** **

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

**FORM 10-K**

**(MarkOne)**
| **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** |

 

**CommissionFile Number 1-5103**

**BARNWELLINDUSTRIES, INC.******(Exact name of registrant asspecified 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                        |

 

Securitiesregistered pursuant to Section 12(g) of the Act:  **None**

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

oYes    x No

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

o Yes   xNo 
| 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 checkmark whether the registrant is a large accelerated filer, an accelerated filer,or a non-accelerated filer.  Seedefinition of “accelerated filer and large accelerated filer” in Rule 12b-2 ofthe Exchange Act.  (Check one):

Large acceleratedfiler o           Acceleratedfiler o            Non-acceleratedfiler x

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of theAct).                       oYes      x No

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

Asof December 20, 2006 there were 8,169,060 shares of common stockoutstanding.

Documents Incorporated byReference

1.                                       Proxystatement to be forwarded to shareholders on or about January 18, 2007 isincorporated by reference in Part III hereof.

 

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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                                                                            |   |   |

 

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PART I

**CAUTIONARYSTATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION**

**FOR THEPURPOSE OF “SAFE HARBOR” PROVISIONS OF THEPRIVATE SECURITIES LITIGATION REFORM ACT OF 1995**

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

*Among the important factors thatcould cause actual results to differ materially from those in theforward-looking statements are domestic and international general economicconditions, such as recessionary trends and inflation; domestic andinternational political, legislative, economic, regulatory and legal actions,including changes in the policies of the Organization of Petroleum ExportingCountries or other developments involving or affecting oil-producing countries;military conflict, embargoes, internal instability or actions or reactions ofthe government of the United States in anticipation of or in response to suchdevelopments; interest costs, restrictions on production, restrictions onimports and exports, the maintenance of specified reserves, tax increases andretroactive tax claims, expropriation of property, cancellation of contractrights, environmental protection controls, environmental compliancerequirements and laws pertaining to workers’ health and safety; the conditionof Hawaii’s real estate market, including the level of real estate activity andprices, 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, theintroduction of building code modifications, changes to zoning laws, thecondition of Hawaii’s tourism industry and the level of confidence in Hawaii’seconomy; levels of land development activity in Hawaii; levels of demand forwater well drilling and pump installation in Hawaii; the potential liabilityresulting from pending or future litigation; the company’s acquisition ordisposition of assets; the effects of changed accounting rules under generallyaccepted accounting principles promulgated by rule-setting bodies; and thefactors set forth under the heading “Risk Factors” in this Form 10-K, in otherportions of this Form 10-K, in the Notes to Consolidated Financial Statements,and in other documents filed by Barnwell with the Securities and ExchangeCommission (“SEC”).  In addition,unpredictable or unknown factors not discussed in this report could also causeactual results to materially and adversely differ from those discussed in theforward-looking statements.*

Unlessotherwise indicated, all references to “dollars” in this Form 10-K are to UnitedStates dollars.

3

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** **

**Item 1.        Business**

**Overview**

Barnwellenjoyed its 50th year of operations in fiscal 2006, having been incorporated inDelaware in 1956.  Barnwell has thefollowing 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 forgeothermal well drilling and workovers, and water pumping system installationand repair in Hawaii.

Barnwell’soil and natural gas activities comprise its largest business segment.  Approximately 66% of Barnwell’s revenues forthe fiscal year ended September 30, 2006 was attributable to its oil andnatural gas activities.  Barnwell’s landinvestment segment revenues accounted for 21% of fiscal 2006 revenues; Barnwell’scontract drilling activities accounted for 10% of fiscal 2006 revenues; andother revenues comprised 3% of fiscal 2006 revenues.  Approximately 98% of Barnwell’s capitalexpenditures for the fiscal year ended September 30, 2006 was attributableto oil and natural gas activities and 2% was applicable to its otheractivities.

**Oil andNatural Gas Segment**

Overview

Barnwell’s wholly-ownedsubsidiary, Barnwell of Canada, Limited (“Barnwell of Canada”), is involved inthe acquisition, exploration and development of oil and natural gasproperties.  Barnwell of Canada initiatesand participates in exploratory and developmental operations for oil andnatural gas on property in which it has an interest, and evaluates proposals bythird parties with regard to participation in such exploratory and developmentaloperations elsewhere.

Operations

Barnwell’sinvestments in oil and natural gas properties consist of investments in Canada,principally in the Province of Alberta, with minor holdings in the Provinces ofSaskatchewan and British Columbia.  Theseproperty interests are principally held under governmental leases orlicenses.  Under the typical Canadianprovincial governmental lease, Barnwell must perform exploratory operations andcomply with certain other conditions. Lease terms vary with each province, but, in general, the terms grantBarnwell the right to remove oil, natural gas and related substances subject topayment of specified royalties on production.

4

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Barnwellinitiates and participates in exploratory and developmental operations for oiland natural gas on property in which it has an interest.  Barnwell also evaluates proposals by thirdparties for participation in other exploratory and developmentalopportunities.  All exploratory anddevelopmental operations are overseen by Barnwell’s Calgary, Alberta staffalong with senior management and independent consultants as necessary.  In fiscal 2006, Barnwell participated inexploratory and developmental operations in the Canadian Province of Alberta,although Barnwell does not limit its consideration of exploratory anddevelopmental operations to this area.

TheProvince of Alberta determines its royalty share of natural gas and of oil byusing reference prices that average all natural gas sales and oil sales,respectively, in Alberta.  Royalty ratesare calculated on a sliding scale basis, increasing as prices increase up to amaximum royalty rate of 35%. Additionally, Barnwell pays gross overriding royalties and leaseholdroyalties on a portion of its natural gas and oil sales to parties other thanthe Province of Alberta.  

Infiscal 2006 and 2005, the weighted-average rate of all royalties paid on all ofBarnwell’s natural gas was approximately 28% and 27%, respectively.  The weighted-average rate of all royaltiespaid to governments and others on natural gas from the Dunvegan Unit, Barnwell’sprincipal oil and natural gas property, was approximately 30% and 31% in fiscal2006 and 2005, respectively.  Theincrease in royalty rate on all properties was primarily due to higher averagenatural gas prices.  The increase waspartially offset by the lower average royalty rate at Dunvegan in fiscal 2006as compared to fiscal 2005 which was due to royalty credits received from theAlberta Department of Energy for prior year capital and operating expendituresincurred by Barnwell on the Dunvegan property for the processing of naturalgas.

Infiscal 2006 and 2005, the weighted-average royalty rate paid on oil wasapproximately 23% and 24%, respectively. The decrease in the weighted-average royalty rate on oil was primarilydue to a higher percentage of Barnwell’s fiscal 2006 production of oil comingfrom newer wells where royalties are assessed at a lower rate than on olderwells.

Pricesof natural gas are typically higher in the winter than at other times due to demandfor heating.  Prices of oil are alsosubject to seasonal fluctuations, but to a lesser degree.  Unit sales of oil and natural gas are basedon 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 intounderground storage facilities for delivery at a future date.

WellDrilling Activities

Duringfiscal 2006, Barnwell participated in the drilling of 40 gross developmentwells and seven gross exploratory wells, of which management believes 40 shouldbe capable of production and seven are dry holes.  

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Thefollowing table sets forth more detailed information with respect to the numberof exploratory (“Exp.”) and development (“Dev.”) wells drilled for the fiscalyears ended September 30, 2006, 2005, and 2004 in which Barnwellparticipated:
|            | ** ** | **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 |   |

 

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*                 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 wellrepresents one gross well, but 0.5 net well. The gross figure includes interests owned of record by Barnwell and, inaddition, the portion owned by others.

Barnwellinvested $25,949,000 in oil and natural gas properties during fiscal 2006, ofwhich $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%) wasfor intangible drilling costs, $4,328,000 (17%) was for production equipment,and $600,000 (2%) was for future site restoration and abandonment and othercosts.  The major areas of investments infiscal 2006 were in the Progress, Pouce Coupe South, Simonette, Dunvegan,Swalwell, Josephine, Bonanza/Balsam, and Doris areas of Alberta.  

TheDunvegan Unit, in which Barnwell holds an 8.9% working interest, is Barnwell’sprincipal oil and natural gas property and is located in Alberta, Canada.  At September 30, 2006, the Dunvegan Unithad 197 producingnatural gas wells.  In fiscal 2006,Barnwell participated in the drilling of 12 gross (1.1 net) development gaswells 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 fiscal2005 and 2004, respectively.  Barnwell expects that fiscal 2007 capitalexpenditures at Dunvegan will decline slightly from fiscal 2006’s level withthe anticipated drilling of 10 gross (0.9 net) development gas wells.

Capitalexpenditures 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 consideredsuccessful.  In the Doris area Barnwellacquired oil and natural gas rights in 3,840 gross (2,240 net) acres ofundeveloped land in fiscal 2006.  AtSeptember 30, 2006 Barnwell’s average working interest in its productivewells in the Doris area was 46%. Barnwell expects to drill two to four gross wells in the Doris area infiscal 2007.

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

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

Capitalexpenditures totaled $6,094,000 in the Progress area in fiscal 2006 as comparedto $1,670,000 in fiscal 2005.  Threegross (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 andtwo gross (1.3 net) wells were successful but awaiting tie-in.  In the Progress area Barnwell acquired oiland natural gas rights in 640 gross (420 net) acres of undeveloped land infiscal 2006.  At September 30, 2006Barnwell’s average working interest in its productive wells in the Progressarea was 37%.  Barnwell plans on drillingfour to six gross wells in the Progress area in fiscal 2007.  

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

Capitalexpenditures totaled $2,101,000 in the Pouce Coupe South area in fiscal 2006 ascompared to $173,000 in fiscal 2005.  Twogross (0.9 net) wells were successfully drilled in fiscal 2006.  At September 30, 2006 Barnwell’s averageworking interest in its productive wells in the Pouce Coupe South area was53%.  Barnwell plans on drilling twogross wells in the Pouce Coupe South area in fiscal 2007.

Capitalexpenditures totaled $1,890,000 in the Simonette area in fiscal 2006.  One gross (0.1 net) well was successful andone gross (0.5 net) well drilled in fiscal 2005 initially estimated to beproductive was determined to be unsuccessful.

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

Capitalexpenditures totaled $1,101,000 in the Josephine area in fiscal 2006, a newarea 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’saverage 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 tofiscal 2005 was due to Barnwell taking a higher working interest in projectsthat were internally developed and initiated. In fiscal 2006, Barnwell initiated 28 gross (11.7 net) wellsas compared to 27 gross (8.8 net) wells in fiscal 2005.  The increase in fiscal 2005, as compared tofiscal 2004, was principally due to an 81 gross (2.7 net) well shallow gasdrilling program in fiscal 2004 in the Hilda area, where Barnwell’s interestaveraged 3.3%, reducing Barnwell’s average net interest in fiscal 2004.

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Oil andNatural Gas Production

Thefollowing table summarizes (a) Barnwell’s net unit production for the lastthree fiscal years, based on sales of crude oil, natural gas, condensate andother 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 suchproduction during the same periods. Production amounts reported are net of royalties and the Alberta RoyaltyTax Credit.  Barnwell’s net production infiscal 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 |   |

 

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

**                                  Calculatedon revenues before royalty expense and Alberta Royalty Tax Credit divided by grossproduction.  

***                           Calculatedon revenues net of pipeline charges before royalty expense and Alberta RoyaltyTax Credit divided by gross production.  

****                    Natural gasliquids, oil and natural gas units were combined by converting barrels ofnatural gas liquids and oil to an MCF equivalent (“MCFE”) on the basis of 1 BBL= 5.8 MCF.  Excludes natural gas pipelinecharges.

*****             Natural gasliquids, oil and natural gas units were combined by converting barrels ofnatural gas liquids and oil to an MCF equivalent (“MCFE”) on the basis of 1 BBL= 5.8 MCF.

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

Infiscal 2006, Barnwell’s net production after royalties for natural gas averaged9,940 MCF per day, a slight increase from 9,920 MCF per day in fiscal2005.  Gross natural gas production alsoincreased 1% in fiscal 2006, as compared to fiscal 2005.  Dunvegan contributed approximately 50% of Barnwell’snet natural gas production in fiscal 2006, an increase from 48% infiscal 2005 due to the new wells drilled at Dunvegan.

Barnwell’smajor oil producing properties are the Red Earth, Chauvin and Bonanza/Balsamareas in Canada.  In fiscal 2006, netproduction after royalties for oil averaged 400 barrels per day, an 

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

Infiscal 2006, net production after royalties for natural gas liquids averaged320 barrels per day, an increase of 3% from 310 barrels per day in fiscal 2005.  This increase was due to higher Dunveganproduction which increased 8% or 19 barrels perday.  Dunvegan contributed approximately 87% of Barnwell’snet 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 toindustry-wide increases in costs for oilfield services and utilities in Canadaand a 7% increase in the average exchange rate of the Canadian dollar to theU.S. dollar in fiscal 2006, as compared to fiscal 2005.

Theaverage depletion cost per MCFE was $2.17 for fiscal2006, a 31% increase from $1.66for fiscal 2005.  The increase was due toa 22% increase in thedepletion rate and a 7% increase in the average exchange rate of the Canadiandollar to the U.S. dollar.  The 22%increase in the depletion rate was due to an increase in Barnwell’s costs offinding and developing new proven reserves, and costs that are incurred tomaintain production from existing reserves. Barnwell’s cost of finding and developing proven reserves has increasedas the costs of oil and natural gas exploration and development has increasedin Canada, and increased capital costs attributed to existing reserves.

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

Infiscal 2005, Barnwell’s net production after royalties for natural gas averaged9,920 MCF per day, an increase of 7% from 9,240 MCF per day in fiscal2004.  Gross natural gas production alsoincreased 7% in fiscal 2005, as compared to fiscal 2004.  Dunvegan contributed approximately 48% of Barnwell’snet natural gas production in fiscal 2005, an increase from 44% in fiscal 2004due to the new well drilling at Dunvegan.

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

Infiscal 2005, net production after royalties for natural gas liquids averaged310 barrels per day, an increase of 7% from 290 barrels per day in fiscal2004.  This increase was due to higherDunvegan production which increased 12% or 29 barrels per day.  Dunvegan contributed approximately 82% ofBarnwell’s net natural gas liquids production in fiscal 2005.

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

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

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## ProductiveWells

 

The following table setsforth the gross and net number of productive wells Barnwell has an interest inas 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 |   |

 

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*                       Twenty-fournatural gas wells have dual or multiple completions.

**                Please see note(2) on the following table.

DevelopedAcreage and Undeveloped Acreage

Thefollowing table sets forth certain information with respect to oil and naturalgas 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 |   |

 

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(1)                “Developed Acreage”includes the acres covered by leases upon which there are one or more producingwells.  “Undeveloped Acreage” includesacres covered by leases upon which there are no producing wells and which aremaintained in effect by the payment of delay rentals or the commencement ofdrilling thereon.

(2)                “Gross” alsorefers to the total number of acres or wells in which Barnwell owns aninterest, and “Net” refers to Barnwell’s aggregate interest therein.  For example, a 50% interest in a 320 acrelease represents 320 gross acres and 160 net acres.  The gross acreage and well figures includeinterests owned of record by Barnwell and, in addition, the portion owned byothers.

Barnwell’sleasehold interests in its undeveloped acreage expire over the next fiscalyears, if not developed, as follows: 7% expire during fiscal 2007; 14% expireduring fiscal 2008; 28% expire during fiscal 2009; 25% expire during fiscal2010; and 15% expire during fiscal 2011. Eleven percent of Barnwell’s undeveloped acreage is related to heavy oiland therefore not subject to expiration. There can be no assurance that Barnwell will be successful in renewing itsleasehold interests in the event of expiration.

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Barnwell’sundeveloped acreage includes major concentrations in Alberta, at Bremner (8,640 net acres), Doris (7,392 netacres), 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 netacres), and Paddle River (5,184 net acres).

Reserves

Theamounts 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 provedreserves of crude oil (including condensate and natural gas liquids) andnatural gas as of September 30, 2006, 2005, and 2004 on all properties inwhich Barnwell has an interest.  Thesereserves are before deductions for indebtedness secured by the properties andare based on constant dollars.  Noestimates of total proved net oil or natural gas reserves have been filed withor included in reports to any federal authority or agency, other than theUnited 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 ProvedReserves  (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 |   |

 

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Asof September 30, 2006, essentially all of Barnwell’s proved producing andtotal proved reserves were located in the Province of Alberta, with minorvolumes located in the Provinces of Saskatchewan and British Columbia.

Duringfiscal 2006, Barnwell’s total net proved reserves, including proved producingreserves, of oil, condensate and natural gas liquids decreasedby 3,000 barrels, and total net proved reserves of natural gas decreased by408,000 MCF.

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

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

Barnwell’sworking 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 gasliquids reserves at September 30, 2006 and 2005, respectively. 

Thefollowing table sets forth Barnwell’s oil and natural gas reserves atSeptember 30, 2006, by property name, based on information prepared byPaddock Lindstrom & Associates Ltd. Gross reserves are before the deduction of royalties; net reserves areafter the deduction of royalties.  Thistable is based on constant dollars where reserve estimates are based on salesprices, costs and statutory tax rates in existence at the date of theprojection.  Oil, which includes naturalgas liquids (“NGL”), is shown in thousands of barrels (“MBBLS”) and natural gasis shown in millions of cubic feet (“MMCF”).

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OIL AND NATURAL GASRESERVES 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** | ** ** |

 

EstimatedFuture Net Revenues

Thefollowing table sets forth Barnwell’s “Estimated Future Net Revenues” fromtotal proved oil, natural gas and condensate reserves and the present value ofBarnwell’s “Estimated Future Net Revenues” (discounted at 10%).  Estimated future net revenues for totalproved reserves are net of estimated development costs.  Net revenues have been calculated usingcurrent 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 | * |

 

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*                 These amounts donot purport to represent, nor should they be interpreted as, the fair value ofBarnwell’s natural gas and oil reserves. An estimate of fair value would also consider, among other items, thevalue of Barnwell’s undeveloped land position, the recovery of reserves notpresently classified as proved, anticipated future changes in oil and naturalgas prices (these amounts were based on a natural gas price of $3.34 per 1,000cubic feet as of September 30, 2006) and costs, and a discount factor morerepresentative of the time value of money and the risks inherent in reserveestimates.

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Marketingof Oil and Natural Gas

Barnwellsells substantially all of its oil and natural gas liquids production undershort-term contracts between itself and marketers of oil.  The price of oil and natural gas liquids isfreely negotiated between the buyers and sellers and is largely determined bythe world price for oil, which is principally denominated in U.S. dollars.

Naturalgas sold by Barnwell is generally sold under both long-term and short-termcontracts with prices indexed to market prices. The price of natural gas and natural gas liquids is freely negotiatedbetween buyers and sellers and is principally determined for Barnwell by theNorth 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 Barnwellmarkets the products instead of having the operator of a producing propertymarket the products on Barnwell’s behalf.

Infiscal 2006, natural gas production from the Dunvegan Unit was responsible forapproximately 50% of Barnwell’s natural gas revenues, as compared to 46% infiscal 2005.  In fiscal 2006, Barnwellhad fourindividually significant marketers that accounted for 69% of Barnwell’s oil andnatural gas revenues.  A substantialportion of Barnwell’s Dunvegan natural gas production and natural gasproduction from other properties is sold to aggregators and marketers undervarious short-term and long-term contracts, with the price of natural gasdetermined by negotiations between the aggregators and the final purchasers.  In fiscal 2006, over 90% of Barnwell’s oiland natural gas revenues were from products sold at spot prices.

GovernmentalRegulation

Thejurisdictions in which the oil and natural gas properties of Barnwell arelocated have regulatory provisions relating to permits for the drilling ofwells, 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 issubject to control by regulatory agencies in each province that periodicallyassign allowable rates of production. The Province of Alberta and Government of Canada also monitor andregulate the volume of natural gas that may be removed from the province andthe conditions of removal.

Thereis no current government regulation of the price that may be charged on thesale of Canadian oil or natural gas production. Canadian natural gas production destined for export is priced by marketforces subject to export contracts meeting certain criteria prescribed byCanada’s National Energy Board and the Government of Canada. 

