at date of grant), respectively. These options are fully vested. The $1.98 per share options expire in December 2009, and the $2.18 per share options expired in December 2004. During the years ended September 30, 2005 and 2004, Barnwell issued 207,000 shares and 105,000 shares, respectively, of its common stock to certain employees resulting from exercises of qualified stock options at exercise prices ranging from $1.98 to $2.18 per share. No compensation cost was recognized for these options for the years ended September 30, 2006, 2005 and 2004.

In December 2004, Barnwell granted qualified stock options to certain officers/directors of Barnwell to acquire 210,000 shares of Barnwell’s common stock at a weighted-average exercise price per share of $9.23 (based on grants at market price and 110% of market price at the date of grant). These options vest annually over four years commencing one year from the date of grant and expire in December 2014 and December 2009. No compensation cost was recognized for options granted under this plan for the year ended September 30, 2005. At September 30, 2005, 6,000 shares were available for grant under the qualified option plan.

In December 2004, Barnwell granted stock options to certain officers/directors of Barnwell to acquire 210,000 shares of Barnwell’s common stock under a non-qualified plan at a purchase price of

$8.80 per share (market price on date of grant). These options vest annually over five years commencing one year from the date of grant and expire in December 2014. 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. During the year ended September 30, 2006, an officer/director exercised the stock appreciation rights feature on 30,000 shares of these options and the difference between the exercise price and the closing price per share on the day prior to the date of exercise ($25.10 per share) was paid to this officer/director in cash by Barnwell. Barnwell recognized $798,000 and $1,001,000 of compensation costs relating to these options in the years ended September 30, 2006 and 2005, respectively.

There were no forfeitures or expirations of unexercised options in the years ended September 30, 2006, 2005 and 2004.

Barnwell plans to repurchase shares of its common stock from time to time in the open market or in privately negotiated transactions, depending on market conditions. In December 2005, Barnwell’s Board of Directors authorized the purchase of up to 250,000 shares.

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 $18,000, $131,000 and $60,000 of compensation expense pursuant to this incentive plan in fiscal 2006, 2005 and 2004, respectively.

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 $359,000, $90,000 and $190,000 of costs pursuant to this plan in fiscal 2006, 2005 and 2004, respectively.

Barnwell has several non-cancelable operating leases for office space and leasehold land. Rental expense was $528,000 in 2006, $481,000 in 2005, and $444,000 in 2004. Barnwell is committed under these leases for minimum rental payments summarized by fiscal year as follows: 2007 - $571,000, 2008 - $502,000, 2009 - $437,000, 2010 - $437,000, 2011 - $430,000 and thereafter through 2026 an aggregate of $1,685,000. The lease payments for land were subject to renegotiation as of January 1, 2006. Per the lease agreement, the lease payments will remain unchanged pending an appraisal, whereupon the lease rent could be adjusted to fair market value. Barnwell does not know the amount of the new lease payments which could be effective upon performance of the appraisal; they may remain unchanged or increase, and Barnwell currently expects the adjustment, if any, to not be material. The future rental payment disclosures above assume the minimum lease payments for land in effect at December 31, 2005 remain unchanged through December 2025, the end of the lease term.

Barnwell is committed to pay commissions to Nearco, Inc. (“Nearco”), a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 20.6% 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 2% of Kaupulehu Developments’

gross receipts from real estate transactions, and Cambridge Hawaii Limited Partnership, a 49.9% partner 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 4% of Kaupulehu Developments’ gross receipts from real estate transactions. The fees represent compensation for promotion and marketing of Kaupulehu Developments’ property and were determined based on the estimated fair value of such services.

In conjunction with the closing of the Increment II transaction in fiscal 2006, Kaupulehu Developments entered into an agreement to pay its external real estate legal counsel 1.5% of all Increment II Percentage Payments received by Kaupulehu Developments for services provided by its external real estate legal counsel in the negotiation and closing of the Increment II transaction. No amounts were paid pursuant to this arrangement in fiscal 2006.

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. Other primarily relates to gas processing.

