**U.S. SECURITIES ANDEXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

** **

**FORM 10-KSB**

 

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

 

**For the fiscal year ended September30, 2004**

 

| **o** | **TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934** |
|-------|-----------------------------------------------------------------------------------------|

 

**CommissionFile Number 1-5103**

 

**BARNWELL INDUSTRIES, INC.**

(Name of small businessissuer in its charter)

 

| **Delaware**                                                            |   | **72-0496921**                        |
|-------------------------------------------------------------------------|--------|---------------------------------------|
| (State or other  jurisdiction of incorporation or organization)         |   | (I.R.S. Employer  Identification No.) |
|                                                                    |   |                                  |
| **1100  Alakea Street, Suite 2900, Honolulu, Hawaii   96813-2833** |
| (Address of principal  executive offices)                               |   | (Zip code)                            |
|                                                                         |        |                                       |  |  |

 

**(808)531-8400**

(Issuer’s telephonenumber)

 

**Securities registered under Section 12(b) of the ExchangeAct:**

** **

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

** **

Securities registeredunder Section 12(g) of the Exchange Act: **None**

 

Check whether the issuer (1) filed all reports required to be filed by Section13 or 15(d) of the Exchange Act during the past 12 months (or for such shorterperiod that the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days.

 

| Yes | ý | No | o |   |
|-----|--------|----|---|--------|

 

Check if there is no disclosure of delinquent filers in response toItem 405 of Regulation S-B, and no disclosure will be contained, to the best ofregistrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-KSB or any amendment tothis Form 10-KSB.      o

 

Issuer’s revenues for the fiscal year ended September 30, 2004: **$37,970,000**

 

Theaggregate market value of the voting stock held by non-affiliates (687,097shares) of the Registrant on December 20, 2004, based on the closing priceof $63.79 on that date on the American Stock Exchange, was $43,830,000.

 

Asof December 20, 2004 there were 1,356,510 shares of common stock, par value$0.50, outstanding.

 

Documents Incorporated byReference

 

1.                                             Proxystatement to be forwarded to shareholders on or about January 20, 2005 isincorporated by reference in Part III hereof.

 

Transitional Small Business Disclosure Format                                         Yes  o   No  ý

 

 

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TABLE OF CONTENTS

 
| PART I   |                                      |
|----------|-------------------------------------------|
|     | Discussion of  Forward-Looking Statements |   |
|     | Item  1.                                  | Description  of Business |   |
|     |                                      |   | General Development of  Business |   |
|     |                                      |   | Financial  Information about Industry Segments |   |
|     |                                      |   | Narrative Description  of Business |   |
|     |                                      |   | Financial Information about  Foreign and Domestic Operations and Export Sales |   |
|     | Item  2.                                  | Description  of Property |   |
|     |                                      |  Oil and Natural  Gas Operations |   |
|     |                                      |   | General |   |
|     |                                      |   | Well Drilling Activities |   |
|     |                                      |   | Oil and Natural Gas  Production |   |
|     |                                      |   | Productive Wells |   |
|     |                                      |   | Developed  Acreage and Undeveloped Acreage |   |
|     |                                      |   | Reserves |   |
|     |                                      |   | Estimated Future Net  Revenues |   |
|     |                                      |   | Marketing of Oil and  Natural Gas |   |
|     |                                      |   | Governmental Regulation |   |
|     |                                      |   | Competition |   |
|     |                                      |  Contract Drilling  Operations |   |
|     |                                      |   | Activity |   |
|     |                                      |   | Competition |   |
|     |                                      |  Land Investment  Operations |   |
|     |                                      |   | Activity |   |
|     |                                      |   | Competition |   |
|     |                                      | Corporate Office |   |
|     | Item 3.                                   | Legal Proceedings |   |
|     | Item  4.                                  | Submission  of Matters to a Vote of Security Holders |   |
| PART II  |                                      |   |   |
|     | Item  5.                                  | Market  For Common Equity and Related Stockholder Matters |   |
|     | Item  6.                                  | Management’s  Discussion and Analysis or Plan of Operation |   |
|     |                                      |   | Results of Operations |   |
|     |                                      |   | Liquidity and Capital  Resources |   |
|     | Item 7.                                   | Financial Statements |   |
|     | Item  7A.                                 | Quantitative  and Qualitative Disclosures About Market Risk |   |
|     | Item  8.                                  | Changes  in and Disagreements with Accountants on Accounting and Financial Disclosure |   |
|     | Item 8A.                                  | Controls and  Procedures |   |
|     | Item 8B.                                  | Other Information |   |
| PART III |                                      |   |   |
|     | Item 9.                                   | Directors, Executive Officers,  Promoters and Control Persons, Compliance With Section 16(a) of the Exchange  Act |   |
|     | Item 10.                                  | Executive Compensation |   |
|     | Item  11.                                 | Security  Ownership of Certain Beneficial Owners and Management |   |
|     | Item  12.                                 | Certain  Relationships and Related Transactions |   |
|     | Item 13.                                  | Exhibits and Reports on Form 8-K |   |
|     | Item  14.                                 | Principal  Accountant Fees and Services |   |

 

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PART I

 

Forward-Looking Statements

 

This Form 10-KSB, and the documents incorporatedherein by reference, contain forward-looking statements within the meaning ofSection 27A of the Securities Act of 1933, as amended, and Section 21E of theSecurities Exchange Act of 1934, as amended, including various forecasts,projections of Barnwell Industries, Inc.’s (referred to herein together withits subsidiaries as “Barnwell”) future performance, statements of Barnwell’splans and objectives and other similar types of information.  Although Barnwell believes that itsexpectations are based on reasonable assumptions, it cannot assure that theexpectations contained in such forward-looking statements will beachieved.  Such statements involve risks,uncertainties and assumptions, including, but not limited to, those relating tothe factors discussed below, in other portions of this Form 10-KSB, in theNotes to Consolidated Financial Statements, and in other documents filed byBarnwell with the Securities and Exchange Commission from time to time, whichcould cause actual results to differ materially from those contained in suchstatements.  These forward-lookingstatements speak only as of the date of filing of this Form 10-KSB, andBarnwell expressly disclaims any obligation or undertaking to publicly releaseany updates or revisions to any forward-looking statements contained herein.

 

Barnwell’s oil and natural gas operations are affectedby domestic and international political, legislative, regulatory and legalactions.  Such actions may includechanges in the policies of the Organization of Petroleum Exporting Countries orother developments involving or affecting oil-producing countries, includingmilitary conflict, embargoes, internal instability or actions or reactions ofthe government of the United States in anticipation of or in response to suchdevelopments.  Domestic and internationaleconomic conditions, such as recessionary trends, inflation, interest costs,monetary exchange rates and labor costs, as well as changes in the availabilityand market prices of crude oil, natural gas and other petroleum products, mayalso have a significant effect on Barnwell’s oil and natural gasoperations.  While Barnwell maintainsreserves for anticipated liabilities and carries various levels of insurance,Barnwell could be affected by civil, criminal, regulatory or administrativeactions, claims or proceedings.  Inaddition, climate and weather can significantly affect Barnwell in several ofits operations.  Barnwell’s oil and gasoperations are also 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.  Costs of compliance withenvironmental laws are ingrained in Barnwell’s expenses and not distinguishedfrom other costs and expenses.

 

Barnwell’s land investment business segment isaffected by the condition of Hawaii’s real estate market.  The Hawaii real estate market is affected byHawaii’s economy in general and Hawaii’s tourism industry in particular.  Any future cash flows from Barnwell’s landdevelopment activities are subject to, among other factors, the level of realestate activity and prices, the demand for new housing and second homes on theIsland of Hawaii, the rate of increase in the cost of building materials andlabor, the introduction of building code modifications, changes to zoning laws,and the level of confidence in Hawaii’s economy.

 

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

 

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materially dependent upon levels of land development activity inHawaii.  Such activity levels areaffected by both short-term and long-term trends in Hawaii’s economy.  A decline in land development activity inHawaii could have a material adverse effect on Barnwell’s contract drillingrevenues and profitability.

 

Item 1.            Description of Business

(a)       GeneralDevelopment of Business

 

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

 

Barnwell’s oil and natural gas activities comprise itslargest business segment.  Approximately61% of Barnwell’s revenues for the fiscal year ended September 30,2004 were attributable to its oil and natural gas activities.  Barnwell’s land investment segment revenues,including land segment revenues reported as “Gas processing and other” revenuesin the Consolidated Statements of Operations, accounted for 27% of Barnwell’srevenues in fiscal 2004; contract drilling activities comprised 10% of fiscal2004 revenues; and other revenues comprised 2% of fiscal 2004 revenues.  Approximately 90% of Barnwell’s capitalexpenditures for the fiscal year ended September 30, 2004 were attributable tooil and natural gas activities and 10% were applicable to other activities.

 

(i)                Oil and Natural GasActivities. Barnwell’s wholly-owned subsidiary, Barnwell of Canada,Limited, is involved in the acquisition, exploration and development of oil andnatural gas properties, principally in Alberta, Canada.  Barnwell of Canada initiates and participatesin exploratory and developmental operations for oil and natural gas on propertyin which it has an interest, and evaluates proposals by third parties withregard to participation in such exploratory and developmental operationselsewhere.  Barnwell’s oil and naturalgas segment received 53% of its oil and natural gas revenues in fiscal 2004from three individually significant customers, ProGas Limited, Coral EnergyCanada Inc., and Plains Marketing Canada, L.P.

 

(ii)               Contract Drilling. Barnwell’swholly-owned subsidiary, Water Resources International, Inc., drills wells andinstalls and repairs water pumping systems in Hawaii.  Water Resources owns and operates four rotarydrill rigs, pump installation and service equipment, leases one rotarydrill/workover rig to an oil company, and maintains drilling materials and pumpinventory in Hawaii.  Water Resources’contracts are usually fixed price per lineal foot drilled or day rate contractsthat are either negotiated with private entities or are obtained throughcompetitive bidding with various private entities or local, state and federalagencies.  Barnwell’s contract drillingsubsidiary derived 70%, 66% and 70% of its contract drilling revenues in fiscal2004, 2003 and 2002, respectively, pursuant to Federal, State of Hawaii andcounty contracts.

 

(iii)          LandInvestment. Barnwell owns a 77.6% controlling interest in KaupulehuDevelopments, a Hawaii general partnership which owns interests in leaseholdland and development rights for property located approximately six miles northof the Kona International Airport in the North Kona District of the Island ofHawaii.  Between 1986 and 1989, KaupulehuDevelopments obtained the state and county zoning changes necessary to permitdevelopment of the Four Seasons Resort Hualalai at

 

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Historic Ka’upulehu and Hualalai Golf Club, which opened in 1996, asecond golf course, and single and multiple family residential units.  These projects were developed on leaseholdland acquired from Kaupulehu Developments by Kaupulehu Makai Venture, anunrelated entity that is an affiliate of Kajima Corporation of Japan.  Kaupulehu Developments later obtained thestate and county zoning changes necessary to permit development of single 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.

 

Kaupulehu Developments currently owns development rightsunder option; rights to receive percentage and interim payments on Increment Iof the approximately 870 leasehold acres; an interest in leasehold land zonedfor resort/residential development within Increment II of the approximately 870leasehold acres, which is under a right of negotiation; and approximately 1,000acres of vacant leasehold land zoned conservation.

 

(b)       Financial Information aboutIndustry Segments

 

Revenues of each industry segment for the fiscal yearsended September 30, 2004, 2003 and 2002 are summarized as follows (all revenueswere from unaffiliated customers with no intersegment sales or transfers):

 
| ** **             | ** ** | **2004**       | ** **     | **2003**   | ** ** | **2002**   | ** ** |
|------------------------|------------|----------------|----------------|------------|------------|------------|------------|
| Oil and natural  gas   | ** ** | **$**          | **23,270,000** | ** ** | **61**     | **%**      | $          | 19,350,000 |   | 82 | % | $ | 11,320,000 |   | 71 | % |
| Contract  drilling     | ** ** | **3,690,000**  | ** **     | **10**     | **%**      | 2,050,000  |       | 9 | % | 3,480,000 |   | 22 | % |
| Land investment        | ** ** | **10,077,000** | ** **     | **27**     | **%**      | 1,220,000  |       | 5 | % | 220,000 |   | 1 | % |
| Other                  | ** ** | **827,000**    | ** **     | **2**      | **%**      | 720,000    |       | 3 | % | 598,000 |   | 4 | % |
| Revenues from segments | ** ** | **37,864,000** | ** **     | **100**    | **%**      | 23,340,000 |       | 99 | % | 15,618,000 |   | 98 | % |
| Interest income        | ** ** | **106,000**    | ** **     | **0**      | **%**      | 340,000    |       | 1 | % | 262,000 |   | 2 | % |
| Total revenues         | ** ** | **$**          | **37,970,000** | ** ** | **100**    | **%**      | $          | 23,680,000 |   | 100 | % | $ | 15,880,000 |   | 100 | % |

 

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

 

(c)       NarrativeDescription of Business

 

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

 

Asof September 30, 2004, Barnwell employed 52 employees, 49 of which are on afull-time basis.  Twenty-five areemployed in contract drilling activities, 16 are employed in oil and naturalgas activities, and 11 are members of the corporate and administrative staff.

 

Forfurther discussion see the “Governmental Regulation” section and the “Competition”section in Item 2 hereof.

 

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(d)                     Financial Information about Foreign andDomestic Operations and Export Sales

 

Revenues and long-lived assets by geographic area forthe three years ended and as of September 30, 2004, 2003 and 2002 are setforth in Note 12 (SEGMENT AND GEOGRAPHIC INFORMATION) of “Notes to ConsolidatedFinancial Statements” in Item 7.

 

Item 2.            Description of Property

 

OIL AND NATURAL GAS OPERATIONS

 

General

 

Barnwell’s investments in oil and natural gasproperties consist of investments in Canada, principally in the Province ofAlberta, with minor holdings in Saskatchewan and British Columbia.  These property interests are principally heldunder governmental leases or licenses. Under the typical Canadian provincial governmental lease, Barnwell mustperform exploratory operations and comply with certain other conditions.  Lease terms vary with each province, but, ingeneral, the terms grant Barnwell the right to remove oil, natural gas andrelated substances subject to payment of specified royalties on production.

 

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 independent consultants as necessary.  In fiscal 2004, Barnwell participated inexploratory and developmental operations in the Canadian Provinces of Albertaand Saskatchewan, although Barnwell does not limit its consideration ofexploratory and developmental operations to these areas.

 

Barnwell’s producing natural gas properties arelocated principally in Alberta.  A smallnumber of producing properties are located in British Columbia andSaskatchewan.  The Province of Albertadetermines its royalty share of natural gas by using a reference price thataverages all natural gas sales in Alberta. Royalty rates are calculated on a sliding scale basis, increasing asprices increase.  Additionally, Barnwellpays gross overriding royalties on a portion of its natural gas sales to otherparties.

 

Infiscal 2004, the weighted average rate of all royalties paid to governments andothers on natural gas from the Dunvegan Unit, Barnwell’s principal oil andnatural gas property, before the Alberta Royalty Tax Credit, was approximately30%.  The weighted average rate ofroyalties paid on all of Barnwell’s natural gas was approximately 27% in fiscal2004, versus approximately 28% in fiscal 2003.

 

Infiscal 2004, virtually all of Barnwell’s oil production was from propertieslocated in Alberta.  The Province ofAlberta determines its royalty share of oil by using a reference price thataverages all oil sales in Alberta. Royalty rates are calculated on a sliding scale basis, increasing asprices increase.  Additionally, Barnwellpays gross overriding royalties and leasehold royalties on a portion of its oilsales to parties other than the Province of Alberta.  In fiscal 2004 and 2003, the weightedaverage royalty rate paid on oil was approximately 22% and 24%,respectively.  The decrease in theweighted average royalty rate on oil was primarily due to lower royalty rateson new oil production.

 

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Prices of natural gas are typically higher in thewinter than at other times due to demand for heating.  Prices of oil are also subject to seasonalfluctuations, but to a lesser degree. Unit sales of oil and natural gas are based on the quantity producedfrom the properties by the operator based on sound petroleum practices andapplicable rules and regulations.  Duringperiods of low demand for natural gas, the operator of the Dunvegan propertymay re-inject natural gas into underground storage facilities for delivery at afuture date.

 

Well DrillingActivities

 

Duringfiscal 2004, Barnwell participated in the drilling of 128 gross developmentwells and 16 gross exploratory wells, of which management believes 134should be capable of production. Barnwell also participated in the recompletion of 33 gross wells (4.6net wells).  The most significantdrilling operations took place in the Dunvegan, Bonanza/Balsam, Doris, WoodRiver, Progress, and Armada areas.

 

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, 2004, 2003, and 2002 in which Barnwell participated:

 
| ** ** | ** ** | **Productive  Oil Wells** | ** ** | **Productive  Gas Wells** | ** **    | **Total Productive  Wells** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------|------------|---------------------------|------------|---------------------------|---------------|-----------------------------|-----------------|------------|------------|------------|------------|------------|------------|------------|------------|
| ** ** | ** ** | ** **                | ** ** | ** **                | **Dry Holes** | ** **                  | **Total Wells** | ** ** |
| ** ** | ** ** | **Exp.**                  | ** ** | **Dev.**                  | ** **    | **Exp.**                    | ** **      | **Dev.**   | ** ** | **Exp.**   | ** ** | **Dev.**   | ** ** | **Exp.**   | ** ** | **Dev.** | ** ** | **Exp.** | ** ** | **Dev.** | ** ** |
| **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** | ** ** |
|       |       |                      |       |                      |          |                        |            |       |       |       |       |       |       |       |       |   |   |   |   |   |   |
| 2003       |       |                      |       |                      |          |                        |            |       |       |       |       |       |       |       |       |   |   |   |   |   |   |
| Gross*     |       | —                    |       | 5.0                       |          | 8.0                         |            | 40.0       |       | 8.0        |       | 45.0       |       | 5.0        |       | 7.0 |   | 13.0 |   | 52.0 |   |
| Net*       |       | —                    |       | 1.5                       |          | 2.1                         |            | 7.5        |       | 2.1        |       | 9.0        |       | 1.5        |       | 2.1 |   | 3.6 |   | 11.1 |   |
|       |       |                      |       |                      |          |                        |            |       |       |       |       |       |       |       |       |   |   |   |   |   |   |
| 2002       |       |                      |       |                      |          |                        |            |       |       |       |       |       |       |       |       |   |   |   |   |   |   |
| Gross*     |       | 3.0                       |       | 3.0                       |          | 1.0                         |            | 5.0        |       | 4.0        |       | 8.0        |       | 1.0        |       | 3.0 |   | 5.0 |   | 11.0 |   |
| Net*       |       | 0.6                       |       | 1.1                       |          | 0.2                         |            | 2.3        |       | 0.8        |       | 3.4        |       | 0.1        |       | 1.1 |   | 0.9 |   | 4.5 |   |

 

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

 

The Dunvegan Unit, in which Barnwell holds an 8.9%interest, is Barnwell’s principal oil and natural gas property and is locatedin Alberta, Canada.  At September 30,2004, the Dunvegan Unit had 148 natural gas wells producing from 148 wellzones.  In fiscal 2004, Barnwellparticipated in the drilling of 27 gross (2.4 net) development gas wells, ofwhich 24 gross (2.1 net) wells were successful, and recompletion of 11 gaswells (1.0 net wells) in the Dunvegan area. These new wells added proved reserves and are expected to increase therate of future production from the area. Total capital expenditures at Dunvegan were $3,670,000 in fiscal 2004 ascompared to $1,223,000 and $325,000 in fiscal 2003 and 2002, respectively.

 

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Capitalexpenditures totaled $1,740,000 in the Bonanza/Balsam area, where five grosswells (2.2 net wells) were drilled in fiscal 2004, as compared to $1,552,000 infiscal 2003.  Two gross wells (0.7 netwells) were successful and tied in and producing at September 30, 2004, andthree gross wells (1.5 net wells) were unsuccessful.

 

In the Doris area, where capital expenditures totaled$735,000 in fiscal 2004, Barnwell drilled three gross wells (1.5 netwells).  One of the wells (0.5 net well)was successful, one (0.5 net well) was unsuccessful, and one (0.5 net well)initially flowed commercial quantities of gas, but additional work is requiredon the well before it can be determined to be a successful well.

 

In the Wood River area, where capital expenditurestotaled $615,000 in fiscal 2004, Barnwell drilled four gross wells (0.4 netwells).  Three gross wells (0.2 net well)are estimated to be successful, and one well (0.2 net well) was tied in and producing at September 30, 2004.

 

In the Progress area, where capital expenditurestotaled $550,000 in fiscal 2004, one unsuccessful well (0.5 net well) wasdrilled and one gross well (0.3 net well) was a successful oil well.

 

In the Armada area, where capital expenditures totaled$320,000 in fiscal 2004, eight successful gross wells (1.8 net wells) weredrilled, seven of which were producing at September 30, 2004.

 

Barnwell’saverage net interest in wells drilled in fiscal 2004 was approximately 10%, ascompared to 23% in fiscal 2003 and 34% in fiscal 2002.  The decrease in fiscal 2004, as compared tofiscal 2003, was due principally to drilling programs at Dunvegan, 27 gross(2.4 net) wells, and Hilda, 81 gross (2.7 net) wells, for a total of 108 gross(5.1 net) wells or an average net well interest of 5% for these two drillingprograms.  The average net interest inall other wells drilled in fiscal 2004 was 26%. Of the wells drilled in fiscal 2004, 20 gross wells (7.9 net wells) wereon prospects developed by Barnwell.

 

Oil and Natural Gas Production

 

The following table summarizes (a) Barnwell’s net unitproduction for the last three fiscal years, based on sales of crude oil,natural gas, condensate and other natural gas liquids, from all wells in whichBarnwell has or had an interest, and (b) the average sales prices and averageproduction costs for such production during the same periods.  Production amounts reported are net ofroyalties and the Alberta Royalty Tax Credit. Barnwell’s net production in fiscal 2004, 2003, and 2002 was derivedprimarily from the Province of Alberta. All dollar amounts in this table are in U.S. dollars.

 

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| ** **                                           | ** ** | **Year Ended September 30,** | ** ** |
|------------------------------------------------------|------------|------------------------------|------------|
| ** **                                           | ** ** | **2004**                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| Annual net  production:                              |       |                         |       |   |   |   |   |
| Natural gas  liquids (BBLS)*                         | ** ** | **105,000**                  |       | 85,000 |   | 94,000 |   |
| Oil (BBLS)*                                          | ** ** | **154,000**                  |       | 142,000 |   | 148,000 |   |
| Natural gas  (MCF)*                                  | ** ** | **3,383,000**                |       | 3,175,000 |   | 3,277,000 |   |
|                                                 |       |                         |       |   |   |   |   |
| Annual average  sale price per unit of production:   |       |                         |       |   |   |   |   |
| BBL of liquids**                                     | ** ** | **$**                        | **24.18**  |   | $ | 21.50 |   | $ | 12.46 |   |
| BBL of oil**                                         | ** ** | **$**                        | **33.24**  |   | $ | 27.69 |   | $ | 21.28 |   |
| MCF of natural  gas**                                | ** ** | **$**                        | **4.60**   |   | $ | 4.27 |   | $ | 2.12 |   |
|                                                 |       |                         |       |   |   |   |   |
| Annual average  production cost per MCFE produced*** | ** ** | **$**                        | **1.11**   |   | $ | 0.93 |   | $ | 0.66 |   |
|                                                 |       |                         |       |   |   |   |   |
| Annual average  depletion cost per MCFE produced***  | ** ** | **$**                        | **1.31**   |   | $ | 0.90 |   | $ | 0.71 |   |

 

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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 royalty tax credit divided by grossproduction.