Differentroyalty rates are imposed by the provincial governments, the Government ofCanada and private interests with respect to the production and sale of crudeoil, natural gas and liquids.  In addition,provincial governments receive additional revenue through the imposition oftaxes on crude oil and natural gas owned by private interests within theprovince.  Essentially, provincialroyalties are calculated as a percentage of revenue and vary depending onproduction volumes, selling prices and the date of discovery.

In2002, Canadian taxpayers were not permitted to deduct royalties, taxes, rentalsand similar levies paid to the federal or provincial governments in connectionwith oil and natural gas production in computing income for Canadian federalincome tax purposes.  However, they wereallowed to deduct a “Resource Allowance” which is 25% of the taxpayer’s “ResourceProfits for the Year” 

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(essentially, netincome from the production of oil, natural gas or minerals) in computing theirtaxable income.  In November 2003, RoyalAssent was received on a bill passed by the Parliament of Canada, which wasthen enacted into law, to reduce Canada’s corporate tax rate on “resource”income (income derived from oil and natural gas operations) over a four-yearperiod beginning January 1, 2003 from 29% to 21% with the 21% tax ratecommencing on January 1, 2007. Additionally, the bill phases in over the same four-year period taxdeductions for royalties, which previously were not tax deductible, and phasesout the Resource Allowance deduction along with other changes.  Accordingly, during fiscal 2004, Barnwell’sCanadian 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 taxliabilities were also reduced by approximately $300,000 in fiscal 2004 as aresult of the Province of Alberta’s reduction of the province’s corporate taxrate from 13.0% to 12.5%, effective April 1, 2003 (enacted into law inDecember 2003), and from 12.5% to 11.5%, effective April 1, 2004 (enactedinto law in May 2004).

InMay 2006, a bill reducing the Province of Alberta’s corporate tax rate from11.5% to 10.0% effective April 1, 2006 received Royal Assent and waspassed into law.  In June 2006, RoyalAssent was received on a bill passed by the Parliament of Canada which reducesthe federal corporate income tax rate to 19% from 21% by 2010 startingJanuary 1, 2008.  The federalcorporate 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 byapproximately $1,094,000 as a result of these reductions in Canadian tax rates.

InAlberta, a producer of oil or natural gas is entitled to a credit against theroyalties payable to Alberta called the Alberta Royalty Tax Credit (“ARTC”).  The ARTC has been discontinued by the Albertagovernment effective January 1, 2007. Barnwell received ARTC payments of $438,000, $409,000 and $377,000 infiscal years 2006, 2005 and 2004, respectively. The ARTC payments were recorded as a credit against oil and natural gasroyalties and reported in oil and natural gas revenues.  In fiscal 2007, Barnwell expects to receiveARTC payments of approximately $100,000, representing the ARTC for the periodfrom October 1, 2006 to December 31, 2006.  Beginning January 1, 2007, Barnwell willno longer receive ARTC payments.

Competition

The majorityof Barnwell’s natural gas sales take place in Alberta, Canada.  Natural gas prices in Alberta are generallycompetitive with other major North American areas due to increased pipelinecapacity into the United States. Barnwell’s oil and natural gas liquids are sold in Alberta with pricesdetermined by the world price for oil.

Barnwellcompetes in the sale of oil and natural gas on the basis of price, and on theability to deliver products.  The oil andnatural gas industry is intensely competitive in all phases, including theexploration for new production and reserves and the acquisition of equipmentand labor necessary to conduct drilling activities.  The competition comes from numerous major oilcompanies as well as numerous other independent operators.  There is also competition between the oil andnatural gas industry and other industries in supplying the energy and fuelrequirements of industrial, commercial and individual consumers.  Barnwell is a minor participant in theindustry and competes in its oil and natural gas activities with many othercompanies having far greater financial, technical and other resources.

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**LandInvestment Segment**

Overview

Barnwell owns a 77.6% controlling interest inKaupulehu Developments, a Hawaii general partnership which owns interests inleasehold land and development rights for property located approximately sixmiles north of the Kona International Airport in the North Kona District of theisland of Hawaii.

Operations

Between 1986 and 1989, Kaupulehu Developments obtainedthe state and county zoning changes necessary to permit development of the FourSeasons Resort Hualalai at Historic Ka’upulehu and Hualalai Golf Club, whichopened in 1996, a second golf course, and single-family and multi-familyresidential units.  These projects weredeveloped on leasehold land acquired from Kaupulehu Developments by KaupulehuMakai Venture, an unrelated entity.  Thedevelopment rights held by Kaupulehu Developments are for residentially-zonedleasehold land within and adjacent to the two golf courses and are under optionto Kaupulehu Makai Venture.

Kaupulehu Developments later obtained the state andcounty zoning changes necessary to permit development of single-family andmulti-family residential units, a golf course and a limited commercial area onapproximately 870 leasehold acres located adjacent to and north of the FourSeasons Resort Hualalai at Historic Ka’upulehu.

InFebruary 2004, Kaupulehu Developments entered into a Purchase and SaleAgreement with WB KD Acquisition, LLC (“WB”) by which Kaupulehu Developmentstransferred its leasehold interest in the aforementioned 870 acres zoned forresort/residential development, in two increments, to WB.  There is no affiliation between KaupulehuDevelopments and WB.  WB is affiliatedwith Westbrook Partners, the developers of the nearby Kuki’o Resort.  The first increment (“Increment I”) isan area planned for approximately 80 single-family lots and a beach club on theportion of the property bordering the Pacific Ocean.  The purchasers of the 80 single-family lotswill have the right to apply for membership in the Kuki’o Resort Golf and BeachClub, which is located adjacent to and south of the Four Seasons ResortHualalai at Historic Ka’upulehu.  Thesecond increment (“Increment II”) is the remaining portion of theapproximately 870-acre property and is zoned for single-family and multi-familyresidential units and a golf course and clubhouse.

With respect to Increment I, KaupulehuDevelopments received an $11,550,000 payment in February 2004 and is entitledto receive payment of the following percentages of the gross proceeds generatedfrom 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 grossproceeds 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 grossproceeds in excess of $300,000,000. Minimum amounts of these Percentage Payments are due by certaindates.  There is no assurance that anyfuture payments will be received.  

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

Activity

WBsold the first of the 80 single-family lots under development inIncrement I in January 2006.  Twoadditional lots were sold by WB in February 2006 and another two lots were soldin April 2006, bringing total lot sales in fiscal 2006 to five lots.  Kaupulehu Developments received PercentagePayments totaling $3,660,000 for these five lot sales.  Revenue from the Percentage Payments wasreduced 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 futurepayments will be received. 

InJune 2006, Kaupulehu Developments entered into an Agreement (“Increment IIAgreement”) with WB and WB KD Acquisition II, LLC (“WBKD”) by which KaupulehuDevelopments sold its interest in Increment II, representing the remainderof the approximately 870 acres, to WBKD. There is no affiliation between Kaupulehu Developments and WB or WBKD.  WB and WBKD are both affiliates of WestbrookPartners, developers of the nearby Kuki’o Resort.  Pursuant to the Increment II Agreement,Kaupulehu Developments received a $10,000,000 payment and is entitled toreceive future payments from WBKD based on a percentage of the sales prices ofthe residential lots, ranging from 3.25% to 14%, to be determined in the futuredepending upon a number of variables, including whether the lots are sold priorto 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 ofpreviously capitalized costs relating to Increment II, resulting in netrevenues of $6,197,000 and a $4,621,000 operating profit, after minorityinterest.  There is no assurance that anyfuture payments will be received.

Inaddition, under the terms of the Increment II Agreement, WBKD has theexclusive right to negotiate with Kaupulehu Developments with respect to Lot4C, which is comprised of approximately 1,000 acres of vacant leasehold landzoned conservation located adjacent to Increment II.  This right expires in June 2009 or, if beforesuch date WBKD completes any and all environmental assessments and surveysreasonably required to support a petition to the Hawaii State Land UseCommission 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 rightsoption due on December 31, 2005 and $218,750 for a portion of itsdevelopment rights option due on December 31, 2006.  The$2,875,000 of option proceeds was reduced by $173,000 of fees related to thesale, resulting in net revenues of $2,702,000 and a $2,111,000 operatingprofit, after minority interest.  Therewere no other costs deducted from revenues from the sale of development rightsin fiscal 2006 as all capitalized costs associated with the development rightswere expensed in previous years.

The total amount of remaining future developmentrights option receipts at September 30, 2006, if all options are fullyexercised, is $13,062,500, comprised of the balance of $2,437,500 due onDecember 31, 2006 and four payments of $2,656,250 due on eachDecember 31 of years 2007 to 2010.  

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

The interests held by Kaupulehu Developments atSeptember 30, 2006 include the development rights under option, the rightsto receive percentage of sales payments, and approximately 1,000 acres ofvacant leasehold land zoned conservation, which is under a right of negotiationwith WBKD.

Competition

Barnwell’sland investment segment is subject to intense competition in all phases of itsoperations including the acquisition of new properties, the securing ofapprovals necessary for land rezoning, and the search for potential buyers ofproperty interests presently owned.  Thecompetition comes from numerous independent land development companies andother industries involved in land investment activities.  The principal factors affecting competitionare the location of the project and pricing. Kaupulehu Developments is a minor participant in the land developmentindustry and competes in its land investment activities with many otherentities having far greater financial and other resources.

Forthe past few years, Hawaii’s economy has experienced positive growth and theSouth Kohala/North Kona area of the island of Hawaii, the area in whichKaupulehu Developments’ property is located, has experienced strong demand forresidential real estate.  This trendcontinued through fiscal 2006, but at a diminished rate, and, although wecannot be certain, it is not expected to decline significantly in the nearterm, although there can be no assurance this trend will in fact continue.  The price and market for real estate in theSouth Kohala/North Kona area of the island of Hawaii has historically beencyclical and if the demand for real estate in the area Kaupulehu Developments’interests are located were to decrease, Barnwell’s operating results could benegatively affected.  During periods whendemand for real estate is low, inventory may turn at slower rates than expectedor may be sold at prices lower than anticipated.  This could potentially impair Barnwell’sliquidity and impede its ability to proceed with other planned projects oractivities.

**Contract Drilling Segment**

Overview

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

Operations

Water Resources owns and operates threeSpencer-Harris portable rotary drill rigs ranging in drilling capacity from3,500 feet to 7,000 feet, an IDECO H-35 rotary drill/workover rig and pumpinstallation and service equipment. Additionally, Water Resources leases a three-quarter of an acremaintenance facility in Honolulu, Hawaii and a one acre maintenance and storagefacility with 2,800 square feet of interior space in Kawaihae, Hawaii, andmaintains an inventory of drilling materials and 

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pump supplies.  As of September 30, 2006, WaterResources employed 21 drilling, pump and administrative employees, none of whomare union members.  

The demand for Water Resources’ services isprimarily dependent upon land development activities in Hawaii.  Water Resources markets its services to landdevelopers and government agencies, and identifies potential contracts throughpublic notices, its officers’ involvement in community activities andreferrals.  Contracts are usually fixedprice per lineal foot drilled or day rate contracts and are negotiated withprivate entities or obtained through competitive bidding with private entitiesor local, state and federal agencies.  Contractrevenues are not dependent upon the discovery of water, geothermal productionzones or other similar targets, and contracts are not subject to renegotiationof profits or termination at the election of the governmental entitiesinvolved.  Contracts provide forarbitration in the event of disputes.

Water Resources derived 37%, 63%, and 70% of itscontract drilling revenues in fiscal 2006, 2005, and 2004, respectively,pursuant to federal, State of Hawaii and county contracts.  At September 30, 2006, Barnwell hadaccounts receivable from the State of Hawaii and county entities totalingapproximately $754,000.  Barnwell haslien rights on wells drilled and pumps installed for federal, State of Hawaii,county and private entities.

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

Activity

Infiscal 2006, Water Resources started six well drilling contracts and four pumpinstallation contracts and completed 11 well drilling contracts and six pumpinstallation contracts.  Seven of thecompleted well drilling contracts and three of the completed pump installationcontracts 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 beenpursuant to government contracts.

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

Thedollar amount of Water Resources’ backlog of firm well drilling and pumpinstallation and repair contracts at November 30, 2006 and 2005 was asfollows:
|                               | ** ** | **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 |   |

 

Allof the contracts in backlog at November 30, 2006 are expected to becompleted within fiscal year 2007.

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Competition

WaterResources utilizes rotary drill rigs and competes with other drillingcontractors in Hawaii which use drill rigs similar to Water Resources’ drillingrigs or drilling rigs that drill as quickly as Water Resources’ equipment butrequire less labor.  These competitorsare also capable of installing and repairing vertical turbine and submersiblewater pumping systems in Hawaii.  Thesecontractors compete actively with Water Resources for government and privatecontracts.  Pricing is Water Resources’major method of competition; reliability of service is also a significantfactor.

Competitivepressures are expected to remain high, thus there is no assurance that thequantity of available or awarded jobs which occurred in fiscal 2006 willcontinue.

**Summary Financial Information For all IndustrySegments**

Revenuesof each industry segment for the fiscal years ended September 30, 2006,2005, and 2004 are summarized as follows (all revenues were from unaffiliatedcustomers 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 | % |

 

Forfurther 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**

Asof September 30, 2006, Barnwell employed 55 employees, 52 of which are ona full-time basis.  Twenty-one areemployed in contract drilling activities, 20 are employed in oil and naturalgas activities, and 14 are members of the corporate and administrative staff.

**FinancialInformation about geographic areas**

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

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**AvailableInformation**

Weare required to file annual, quarterly and current reports, proxy statementsand other information with the Securities and Exchange Commission. Thesefilings are not deemed to be incorporated by reference in this report. You mayread and copy any documents filed by us at the Public Reference Section of theSEC, 100 F Street, N.E., Washington, D.C. 20549. You may obtain information onthe 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’swebsite at http://www.sec.gov.  We alsomaintain an Internet site at www.brninc.com. We make available on our Internetwebsite free of charge our annual reports on Form 10-K, quarterly reports onForm 10-Q and current reports on Form 8-K as soon as practicable after weelectronically file such reports with the SEC.

**ITEM 1A.               RISKFACTORS**

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

*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 andother equipment, access to processing facilities, pipeline and refiningcapacity and in many other respects with a substantial number of otherorganizations, many of which may have greater technical and financial resourcesthan we do.  Some of these organizationsexplore for, develop and produce oil and natural gas, carry on refining operationsand market oil and other products on a worldwide basis.  As a result of these complementaryactivities, some of our competitors may have competitive resources that aregreater and more diverse than ours. Furthermore, many of our competitors may have a competitive advantagewhen responding to factors that affect demand for oil and natural gasproduction, such as changing prices and production levels, the cost andavailability of alternative fuels and the application of governmentregulations.  If our competitors are ableto capitalize on these competitive resources, it could adversely affect ourrevenues.

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

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

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theprice and availability of alternative fuels and the overall economicenvironment.  Any decline in crude oil ornatural gas prices may have a material adverse effect on our operations,financial condition, borrowing ability, reserves and amount of capital that weare able to allocate for the development of oil and natural gas reserves.

Energyprices are also subject to other political and regulatory actions outside ourcontrol, which may include changes in the policies of the Organization ofPetroleum Exporting Countries or other developments involving or affectingoil-producing countries, or actions or reactions of the government of the UnitedStates in anticipation of or in response to such developments.

****An increase in operating costs or a decline in our production levelcould have a material adverse effect on our results of operations and financialcondition.****

Higheroperating costs for our underlying properties will directly decrease the amountof cash flow received by us and, therefore, may reduce the price of our commonstock.  Electricity, supplies, and laborcosts are a few of the operating costs that are susceptible to material fluctuation.

Thelevel of production from our existing properties may decline at rates greaterthan anticipated due to unforeseen circumstances, many of which are beyond ourcontrol.  A significant decline in ourproduction could result in materially lower revenues and cash flow.

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

Ourbusiness depends in part upon the availability, proximity and capacity of gasgathering systems, pipelines and processing facilities.  Canadian federal and provincial, as well asUnited States federal and state, regulation of oil and gas production,processing and transportation, tax and energy policies, general economicconditions, and changes in supply and demand could adversely affect our abilityto 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 governmentregulation and other risks, particularly in the United States and Canada.**

Barnwell’soil and gas operations are affected by political developments and laws andregulations, particularly in the United States and Canada, such as restrictionson production, restrictions on imports and exports, the maintenance ofspecified reserves, tax increases and retroactive tax claims, expropriation ofproperty, cancellation of contract rights, environmental protection controls,environmental compliance requirements and laws pertaining to workers’ healthand safety.  Further, the right toexplore for and develop oil and natural gas on lands in Alberta, Saskatchewanand British Columbia is controlled by the governments of each of thoseprovinces.  Changes in royalties andother terms of provincial leases, permits and reservations may have asubstantial effect on Barnwell’s operations. We derive asignificant 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 Canadianoil and natural gas industry may be adversely affected by governmentalregulations or other policies that favor the awarding of contracts to

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

Government regulationscontrol and often limit access to potential markets and impose extensiverequirements concerning employee safety, environmental protection, pollutioncontrol and remediation of environmental contamination.  Environmental regulations, in particular,prohibit access to some markets and make others less economical, increase equipmentand personnel costs and often impose liability without regard to negligence orfault.  In addition, governmentalregulations may discourage our customers’ activities, reducing demand for ourproducts and services.

**Compliancewith foreign tax and other laws may adversely affect our operations.**

Tax and other laws andregulations are not always interpreted consistently among local, regional andnational authorities.  It is alsopossible that in the future we will be subject to disputes concerning taxationand other matters in Canada, and these disputes could have a material adverseeffect on our financial performance.

****We are dependent upon future discoveries or acquisitions of oil and gasto maintain our reserves.****

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

****Actual reserves will vary from reserve estimates.****

The value of our common stockdepends 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 varyfrom estimates, and those variations may be material.  The estimation of reserves involves a numberof factors and assumptions, including, among others:

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

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

·                  initial production rates;

·                  production decline rates;

·                  ultimate recovery of reserves;

·                  success of future development activities;

·                  marketability of production;

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·                  effects of government regulation; and

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

Reserve estimates are basedon the relevant factors, assumptions and prices as of the date on which theevaluations are prepared.  Many of thesefactors are subject to change and are beyond our control.  If these factors, assumptions and pricesprove to be inaccurate, actual results may vary materially from reserveestimates.

****Delays in business operations could adversely affect our distributions.****

In addition to the usualdelays in payment by purchasers of oil and natural gas to the operators of ourproperties, 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 agathering system;

·                  blowouts or other accidents;

·                  adjustments for prior periods;

·                  recovery by the operator of expenses incurredin the operation of the properties; or

·                  the establishment by the operator of reservesfor these expenses.

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

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

Our operations are subjectto all of the risks associated with the operation and development of oil andnatural 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 unexpectedformations or pressures, premature declines of reservoirs, blow-outs, equipmentfailures and other accidents, cratering, sour gas releases, uncontrollableflows of oil, natural gas or well fluids, adverse weather conditions,pollution, other environmental risks, fires and spills.  A number of these risks could result inpersonal injury, loss of life, or environmental and other damage to ourproperty or the property of others.

While we maintain reservesfor anticipated liabilities and carry various levels of insurance, we could beaffected by civil, criminal, regulatory or administrative actions, claims orproceedings.  We cannot fully protectagainst all of the risks listed above, nor are all of these risksinsurable.  There is no assurance thatany applicable insurance or indemnification agreements will adequately protectus against liability for the risks listed above.  We could face substantial losses, if an eventoccurs for which we are not fully insured or are not indemnified against, or acustomer or insurer fails to meet its indemnification or insuranceobligations.  In addition, there can beno assurance that insurance will continue to be available to cover any or allof these risks, or, even if available, that insurance premiums or other costswill not rise significantly in the future, so as to make the cost of suchinsurance prohibitive.