	Year ended September 30,
	2006			2005			2004
Revenues:
Oil and natural gas	$	37,904,000		$	32,724,000		$	23,840,000
Land investment	12,339,000			3,047,000			10,077,000
Contract drilling	5,866,000			7,644,000			3,690,000
Other	765,000			652,000			827,000
Total before gain on sale and interest income	56,874,000			44,067,000			38,434,000
Gain on sale of drill rig	700,000			—			—
Interest income	386,000			143,000			106,000
Total revenues	$	57,960,000		$	44,210,000		$	38,540,000

Depletion, depreciation and amortization:
Oil and natural gas	$	11,130,000		$	8,447,000		$	6,423,000
Contract drilling	189,000			125,000			98,000
Other	258,000			216,000			240,000
Total	$	11,577,000		$	8,788,000		$	6,761,000

Operating profit (before general and administrative expenses):
Oil and natural gas	$	18,557,000		$	17,378,000		$	11,444,000
Land investment, net of minority interest	9,420,000			2,378,000			7,612,000
Contract drilling	968,000			1,754,000			408,000
Other	507,000			436,000			587,000
Total	29,452,000			21,946,000			20,051,000
General and administrative expenses, net of minority interest	(11,508,000		)	(11,479,000		)	(7,653,000		)
Interest expense	(833,000		)	(616,000		)	(487,000		)
Interest income	386,000			143,000			106,000
Gain on sale of drill rig	700,000			—			—
Earnings before income taxes and equity in earnings of real estate affiliate	$	18,197,000		$	9,994,000		$	12,017,000

Capital expenditures:
Oil and natural gas	$	25,949,000		$	18,229,000		$	11,876,000
Contract drilling	247,000			242,000			65,000
Other	178,000			406,000			1,191,000
Total	$	26,374,000		$	18,877,000		$	13,132,000

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 $2.17 in fiscal 2006, $1.66 in fiscal 2005, and $1.31 in fiscal 2004. The escalating depletion rate is the result of increased costs of finding and developing proven reserves, as compared to prior years, as well as increases in the

average exchange rate of the Canadian dollar to the U.S. dollar of 7% in fiscal 2006, as compared to fiscal 2005, and 8% in fiscal 2005, as compared to fiscal 2004.

ASSETS BY SEGMENT:

	September 30,
	2006				2005				2004
Oil and natural gas (1)	$	84,584,000	81	%	$	68,592,000	81	%	$	50,658,000	78	%
Contract drilling (2)	2,846,000		3	%	2,703,000		3	%	3,062,000		5	%
Land investment (2)	50,000		0	%	3,033,000		4	%	3,033,000		5	%
Other:
Cash and cash equivalents, and certificates of deposit	11,972,000		11	%	7,192,000		8	%	5,884,000		9	%
Corporate and other	5,103,000		5	%	3,457,000		4	%	2,450,000		3	%
Total	$	104,555,000	100	%	$	84,977,000	100	%	$	65,087,000	100	%

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

(2) Located in Hawaii.

LONG-LIVED ASSETS BY GEOGRAPHIC AREA:

	September 30,
	2006				2005				2004
United States	$	2,231,000	3	%	$	5,192,000	8	%	$	4,847,000	10	%
Canada	76,986,000		97	%	59,702,000		92	%	46,038,000		90	%
Total	$	79,217,000	100	%	$	64,894,000	100	%	$	50,885,000	100	%

REVENUE BY GEOGRAPHIC AREA:

	Year ended September 30,
	2006		2005		2004
United States	$	18,425,000	$	10,803,000	$	14,051,000
Canada	38,449,000		33,264,000		24,383,000
Total (excluding interest income and gain on sale of drill rig)	$	56,874,000	$	44,067,000	$	38,434,000

13. FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts of cash and cash equivalents, certificates of deposit, accounts receivable, and accounts 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 69% of its oil and natural gas revenues in fiscal 2006 from four individually significant customers, ProGas Limited (30%), Glencoe Resources Ltd. (15%), Plains Marketing Canada, L.P. (14%), and Seminole Canada Gas Company (10%). At September 30, 2006, Barnwell had a total of $1,625,000 in receivables from these four customers. In fiscal 2005 Barnwell derived 62% of its oil and natural gas revenues from four individually significant customers. In fiscal 2004 Barnwell derived 53% of its oil and natural gas revenues from three individually significant customers.

Barnwell’s contract drilling subsidiary derived 37%, 63%, and 70% of its contract drilling revenues in fiscal 2006, 2005, and 2004, respectively, pursuant to federal, State of Hawaii and county contracts. At September 30, 2006, Barnwell had accounts receivables from the federal, State of Hawaii and county entities totaling approximately $754,000. Barnwell has lien rights on wells drilled and pumps installed for federal, State of Hawaii, county and private entities.