***                           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 2004, approximately 67%, 22% and 11% of Barnwell’s oil and natural gasrevenues were from the sale of natural gas, oil and natural gas liquids,respectively.

 

Infiscal 2004, Barnwell’s net production after royalties for natural gas averaged9,240 MCF per day, an increase of 6% from 8,700 MCF per day in fiscal2003.  Gross natural gas production alsoincreased 6% in fiscal 2004, as compared to fiscal 2003.  Dunvegan contributed approximately 44% ofBarnwell’s net natural gas production in fiscal 2004, an increase from 43% infiscal 2003.

 

Barnwell’smajor oil producing properties are the Red Earth, Chauvin and Bonanza areas inCanada.  In fiscal 2004, net productionafter royalties for oil averaged 420 barrels per day, an increase of 8% from390 barrels per day in fiscal 2003.  Thisincrease was due to new production from the Bonanza and Wizard Lake areas,partially offset by decreases in production at certain older properties.

 

Infiscal 2004, net production after royalties for natural gas liquids averaged290 barrels per day, an increase of 26% from 230 barrels per day in fiscal2003.  This increase was due to increasedproduction from the Dunvegan area and to a fire in early October 2002 at aDunvegan gas plant that prevented stripping of natural gas liquids from thenatural gas, resulting in an approximately 6,000 barrel decline in liquids netproduction in fiscal 2003.

 

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Theaverage production cost per MCFE was $1.11 for fiscal 2004, a 19% increase from$0.93 for fiscal 2003.  The increase wasdue to the addition of new properties, costs incurred to re-enter wells forrepair, maintenance and cleaning, and inflationary pressures on oil fieldservice costs.  Also contributing to theincrease was a 10% increase in the average exchange rate of the Canadian dollarto the U.S. dollar which increased the average production cost per MCFE by$0.10 in fiscal 2004, as compared to fiscal 2003.

 

Theaverage depletion cost per MCFE was $1.31 for fiscal 2004, a 46% increase from$0.90 for fiscal 2003.  The increase isthe result of increased costs of finding and developing proven reserves, ascompared to prior years, and a 10% increase in the average exchange rate of theCanadian dollar to the U.S. dollar which increased the average depletion costper MCFE by $0.12 in fiscal 2004, as compared to fiscal 2003.

 

Infiscal 2003, approximately 71%, 20% and 9% of Barnwell’s oil and natural gasrevenues were from the sale of natural gas, oil and natural gas liquids,respectively.

 

Infiscal 2003, Barnwell’s net production after royalties for natural gas averaged8,700 MCF per day, a decrease of 3% from 8,980 MCF per day in fiscal 2002.  Gross natural gas production remainedconstant, while, on a net basis, natural gas production decreased due to anincrease in royalty rates attributable to increased natural gas prices.  Dunvegan contributed approximately 43% ofBarnwell’s net natural gas production in fiscal 2003.

 

Infiscal 2003, net production after royalties for oil averaged 390 barrels perday, a decrease of 3% from 400 barrels per day in fiscal 2002.  This decrease was due to natural declines inproduction from certain of Barnwell’s older oil properties, which was partiallyoffset by new production at Wizard Lake, Bonanza and Boundary Lake.

 

Infiscal 2003, net production after royalties for natural gas liquids averaged230 barrels per day, a decrease of 12% from 260 barrels per day in fiscal2002.  This decrease was due primarily toa fire in early October 2002 at a Dunvegan gas plant that prevented strippingof natural gas liquids from the natural gas, resulting in an approximately6,000 barrel decline in liquids net production in fiscal 2003.  Barnwell did, however, receive a higher pricefor its natural gas than it would have if the liquids had been removed, therebymitigating some of the impact of the liquids production decline.  The damage to the gas plant was repaired andthe plant resumed operations in late December 2002.

 

Theaverage production cost per MCFE was $0.93 for fiscal 2003, a 41% increase from$0.66 for fiscal 2002.  The increase isdue partly to an oil and natural gas operating expense credit for overchargesof operating expenses for fiscal years 1998 through 2001 from the operator ofthe Dunvegan property totaling $470,000 which was received in fiscal 2002.  The increase was also attributable to higherwell repair and maintenance, electricity, fuel, insurance, and generalmaintenance costs.

 

10

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Thefollowing table sets forth the gross and net number of productive wellsBarnwell has an interest in as of September 30, 2004.

 

Productive Wells

 
| ** **       | ** ** | **Productive Wells*** | ** ** |
|------------------|------------|-----------------------|------------|
| ** **       | ** ** | **Gross****           | ** ** | **Net**** | ** ** |
| **Location**     | ** ** | **Oil**               | ** ** | **Gas** | ** ** | **Oil** | ** ** | **Gas** | ** ** |
| Canada           |       |                  |       |   |   |   |   |   |   |
| Alberta          |       | 133                   |       | 553 |   | 23.4 |   | 53.3 |   |
| Saskatchewan     |       | 6                     |       | 31 |   | 0.3 |   | 6.4 |   |
| British Columbia |       | 1                     |       | — |   | 0.3 |   | — |   |
| Total            |       | 140                   |       | 584 |   | 24.0 |   | 59.7 |   |

 

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*                                         Eleven grossnatural gas wells have dual or multiple completions and six gross oil wellshave dual completions.

**                                  Pleasesee note (2) on the following table.

 

Developed Acreage and Undeveloped Acreage

 

The following table sets forth certain informationwith respect to oil and natural gas properties of Barnwell as of September 30,2004:

 
| ** **       | ** ** | ** **     | ** ** | ** **      | ** ** | ** **      | ** ** | ** ** | ** ** | **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          |       | 254,589        |       | 38,272          |       | 178,745         |       | 64,001     |       | 433,334           |       | 102,273 |   |
| British Columbia |       | 1,753          |       | 555             |       | 4,401           |       | 1,653      |       | 6,154             |       | 2,208 |   |
| Saskatchewan     |       | 3,336          |       | 530             |       | —          |       | —     |       | 3,336             |       | 530 |   |
| Total            |       | 259,678        |       | 39,357          |       | 183,146         |       | 65,654     |       | 442,824           |       | 105,011 |   |

 

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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 2005; 8% expireduring fiscal 2006; 9% expire during fiscal 2007; 18% expire during fiscal2008; 40% expire during fiscal 2009; and 3% expire during fiscal 2010.  Fifteen percent of Barnwell’s undevelopedacreage is not subject to expiration because they are

 

11

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relatedto heavy oil and other areas where leases are allowed to continue indefinitelywithout having a well on the acreage. There can be no assurance that Barnwell will be successful in renewingits leasehold interests in the event of expiration.

 

Barnwell’s undeveloped acreage includes majorconcentrations in Alberta, at Thornbury (5,584 net acres), Swalwell (4,045 netacres), Boundary Lake (3,880 net acres), Mulligan (3,380 net acres),Bonanza/Balsam (3,240 net acres), Paddle River (3,200 net acres), Red Earth(2,339 net acres), Doris (2,304 net acres), Pouce Coupe South (1,920 netacres), and Gere (1,507 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, 2004, 2003, and 2002 on all properties in whichBarnwell has an interest.  These reservesare before deductions for indebtedness secured by the properties and are basedon constant dollars.  No estimates oftotal proved net oil or natural gas reserves have been filed with or includedin reports to any federal authority or agency since October 1, 2001.

 

Proved Producing Reserves

 
| ** **                                            | ** ** | **September 30,** | ** ** |
|-------------------------------------------------------|------------|-------------------|------------|
| ** **                                            | ** ** | **2004**          | ** ** | **2003** | ** ** | **2002** | ** ** |
| Oil - barrels  (BBLS) (including natural gas liquids) | ** ** | **1,135,000**     |       | 1,262,000 |   | 1,303,000 |   |
| Natural gas –  thousand cubic feet (MCF)         | ** ** | **21,614,000**    |       | 21,463,000 |   | 19,612,000 |   |

 

Total Proved Reserves

  (Includes Proved Producing Reserves)

 
| ** **                                            | ** ** | **September 30,** | ** ** |
|-------------------------------------------------------|------------|-------------------|------------|
| ** **                                            | ** ** | **2004**          | ** ** | **2003** | ** ** | **2002** | ** ** |
| Oil - barrels  (BBLS) (including natural gas liquids) | ** ** | **1,304,000**     |       | 1,401,000 |   | 1,527,000 |   |
| Natural gas –  thousand cubic feet (MCF)         | ** ** | **26,825,000**    |       | 27,639,000 |   | 27,166,000 |   |

 

As of September 30, 2004, essentially all of Barnwell’sproved producing and total proved reserves were located in the Province ofAlberta, with minor volumes located in the Provinces of Saskatchewan andBritish Columbia.

 

Duringfiscal 2004, Barnwell’s total net proved reserves, including proved producingreserves, of oil, condensate and natural gas liquids decreased by 97,000barrels, and total net proved reserves of natural gas decreased by 814,000 MCF.

 

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Thechange in oil, condensate and natural gas liquids reserves was the net resultof production during the year of 259,000 barrels, the addition of 115,000barrels from the drilling of productive wells, the addition of 54,000undeveloped barrels from the planned drilling of wells at Dunvegan in fiscal2005, and the independent engineer’s 7,000 barrel downward revision of Barnwell’soil reserves.

 

Thechange in natural gas reserves was the net result of production during the yearof 3,383,000 MCF, the addition of 2,127,000 MCF from the drilling of productivenatural gas wells, the addition of 1,571,000 undeveloped MCF from the planneddrilling of wells at Dunvegan in fiscal 2005, and the independent engineer’s1,129,000 MCF downward revision of Barnwell’s natural gas reserves.  543,000 MCF of the independent engineer’sdownward revision was due to newly enacted regulations restricting theproduction of natural gas at Thornbury due to its possible negative impact onthe future production of heavy oil in the area.

 

Barnwell’s working interest in the Dunvegan areaaccounted for approximately 60% and 58% of its total proved natural gasreserves at September 30, 2004 and 2003, respectively, and approximately 40% oftotal proved oil and natural gas liquids reserves at September 30, 2004 and2003.

 

Thefollowing table sets forth Barnwell’s oil and natural gas reserves at September30, 2004, by property name, based on information prepared by Paddock Lindstrom& Associates Ltd.  Gross reserves arebefore the deduction of royalties; net reserves are after the deduction ofroyalties net of the Alberta Royalty Tax Credit.  This table is based on constant dollars wherereserve estimates are based on sales prices, costs and statutory tax rates inexistence at the date of the projection. Oil, which includes natural gas liquids, is shown in thousands ofbarrels (“MBBLS”) and natural gas is shown in millions of cubic feet (“MMCF”).

 

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OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30,2004

 
| ** **                       | ** ** | **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**                     | ** ** | **620**                    | ** ** | **446**          | ** ** | **16,429** | ** ** | **13,796** | ** ** | **729** | ** ** | **524** | ** ** | **19,408** | ** ** | **15,975** | ** ** |
| Red Earth                        |       | 375                        |       | 330              |       | — |   | — |   | 389 |   | 340 |   | — |   | — |   |
| Bonanza/Balsam                   |       | 77                         |       | 65               |       | 747 |   | 587 |   | 136 |   | 110 |   | 1,305 |   | 1,019 |   |
| Pouce Coupe  South               |       | 5                          |       | 3                |       | 1,104 |   | 849 |   | 11 |   | 7 |   | 1,720 |   | 1,247 |   |
| Medicine River                   |       | 48                         |       | 33               |       | 1,078 |   | 737 |   | 48 |   | 33 |   | 1,078 |   | 737 |   |
| Doris                            |       | 5                          |       | 3                |       | 1,136 |   | 906 |   | 5 |   | 3 |   | 1,136 |   | 906 |   |
| Leduc                            |       | 9                          |       | 6                |       | 574 |   | 450 |   | 16 |   | 11 |   | 1,013 |   | 800 |   |
| Faith South                      |       | —                     |       | —           |       | — |   | — |   | — |   | — |   | 1,011 |   | 802 |   |
| Hillsdown                        |       | 14                         |       | 11               |       | 631 |   | 497 |   | 30 |   | 23 |   | 797 |   | 629 |   |
| Chauvin                          |       | 128                        |       | 107              |       | 14 |   | 12 |   | 128 |   | 107 |   | 14 |   | 12 |   |
| Wood River                       |       | 4                          |       | 4                |       | 263 |   | 224 |   | 4 |   | 4 |   | 682 |   | 572 |   |
| Progress                         |       | 8                          |       | 5                |       | 597 |   | 469 |   | 22 |   | 19 |   | 613 |   | 482 |   |
| Thornbury                        |       | —                     |       | —           |       | 519 |   | 450 |   | — |   | — |   | 565 |   | 491 |   |
| Charlotte Lake                   |       | —                     |       | —           |       | 284 |   | 262 |   | — |   | — |   | 504 |   | 452 |   |
| Pouce Coupe                      |       | 9                          |       | 7                |       | 501 |   | 410 |   | 9 |   | 7 |   | 501 |   | 410 |   |
| Rat Creek                        |       | 32                         |       | 25               |       | 292 |   | 243 |   | 32 |   | 25 |   | 292 |   | 243 |   |
| Hilda                            |       | —                     |       | —           |       | 279 |   | 265 |   | — |   | — |   | 279 |   | 265 |   |
| Zama                             |       | 1                          |       | —           |       | 119 |   | 79 |   | 1 |   | 1 |   | 363 |   | 245 |   |
| Mulligan                         |       | 3                          |       | 2                |       | 279 |   | 227 |   | 3 |   | 2 |   | 279 |   | 227 |   |
| Barrhead                         |       | 8                          |       | 7                |       | 216 |   | 195 |   | 8 |   | 7 |   | 216 |   | 195 |   |
| Wizard Lake                      |       | 35                         |       | 28               |       | — |   | — |   | 35 |   | 28 |   | — |   | — |   |
| Armada                           |       | —                     |       | —           |       | 168 |   | 157 |   | — |   | — |   | 168 |   | 157 |   |
| Pine Creek                       |       | 8                          |       | 5                |       | 146 |   | 110 |   | 8 |   | 5 |   | 146 |   | 110 |   |
| Chigwell                         |       | —                     |       | —           |       | 70 |   | 60 |   | — |   | — |   | 141 |   | 121 |   |
| Clive                            |       | —                     |       | —           |       | 41 |   | 36 |   | — |   | — |   | 116 |   | 105 |   |
| Manyberries                      |       | 17                         |       | 15               |       | 4 |   | 2 |   | 17 |   | 15 |   | 4 |   | 2 |   |
| Gilby                            |       | 4                          |       | 3                |       | 76 |   | 67 |   | 4 |   | 3 |   | 76 |   | 67 |   |
| Smaller Alberta  properties      |       | 10                         |       | 9                |       | 210 |   | 179 |   | 10 |   | 9 |   | 218 |   | 185 |   |
| Boundary Lake,  British Columbia |       | 20                         |       | 19               |       | 227 |   | 211 |   | 20 |   | 19 |   | 227 |   | 211 |   |
| Hatton,  Saskatchewan            |       | —                     |       | —           |       | 191 |   | 134 |   | — |   | — |   | 226 |   | 158 |   |
| Webb-Beverley,  Saskatchewan     |       | 2                          |       | 2                |       | — |   | — |   | 2 |   | 2 |   | — |   | — |   |
| **TOTAL**                        | ** ** | **1,442**                  | ** ** | **1,135**        | ** ** | **26,195** | ** ** | **21,614** | ** ** | **1,667** | ** ** | **1,304** | ** ** | **33,098** | ** ** | **26,825** | ** ** |

 

Properties are located in Alberta, Canada unlessotherwise noted.

 

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Estimated Future Net Revenues

 

The following table sets forth Barnwell’s “EstimatedFuture Net Revenues” from total proved oil, natural gas and condensate reservesand the present value of Barnwell’s “Estimated Future Net Revenues” (discountedat 10%).  Estimated future net revenuesfor total proved reserves are net of estimated development costs.  Net revenues have been calculated usingcurrent sales prices and costs, after deducting all royalties net of theAlberta Royalty Tax Credit, operating costs, future estimated capitalexpenditures, and income taxes.

 
| ** **                                               | ** ** | **Proved Producing  Reserves** | ** ** | **Total Proved  Reserves** | ** ** |
|----------------------------------------------------------|------------|--------------------------------|------------|----------------------------|------------|
| Year ending  September 30,                               |       |                           |       |                       |       |
|                                                     |       |                           |       |                       |       |
| 2005                                                     |       | 12,575,000                     |       | 14,147,000                 |       |
| 2006                                                     |       | 10,748,000                     |       | 14,708,000                 |       |
| 2007                                                     |       | 9,134,000                      |       | 11,417,000                 |       |
| Thereafter                                               |       | 40,643,000                     |       | 48,010,000                 |       |
|                                                     |       | $                              | 73,100,000 |                       | $          | 88,282,000 |   |
|                                                     |       |                           |       |                       |       |
| Present value  (discounted at 10%) at September 30, 2004 |       | $                              | 50,517,000 |                       | $          | 61,010,000 |   |

 

Marketing of Oil and Natural Gas

 

Barnwell sells substantially all of its oil andcondensate production under short-term contracts between itself and marketersof oil.  The price of oil is freelynegotiated between the buyers and sellers.

 

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.  In 2004,2003, and 2002, Barnwell took virtually all of its oil and natural gas “in kind”where Barnwell markets the products instead of having the operator of aproducing property market the products on Barnwell’s behalf.

 

Infiscal 2004, natural gas production from the Dunvegan Unit was responsible forapproximately 42% of Barnwell’s natural gas revenues, as compared to 41% infiscal 2003.  In fiscal 2004, Barnwellhad three individually significant customers that accounted for 53% of Barnwell’soil and natural 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 finalpurchasers.  In fiscal 2004, Barnwellcontinued its strategy to increase the volumes of natural gas sold into spotmarkets, reaching approximately 49% of natural gas volumes, to take advantageof new pipeline access to premium markets and higher prices.

 

GovernmentalRegulation

 

The jurisdictions in which the oil and natural gasproperties of Barnwell are located have regulatory provisions relating topermits for the drilling of wells, the spacing of wells, the prevention of

 

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oil and natural gas waste, allowable rates of production and othermatters.  The amount of oil and naturalgas produced is subject to control by regulatory agencies in each province andstate that periodically assign allowable rates of production.  The Province of Alberta and Government ofCanada also monitor and regulate the volume of natural gas that may be removedfrom the province and the conditions of removal.

 

There is no current government regulation of the pricethat may be charged on the sale of Canadian oil or natural gas production.  Canadian natural gas production destined forexport is priced by market forces subject to export contracts meeting certaincriteria prescribed by Canada’s National Energy Board and the Government ofCanada.

 

The right to explore for and develop oil and naturalgas on lands in Alberta, Saskatchewan and British Columbia is controlled by thegovernments of each of those provinces. Changes in royalties and other terms of provincial leases, permits andreservations may have a substantial effect on Barnwell’s operations.  In addition to the foregoing, in the future,Barnwell’s Canadian operations may be affected from time to time by politicaldevelopments in Canada and by Canadian Federal, provincial and local laws andregulations, such as restrictions on production and export, oil and natural gasallocation and rationing, price controls, tax increases, expropriation ofproperty, modification or cancellation of contract rights, and environmentalprotection controls.  Furthermore,operations may also be affected by United States import fees and restrictions.

 

Different royalty rates are imposed by the provincialgovernments, the Government of Canada and private interests with respect to theproduction and sale of crude oil, natural gas and liquids.  In addition, provincial governments receiveadditional revenue through the imposition of taxes on crude oil and natural gasowned by private interests within the province.  Essentially, provincial royalties arecalculated as a percentage of revenue, and vary depending on productionvolumes, selling prices and the date of discovery.

 

In 2002, Canadian taxpayers were not permitted todeduct royalties, taxes, rentals and similar levies paid to the Federal orprovincial governments in connection with oil and natural gas production incomputing income for purposes of Canadian Federal income tax.  However, they were allowed to deduct a “ResourceAllowance” which is 25% of the taxpayer’s “Resource Profits for the Year”(essentially, net income from the production of oil, natural gas or minerals)in computing their taxable income.

 

In November 2003, Royal Assent was received on a billpassed by the Parliament of Canada, which was then enacted into law, to reduceCanada’s corporate tax rate on “resource” income (income derived from oil andnatural gas operations) over a four-year period beginning January 1, 2003 from29% to 21% with the 21% tax rate commencing on January 1, 2007.  Additionally, the bill phases in over thesame four-year period tax deductions for royalties, which previously were nottax deductible, and phases out the Resource Allowance deduction along withother changes.  Accordingly, duringfiscal 2004, Barnwell’s Canadian deferred income tax liabilities were reducedby approximately $1,440,000 due to the reduction in Canada’s Federal corporatetax rate.

 

In Alberta, a producer of oil or natural gas isentitled to a credit against the royalties payable to the Crown by virtue ofthe Alberta Royalty Tax Credit program. The Alberta Royalty Tax Credit rate is based on a price-sensitiveformula and varies between 75% at prices below a specified royalty tax creditreference price and 25% at prices above a specified royalty tax creditreference price.  The Alberta Royalty TaxCredit will be applied to a maximum annual amount of $2,000,000 Canadiandollars of

 

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Alberta Crown royalties payable for each producer or associated group ofproducers.  Crown royalties on productionfrom producing properties acquired from corporations claiming maximumentitlements to Alberta Royalty Tax Credit will generally not be eligible forAlberta Royalty Tax Credit.  The rate isestablished quarterly based on the average royalty tax credit reference price,as determined by the Alberta Department of Energy.  The royalty tax credit reference price isbased on a weighted average oil and gas price.

 

TheProvince of Alberta has stated that changes in the Alberta Royalty Tax Creditwill be announced three years in advance. The government of Alberta has considered limiting the Alberta RoyaltyTax Credit on some basis, as yet undetermined, to entities that invest in oil andnatural gas in Alberta.  Barnwell currentlydoes such investing.  The Alberta RoyaltyTax Credit program has been in effect in various forms since 1974 and Barnwellanticipates that it will be continued in some form for the foreseeable future.  In fiscal 2004, Barnwell’s Alberta RoyaltyTax Credit totaled approximately $377,000. If the Alberta Royalty Tax Credit is not continued, it will have anadverse effect on Barnwell.

 

Competition

 

The majority of Barnwell’s natural gas sales takeplace in Alberta, Canada.  Natural gasprices in Alberta are generally competitive with other major North Americanareas due to increased pipeline capacity into the United States.  Barnwell’s oil and natural gas liquids aresold in Alberta with prices determined by the world price for oil.

 

Barnwell competes in the sale of oil and natural gason the basis of price, and on the ability to deliver products.  The oil and natural gas industry is intenselycompetitive in all phases, including the exploration for new production andreserves and the acquisition of equipment and labor necessary to conductdrilling activities.  The competitioncomes from numerous major oil companies as well as numerous other independentoperators.  There is also competitionbetween the oil and natural gas industry and other industries in supplying theenergy and fuel requirements of industrial, commercial and individualconsumers.  Barnwell is a minorparticipant in the industry and competes in its oil and natural gas activitieswith many other companies having far greater financial, technical and otherresources.