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

The oil and natural gasindustry is subject to extensive environmental regulation pursuant to local,provincial and federal legislation.  Aviolation of that legislation may result in the imposition of fines or the issuanceof “clean up” orders.  Legislationregulating the oil and natural gas industry may be changed to impose higherstandards and potentially more costly obligations.  For example, the 1997 Kyoto Protocol to theUnited Nation’s Framework Convention on Climate Change, known as the KyotoProtocol, was ratified by the Canadian government in December 2002 and willrequire, among other things, significant reductions in greenhouse gases.  The impact of the Kyoto Protocol on us isuncertain and may result in significant additional costs for our futureoperations.  Although we record aprovision in our financial statements relating to our estimated futureenvironmental and reclamation obligations, we cannot guarantee that we will beable to satisfy our actual future environmental and reclamation obligations.

We are not fully insuredagainst certain environmental risks, either because such insurance is notavailable or because of high premium costs. In particular, insurance against risks from environmental pollution occurringover time (as opposed to sudden and catastrophic damages) is not available oneconomically reasonable terms. Accordingly, any site reclamation or abandonment costs actually incurredin the ordinary course of business in a specific period could negatively impactour cash flow.  Should we be unable tofully fund the cost of remedying an environmental problem, we might be requiredto suspend operations or enter into interim compliance measures pendingcompletion 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 tomake substantial capital expenditures in our exploration and developmentprojects.  Without additional capitalresources, 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 additionalfinancing on reasonable terms or at all and financing may not continue to be availableto us under our existing financing arrangements.  If additional capital resources areunavailable, we may curtail our drilling, development and other activities orbe forced to sell some of our assets under untimely or unfavorable terms.  Any such curtailment or sale could have amaterial adverse effect on our business, financial condition and results ofoperation.

**Unforeseen title defects may result in a loss of entitlement toproduction and reserves.**

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

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****Changes in tax and other legislation may adversely affect shareholders.****

Income tax laws, otherlegislation or government incentive programs relating to the oil and gasindustry may in the future be changed or interpreted in a manner that adverselyaffects us and our shareholders.  Taxauthorities having jurisdiction over us may disagree with the manner in whichwe calculate our income for tax purposes or could change their administrativepractices to our detriment.

*Risks Related to Real Estate Investment Segment*

**Significant competition in thereal estate industry could have an adverse effect on our business.**

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

**A downturn in economic conditionsand demand for real estate could adversely affect our business.**

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

Considerable economic andpolitical uncertainties currently exist that could have adverse effects onconsumer buying habits, construction costs, availability of labor and materialsand other factors affecting us and the real estate industry in general.  Significant expenditures associated withinvestment in real estate, such as real estate taxes, insurance, maintenancecosts and debt payments, cannot generally be reduced even though changes inHawaii’s or the nation’s economy may cause a decrease in revenues from ourproperties.

**Our real estate business isprimarily concentrated in the state of Hawaii. As a result, our financial results are dependent on the economic growthand health of Hawaii, particularly the island of Hawaii.**

Barnwell’s land investmentbusiness segment is affected by the condition of Hawaii’s real estate market.  The Hawaii real estate market is affected byHawaii’s economy and Hawaii’s tourism industry, as well as the United States’economy in general.  Any future cashflows from Barnwell’s land development activities are subject to, among otherfactors, the level of real estate activity and prices, the demand for newhousing and second homes on the island of Hawaii, the rate of increase in thecost of building materials and labor, the introduction of building codemodifications, changes to zoning laws, and the level of confidence in Hawaii’seconomy.  The future economic growth incertain portions of the island of Hawaii may be adversely affected if itsinfrastructure, such as roads, airports, medical facilities and schools, arenot improved to meet increased demand. There can be no assurance that these improvements will occur.

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**The occurrence of naturaldisasters in Hawaii could adversely affect our business.**

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

**Increases in interest rates couldreduce demand for our real estate.**

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

**Our business is subject toextensive regulation which makes it difficult and expensive for us to conductour operations.**

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

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

In 2006 we sold ourleasehold interest in the second of two increments of resort/residential zonedproperty to an unrelated developer.  As apart of the sale, we are entitled to receive future payments based on apercentage of the sales prices of residential lots sold in this secondincrement.  Receipt of these percentageof sales payments will be contingent upon the ability of the developer of theleasehold interest in the resort/residential zoned property to successfullynegotiate fee simple prices within this second increment.  If the developer is unsuccessful in suchnegotiations, our ability to receive percentage of sales payments on the salesof those lots would be impaired.

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

We hold the leaseholdinterest to approximately 1,000 acres of vacant land that is currently zonedconservation.  Our success in sellingthis interest may be contingent upon obtaining the necessary reclassificationfrom the State of Hawaii Land Use Commission and County of Hawaii.  Obtaining the necessary reclassification andministerial approvals is often difficult, costly and may take several years, ormore, to complete.  Delays or failures toobtain the necessary reclassification approvals may adversely affect ourfinancial results.

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**Environmental and otherregulations may have an adverse effect on our business.**

Our properties are subjectto federal, state and local environmental regulations and restrictions that mayimpose significant limitations.  In mostcases, approval to develop requires multiple permits which involve a long,uncertain and costly regulatory process.

**We are involved in joint venturesand are subject to risks associated with joint venture partnerships.**

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

·                  the inability to exercise voting control overthe joint venture;

·                  economic or business interests which are notaligned with our venture partner; and

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

*Risks Related to ContractDrilling Segment*

**Demand for water well drillingand/or pump installation is volatile.  Adecrease in demand for our services would result in a decrease in our revenues.**

Demand for services ishighly dependent upon land development activities in the state of Hawaii.  As also noted above, the real estateinvestment industry is cyclical in nature and is particularly vulnerable toshifts in local, regional, and national economic conditions outside of ourcontrol such as interest rates, housing demand, population growth, employmentlevels and job growth and property taxes. If we experience a decrease in water well drilling and/or pumpinstallation contracts, we may experience decreased revenues and operatingresults.

**A significant portion of ourcontract drilling business is dependent on municipalities and a decline inmunicipal spending could adversely impact our business.**

A significant portion of ourcontract drilling water resources division revenues are derived from water andinfrastructure contracts with governmental entities or agencies.  Reduced tax revenues in certain regions maylimit spending and new development by local municipalities which in turn willaffect the demand for our services in these regions.  Material reductions in spending by asignificant number of municipalities or local governmental agencies could havea material adverse effect on our business, results of operations, liquidity andfinancial position.

**Our contract drilling operationsface significant competition from companies with greater financial resources.**

We face competition for ourservices from a variety of competitors. Many of our competitors utilize drilling rigs that drill as quickly asour 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 tocompete effectively with our competitors, our financial results could beadversely affected.

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**The loss of or damage to keyvendor, customer or sub-contractor relationships would adversely affect ouroperations.**

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

*Entity-Wide Risks*

**The price of our common stock has been volatile and could continue tofluctuate substantially.**

The market price of ourcommon stock has been volatile and could fluctuate based on a variety offactors, 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 theoil and natural gas industry.

**Failureto retain key personnel could hurt our operations*.***

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

**A smallnumber of shareholders, including our executive officers, own a significantamount of our common stock and have influence over our business regardless ofthe opposition of other shareholders.**

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

**We maybe required to comply with Section 404 of the Sarbanes-Oxley Act in 2007, whichwe believe will result in additional expenses and may divert management’sattention.**

The Company may become anaccelerated filer as defined in Rule 12b-2 of the Exchange Act, which wouldrequire the Company to comply with Section 404 of the Sarbanes-Oxley Act forfiscal 2007.  In such event, managementwould be required to provide with the Company’s Annual Report on

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Form 10-K for the year ending September 30,2007, its assessment of the effectiveness of the Company’s internal controlover financial reporting as of September 30, 2007 and our independentregistered public accounting firm would be required to provide its attestationreport on management’s assessment.  Ifsuch compliance is required, the Company anticipates incurring additionalgeneral and administrative expenses and anticipates that its compliance effortsmay divert management’s time and attention away from other aspects of ourbusiness.

**Adversechanges in actuarial assumptions used to calculate retirement plan costs due toeconomic or other factors, or lower returns on plan assets could adverselyaffect Barnwell’s results and financial condition.**

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

**ITEM 2.          PROPERTIES**

**Oil andGas and Real Estate Investment Properties.**

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

**CorporateOffices**

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

**ITEM 3.          LEGAL PROCEEDINGS**

Barnwell is occasionallyinvolved in routine litigation and is subject to governmental and regulatorycontrols that are incidental to the business. Barnwell’s management believes that routine claims and litigationinvolving Barnwell are not likely to have a material adverse effect on itsfinancial position, results of operations or liquidity.

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PART II

**ITEM 5.****                            ****MARKET FOR REGISTRANT’S COMMONEQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITYSECURITIES**

**MarketInformation**

InDecember 2004, Barnwell declared a two-for-one stock split in the form of astock dividend.  The new shares weredistributed on January 28, 2005 to all shareholders of record as ofJanuary 11, 2005.

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

The principal market on which Barnwell’s common stockis being traded is the American Stock Exchange. The following tables present the quarterly high and low sales prices, onthe American Stock Exchange, for Barnwell’s common stock during the periodsindicated:
| 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 8,169,060shares of common stock, par value $0.50, outstanding.  There were approximately 1,500 holders of thecommon stock of the registrant as of December 20, 2006.

**Dividends**

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

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The table below sets forth the cash dividends paidper 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       |   |

 

**SecuritiesAuthorized for Issuance Under Equity Compensation Plans**

Seethe information included in Part III, Item 12, under the caption “EquityCompensation Plan Information.”

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**ITEM 6.****                            ****SELECTED FINANCIAL DATA**

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

**FINANCIALAND 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 |   |

 

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 *           MCF means1,000 cubic feet

**          Oil andliquids are converted to natural gas equivalents on the basis of one barrelequals 5.8 MCF.

Reserves are calculatedby an independent engineering firm based on estimated prices received by Barnwellat year end.

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**ITEM 7.****                            ****MANAGEMENT’S DISCUSSION ANDANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION**

Thefollowing discussion is intended to assist in the understanding of theconsolidated balance sheets of Barnwell Industries, Inc. and subsidiaries(collectively referred to herein as “Barnwell”) as of September 30, 2006and 2005, and the related consolidated statements of operations, stockholders’ equityand comprehensive income, and cash flows for each of the years in the three-yearperiod ended September 30, 2006. This discussion should be read in conjunction with the consolidatedfinancial statements and related Notes to Consolidated Financial Statementsincluded in this report.

**Use ofEstimates in the Preparation of Financial Statements**

Thepreparation of financial statements in conformity with accounting principlesgenerally accepted in the United States of America requires management to makeestimates and assumptions that affect the reported amounts of assets,liabilities, revenues and expenses and the disclosure of contingent assets andliabilities.  Actual results could differsignificantly from those estimates.

**CriticalAccounting Policies and Estimates**

Inresponse to U.S. Securities and Exchange Commission Release No. 33-8040, “CautionaryAdvice Regarding Disclosure About Critical Accounting Policies,” Barnwell hasidentified certain of its policies as being of particular importance to theunderstanding of its financial position and results of operations and whichrequire the application of significant judgment by management.

Oil and naturalgas properties

Barnwelluses the full cost method of accounting under which all costs incurred in theacquisition, exploration and development of oil and natural gas reserves,including costs related to unsuccessful wells and estimated future siterestoration and abandonment, are capitalized until such time as the aggregateof such costs net of accumulated depletion and oil and gas related deferredincome taxes, on a country-by-country basis, equals the sum of 1) the discountedpresent value (at 10%), using prices as of the end of the fiscal year on aconstant basis, of Barnwell’s estimated future net cash flows from estimatedproduction of proved oil and natural gas reserves as determined by independentpetroleum engineers, less estimated future expenditures to be incurred indeveloping and producing the proved reserves but excluding future cash outflowsassociated with settling asset retirement obligations accrued on the balancesheet; plus 2) the cost of major development projects and unproven propertiesnot subject to depletion, if any; plus 3) the lower of cost or estimated fairvalue of unproven properties included in costs subject to depletion; less 4)related income tax effects.  If netcapitalized costs exceed this limit, the excess is expensed unless subsequentmarket price changes eliminate or reduce the indicated write-down in accordancewith U.S. Securities and Exchange Commission Staff Accounting Bulletin Topic12D.  Depletion is computed using theunits-of-production method whereby capitalized costs, net of salvage values,plus estimated future costs to develop proved reserves and satisfy assetretirement obligations, are amortized over the total estimated proved reserveson a country-by-country basis.  Investmentsin major development projects are not depleted until either proved reserves areassociated with the projects or impairment has been

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determined.  At September 30, 2006 and 2005, Barnwell hadno investments in major oil and natural gas development projects that were notbeing depleted.  General andadministrative costs related to oil and natural gas operations are expensed asincurred.  Proceeds from the dispositionof minor producing oil and natural gas properties are credited to the cost ofoil and natural gas properties.  Gains orlosses are recognized on the disposition of significant oil and natural gasproperties.

Basedon a natural gas spot price of $3.34 per 1,000 cubic feet (“MCF”) as ofSeptember 30, 2006, the full cost pool exceeded the ceiling limitation byapproximately $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 fullcost pool would not have exceeded the ceiling limitation.  The spot price of natural gas onDecember 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 ExchangeCommission Staff Accounting Bulletin Topic 12D, Barnwell has not recorded animpairment write-down of its oil and natural gas properties atSeptember 30, 2006.

Investment in landand revenue recognition

Barnwell’sinvestment in land is comprised of development rights under option, rights toreceive percentage of sales payments, and approximately 1,000 acres of vacantleasehold land zoned conservation, which is under a right of negotiation.  Investment in land is reported at the lowerof the asset carrying value or fair value, less costs to sell, and is evaluatedfor impairment whenever events or changes in circumstances indicate that therecorded investment balance may not be fully recoverable.

Costsincurred for the acquisition and improvement of sales of leasehold landinterests, including capitalized interest, are included in the Consolidated BalanceSheets under the caption “Investment in Land.”

Salesof development rights under option and revenues from sales of leasehold landinterests are accounted for pursuant to the provisions of Statement ofFinancial Accounting Standards (“SFAS”) No. 66, “Accounting for Sales ofReal Estate.”  SFAS No. 66 providesspecific sales recognition criteria to determine when land sale revenue can berecorded.

Investment inaffiliate

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

Barnwell has evaluatedthe aforementioned investment in accordance with FASB InterpretationNo. 46, “Consolidation of Variable Interest Entities,” as revised, as wellas other applicable authoritative accounting literature, and has determinedthat the investment in Mauka 3K does not meet the requirements forconsolidation.  Barnwell accounts for itsinvestment in unconsolidated affiliates under the equity method when Barnwell’sownership interest is more than 20% but no more than 50% and Barnwell does notexercise direct or indirect control over the investee.  Factors that are considered

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in determiningwhether or not Barnwell exercises control include rights of partners regardingsignificant strategic and operational decisions.  As Barnwell does not exercise direct orindirect control over Mauka 3K, the investment is accounted for using theequity method of accounting.

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

Contract drilling

Revenues,costs and profits applicable to contract drilling contracts are included in theConsolidated Statements of Operations using the percentage of completionmethod, principally measured by the percentage of labor dollars incurred todate for each contract to total estimated labor dollars for each contract.  Contract losses are recognized in full in theperiod the losses are identified.  Theperformance of drilling contracts may extend over more than one year and, inthe interim periods, estimates of total contract costs and profits are used todetermine revenues and profits earned for reporting the results of contractdrilling operations.  Revisions in theestimates required by subsequent performance and final contract settlements areincluded as adjustments to the results of operations in the period suchrevisions and settlements occur. Contracts are normally less than one year in duration.

Income taxes

Deferredincome taxes are determined using the asset and liability method.  Deferred tax assets and liabilities arerecognized for the estimated future tax impacts of differences between thefinancial statement carrying amounts of existing assets and liabilities andtheir respective tax bases.  Deferred taxassets and liabilities are measured using enacted tax rates in effect for theyear in which those temporary differences are expected to be recovered orsettled.  The effect on deferred taxassets and liabilities of a change in tax rates is recognized in income in theperiod that includes the enactment date.

A valuation allowance isprovided when it is more likely than not that some portion or all of thedeferred 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 netoperating loss carryforwards which may not be realizable in future years asthere can be no assurance of any specific level of earnings or that the timingof U.S. earnings will coincide with the payment of Canadian taxes to enableCanadian taxes to be fully deducted (or recoverable) for U.S. tax purposes.

Netdeferred 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 taxpurposes, $614,000 related to the excess of the cost basis of investment inland for tax purposes over the cost basis of investment in land for bookpurposes, and $1,522,000 for foreign tax credit carryforwards.  Canadian deferred tax assets related toexpenses accrued for book purposes but not for tax purposes are estimated to berealized through future Canadian income tax deductions against future Canadianoil and natural gas earnings.  U.S.deferred tax assets related to expenses accrued for book purposes but not fortax purposes and the excess of the cost basis of investment in land for taxpurposes over the cost basis of investment in land for book purposes areestimated to be realized from deductions against future U.S. earnings fromsales of interests in leasehold land and land development rights.  Foreign tax credit carryforwards areestimated to be utilized when U.S. federal income taxes otherwise due onCanadian source income in a given

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yearexceeds the foreign tax credit generated in that year.  The foreign tax credit carryforwards will expireif not utilized in fiscal years 2012 through 2013.  The amount of deferred income tax assetsconsidered realizable may be reduced if estimates of future taxable income arereduced.

Retirement plans

Barnwell sponsors anoncontributory defined benefit pension plan covering substantially all of itsU.S. employees, with benefits based on years of service and the employee’shighest consecutive five-year average earnings. Additionally, Barnwell sponsors a Supplemental Employee Retirement Plan,a noncontributory supplemental retirement benefit plan which covers certaincurrent and former employees of Barnwell for amounts exceeding the limitsallowed under the pension plan.  Barnwellaccounts for its retirement plans in accordance with SFAS No. 87, “Employers’Accounting for Pensions,” which requires that amounts recognized in financialstatements be determined on an actuarial basis. SFAS No. 87 requires that the effects of the performance of thepension plan’s assets and changes in pension liability discount rates onBarnwell’s computation of pension income (expense) be amortized over futureperiods.  Any variances in the futurebetween the assumed rates utilized for actuarial purposes and the actual ratesexperienced by the plan may materially affect Barnwell’s results of operationsor financial condition.

Duringand as of the end of fiscal 2006 and fiscal 2005, Barnwell assumed an expectedlong-term rate of return on plan assets of 8% and an expected rate of futureannual compensation increases of 5%.

Atthe end of each year, Barnwell determines the discount rate to be used tocalculate the present value of plan liabilities.  The discount rate is an estimate of thecurrent interest rate at which the pension liabilities could be effectivelysettled at the end of the year.  Inestimating 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 rateof 5.25% used at September 30, 2005.

Barnwellmade 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 aprepaid pension cost of $234,000 at September 30, 2006.  Barnwell recognized net periodic benefit costsof $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’saccrued benefit cost at September 30, 2005 and 2004 was $517,000 and$418,000, respectively.

InSeptember 2006, the FASB issued SFAS No. 158, “Employers’ Accounting forDefined Benefit Pension and Other Postretirement Plans – an amendment of FASBStatements No. 87, 88, 106 and 132(R).” SFAS No. 158 requires an employer to recognize the over-funded orunder-funded status of a defined benefit postretirement plan (other than amultiemployer plan) as an asset or liability in its statement of financialposition and to recognize changes in that funded status in the year in whichthe changes occur through comprehensive income. SFAS No. 158 also requires the measurement of defined benefit planassets and obligations as of the date of the employer’s fiscal year-endstatement of financial position (with limited exceptions).  Under SFAS No. 158, Barnwell will berequired to recognize the funded status of its defined benefit postretirementplan and supplemental employee retirement plan and to provide the requireddisclosures.  SFAS No. 158 iseffective for fiscal years ending after December 15, 2006.  If SFAS No. 158 were applied as ofSeptember 30, 2006, Barnwell

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wouldhave recognized an additional pension and other postretirement benefitobligation of approximately $1,500,000 along with a corresponding decrease inaccumulated other comprehensive income of approximately $990,000, net of$510,000 of deferred income tax benefits associated with the temporarydifference between pension and postretirement liabilities recognized for bookversus tax purposes.