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, 2006.

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,
	2006			2005			2004
Increase (decrease) from changes in:

Receivables	$	2,519,000		$	(2,450,000	)	$	(2,439,000	)
Other current assets	(1,664,000		)	151,000			(756,000		)
Accounts payable	(2,291,000		)	2,204,000			(353,000		)
Accrued incentive plan and other compensation costs	511,000			1,745,000			654,000
Other current liabilities	2,821,000			(1,211,000		)	857,000
Increase (decrease) from changes in current assets and liabilities	$	1,896,000		$	439,000		$	(2,037,000	)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest	$	833,000		$	616,000		$	448,000
Income taxes	$	5,273,000		$	5,293,000		$	4,495,000

16. SUBSEQUENT EVENTS

In December 2006, Barnwell declared a cash dividend of $0.10 per share payable January 15, 2007, to stockholders of record on December 28, 2006.

17. SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following is a summary of unaudited quarterly results of operations for the years ended September 30, 2006 and 2005:

Fiscal 2006:

	Quarter ended
	December 31		March 31		June 30		September 30

Revenues	$	17,601,000	$	13,467,000	$	17,147,000	$	9,745,000

Operating profit	$	10,427,000	$	6,838,000	$	9,317,000	$	2,870,000

Net earnings (1)	$	6,340,000	$	3,423,000	$	3,032,000	$	1,842,000	(3)

Basic earnings per common share (2)	$	0.78	$	0.42	$	0.37	$	0.23

Diluted earnings per common share (2)	$	0.73	$	0.39	$	0.35	$	0.21

Fiscal 2005:

	Quarter ended
	December 31		March 31		June 30		September 30

Revenues	$	12,597,000	$	10,026,000	$	9,900,000	$	11,687,000

Operating profit	$	6,645,000	$	4,842,000	$	4,428,000	$	6,031,000

Net earnings	$	2,440,000	$	910,000	$	874,000	$	1,803,000

Basic earnings per common share (2)	$	0.30	$	0.11	$	0.11	$	0.22

Diluted earnings per common share (2)	$	0.29	$	0.11	$	0.10	$	0.21

(1) The quarterly results for fiscal year 2006 reflect share-based compensation expense as a result of the adoption of SFAS No. 123(R) on a prospective basis in the first quarter of fiscal year 2006. Accordingly, the quarterly results for fiscal year 2005 do not reflect such expense.

(2) Due to the use of the weighted-average number of shares of common shares outstanding for each quarter for computing earnings per share, the sum of the quarterly per share amounts may not equal the per share amount for the year.

(3) Prior to the end of the quarter ended September 30, 2006, a holder of stock appreciation rights represented his intention to exercise a portion of those rights in stock in the future. Stock appreciation rights payments made in cash are deductible for Canadian income tax purposes. However, payments of stock appreciation rights in shares of Barnwell’s stock are not deductible for Canadian income tax purposes, thus a deferred tax valuation allowance was recorded for the portion of stock appreciation rights represented to be exercised in stock. During the three months ended September 30, 2006, the holder of these stock appreciation rights exercised a portion of his stock appreciation rights in cash and subsequently represented that he intends to exercise the remaining outstanding stock appreciation rights in cash. Accordingly, Barnwell recorded an approximately $350,000 deferred tax benefit in the three months ended September 30, 2006 related to the reduction of the valuation allowance for stock appreciation rights for Canadian income tax purposes to zero.

18. 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 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 and proved 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 natural gas liquids (“NGL”) and natural gas (“MCF” means 1,000 cubic feet of natural gas) which are all in Canada:

	OIL & NGL		GAS
	(Barrels)		(MCF)
Balance at September 30, 2003	1,401,000		27,639,000

Revisions of previous estimates	(7,000	)	(1,129,000	)
Proved undeveloped extensions and other additions	54,000	*	1,571,000	*
Extensions, discoveries and other additions	115,000		2,127,000
Less production	(259,000	)	(3,383,000	)
Balance at September 30, 2004	1,304,000		26,825,000

Revisions of previous estimates	76,000		(1,236,000	)
Extensions, discoveries and other additions	179,000		3,266,000
Less production	(253,000	)	(3,621,000	)
Balance at September 30, 2005	1,306,000		25,234,000