 

 

CONTRACT DRILLING OPERATIONS

 

Barnwellowns 100% of Water Resources International, Inc. which drills water andexploratory wells and installs and repairs water pumping systems inHawaii.  Water Resources owns andoperates four Spencer-Harris portable rotary drill rigs ranging in drillingcapacity from 3,500 feet to 7,000 feet, and leases an IDECO H-35 rotarydrill/workover rig to an oil company. Additionally, Water Resources leases a three-quarter of an acremaintenance facility in Honolulu and a one acre maintenance and storagefacility with 2,800 square feet of interior space in Kawaihae, Hawaii, andmaintains an inventory of drilling and pump supplies.  As of September 30, 2004, Water Resourcesemployed 25 drilling, pump and administrative employees, none of whom are unionmembers.

 

Water Resources drills water, water monitoring andgeothermal wells of varying depths in Hawaii and also installs and repairswater pumps and is the State of Hawaii’s distributor for Floway pumps andequipment.  The demand for WaterResources’ services is primarily dependent upon land development activities inHawaii.  Water Resources markets itsservices to land developers and government agencies, and identifies potentialcontracts through public notices, its officers’ involvement

 

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in community activities and referrals. Contracts are usually fixed price per lineal foot or day rate contractsand are negotiated with private entities or obtained through competitivebidding with private entities or with local, state and Federal agencies.  Contract revenues are not dependent upon thediscovery of water, geothermal production zones or other, similar targets, andcontracts are not subject to renegotiation of profits or termination at theelection of the governmental entities involved. Contracts provide for arbitration in the event of disputes.

 

Barnwell’scontract drilling subsidiary derived 70%, 66%, and 70% of its contract drillingrevenues in fiscal 2004, 2003, and 2002, respectively, pursuant to Federal,State of Hawaii and county contracts.  AtSeptember 30, 2004, Barnwell had accounts receivable from the State of Hawaiiand county entities totaling approximately $1,705,000.  Barnwell has lien rights on wells drilled andpumps installed for Federal, State of Hawaii, county and private entities.

 

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

 

Activity

 

Infiscal 2004, Water Resources started five well drilling contracts and four pumpinstallation contracts and completed one well drilling contracts and two pumpinstallation contracts.  None of thecompleted well or pump contracts were started in the prior year.  Seventy-four percent (74%) of well drillingand pump installation jobs, representing 70% of total contract drillingrevenues in fiscal 2004, have been pursuant to government contracts.

 

AtSeptember 30, 2004, Water Resources had a backlog of nine well drillingcontracts and eight pump installation and repair contracts, five and two ofwhich were in progress as of September 30, 2004.

 

The dollar amount of Barnwell’s backlog of firm welldrilling and pump installation and repair contracts at November 30, 2004 and2003 is as follows:

 
| ** **                    | ** ** | **2004**      | ** **    | **2003** | ** ** |
|-------------------------------|------------|---------------|---------------|----------|------------|
| Well drilling                 | ** ** | **$**         | **4,500,000** |     | $          | 1,470,000 |   |
| Pump  installation and repair | ** ** | **1,100,000** |          | 880,000  |       |
| ** **                    |       | **$**         | **5,600,000** |     | $          | 2,350,000 |   |

 

Allof the contracts in backlog at November 30, 2004 are expected to be completedwithin or shortly after the end of fiscal year 2005.

 

Competition

 

Water Resources utilizes rotary drill rigs andcompetes with other drilling contractors in Hawaii which use cable tool rigs,which require less labor to operate but generally drill slower, rotary drillrigs similar to Water Resources’ drilling rigs, and top head rotary drillingrigs that drill as quickly as Water Resources’ equipment but require lesslabor.  These competitors are alsocapable of installing and repairing vertical turbine and submersible waterpumping systems in Hawaii.  Thesecontractors compete actively with Water Resources for government and privatecontracts.  Pricing is Barnwell’s majormethod of competition; reliability of service is also a significant factor.

 

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Thenumber of available water well drilling jobs has increased from the prior yearand Barnwell has been awarded more jobs in recent months.  Competitive pressures are expected to remainhigh, thus there is no assurance that the trend in available or awarded jobswill continue.

 

LAND INVESTMENT OPERATIONS

 

Barnwell owns a 77.6% controlling interest inKaupulehu Developments, a Hawaii general partnership that 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.  Between 1986 and 1989,Kaupulehu Developments obtained the state and county zoning changes necessaryto permit development of the Four Seasons Resort Hualalai at Historic Ka’upulehuand Hualalai Golf Club, which opened in 1996, a second golf course, and singleand multiple family residential units. These projects were developed on leasehold land acquired from KaupulehuDevelopments by Kaupulehu Makai Venture, an unrelated entity that is anaffiliate of Kajima Corporation of Japan.

 

In 1993, Kaupulehu Developments submitted a rezoningpetition to the State Land Use Commission and in 1998, filed an Application fora Project District zoning ordinance and a Special Management Area Use PermitPetition with the County of Hawaii to reclassify conservation-zoned land tozoning which allows resort/residential development.  In October 2001, Kaupulehu Developmentsreceived final approval for the reclassification.

 

Kaupulehu Developments holds development rights forresidentially zoned leasehold land within and adjacent to the Hualalai GolfClub and are under option to Kaupulehu Makai Venture.

 

Activity

 

Interests in LeaseholdLand

 

On February 13, 2004, Kaupulehu Developments enteredinto a Purchase and Sale Agreement with WB KD Acquisition LLC (“WB”) by whichKaupulehu Developments transferred its leasehold interest in the approximately870 acres zoned for resort/residential development, in two increments, toWB.  There is no affiliation betweenKaupulehu Developments and WB.  WB is anaffiliate of Westbrook Partners, developers of the Kuki’o Resort.  The first increment (“Increment I”) is anarea 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 the approximately870-acre property and is zoned for single-family and multi-family residentialunits and a golf course and clubhouse.

 

 With respect toIncrement I, Kaupulehu Developments received a non-refundable $11,550,000payment (“Closing Payment”) 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.  If prior to

 

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December 31, 2005, Kaupulehu Developments has not received PercentagePayments equal to or greater than $2,500,000 in the aggregate, WB will payKaupulehu Developments the amount by which the aggregate amount of all priorPercentage Payments made by WB to Kaupulehu Developments is less than$2,500,000.  If prior to December 31,2006, Kaupulehu Developments has not received Percentage Payments (includingpayments in lieu of Percentage Payments as described in the immediatelypreceding sentence) equal to or greater than $5,000,000 in the aggregate, thenWB will pay Kaupulehu Developments the amount by which the aggregate amount ofall such payments is less than $5,000,000. Additionally, WB agreed to pay Kaupulehu Developments non-refundableinterim payments of $50,000 per month (“Interim Payments”), until the first tooccur of the closing of the sale of the 40th single-family lot sold inIncrement I or WB’s payment to Kaupulehu Developments of a total of $900,000 inInterim Payments subsequent to February 2004. As of November 30, 2004, Kaupulehu Developments has received a total of$450,000 of Interim Payments subsequent to February 2004.  There is no assurance that any future InterimPayments or any Percentage Payments will be received.

 

Kaupulehu Developments, WB and The Trustees of TheEstate of Bernice Pauahi Bishop (“KS”) also entered into an agreement (the “Step-InRights Agreement”) whereby if WB elects not to proceed with development ofIncrement I within the time frame set forth in the Step-In Rights Agreement,which may be extended by KS, or defaults under the terms of its lease with KS,Kaupulehu Developments would have the right to succeed to WB’s developmentrights and develop the property without any payment to WB.

 

In March 2004, WB commenced engineering ofinfrastructure, preparation of covenants, conditions and restrictions for acommunity association, and preparation of legal documents to enable real estatesales, and broke ground and graded several miles of access roads.  In late September 2004, WB began mass gradingof the first phase of 38 lots for development.

 

For Increment II, Kaupulehu Developments and WB agreedto use diligent efforts to negotiate, and attempt to document and enter into,prior to the date which is three (3) years following the closing of the sale ofthe first single-family lot in Increment I, an agreement with regards to theownership and development of Increment II. WB, however, may terminate such negotiations at any time without anyfurther obligation. Under the terms of the Step-In Rights Agreement, if at theend of three years following the closing of the sale of the first single-familylot in Increment I the parties have not entered into a definitive agreementwith respect to Increment II, the leasehold rights with respect to Increment IIwill revert to Kaupulehu Developments.

 

The sale of Kaupulehu Developments’ interest inIncrement I was accounted for by use of the cost recovery method, under whichno operating profit is recognized until cash received exceeds the cost and theestimated future costs related to the leasehold interest sold.  The revenue from the $11,550,000 ClosingPayment plus $350,000 of post-closing Interim Payments received in Marchthrough September 2004, 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 ofpreviously capitalized costs relating to Increment I.  The $7,330,000 of net revenue from theClosing Payment and Interim Payments for the year ended September 30, 2004 isrecorded in the Consolidated Statements of Operations as “Sale of interest inleasehold land, net.”  Operating profiton the Increment I transaction, after minority interest, totaled approximately$5,470,000 for the year ended September 30, 2004.  There were no sales of interests in leaseholdland in the years ended September 30, 2003 and 2002.  As no sales price or agreement with regardsto the ownership and development of Increment II has yet been determined, norevenues or cost of sales have been recognized on Increment II.

 

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Development Rights

 

Thedevelopment rights held by Kaupulehu Developments are for residentially zonedleasehold land within and adjacent to the Hualalai Golf Club and are underoption to Kaupulehu Makai Venture, an unrelated entity that is an affiliate of KajimaCorporation of Japan.  On December 31,2003, Kaupulehu Makai Venture exercised the portion of its development rightsoption due on those dates and paid Kaupulehu Developments $2,656,000 in fiscal2004.  At September 30, 2004,approximately 100 acres remain under option. Barnwell accounts for sales of development rights under option by use ofthe cost recovery method.  Under the costrecovery method, no operating profit is recognized until cash received exceedsthe cost and the estimated future costs related to development rightssold.  In fiscal 2004, $2,656,000 ofrevenues attributable to the development rights sale were reduced by $159,000of fees related to the sale, resulting in net revenues of $2,497,000 and a$1,950,000 operating profit, after minority interest, on the transaction.  There were no other costs deducted fromrevenues from the sale of development rights in fiscal 2004 as all capitalizedcosts associated with the development rights were expensed in previous yearsunder the cost recovery method.

 

The totalamount of remaining future option receipts at September 30, 2004, if alloptions are fully exercised, is $18,593,750, comprised of seven payments of$2,656,250 due on each December 31 of years 2004 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.

 

Interests at September 30, 2004

 

The interestsheld by Kaupulehu Developments at September 30, 2004 include the developmentrights under option; the rights to receive Increment I percentage and interimpayments; the leasehold land zoned for resort/residential development withinIncrement II, which is under a right of negotiation with WB; and approximately1,000 acres of vacant leasehold land zoned conservation.

 

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 other entitieshaving far greater financial and other resources.

 

For the pastseveral years, Hawaii’s economy has experienced little or no growth.  However, the South Kohala/North Kona area ofthe island of Hawaii, the area in which Kaupulehu Developments’ property islocated, has experienced strong demand for residential real estate in recentyears.  This trend continued throughfiscal 2004 and is not expected to decline significantly in the near term,although there can be no assurance this trend will in fact continue.

 

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CORPORATEOFFICE

 

InDecember 2003, Barnwell purchased the space it was leasing for its corporateoffices located at 1100 Alakea Street, Suite 2900, Honolulu, Hawaii 96813 for$1,057,000, of which $883,000 was financed by a note payable to a Hawaii bankand the remainder was paid in cash.  Theseller was A&B Alakea LLC, an independent third party.  The note was payable in monthly principalpayments of approximately $3,000, plus interest, and was due in full inDecember 2006.  Barnwell repaid the notein full in fiscal 2004.  The spacepurchased has 4,662 useable square feet in an office building in downtownHonolulu, Hawaii.

 

Item 3.            Legal Proceedings

 

Barnwell is occasionally involved in routine litigation and is subjectto governmental and regulatory controls that are incidental to thebusiness.  Barnwell’s management believesthat routine claims and litigation involving Barnwell are not likely to have amaterial adverse effect on its financial position, results of operations orliquidity.

 

Item 4.            Submission of Matters to a Voteof Security Holders

 

None.

 

PART II

 

Item 5.            Market For Common Equity andRelated Stockholder Matters

 

The principalmarket on which Barnwell’s common stock is being traded is the American StockExchange.  The following tables presentthe quarterly high and low sales prices, on the American Stock Exchange, forBarnwell’s common stock during the periods indicated:

 
| **Quarter Ended**  | ** ** | **High** | ** ** | **Low** | ** ** | **Quarter Ended**   | ** ** | **High**           | ** ** | **Low** | ** ** |
|--------------------|------------|----------|------------|---------|------------|---------------------|------------|--------------------|------------|---------|------------|
| December 31, 2002  |       | $        | 20.45      |    | $          | 19.75               |       | December 31,  2003 |       | $       | 34.00      |   | $ | 24.80 |   |
| March 31, 2003     |       | 22.80    |       | 20.01   |       | March 31,  2004     |       | 48.00              |       | 31.40   |       |
| June 30, 2003      |       | 25.05    |       | 22.25   |       | June 30,  2004      |       | 50.00              |       | 41.25   |       |
| September 30, 2003 |       | 25.15    |       | 24.00   |       | September  30, 2004 |       | 48.20              |       | 42.01   |       |
|                    |            |          |            |         |            |                     |            |                    |            |         |            |  |  |  |  |

 

As of December20, 2004, there were 1,356,010 shares of common stock, par value $0.50,outstanding.  There were approximately400 holders of the common stock of the registrant as of December 20, 2004.

 

On December 3, 2004, Barnwell declared a cashdividend of $0.25 per share payable January 5, 2005, to stockholders of recordon December 20, 2004.

 

Also onDecember 3, 2004, Barnwell declared a two-for-one stock split in the form of astock dividend.  The new shares will bedistributed on January 28, 2005 to all shareholders of record as of January 11,2005.

 

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In August 2004, Barnwell declared a dividend of$0.15 per share payable September 15, 2004, to stockholders of record on August27, 2004.

 

In February 2004, Barnwell declared a dividend of$0.50 per share payable March 12, 2004, to stockholders of record on February27, 2004.

 

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

 

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Item 6.    MANAGEMENT’S DISCUSSION AND ANALYSIS ORPLAN OF OPERATION

 

The followingdiscussion is intended to assist in the understanding of the consolidatedbalance sheets of Barnwell Industries, Inc. and subsidiaries (collectivelyreferred to herein as “Barnwell”) as of September 30, 2004 and 2003, and therelated consolidated statements of operations, stockholders’ equity andcomprehensive income (loss), and cash flows for each of the years in thethree-year period ended September 30, 2004. 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.

 

# **CRITICAL ACCOUNTING POLICIES ANDESTIMATES**

 

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 andnatural gas properties

 

Barnwell usesthe full cost method of accounting under which all costs incurred in theacquisition, exploration and development of oil and natural gas reserves,including unsuccessful wells, are capitalized until such time as the aggregateof such costs, on a country-by-country basis, equals the discounted presentvalue (at 10%) of Barnwell’s estimated future net cash flows from estimatedproduction of proved oil and natural gas reserves, from such country, asdetermined by independent petroleum engineers, less related income taxeffects.  Any capitalized costs, net ofoil and gas related deferred income taxes, in excess of the discounted presentvalue of proved properties and the lower of cost or estimated fair value ofunproved properties are charged to expense. Depletion of all such costs, except costs related to major developmentprojects, is provided by the unit-of-production method based uponproved oil and natural gas reserves of all properties on a country-by-countrybasis.  Investments in major developmentprojects are not amortized until either proved reserves are associated with theprojects or impairment has been determined. At September 30, 2004, Barnwell had no investments in major oil andnatural gas development projects that were not being amortized.  General and administrative costs related tooil and natural gas operations are expensed as incurred.  Estimated future site restoration andabandonment costs are capitalized as part of the carrying amount of oil andnatural gas properties and depleted over the life of the related reserves.  Proceeds from the disposition of minorproducing oil and natural gas properties are credited to the cost of oil andnatural gas properties.  Gains or lossesare recognized on the disposition of significant oil and natural gasproperties.

 

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Investment inland and revenue recognition

 

Barnwell’sinvestment in land is comprised of development rights under option; rights toreceive Increment I percentage and interim payments; leasehold land interestsin land zoned resort/residential which are under right of negotiation; and landzoned conservation which is not under option or 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 the recordedinvestment balance may not be fully recoverable.

 

Costs incurredfor the acquisition and improvement of leasehold land interests, includingcapitalized interest, are included in the consolidated balance sheets under thecaption “Investment in Land.”

 

Sales ofdevelopment rights under option and revenues from the sale of Increment I ofleasehold land interests are accounted for under the cost recovery method.  Under the cost recovery method, no operatingprofit is recognized until cash received exceeds the cost and the estimatedfuture costs related to the development rights sold.

 

Contractdrilling

 

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 consequences attributable todifferences between the financial statement carrying amounts of existing assetsand liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax ratesin effect for the year in which those temporary differences are expected to berecovered or settled.  The effect ondeferred tax assets and liabilities of a change in tax rates is recognized inincome in the period 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 valuationallowance primarily for the U.S. tax effect of deferred Canadian taxes, foreigntax credits, accrued expenses and state of Hawaii net operating losscarryforwards which may not be realizable in future years as there can be noassurance of any specific level of earnings or that the timing of U.S. earningswill coincide with the payment of Canadian taxes to enable Canadian taxes to befully deducted (or recoverable) for U.S. tax purposes.

 

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Net deferred tax assets at September 30,2004 of $3,093,000 consists of $1,165,000 related to the excess of the costbasis of investment in land for tax purposes over the cost basis of investmentin land for book purposes and $1,812,000 related to the excess of liabilitiesaccrued for book purposes over liabilities accrued for tax purposes.  The deferred tax assets are estimated to berealized through the deduction of the cost basis of investment in land andexpenses for tax purposes against future proceeds from sales of interests inleasehold land and land development rights. Additionally, at September 30, 2004, Barnwell had a deferred tax assetof $116,000 for alternative minimum tax credit carryforwards which are availableto reduce future U.S. federal regular income taxes, if any, over an indefiniteperiod.  The amount of deferred incometax assets considered realizable may be reduced if estimates of future taxableincome are reduced.

 

###### Pension Plan

 

Barnwell sponsors a noncontributory definedbenefit pension plan covering substantially all of its U.S. employees, withbenefits based on years of service and the employee’s highest consecutivefive-year average earnings.  Barnwellaccounts for its defined benefit pension plan in accordance with Statement ofFinancial Accounting Standards No. 87, “Employers’ Accounting for Pensions,”which requires that amounts recognized in financial statements be determined onan actuarial basis.  Statement ofFinancial Accounting Standards No. 87 requires that the effects of the performanceof the pension 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 2004 andfiscal 2003, Barnwell assumed an expected long-term rate of return on planassets of 8%.  The expected rate offuture annual compensation increases utilized during and as of the end offiscal 2004 and fiscal 2003 was 5%.

 

At the end of each year, Barnwell determines thediscount rate 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.  At September30, 2004, Barnwell determined this rate to be 5.75%.

 

At September 30, 2004, Barnwell’s accruedbenefit cost was $418,000.  For the yearended September 30, 2004, Barnwell recognized a net periodic benefit cost of$168,000.

 

CONTRACTUALOBLIGATIONS

 

Thefollowing table lists the scheduled maturities of long-term debt, estimatingthat Barnwell’s credit facility with the Royal Bank of Canada will be renewedon each annual renewal date, currently April 30, and scheduled minimum rentalpayments of non-cancelable operating leases for office space and leaseholdland:

 

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| ** **                  | ** ** | **Payments Due by Fiscal Year** | ** ** |
|-----------------------------|------------|---------------------------------|------------|
| **Contractual Obligations** | ** ** | **2005**                        | ** ** | **2006-2007** | ** ** | **2008-2009** | ** ** | **After 2009** | ** ** | **Total** | ** ** |
| Long-term debt              |       | $                               | —     |   | $ | — |   | $ | — |   | $ | 10,165,000 |   | $ | 10,165,000 |   |
| Operating leases            |       | 495,000                         |       | 923,000 |   | 797,000 |   | 2,390,000 |   | 4,605,000 |   |
|                        |       |                            |       |   |   |   |   |   |   |   |   |
| Total                       |       | $                               | 495,000    |   | $ | 923,000 |   | $ | 797,000 |   | $ | 12,555,000 |   | $ | 14,770,000 |   |

 

There is no assurance that the bank willin fact extend the term of the facility on each renewal date or that thefacility will be renewed at its current amount. The following table lists the scheduled maturities of long-term debtassuming that the facility will not be renewed on the next renewal date andthat Barnwell 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** | ** ** | **2005**                        | ** ** | **2006-2007** | ** ** | **2008-2009** | ** ** | **After 2009** | ** ** | **Total** | ** ** |
| Long-term debt              |       | $                               | 508,000    |   | $ | 9,657,000 |   | $ | — |   | $ | — |   | $ | 10,165,000 |   |
| Operating leases            |       | 495,000                         |       | 923,000 |   | 797,000 |   | 2,390,000 |   | 4,605,000 |   |
|                        |       |                            |       |   |   |   |   |   |   |   |   |
| Total                       |       | $                               | 1,003,000  |   | $ | 10,580,000 |   | $ | 797,000 |   | $ | 2,390,000 |   | $ | 14,770,000 |   |

 

The leasepayments for land are subject to renegotiation after December 31, 2005; thefuture rental payment disclosures above assume the minimum lease payments forland in effect at December 31, 2005 remain unchanged through 2025, the end ofthe lease term.

 

# **OVERVIEW**

 

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

 

Barnwell sellssubstantially all of its oil and condensate production under short-termcontracts with marketers of oil.  Theprice of oil is freely negotiated between the buyers and sellers.  Natural gas sold by Barnwell is generallysold under both long-term and short-term contracts with pricesindexed to market prices.  The price ofnatural gas and natural gas liquids is freely negotiated between buyers andsellers.  Market prices for petroleumproducts are dependent upon factors such as, but not limited to, changes inweather, storage levels, and output. Petroleum and natural gas prices are very difficult to predict andfluctuate significantly.  For example,natural gas prices for Barnwell, based on quarterly averages during the threeyears ended September 30, 2004, have ranged from a low of $1.96 per thousandcubic feet to a high of $5.08 per thousand cubic feet, and tend to be higher inthe winter season than in the summer due to increased demand.  Oil and natural gas costs generally followtrends in product market prices, thus in times of higher product prices the costof exploration, development and operation of oil and natural gas propertieswill tend to escalate as well.  Barnwell’soil and natural gas operations makes capital expenditures in the exploration,development, and production of oil and natural gas.  Cash outlays for capital expenditures are largelydiscretionary, however, a minimum level of capital

 

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expenditures is required toreplace depleting reserves.  Due to thenature of oil and natural gas exploration and development, uncertainty existsas to the ultimate success of any drilling effort.

 

Barnwell owns a 77.6% controllinginterest in Kaupulehu Developments, a Hawaii general partnership which ownsinterests in leasehold land and development rights for property locatedapproximately six miles north of the Kona International Airport in the NorthKona District of the Island of Hawaii, adjacent to and north of the FourSeasons Resort Hualalai 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. The remaining options are comprised of seven payments of $2,656,250 dueon each December 31 of years 2004 to 2010. In February 2004, Kaupulehu Developments entered into a Purchase andSale 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.  For the first increment, KaupulehuDevelopments received an $11,550,000 cash closing payment and is also entitledto receive future payments from the buyer based on the following percentages ofgross receipts from the developer’s sales of single-family residential lots inthe first increment: 9% of the gross proceeds from single-family lot sales upto aggregate gross proceeds of $100,000,000; 10% of such aggregate grossproceeds greater than $100,000,000 but less than $300,000,000; and 14% of suchaggregate gross proceeds in excess of $300,000,000.  For the second increment, KaupulehuDevelopments and WB agreed to use diligent efforts to negotiate, and attempt todocument and enter into, prior to the date which is three (3) years followingthe closing of the sale of the first single-family lot in Increment I, anagreement with regards to the ownership and development of Increment II.  The area in which Kaupulehu Developments’interests are located has experienced strong demand for premium residentialreal estate in recent years, however there is no assurance that any futurepercentage or development rights payments will be received.