Asset retirement obligation

Barnwellaccounts for asset retirement obligations in accordance with SFAS No. 143,“Accounting for Asset Retirement Obligations,” and FASB InterpretationNo. 47, “Accounting for Conditional Asset Retirement Obligations - aninterpretation of FASB Statement No. 143,” which requires that the fairvalue of a liability for an asset retirement obligation be recognized in theperiod in which it is incurred if a reasonable estimate of fair value can bemade.  The asset retirement obligationreflects Barnwell’s obligation to plug and abandon natural gas and oil wells,dismantle and remove related equipment and plants, and restore the propertiesto a suitable condition at the end of oil and gas operations based on Barnwell’snet ownership interest in the properties. The asset retirement obligation is recorded at fair value in the periodin which it is incurred along with a corresponding increase in the carryingamount of the related asset.  Barnwellhas estimated fair value by discounting the estimated future cash outflowsrequired to settle abandonment and restoration liabilities.  The present value calculation includesnumerous estimates, assumptions and judgments regarding the existence ofliabilities, the amount and timing of cash outflows required to settle theliability, what constitutes adequate restoration, inflation factors, creditadjusted discount rates, and consideration of changes in legal, regulatory,environmental and political environments. Barnwell’s estimated site restoration and abandonment costs of its oiland natural gas properties are capitalized as part of the carrying amount ofoil and natural gas properties and depleted over the life of the relatedreserves.  The liability is accreted atthe end of each period through charges to oil and natural gas operating expense.  Abandonment and restoration cost estimatesare determined in conjunction with Barnwell’s reserve engineers based onhistorical information regarding costs incurred to abandon and restore similarwell sites, information regarding current market conditions and costs, andknowledge of subject well sites and properties.

Share-based payments

EffectiveOctober 1, 2005, Barnwell adopted the provisions of SFAS No. 123(R), “Share-BasedPayment,” for its share-based compensation plans.  Barnwell previously accounted for these plansunder the recognition and measurement principles of Accounting Principles BoardOpinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” andrelated interpretations and disclosure requirements established by SFASNo. 123, “Accounting for Stock-Based Compensation,” as amended by SFASNo. 148, “Accounting for Stock-Based Compensation – Transition andDisclosure.”

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

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

Asof September 30, 2006, there was $944,000 of total unrecognizedcompensation cost related to nonvested equity-classified andliability-classified share options.  Thatcost is expected to be recognized over a weighted-average period of 2.7 years.

Long-lived assets

Long-livedassets to be held and used, other than oil and natural gas properties, areevaluated for impairment whenever events or changes in circumstances indicatethat the carrying amount of an asset may not be fully recoverable.  If the future cash flows expected to resultfrom use of the asset (undiscounted and without interest charges) are less thanthe carrying amount of the asset, an impairment loss is recognized.  Such impairment loss is measured as theamount by which the carrying amount of the asset exceeds the fair value of theasset.  Long-lived assets to be disposedof are reported at the lower of the asset carrying value or fair value, lesscost to sell.

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

Environmental

Barnwellis subject to extensive environmental laws and regulations.  These laws, which are constantly changing,regulate the discharge of materials into the environment and maintenance ofsurface conditions and may require Barnwell to remove or mitigate theenvironmental effects of the disposal or release of petroleum or chemicalsubstances at various sites. Environmental expenditures are expensed or capitalized depending ontheir future economic benefit. Expenditures that relate to an existing condition caused by pastoperations and that have no future economic benefits are expensed.  Liabilities for expenditures of a noncapitalnature are recorded when environmental assessment and/or remediation isprobable, and the costs can be reasonably estimated.

**ContractualObligations**

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

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| ** **                       | ** ** | **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 |   |

 

Thereis no assurance that the bank will in fact extend the term of the facility oneach renewal date or that the facility will be renewed at its currentamount.  The following table lists thescheduled maturities of long-term debt assuming that the facility will not berenewed on the next renewal date, April 30, 2007 (for which repayment, ifany, has been deferred until no sooner than October 1, 2007), and thatBarnwell then elects to convert the revolving facility to term status, andscheduled minimum rental payments of non-cancelable operating leases for officespace 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 |   |

 

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

**Overview**

Barnwellis engaged in the following lines of business: 1) oil and natural gasexploration, development, production and sales essentially all in Canada (oiland natural gas segment), 2) investment in leasehold land in Hawaii (landinvestment segment), and 3) drilling wells and installing and repairing waterpumping systems in Hawaii (contract drilling segment).

Oil and Natural GasSegment

Barnwellsells substantially all of its oil and condensate production under short-termcontracts with marketers of oil.  Naturalgas sold by Barnwell is generally sold under both long-term and short-termcontracts with prices indexed to market prices. The price of natural gas, oil and natural gas liquids is freelynegotiated between the buyers and sellers.  Market prices for petroleum products aredependent upon factors such as, but not limited to, changes in weather, storagelevels, and output.  Petroleum andnatural gas prices are very difficult to predict and fluctuatesignificantly.  For example, natural gasprices for Barnwell, based on quarterly averages during the three years endedSeptember 30, 2006, have ranged from a low of $4.08 per thousand cubicfeet to a high of $9.76 per thousand cubic feet, and tend to be higher in thewinter than in the summer due to increased demand.  Oil and natural gas exploration, developmentand operating costs generally follow trends in product market prices, thus

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in times of higherproduct prices the cost of exploration, development and operation of oil andnatural gas properties will tend to escalate as well.  Barnwell’s oil and natural gas operationsmake capital expenditures in the exploration, development, and production ofoil and natural gas.  Cash outlays forcapital expenditures are largely discretionary, however, a minimum level ofcapital expenditures is required to replace depleting reserves.  Due to the nature of oil and natural gasexploration and development, significant uncertainty exists as to the ultimatesuccess of any drilling effort.

Land Investment Segment

Barnwellowns a 77.6% controlling interest in Kaupulehu Developments, a Hawaii generalpartnership which owns interests in leasehold land and development rights forproperty located approximately six miles north of the Kona InternationalAirport in the North Kona District of the Island of Hawaii, within and adjacentto the Hualalai Resort at Historic Ka’upulehu, between the Queen KaahumanuHighway and the Pacific Ocean.  KaupulehuDevelopments’ development rights are under option to a developer and revenuesare recognized when options are exercised.

InFebruary 2004, Kaupulehu Developments entered into a Purchase and Sale Agreementwith an independent buyer whereby Kaupulehu Developments transferred itsleasehold interest in approximately 870 acres zoned for resort/residentialdevelopment, in two increments, to the buyer. For the first increment (“Increment I”), Kaupulehu Developments receivedan $11,550,000 cash closing payment in February 2004 and is also entitled toreceive future payments from the buyer based on the following percentages ofgross receipts from the developer’s sales of single-family residential lots in IncrementI: 9% of the gross proceeds from single-family lot sales up to aggregate grossproceeds 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 grossproceeds in excess of $300,000,000.

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

Thearea in which Kaupulehu Developments’ interests are located has experienceddemand for premium residential real estate in recent years, however there is noassurance that any future development rights or percentage of sales paymentswill be received.

Contract DrillingSegment

Barnwellalso drills water, water monitoring and geothermal wells and installs andrepairs water pumping systems in Hawaii. Contract drilling results are highly dependent upon the quantity, dollarvalue and timing of contracts awarded by governmental and private entities andcan fluctuate

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significantly.  Water well drilling and pump installation activitydecreased during fiscal 2006 as compared to the prior year, and managementexpects these activities to decrease similarly in fiscal 2007, as compared tofiscal 2006.

**Resultsof Operation**

Summary

Barnwellgenerated net earnings of $14,637,000 in fiscal 2006, an $8,610,000 increasefrom net earnings of $6,027,000 in fiscal 2005. The increase was due in part to the receipt of a payment from the saleof Increment II of Kaupulehu Developments’ leasehold land interests whichgenerated an operating profit, after minority interest and before taxes, ofapproximately $4,621,000, higher prices received by Barnwell for all petroleumproducts, the receipt of Percentage Payments from the sale of lots in IncrementI of the leasehold land interest previously held by Kaupulehu Developments, andproceeds from real estate consulting services rendered.  The increase was also due in part to therecognition of $4,130,000 of deferred tax benefits due to a reduction in thevaluation allowance for foreign tax credit carryforwards and $1,094,000 ofdeferred 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 creditcarryforwards or Canadian tax rates in fiscal 2005.

Thefiscal year average exchange rate of the Canadian dollar to the U.S. dollarincreased 7% in fiscal 2006, as compared to fiscal 2005, and the exchange rateof the Canadian dollar to the U.S. dollar increased 4% at September 30,2006, as compared to September 30, 2005. This increase in the value of the Canadian dollar in U.S. dollarsincreased Barnwell’s reported revenues and expenses and assets and liabilities.

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

Oil and natural gas revenues

*SelectedOperating Statistics*

Thefollowing tables set forth Barnwell’s annual net production and annual averageprice per unit of production for fiscal 2006 as compared to fiscal 2005, andfiscal 2005 as compared to fiscal 2004. Production amounts reported are net of royalties and the Alberta RoyaltyTax Credit.

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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 | % |

 

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

**                Bbl = stock tankbarrel equivalent to 42 U.S. gallons

Oiland natural gas revenues increased $5,180,000 (16%) from $32,724,000 in fiscal2005 to $37,904,000 in fiscal 2006, due to increases in prices for allpetroleum products.  Natural gasproduction increased 99,000 MCF at Dunvegan, Barnwell’s principal oil and gasproperty, and where Barnwell has invested approximately $9,750,000 in fiscal2004 through fiscal 2006.  Natural gasproduction also increased at Barnwell’s newer properties at Doris, BoundaryLake, Wood River and Bonanza/Balsam, but was more than offset by declines atProgress, Leduc, Malmo and Pouce Coupe South, which are also newer properties.

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

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TheAlberta Royalty Tax Credit (“ARTC”) program has been discontinued by the Albertagovernment, 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 creditagainst oil and natural gas royalties and reported in oil and natural gasrevenues.  In fiscal 2007, Barnwellexpects to receive approximately $100,000 under the ARTC program, representingthe ARTC for the period from October 1, 2006 to December 31,2006.  Beginning January 1, 2007,Barnwell will no longer receive ARTC payments.

Oiland natural gas revenues increased $8,884,000 (37%) from $23,840,000 in fiscal2004 to $32,724,000 in fiscal 2005, due to increases in prices for allpetroleum products and increases in natural gas production, partially offset bya decrease in net oil production. Natural gas production increased principally due to an increase inproduction at Dunvegan.  Net natural gasproduction at Dunvegan increased 227,000 MCF or 15% and net natural gas liquidsand oil production at Dunvegan increased 10,000 barrels or 12%.  Natural gas production also increased atBarnwell’s newer properties at Doris, Malmo and Armada, but declined at Bonanza/Balsam,Leduc and Progress, which are also newer properties, and at other olderproperties which largely offset the net increase in production at the newerproperties.  Additionally, natural gasand natural gas liquids production at Dunvegan was reduced by approximately30,000 MCF and 3,000 barrels, respectively, in fiscal 2005 as compared tofiscal 2004 due to plant maintenance in fiscal 2005.  There was no such plant maintenance programin fiscal 2004.

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

Oil and naturalgas 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 andmaintenance costs at older properties and to a 7% increase in the averageexchange rate of the Canadian dollar to the U.S. dollar that increased oil andnatural gas operating expenses $535,000 in fiscal 2006 as compared to the prioryear.

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. dollarthat increased oil and natural gas operating expenses $546,000 in fiscal 2005as compared to the prior year.  Alsocontributing to the increase were operating expenses on new wells.

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

InFebruary 2004, Kaupulehu Developments, a land development general partnershipin which Barnwell owns a 77.6% controlling interest, entered into a Purchaseand Sale Agreement with WB KD Acquisition, LLC (“WB”) by which KaupulehuDevelopments transferred its leasehold interest in approximately 870 acreszoned for resort/residential development, in two increments, to WB.  There is

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noaffiliation between Kaupulehu Developments and WB.  WB is affiliated with Westbrook Partners, thedevelopers of the Kuki’o Resort located adjacent to the Hualalai Resort atHistoric Ka’upulehu.  The first increment(“Increment I”) is an area planned for approximately 80 single-family lotsand a beach club on the portion of the property bordering the PacificOcean.  The purchasers of the 80single-family lots will have the right to apply for membership in the Kuki’oResort Golf and Beach Club, which is located adjacent to and south of the FourSeasons Resort Hualalai at Historic Ka’upulehu. The second increment (“Increment II”) is the remaining portion ofthe approximately 870-acre property and is zoned for single-family andmulti-family residential units and a golf course and clubhouse.

Withrespect to Increment I, Kaupulehu Developments received an $11,550,000payment in February 2004 and is entitled to receive payment of the followingpercentages of the gross proceeds generated from the sale by WB ofsingle-family lots in Increment I (“Percentage Payments”): 9% of the grossproceeds from single-family lot sales up to aggregate gross proceeds of$100,000,000; 10% of such aggregate gross proceeds greater than $100,000,000but less than $300,000,000; and 14% of such aggregate gross proceeds in excessof $300,000,000.  Minimum amounts of thesePercentage Payments are due by certain dates. WB sold a total of five single-family lots and paid KaupulehuDevelopments $3,660,000 in Percentage Payments during the year endedSeptember 30, 2006.  Revenue fromthe 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 nolot sales, and therefore, no Percentage Payments received during fiscal2005.  There is no assurance that anyfuture payments will be received.

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

InJune 2006, Kaupulehu Developments entered into an Agreement (“Increment IIAgreement”) with WB and WB KD Acquisition II, LLC (“WBKD”) by which KaupulehuDevelopments sold its interest in Increment II, representing the remainderof the approximately 870 acres, to WBKD. There is no affiliation between Kaupulehu Developments and WB orWBKD.  WB and WBKD are both affiliates ofWestbrook 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 toreceive future payments from WBKD based on a percentage of the sales prices ofthe residential lots, ranging from 3.25% to 14%, to be determined in the futuredepending upon a number of variables, including whether the lots are sold priorto improvement.  The revenue from the$10,000,000 payment received in fiscal 2006 was reduced by $600,000 of feesrelated to the sale, $220,000 in other costs related to the sale, andapproximately $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 noIncrement II Percentage Payments received during the year endedSeptember 30, 2006.  There is noassurance that any future payments will be received.

Inaddition, under the terms of the Increment II Agreement, WBKD has the exclusiveright to negotiate with Kaupulehu Developments with respect to Lot 4C, which iscomprised of approximately 1,000 acres of vacant leasehold land zoned conservationlocated adjacent to Increment II. This right expires in June 2009 or, if WBKD completes any and allenvironmental assessments and surveys reasonably required to support a petitionto the Hawaii State Land Use Commission for reclassification of Lot 4C zoning,in June 2012.

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Thesales of Kaupulehu Developments’ Increment I and Increment IIleasehold land interests in fiscal 2004 and fiscal 2006, respectively, wereaccounted for pursuant to the provisions of SFAS No. 66 which providesspecific sales recognition criteria to determine when land sale revenue can berecorded.  The revenue recognized infiscal 2004 from the $11,550,000 payment plus $350,000 of post-closing InterimPayments, 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 previouslycapitalized 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 minorityinterest, totaling $550,000.  The revenuerecognized in fiscal 2006 from the $10,000,000 Increment II payment andthe $3,660,000 of Percentage Payments received on the Increment I lotsales was reduced by $820,000 of fees related to the sale, $220,000 in othercosts related to the sales, and approximately $2,983,000 of previouslycapitalized 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 andInterim Payment revenues, net of related fees and other costs, are recorded inthe Consolidated Statements of Operations as “Sale of interest in leaseholdland, net.”

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

Thetotal amount of remaining future development rights option receipts atSeptember 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 fourpayments of $2,656,250 due on each December 31 of years 2007 to 2010.  If any annual option payment is not made, thethen remaining development right options will expire.  There is no assurance that any portion of theremaining options will be exercised.

The aforementioned $173,000 in fees ($121,000net 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

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Percentage Payments and Increment II paymentproceeds 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 rightsin fiscal 2005 and 2004, and the $693,000 in fees ($486,000, net of minorityinterest) on the proceeds from the closing and Interim Payments received forthe sale of interest in leasehold land in the year ended September 30,2004 were paid to Nearco, Inc. (“Nearco”), a company controlled by Mr. TerryJohnston, a director of Barnwell and an indirect 20.6% owner of KaupulehuDevelopments.  Under an agreement enteredinto in 1987, prior to Mr. Johnston’s election to Barnwell’s Board ofDirectors, Barnwell is obligated to pay Nearco 2% of Kaupulehu Developments’gross receipts from real estate transactions, and Cambridge Hawaii LimitedPartnership, a 49.9% partner of Kaupulehu Developments in which Barnwellpurchased a 55.2% interest in April 2001, is obligated under an agreemententered into in 1987 to pay Nearco 4% of Kaupulehu Developments’ gross receiptsfrom real estate transactions.  The feesrepresent compensation for promotion and marketing of Kaupulehu Developments’property and were determined based on the estimated fair value of suchservices.  Barnwell believes the fees arefair and reasonable compensation for such services.

Fees were also paid to Nearco for consultingservices related to Kaupulehu Developments’ leasehold land.  In fiscal 2006, 2005 and 2004, consultingservice 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 toNearco in fiscal 2004 for services related to the closing of the February 2004sale of an interest in leasehold land. These fees were a direct cost of the sale and accordingly reduced therevenues recognized from the sale. Barnwell believes the fees are fair and reasonable compensation for suchservices.

Contract drilling

Contractdrilling revenues and costs are associated with well drilling and water pumpinstallation, replacement and repair in Hawaii.

Contractdrilling revenues decreased $1,778,000 (23%) to $5,866,000 in fiscal 2006, ascompared to $7,644,000 in fiscal 2005, and contract drilling operating expensesdecreased $1,056,000 (18%) to $4,709,000 in fiscal 2006, as compared to $5,765,000in fiscal 2005.  Operating profit before generaland administrative expenses decreased $786,000 (45%) from $1,754,000 in fiscal2005 to $968,000 in fiscal 2006 due to a decreasein well drilling work coupled with a decrease in the values and margins ofcontracts performed in fiscal 2006, as compared to fiscal 2005.  Contract drilling revenues and costs arenot seasonal in nature but can fluctuate significantly based on the awardingand timing of contracts, which are determined by contract drilling customerdemand.  Managementcurrently estimates that operating profit will be lower in fiscal 2007 due tolower estimated margins on contracts in backlog.

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

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

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generaland administrative expenses increased $1,346,000 (330%) from $408,000 in fiscal2004 to $1,754,000 in fiscal 2005 due to an increase in water well drillingactivity and higher margins on contracts performed throughout most of fiscal2005, as compared to fiscal 2004.

Gain on sale ofdrill rig

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

Gas processing andother 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 $243,000increase in interest income received from certificates of deposit and cashmanagement funds, gains on sales of other assets of $73,000, and a $42,000increase in gas processing revenues during fiscal 2006, as compared to fiscal2005.

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 Developmentsreceived $250,000 in income related to negotiations on the development ofKaupulehu Developments’ resort/residential acreage; such negotiation revenuesdiscontinued with the consummation of Kaupulehu Developments’ sale of aninterest in leasehold land in February 2004, therefore there were no suchrevenues in fiscal 2005.  In addition,fiscal 2004 gas processing and other income included a $139,000 gain from thesale of a parcel of vacant land formerly used as a storage and maintenance yardby Barnwell’s contract drilling segment; there was no such sale in fiscal 2005.

General and administrativeexpenses

Generaland 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 stockappreciation rights expense for the year ended September 30, 2006 due tofluctuations in Barnwell’s stock price, partially offset by an increase in thenumber of shares vested.  This decrease waspartially offset by increased personnel costs of $1,323,000; increasedprofessional services incurred in connection with the preparation for futurerequirements to comply with the Sarbanes-Oxley Act, legal fees related to theland segment, audit fees and actuarial fees for a total of $1,000,000;decreased administrative expense reimbursements from oil and natural gas jointventure 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 endedSeptember 30, 2006.