Revisions of previous estimates – due to discontinuation of Alberta Royalty Tax Credit	(24,000	)	(378,000	)
Revisions of previous estimates – due to other	91,000		(865,000	)
Extensions, discoveries and other additions	190,000		4,464,000
Less production	(260,000	)	(3,629,000	)
Balance at September 30, 2006	1,303,000		24,826,000

* These amounts represent proved undeveloped reserves at Dunvegan added by Paddock Lindstrom & Associates, Ltd. based on a drilling program that commenced and was completed in fiscal 2005. As of September 30, 2006, 2005 and 2003, Paddock Lindstrom & Associates, Ltd. reported no proved undeveloped reserves at Dunvegan.

	OIL & NGL	GAS
Proved producing reserves at:	(Barrels)	(MCF)
September 30, 2003	1,262,000	21,463,000
September 30, 2004	1,135,000	21,614,000
September 30, 2005	1,102,000	21,842,000
September 30, 2006	1,069,000	18,558,000

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

	September 30,
	2006		2005		2004
Proved properties	$	146,542,000	$	117,995,000	$	93,732,000
Unproved properties	11,020,000		8,110,000		5,100,000
Total capitalized costs	157,562,000		126,105,000		98,832,000
Accumulated depletion and depreciation	80,823,000		66,705,000		53,108,000
Net capitalized costs	$	76,739,000	$	59,400,000	$	45,724,000

	Year ended September 30,
	2006		2005		2004
Acquisition of properties:
Unproved	$	3,052,000	$	2,561,000	$	1,882,000

Proved	$	—	$	—	$	—

Exploration costs	$	8,935,000	$	3,448,000	$	3,460,000

Development costs	$	13,962,000	$	12,220,000	$	6,534,000

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

	Year ended September 30,
	2006		2005		2004
Gross revenues	$	51,197,000	$	43,931,000	$	31,776,000
Royalties, net of credit	13,293,000		11,207,000		7,936,000
Net revenues	37,904,000		32,724,000		23,840,000
Production costs	8,217,000		6,899,000		5,973,000
Depletion and depreciation	11,130,000		8,447,000		6,423,000
Pre-tax results of operations*	18,557,000		17,378,000		11,444,000
Estimated income tax expense	7,423,000		8,341,000		5,489,000
Results of operations*	$	11,134,000	$	9,037,000	$	5,955,000

* Before general and administrative expenses, interest expense, and foreign exchange gains and losses.

(E) Standardized Measure, Including Year-to-Year Changes Therein, of Estimated Discounted Future Net Cash Flows

The following tables have been developed pursuant to procedures prescribed by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities - an amendment of FASB Statements 19, 25, 33, and 39,” 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,
	2006			2005			2004
Future cash inflows	$	147,246,000		$	299,383,000		$	168,526,000

Future production costs	(53,961,000		)	(52,253,000		)	(40,351,000		)

Future development costs	(5,024,000		)	(2,430,000		)	(3,956,000		)

Future net cash flows before income taxes	88,261,000			244,700,000			124,219,000

Future income tax expenses	(20,552,000		)	(73,367,000		)	(35,937,000		)

Future net cash flows	67,709,000			171,333,000			88,282,000

10% annual discount for timing of cash flows	(17,786,000		)	(51,571,000		)	(27,272,000		)

Standardized measure of estimated discounted future net cash flows	$	49,923,000		$	119,762,000		$	61,010,000

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

	Year ended September 30,
	2006			2005			2004

Beginning of year	$	119,762,000		$	61,010,000		$	49,537,000


Sales of oil and natural gas produced, net of production costs	(29,735,000		)	(25,727,000		)	(17,875,000		)

Net changes in prices and production costs, net of royalties and wellhead taxes	(85,254,000		)	68,770,000			16,363,000

Extensions and discoveries	11,356,000			29,958,000			13,304,000		*

Revisions of previous quantity estimates	(5,006,000		)	(4,881,000		)	(2,294,000		)

Net change in Canadian dollar translation rate	4,189,000			4,050,000			2,529,000

Changes in the timing of future production and other	(385,000		)	100,000			(1,899,000		)

Net change in income taxes	22,529,000			(20,159,000		)	(3,956,000		)

Accretion of discount	12,467,000			6,641,000			5,301,000

Net change	(69,839,000		)	58,752,000			11,473,000

End of year	$	49,923,000		$	119,762,000		$	61,010,000

* $3,260,000 of this amount is derived from proved undeveloped reserves at Dunvegan added by Paddock Lindstrom & Associates, Ltd. based on a planned drilling program which commenced and was completed in fiscal 2005. As of September 30, 2006 and 2005, Paddock Lindstrom & Associates, Ltd. reported no proved undeveloped reserves at Dunvegan.