 

Barnwell alsodrills wells and installs and repairs water pumping systems in Hawaii.  Contract drilling results in fiscal 2003 andfor the first quarter of fiscal 2004 reflected the impact of a decrease inactivity due to cyclical changes in the timing of jobs put out for bid bygovernmental and private entities. During the remainder of fiscal 2004, however, activity increased as thenumber and value of contracts awarded has increased in recent months.  While progress on these contracts willcontinue through a portion of fiscal 2005, there is no assurance that thistrend will continue through all of fiscal 2005 and in future periods.

 

RESULTS OF OPERATIONS

 

Summary

 

Barnwell generated net earnings of$8,710,000 in fiscal 2004, a $6,390,000 increase from net earnings of$2,320,000 in fiscal 2003.  The increasewas the result of an increase in land investment operating profit due to thesale of an interest in leasehold land, higher operating profit from the sale ofdevelopment rights, and deferred income tax benefits of $1,740,000 resultingfrom a reduction in Canadian income tax rates.

 

The fiscal year average exchange rate ofthe Canadian dollar to the U.S. dollar increased 10% in fiscal 2004, ascompared to fiscal 2003, and the exchange rate of the Canadian dollar to theU.S. dollar increased 7% at September 30, 2004, as compared to September 30,2003.  This increase in the value of

 

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the Canadian dollar in U.S.dollars increased Barnwell’s reported assets and liabilities and revenues andexpenses.

 

Barnwell generated net earnings of$2,320,000 in fiscal 2003, a $2,280,000 increase from net earnings of $40,000in fiscal 2002.  The increase was largelyattributable to significant increases in petroleum prices.  In addition, land segment operating profitincreased in fiscal 2003, as compared to fiscal 2002, as revenues from the saleof development rights in fiscal 2003, accounted for under the cost recoverymethod, exceeded associated costs, whereas revenues from the sale ofdevelopment rights in fiscal 2002 were fully offset by associated costs afterconsideration of minority interest in earnings.

 

##### Oil and Natural Gas Revenues

 

Selected Operating Statistics

 

The followingtables set forth Barnwell’s annual net production and annual average price perunit of production for fiscal 2004 as compared to fiscal 2003, and fiscal 2003as compared to fiscal 2002.  Productionamounts reported are net of royalties and the Alberta Royalty Tax Credit.

 

Fiscal 2004 -Fiscal 2003

 
| ** **          | ** ** | **Annual Net Production** | ** ** |
|---------------------|------------|---------------------------|------------|
| ** **          | ** ** | ** **                | ** ** | ** ** | ** ** | **Increase** | ** ** |
| ** **          | ** ** | **2004**                  | ** ** | **2003** | ** ** | **Units** | ** ** | **%** | ** ** |
| Liquids (Bbl)*      | ** ** | **105,000**               |       | 85,000 |   | 20,000 |   | 24 | % |
| Oil (Bbl)*          | ** ** | **154,000**               |       | 142,000 |   | 12,000 |   | 8 | % |
| Natural gas (MCF)** | ** ** | **3,383,000**             |       | 3,175,000 |   | 208,000 |   | 7 | % |

 
| ** **          | ** ** | **Annual Average Price Per Unit** | ** ** |
|---------------------|------------|-----------------------------------|------------|
| ** **          | ** ** | ** **                        | ** ** | ** ** | ** ** | **Increase** | ** ** |
| ** **          | ** ** | **2004**                          | ** ** | **2003** | ** ** | **$** | ** ** | **%** | ** ** |
| Liquids (Bbl)*      | ** ** | **$**                             | **24.18**  |   | $ | 21.50 |   | $ | 2.68 |   | 12 | % |
| Oil (Bbl)*          | ** ** | **$**                             | **33.24**  |   | $ | 27.69 |   | $ | 5.55 |   | 20 | % |
| Natural gas (MCF)** | ** ** | **$**                             | **4.60**   |   | $ | 4.27 |   | $ | 0.33 |   | 8 | % |

 

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Fiscal 2003 -Fiscal 2002

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

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

 

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

**MCF = 1,000cubic feet

 

Oil and natural gas revenues increased$3,920,000 (20%) from $19,350,000 in fiscal 2003 to $23,270,000 in fiscal 2004,due to increases in both prices and production volumes for all petroleumproducts.  Natural gas prices increased8%, and natural gas production increased 7%. The increase in natural gas production was due to both new productionfrom the Bonanza, Foley Lake, South Pouce Coupe and Leduc areas and natural gasproduction from the Dunvegan property which increased approximately 7% as aresult of an infill drilling program in fiscal 2004 and late fiscal 2003 whichadded 39 gross development wells (3.4 net wells).  The increase in natural gas production waspartially offset by production declines at the Thornbury, Pouce Coupe,Progress, and Pollockville areas.  Oilprices increased 20%, and oil production increased 8% due to new productionfrom the Wizard Lake and Bonanza areas, partially offset by a decrease inproduction from older oil properties. Natural gas liquids prices increased 12%, and natural gas liquidsproduction increased 24% due to the abovementioned infill drilling program atthe Dunvegan area and due to the fact that fiscal 2003 natural gas liquidsproduction was impacted by a fire in early October 2002 at a Dunvegan gas plantwhich prevented stripping of natural gas liquids from the natural gas; this resultedin an approximately 6,000 barrel lower liquids net production in fiscal 2003,as compared to fiscal 2004.

 

Oil andnatural gas revenues increased $8,030,000 (71%) from $11,320,000 in fiscal 2002to $19,350,000 in fiscal 2003, due to 101%, 30%, and 73% increases in naturalgas, oil, and natural gas liquids prices, respectively.  The increase was partially offset by 3%, 4%,and 10% declines in net natural gas, oil, and natural gas liquids production,respectively, due to natural declines in production from some of Barnwell’smore mature properties, which were partially offset by an increase inproduction from new wells.  In addition,natural gas liquids production decreased due to the fire at the Dunvegan gasplant.

 

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Oil andNatural Gas Operating Expenses

 

Operating expenses increased $1,211,000(29%) to $5,403,000 in fiscal 2004, as compared to $4,192,000 in fiscal 2003,due to the addition of new properties, costs incurred to re-enter wells forrepair, maintenance and cleaning, and inflationary pressures on oil fieldservice costs.  Also contributing to theincrease was a 10% increase in the average exchange rate of the Canadian dollarto the U.S. dollar that increased oil and natural gas operating expenses$505,000 in fiscal 2004, as compared to fiscal 2003.

 

Operating expenses increased $1,084,000(35%) to $4,192,000 in fiscal 2003, as compared to $3,108,000 in fiscal2002.  The increase was partlyattributable to an oil and natural gas operating expense credit recorded in thefourth quarter of fiscal 2002 for the settlement of overcharges of operatingexpenses for fiscal years 1998 through 2001 from the operator of the Dunveganproperty that reduced fiscal 2002 operating expenses by approximately $470,000.  Also contributing to the increase wereincreases in well repair and maintenance, electricity, fuel, insurance, andgeneral maintenance costs.

 

###### Sale of Interest in Leasehold Land, Sale ofDevelopment Rights, and Minority Interest in Earnings

 

On February 13, 2004, KaupulehuDevelopments, a land development general partnership in which Barnwell owns a77.6% controlling interest, entered into a Purchase and Sale Agreement with WBby which Kaupulehu Developments transferred its leasehold interest in approximately870 acres zoned for resort/residential development, in two increments, toWB.  There is no affiliation betweenKaupulehu Developments and WB.  IncrementI is an area planned for approximately 80 single-family lots and a beach clubon the portion 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. Increment II is the remaining portion of the approximately 870-acreproperty and is zoned for single-family and multi-family residential units anda golf course and clubhouse.

 

With respect to Increment I, KaupulehuDevelopments received a non-refundable $11,550,000 payment (“Closing Payment”)and is entitled to receive payment of the following percentages of the grossproceeds generated from the sale by WB of single-family lots in Increment I (“PercentagePayments”): 9% of the gross proceeds from single-family lot sales up toaggregate gross proceeds of $100,000,000; 10% of such aggregate gross proceedsgreater than $100,000,000 but less than $300,000,000; and 14% of such aggregategross proceeds in excess of $300,000,000. If prior to December 31, 2005, Kaupulehu Developments has not receivedPercentage Payments equal to or greater than $2,500,000 in the aggregate, WBwill pay Kaupulehu Developments the amount by which the aggregate amount of allprior Percentage Payments made by WB to Kaupulehu Developments is less than$2,500,000.  If prior to December 31,2006, Kaupulehu Developments has not received Percentage Payments (includingpayments in lieu of Percentage Payments as described in the immediatelypreceding sentence) equal to or greater than $5,000,000 in the aggregate, thenWB will pay Kaupulehu Developments the amount by which the aggregate amount ofall such payments is less than $5,000,000. Additionally, WB agreed to pay Kaupulehu Developments non-refundableinterim payments of $50,000 per month (“Interim Payments”), until the first tooccur of the closing of the sale of the 40th single-family lot sold inIncrement I or WB’s payment to Kaupulehu Developments of a total of $900,000 inInterim Payments subsequent to February 2004.  As of November 30, 2004, KaupulehuDevelopments has received a total of $450,000 of Interim Payments subsequent toFebruary 2004.  There is no assurancethat any future Interim Payments or any Percentage Payments will be received.

 

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Kaupulehu Developments, WB and TheTrustees of The Estate of Bernice Pauahi Bishop (“KS”) also entered into anagreement (the “Step-In Rights Agreement”) whereby if WB elects not to proceedwith development of Increment I within the time frame set forth in the Step-InRights Agreement, which may be extended by KS, or defaults under the terms ofits lease with KS, Kaupulehu Developments would have the right to succeed to WB’sdevelopment rights and develop the property without any payment to WB.

 

WB has commenced engineering ofinfrastructure, preparation of covenants, conditions and restrictions for acommunity association, and preparation of legal documents to enable real estatesales, and broke ground and graded several miles of access roads.  In late September 2004, WB began mass gradingof the first phase of 38 lots for development. WB estimates that sales of these single-family lots will commence inBarnwell’s fiscal 2005.

 

For Increment II, Kaupulehu Developmentsand WB agreed to use diligent efforts to negotiate, and attempt to document andenter into, prior to the date which is three (3) years following the closing ofthe sale of the first single-family lot in Increment I, an agreement withregards to the ownership and development of Increment II.  WB, however, may terminate such negotiationsat any time without any further obligation. Under the terms of the Step-In Rights Agreement, if at the end of threeyears following the closing of the sale of the first single-family lot inIncrement I the parties have not entered into a definitive agreement withrespect to Increment II, the leasehold rights with respect to Increment II willrevert to Kaupulehu Developments.

 

The sale of Kaupulehu Developments’interest in Increment I was accounted for by use of the cost recovery method,under which no operating profit is recognized until cash received exceeds thecost and the estimated future costs related to the leasehold interestsold.  The revenue from the $11,550,000Closing Payment plus $350,000 of post-closing Interim Payments received inMarch through September 2004, 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.  The $7,330,000 of net revenue from theClosing Payment and Interim Payments for the year ended September 30, 2004is recorded in the Consolidated Statements of Operations as “Sale of interestin leasehold land, net.”  Operatingprofit on the Increment I transaction, after minority interest, totaledapproximately $5,470,000 for the year ended September 30, 2004.  There were no sales of interests in leaseholdland in the years ended September 30, 2003 or 2002.  As no sales price or agreement with regardsto the ownership and development of Increment II has yet been determined, norevenues or cost of sales have been recognized on Increment II.

 

The development rights held by KaupulehuDevelopments are for residentially zoned leasehold land within and adjacent tothe Hualalai Golf Club and are under option to Kaupulehu Makai Venture, anunrelated entity that is an affiliate of Kajima Corporation of Japan.  Net revenues from the sale of developmentrights increased $1,777,000 to $2,497,000 for the year ended September 30,2004, as compared to $720,000 for the same period in the prior year.  On December 31, 2003, Kaupulehu Makai Ventureexercised the portion of its development rights option expiring on that dateand sent Kaupulehu Developments the required $2,656,000 option payment, whichwas received by Kaupulehu Developments in January 2004.  Revenue from the option exercise was reducedby $159,000 of fees related to the sale, resulting in net revenues of $2,497,000and a $1,950,000 operating profit, after minority interest, on thetransaction.  There were no other costsdeducted from revenues from the sale of development rights in the year endedSeptember 30, 2004 as all capitalized costs associated with the

 

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development rights wereexpensed in previous years under the cost recovery method.  In the year ended September 30, 2003,$2,125,000 of revenues from the sale of development rights was reduced by$128,000 of fees related to the sale and $1,277,000 of cost basis related tothe development rights, resulting in net revenues of $720,000 and a $280,000operating profit, after minority interest, on the transaction.  On December 31, 2001, Kaupulehu Makai Ventureexercised the portion of its development rights option due on that date andpaid Kaupulehu Developments $2,125,000. Under the cost recovery method, $1,877,000 of investment in land wasexpensed as a result of this option exercise, reducing operating profit, afterminority interest, to zero in fiscal 2002.

 

Thetotal amount of remaining future development right option receipts at September30, 2004, if all options are fully exercised, is $18,593,750, comprised ofseven payments of $2,656,250 due on each December 31 of years 2004 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 $159,000 in fees($112,000, net of minority interest) on the proceeds from the sale ofdevelopment rights and $693,000 ($486,000, net of minority interest) on theproceeds from the sale of interest in leasehold land for the year endedSeptember 30, 2004 were paid to Nearco, Inc., a company controlled by Mr. TerryJohnston, a director of Barnwell and an indirect 21.8% 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 the sale of real estate interests, and Cambridge HawaiiLimited Partnership, a 49.9% partner of Kaupulehu Developments in whichBarnwell purchased a 55.2% interest in April 2001, is obligated under anagreement entered into in 1987 to pay Nearco 4% of Kaupulehu Developments’gross receipts from the sale of real estate interests.  Fees of $128,000 ($89,000, net of minorityinterest) on the proceeds from sales of development rights were paid in each ofthe years ended September 30, 2003 and 2002. The fees represent compensation for promotion and marketing of KaupulehuDevelopments’ property and were determined based on the estimated fair value ofsuch services.  Barnwell believes thefees are fair and reasonable compensation for such services.

 

Fees were also paid to Nearco forconsulting services related to Kaupulehu Developments’ leasehold land.  In fiscal 2004, 2003 and 2002, consultingservice fees paid to Nearco, Inc. totaled $273,000, $218,000 and $95,000,respectively, and were included in general and administrative expenses.  In addition, $52,000 of fees were 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 under the cost recovery method.  Barnwell believes the fees are fair andreasonable compensation for such services.

 

### Contract Drilling

 

Contract drilling revenues and costs areassociated with well drilling and water pump installation, replacement andrepair in Hawaii.

 

Contract drilling revenues increased$1,640,000 (80%) to $3,690,000 in fiscal 2004, as compared to $2,050,000 infiscal 2003, and contract drilling operating expenses increased $1,256,000(65%) to $3,184,000 in fiscal 2004, as compared to $1,928,000 in fiscal2003.  Operating profit beforedepreciation increased $384,000 (315%) from $122,000 in fiscal 2003 to $506,000in fiscal 2004.  The increases were dueto an increase in water well drilling activity as there were four drilling rigsoperating

 

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at the same time for a portion,including at the end, of fiscal 2004, but not during fiscal 2003.  Contract drilling revenues and costs are notseasonal in nature but can fluctuate significantly based on the awarding andtiming of contracts, which are determined by contract drilling customers.

 

At September 30, 2004, Water Resources,had a backlog of nine well drilling contracts and eight pump installation andrepair contracts, five and two of which were in progress as of September 30,2004.  The backlog of contract drillingrevenues as of November 30, 2004 was approximately $5,600,000.

 

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

 

Gas Processingand Other Income

 

Gas processingand other income decreased $377,000 (24%) to $1,183,000 in fiscal 2004, ascompared to $1,560,000 in fiscal 2003. In fiscal 2004, Kaupulehu Developments received $250,000 in incomerelated to negotiations on the development of Kaupulehu Developments’resort/residential acreage, as compared to $500,000 in fiscal 2003, a decreaseof $250,000; these revenues discontinued with the consummation of KaupulehuDevelopments’ sale of an interest in leasehold land in February 2004.  In addition, interest income decreased infiscal 2004, as compared to fiscal 2003, as fiscal 2003 interest incomeincluded $102,000 of interest on an income tax refund from the Canadian governmentrelating to Barnwell’s fiscal 1994 tax return (there was no such income infiscal 2004), and as a note receivable that was outstanding during all offiscal 2003 was repaid in February 2004, which resulted in an approximately$100,000 decrease in interest income. These decreases were partially offset by an increase in other income infiscal 2004 from a $139,000 gain from the sale of an approximately two andone-quarter acre parcel of fee simple vacant land located in the Hilo districtof the Island of Hawaii for $440,000, net of costs related to the sale, inMarch 2004; the property was formerly used as a storage and maintenance yard byBarnwell’s contract drilling segment. The remainder of the decrease was primarily due to a $30,000 decrease ingas processing fees due to a decrease in the processing of third-party gas, ascompared to the prior year.

 

Gas processingand other income increased $600,000 (63%) to $1,560,000 in fiscal 2003, ascompared to $960,000 in fiscal 2002, due principally to the receipt byKaupulehu Developments of $500,000 in income related to negotiations on thedevelopment of Kaupulehu Developments’ resort/residential acreage during fiscal2003, as compared to $100,000 in fiscal 2002. Interest income in fiscal 2003 also increased due to $102,000 ofinterest on an income tax refund from the Canadian government relating toBarnwell’s fiscal 1994 tax return and a $61,000 increase in interest income ona note receivable (interest on the note began in February 2002, therefore therewere only eight months of interest earned in fiscal 2002, as compared to a fulltwelve months of interest earned in fiscal 2003).

 

### General andAdministrative Expenses

 

General and administrative expensesincreased $1,940,000 (32%) to $7,911,000 in fiscal 2004, as compared to$5,971,000 in fiscal 2003.  The increasewas due to the impact of an increase in Barnwell’s stock price on stockappreciation rights, which increased general and administrative expenses by

 

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$765,000 as compared to theprior year, $733,000 of bonuses issued in conjunction with the consummation ofKaupulehu Developments’ sale of an interest in leasehold land in February 2004,and $443,000 of higher payroll costs, as compared to the prior year.

 

General and administrative expensesinclude fees paid to Nearco, Inc., an entity controlled by Mr. Terry Johnston,a director of Barnwell and an indirect 21.8% owner of Kaupulehu Developments,for consulting services related to Kaupulehu Developments’ leasehold land.  In fiscal 2004 and fiscal 2003, fees paid toNearco, Inc. totaled $273,000 and $218,000, respectively.  As previously stated, Barnwell believes thefees are fair and reasonable compensation for such services.

 

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

 

Depletion,Depreciation and Amortization

 

Depletion,depreciation and amortization increased $2,428,000 (56%) to $6,761,000 infiscal 2004, as compared to $4,333,000 in fiscal 2003, due to a 33% increase inthe depletion rate, a 9% increase in production (in MCF equivalents where onebarrel of oil and natural gas liquids are converted to 5.8 MCF equivalents),and a 10% increase in the fiscal year average exchange rate of the Canadiandollar to the U.S. dollar.

 

Thehigher depletion rate is due to increases in Barnwell’s costs of finding anddeveloping proven reserves, and development costs that are incurred to maintainor increase rates of production from reserves found in previous years.  Barnwell’s cost of finding and developingproven reserves has increased as a result of the cost of oil and natural gasexploration and development having increased along with product prices, thedrilling of unsuccessful wells, and as a portion of recent oil and natural gascapital expenditures were for the development of existing reserves.

 

Depletion,depreciation and amortization increased $685,000 (19%) to $4,333,000 in fiscal2003, as compared to $3,648,000 in fiscal 2002, due to an 18% increase in thedepletion rate and an 8% increase in the fiscal year average exchange rate ofthe Canadian dollar to the U.S. dollar, partially offset by a 4% decrease inproduction (in MCF equivalents where one barrel of oil and natural gas liquidsare converted to 5.8 MCF equivalents).

 

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InterestExpense

 

Interestexpense increased $45,000 (10%) to $487,000 in fiscal 2004, as compared to$442,000 in fiscal 2003, as there was no capitalization of interest in fiscal2004, as compared to $45,000 of capitalized interest in fiscal 2003.

 

Interest costsfor the years ended September 30, 2004, 2003, and 2002 are summarized asfollows:

 
| ** **                                             | ** ** | **2004**   | ** **  | **2003** | ** ** | **2002** | ** ** |
|--------------------------------------------------------|------------|------------|-------------|----------|------------|----------|------------|
| Interest costs incurred                                | ** ** | **$**      | **487,000** |     | $          | 487,000  |       | $ | 498,000 |   |
| Less interest costs capitalized on  investment in land | ** ** | **—** |        | 45,000   |       | 202,000  |       |
| Interest expense                                       | ** ** | **$**      | **487,000** |     | $          | 442,000  |       | $ | 296,000 |   |

 

The average interest rate incurred duringfiscal 2004 on Barnwell’s borrowings from the Royal Bank of Canada decreased to3.67%, as compared to 3.84% in fiscal 2003, and the weighted average balance ofoutstanding borrowings from the Royal Bank of Canada increased fromapproximately $10,100,000 in fiscal 2003 to approximately $10,305,000 in fiscal2004, due to an increase in the exchange rate of Canadian dollar to the U.S.dollar.

 

Interestexpense increased $146,000 (49%) to $442,000 in fiscal 2003, as compared tointerest expense of $296,000 in fiscal 2002. The increase was due primarily to decreased capitalized interest asBarnwell no longer capitalizes interest on the accumulated development costs ofthe property effective January 1, 2003.

 

### Foreign CurrencyFluctuations

 

Inaddition to U.S. operations, Barnwell conducts foreign operations inCanada.  Consequently, Barnwell issubject to foreign currency translation and transaction gains and losses due tofluctuations of the exchange rates between the Canadian dollar and the U.S.dollar.

 

The fiscal year average exchange rate ofthe Canadian dollar to the U.S. dollar increased 10% in fiscal 2004, ascompared to fiscal 2003, and the exchange rate of the Canadian dollar to theU.S. dollar increased 7% at September 30, 2004, as compared to September 30,2003.  Accordingly, the assets,liabilities, stockholders’ equity and revenues and expenses of Barnwell’ssubsidiaries operating in Canada have increased.  Barnwell’s Canadian dollar assets are greaterthan its Canadian dollar liabilities; therefore, increases in value of theCanadian dollar to the U.S. dollar generate other comprehensive income.  The fiscal year average exchange rate of theCanadian dollar to the U.S. dollar increased 8% in fiscal 2003, as compared tofiscal 2002, and the exchange rate of the Canadian dollar to the U.S. dollarincreased 17% at September 30, 2003, as compared to September 30, 2002.  Other comprehensive income due to foreigncurrency translation adjustments for fiscal 2004 was $1,660,000, a $732,000decrease from other comprehensive income of $2,392,000 in fiscal 2003.