Generaland administrative expenses increased $3,820,000 (48%) to $11,731,000 in fiscal2005, as compared to $7,911,000 in fiscal 2004. The increase was due in part to a $2,509,000 increase in stockappreciation rights expense resulting from an increase in Barnwell’s stockprice and the issuance of additional stock options with stock appreciationrights in fiscal 2005, as compared to the prior year.  Personnel costs also increased by $1,192,000in fiscal 2005 as a result of the addition of new personnel in the oil andnatural gas operations and increased compensation costs.  In addition, professional fees

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

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

Depletion, depreciationand amortization

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

The higher depletion rateis due to increases in Barnwell’s costs of finding and developing provenreserves, and costs that are incurred to decrease the rate of productiondeclines or maintain or increase rates of production from reserves found inprevious years.  Barnwell’s cost offinding and developing proven reserves has increased due to the cost of oil andnatural gas exploration and development having increased along with productprices and the drilling of unsuccessful wells.

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

Interest expense

Interest expenseincreased $217,000 (35%) to $833,000 in fiscal 2006, as compared to $616,000 infiscal 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 duringfiscal 2006 on Barnwell’s borrowings from Royal Bank of Canada increased to6.67%, as compared to 4.82% in fiscal 2005. The weighted-average balance of outstanding borrowings from Royal Bankof Canada increased to $11,640,000 in fiscal 2006 as compared to $10,300,000 infiscal 2005.

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

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The majority of Barnwell’sdebt is denominated in U.S. dollars. Therefore, the increase in the average exchange rate of the Canadiandollar 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 foreigncurrency translation and transaction gains and losses due to fluctuations ofthe exchange rates between the Canadian dollar and the U.S. dollar.

Thefiscal year average exchange rate of the Canadian dollar to the U.S. dollarincreased 7% in fiscal 2006, as compared to fiscal 2005, and the exchange rateof 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 andstockholders’ equity of Barnwell’s subsidiaries operating in Canada haveincreased.  Barnwell’s Canadian dollarassets are greater than its Canadian dollar liabilities; therefore, increasesin value of the Canadian dollar to the U.S. dollar generate other comprehensiveincome.  The fiscal year average exchangerate of the Canadian dollar to the U.S. dollar increased 8% in fiscal 2005, ascompared to fiscal 2004, and the exchange rate of the Canadian dollar to theU.S. dollar increased 9% at September 30, 2005, as compared to September 30,2004.  Other comprehensive income due toforeign currency translation adjustments for fiscal 2006 was $1,140,000, a $403,000decrease from other comprehensive income of $1,543,000 in fiscal 2005.

Foreign currencytransaction gains and losses were not material in fiscal 2006, 2005, and 2004and are reflected in general and administrative expenses.

The impact offluctuations 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 theCanadian and U.S. dollars.

Income taxes

InMay 2006, a bill reducing the Province of Alberta’s corporate tax rate from11.5% to 10.0% effective April 1, 2006 received Royal Assent and waspassed into law.  In June 2006, RoyalAssent was received on a bill passed by the Parliament of Canada which reducesthe federal corporate income tax rate to 19% from 21% by 2010 startingJanuary 1, 2008.  The federalcorporate surtax will also be eliminated effective January 1, 2008.  Accordingly, during the year endedSeptember 30, 2006, Barnwell’s Canadian net deferred income taxliabilities were reduced by approximately $1,094,000 as a result of thesereductions in Canadian tax rates.  Therewas no benefit attributable to changes in Canada’s federal or Alberta’sprovincial corporate tax rates in the year ended September 30, 2005.

Alsoincluded in the provision for income taxes for the year endedSeptember 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 creditcarryforwards.  The acceleration ofBarnwell’s investments in Canadian oil and natural gas properties beginning inthe first quarter of fiscal 2006 resulted in the determination that it was morelikely than not that fiscal 2006 and future years’ taxable income from Canadianoperations under U.S. tax law will exceed taxable income from Canadianoperations under Canadian tax law to a degree that will result in theutilization of foreign tax credit carryforwards to

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reduceU.S. taxes.  This is primarilyattributable to differences in the statutory deduction rates for Barnwell’sCanadian oil and natural gas capital expenditures under Canadian tax law ascompared to such deductions under U.S. tax law. There was no reduction in the valuation allowance for foreign tax creditcarryforwards in the year ended September 30, 2005.  Barnwell’s estimates of the tax effects oftemporary differences under both Canadian tax jurisdiction and U.S. taxjurisdiction that give rise to deferred tax assets and liabilities andestimates of deferred tax asset valuation allowances require subjectiveassumptions including, among others, estimates of Canadian taxable income, U.S.taxable income and Canadian capital expenditures in future years.

In November 2003, RoyalAssent was received on a bill passed by the Parliament of Canada, which wasthen enacted into law, to reduce Canada’s corporate tax rate on “resource”income (income derived from oil and natural gas operations) over a four-yearperiod beginning January 1, 2003 from 29% to 21% beginning January 1,2007.  Additionally, the bill phases inover the same four-year period tax deductions for royalties, which previouslywere not tax deductible, and phases out the Resource Allowance deduction alongwith other changes.  Accordingly, duringfiscal 2004, Barnwell’s Canadian net deferred income tax liabilities werereduced by approximately $1,440,000 due to the reduction in Canada’s federalcorporate tax rate.  There was no benefitattributable to changes in Canada’s corporate tax rate on “resource” income infiscal 2005.  Barnwell’s Canadian netdeferred income tax liabilities were also reduced by approximately $300,000 infiscal 2004 as a result of the Province of Alberta’s reduction of the province’scorporate tax rate from 13.0% to 12.5%, effective April 1, 2003 (enacted intolaw 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 estateaffiliate

InJune 2006, Barnwell entered into an agreement with Nearco to form Mauka 3Kfor the purpose of providing real estate consulting services and investing inreal estate. Barnwell and Nearco each have an equal 50% voting interest inMauka 3K.  Nearco is a companycontrolled by Mr. Terry Johnston, a director of Barnwell and an indirect 20.6%owner of Kaupulehu Developments, a general partnership in which Barnwell owns a77.6% controlling interest.  Barnwelldoes not have a controlling interest in Mauka 3K and thus accounts for itsinvestment utilizing the equity method of accounting.  Under the equity method of accounting, Barnwell’sproportionate share of its affiliate’s income is included in equity in earningsof real estate affiliate.

InSeptember 2006 Barnwell received net proceeds of $1,440,000 representing itsshare of real estate consulting revenues, less related expenses.  The net proceeds are reflected in theConsolidated Statements of Operations as “Equity in earnings of real estateaffiliate, net of tax.”

EnvironmentalMatters

Federal,state, and Canadian governmental agencies issue rules and regulations andenforce laws to protect the environment which are often difficult and costly tocomply 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 gasindustry increases its cost of doing business. These laws, rules and regulations affect the operations of Barnwell andcould have a material adverse effect upon the earnings or competitive positionof Barnwell.  Although Barnwell’sexperience has been to the contrary, there is no assurance that this willcontinue to be the case.

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Inflation

Theeffect of inflation on Barnwell has generally been to increase its cost ofoperations, interest cost (as a substantial portion of Barnwell’s debt is atvariable short-term rates of interest which tend to increase as inflationincreases), general and administrative costs and direct costs associated withoil and natural gas production and contract drilling operations.  Oil and natural gas prices realized byBarnwell are essentially determined by world prices for oil and westernCanadian/Midwestern U.S. prices for natural gas.

Recent AccountingPronouncements

In May 2005, theFinancial Accounting Standards Board (“FASB”) issued Statement of FinancialAccounting Standards (“SFAS”) No. 154, “Accounting Changes and ErrorCorrection — a replacement of APB Opinion No. 20 and FASB StatementNo. 3.”  This statement changes therequirements for the accounting for and reporting of a change in accountingprinciple and applies to all voluntary changes in accounting principle.  It also applies to changes required by anaccounting pronouncement in the unusual instance that the pronouncement doesnot include specific transition provisions. When a pronouncement includes specific transition provisions, thoseprovisions should be followed. Accounting Principal Board (“APB”) No. 20 required that mostvoluntary changes in accounting principle be recognized by including in netincome of the period of the change the cumulative effect of changing to the newaccounting principle.  This statementrequires retrospective application to prior period financial statements ofchanges in accounting principle, unless it is impracticable to determine eitherthe period-specific effects or the cumulative effect of the change.  Theprovisions of SFAS No. 154 are effective for fiscal years beginning afterDecember 15, 2005.

InFebruary 2006, the FASB issued SFAS No. 155, “Accounting for CertainHybrid Financial Instruments,” which amends SFAS No. 133, “Accounting forDerivative Instruments and Hedging Activities” and SFAS No. 140, “Accountingfor Transfers and Servicing of Financial Assets and Extinguishments ofLiabilities.”  SFAS No. 155 is aimedat improving the financial reporting of certain hybrid financial instruments byrequiring more consistent accounting that eliminates exemptions and provides ameans to simplify the accounting for these instruments.  SFAS No. 155 is applicable to new ormodified financial instruments in fiscal years beginning after September 15,2006, though the provisions related to fair value accounting for hybridfinancial instruments can also be applied to existing instruments.  Early adoption, as of the beginning of anentity’s fiscal year, is also permitted, provided interim financial statementshave not yet been issued.  Adoption ofthe provisions of SFAS No. 155 is not expected to have a material impacton Barnwell’s financial condition, results of operations, or liquidity.

InMarch 2006, the FASB issued SFAS No. 156, “Accounting for Servicing ofFinancial Assets,” which provides an approach to simplify efforts to obtainhedge-like (offset) accounting.  SFASNo. 156 amends FASB Statement No. 140, “Accounting for Transfers andServicing of Financial Assets and Extinguishments of Liabilities,” with respectto the accounting for separately recognized servicing assets and servicingliabilities.  SFAS No. 156i) requires an entity to recognize a servicing asset or servicingliability each time it undertakes an obligation to service a financial asset byentering into a servicing contract in certain situations; ii) requiresthat a separately recognized servicing asset or servicing liability beinitially measured at fair value, if practicable; iii) permits an entityto choose

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either the amortizationmethod or the fair value method for subsequent measurement for each class ofseparately recognized servicing assets or servicing liabilities;iv) permits at initial adoption a one-time reclassification ofavailable-for-sale securities to trading securities by an entity withrecognized servicing rights, provided the securities reclassified offset theentity’s exposure to changes in the fair value of the servicing assets orliabilities; and v) requires separate presentation of servicing assets andservicing liabilities subsequently measured at fair value in the balance sheetand additional disclosures for all separately recognized servicing assets andservicing liabilities.  SFAS No. 156is effective for all separately recognized servicing assets and liabilities asof the beginning of an entity’s fiscal year that begins afterSeptember 15, 2006, with earlier adoption permitted in certaincircumstances.  SFAS No. 156 alsodescribes the manner in which it should be initially applied.  Adoption of the provisions of SFASNo. 156 is not expected to have a material impact on Barnwell’s financialcondition, results of operations, or liquidity.

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

In June 2006, the FASBratified the consensus on Emerging Issues Task Force (“EITF”) IssueNo. 06-3, “How Taxes Collectedfrom Customers and Remitted to Governmental Authorities Should Be Presented inthe Income Statement.”  The scopeof EITF 06-3 includes any tax assessed by a governmental authority that isdirectly imposed on a revenue-producing transaction between a seller and acustomer 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 thatentities should present these taxes in the income statement on either a grossor a net basis, based on their accounting policy, which should be disclosedpursuant to APB Opinion No. 22, “Disclosureof Accounting Policies.”  If suchtaxes are significant and are presented on a gross basis, the amounts of thosetaxes should be disclosed.  The consensuson EITF 06-3 will be effective for interim and annual reporting periodsbeginning after December 15, 2006. Barnwell’s management is currently evaluating the effect of theseprovisions on Barnwell’s results of operations, financial condition andliquidity.

In September 2006, the FASBissued SFAS No. 157, “Fair ValueMeasurements.”  SFAS No. 157 definesfair value, establishes a framework for measuring fair value in generallyaccepted accounting principles, and expands disclosures about fair valuemeasurements.  SFAS No. 157 does notrequire any new fair value measurements, however, for some entities, theapplication of SFAS No. 157 will change current practice.  SFAS No. 157 is effective for fiscalyears beginning after November 15, 2007.  Barnwell’s management is currently evaluatingthe effect of these provisions on Barnwell’s results of operations, financialcondition and liquidity.

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

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

In September 2006, the United States Securities andExchange Commission issued Staff Accounting Bulletin (“SAB”) No. 108, “Consideringthe Effects of Prior Year Misstatements when Quantifying Misstatements inCurrent Year Financial Statements.”  SABNo. 108 provides guidance on the consideration of the effects of prioryear misstatements in quantifying current year misstatements for the purpose ofa materiality assessment.  SAB No. 108establishes an approach that requires quantification of financial statementerrors based on the effects of each of the company’s balance sheet andstatement of operations financial statements and the related financialstatement disclosures.  SAB No. 108 permitsexisting public companies to record the cumulative effect of initially applyingthis approach in the first year ending after November 15, 2006 byrecording the necessary correcting adjustments to the carrying values of assetsand liabilities as of the beginning of that year with the offsetting adjustmentrecorded to the opening balance of retained earnings.  Additionally, the use of the cumulative effecttransition method requires detailed disclosure of the nature and amount of eachindividual error being corrected through the cumulative adjustment and how andwhen it arose.  Barnwell’s management iscurrently evaluating the effect of these provisions on Barnwell’s results ofoperations, financial condition and liquidity.

**Liquidity and Capital Resources**

Cash Flows, Debtand Available Credit

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

Cash flows used ininvesting activities totaled $7,304,000 for fiscal 2006, a decrease of $6,119,000from cash flows used in investing activities of $13,423,000 in fiscal 2005.  Cash inflows from investing activitiesincreased during fiscal 2006, as compared to fiscal 2005, due primarily toKaupulehu Developments’ receipt of a closing payment from the sale of itsinterest in Increment II which generated $9,180,000 of proceeds, net of expenses, in fiscal2006; there were no sales related to Increment II in the prior year.  The increase was also due to $3,440,000 of PercentagePayments, net of expenses, received from WB for WB’s Lot 4A Increment Isales; there were no such proceeds received

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in fiscal 2005.  Barnwell also received $2,702,000 ofproceeds, net of expenses, from the sale of development rights during fiscal2006, as compared to $2,497,000 of proceeds, net of expenses, received duringfiscal 2005.  Investing cash flows forthe current year also include $1,700,000 of proceeds from the maturity ofcertificates of deposit, as compared to net investments in certificates ofdeposit of $313,000 in the prior year, and $712,000 of proceeds, net ofassociated costs, from the sale of a drill rig; there were no such fixed assetsales proceeds received in fiscal 2005. The increase in cash flows from investing activities was partiallyoffset by an $8,670,000 increase in capital expenditures, primarilyattributable to the oil and natural gas segment, to $25,385,000 in fiscal 2006,as compared to $16,715,000 in fiscal 2005.

Cashflows used in financing activities totaled $4,525,000 for the year endedSeptember 30, 2006, a $4,523,000 increase from $2,000 of cash used infinancing activities in fiscal 2005. This increase was primarily due to $3,095,000 of distributions made to minority interest partnersin 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 inproceeds from the exercise of stock options in fiscal 2005; there were no long-termdebt borrowings or proceeds from the exercise of stock options in fiscal 2006.

In October 2005, Barnwelldeclared a three-for-one stock split in the form of a stock dividend.  The new shares were distributed onNovember 14, 2005 to all shareholders of record as of October 28,2005.

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

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

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

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

Royal Bank of Canada hasrenewed Barnwell’s credit facility through April 2007 at $20,000,000 Canadiandollars, approximately US$17,932,000, at September 30, 2006.  All other terms of the credit facilityremained unchanged upon renewal.  Thebank affirmed that it will not require any repayments under the facility beforeOctober 1, 2007.  Accordingly,Barnwell has classified outstanding borrowings under the facility as long-termdebt.

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

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production declines from current levels or oil and natural gas pricesdecline from current levels, current working capital balances and cash flowsgenerated by operations may not be sufficient to fund Barnwell’s currentprojected level of oil and natural gas capital expenditures, in which caseBarnwell may fund capital expenditures with funds generated by land segmentsales, long-term debt borrowings, or it may reduce future oil and natural gascapital expenditures.  Additionally, if Barnwell’s credit facilitywith a Canadian bank is reduced below the current level of borrowings under thefacility after the April 2007 review, Barnwell may be required to reduceexpenditures or seek alternative sources of financing to make any requiredpayments under the facility. 

Oil and NaturalGas Capital Expenditures

Barnwell’s oil andnatural gas capital expenditures, including accrued capital expenditures,increased $7,720,000 (42%) from $18,229,000 in fiscal 2005 to $25,949,000 in fiscal2006.  Barnwell participated indrilling 47 gross (13.5 net) wells, of which 40 gross (11.2 net) wells wereinitially deemed by management to be successful, and replaced 73% of oilproduction (including natural gas liquids) and 123% of natural gas production.  Of these 47 gross wells in fiscal 2006, Barnwellinitiated 28 gross (11.7 net) wells.  Ofthe $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 intangibledrilling 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 2006were in the Progress, Pouce Coupe South, Simonette, Dunvegan, Swalwell,Josephine, Bonanza/Balsam, and Doris areas of Alberta.

Thefollowing table sets forth the gross and net numbers of oil and natural gaswells Barnwell participated in drilling for each of the last three fiscalyears:
| ** **                              | ** ** | **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 |   |

 

Barnwellestimates that oil and natural gas capital expenditures for fiscal 2007 willrange from $13,500,000 to $16,000,000. This estimated amount may increase or decrease as dictated by management’sassessment of the oil and natural gas environment and prospects.

Subsequent Events

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

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InNovember 2006, Kaupulehu Investors, LLC, a limited liability companywholly-owned by Barnwell, invested $3,000,000 in two unrelated limited liabilitycompanies to acquire a passive minority interest in Hualalai Resort, located atKaupulehu, North Kona, Hawaii, which includes the Four Seasons Resort Hualalaiat Historic Ka’upulehu, two golf courses and undeveloped residentialproperty.  Barnwell’s internal cash flowsare expected to be sufficient to finance this investment.

**ITEM 7A.****                   ****QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK**

Theprimary objective of the following information is to provide forward-lookingquantitative and qualitative information about our potential exposure to marketrisks.  The term “market risk” refers tothe risk of loss arising from adverse fluctuations in commodity prices,interest rates and foreign currency exchange rates.  The disclosures are not meant to be preciseindicators of expected future losses, but rather indicators of reasonablypossible losses.  This forward-lookinginformation provides indicators of how we view and manage our ongoing marketrisk exposures.  All of our market risksensitive instruments were entered into for purposes other than speculativetrading.

Commodity Price Risk

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

Currently, Barnwell acceptsthe volatility risk that oil and natural gas prices present as Barnwell has notentered into transactions utilizing derivative financial instruments orderivative commodity instruments.  Inaddition, virtually none of Barnwell’s estimated 2007 oil or natural gasproduction is subject to fixed-price physical delivery contracts.

Interest Rate Risk 

Barnwell is exposed tochanges in U.S. and Canadian interest rates, primarily resulting from itsborrowing and investing activities used to fund operations and maintainliquidity.  Barnwell has a revolvingcredit facility which carries a variable interest rate that is tied to marketindices.  The credit facility isavailable 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 ExchangeRisk

Barnwell’soil 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 Canadiansubsidiaries are based on the U.S. dollar equivalent of such amounts measuredin the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated toU.S. dollars using the applicable exchange rate as of the end of a reportingperiod.  Revenues, expenses and cash floware translated using the average exchange rate during the reporting period.