100

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

As of September 30, 2006, 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. There was no change in Barnwell’s internal control over financial reporting during the quarter ended September 30, 2006, that materially affected, or is reasonably likely to materially affect, Barnwell’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the 2007 Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2006, which proxy statement is incorporated herein by reference.

Barnwell adopted a Code of Ethics that applies to its chief executive officer and the chief financial officer. This Code of Ethics has been posted on Barnwell’s website at www.brninc.com.

ITEM 11. EXECUTIVE COMPENSATION

101

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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, 2006:

	(a)	(b)		(c)
	Number of	Weighted-		Number of securities
	securities	average		remaining available
	to be issued	price of		for future issuance
	upon exercise	outstanding		under equity
	of outstanding	options,		compensation plans
	options, warrants	warrants		(excluding securities
Plan Category	and rights	and rights		reflected in column (a))
Equity compensation plans approved by security holders	456,000	$	5.32	6,000
Equity compensation plans not approved by security holders	300,000	$	6.32	—
Total	756,000	$	5.72	6,000

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

In December 2004, Barnwell granted stock options to certain officers/directors of Barnwell to acquire 210,000 shares of Barnwell’s common stock under a non-qualified plan at a purchase price of $8.80 per share (market price on date of grant). These options have stock appreciation rights that permit the holders 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. These options vest annually over five years commencing one year from the date of grant and expire in December 2014. During the year ended September 30, 2006, an officer/director holding these options exercised the stock appreciation rights feature on 30,000 shares of these options.

102

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

103

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements

The following consolidated financial statements of Barnwell Industries, Inc. and its subsidiaries are included in Part II, Item 8:

Report of Independent Registered Public Accounting Firm – KPMG LLP

Consolidated Balance Sheets – September 30, 2006 and 2005

Consolidated Statements of Operations – for the three years ended September 30, 2006

Consolidated Statements of Cash Flows – for the three years ended September 30, 2006

Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the three years ended September 30, 2006

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) 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
No. 31.1		Certification of Chief Executive Officer Pursuant To 18 U.S.C. Section 1350, As Adopted Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
No. 31.2		Certification of Chief Financial Officer Pursuant To 18 U.S.C. Section 1350, As Adopted Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
No. 32		Certification of Chief Executive Officer and Chief Financial Officer Pursuant To 18 U.S.C. Section 1350, As Adopted Pursuant To 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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

BARNWELL INDUSTRIES, INC.
(Registrant)

	/s/ Russell M. Gifford
By:	Russell M. Gifford
	Chief Financial Officer,
	Executive Vice President,
	Treasurer and Secretary
Date:	December 7, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this 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 7, 2006

/s/ Alexander C. Kinzler		/s/ Russell M. Gifford
ALEXANDER C. KINZLER		RUSSELL M. GIFFORD
President, Chief Operating Officer,		Executive Vice President,
General Counsel and Director		Chief Financial Officer, Treasurer
Date: December 7, 2006		Secretary and Director
		Date: December 7, 2006

/s/ Martin Anderson		/s/ Alan D. Hunter
MARTIN ANDERSON, Director		ALAN D. HUNTER, Director
Date: December 7, 2006		Date: December 7, 2006

/s/ Murray C. Gardner		/s/ Terry Johnston
MURRAY C. GARDNER, Director		TERRY JOHNSTON, Director
Date: December 7, 2006		Date: December 7, 2006

/s/ Erik Hazelhoff-Roelfzema		/s/ Diane G. Kranz
ERIK HAZELHOFF-ROELFZEMA, Director		DIANE G. KRANZ, Director
Date: December 7, 2006		Date: December 7, 2006

/s/ Kevin K. Takata		/s/ Ahron H. Haspel
KEVIN K. TAKATA, Director		AHRON H. HASPEL, Director
Date: December 7, 2006		Date: December 7, 2006

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