 

Foreigncurrency transaction gains and losses were not material in fiscal 2004, 2003,and 2002 and are reflected in general and administrative expenses.

 

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Theimpact of fluctuations of the exchange rates between the Canadian dollar andthe U.S. dollar may be material from period to period.  Barnwell cannot accurately predict futurefluctuations between the Canadian and U.S. dollars.

 

Income Taxes

 

In November2003, Royal Assent was received on a bill passed by the Parliament of Canada,which was then enacted into law, to reduce Canada’s corporate tax rate on “resource”income (income derived from oil and natural gas operations) over a four-year periodbeginning January 1, 2003 from 29% to 21% with the 21% tax rate commencing onJanuary 1, 2007.  Additionally, the billphases in over the same four-year period tax deductions for royalties, whichpreviously were not tax deductible, and phases out the Resource Allowancededuction along with other changes. Accordingly, during fiscal 2004, Barnwell’s Canadian deferred income taxliabilities were reduced by approximately $1,440,000 due to the reduction inCanada’s corporate tax rate.  There wasno benefit attributable to changes in Canada’s Federal corporate tax rate on “resource”income in fiscal 2003 or fiscal 2002.

 

Barnwell’sCanadian deferred income tax liabilities were also reduced by approximately$300,000 in fiscal 2004 as a result of the Province of Alberta’s reduction ofthe province’s corporate tax rate from 13.0% to 12.5%, effective April 1, 2003(enacted into law in December 2003), and from 12.5% to 11.5%, effective April1, 2004 (enacted into law in May 2004). In April 2002, the legislative assembly of the Province of Albertapassed a bill to reduce the province’s corporate tax rate from 13.5% to 13.0%,effective April 1, 2002.  The bill wasenacted into law in December 2002.  Thereduction in the tax rate reduced Canadian deferred income tax liabilities byapproximately $75,000 in fiscal 2003. There was no such reduction recorded in fiscal 2002.  The Government of the Province of Alberta hasstated that their goal is to lower the corporate tax rate, over a period ofyears, to 8% based on affordability.

 

The U.S. deferred tax expense of $608,000for fiscal 2004 includes reversals of temporary differences, resulting from theexcess of expenses deductible for tax purposes over expenses recognized underthe cost recovery method for books, generated by sales of KaupulehuDevelopments’ development rights and interest in leasehold land.

 

Included in the provisions for deferredincome taxes for fiscal 2003 and 2002 are U.S. deferred tax benefits of$320,000 and $376,000, respectively, related to the sale of land developmentrights in December 2002 and 2001, respectively. The sales of land development rights in fiscal 2003 and 2002 createdtemporary differences due to the excess of expenses recognized under the costrecovery method for books over expenses deductible for tax purposes.

 

In fiscal 2003 and 2002, the provisionfor income taxes did not bear a normal relationship to earnings becauseCanadian taxes were payable on Canadian operations and losses from U.S.operations provide no foreign tax benefits.

 

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.

 

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These laws, rules and regulationsaffect the operations of Barnwell and could have a material adverse effect uponthe earnings or competitive position of Barnwell.  Although Barnwell’s experience has been tothe contrary, there is no assurance that this will continue to be the case.

 

Inflation

 

The effect ofinflation on Barnwell has generally been to increase its cost of operations,interest cost (as a substantial portion of Barnwell’s debt is at variableshort-term rates of interest which tend to increase as inflation increases),general and administrative costs and direct costs associated with oil andnatural gas production and contract drilling operations.  In the case of contract drilling, Barnwellhas not been able to increase its contract revenues to fully compensate forincreased costs.  In the case of oil andnatural gas, prices realized by Barnwell are essentially determined by worldprices for oil and western Canadian/Midwestern U.S. prices for natural gas.

 

RecentAccounting Pronouncements

 

In December 2003, the Financial Accounting Standards Board (“FASB”)revised Statement of Financial Accounting Standards (“SFAS”) No. 132, “Employers’Disclosures about Pensions and other Postretirement Benefits,” establishingadditional annual disclosures about plan assets, investment strategy,measurement date, plan obligations and cash flows.  In addition, the revised standard establishedinterim disclosure requirements related to the net periodic benefit costrecognized and contributions paid or expected to be paid during the currentfiscal year.  The new annual disclosuresare effective for financial statements with fiscal years ending after December15, 2003 and the interim-period disclosures are effective for interim periodsbeginning after December 15, 2003. Barnwell adopted the interim disclosures in its quarter ending March 31,2004 and adopted the annual disclosures in its fiscal year ending September 30,2004.  The adoption of the revisions toSFAS No. 132 had no impact on Barnwell’s financial condition, results ofoperations or liquidity.

 

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

 

LIQUIDITY ANDCAPITAL RESOURCES

 

### Cash Flows, Debt andAvailable Credit

 

Cash flows provided by operations totaled$6,148,000 for fiscal 2004, a decrease of $2,367,000 as compared to $8,515,000of cash flows provided by operations for the same period in the prioryear.  The decrease was primarily due toan increase in income tax payments in the current period as compared to thesame period in the prior year.  Incometaxes of $4,495,000 were paid in fiscal 2004, including $430,000 for taxes duefor fiscal 2003, as compared to $2,961,000 in fiscal 2003, an increase of$1,534,000.  Income tax payments alsoinclude $450,000 of installments due on the gain on sale of an

 

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interest in leasehold land,whereas cash flows from the sale of an interest in leasehold land are reportedunder cash flows provided by investing activities.  Cash flow from operations also decreased dueto $733,000 of bonuses issued in conjunction with the consummation of KaupulehuDevelopments’ sale of an interest in leasehold land in February 2004.  Partially offsetting these decreases in cashflows provided by operations was an increase in pre-tax operational cash flowsgenerated by the oil and natural gas segment.

 

Cashflows provided by investing activities totaled $1,557,000 for fiscal 2004, anincrease of $9,306,000 from cash used in investing activities of $7,749,000 infiscal 2003.  The increase is dueprimarily to Kaupulehu Developments’ sale of an interest in leasehold land,which generated $10,805,000 of cash, net of associated costs.  In addition, cash flows from KaupulehuDevelopments’ sale of development rights, net of associated costs, increased$500,000 to $2,497,000 in the current period, as compared to $1,997,000 in thesame period in the prior year.  Barnwellalso fully collected a $1,311,000 note receivable, and received $440,000 ofproceeds, net of associated costs, from the sale of land that was previouslyutilized as a contract drilling storage yard. Partially offsetting the increase was a $2,293,000 increase in capitalexpenditures, primarily oil and natural gas capital expenditures, as comparedto the prior year period, and $1,387,000 of investments in six-month andone-year certificates of deposit at various financial institutions, net ofproceeds from matured certificates of deposit, in fiscal 2004; there were nosuch investments in the same period of the prior year.

 

Duringfiscal 2004, Barnwell purchased the office space it was previously leasing for$1,057,000, of which $883,000 was financed by a note payable to a Hawaii bankand the remainder was paid in cash.  Thenote was payable in monthly principal payments of approximately $3,000, plusinterest, and was due in full in December 2006. Barnwell repaid the note in full in fiscal 2004.  The space purchased has 4,662 useable squarefeet in an office building in downtown Honolulu.

 

Duringfiscal 2004, Barnwell used $4,946,000 of cash flows for financing activities, a$4,311,000 increase from $635,000 in the same period of the prior year.  Barnwell distributed $2,633,000 to minorityinterests resulting from Kaupulehu Developments’ sales of leasehold landinterest and development rights, a $2,358,000 increase in minoritydistributions from $275,000 during the same period of the prior year.  Barnwell also made $1,408,000 of long-termdebt repayments, a $1,048,000 increase from debt repayments of $360,000 in thesame period of the prior year; of the $1,408,000 in current period debt netrepayments, $883,000 was for the full repayment of the note payable to a Hawaiibank and $525,000 was paid toward the credit facility with the Royal Bank ofCanada.  Barnwell also paid $1,123,000 individends (no dividends were paid in the prior year period), and collected$218,000 in proceeds from employees’ exercise of stock options (no stockoptions were exercised in the prior year period).

 

Dividendspaid by Barnwell in fiscal 2004 were as follows:

 
| **Declaration  Date** | ** ** | **Value Per  Share** | ** ** | **Record  Date** | ** **         | **Payment  Date** | ** **          |
|-----------------------|------------|----------------------|------------|------------------|--------------------|-------------------|---------------------|
| August 2004           |       | $                    | 0.15       |             | August 27,  2004   |              | September  15, 2004 |   |
| February 2004         |       | $                    | 0.50       |             | February 27,  2004 |              | March 12,  2004     |   |
| December 2003         |       | $                    | 0.20       |             | December 22,  2003 |              | January 6,  2004    |   |

 

39

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TheRoyal Bank of Canada has renewed Barnwell’s credit facility through April 2005at an unchanged $19,000,000 Canadian dollars, approximately U.S. $15,000,000,at September 30, 2004, and with an increase in the interest rate of U.S. dollardenominated borrowings from the London Interbank Offer Rate plus 1-3/4% to theLondon Interbank Offer Rate plus 2%.

 

AtSeptember 30, 2004, Barnwell had $4,497,000 in cash and cash equivalents,$1,387,000 in certificates of deposit with maturity dates ranging from October2004 to April 2005, $1,331,000 in working capital, and approximately $4,800,000of available credit under its credit facility with the Royal Bank ofCanada.  Barnwell believes its currentcash balances, certificates of deposit, future cash flows from operations, landsegment sales, and available credit will be sufficient to fund its estimatedcapital expenditures for at least the next twelve months and meet the repaymentschedule on its long-term debt.  However,if oil and natural gas production remains at or declines from current levels oroil and natural gas prices decline from current levels, current working capitalbalances and cash flows generated by operations may not be sufficient to fundBarnwell’s current projected level of oil and natural gas capital expenditures,in which case Barnwell may fund capital expenditures with funds generated byland segment sales, long-term debt borrowings, or it may reduce future oil andnatural gas capital expenditures. Additionally, if Barnwell’s credit facility with a Canadian bank isreduced below the current level of borrowings under the facility after theApril 2005 review, Barnwell may be required to reduce expenditures or seekalternative sources of financing to make any required payments under thefacility.

 

### Oil and Natural GasCapital Expenditures

 

Infiscal 2004, Barnwell’s oil and natural gas capital expenditures, includingaccrued capital expenditures, increased $817,000 (7%) from $11,059,000 infiscal 2003 to $11,876,000 in fiscal 2004. Barnwell participated in drilling 144 (14.6 net) wells, 134 (11.2 net) ofwhich were successful, and the recompletion of 33 wells (4.6 net wells), 90% ofwhich were successful, and replaced 44% of oil production (including naturalgas liquids) and 63% of natural gas production. Barnwell’s participation in the drilling of 84 gross wells (2.6 netwells) was a result of Barnwell’s ownership of an average 3% working interestin a shallow development prospect in Southern Alberta.  The major areas of investments in fiscal 2004were in the Dunvegan, Balsam, Bonanza, Doris, Wood River and Progress areas ofAlberta.  In the Dunvegan area, Barnwellinvested $3,670,000 for the drilling of 27 gross development wells (2.4 netdevelopment wells) as part of the operator’s objective of increasing productionfrom the area.  Additionally, the operatorof the Dunvegan property plans to drill 24 gross wells (2.14 net wells) atDunvegan in fiscal 2005.  Barnwelloperated and supervised the drilling of eight wells in 2004.  Of the $11,876,000 total oil and natural gasproperties investments for fiscal 2004, $1,965,000 (17%) was for acquisition ofleases and lease rentals, $1,089,000 (9%) was for geological and geophysicalcosts, $6,449,000 (54%) was for intangible drilling costs, $2,240,000 (19%) wasfor production equipment, and $133,000 (1%) was for future site restoration andabandonment costs.

 

40

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Thefollowing table sets forth the gross and net numbers of oil and natural gaswells Barnwell participated in drilling and purchased for each of the lastthree fiscal years:

 
| ** **                                     | ** ** | **2004**  | ** ** | **2003** | ** ** | **2002**  | ** ** |
|------------------------------------------------|------------|-----------|------------|----------|------------|-----------|------------|
| ** **                                     | ** ** | **Gross** | ** ** | **Net**  | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Exploratory oil  and natural gas wells drilled | ** ** | **16**    | ** ** | **6.1**  |       | 13        |       | 3.6 |   | 5 |   | 0.9 |   |
|                                           |       |      |       |     |       |      |       |   |   |   |   |   |   |
| Development oil  and natural gas wells drilled | ** ** | **128**   | ** ** | **8.5**  |       | 52        |       | 11.1 |   | 11 |   | 4.5 |   |
|                                           |       |      |       |     |       |      |       |   |   |   |   |   |   |
| Successful oil  and natural gas wells drilled  | ** ** | **134**   | ** ** | **11.2** |       | 53        |       | 11.1 |   | 12 |   | 4.2 |   |

 

Barnwell estimates that oil and natural gas capitalexpenditures for fiscal 2005 will range from $12,500,000 to $14,000,000.  This estimated amount may increase ordecrease as dictated by management’s assessment of the oil and gas environment andprospects.

 

41

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Item 7.FINANCIALSTATEMENTS

 

 

**Report ofIndependent** Registered PublicAccounting Firm

 

 

The Board of Directors

Barnwell Industries, Inc.:

 

We have audited the accompanying consolidated balance sheetsof Barnwell Industries, Inc. and subsidiaries as of September 30, 2004 and2003, and the related consolidated statements of operations, stockholders’equity and comprehensive income (loss), and cash flows for each of the years inthe three-year period ended September 30, 2004. These consolidatedfinancial statements are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these consolidated financialstatements based on our audits.

 

We conducted our auditsin accordance with the standards of the Public Company Accounting OversightBoard (United States). Those standards require that we plan and perform theaudit to obtain reasonable assurance about whether the financial statements arefree of material misstatement. An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the financial statements. Anaudit also includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basisfor our opinion.

 

In our opinion, theconsolidated financial statements referred to above present fairly, in allmaterial respects, the financial position of Barnwell Industries, Inc. andsubsidiaries as of September 30, 2004 and 2003, and the results of theiroperations and their cash flows for each of the years in the three-year periodended September 30, 2004, in conformity with U.S. generally acceptedaccounting principles.

 

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

 

 
| /s/KPMG LLP      |   |
|------------------|--------|
|             |
| Honolulu, Hawaii |
| December 6, 2004 |

 

42

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BARNWELLINDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCESHEETS

 
| ** **                                                                                                                                                   | ** ** | **September  30,** | ** **     |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------|----------------|
| ** **                                                                                                                                                   | ** ** | **2004**           | ** **     | **2003** | ** ** |
| ASSETS                                                                                                                                                       |       |               | ** **     |   |   |
| CURRENT ASSETS:                                                                                                                                              |       |               | ** **     |   |   |
| Cash and cash  equivalents                                                                                                                                   | ** ** | **$**              | **4,497,000**  | ** ** | $ | 1,648,000 |   |
| Certificates of  deposit                                                                                                                                     | ** ** | **1,387,000**      | ** **     | — |   |
| Accounts  receivable, net                                                                                                                                    | ** ** | **5,513,000**      | ** **     | 2,866,000 |   |
| Note receivable                                                                                                                                              | ** ** | **—**         | ** **     | 1,311,000 |   |
| Costs and  estimated earnings in excess of billings on uncompleted contracts                                                                                 | ** ** | **493,000**        | ** **     | 166,000 |   |
| Deferred income  taxes                                                                                                                                       | ** ** | **1,231,000**      | ** **     | 515,000 |   |
| Prepaid expenses  and other current assets                                                                                                                   | ** ** | **1,081,000**      | ** **     | 675,000 |   |
| TOTAL CURRENT  ASSETS                                                                                                                                        | ** ** | **14,202,000**     | ** **     | 7,181,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| INVESTMENT IN  LAND                                                                                                                                          | ** ** | **3,033,000**      | ** **     | 6,508,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| PROPERTY AND  EQUIPMENT, NET                                                                                                                                 | ** ** | **47,852,000**     | ** **     | 38,948,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| TOTAL ASSETS                                                                                                                                                 | ** ** | **$**              | **65,087,000** | ** ** | $ | 52,637,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| LIABILITIES AND  STOCKHOLDERS’ EQUITY                                                                                                                   |       |               | ** **     |   |   |
| CURRENT  LIABILITIES:                                                                                                                                        |       |               | ** **     |   |   |
| Accounts payable                                                                                                                                             | ** ** | **$**              | **3,199,000**  | ** ** | $ | 3,357,000 |   |
| Accrued  liabilities                                                                                                                                         | ** ** | **8,625,000**      | ** **     | 6,082,000 |   |
| Billings in  excess of costs and estimated earnings on uncompleted contracts                                                                                 | ** ** | **407,000**        | ** **     | 29,000 |   |
| Payable to joint  interest owners                                                                                                                            | ** ** | **604,000**        | ** **     | 608,000 |   |
| Income taxes  payable                                                                                                                                        | ** ** | **36,000**         | ** **     | 442,000 |   |
| TOTAL CURRENT  LIABILITIES                                                                                                                                   | ** ** | **12,871,000**     | ** **     | 10,518,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| LONG-TERM DEBT                                                                                                                                               | ** ** | **10,165,000**     | ** **     | 10,477,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| ASSET RETIREMENT  OBLIGATION                                                                                                                                 | ** ** | **1,775,000**      | ** **     | 1,432,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| DEFERRED INCOME  TAXES                                                                                                                                       | ** ** | **10,719,000**     | ** **     | 9,743,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| MINORITY  INTEREST                                                                                                                                           | ** ** | **408,000**        | ** **     | 834,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| COMMITMENTS AND  CONTINGENCIES                                                                                                                               |       |               | ** **     |   |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| STOCKHOLDERS’  EQUITY:                                                                                                                                  |       |               | ** **     |   |   |
| Common stock,  par value $0.50 per share:                                                                                                                    | ** ** | ** **         | ** **     |   |   |
| Authorized,  4,000,000 shares; 1,660,297 issued, 1,332,010 outstanding at September 30,  2004, 1,642,797 issued, 1,314,510 outstanding at September 30, 2003 | ** ** | **830,000**        | ** **     | 821,000 |   |
| Additional paid-in  capital                                                                                                                                  | ** ** | **3,399,000**      | ** **     | 3,139,000 |   |
| Retained  earnings                                                                                                                                           | ** ** | **29,605,000**     | ** **     | 22,018,000 |   |
| Accumulated  other comprehensive income (loss) - foreign currency translation adjustments                                                                    | ** ** | **169,000**        | ** **     | (1,491,000 | ) |
| Treasury stock,  at cost, 328,287 shares                                                                                                                     | ** ** | **(4,854,000**     | **)**          | (4,854,000 | ) |
| TOTAL  STOCKHOLDERS’ EQUITY                                                                                                                             | ** ** | **29,149,000**     | ** **     | 19,633,000 |   |
|                                                                                                                                                         |       |               | ** **     |   |   |
| TOTAL  LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                                                             | ** ** | **$**              | **65,087,000** | ** ** | $ | 52,637,000 |   |

 

See Notes toConsolidated Financial Statements

 

43

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BARNWELL INDUSTRIES,INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF OPERATIONS

 
| ** **                                             | ** ** | **Year ended September 30,** | ** **     |
|--------------------------------------------------------|------------|---------------------------------------------|----------------|
| ** **                                             | ** ** | **2004**                                    | ** **     | **2003** | ** ** | **2002** | ** ** |
| Revenues:                                              |       |                                        |           |   |   |   |   |
| Oil and natural  gas                                   | ** ** | **$**                                       | **23,270,000** |   | $ | 19,350,000 |   | $ | 11,320,000 |   |
| Sale of interest  in leasehold land, net               | ** ** | **7,330,000**                               |           | — |   | — |   |
| Sale of  development rights, net                       | ** ** | **2,497,000**                               |           | 720,000 |   | 120,000 |   |
| Contract  drilling                                     | ** ** | **3,690,000**                               |           | 2,050,000 |   | 3,480,000 |   |
| Gas processing  and other                              | ** ** | **1,183,000**                               |           | 1,560,000 |   | 960,000 |   |
| ** **                                             |       | **37,970,000**                              |           | 23,680,000 |   | 15,880,000 |   |
|                                                   |       |                                        |           |   |   |   |   |
| Costs and  expenses:                                   |       |                                        |           |   |   |   |   |
| Oil and natural  gas operating                         | ** ** | **5,403,000**                               |           | 4,192,000 |   | 3,108,000 |   |
| Contract  drilling operating                           | ** ** | **3,184,000**                               |           | 1,928,000 |   | 2,821,000 |   |
| General and  administrative                            | ** ** | **7,911,000**                               |           | 5,971,000 |   | 4,344,000 |   |
| Depletion,  depreciation and amortization              | ** ** | **6,761,000**                               |           | 4,333,000 |   | 3,648,000 |   |
| Interest  expense, net                                 | ** ** | **487,000**                                 |           | 442,000 |   | 296,000 |   |
| Minority  interest in earnings                         | ** ** | **2,207,000**                               |           | 309,000 |   | 62,000 |   |
|                                                   |       |                                        |           |   |   |   |   |
| ** **                                             |       | **25,953,000**                              |           | 17,175,000 |   | 14,279,000 |   |
|                                                   |       |                                        |           |   |   |   |   |
| Earnings before  income taxes                          | ** ** | **12,017,000**                              |           | 6,505,000 |   | 1,601,000 |   |
|                                                   |       |                                        |           |   |   |   |   |
| Provision for  income taxes                            | ** ** | **3,307,000**                               |           | 4,185,000 |   | 1,561,000 |   |
|                                                   |       |                                        |           |   |   |   |   |
| NET EARNINGS                                           | ** ** | **$**                                       | **8,710,000**  |   | $ | 2,320,000 |   | $ | 40,000 |   |
|                                                   |       |                                        |           |   |   |   |   |
| BASIC EARNINGS  PER COMMON SHARE                       | ** ** | **$**                                       | **6.58**       |   | $ | 1.76 |   | $ | 0.03 |   |
| DILUTED EARNINGS  PER COMMON SHARE                     | ** ** | **$**                                       | **6.19**       |   | $ | 1.69 |   | $ | 0.03 |   |
|                                                   |       |                                        |           |   |   |   |   |
| WEIGHTED AVERAGE  NUMBER OF COMMON SHARES OUTSTANDING: | ** ** | ** **                                  |           |   |   |   |   |
| BASIC                                                  | ** ** | **1,323,947**                               |           | 1,314,510 |   | 1,313,915 |   |
|                                                   |       |                                        |           |   |   |   |   |
| DILUTED                                                | ** ** | **1,406,895**                               |           | 1,369,595 |   | 1,357,181 |   |

 

See Notes to ConsolidatedFinancial Statements

 