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**ITEM 8.                  FINANCIAL STATEMENTS ANDSUPPLEMENTARY DATA**

**Reportof Independent Registered Public Accounting Firm**

The Board of Directorsand ShareholdersBarnwell Industries, Inc.:

Wehave audited the accompanying consolidated balance sheets of Barnwell Industries,Inc. and subsidiaries as of September 30, 2006 and 2005, and the relatedconsolidated statements of operations, stockholders’ equity and comprehensiveincome, and cash flows for each of the years in the three-year period endedSeptember 30, 2006. These consolidated financial statements are theresponsibility of the Company’s management. Our responsibility is to express anopinion on these consolidated financial statements based on our audits.

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation. We believe that ouraudits provide a reasonable basis for our opinion.

Inour opinion, the consolidated financial statements referred to above presentfairly, in all material respects, the financial position of BarnwellIndustries, Inc. and subsidiaries as of September 30, 2006 and 2005, andthe results of their operations and their cash flows for each of the years inthe three-year period ended September 30, 2006, in conformity with U.S.generally accepted accounting principles. As discussed in note 10 to theconsolidated financial statements, effective October 1, 2005, the Companychanged its method of accounting for share-based payments.
| /s/KPMG LLP |   |
|-------------|--------|

 

Honolulu,HawaiiDecember 20, 2006

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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIESCONSOLIDATED 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 toConsolidated Financial Statements

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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIESCONSOLIDATED 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

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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIESCONSOLIDATED 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

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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOMEYears 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 |   |

 

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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOMEYears 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 nextpage)

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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOMEYears 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

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**BARNWELL INDUSTRIES, INC.AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED SEPTEMBER 30, 2006, 2005 AND 2004**

**1.             DESCRIPTION OF THE REPORTINGENTITY AND BUSINESS**

Theconsolidated financial statements include the accounts of Barnwell Industries,Inc. and all majority-owned subsidiaries, including an indirect 77.6%-ownedland development general partnership, (collectively referred to herein as “Barnwell”).  All significant intercompany accounts andtransactions have been eliminated.  Investmentsin companies over which Barnwell has the ability to exercise significantinfluence, but not control, are accounted for using the equity method.

Duringits last three fiscal years, Barnwell was engaged in exploring for, developing,producing and selling oil and natural gas in Canada, investing in leaseholdland in Hawaii, and drilling wells and installing and repairing water pumpingsystems in Hawaii.  Barnwell’s oil andnatural gas activities comprise its largest business segment.  Approximately 66% of Barnwell’s revenues and98% of Barnwell’s capital expenditures for the fiscal year endedSeptember 30, 2006 were attributable to its oil and natural gasactivities.  Barnwell’s land investmentsegment revenues accounted for 21% of fiscal 2006 revenues; Barnwell’s contractdrilling activities accounted for 10% of fiscal 2006 revenues; and otherrevenues comprised 3% of fiscal 2006 revenues.

**2.             SIGNIFICANT ACCOUNTING POLICIES**

Cash andCash Equivalents

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

TradeAccounts Receivable

Tradeaccounts receivable are recorded at the invoiced amount and do not bearinterest.  The allowance for doubtfulaccounts is Barnwell’s best estimate of the amount of probable credit losses inBarnwell’s existing accounts receivable and is based on historical write-offexperience.  Account balances are chargedoff against the allowance after all means of collection have been exhausted andthe potential for recovery is considered remote.  Barnwell does not have any off-balance sheetcredit exposure related to its customers.

Oil andNatural Gas Properties

Revenuesassociated with the sale of oil, natural gas and natural gas liquids arerecognized in the Consolidated Statements of Operations when the oil, naturalgas and natural gas liquids are delivered and title has passed to the customer.

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Barnwelluses the full cost method of accounting under which all costs incurred in theacquisition, exploration and development of oil and natural gas reserves,including costs related to unsuccessful wells and estimated future siterestoration and abandonment, are capitalized until such time as the aggregateof such costs net of accumulated depletion and oil and gas related deferredincome taxes, on a country-by-country basis, equals the sum of 1) thediscounted present value (at 10%), using prices as of the end of the fiscalyear on a constant basis, of Barnwell’s estimated future net cash flows fromestimated production of proved oil and natural gas reserves as determined byindependent petroleum engineers, less estimated future expenditures to beincurred in developing and producing the proved reserves but excluding futurecash outflows associated with settling asset retirement obligations accrued onthe balance sheet; plus 2) the cost of major development projects and unprovenproperties not subject to depletion, if any; plus 3) the lower of cost orestimated fair value of unproven properties included in costs subject todepletion; less 4) related income tax effects. If net capitalized costs exceed this limit, the excess is expensedunless subsequent market price changes eliminate or reduce the indicatedwrite-down in accordance with U.S. Securities and Exchange Commission StaffAccounting Bulletin Topic 12D.  Depletionis computed using the units-of-production method whereby capitalized costs, netof salvage values, plus estimated future costs to develop proved reserves andsatisfy asset retirement obligations, are amortized over the total estimatedproved reserves on a country-by-country basis. Investments in major development projects are not depleted until eitherproved reserves are associated with the projects or impairment has beendetermined.  At September 30, 2006and 2005, Barnwell had no investments in major oil and natural gas developmentprojects that were not being depleted. General and administrative costs related to oil and natural gasoperations are expensed as incurred. Proceeds from the disposition of minor producing oil and natural gasproperties are credited to the cost of oil and natural gas properties.  Gains or losses are recognized on thedisposition of significant oil and natural gas properties.

Investment in Landand Revenue Recognition

Barnwell’sinvestment in land is comprised of development rights under option, rights toreceive percentage of sales payments, and approximately 1,000 acres of vacantleasehold land zoned conservation, which is under a right of negotiation.  Investment in land is reported at the lowerof the asset carrying value or fair value, less costs to sell, and is evaluatedfor impairment whenever events or changes in circumstances indicate that therecorded investment balance may not be fully recoverable.

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

Salesof development rights under option and revenues from sales of leasehold landinterests are accounted for pursuant to the provisions of Statement ofFinancial Accounting Standards (“SFAS”) No. 66, “Accounting for Sales ofReal Estate.”  SFAS No. 66 providesspecific sales recognition criteria to determine when land sale revenue can berecorded.

Investment inAffiliate

InJune 2006, Barnwell entered into an agreement with Nearco, Inc. (“Nearco”) toform Mauka 3K, LLC (“Mauka 3K”), for the purpose of providing realestate consulting services and investing in real estate.  Barnwell and Nearco each have an equal 50%voting interest in Mauka 3K.  Nearcois a company controlled by Mr. Terry Johnston, a director of Barnwell and anindirect 20.6%

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

Barnwellhas evaluated the aforementioned investment in accordance with FASBInterpretation No. 46, “Consolidation of Variable Interest Entities,” asrevised, as well as other applicable authoritative accounting literature, andhas determined that the investment in Mauka 3K does not meet therequirements for consolidation.  Barnwellaccounts for its investment in unconsolidated affiliates under the equitymethod when Barnwell’s ownership interest is more than 20% but no more than 50%and Barnwell does not exercise direct or indirect control over theinvestee.  Factors that are considered indetermining whether or not Barnwell exercises control include rights ofpartners regarding significant strategic and operational decisions.  As Barnwell does not exercise direct orindirect control over Mauka 3K, the investment is accounted for using theequity method of accounting.

Revenuesfrom real estate consulting services are recognized when services have beenrendered and the terms of the consulting agreement have been satisfied.

Contract Drilling

Revenues,costs and profits applicable to contract drilling contracts are included in theConsolidated Statements of Operations using the percentage of completionmethod, principally measured by the percentage of labor dollars incurred todate for each contract to total estimated labor dollars for each contract.  Contract losses are recognized in full in theperiod the losses are identified.  Theperformance of drilling contracts may extend over more than one year and, inthe interim periods, estimates of total contract costs and profits are used todetermine revenues and profits earned for reporting the results of contractdrilling operations.  Revisions in theestimates required by subsequent performance and final contract settlements areincluded as adjustments to the results of operations in the period suchrevisions and settlements occur. Contracts are normally less than one year in duration.

Income Taxes

Deferredincome taxes are determined using the asset and liability method.  Deferred tax assets and liabilities arerecognized for the estimated future tax impacts of differences between thefinancial statement carrying amounts of existing assets and liabilities andtheir respective tax bases.  Deferred taxassets and liabilities are measured using enacted tax rates in effect for theyear in which those temporary differences are expected to be recovered orsettled.  The effect on deferred taxassets and liabilities of a change in tax rates is recognized in income in theperiod that includes the enactment date.

Avaluation allowance is provided when it is more likely than not that someportion or all of the deferred tax asset will not be realized.  Barnwell has established a valuation allowanceprimarily for the U.S. tax effect of deferred Canadian taxes, accrued expensesand state of Hawaii net operating loss carryforwards which may not berealizable in future years as there can be no assurance of any specific levelof earnings or that the timing of U.S. earnings will coincide with the paymentof Canadian taxes to enable Canadian taxes to be fully deducted (orrecoverable) for U.S. tax purposes.

Retirement Plans

Barnwellsponsors a noncontributory defined benefit pension plan covering substantiallyall of its U.S. employees, with benefits based on years of service and theemployee’s highest consecutive

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five-yearaverage earnings.  Additionally, Barnwellsponsors a Supplemental Employee Retirement Plan, a noncontributorysupplemental retirement benefit plan which covers certain current and formeremployees of Barnwell for amounts exceeding the limits allowed under thepension plan.  Barnwell accounts for itsretirement plans in accordance with SFAS No. 87, “Employers’ Accountingfor Pensions,” which requires that amounts recognized in financial statementsbe determined on an actuarial basis. SFAS No. 87 requires that the effects of the performance of thepension plan’s assets and changes in pension liability discount rates onBarnwell’s computation of pension income (expense) be amortized over futureperiods.  Any variances in the futurebetween the assumed rates utilized for actuarial purposes and the actual ratesexperienced by the plan may materially affect Barnwell’s results of operationsor 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% andan expected rate of future annual compensation increases of 5%.

At the end of each year, Barnwell determines the discountrate to be used to calculate the present value of plan liabilities.  The discount rate is an estimate of thecurrent interest rate at which the pension liabilities could be effectivelysettled at the end of the year.  Inestimating this rate, Barnwell looks to rates of return on high-quality,fixed-income investments.  AtSeptember 30, 2006, Barnwell determined this rate to be 5.50% as comparedto a discount rate of 5.25% used at September 30, 2005.

Long-lived Assets

Long-livedassets to be held and used, other than oil and natural gas properties, areevaluated for impairment whenever events or changes in circumstances indicatethat the carrying amount of an asset may not be fully recoverable.  If the future cash flows expected to resultfrom use of the asset (undiscounted and without interest charges) are less thanthe carrying amount of the asset, an impairment loss is recognized.  Such impairment loss is measured as theamount by which the carrying amount of the asset exceeds the fair value of theasset.  Long-lived assets to be disposedof are reported at the lower of the asset carrying value or fair value, lesscost to sell.

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

Inventories

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

Environmental

Barnwellis subject to extensive environmental laws and regulations.  These laws, which are constantly changing,regulate the discharge of materials into the environment and maintenance ofsurface conditions and may require Barnwell to remove or mitigate theenvironmental effects of the disposal or release of petroleum or chemical substancesat various sites.  Environmentalexpenditures are expensed or capitalized depending on their future economicbenefit.  Expenditures that relate to anexisting condition caused by past operations and that have no future economicbenefits are expensed.

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Liabilities forexpenditures of a noncapital nature are recorded when environmental assessmentand/or remediation is probable, and the costs can be reasonably estimated.

Asset RetirementObligation

Barnwell accounts for asset retirement obligationsin accordance with SFAS No. 143, “Accounting for Asset RetirementObligations,” and FASB Interpretation No. 47, “Accounting for ConditionalAsset Retirement Obligations - an interpretation of FASB StatementNo. 143,” which requires that the fair value of a liability for an assetretirement obligation be recognized in the period in which it is incurred if areasonable estimate of fair value can be made. Barnwell’s estimated site restoration and abandonment costs of its oiland natural gas properties are capitalized as part of the carrying amount ofoil and natural gas properties and depleted over the life of the relatedreserves.  The liability is accreted atthe end of each period through charges to oil and natural gas operatingexpense.  If an obligation is settled forother than the carrying amount of the liability, Barnwell will recognize a gainor loss on settlement.

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

Earnings PerCommon Share

InDecember 2004, Barnwell’s Board of Directors declared a two-for-one stock splitin the form of a 100% stock dividend. The shares were distributed on January 28, 2005 to all shareholdersof record as of January 11, 2005. There were 1,361,510 shares outstanding on January 11, 2005 beforethe split.  Barnwell issued 1,028,223 ofnew shares and utilized 333,287 shares of treasury stock to execute the stockdividend, resulting in outstanding shares of 2,723,020 following thesplit.  Barnwell’s common stock begantrading on a split-adjusted basis on January 31, 2005.

InOctober 2005, Barnwell’s Board of Directors declared a three-for-one stocksplit in the form of a 200% stock dividend. The shares were distributed on November 14, 2005 to allshareholders of record as of October 28, 2005.  There were 2,723,020 shares outstanding onOctober 28, 2005.  Barnwell issued5,446,040 of new shares to execute the stock dividend, resulting in outstandingshares of 8,169,060 following the split. Barnwell’s common stock began trading on a split-adjusted basis on November 15,2005.

Allinformation in this Form 10-K has been adjusted where necessary toreflect the stock splits for all periods presented.

Basicearnings per share excludes dilution and is computed by dividing net earningsby the weighted-average number of common shares outstanding for theperiod.  Diluted earnings per shareincludes the potentially dilutive effect of outstanding common stock optionsand securities which are convertible to common shares.

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Reconciliationsbetween the numerator and denominator of the basic and diluted earnings pershare computations for the years ended September 30, 2006, 2005 and 2004are 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-BasedCompensation

EffectiveOctober 1, 2005, Barnwell adopted the provisions of SFAS No. 123(R), “Share-BasedPayment,” for its share-based compensation plans, using the modifiedprospective transition method.  Barnwellpreviously accounted for these plans under the recognition and measurementprinciples of Accounting Principles Board Opinion (“APB”) No. 25, “Accountingfor Stock Issued to Employees,” and related interpretations and disclosurerequirements established by SFAS No. 123, “Accounting for Stock-BasedCompensation,” as amended by SFAS No. 148, “Accounting for Stock-BasedCompensation – Transition and Disclosure.”

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

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

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

Foreign CurrencyTranslation

Assetsand liabilities of foreign operations and subsidiaries are translated at theyear-end exchange rate and resulting translation gains or losses are accountedfor in a stockholders’ equity account entitled “Accumulated other comprehensiveincome, net.”  Operating results offoreign subsidiaries are translated at average exchange rates during theperiod.  Realized foreign currencytransaction gains or losses were not material in fiscal years 2006, 2005, and2004.

Use of Estimatesin the Preparation of Financial Statements

Thepreparation of financial statements in conformity with accounting principlesgenerally accepted in the United States of America requires management to makeestimates 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 significantlyfrom those estimates.  Significantassumptions are required in the valuation of deferred tax assets, assetretirement obligations, share-based payment arrangements, obligations forretirement plans, contract drilling estimated costs to complete, and proved oiland natural gas reserves, and such assumptions may impact the amount at whichdeferred tax assets and oil and natural gas properties are recorded.

**3.             ACCOUNTS RECEIVABLE AND CONTRACTCOSTS**

Accountsreceivable are net of allowances for doubtful accounts of $10,000 as ofSeptember 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 areexpected to be collected within one year, generally within 45 days after therelated contracts have received final acceptance and approval.

Costsand 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 |   |

 

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Costsand estimated earnings on uncompleted contracts are included in theConsolidated 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

Barnwellowns a 77.6% controlling interest in Kaupulehu Developments, a Hawaii generalpartnership that owns interests in leasehold land and development rights forproperty located approximately six miles north of the Kona InternationalAirport in the North Kona District of the Island of Hawaii.

Between1986 and 1989, Kaupulehu Developments obtained the state and county zoningchanges necessary to permit development of the Four Seasons Resort Hualalai atHistoric Ka’upulehu and Hualalai Golf Club, which opened in 1996, a second golfcourse, and single-family and multi-family residential units.  These projects were developed on leaseholdland acquired from Kaupulehu Developments by Kaupulehu Makai Venture, anunrelated entity.

Between1993 and 2001, Kaupulehu Developments obtained the state and county zoningchanges necessary to permit resort/residential development of approximately 870acres.

Sale of Interestin Leasehold Land

InFebruary 2004, Kaupulehu Developments entered into a Purchase and SaleAgreement with WB KD Acquisition, LLC (“WB”) by which Kaupulehu Developmentstransferred its leasehold interest in the aforementioned 870 acres zoned forresort/residential development, in two increments, to WB.  There is no affiliation between KaupulehuDevelopments and WB.  WB is affiliatedwith Westbrook Partners, the developers of the Kuki’o Resort located adjacentto the Hualalai Resort at Historic Ka’upulehu. The first increment (“Increment I”) is an area planned forapproximately 80 single-family lots and a beach club on the portion of theproperty bordering the Pacific Ocean. The purchasers of the 80 single-family lots will have the right to applyfor membership in the Kuki’o Resort Golf and Beach Club, which is locatedadjacent to and south of the Four Seasons Resort Hualalai at Historic Ka’upulehu.  The second increment (“Increment II”) isthe remaining portion of the approximately 870-acre property and is zoned forsingle-family and multi-family residential units and a golf course andclubhouse.

With respect to Increment I, KaupulehuDevelopments received an $11,550,000 payment in February 2004 and is entitledto receive payment of the following percentages of the gross proceeds generatedfrom the sale by WB of single-family lots in Increment I (“PercentagePayments”): 9% of

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the gross proceeds from single-family lot sales up to aggregate grossproceeds 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 grossproceeds in excess of $300,000,000. Minimum amounts of these Percentage Payments are due by certaindates.  WB sold a total of fivesingle-family lots and paid Kaupulehu Developments $3,660,000 in PercentagePayments during the year ended September 30, 2006.  Revenue from the Percentage Paymentswas reduced by $220,000 of fees related to the sales resulting in net revenuesof $3,440,000 and a $2,688,000 operating profit, after minority interest.  Therewere no lot sales, and therefore, no Percentage Payments received during fiscal2005.  There is no assurance that anyfuture payments will be received.

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

InJune 2006, Kaupulehu Developments entered into an Agreement (“Increment IIAgreement”) with WB and WB KD Acquisition II, LLC (“WBKD”) by which KaupulehuDevelopments sold its interest in Increment II, representing the remainderof the approximately 870 acres, to WBKD. There is no affiliation between Kaupulehu Developments and WB orWBKD.  WB and WBKD are both affiliates ofWestbrook 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 toreceive future payments from WBKD based on a percentage of the sales prices ofthe residential lots, ranging from 3.25% to 14%, to be determined in the futuredepending upon a number of variables, including whether the lots are sold priorto improvement.  The revenue from the$10,000,000 payment received in fiscal 2006 was reduced by $600,000 of feesrelated to the sale, $220,000 in other costs related to the sale, andapproximately $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 noIncrement II Percentage Payments received during the year ended September 30,2006.  There is no assurance that anyfuture payments will be received.

Inaddition, under the terms of the Increment II Agreement, WBKD has theexclusive right to negotiate with Kaupulehu Developments with respect to Lot4C, which is comprised of approximately 1,000 acres of vacant leasehold landzoned conservation located adjacent to Increment II.  This right expires in June 2009 or, if WBKDcompletes any and all environmental assessments and surveys reasonably requiredto support a petition to the Hawaii State Land Use Commission forreclassification of Lot 4C zoning, in June 2012.

Thesales of Kaupulehu Developments’ Increment I and Increment IIleasehold land interests in~~~~fiscal 2004 and fiscal 2006, respectively,were accounted for pursuant to the provisions of SFAS No. 66 whichprovides specific sales recognition criteria to determine when land salerevenue can be recorded.  The revenuerecognized in fiscal 2004 from the $11,550,000 payment plus $350,000 ofpost-closing Interim Payments, was reduced by $693,000 of fees related to thesale, approximately $402,000 in other costs related to the sale, and $3,475,000of previously capitalized costs relating to Increment I resulting in netrevenues of $7,330,000 and an operating profit, after minority interest, ofapproximately $5,470,000.  During fiscal2005, Kaupulehu Developments received additional Interim Payments, beforeminority interest, totaling $550,000. The revenue recognized in fiscal 2006 from the $10,000,000Increment II payment and the $3,660,000 of Percentage Payments received onthe Increment I lot sales was reduced by $820,000 of fees related to thesale, $220,000 in other costs related to the sales, and approximately$2,983,000 of previously capitalized costs relating to Increment IIresulting in net revenues of $9,637,000 and an operating profit, after minorityinterest, of

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

Development RightsUnder Option

The developmentrights held by Kaupulehu Developments are for residentially-zoned leaseholdland within and adjacent to the Hualalai Golf Club and the second golf courseand are under option to Kaupulehu Makai Venture, an unrelated entity.  Sales of Kaupulehu Developments’ developmentrights are accounted for pursuant to the provisions of SFAS No. 66 whichprovides specific sales recognition criteria to determine when land salerevenue can be recorded.  In December 2003and 2004, Kaupulehu Makai Venture exercised the portion of its developmentrights option then due and paid Kaupulehu Developments non-refundable paymentsof $2,656,000 in both fiscal 2005 and 2004.  In November 2005, KaupulehuMakai Venture paid Kaupulehu Developments a non-refundable payment of$2,875,000 upon exercising its development rights option due onDecember 31, 2005 of $2,656,250 and a $218,750 portion of its developmentrights option due on December 31, 2006.  Ineach of fiscal years 2005 and 2004, $2,656,000 of revenues attributable to thedevelopment 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 wasreduced 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 costsdeducted from revenues from the sale of development rights in fiscal 2006, 2005and 2004 as all capitalized costs associated with the development rights wereexpensed in previous years.  Thedevelopment rights option revenues, net of related fees, are recorded in theConsolidated Statements of Operations as “Sale of development rights, net.”

The total amount of remaining future developmentrights option receipts at September 30, 2006, if all options are fullyexercised, is $13,062,500, comprised of the balance of $2,437,500 due onDecember 31, 2006 and four payments of $2,656,250 due on eachDecember 31 of years 2007 to 2010. If any annual option payment is not made, the then remaining developmentright options will expire.  There is noassurance that any portion of the remaining options will be exercised.

Fees

Theaforementioned $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 netof minority interest) on the Percentage Payments and Increment II paymentproceeds 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 rightsin 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 ofinterest in leasehold land in the year ended September 30, 2004 were paidto Nearco, Inc. (“Nearco”), a company controlled by Mr. Terry Johnston, adirector of Barnwell and an indirect 20.6% owner of KaupulehuDevelopments.  Under an agreement enteredinto in 1987, prior to Mr. Johnston’s election to Barnwell’s Board ofDirectors, Barnwell is obligated to pay Nearco 2% of Kaupulehu Developments’gross receipts from real estate transactions, and Cambridge Hawaii LimitedPartnership, a 49.9% partner of Kaupulehu Developments in which Barnwellpurchased a 55.2% interest in April 2001, is obligated under an agreemententered into in 1987 to pay Nearco 4% of Kaupulehu Developments’ gross receiptsfrom real estate transactions.  The feesrepresent compensation for promotion and marketing of Kaupulehu Developments’property and were determined based on the estimated fair value of suchservices.

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Fees were also paid to Nearco for consultingservices related to Kaupulehu Developments’ leasehold land.  In fiscal 2006, 2005 and 2004, consultingservice 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 toNearco in fiscal 2004 for services related to the closing of the February 2004sale of an interest in leasehold land. These fees were a direct cost of the sale and accordingly reduced therevenues recognized from the sale.

Interests atSeptember 30, 2006

Theinterests held by Kaupulehu Developments at September 30, 2006 include thedevelopment rights under option, the rights to receive percentage of salespayments on Increment I and Increment II of the two increments of the 870acres, and approximately 1,000 acres of vacant leasehold land zonedconservation, which is under a right of negotiation with WBKD.  There is no assurance that any future developmentrights option payments or percentage of sales payments will be received, nor isthere any assurance that WBKD will enter into an agreement with KaupulehuDevelopments regarding Lot 4C.  Theseinterests relate to land within and adjacent to the Hualalai Resort at HistoricKa’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 BalanceSheets under the caption “Investment in Land” and consists of the followingamounts:

|                                                               | ** ** | **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.****                                      INVESTMENTIN AFFILIATE**

In June 2006, Barnwell entered into an agreementwith Nearco to form Mauka 3K, LLC (“Mauka 3K”), for the purpose ofproviding real estate consulting services and investing in real estate.  Barnwell and Nearco each have an equal 50%voting interest in Mauka 3K.  Nearcois a company controlled by Mr. Terry Johnston, a director of Barnwell and anindirect 20.6% owner of Kaupulehu Developments, a general partnership in whichBarnwell owns a 77.6% controlling interest. Barnwell does not have a controlling interest in Mauka 3K and thusaccounts 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 equityin earnings of real estate affiliate.

In September 2006 Barnwell received net proceedsof $1,440,000 representing its share of real estate consulting revenues, lessrelated expenses.  The net proceeds arereflected in the Consolidated Statements of Operations as “Equity in earningsof real estate affiliate, net of tax.” The tax provision related to equity in earnings of real estate affiliatewas $545,000 in fiscal 2006.

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

**6.****                                      PROPERTYAND EQUIPMENT AND ASSET RETIREMENT OBLIGATION**

Barnwell’sproperty 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 |   |

 

Basedon a natural gas spot price of $3.34 per 1,000 cubic feet (“MCF”) as ofSeptember 30, 2006, the full cost pool exceeded the ceiling limitation byapproximately $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 fullcost pool would not have exceeded the ceiling limitation.  The spot price of natural gas onDecember 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 ExchangeCommission Staff Accounting Bulletin Topic 12D, Barnwell has not recorded animpairment write-down of its oil and natural gas properties atSeptember 30, 2006.

InOctober 2004, the Government of Alberta enacted amendments to the Natural GasRoyalty Regulation which provide a mechanism to reduce royalties calculatedthrough the Crown royalty system for operators of gas wells which have beendenied the right to produce by the Alberta Energy Utilities Board as a result ofrecent bitumen conservation decisions. In December 2004, royalty reductions were effected by the AlbertaDepartment of Energy’s Information Letter 2004-36 which

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sets out thedetails of the royalty adjustment, the impact on the existing temporary assistancereceived to date by affected gas well operators, the provisions for potentialrecapture of the royalty adjustments, and continuation of impacted petroleumand natural gas agreements.  Barnwellreceived a total of approximately $347,000 and $558,000 related to theaforementioned royalty adjustments for wells in the Thornbury area in fiscalyears 2006 and 2005, respectively.  It isBarnwell’s estimation that the subject Thornbury wells will not recommenceproduction, thus no returns to the Government of Alberta of the royaltyadjustments received would be required under the recapture provisions.  Accordingly, the receipts are payments fordeemed production by the Government of Alberta to Barnwell for condemnation ofthe wells, and such receipts were credited to oil and natural gas propertiesfor book purposes.

OnOctober 1, 2002, Barnwell adopted SFASNo. 143, “Accounting for Asset Retirement Obligations,” which requiresthat the fair value of a liability for an asset retirement obligation berecognized in the period in which it is incurred if a reasonable estimate offair value can be made.  Adoption of SFASNo. 143 increased gross oil and natural gas properties by $564,000,decreased accumulated depletion by $546,000, and increased the asset retirementobligation by $1,110,000 on October 1, 2002.  Following the initial implementationof SFAS No. 143, the asset retirement obligation was increased during theyear ended September 30, 2003 by $39,000 to reflect obligations incurredon new wells drilled, by $85,000 for accretion of the asset retirementobligation, and by $198,000 for changes in foreign currency translationrates.  During the year endedSeptember 30, 2004, the asset retirement obligation was increased by$133,000 to reflect obligations incurred on new wells drilled and changes inthe timing and amount of estimated future expenditures, by $100,000 foraccretion of the asset retirement obligation, and by $110,000 for changes inforeign currency translation rates. During the year ended September 30, 2005, the asset retirementobligation was increased by $221,000 to reflect obligations incurred on newwells drilled, $545,000 for changes in the timing and amount of estimatedfuture 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 ofestimated future expenditures primarily resulted from an increase in theinflation-adjusted cost of abandonment and restoration services, due in part torecent rises in oil and natural gas prices.

Duringthe year ended September 30, 2006, the asset retirement obligation wasincreased 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 forchanges in foreign currency translation rates. The changes due to the timing and amount of estimated futureexpenditures primarily resulted from an increase in the inflation-adjusted costof abandonment and restoration services, due in part to recent rises in oil andnatural gas prices.  The increase waspartially offset by $20,000 in abandonment and restoration disbursements infiscal 2006.

**7.****                                      LONG-TERMDEBT**

Barnwellhas a credit facility at Royal Bank of Canada, a Canadian bank, forapproximately $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.  AtSeptember 30, 2006, Barnwell had unused credit available under thisfacility of approximately $6,197,000.

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Thefacility is available in U.S. dollars at the London Interbank Offer Rate plus2%, at U.S. prime plus 1%, or in Canadian dollars at Canadian prime plus1%.  A standby fee of 0.5% per annum ischarged on the unused facility balance. Under the financing agreement, the facility is reviewed annually, withthe next review planned for April 2007. Subject to that review, the facility may be extended one year with norequired debt repayments for one year or converted to a two-year term loan bythe bank.  The primary focus of theannual review is on the future cash flows that will be generated by Barnwell’sCanadian oil and natural gas properties. Additionally, Royal Bank of Canada may adjust the total amount of thecredit facility during its next review. If the facility is converted to a two-year term loan, Barnwell hasagreed to the following repayment schedule of the then outstanding loanbalance:  first year of the term period –20% (5% per quarter), and in the second year of the term period – 80% (5% perquarter for the first three quarters and 65% in the final quarter).

Barnwellhas the option to change the currency denomination and interest rate applicableto 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 facilityat September 30, 2006 was 7.217%. The facility is collateralized by Barnwell’s interests in its major oiland natural gas properties and a pledge not to otherwise pledge on itsremaining oil and natural gas properties. The facility is guaranteed by Barnwell Industries, Inc.  No compensating bank balances are requiredfor this facility.

Thebank affirmed that it will not require any repayments under the facility beforeOctober 1, 2007.  Accordingly,Barnwell has classified outstanding borrowings under the facility as long-termdebt.

Interestcosts amounted to $833,000, $616,000 and $487,000 for the years endedSeptember 30, 2006, 2005 and 2004, respectively.

**8.****                                      TAXESON INCOME**

Thecomponents 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 |   |

 

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Thecomponents 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 theprovision for income taxes for fiscal 2006 is a Canadian deferred tax benefitof $1,094,000 resulting from a reduction in Canadian tax rates.  In May 2006, a bill reducing the Province ofAlberta’s corporate tax rate from 11.5% to 10.0% effective April 1, 2006received Royal Assent and was passed into law. In June 2006, Royal Assent was received on a bill passed by theParliament 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 January1, 2008.  Accordingly, Barnwell’sCanadian net deferred income tax liabilities were reduced in fiscal 2006 as aresult of these reductions in Canadian tax rates.

Also included inthe provision for income taxes for fiscal 2006 is the recognition of a deferredincome tax benefit of $4,130,000 due to a reduction in the valuation allowancefor foreign tax credit carryforwards. The acceleration of Barnwell’s investments in Canadian oil and naturalgas properties beginning in the first quarter of fiscal 2006, coupled withKaupulehu Developments’ receipt of proceeds related to Increment I, resulted inthe determination that it was more likely than not that fiscal 2006 and futureyears’ taxable income from Canadian operations under U.S. tax law will exceedtaxable income from Canadian operations under Canadian tax law to a degree thatwill result in the utilization of foreign tax credit carryforwards to reduceU.S. taxes.  This is primarilyattributable to differences in the statutory deduction rates for Barnwell’sCanadian oil and natural gas capital expenditures under Canadian tax law as comparedto such deductions under U.S. tax law. There were no reductions in the valuation allowance for foreign taxcredit carryforwards in the years ended September 30, 2005 or 2004.  Approximately $2,600,000 of foreign taxcredit carryforwards will be utilized to reduce U.S. income taxes for fiscal2006.  Barnwell’s estimates of the taxeffects of temporary differences under both Canadian tax jurisdiction and U.S.tax jurisdiction that give rise to deferred tax assets and liabilities andestimates of deferred tax asset valuation allowances require subjectiveassumptions including, among others, estimates of Canadian taxable income, U.S.taxable income and Canadian capital expenditures in future years.

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

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use the full alternativeminimum tax foreign tax credit to offset alternative minimum taxes on foreignsource 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 increasesin stock appreciation rights accruals, bonus accruals, the excess of depletionand depreciation for book purposes over tax, and alternative minimum taxcredits generated during the year which are estimated to have future taxbenefits.

Includedin the provision for income taxes for fiscal 2004 is a $1,740,000 deferred taxbenefit resulting from reductions in Canadian federal and provincial tax rates,partially offset by Barnwell’s $825,000 Canadian deferred tax provisionresulting from changes in differences between Canadian assets and liabilitiesfor book purposes versus Canadian assets and liabilities for Canadian taxpurposes.  In November 2003, Royal Assentwas received on a bill passed by the Parliament of Canada, which was thenenacted into law, to reduce Canada’s corporate tax rate on “resource” income(income derived from oil and natural gas operations) over a four-year periodbeginning January 1, 2003 from 29% to 21% beginning January 1,2007.  Additionally, the bill phases inover the same four-year period tax deductions for royalties, which previouslywere not tax deductible, and phases out the Resource Allowance deduction alongwith other changes.  Accordingly, duringfiscal 2004, Barnwell’s Canadian net deferred income tax liabilities werereduced by approximately $1,440,000 due to the reduction in Canada’s federalcorporate tax rate.  Barnwell’s Canadiannet deferred income tax liabilities were also reduced by approximately $300,000in fiscal 2004 as a result of the Province of Alberta’s reduction of theprovince’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%, effectiveApril 1, 2004 (enacted into law in May 2004).

Areconciliation between the reported provision for income taxes and the amountcomputed by multiplying the earnings before income taxes by the U.S. federaltax 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 |   |

 

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Equityin earnings of real estate affiliate is shown net of income taxes in theConsolidated Statement of Operations for fiscal 2006.  The tax provision relating to equity inearnings of real estate affiliate was $545,000 in fiscal 2006, representing a38% effective tax rate.

Thetax effects of temporary differences that give rise to significant portions ofthe deferred tax assets and deferred tax liabilities at September 30, 2006 and2005 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 and2004, respectively, and increased $1,247,000 for the year endedSeptember 30, 2005. The change in the valuation allowance in fiscal 2006 relates primarilyto the abovementioned reduction of the valuation allowance previously placed onforeign tax credit carryforwards, partially offset by an increase in thevaluation allowance for the U.S. tax effect of deferred Canadian taxes.  The change in the valuation allowance infiscal 2005 was due to an increase in stock appreciation rights accruals for aCanadian employee for which it is more likely than not that such accruals willnot be utilized in the future to reduce Barnwell’s U.S. tax obligation.  The change in the valuation allowance infiscal 2004 was due to a decrease in foreign tax credit carryforwards as aresult of the expiration of a portion of the carryforwards.

Avaluation allowance is provided when it is more likely than not that someportion or all of the deferred tax asset will not be realized.  Barnwell has established a valuationallowance primarily for the U.S. tax effect of deferred Canadian taxes, accruedexpenses and state of Hawaii net operating loss carryforwards which may not berealizable in future years as there can be no assurance of any specific

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

Netdeferred 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 taxpurposes, $614,000 related to the excess of the cost basis of investment inland for tax purposes over the cost basis of investment in land for bookpurposes, and $1,522,000 for foreign tax credit carryforwards.  Canadian deferred tax assets related toexpenses accrued for book purposes but not for tax purposes are estimated to berealized through future Canadian income tax deductions against future Canadianoil and natural gas earnings.  U.S.deferred tax assets related to expenses accrued for book purposes but not fortax purposes and the excess of the cost basis of investment in land for taxpurposes over the cost basis of investment in land for book purposes areestimated to be realized from deductions against future U.S. earnings from landsale Percentage Payments, sales of interests in leasehold land, and sales ofland development rights.  Foreign taxcredit carryforwards are estimated to be utilized when U.S. federal incometaxes otherwise due on Canadian source income in a given year exceeds theforeign tax credit generated in that year. The foreign tax credit carryforward expires if not utilized on or beforeSeptember 30, 2011.  The amount ofdeferred income tax assets considered realizable may be reduced if estimates offuture taxable income are reduced.

**9.****                                      RETIREMENTPLANS**

Barnwellsponsors a noncontributory defined benefit pension plan covering substantiallyall of its U.S. employees, with benefits based on years of service and theemployee’s highest consecutive five-year average earnings.  Barnwell’s funding policy is intended toprovide for both benefits attributed to service to date and for those expectedto be earned in the future.  In addition,Barnwell sponsors a Supplemental Employee Retirement Plan (“SERP”), anoncontributory supplemental retirement benefit plan which covers certaincurrent and former employees of Barnwell for amounts exceeding the limitsallowed under the defined benefit pension plan. Barnwell recorded $95,000, $85,000 and $64,000 in expense associatedwith the SERP for the years ended September 30, 2006, 2005 and 2004,respectively.  The plan is unfunded andBarnwell will fund benefits when payments are made.  The total liability for the SERP was $499,000and $410,000 at September 30, 2006 and 2005, respectively.

Theoverall investment objective of the defined benefit pension plan is to providegrowth in the assets of the plan to fund future benefit obligations whilemanaging risk in order to meet current benefit obligations.  Generally, principal repayments and interestreceived on government mortgage securities provide cash flows to fund currentbenefit obligations.  Longer-termobligations are generally estimated to be provided for by growth in equitysecurities.  The plan assets atSeptember 30, 2006 were invested as follows: 1% in cash, 18% incertificates of deposit, 28% in debt securities, and 53% in equitysecurities.  The plan assets atSeptember 30, 2005 were invested as follows: 3% in cash, 3% in acertificate of deposit, 41% in debt securities, and 53% in equitysecurities.  Target asset allocations arenot used, and allocations are adjusted from time to time as dictated by currentand anticipated market conditions and required cash flows.

Barnwellcontributed $1,050,000 to the pension plan in fiscal 2006 resulting in aprepaid 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 asof September 30, 2006.  Fluctuations inactual equity market returns as well as changes in general interest

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rateswill result in changes in the market value of plan assets and may result inincreased or decreased retirement benefits costs and contributions in futureperiods.

Themeasurement date used to determine pension measures for the pension plan isSeptember 30.

Thefunded status of the pension plan and the amounts recognized in theconsolidated 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 accumulatedbenefit obligation for the pension plan was $2,992,000 and $2,978,000 atSeptember 30, 2006 and 2005, respectively. SFAS No. 132 requires the recognition of a minimum liability equalto the excess, if any, of the accumulated benefit obligation over plan assets.  At September 30, 2005, Barnwellrecognized an additional minimum liability of $132,000 as the accrued benefitcost was less than the minimum liability. The increase in the additional minimum liability during the year endedSeptember 30, 2005 was included in other comprehensive income; there wasno additional minimum liability as of September 30, 2006.

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

83

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| ** **                                                           | ** ** | **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 | % |

 

Todevelop the expected long-term rate of return on assets assumption, historicalreturns and the future expectations for returns for each asset class wereconsidered.
|   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 |   |

 

Barnwellestimates that it will contribute approximately $500,000 to the plan duringfiscal 2007.