44

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BARNWELL INDUSTRIES, INC.AND SUBSIDIARIES

CONSOLIDATEDSTATEMENTS OF CASH FLOWS

 
| ** **                                                                                             | ** ** | **Year ended September 30,** | ** **    |
|--------------------------------------------------------------------------------------------------------|------------|---------------------------------------------|---------------|
| ** **                                                                                             | ** ** | **2004**                                    | ** **    | **2003** | ** ** | **2002** | ** ** |
| Cash flows from  operating activities:                                                                 |       |                                        | ** **    |   |   |   |   |
| Net earnings                                                                                           | ** ** | **$**                                       | **8,710,000** | ** ** | $ | 2,320,000 |   | $ | 40,000 |   |
| Adjustments to  reconcile net earnings to net cash provided by operating activities:                   |       |                                        | ** **    |   |   |   |   |
| Depreciation,  depletion and amortization                                                              | ** ** | **6,761,000**                               | ** **    | 4,333,000 |   | 3,648,000 |   |
| Minority  interest in earnings                                                                         | ** ** | **2,207,000**                               | ** **    | 309,000 |   | 62,000 |   |
| Accretion of  asset retirement obligation                                                              | ** ** | **100,000**                                 | ** **    | 85,000 |   | — |   |
| Gain on sale of  contract drilling yard                                                                | ** ** | **(139,000**                                | **)**         | — |   | — |   |
| Deferred income taxes                                                                        | ** ** | **(307,000**                                | **)**         | 709,000 |   | 405,000 |   |
| Sale of development rights, net                                                    | ** ** | **(2,497,000**                              | **)**         | (720,000 | ) | (120,000 | ) |
| Sale of interest  in leasehold land, net                                                | ** ** | **(7,330,000**                              | **)**         | — |   | — |   |
|                                                                                                   |       |                                        | ** **    |   |   |   |   |
| ** **                                                                                             |       | **7,505,000**                               | ** **    | 7,036,000 |   | 4,035,000 |   |
| Increase (decrease) from changes in  current assets and liabilities | ** ** | **(1,357,000**                              | **)**         | 1,479,000 |   | (2,587,000 | ) |
|                                                                                                   |       |                                        | ** **    |   |   |   |   |
| Net cash provided by operating activities                                     | ** ** | **6,148,000**                               | ** **    | 8,515,000 |   | 1,448,000 |   |
|                                                                                                   |       |                                        | ** **    |   |   |   |   |
| Cash flows from investing activities:                                              |       |                                        | ** **    |   |   |   |   |
| Proceeds from sale of interest  in leasehold land, net                        | ** ** | **10,805,000**                              | ** **    | — |   | — |   |
| Proceeds from sale of development rights, net                            | ** ** | **2,497,000**                               | ** **    | 1,997,000 |   | 1,997,000 |   |
| Proceeds from  collection of notes receivable                                                          | ** ** | **1,311,000**                               | ** **    | 70,000 |   | 100,000 |   |
| Proceeds from  matured certificates of deposit                                                         | ** ** | **595,000**                                 | ** **    | — |   | — |   |
| Proceeds from  sale of contract drilling yard, net                                                     | ** ** | **440,000**                                 | ** **    | — |   | — |   |
| Investments in  certificates of deposit                                                                | ** ** | **(1,982,000**                              | **)**         | — |   | — |   |
| Capital expenditures                                                                              | ** ** | **(12,109,000**                             | **)**         | (9,816,000 | ) | (5,644,000 | ) |
|                                                                                                   |       |                                        | ** **    |   |   |   |   |
| Net cash provided  by (used in) investing activities                               | ** ** | **1,557,000**                               | ** **    | (7,749,000 | ) | (3,547,000 | ) |
|                                                                                                   |       |                                        | ** **    |   |   |   |   |
| Cash flows from financing activities:                                              |       |                                        | ** **    |   |   |   |   |
| Distributions to minority interest partners                                        | ** ** | **(2,633,000**                              | **)**         | (275,000 | ) | (278,000 | ) |
| Repayments of long-term debt                                                            | ** ** | **(1,408,000**                              | **)**         | (360,000 | ) | (370,000 | ) |
| Payment of dividends                                                                         | ** ** | **(1,123,000**                              | **)**         | — |   | (394,000 | ) |
| Proceeds from  exercise of stock options                                                               | ** ** | **218,000**                                 | ** **    | — |   | — |   |
| Repayments of  notes payable                                                                           | ** ** | **—**                                  | ** **    | — |   | (2,209,000 | ) |
| Long-term debt borrowings                                                                    | ** ** | **—**                                  | ** **    | — |   | 1,711,000 |   |
|                                                                                                   | ** ** | ** **                                  | ** **    |   |   |   |   |
| Net cash used in financing activities                                         | ** ** | **(4,946,000**                              | **)**         | (635,000 | ) | (1,540,000 | ) |
|                                                                                                   |       |                                        | ** **    |   |   |   |   |
| Effect of exchange rate  changes on cash and cash equivalents  | ** ** | **90,000**                                  | ** **    | 28,000 |   | (26,000 | ) |
|                                                                                                   |       |                                        | ** **    |   |   |   |   |
| Net increase (decrease) in  cash and cash equivalents                    | ** ** | **2,849,000**                               | ** **    | 159,000 |   | (3,665,000 | ) |
|                                                                                                   |       |                                        | ** **    |   |   |   |   |
| Cash and cash equivalents at beginning of year                      | ** ** | **1,648,000**                               | ** **    | 1,489,000 |   | 5,154,000 |   |
|                                                                                                   |       |                                        | ** **    |   |   |   |   |
| Cash and cash equivalents at end of year                            | ** ** | **$**                                       | **4,497,000** | ** ** | $ | 1,648,000 |   | $ | 1,489,000 |   |
|                                                                                                        |            |                                             |               |  |  |  |  |  |  |  |  |

 

See Notes to Consolidated Financial Statements

 

45

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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME(LOSS)Years ended September 30, 2004, 2003 and 2002

 
| ** **                                                                                 | ** ** | **Common  Stock** | ** ** | **Additional  Paid-In  Capital** | ** ** | **Comprehensive  Loss** | ** ** | **Retained  Earnings** | ** ** | **Accumulated  Other  Comprehensive  Income (Loss)** | ** ** | **Treasury  Stock** | ** ** | **Total  Stockholders’  Equity** | ** ** |
|--------------------------------------------------------------------------------------------|------------|-------------------|------------|----------------------------------|------------|-------------------------|------------|------------------------|------------|------------------------------------------------------|------------|---------------------|------------|---------------------------------------|------------|
| Balance at  September 30, 2001                                                             |       | $                 | 821,000    |                             | $          | 3,105,000               |       |                   |       | $                                                    | 19,855,000 |                | $          | (3,797,000                            | )          | $ | (4,891,000 | ) | $ | 15,093,000 |   |
|                                                                                       |       |              |       |                             |       |                    |       |                   |       |                                                 |       |                |       |                                  |       |
| Conversion of  debentures to common stock at $20.00 per share                              |       |              |       | 34,000                           |       |                    |       |                   |       |                                                 |       | 37,000              |       | 71,000                                |       |
|                                                                                       |       |              |       |                             |       |                    |       |                   |       |                                                 |       |                |       |                                  |       |
| Dividends  declared ($0.15 per share)                                                 |       |              |       |                             |       |                    |       | (197,000               | )          |                                                 |       |                |       | (197,000                              | )          |
|                                                                                       |       |              |       |                             |       |                    |       |                   |       |                                                 |       |                |       |                                  |       |
| Comprehensive  loss:                                                                       |       |              |       |                             |       |                    |       |                   |       |                                                 |       |                |       |                                  |       |
| Net earnings                                                                               |       |              |       |                             |       | $                       | 40,000     |                   | 40,000     |                                                 |       |                |       |                                  | 40,000     |   |
| Other  comprehensive loss, net of income taxes - foreign currency translation  adjustments |       |              |       |                             |       | (86,000                 | )          |                   |       | (86,000                                              | )          |                |       | (86,000                               | )          |
| Total  comprehensive loss                                                                  |       |              |       |                             |       | $                       | (46,000    | )                      |       |                                                 |       |                |       |                                  |       |   |
|                                                                                       |       |              |       |                             |       |                    |       |                   |       |                                                 |       |                |       |                                  |       |
| At September 30,  2002                                                                     |       | $                 | 821,000    |                             | $          | 3,139,000               |       |                   |       | $                                                    | 19,698,000 |                | $          | (3,883,000                            | )          | $ | (4,854,000 | ) | $ | 14,921,000 |   |

 

 

 

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BARNWELLINDUSTRIES, INC. AND SUBSIDARIES

CONSOLIDATEDSTATEMENTS OF STOCKHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS)

Years endedSeptember 30, 2004, 2003, and 2002

 
| ** **                                                                                  | ** ** | **Common  Stock** | ** ** | **Additional  Paid-In  Capital** | ** ** | **Comprehensive  Income** | ** ** | **Retained  Earnings** | ** ** | **Accumulated  Other  Comprehensive  Income (Loss)** | ** ** | **Treasury  Stock** | ** ** | **Total  Stockholders’  Equity** | ** ** |
|---------------------------------------------------------------------------------------------|------------|-------------------|------------|----------------------------------|------------|---------------------------|------------|------------------------|------------|------------------------------------------------------|------------|---------------------|------------|---------------------------------------|------------|
| Balance at  September 30, 2002                                                              |       | $                 | 821,000    |                             | $          | 3,139,000                 |       |                   |       | $                                                    | 19,698,000 |                | $          | (3,883,000                            | )          | $ | (4,854,000 | ) | $ | 14,921,000 |   |
|                                                                                        |       |              |       |                             |       |                      |       |                   |       |                                                 |       |                |       |                                  |       |
| Comprehensive  income:                                                                      |       |              |       |                             |       |                      |       |                   |       |                                                 |       |                |       |                                  |       |
| Net earnings                                                                                |       |              |       |                             |       | $                         | 2,320,000  |                   | 2,320,000  |                                                 |       |                |       |                                  | 2,320,000  |   |
| Other comprehensive  income, net of income taxes - foreign currency translation adjustments |       |              |       |                             |       | 2,392,000                 |       |                   |       | 2,392,000                                            |       |                |       | 2,392,000                             |       |
| Total  comprehensive income                                                                 |       |              |       |                             |       | $                         | 4,712,000  |                   |       |                                                 |       |                |       |                                  |       |   |
|                                                                                        |       |              |       |                             |       |                      |       |                   |       |                                                 |       |                |       |                                  |       |
| At September 30,  2003                                                                      |       | $                 | 821,000    |                             | $          | 3,139,000                 |       |                   |       | $                                                    | 22,018,000 |                | $          | (1,491,000                            | )          | $ | (4,854,000 | ) | $ | 19,633,000 |   |

 

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BARNWELLINDUSTRIES, INC. AND SUBSIDARIES

CONSOLIDATEDSTATEMENTS OF STOCKHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS)

Years endedSeptember 30, 2004, 2003, and 2002

 
| ** **                                                                                   | ** ** | **Common  Stock** | ** **  | **Additional  Paid-In  Capital** | ** ** | **Comprehensive  Income** | ** ** | **Retained  Earnings** | ** ** | **Accumulated  Other  Comprehensive  Income (Loss)** | ** **     | **Treasury  Stock** | ** ** | **Total  Stockholders’  Equity** | ** ** |
|----------------------------------------------------------------------------------------------|------------|-------------------|-------------|----------------------------------|------------|---------------------------|------------|------------------------|------------|------------------------------------------------------|----------------|---------------------|------------|---------------------------------------|------------|
| Balance at  September 30, 2003                                                          |       | $                 | 821,000     |                             | $          | 3,139,000                 |       |                   |       | $                                                    | 22,018,000     |                | $          | (1,491,000                            | )          | $ | (4,854,000 | ) | $ | 19,633,000 |   |
|                                                                                         |       |              |        |                             |       |                      |       |                   |       |                                                 |           |                |       |                                  |       |
| Exercise of stock  options, 17,500 shares                                                    |       | 9,000             |        | 209,000                          |       |                      |       |                   |       |                                                 |           |                |       | 218,000                               |       |
|                                                                                         |       |              |        |                             |       |                      |       |                   |       |                                                 |           |                |       |                                  |       |
| Tax benefit from  employee stock option transactions                                         |       |              |        | 51,000                           |       |                      |       |                   |       |                                                 |           |                |       | 51,000                                |       |
|                                                                                         |       |              |        |                             |       |                      |       |                   |       |                                                 |           |                |       |                                  |       |
| Dividends  declared ($0.85 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**                                                                   | ** ** | **$**             | **830,000** | ** **                       | **$**      | **3,399,000**             | ** ** | ** **             | ** ** | **$**                                                | **29,605,000** | ** **          | **$**      | **169,000**                           | ** ** | **$** | **(4,854,000** | **)** | **$** | **29,149,000** | ** ** |

 

See Notes to Consolidated Financial Statements

 

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**BARNWELL INDUSTRIES, INC.**

**AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED****FINANCIAL STATEMENTS**

**YEARS ENDED SEPTEMBER 30, 2004,2003 AND 2002**

 

**1.****             DESCRIPTION OF THE REPORTING ENTITY ANDBUSINESS**

 

The consolidated financial statements includethe accounts of Barnwell Industries, Inc. and all majority-owned subsidiaries,including an indirect 77.6%-owned land development general partnership,(collectively referred to herein as “Barnwell”).  All significant intercompany accounts andtransactions have been eliminated.

 

During its last three fiscal years, Barnwell wasengaged in exploring for, developing, producing and selling oil and natural gasin Canada, investing in leasehold land in Hawaii, and drilling wells andinstalling and repairing water pumping systems in Hawaii.  Barnwell’s oil and natural gas activitiescomprise its largest business segment. Approximately 61% of Barnwell’s revenues and 90% of Barnwell’s capitalexpenditures for the fiscal year ended September 30, 2004 were attributable toits oil and natural gas activities. Barnwell’s land investment segment revenues, including land segmentrevenues reported as “Gas processing and other” revenues in the ConsolidatedStatements of Operations, accounted for 27% of fiscal 2004 revenues; Barnwell’scontract drilling activities accounted for 10% of fiscal 2004 revenues; andother revenues comprised 2% of fiscal 2004 revenues.

 

**2.****             SIGNIFICANT ACCOUNTING POLICIES**

 

Cash and Cash Equivalentsand Certificates of Deposit

 

Cash and cash equivalentsinclude cash on hand, demand deposits and short-term investments with originalmaturities of three months or less.  AtSeptember 30, 2004, Barnwell had $1,387,000 of certificates of deposit atvarious financial institutions with maturities ranging from October 2004 toApril 2005.  Due to their original maturities,these certificates of deposit are excluded from cash and cash equivalents andare reported separately on the Consolidated Balance Sheets.

 

# Trade Accounts Receivable

 

Trade accounts receivableare recorded at the invoiced amount and do not bear interest.  The allowance for doubtful accounts isBarnwell’s best estimate of the amount of probable credit losses in Barnwell’sexisting 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 and Natural GasProperties

 

Barnwell uses the full costmethod of accounting under which all costs incurred in the acquisition,exploration and development of oil and natural gas reserves, including unsuccessfulwells,

 

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are capitalized until such time as the aggregate of such costs, on acountry-by-country basis, equals the discounted present value (at 10%) ofBarnwell’s estimated future net cash flows from estimated production of provedoil and natural gas reserves, as determined by independent petroleum engineers,less related income tax effects.  Anycapitalized costs, net of oil and gas related deferred income taxes, in excessof the discounted present value of proved properties and the lower of cost orestimated fair value of unproved properties are charged to expense.  Depletion of all such costs, except costsrelated to major development projects, is provided by the unit-of-productionmethod based upon proved oil and natural gas reserves of all properties on acountry-by-country basis.  Investments inmajor development projects are not amortized until either proved reserves areassociated with the projects or impairment has been determined.  At September 30, 2004, Barnwell had noinvestments in major oil and natural gas development projects that were notbeing amortized.  General andadministrative costs related to oil and natural gas operations are expensed asincurred.  Estimated future siterestoration and abandonment costs are capitalized as part of the carryingamount of oil and natural gas properties and depleted over the life of therelated reserves.  Proceeds from thedisposition of minor producing oil and natural gas properties are credited tothe cost of oil and natural gas properties. Gains or losses are recognized on the disposition of significant oil andnatural gas properties.

 

Investment in Land andRevenue Recognition

 

Barnwell’s investment inland is comprised of development rights under option; rights to receivepercentage and interim payments; leasehold land interests in land zoned resort/residentialwhich are under right of negotiation; and land zoned conservation which is notunder option or right of negotiation. Investment in land is reported at the lower of the asset carrying valueor fair value, less costs to sell, and is evaluated for impairment wheneverevents or changes in circumstances indicate that the recorded investmentbalance may not be fully recoverable.

 

Costs incurred for theacquisition and improvement of leasehold land interests, including capitalizedinterest, are included in the consolidated balance sheets under the caption “Investmentin Land.”

 

Sales of developmentrights under option and revenues from the sale of Increment I of leasehold landinterests are accounted for under the cost recovery method.  Under the cost recovery method, no operatingprofit is recognized until cash received exceeds the cost and the estimatedfuture costs related to the development rights sold.

 

Contract Drilling

 

Revenues, costs andprofits 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.

 

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Long-lived Assets

 

Long-lived assets to beheld and used, other than oil and natural gas properties, are evaluated forimpairment whenever events or changes in circumstances indicate that thecarrying 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.

 

Drilling Rigs, OtherProperty and Equipment

 

Drilling rigs and otherproperty and equipment are stated at cost. Depreciation is computed using the straight-line method based onestimated useful lives.

 

Inventories

 

Inventories are comprisedof drilling materials and are valued at the lower of weighted average cost ormarket value.

 

Environmental

 

Barnwell is subject toextensive environmental laws and regulations. These laws, which are constantly changing, regulate the discharge ofmaterials into the environment and maintenance of surface conditions and mayrequire Barnwell to remove or mitigate the environmental effects of thedisposal or release of petroleum or chemical substances at various sites.  Environmental expenditures are expensed orcapitalized depending on their future economic benefit.  Expenditures that relate to an existingcondition caused by past operations and that have no future economic benefitsare expensed.  Liabilities forexpenditures of a noncapital nature are recorded when environmental assessmentand/or remediation is probable, and the costs can be reasonably estimated.

 

Asset RetirementObligation

 

On October 1, 2002,Barnwell adopted Statement ofFinancial Accounting Standards (“SFAS”) No. 143, “Accounting for AssetRetirement Obligations,” which requires that the fair value of a liability foran asset retirement obligation be recognized in the period in which it isincurred if a reasonable estimate of fair value can be made.  Barnwell’s estimated site restoration andabandonment costs of its oil and natural gas properties are capitalized as partof the carrying amount of oil and natural gas properties and depleted over thelife of the related reserves.  Theliability is accreted at the end of each period through charges to oil andnatural gas operating expense.  If theobligation is settled for other than the carrying amount of the liability,Barnwell will recognize a gain or loss on settlement.

 

InSeptember 2004, the Securities and Exchange Commission (“SEC”) released StaffAccounting Bulletin (“SAB”) No. 106 which expresses the SEC’s views regardingthe application of SFAS No. 143, “Accounting for Asset Retirement Obligations,”by oil and gas producing companies following the full cost accountingmethod.  SAB No. 106 addresses thecalculation of ceiling tests for full-cost oil and gas companies, depreciation,depletion and amortization as affected by the adoption of SFAS No. 143, as wellas the related required disclosures. Barnwell adopted the provisions of SAB No. 106 during the

 

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year ended September 30, 2004. The adoption of SAB No. 106 had no material impact on Barnwell’sfinancial condition, results of operations or liquidity.

 

Income Taxes

 

Deferred income taxes aredetermined using the asset and liability method.  Deferred tax assets and liabilities arerecognized for the estimated future tax consequences attributable todifferences between the financial statement carrying amounts of existing assetsand liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax ratesin effect for the year in which those temporary differences are expected to berecovered or settled.  The effect ondeferred tax assets and liabilities of a change in tax rates is recognized inincome in the period that includes the enactment date.

 

Earnings Per Common Share

 

Basic earnings per shareexcludes dilution and is computed by dividing net earnings by theweighted-average number of common shares outstanding for the period.  Diluted earnings per share includes thepotentially dilutive effect of outstanding common stock options and securitieswhich are convertible to common shares.

 

Reconciliations between the numerator anddenominator of the basic and diluted earnings per share computations for theyears ended September 30, 2004, 2003 and 2002 are as follows:

 
| ** **                                            | ** ** | **September  30, 2004**        | ** **    |
|-------------------------------------------------------|------------|--------------------------------|---------------|
| ** **                                            | ** ** | **Net  Earnings  (Numerator)** | ** **    | **Shares  (Denominator)** | ** ** | **Per-Share  Amount** | ** ** |
| Basic earnings  per share                             | ** ** | **$**                          | **8,710,000** | ** ** | **1,323,947** | ** ** | **$** | **6.58** | ** ** |
| Effect of  dilutive securities - common stock options | ** ** | **—**                     | ** **    | **82,948** | ** ** | ** ** | ** ** |
| Diluted earnings  per share                           | ** ** | **$**                          | **8,710,000** | ** ** | **1,406,895** | ** ** | **$** | **6.19** | ** ** |
|                                                       |            |                                |               |  |  |  |  |  |  |  |  |

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

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

 

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Assumed conversion of convertible debentures to6,750 shares of common stock was excluded from the computation of dilutedearnings per share for the period that the debentures were outstanding duringthe year ended September 30, 2003 because the effect would have beenantidilutive (the convertible debentures were repaid in full on June 30,2003).  Assumed conversion of convertibledebentures to acquire 18,000 shares of common stock at September 30, 2002 wasexcluded from the computation of diluted earnings per share for the year endedSeptember 30, 2002 because the effect would have been antidilutive.

 

# Stock-Based Compensation

 

Barnwell applies the provisions of AccountingPrinciples Board Opinion No. 25 in accounting for stock-based compensation andadopted the disclosure-only provisions of SFAS No. 123, “Accounting forStock-Based Compensation,” as amended by SFAS No. 148, “Accounting forStock-Based Compensation – Transition and Disclosure.”  Had compensation cost for stock optionsgranted since October 1, 1995 been determined based on the fair value method ofmeasuring stock-based compensation provisions of SFAS No. 123, Barnwell’s netearnings (loss) and basic and diluted earnings (loss) per share would have beenas follows:

 
| ** **                                                                                                                 | ** ** | **Year  ended September 30,** | ** **    |
|----------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------|---------------|
| ** **                                                                                                                 | ** ** | **2004**                      | ** **    | **2003** | ** ** | **2002** | ** ** |
| Net earnings, as  reported                                                                                                 | ** ** | **$**                         | **8,710,000** | ** ** | $ | 2,320,000 |   | $ | 40,000 |   |
| Less stock-based  employee compensation expense determined under the fair value based method,  net of related income taxes | ** ** | **(6,000**                    | **)**         | (44,000 | ) | (95,000 | ) |
| Pro-forma net  earnings (loss)                                                                                             | ** ** | **$**                         | **8,704,000** | ** ** | $ | 2,276,000 |   | $ | (55,000 | ) |
|                                                                                                                       |       |                          | ** **    |   |   |   |   |
| Basic Earnings  (Loss) Per Share:                                                                                          |       |                          | ** **    |   |   |   |   |
| As reported                                                                                                                | ** ** | **$**                         | **6.58**      | ** ** | $ | 1.76 |   | $ | 0.03 |   |
| Pro forma                                                                                                                  | ** ** | **$**                         | **6.57**      | ** ** | $ | 1.73 |   | $ | (0.04 | ) |
|                                                                                                                       |       |                          | ** **    |   |   |   |   |
| Diluted Earnings  (Loss) Per Share:                                                                                        |       |                          | ** **    |   |   |   |   |
| As reported                                                                                                                | ** ** | **$**                         | **6.19**      | ** ** | $ | 1.69 |   | $ | 0.03 |   |
| Pro forma                                                                                                                  | ** ** | **$**                         | **6.19**      | ** ** | $ | 1.66 |   | $ | (0.04 | ) |
|                                                                                                                            |            |                               |               |  |  |  |  |  |  |  |  |  |  |

 

Fair value measurement ofthe options was based on a option-pricing model which included assumptions of aweighted average expected life of 5.97 years, expected volatility of 30%,weighted average risk-free interest rate of 6.12%, and an expected dividendyield of 0%.

 

# Foreign Currency Translation

 

Assets and liabilities of foreign operations andsubsidiaries are translated at the year-end exchange rate and resultingtranslation gains or losses are accounted for in a stockholders’ equity accountentitled “accumulated other comprehensive income (loss) - foreign currencytranslation adjustments.”  Operatingresults of foreign subsidiaries are translated at average exchange rates duringthe period. Realized foreign currency transaction gains or losses were notmaterial in fiscal years 2004, 2003, and 2002.

 

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Use of Estimates in thePreparation of Financial Statements

 

The preparation offinancial statements in conformity with accounting principles generallyaccepted in the United States of America requires management to make estimatesand 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. Significant assumptions are required in the valuation of deferred taxassets and proved oil and natural gas reserves, and such assumptions may impactthe amount at which deferred tax assets and oil and natural gas properties arerecorded.

 

Reclassification

 

Certain reclassificationshave been made to the September 30, 2003 consolidated balance sheet to conformto classifications used in the September 30, 2004  consolidated balance sheet.

 

**3.****             ACCOUNTS RECEIVABLE AND CONTRACT COSTS**

 

Accounts receivable are net of allowances fordoubtful accounts of $10,000 as of September 30, 2004 and 2003.  Included in accounts receivable are contractretainage balances of $242,000 and $96,000 as of September 30, 2004 and2003, respectively.  These balances areexpected to be collected within one year, generally within 45 days after therelated contracts have received final acceptance and approval.

 

Costs and estimatedearnings on uncompleted contracts are as follows:

 
| ** **                               | ** ** | **September  30,** | ** **    |
|------------------------------------------|------------|--------------------|---------------|
| ** **                               | ** ** | **2004**           | ** **    | **2003** | ** ** |
| Costs incurred  on uncompleted contracts | ** ** | **$**              | **4,945,000** |   | $ | 1,667,000 |   |
| Estimated  earnings                      | ** ** | **482,000**        |          | 109,000 |   |
| ** **                               |       | **5,427,000**      |          | 1,776,000 |   |
| Less billings to  date                   | ** ** | **5,341,000**      |          | 1,639,000 |   |
| ** **                               |       | **$**              | **86,000**    |   | $ | 137,000 |   |
|                                          |            |                    |               |  |  |  |  |  |

 

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

 
| ** **                                                                   | ** ** | **September  30,** | ** **  |
|------------------------------------------------------------------------------|------------|--------------------|-------------|
| ** **                                                                   | ** ** | **2004**           | ** **  | **2003** | ** ** |
| Costs and  estimated earnings in excess of billings on uncompleted contracts | ** ** | **$**              | **493,000** |   | $ | 166,000 |   |
| Billings in  excess of costs and estimated earnings on uncompleted contracts | ** ** | **(407,000**       | **)**       | (29,000 | ) |
| ** **                                                                   |       | **$**              | **86,000**  | ** ** | $ | 137,000 |   |
|                                                                              |            |                    |             |  |  |  |  |  |  |

 

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**4.****             NOTE RECEIVABLE**

 

In January and February 2004, Nearco, Inc. repaid the$1,311,000 note payable to Barnwell in full plus all outstanding interest.

 

**5.****             INVESTMENT IN LAND**

 

Background

 

Barnwell owns a 77.6%controlling interest in Kaupulehu Developments, a Hawaii general partnershipthat owns interests in leasehold land and development rights for propertylocated approximately six miles north of the Kona International Airport in theNorth Kona District of the Island of Hawaii.  Between 1986 and 1989, Kaupulehu Developmentsobtained the state and county zoning changes necessary to permit development ofthe Four Seasons Resort Hualalai at Historic Ka’upulehu and Hualalai Golf Club,which opened in 1996, a second golf course, and single and multiple familyresidential units.  These projects weredeveloped on leasehold land acquired from Kaupulehu Developments by KaupulehuMakai Venture, an unrelated entity that is an affiliate of Kajima Corporationof Japan.

 

Rezoning and Partial Saleof Interest in Leasehold Land

 

In 1993, Kaupulehu Developments submitted a rezoningpetition to the State Land Use Commission and in 1998, filed an Application fora Project District zoning ordinance and a Special Management Area Use PermitPetition with the County of Hawaii to reclassify conservation-zoned land tozoning which allows resort/residential development.  In October 2001, Kaupulehu Developmentsreceived final approval for the reclassification.

 

On February 13, 2004, Kaupulehu Developments enteredinto a Purchase and Sale Agreement with WB KD Acquisition LLC (“WB”) by whichKaupulehu Developments transferred its leasehold interest in the approximately870 acres zoned for resort/residential development, in two increments, toWB.  There is no affiliation betweenKaupulehu Developments and WB.  WB is anaffiliate of Westbrook Partners LLC, an affiliate of the developers of the Kuki’oResort.  The first increment (“IncrementI”) is an area planned for approximately 80 single-family lots and a beach clubon the portion 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 the approximately870-acre property and is zoned for single-family and multi-family residentialunits and a golf course and clubhouse.

 

With respect to Increment I, Kaupulehu Developmentsreceived a non-refundable $11,550,000 payment (“Closing Payment”) and isentitled to receive payment of the following percentages of the gross proceedsgenerated from the sale by WB of single-family lots in Increment I (“PercentagePayments”): 9% of the gross proceeds from single-family lot sales up toaggregate gross proceeds of $100,000,000; 10% of such aggregate gross proceedsgreater than $100,000,000 but less than $300,000,000; and 14% of such aggregategross proceeds in excess of $300,000,000. If prior to December 31, 2005, Kaupulehu Developments has not receivedPercentage Payments equal to or greater than $2,500,000 in the aggregate, WBwill pay Kaupulehu Developments the amount by which the aggregate amount of allprior Percentage Payments made by WB to Kaupulehu Developments is less

 

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than $2,500,000.  If prior toDecember 31, 2006, Kaupulehu Developments has not received Percentage Payments(including payments in lieu of Percentage Payments as described in theimmediately preceding sentence) equal to or greater than $5,000,000 in theaggregate, then WB will pay Kaupulehu Developments the amount by which theaggregate amount of all such payments is less than $5,000,000.  Additionally, WB agreed to pay KaupulehuDevelopments non-refundable interim payments of $50,000 per month (“InterimPayments”), until the first to occur of the closing of the sale of the 40thsingle-family lot sold in Increment I or WB’s payment to Kaupulehu Developmentsof a total of $900,000 in Interim Payments subsequent to February 2004.  As of November 30, 2004, KaupulehuDevelopments has received a total of $450,000 of Interim Payments subsequent toFebruary 2004.  There is no assurance thatany future Interim Payments or any Percentage Payments will be received.

 

Kaupulehu Developments, WB and The Trustees of TheEstate of Bernice Pauahi Bishop (“KS”) also entered into an agreement (the “Step-InRights Agreement”) whereby if WB elects not to proceed with development ofIncrement I within the time frame set forth in the Step-In Rights Agreement,which may be extended by KS, or defaults under the terms of its lease with KS,Kaupulehu Developments would have the right to succeed to WB’s developmentrights and develop the property without any payment to WB.

 

In March 2004, WB commenced engineering ofinfrastructure, preparation of covenants, conditions and restrictions for acommunity association, and preparation of legal documents to enable real estatesales, and broke ground and graded several miles of access roads.  In late September 2004, WB began mass gradingof the first phase of 38 lots for development.

 

For Increment II, Kaupulehu Developments and WB agreedto use diligent efforts to negotiate, and attempt to document and enter into,prior to the date which is three (3) years following the closing of the sale ofthe first single-family lot in Increment I, an agreement with regards to theownership and development of Increment II. WB, however, may terminate such negotiations at any time without anyfurther obligation. Under the terms of the Step-In Rights Agreement, if at theend of three years following the closing of the sale of the first single-familylot in Increment I the parties have not entered into a definitive agreementwith respect to Increment II, the leasehold rights with respect to Increment IIwill revert to Kaupulehu Developments.

 

The sale of Kaupulehu Developments’ interest inIncrement I was accounted for by use of the cost recovery method, under whichno operating profit is recognized until cash received exceeds the cost and theestimated future costs related to the leasehold interest sold.  The revenue from the $11,550,000 Closing Paymentplus $350,000 of post-closing Interim Payments received in March throughSeptember 2004, 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 ofpreviously capitalized costs relating to Increment I.  The $7,330,000 of net revenue from theClosing Payment and Interim Payments for the year ended September 30, 2004 isrecorded in the Consolidated Statements of Operations as “Sale of interest inleasehold land, net.”  Operating profiton the Increment I transaction, after minority interest, totaled approximately$5,470,000 for the year ended September 30, 2004.  There were no sales of interests in leaseholdland in the years ended September 30, 2003 and 2002.  As no sales price or agreement with regardsto the ownership and development of Increment II has yet been determined, norevenues or cost of sales have been recognized on Increment II.

 

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Development Rights Under Option

 

The developmentrights held by Kaupulehu Developments are for residentially zoned leaseholdland within and adjacent to the Hualalai Golf Club and are under option toKaupulehu Makai Venture, an unrelated entity that is an affiliate of KajimaCorporation of Japan.  On December31, 2001, 2002 and 2003, Kaupulehu Makai Venture exercised the portion of itsdevelopment rights option due on those dates and paid Kaupulehu Developments$2,125,000 in both fiscal 2002 and 2003 and $2,656,000 in fiscal 2004.  At September 30, 2004, approximately 100acres remain under option.  Barnwellaccounts for sales of development rights under option by use of the costrecovery method.  Under the cost recoverymethod, no operating profit is recognized until cash received exceeds the costand the estimated future costs related to development rights sold.  Infiscal 2002, approximately $1,877,000 of the proceeds from the sales ofdevelopment rights were applied to reduce the carrying value of the underlyinginvestment in land.  Sales of developmentrights were further reduced in fiscal 2002 by $128,000 of fees related to thesale, and the remaining $120,000 of sales proceeds is recorded in theConsolidated Statements of Operations for fiscal 2002 as “Sale of developmentrights, net.”   In fiscal 2003,$1,277,000 of the proceeds from the sales of development rights were applied toreduce the carrying value of the underlying development rights recorded on theCondensed Consolidated Balance Sheets under the caption “Investment in land” tozero.  Sales of development rights werefurther reduced in fiscal 2003 by $128,000 of fees related to the sale and theremaining $720,000 of sales proceeds is recorded in the Consolidated Statementsof Operations for fiscal 2003 as “Sale of development rights, net.” In fiscal 2004, $2,656,000 of revenues attributable to the developmentrights sale  were reduced by $159,000 offees related to the sale, resulting in net revenues of $2,497,000 and a$1,950,000 operating profit, after minority interest, on the transaction.  There were no other costs deducted fromrevenues from the sale of development rights in fiscal 2004 as all capitalizedcosts associated with the development rights were expensed in previous yearsunder the cost recovery method.

 

The total amount of remaining future optionreceipts at September 30, 2004, if all options are fully exercised, is$18,593,750, comprised of seven payments of $2,656,250 due on each December 31of years 2004 to 2010.  If any annualoption payment is not made, the then remaining development right options willexpire.  There is no assurance that anyportion of the remaining options will be exercised.

 

Fees

 

The aforementioned $159,000 in fees ($112,000, net ofminority interest) on the proceeds from the sale of development rights and$693,000 ($486,000, net of minority interest) on the proceeds from the sale ofinterest in leasehold land for the year ended September 30, 2004 were paid toNearco, Inc., a company controlled by Mr. Terry Johnston, a director ofBarnwell and an indirect 21.8% owner of Kaupulehu Developments.  Under an agreement entered into in 1987,prior to Mr. Johnston’s election to Barnwell’s Board of Directors, Barnwell isobligated to pay Nearco 2% of Kaupulehu Developments’ gross receipts from thesale of real estate interests, and Cambridge Hawaii Limited Partnership, a49.9% partner of Kaupulehu Developments in which Barnwell purchased a 55.2%interest in April 2001, is obligated under an agreement entered into in 1987 topay Nearco 4% of Kaupulehu Developments’ gross receipts from the sale of real estateinterests.  Fees of $128,000 ($89,000,net of minority interest) on the proceeds from sales of development rights werepaid in each of the years ended September 30, 2003 and 2002.  The fees represent compensation for promotionand marketing of Kaupulehu Developments’ property and were determined based onthe estimated fair value of such services. Barnwell believes the fees are fair and reasonable compensation for suchservices.

 

Fees were also paid to Nearco for consulting servicesrelated to Kaupulehu Developments’

 

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leasehold land.  In fiscal 2004,2003 and 2002, consulting service fees paid to Nearco, Inc. totaled $273,000,$218,000 and $95,000, respectively, and were included in general and administrativeexpenses.  In addition, $52,000 of feeswere paid to Nearco in fiscal 2004 for services related to the closing of theFebruary 2004 sale of an interest in leasehold land.   These fees were a direct cost of the saleand accordingly reduced the revenues recognized from the sale under the costrecovery method.  Barnwell believes thefees are fair and reasonable compensation for such services.

 

Interests at September30, 2004

 

The interests held by Kaupulehu Developments atSeptember 30, 2004 include the development rights under option; the rights toreceive Increment I percentage and interim payments; the leasehold land zonedfor resort/residential development within Increment II, which is under a rightof negotiation with WB; and approximately 1,000 acres of vacant leasehold landzoned conservation.  These interestsrelate to land located adjacent to and north of the Four Seasons ResortHualalai at Historic Ka’upulehu, between the Queen Kaahumanu Highway and thePacific Ocean.  Barnwell’s cost of KaupulehuDevelopments’ interests is included in the September 30, 2004 and 2003consolidated balance sheets under the caption “Investment in Land” andconsisted of the following amounts:

 
| ** **                                                    | ** ** | **September  30,** | ** **    |
|---------------------------------------------------------------|------------|--------------------|---------------|
|                                                          | ** ** | **2004**           | ** **    | **2003** | ** ** |
| Leasehold land  interests:                                    | ** ** | ** **         |          |   |   |
| Zoned for  resort/residential development – Increment I  | ** ** | **$**              | **—**    |   | $ | 3,475,000 |   |
| Zoned for  resort/residential development – Increment II | ** ** | **2,983,000**      |          | 2,983,000 |   |
| Zoned  conservation                                           | ** ** | **50,000**         |          | 50,000 |   |
| ** **                                                    |       | **3,033,000**      |          | 6,508,000 |   |
| Development  rights under option                              | ** ** | **—**         |          | — |   |
| Total investment  in land                                     | ** ** | **$**              | **3,033,000** |   | $ | 6,508,000 |   |

 

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**6.****             PROPERTY AND EQUIPMENT AND ASSETRETIREMENT OBLIGATION**

 

Barnwell’s property andequipment is detailed as follows:

 
| ** **                                             | ** ** | **Estimated  Useful  Lives** | ** ** | **Gross  Property and  Equipment** | ** **      | **Accumulated  Depreciation,  Depletion and  Amortization** | ** ** | **Net  Property and  Equipment** | ** ** |
|--------------------------------------------------------|------------|------------------------------|------------|------------------------------------|-----------------|-------------------------------------------------------------|------------|----------------------------------|------------|
| At September 30,  2004:                                |       |                         |       |                               |            |                                                        |       |                             |       |
| Land                                                   |       |                         |       | $                                  | 365,000         |                                                        | $          | —                           |       | $ | 365,000 |   |
| Oil and natural  gas properties (full cost accounting) |       |                         |       | 98,832,000                         |            | (53,108,000                                                 | )          | 45,724,000                       |       |
| Drilling rigs  and equipment                           |       | 3 – 7 years             |       | 4,126,000                          |            | (3,906,000                                                  | )          | 220,000                          |       |
| Premises                                               |       | 40 years                     |       | 857,000                            |            | (17,000                                                     | )          | 840,000                          |       |
| Other property  and equipment                          |       | 3 – 17 years            |       | 3,177,000                          |            | (2,474,000                                                  | )          | 703,000                          |       |
| Total                                                  | ** ** |                         | ** ** | **$**                              | **107,357,000** | ** **                                                  | **$**      | **(59,505,000**                  | **)**      | **$** | **47,852,000** | ** ** |
| ** **                                             | ** ** | ** **                   | ** ** | ** **                         | ** **      | ** **                                                  | ** ** | ** **                       | ** ** |
| At September 30,  2003:                                |       |                         |       |                               |            |                                                        |       |                             |       |
| Land                                                   |       |                         |       | $                                  | 465,000         |                                                        | $          | —                           |       | $ | 465,000 |   |
| Oil and natural  gas properties (full cost accounting) |       |                         |       | 80,863,000                         |            | (43,404,000                                                 | )          | 37,459,000                       |       |
| Drilling rigs  and equipment                           |       | 3 – 7 years             |       | 4,094,000                          |            | (3,841,000                                                  | )          | 253,000                          |       |
| Other property  and equipment                          |       | 3 – 17 years            |       | 3,077,000                          |            | (2,306,000                                                  | )          | 771,000                          |       |
| Total                                                  |       |                         |       | $                                  | 88,499,000      |                                                        | $          | (49,551,000                      | )          | $ | 38,948,000 |   |
|                                                        |            |                              |            |                                    |                 |                                                             |            |                                  |            |  |  |  |  |  |  |  |  |  |

 

On October 1, 2002,Barnwell adopted Statement ofFinancial Accounting Standards (“SFAS”) No. 143, “Accounting for AssetRetirement Obligations,” which requires that the fair value of a liability foran asset retirement obligation be recognized in the period in which it isincurred if a reasonable estimate of fair value can be made.  Adoption of SFAS No. 143 increased gross oiland natural gas properties by $564,000, decreased accumulated depletion by$546,000, and increased the asset retirement obligation by $1,110,000 on October1, 2002.

 

Following the initialimplementation of SFAS No. 143, the asset retirement obligation was increasedduring the year ended September 30, 2003 by $39,000 to reflect obligationsincurred on 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 ended September30, 2004, the asset retirement obligation was increased by $133,000 to reflectobligations incurred on new wells drilled and changes in the timing and amountof estimated future expenditures, by $100,000 for accretion of the assetretirement obligation, and by $110,000 for changes in foreign currencytranslation rates.

 

InDecember 2003, Barnwell purchased the space it was leasing for its corporateoffices in Honolulu, Hawaii for $1,057,000, of which $883,000 was financed by anote payable to a Hawaii bank and the remainder was paid in cash.  The note was payable in monthly principalpayments of approximately $3,000, plus interest, and was due in full inDecember 2006.  Barnwell repaid the notein full in fiscal 2004.  The spacepurchased has 4,662 useable square feet in an office building in downtownHonolulu, Hawaii.

 

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**7.****             LONG-TERM DEBT**

 

Barnwell has a creditfacility at the Royal Bank of Canada, a Canadian bank, for approximately$15,000,000 at September 30, 2004. Borrowings under this facility were $10,165,000 and $10,477,000 atSeptember 30, 2004 and 2003, respectively, and are included in long-termdebt.  At September 30, 2004, Barnwellhad unused credit available under this facility of approximately $4,800,000.

 

The facility is availablein U.S. dollars at the London Interbank Offer Rate plus 2%, at U.S. prime plus1%, or in Canadian dollars at Canadian prime plus 1%.  A standby fee of 1% per annum is charged onthe unused facility balance.  Under thefinancing agreement, the facility is reviewed annually, with the next reviewplanned for April 2005.  Subject to thatreview, the facility may be extended one year with no required debt repaymentsfor one year or converted to a 2-year term loan by the bank.  If the facility is converted to a 2-year termloan, Barnwell has agreed to the following repayment schedule of the thenoutstanding loan balance:  first year ofthe term period – 20% (5% per quarter), and in the second year of the termperiod  – 80% (5% per quarter for thefirst three quarters and 65% in the final quarter).

 

Barnwell has the option to change the currencydenomination and interest rate applicable to the loan at periodic intervalsduring the term of the loan.  During theyear ended September 30, 2004, Barnwell paid interest at rates ranging from2.69% to 5.50%.  The weighted averageinterest rate on the facility at September 30, 2004 was 3.65%.  The facility is collateralized by Barnwell’sinterests in its major oil and natural gas properties and a negative pledge onits remaining oil and natural gas properties. The facility is reviewed annually with a primary focus on the futurecash flows that will be generated by Barnwell’s Canadian oil and natural gasproperties.  No compensating bankbalances are required for this facility.

 

The bank represented thatit will not require any repayments under the facility before October 1,2005.  Accordingly, Barnwell has classifiedoutstanding borrowings under the facility as long-term debt.

 

In fiscal 2002 and during the first quarter offiscal 2003, Barnwell capitalized interest on costs related to its investmentin land.  Attainment of zoning anddevelopment entitlements for Kaupulehu Developments’ leasehold land interestsin approximately 870 acres of land zoned for resort/residential development wassubstantially complete as of the end of December 2002.  Accordingly, effective January 1, 2003,Barnwell no longer capitalizes interest on the accumulated development costs ofthe property.

 

Interest costs for theyears ended September 30, 2004, 2003 and 2002 are summarized as follows:

 
| ** **                                             | ** ** | **2004**   | ** **  | **2003** | ** ** | **2002** | ** ** |
|--------------------------------------------------------|------------|------------|-------------|----------|------------|----------|------------|
| Interest costs  incurred                               |       | **$**      | **487,000** |     | $          | 487,000  |       | $ | 498,000 |   |
| Less interest  costs capitalized on investment in land |       | **—** |        | 45,000   |       | 202,000  |       |
| Interest expense                                       |       | **$**      | **487,000** |     | $          | 442,000  |       | $ | 296,000 |   |

 

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**8.****             TAXES ON INCOME**

 

The components ofearnings before income taxes are as follows:

 
| ** **                               | ** ** | **Year ended September 30,** | ** **     |
|------------------------------------------|------------|------------------------------|----------------|
| ** **                               | ** ** | **2004**                     | ** **     | **2003** | ** ** | **2002** | ** ** |
| Earnings (loss)  before income taxes in: |       |                         |           |   |   |   |   |
| United States                            | ** ** | **$**                        | **3,592,000**  |   | $ | (2,499,000 | ) | $ | (1,811,000 | ) |
| Canada                                   | ** ** | **8,425,000**                |           | 9,004,000 |   | 3,412,000 |   |
| ** **                               |       | **$**                        | **12,017,000** |   | $ | 6,505,000 |   | $ | 1,601,000 |   |

 

The components of theprovision (benefit) for income taxes related to the above earnings (loss) areas follows:

 
| ** **                    | ** ** | **Year ended September 30,** | ** **    |
|-------------------------------|------------|------------------------------|---------------|
| ** **                    | ** ** | **2004**                     | ** **    | **2003** | ** ** | **2002** | ** ** |
| Current provision:            |       |                         |          |   |   |   |   |
| United States –  Federal | ** ** | **$**                        | **594,000**   |   | $ | 143,000 |   | $ | 21,000 |   |
| United States –  State   | ** ** | **28,000**                   |          | — |   | — |   |
| ** **                    |       | **622,000**                  |          | 143,000 |   | 21,000 |   |
| Canadian                      | ** ** | **2,992,000**                |          | 3,333,000 |   | 1,135,000 |   |
| Total current                 | ** ** | **3,614,000**                |          | 3,476,000 |   | 1,156,000 |   |
|                          |       |                         |          |   |   |   |   |
| Deferred  provision:          |       |                         |          |   |   |   |   |
| United States                 | ** ** | **608,000**                  |          | (191,000 | ) | 42,000 |   |
| Canadian                      | ** ** | **(915,000**                 | **)**         | 900,000 |   | 363,000 |   |
| Total deferred                | ** ** | **(307,000**                 | **)**         | 709,000 |   | 405,000 |   |
| ** **                    |       | **$**                        | **3,307,000** |   | $ | 4,185,000 |   | $ | 1,561,000 |   |

 

Barnwell’s Canadiandeferred tax benefit of $915,000 for fiscal 2004 was due to reductions inCanadian Federal and Provincial tax rates, partially offset by Barnwell’s$825,000 Canadian deferred tax provision resulting from changes in differencesbetween Canadian assets and liabilities for book purposes versus Canadianassets and liabilities for Canadian tax purposes.  In November 2003, Royal Assent was receivedon a bill passed by the Parliament of Canada, which was then enacted into law,to reduce Canada’s corporate tax rate on “resource” income (income derived fromoil and natural gas operations) over a four-year period beginning January 1,2003 from 29% to 21% with the 21% tax rate commencing on January 1, 2007.  Additionally, the bill phases in over thesame four-year period tax deductions for royalties, which previously were nottax deductible, and phases out the Resource Allowance deduction along withother changes.  Accordingly, duringfiscal 2004, Barnwell’s Canadian deferred income tax liabilities were reducedby approximately $1,440,000 due to the reduction in Canada’s Federal corporatetax rate.  There was no benefitattributable to changes in Canada’s corporate tax rate on “resource” income infiscal 2003 or fiscal 2002.