InSeptember 2006, the FASB issued SFAS No. 158, “Employers’ Accounting forDefined Benefit Pension and Other Postretirement Plans – an amendment of FASBStatements No. 87, 88, 106 and 132(R).” SFAS No. 158 requires an employer to recognize the over-funded orunder-funded status

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

**10.****                               SHARE-BASEDPAYMENTS**

Barnwell hasoutstanding stock options issued to certain employees under both a qualifiedplan approved by shareholders (the 1998 Stock Option Plan) and non-qualifiedplans.  The qualified options weregranted with an exercise price equal to the market price of Barnwell’s stock onthe date of grant (110% of market price at date of grant for options granted toaffiliates), vest annually over four years of continuous service, and expireten years from the date of grant (five years from date of grant for optionsgranted to affiliates).  The qualifiedplan permits the grant of share options to employees for up to 780,000 sharesof common stock.  A total of 774,000share options have been granted under this plan, leaving 6,000 option sharesavailable for grant under the qualified plan at September 30, 2006.  The non-qualified options were granted withan exercise price equal to the market price of Barnwell’s stock on the date ofgrant, vest annually over five years of continuous service, and expire tenyears from the date of grant.  Thenon-qualified options have stock appreciation rights features that permit theholder to receive stock, cash or a combination thereof equal to the amount bywhich the fair market value, at the time of exercise of the option, exceeds theoption price.  Barnwell currently has apolicy of issuing new shares to satisfy share option exercises under thequalified plan and under the non-qualified plans when the optionee requestsshares.

Effective October1, 2005, Barnwell adopted the provisions of SFAS No. 123(R), “Share-BasedPayment,” for its share-based compensation plans.  Barnwell previously accounted for these plansunder the recognition and measurement principles of APB No. 25, “Accounting forStock Issued to Employees,” and related interpretations and disclosurerequirements established by SFAS No. 123, “Accounting for Stock-BasedCompensation,” as amended by SFAS No. 148, “Accounting for Stock-BasedCompensation – Transition and Disclosure.”

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

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of Operations.

Equity-classifiedAwards

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

A summary ofequity-classified share options as of the beginning and end of the year endedSeptember 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-classifiedAwards

The followingassumptions were used in estimating fair value for all liability-classifiedshare options previously granted prior to October 1, 2005 and outstandingduring the year ended September 30, 2006 (there were no options granted infiscal 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 rightsfeatures, is remeasured at each period-end using a closed-form valuation modelbased on current values and is recognized as an expense over the requisiteservice period.  Total share-basedcompensation expense for liability-classified awards was $439,000 for the yearended September 30, 2006.  Therelated income tax benefit was $146,000 for the year ended September 30,2006.  Included in share-basedcompensation expense for liability-classified awards for the year ended September 30,2006 was $740,000 of compensation expense related to shares that vested duringthe year and $301,000 of compensation benefit due to remeasurement at September 30,2006 of the fair value of previously vested shares.

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During the year ended September 30, 2006, an officer and an officer/directorexercised 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 theclosing prices per share on the days prior to the dates of exercise were paidto the officer and officer/director, respectively, in cash by Barnwell.  The actual tax benefits realized for the taxdeductions of these exercises were $406,000 and $171,000, respectively, for theyear ended September 30,2006.  There were no otherliability-classified share option grants, exercises, expirations, orforfeitures in the year ended September 30, 2006.

Asummary of liability-classified share options as of the beginning and end ofthe 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 |   |

 

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

Barnwelladopted SFAS No. 123(R) using the modified prospective method.  Under this transition method, compensationcost recognized in the year ended September 30, 2006 includes the cost forequity-classified share options vested during the period and all vestedliability-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 yearended 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-classifiedawards was not material to the consolidated financial statements.  Results for prior periods have not beenrestated.

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Thefollowing table illustrates the effect on net earnings and earnings per shareas if the fair-value recognition provisions of SFAS No. 123 were appliedto 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 |   |

 

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

InDecember 2004, 210,000 equity-classified option shares were granted at aweighted-average grant-date fair value of $2.18.  The total intrinsic value of equity optionsexercised during the year ended September 30, 2005 was $1,384,000; therewere no expirations or forfeitures of equity-classified options during the yearended September 30, 2005.

InDecember 2004, Barnwell granted stock options to certain officers/directors ofBarnwell to acquire 210,000 shares of Barnwell’s common stock under anon-qualified plan at a purchase price of $8.80 per share (market price on dateof grant).  These options have stockappreciation rights that

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permit the holder to receive stock, cash or a combinationthereof equal to the amount by which the fair market value, at the time ofexercise of the option, exceeds the option price.

InMarch 1995, Barnwell granted 120,000 stock options to an officer/director ofBarnwell under a non-qualified plan at a purchase price of $3.27 per share(market price on date of grant).  Theseoptions had stock appreciation rights that permitted the holder to receivestock, cash or a combination thereof equal to the amount by which the fairmarket value, at the time of exercise of the option, exceeds the optionprice.  During the year endedSeptember 30, 2004, the officer/director exercised the stock appreciationrights feature of 78,000 shares of these options and $310,000, representing thedifference between the exercise price and the closing prices per share on thedays prior to the dates of exercise was paid to this employee in cash byBarnwell.  During the year endedSeptember 30, 2005, the officer/director exercised the stock appreciationrights feature of 42,000 shares of these options and $463,000, representing thedifference between the exercise price and the closing price per share on theday prior to the date of exercise was paid to this officer/director in cash byBarnwell.  Barnwell recognized $275,000and $392,000 of compensation cost relating to these options in the years endedSeptember 30, 2005 and 2004, respectively.

InJune 1998, Barnwell granted 180,000 stock options to an officer of Barnwell’soil and gas segment under a non-qualified plan at a purchase price of $2.60 pershare (market price on date of grant). These options are fully vested and have stock appreciation rights thatpermit the holder to receive stock, cash or a combination thereof equal to theamount by which the fair market value, at the time of exercise of the option,exceeds the option price.  During theyear ended September 30, 2006, the officer exercised the stockappreciation rights feature on 60,000 shares of these options and thedifference between the exercise price and the closing price per share on theday prior to the date of exercise ($21.93 per share) was paid to this officerin cash by Barnwell.  The remaining120,000 options expire in May 2008. Barnwell recognized a compensation benefit of $359,000 relating to theseoptions in fiscal 2006 and $2,223,000 and $599,000 of compensation costs in theyears ended September 30, 2005 and 2004, respectively.

InDecember 1999, Barnwell granted qualified stock options to certain employees ofBarnwell to acquire 408,000 shares and 174,000 shares of Barnwell’s commonstock 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 inDecember 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 qualifiedstock options at exercise prices ranging from $1.98 to $2.18 per share.  No compensation cost was recognized for theseoptions for the years ended September 30, 2006, 2005 and 2004.

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

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

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$8.80 per share(market price on date of grant).  Theseoptions vest annually over five years commencing one year from the date ofgrant and expire in December 2014.  Theseoptions have stock appreciation rights that permit the holder to receive stock,cash or a combination thereof equal to the amount by which the fair marketvalue, 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 on30,000 shares of these options and the difference between the exercise priceand 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 $1,001,000of compensation costs relating to these options in the years endedSeptember 30, 2006 and 2005, respectively.

There were no forfeitures or expirationsof unexercised options in the years ended September 30, 2006, 2005 and2004.

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

**11.          COMMITMENTS AND CONTINGENCIES**

Barnwellhas committed to compensate its Vice President of Canadian Operations pursuantto an incentive compensation plan, the value of which directly relates toBarnwell’s oil and natural gas segment’s net income and the change in the valueof Barnwell’s oil and gas reserves since 1998 with adjustments for changes innatural 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 certainCanadian personnel pursuant to an incentive compensation plan, the value ofwhich directly relates to Barnwell’s oil and natural gas segment’s net incomeand the value of Barnwell’s oil and gas reserves discovered, commencing infiscal 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 and2004, respectively.

Barnwell has several non-cancelable operatingleases for office space and leasehold land. Rental expense was $528,000 in 2006, $481,000 in 2005, and $444,000 in2004.  Barnwell is committed under theseleases for minimum rental payments summarized by fiscal year as follows: 2007 -$571,000, 2008 - $502,000, 2009 - $437,000, 2010 - $437,000, 2011 - $430,000and thereafter through 2026 an aggregate of $1,685,000.  The lease payments for land were subject torenegotiation as of January 1, 2006. Per the lease agreement, the lease payments will remain unchangedpending an appraisal, whereupon the lease rent could be adjusted to fair marketvalue.  Barnwell does not know the amount of the newlease payments which could be effective upon performance of the appraisal; theymay remain unchanged or increase, and Barnwell currently expects the adjustment,if any, to not be material.  The futurerental payment disclosures above assume the minimum lease payments for land ineffect at December 31, 2005 remain unchanged through December 2025, theend of the lease term.

Barnwellis committed to pay commissions to Nearco, Inc. (“Nearco”), a companycontrolled by Mr. Terry Johnston, a director of Barnwell and an indirect 20.6%owner of Kaupulehu Developments.  Underan agreement entered into in 1987, prior to Mr. Johnston’s election to Barnwell’sBoard of Directors, Barnwell is obligated to pay Nearco 2% of KaupulehuDevelopments’

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grossreceipts from real estate transactions, and Cambridge Hawaii LimitedPartnership, a 49.9% partner of Kaupulehu Developments in which Barnwellpurchased a 55.2% interest in April 2001, is obligated under an agreemententered into in 1987 to pay Nearco 4% of Kaupulehu Developments’ gross receiptsfrom real estate transactions.  The feesrepresent compensation for promotion and marketing of Kaupulehu Developments’property and were determined based on the estimated fair value of suchservices.

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

Barnwellis occasionally involved in routine litigation and is subject to governmentaland regulatory controls that are incidental to the ordinary course ofbusiness.  Barnwell’s management believesthat all claims and litigation involving Barnwell are not likely to have amaterial adverse effect on its financial statements taken as a whole.

**12.          SEGMENT AND GEOGRAPHIC INFORMATION**

Barnwelloperates three segments: exploring for, developing, producing and selling oiland natural gas (oil and natural gas); investing in leasehold land in Hawaii(land investment); and drilling wells and installing and repairing waterpumping systems in Hawaii (contract drilling). Barnwell’s reportable segments are strategic business units that offerdifferent products and services.  Theyare managed separately as each segment requires different operational methods,operational assets and marketing strategies, and operate in differentgeographical locations.

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Barnwelldoes not allocate general and administrative expenses, interest expense,interest income or income taxes to segments, and there are no transactionsbetween segments that affect segment profit or loss. Other primarily relates togas 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 |   |

 

Depletionper 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 resultof increased costs of finding and developing proven reserves, as compared toprior years, as well as increases in the

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average exchangerate of the Canadian dollar to the U.S. dollar of 7% in fiscal 2006, ascompared 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)                Primarilylocated in the Province of Alberta, Canada.

(2)                Located in Hawaii.

LONG-LIVED ASSETS BYGEOGRAPHIC 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.          FAIRVALUE OF FINANCIAL INSTRUMENTS**

Thecarrying amounts of cash and cash equivalents, certificates of deposit,accounts receivable, and accounts payable approximate fair value because of theshort maturity of these instruments.  Thecarrying value of long-term debt approximates fair value as the termsapproximate current market terms for similar debt instruments of comparablerisk and maturities.

Thedifferences between the estimated fair values and carrying values of Barnwell’sfinancial instruments are not material.

93

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**14.          CONCENTRATIONS OF CREDIT RISK**

Barnwell’s oil and natural gas segment derived69% of its oil and natural gas revenues in fiscal 2006 from four individuallysignificant 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 itsoil and natural gas revenues from four individually significant customers.  In fiscal 2004Barnwell derived 53% of its oil and natural gas revenues from threeindividually significant customers.

Barnwell’scontract drilling subsidiary derived 37%, 63%, and 70% of its contract drillingrevenues in fiscal 2006, 2005, and 2004, respectively, pursuant to federal,State of Hawaii and county contracts.  AtSeptember 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 andpumps installed for federal, State of Hawaii, county and private entities.

Historically,Barnwell has not incurred significant credit related losses on its tradereceivables, and management does not believe significant credit risk related tothese trade receivables exists at September 30, 2006.

**15.          SUPPLEMENTAL STATEMENTS OF CASHFLOWS INFORMATION**

Thefollowing details the effect of changes in current assets and liabilities onthe Consolidated Statements of Cash Flows, and presents supplemental cash flowinformation:
| ** **                                                          | ** ** | **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 |   |

** **

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**16.          SUBSEQUENTEVENTS**

In November 2006, Kaupulehu Investors, LLC, alimited liability company wholly-owned by Barnwell, invested $3,000,000 in twounrelated limited liability companies to acquire a passive minority interest inHualalai Resort, located at Kaupulehu, North Kona, Hawaii, which includes theFour Seasons Resort Hualalai at Historic Ka’upulehu,two golf courses and undeveloped residential property.

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

95

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**17.          SUMMARY OF SELECTED QUARTERLYFINANCIAL DATA (UNAUDITED)**

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

Fiscal2006:
| ** **                             | ** ** | **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 reflectshare-based compensation expense as a result of the adoption of SFASNo. 123(R) on a prospective basis in the first quarter of fiscal year2006.  Accordingly, the quarterly resultsfor fiscal year 2005 do not reflect such expense.

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

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

96

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**18.          SUPPLEMENTARY OIL AND NATURAL GASINFORMATION (UNAUDITED)**

Thefollowing tables summarize information relative to Barnwell’s oil and naturalgas operations, which are substantially conducted in Canada.  Proved reserves are the estimated quantitiesof crude oil, condensate and natural gas which geological and engineering datademonstrate with reasonable certainty to be recoverable in future years fromknown reservoirs under existing economic and operating conditions.  Proved producing oil and natural gas reservesare reserves that can be expected to be recovered through existing wells withexisting equipment and operating methods. The estimated net interests in total proved and proved producingreserves are based upon subjective engineering judgments and may be affected bythe limitations inherent in such estimations. The process of estimating reserves is subject to continual revision asadditional 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 materiallyrevised in subsequent periods.

(A)          Oil and Natural Gas Reserves

Thefollowing table, based on information prepared by independent petroleumengineers, Paddock Lindstrom & Associates Ltd., summarizes changes in theestimates of Barnwell’s net interests in total proved reserves of crude oil andnatural gas liquids (“NGL”) and natural gas (“MCF” means 1,000 cubic feet ofnatural 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** | ** ** |

----

*                       Theseamounts represent proved undeveloped reserves at Dunvegan added by PaddockLindstrom & Associates, Ltd. based on a drilling program that commenced andwas completed in fiscal 2005.  As ofSeptember 30, 2006, 2005 and 2003, Paddock Lindstrom & Associates,Ltd. reported no proved undeveloped reserves at Dunvegan.

97

----

 
|                                                  | ** ** | **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)           CapitalizedCosts 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 |   |

 

(C)                                CostsIncurred in Oil and Natural Gas Property Acquisition, Exploration andDevelopment
| ** **                  | ** ** | **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)                               TheResults 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 |   |

----

*                       Beforegeneral and administrative expenses, interest expense, and foreign exchangegains and losses.

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(E)                                 StandardizedMeasure, Including Year-to-Year Changes Therein, of Estimated Discounted FutureNet Cash Flows

Thefollowing tables have been developed pursuant to procedures prescribed by SFASNo. 69, “Disclosures about Oil and Gas Producing Activities - an amendmentof FASB Statements 19, 25, 33, and 39,” and utilize reserve and production dataestimated by petroleum engineers.  Theinformation may be useful for certain comparison purposes but should not besolely relied upon in evaluating Barnwell or its performance.  Moreover, the projections should not beconstrued as realistic estimates of future cash flows, nor should thestandardized measure be viewed as representing current value.

Theestimated future cash flows are based on sales prices, costs, and statutoryincome tax rates in existence at the dates of the projections.  Material revisions to reserve estimates mayoccur in the future, development and production of the oil and natural gasreserves may not occur in the periods assumed and actual prices realized andactual costs incurred are expected to vary significantly from those used.  Management does not rely upon thisinformation in making investment and operating decisions; rather, thosedecisions are based upon a wide range of factors, including estimates ofprobable reserves as well as proved reserves and price and cost assumptionsdifferent than those reflected herein.

Standardized Measure ofEstimated 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 |   |

 

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Changes in theStandardized 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 |   |

Based on a natural gasspot 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 pricesincreased significantly subsequent to September 30, 2006, but prior to thefiling of this annual report, such that Barnwell’s full cost pool would nothave exceeded the ceiling limitation. The spot price of natural gas on December 18, 2006 wasapproximately $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 StaffAccounting Bulletin Topic 12D, Barnwell has not recorded an impairmentwrite-down of its oil and natural gas properties at September 30, 2006.

----

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

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**ITEM 9.****                            ****CHANGES IN AND DISAGREEMENTS WITHACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE**

None.

**ITEM 9A.****                   ****CONTROLS AND PROCEDURES**

Asof September 30, 2006, an evaluation was carried out by Barnwell’s ChiefExecutive Officer and Chief Financial Officer of the effectiveness of Barnwell’sdisclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and ChiefFinancial Officer have concluded that Barnwell’s disclosure controls andprocedures are effective to ensure that information required to be disclosed byBarnwell in reports that it files or submits under the Securities and ExchangeAct of 1934 is recorded, processed, summarized and reported within the timeperiods specified in the Securities and Exchange Act of 1934 and the rulesthereunder.  There was no change inBarnwell’s internal control over financial reporting during the quarter endedSeptember 30, 2006, that materially affected, or is reasonably likely tomaterially affect, Barnwell’s internal control over financial reporting.

**ITEM 9B.****                   ****OTHER INFORMATION**

None.

PART III

**ITEM 10.****                     ****DIRECTORS AND EXECUTIVE OFFICERSOF THE REGISTRANT**

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

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

**ITEM 11.****                     ****EXECUTIVE COMPENSATION**

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

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**ITEM 12.****                     ****SECURITY OWNERSHIP OF CERTAINBENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS**

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

**Equity Compensation Plan Information**

Thefollowing table provides information about Barnwell’s common stock that may beissued upon exercise of options and rights under all of Barnwell’s existingequity 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 plansnot approved by security holders are comprised of the following awards:

InJune 1998, Barnwell granted 180,000 stock options to an officer of Barnwell’soil and gas segment under a non-qualified plan at a purchase price of $2.60 pershare (market price on date of grant). These options are fully vested and have stock appreciation rights thatpermit the holder to receive stock, cash or a combination thereof equal to theamount by which the fair market value, at the time of exercise of the option,exceeds the option price.  During theyear ended September 30, 2006, the officer exercised the stockappreciation rights feature on 60,000 shares of these options.  The remaining 120,000 options expire in May2008.

InDecember 2004, Barnwell granted stock options to certain officers/directors ofBarnwell to acquire 210,000 shares of Barnwell’s common stock under anon-qualified plan at a purchase price of $8.80 per share (market price on dateof grant).  These options have stockappreciation rights that permit the holders to receive stock, cash or acombination thereof equal to the amount by which the fair market value, at thetime of exercise of the option, exceeds the option price.  These options vest annually over five yearscommencing 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 appreciationrights feature on 30,000 shares of these options.

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**ITEM 13.****                     ****CERTAIN RELATIONSHIPS AND RELATEDTRANSACTIONS**

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

**ITEM 14.****                     ****PRINCIPAL ACCOUNTING FEES ANDSERVICES**

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

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PART IV

**ITEM 15.****                     ****EXHIBITS AND FINANCIAL STATEMENTSCHEDULES**

(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 beenomitted because they were not applicable, not required, or the information isincluded 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 |

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(1)          Incorporatedby reference to the Registrant’s Form S-8 dated November 8, 1991.

(2)          Incorporatedby reference to the registration statement on Form S-1 originally filedby the Registrant January 29, 1957 and as amended February 15, 1957and February 19, 1957.

(3)          Incorporatedby reference to Form 10-K for the year ended September 30, 1989.

(4)          Incorporatedby reference to Form 10-K for the year ended September 30, 1992.

(5)          Incorporatedby reference to Form 10-KSB for the year ended September 30, 2000.

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SIGNATURES

Pursuantto the requirements of Section 13 or 15(d) of the Securities Act of 1934, theregistrant has duly caused this report to be signed on its behalf by theundersigned, 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 |   |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the registrant and inthe 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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