 

Barnwell’s Canadiandeferred 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).  In April2002, the legislative assembly of the Province of Alberta passed a bill toreduce the province’s corporate tax rate from 13.5% to 13.0%, effective April1, 2002.  The bill was enacted into lawin December 2002.  The reduction in 

 

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the tax rate reduced Canadian deferred income tax liabilities byapproximately $75,000 in fiscal 2003. There was no such reduction recorded in fiscal 2002.

 

Barnwell’s Canadiandeferred tax provision of $825,000 for fiscal 2004, excluding the deferred taxbenefit associated with the aforementioned reduction in income tax rates, andBarnwell’s Canadian deferred tax provisions for fiscal years 2003 and 2002 wereprimarily due to Barnwell’s Canadian tax deductions related to its oil andnatural gas properties exceeding Barnwell’s depletion of its oil and naturalgas properties for book purposes.

 

The U.S. deferred tax expense of $608,000 for fiscal2004 includes reversals of temporary differences, resulting from the excess ofexpenses deductible for tax purposes over expenses recognized under the costrecovery method for books, generated by sales of Kaupulehu Developments’development rights and interest in leasehold land.

 

Included in the provisions for deferred income taxesfor fiscal 2003 and 2002 are U.S. deferred tax benefits of $320,000 and$376,000, respectively, related to the sale of land development rights inDecember 2002 and 2001, respectively. The sales of land development rights in fiscal 2003 and 2002 createdtemporary differences due to the excess of expenses recognized under the costrecovery method for books over expenses deductible for tax purposes.

 

A reconciliation betweenthe reported provision for income taxes and the amount computed by multiplyingthe earnings before income taxes by the U.S. federal tax rate of 35% is asfollows:

 
| ** **                                                                                               | ** ** | **Year ended September 30,** | ** **    |
|----------------------------------------------------------------------------------------------------------|------------|------------------------------|---------------|
| ** **                                                                                               | ** ** | **2004**                     | ** **    | **2003** | ** ** | **2002** | ** ** |
|                                                                                                     |       |                         |          |   |   |   |   |
| Tax expense  computed by applying statutory rate                                                         | ** ** | **$**                        | **4,206,000** |   | $ | 2,277,000 |   | $ | 560,000 |   |
|                                                                                                     |       |                         |          |   |   |   |   |
| Effect of  reduction of Canadian tax rates on Canadian deferred taxes                                    | ** ** | **(1,740,000**               | )             | (75,000 | ) | — |   |
| Effect of the  foreign tax provision, before effect of changes in tax rates, on the total  tax provision | ** ** | **525,000**                  |          | 2,042,000 |   | 1,060,000 |   |
| State net  operating losses (generated) utilized                                                         | ** ** | **83,000**                   |          | (39,000 | ) | (22,000 | ) |
| State income  taxes                                                                                      | ** ** | **28,000**                   |          | — |   | — |   |
| Other                                                                                                    | ** ** | **205,000**                  |          | (20,000 | ) | (37,000 | ) |
| ** **                                                                                               |       | **$**                        | **3,307,000** |   | $ | 4,185,000 |   | $ | 1,561,000 |   |

 

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The tax effects of temporary differences thatgive rise to significant portions of the deferred tax assets and deferred taxliabilities at September 30, 2004 and 2003 are as follows:

 
| ** **                                                                                                   | ** ** | **2004**        | ** **          | **2003**    | ** ** |
|--------------------------------------------------------------------------------------------------------------|------------|-----------------|---------------------|-------------|------------|
| Deferred income  tax assets:                                                                                 |       |            |                |        |       |
| U.S. tax effect  of deferred Canadian taxes                                                                  |       | **$**           | ** 3,028,000** |        | $          |  3,139,000 |   |
| Foreign tax  credit carryforwards                                                                            | ** ** | **4,261,000**   |                | 5,286,000   |       |
| Tax basis in  investment in land in excess of book basis                                                     | ** ** | **1,165,000**   |                | 1,535,000   |       |
| Alternative  minimum tax credit carryforwards                                                                | ** ** | **116,000**     |                | 514,000     |       |
| Liabilities  accrued for books but not for tax under U.S. tax law                                       | ** ** | **1,965,000**   |                | 1,288,000   |       |
| Liabilities  accrued for books but not for tax under Canadian tax law                                        | ** ** | **612,000**     |                | 300,000     |       |
| Other                                                                                                        | ** ** | **402,000**     |                | 488,000     |       |
| Total gross  deferred tax assets                                                                             | ** ** | **11,549,000**  |                | 12,550,000  |       |
| Less-valuation  allowance                                                                                    | ** ** | **(8,456,000**  | )                   | (9,385,000  | )          |
| Net deferred  income tax assets                                                                              | ** ** | **3,093,000**   |                | 3,165,000   |       |
|                                                                                                         |       |            |                |        |       |
| Deferred income  tax liabilities:                                                                            |       |            |                |        |       |
| Property and  equipment accumulated tax depreciation and depletion in excess of book under  Canadian tax law | ** ** | **(9,518,000**  | )                   | (9,533,000  | )          |
| Property and  equipment accumulated tax depreciation and depletion in excess of book under  U.S. tax law     | ** ** | **(2,722,000**  | )                   | (2,524,000  | )          |
| Other                                                                                                        | ** ** | **(341,000**    | )                   | (336,000    | )          |
| Total deferred  income tax liabilities                                                                       | ** ** | **(12,581,000** | )                   | (12,393,000 | )          |
|                                                                                                         |       |            |                |        |       |
| Net deferred  income tax liability                                                                           | ** ** | **$**           | **(9,488,000**      | )           | $          | (9,228,000 | ) |

 

The total valuation allowance decreased $929,000for the year ended September 30, 2004 and increased $1,790,000, and $730,000for the years ended September 30, 2003 and 2002, respectively.  The changes relate primarily to foreign taxcredit carryforwards for which it is more likely than not that suchcarryforwards will not be utilized to reduce Barnwell’s U.S. tax obligation.

 

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, foreign tax credits, 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.

 

Net deferred tax assets at September 30,2004 of $3,093,000 consists of $1,165,000 related to the excess of the costbasis of investment in land for tax purposes over the cost basis of investmentin land for book purposes and $1,812,000 related to the excess of liabilitiesaccrued for book purposes over liabilities accrued for tax purposes.  The deferred tax assets are estimated to berealized through the deduction of the cost basis of investment in land andexpenses for tax purposes against future proceeds from sales of interests inleasehold land and land development rights. Additionally, at September 30, 2004, Barnwell had a deferred tax assetof $116,000 for alternative minimum tax credit carryforwards 

 

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which are available to reduce future U.S. federal regular income taxes,if any, over an indefinite period.  Theamount of deferred income tax assets considered realizable may be reduced ifestimates of future taxable income are reduced.

 

**9.****             PENSION PLAN**

 

Barnwell sponsors a noncontributory definedbenefit pension plan covering substantially all of its U.S. employees, withbenefits based on years of service and the employee’s highest consecutivefive-year average earnings.  Barnwell’sfunding policy is intended to provide for both benefits attributed to serviceto-date and for those expected to be earned in the future.

 

The overall investment objective of the plan isto provide growth in the assets of the plan to fund future benefit obligationswhile managing 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 at September30, 2004 were invested as follows: 1% in cash, 3% in a certificate of deposit,42% in debt securities, and 54% in equity securities.  The plan assets at September 30, 2003 wereinvested as follows: 7% in cash and cash equivalents, 34% in debt securities,and 59% in equity securities.  Targetasset allocations are not used, and allocations are adjusted from time to timeas dictated by current and anticipated market conditions and required cashflows.

 

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

 

The funded status of thepension plan and the amounts recognized in the consolidated financialstatements are as follows:

 
| ** **                                      | ** ** | **September 30,** | ** **    |
|-------------------------------------------------|------------|-------------------|---------------|
| ** **                                      | ** ** | **2004**          | ** **    | **2003** | ** ** |
| Change in  Benefit Obligation:                  | ** ** | ** **        |          |   |   |
| Benefit  obligation at beginning of year        | ** ** | **$**             | **3,086,000** |   | $ | 2,753,000 |   |
| Service cost                                    | ** ** | **121,000**       |          | 128,000 |   |
| Interest cost                                   | ** ** | **180,000**       |          | 171,000 |   |
| Actuarial loss                                  | ** ** | **125,000**       |          | 182,000 |   |
| Benefits paid                                   | ** ** | **(120,000**      | )             | (148,000 | ) |
| Benefit  obligation at end of year              | ** ** | **3,392,000**     |          | 3,086,000 |   |
|                                            |       |              |          |   |   |
| Change in Plan  Assets                          |       |              |          |   |   |
| Fair value of  plan assets at beginning of year | ** ** | **2,027,000**     |          | 1,855,000 |   |
| Actual return on  plan assets                   | ** ** | **133,000**       |          | 228,000 |   |
| Employer  contribution                          | ** ** | **74,000**        |          | 92,000 |   |
| Benefits paid                                   | ** ** | **(120,000**      | )             | (148,000 | ) |
| Fair value of  plan assets at end of year       | ** ** | **2,114,000**     |          | 2,027,000 |   |
|                                            |       |              |          |   |   |
| Funded status                                   | ** ** | **(1,278,000**    | )             | (1,059,000 | ) |
| Unrecognized  prior service cost                | ** ** | **7,000**         |          | 12,000 |   |
| Unrecognized  actuarial loss                    | ** ** | **853,000**       |          | 723,000 |   |
| Accrued benefit  cost                           | ** ** | **$**             | **(418,000**  | ) | $ | (324,000 | ) |

 

64

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The accumulated benefit obligation for the pensionplan was $2,357,000 and $2,083,000 at September 30, 2004 and 2003,respectively.

 
| Assumptions used  to determine the fiscal year-end benefit obligations: |       |     |   |   |   |
|-------------------------------------------------------------------------|------------|----------|--------|--------|--------|
| Discount rate                                                           | ** ** | **5.75** | %      | 6.00   | %      |
| Rate of  compensation increase                                          | ** ** | **5.00** | %      | 5.00   | %      |

 
| ** **                                                    | ** ** | **Year ended September 30,** | ** **  |
|---------------------------------------------------------------|------------|------------------------------|-------------|
| ** **                                                    | ** ** | **2004**                     | ** **  | **2003** | ** ** | **2002** | ** ** |
| Net Periodic  Benefit Cost for the Year:                      |       |                         |        |   |   |   |   |
| Service cost                                                  | ** ** | **$**                        | **121,000** |   | $ | 128,000 |   | $ | 94,000 |   |
| Interest cost                                                 | ** ** | **180,000**                  |        | 171,000 |   | 161,000 |   |
| Expected return  on plan assets                               | ** ** | **(157,000**                 | )           | (144,000 | ) | (167,000 | ) |
| Amortization of  net asset                                    | ** ** | **—**                   |        | (1,000 | ) | (1,000 | ) |
| Amortization of  prior service cost                           | ** ** | **6,000**                    |        | 6,000 |   | 6,000 |   |
| Amortization of  net actuarial loss (gain)                    | ** ** | **18,000**                   |        | 12,000 |   | — |   |
| Net periodic  benefit cost                                    | ** ** | **$**                        | **168,000** |   | $ | 172,000 |   | $ | 93,000 |   |
|                                                          |       |                         |        |   |   |   |   |
| Assumptions used  to determine the net periodic benefit cost: |       |                         |        |   |   |   |   |
| Discount rate                                                 | ** ** | **6.00**                     | **%**       | 6.50 | % | 7.50 | % |
| Expected return  on plan assets                               | ** ** | **8.00**                     | **%**       | 8.00 | % | 8.00 | % |
| Rate of  compensation increase                                | ** ** | **5.00**                     | **%**       | 5.00 | % | 5.00 | % |

 

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

 
| Expected Benefit  Payments:                          |   |   |    |
|------------------------------------------------------|--------|--------|---------|
| Fiscal year  ending September 30, 2005               |   | $      | 129,000 |   |
| Fiscal year  ending September 30, 2006               |   | $      | 122,000 |   |
| Fiscal year  ending September 30, 2007               |   | $      | 115,000 |   |
| Fiscal year  ending September 30, 2008               |   | $      | 108,000 |   |
| Fiscal year  ending September 30, 2009               |   | $      | 100,000 |   |
| Fiscal years  ending September 30, 2010 through 2014 |   | $      | 528,000 |   |

 

Barnwell estimates thatit will contribute the maximum tax-deductible amount of approximately $80,000to the plan during fiscal 2005.

 

**10.****          STOCK OPTIONS**

 

In March 1995, Barnwellgranted 20,000 stock options to an officer and director of Barnwell under anon-qualified plan at a purchase price of $19.625 per share (market price ondate of grant), with 4,000 of such options vesting annually commencing one yearfrom the date of grant.  These optionshave stock appreciation rights that permit the holder to receive stock, cash ora combination thereof equal to the amount by which the fair market value, atthe time of exercise of the option, exceeds the option price.  The options expire in March 2005.  During the year ended September 30, 2004, theofficer and director exercised his right to receive in cash the value of 13,000shares of these non-qualified stock options (stock appreciation rights) at anexercise price of $19.625 per share.  Thedifference between the exercise price and the price per share on the dates ofexercise (ranging from $41.95 to $45.00 per share) 

 

65

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was paid to this employee in cash by Barnwell.  Barnwell recognized $392,000, $101,000 and$6,000 of compensation cost relating to these options in the years endedSeptember 30, 2004, 2003 and 2002, respectively.

 

In June 1998, Barnwell granted 30,000 stockoptions to an officer of Barnwell’s oil and gas segment under a non-qualifiedplan at a purchase price of $15.625 per share (market price on date of grant),with 6,000 of such options vesting annually commencing one year from the dateof grant.  These options have stockappreciation rights that permit the holder 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.  The options expire in May 2008.  Barnwell recognized $599,000, $125,000 and$43,000 of compensation costs relating to these options in the years endedSeptember 30, 2004, 2003 and 2002, respectively.

 

In December 1999,Barnwell granted qualified stock options to certain employees of Barnwell toacquire 68,000 shares and 29,000 shares of Barnwell’s common stock with anexercise price per share of $11.875 (market price at date of grant) and $13.063(110% of market price at date of grant), respectively.  These options vest annually over four yearscommencing one year from the date of grant. The $11.875 per share options expire in December 2009, and the $13.063per share options expire in December 2004. During the year ended September 30, 2004, Barnwell issued 17,500 sharesof its common stock to certain employees resulting from exercises of qualifiedstock options at exercise prices ranging from $11.875 to $13.063 pershare.   During the year ended September30, 2002, 3,000 options to acquire Barnwell’s stock at $11.875 per share wereforfeited.  No compensation cost wasrecognized for these options for the years ended September 30, 2004, 2003 and2002.  At September 30, 2004, 36,000shares were available for grant under this plan.

 

Stock options atSeptember 30, 2004 were as follows:

 
| ** **                    | ** ** | **Options outstanding** | ** ** | **Options exercisable**                             | ** ** |
|-------------------------------|------------|-------------------------|------------|-----------------------------------------------------|------------|
| **Range of  exercise prices** | ** ** | **Number of  Shares**   | ** ** | **Weighted  Average  Remaining  Contractual  Life** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Number of  Shares** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| $11.875 - $15.625             |       | 105,500                 |       | 3.8 years                                           |       | $ | 13.18 |   | 105,500 |   | $ | 13.18 |   |
| $19.625                       |       | 7,000                   |       | 0.4 years                                           |       | $ | 19.63 |   | 7,000 |   | $ | 19.63 |   |
|                          |       |                    |       |                                                |       |   |   |   |   |   |   |   |   |
| $11.875 - $19.625             |       | 112,500                 |       | 3.5 years                                           |       | $ | 13.58 |   | 112,500 |   | $ | 13.58 |   |

 

Stock options atSeptember 30, 2003 were as follows:

 
| ** **                    | ** ** | **Options outstanding** | ** ** | **Options exercisable**                             | ** ** |
|-------------------------------|------------|-------------------------|------------|-----------------------------------------------------|------------|
| **Range of  exercise prices** | ** ** | **Number of  Shares**   | ** ** | **Weighted  Average  Remaining  Contractual  Life** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Number of  Shares** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| $11.875 - $15.625             |       | 123,000                 |       | 4.6 years                                           |       | $ | 13.07 |   | 99,750 |   | $ | 13.26 |   |
| $19.625                       |       | 20,000                  |       | 1.4 years                                           |       | $ | 19.63 |   | 20,000 |   | $ | 19.63 |   |
|                          |       |                    |       |                                                |       |   |   |   |   |   |   |   |   |
| $11.875 - $19.625             |       | 143,000                 |       | 4.2 years                                           |       | $ | 13.99 |   | 119,750 |   | $ | 14.32 |   |

 

66

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Stock options atSeptember 30, 2002 were as follows:

 
| ** **                    | ** ** | **Options outstanding** | ** ** | **Options exercisable**                             | ** ** |
|-------------------------------|------------|-------------------------|------------|-----------------------------------------------------|------------|
| **Range of  exercise prices** | ** ** | **Number of  Shares**   | ** ** | **Weighted  Average  Remaining  Contractual  Life** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Number of  Shares** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| $11.875 - $15.625             |       | 123,000                 |       | 5.6 years                                           |       | $ | 13.07 |   | 70,500 |   | $ | 13.40 |   |
| $19.625                       |       | 20,000                  |       | 2.4 years                                           |       | $ | 19.63 |   | 20,000 |   | $ | 19.63 |   |
|                          |       |                    |       |                                                |       |   |   |   |   |   |   |
| $11.875 - $19.625             |       | 143,000                 |       | 5.2 years                                           |       | $ | 13.99 |   | 90,500 |   | $ | 14.77 |   |

 

In December 2001, approximately $71,000 ofconvertible debentures, including accrued interest, was converted to 3,558shares of Barnwell’s stock at $20 per share; these shares were issued fromBarnwell’s treasury stock.  There were noconversions or repurchases of Barnwell’s stock in the year ended September 30,2004.  Barnwell plans to repurchaseadditional shares from time to time in the open market or in privatelynegotiated transactions, depending on market conditions.  At September 30, 2004, Barnwell couldpurchase an additional 93,000 shares under the March 2000 repurchaseauthorization.

 

**11.****          COMMITMENTS AND CONTINGENCIES**

 

Barnwell has committed to compensate its VicePresident of Canadian Operations pursuant to an incentive compensation plan,the value of which directly relates to Barnwell’s oil and natural gas segment’snet income and the change in the value of Barnwell’s oil and gas reserves since1998 with adjustments for changes in natural gas and oil prices and subject toother terms and conditions.  Barnwellrecognized $60,000 and $166,000 of compensation expense pursuant to thisincentive plan in fiscal 2004 and fiscal 2003, respectively.  In fiscal 2002, Barnwell recognized a $48,000reduction in compensation expense pursuant to this incentive plan.

 

Barnwell has also committed to compensatecertain Canadian personnel pursuant to an incentive compensation plan, thevalue of which directly relates to Barnwell’s oil and natural gas segment’s netincome and the value of Barnwell’s oil and gas reserves discovered, commencingin fiscal 2002, for projects developed by such personnel.  Barnwell recognized approximately $190,000 ofcompensation costs pursuant to this plan in fiscal 2004, of which approximately$50,000 was expensed and approximately $140,000, the portion related toin-house geologists, was capitalized as oil and natural gas capitalexpenditures.  In fiscal 2003, Barnwellrecognized approximately $80,000 of compensation costs pursuant to this plan,of which approximately $30,000 was expensed and approximately $50,000, theportion related to in-house geologists, was capitalized as oil and natural gascapital expenditures.  Barnwellrecognized no compensation expense pursuant to this plan in fiscal 2002.

 

Barnwell has several non-cancelableoperating leases for office space and leasehold land.  Rental expense was $444,000 in 2004, $474,000in 2003, and $467,000 in 2002.  Barnwellis committed under these leases for minimum rental payments summarized byfiscal year as follows: 2005 - $495,000, 2006 - $476,000, 2007 - $447,000, 2008- $408,000, 2009 - $389,000 and thereafter through 2026 an aggregate of$2,390,000.  The lease payments for landare subject to renegotiation after December 31, 

 

67

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2005; the future rental payment disclosures above assume the minimumlease payments for land in effect at December 31, 2005 remain unchanged through2025, the end of the lease term.  

 

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

 

**12.****          SEGMENT AND GEOGRAPHIC INFORMATION**

 

Barnwell operates three segments: exploring for,developing, producing and selling oil and natural gas (oil and natural gas);investing in leasehold land in Hawaii (land investment); and drilling wells andinstalling and repairing water pumping systems in Hawaii (contractdrilling).  Barnwell’s reportablesegments are strategic business units that offer different products andservices.  They are managed separately aseach segment requires different operational methods, operational assets andmarketing strategies, and operate in different geographical locations.

 

68

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Barnwell does notallocate general and administrative expenses, interest expense, interest incomeor income taxes to segments, and there are no transactions between segmentsthat affect segment profit or loss.

 
| ** **                                                             | ** ** | **Year ended September 30,** | ** **     |
|------------------------------------------------------------------------|------------|------------------------------|----------------|
| ** **                                                             | ** ** | **2004**                     | ** **     | **2003** | ** ** | **2002** | ** ** |
| Revenues:                                                              |       |                         |           |   |   |   |   |
| Oil and natural  gas                                                   | ** ** | **$**                        | **23,270,000** |   | $ | 19,350,000 |   | $ | 11,320,000 |   |
| Contract  drilling                                                     | ** ** | **3,690,000**                |           | 2,050,000 |   | 3,480,000 |   |
| Land investment                                                        | ** ** | **10,077,000**               |           | 1,220,000 |   | 220,000 |   |
| Other                                                                  | ** ** | **827,000**                  |           | 720,000 |   | 598,000 |   |
| Total before  interest income                                          | ** ** | **37,864,000**               |           | 23,340,000 |   | 15,618,000 |   |
| Interest income                                                        | ** ** | **106,000**                  |           | 340,000 |   | 262,000 |   |
| Total revenues                                                         | ** ** | **$**                        | **37,970,000** |   | $ | 23,680,000 |   | $ | 15,880,000 |   |
|                                                                   |       |                         |           |   |   |   |   |
| Depletion,  depreciation and amortization:                             |       |                         |           |   |   |   |   |
| Oil and natural  gas                                                   | ** ** | **$**                        | **6,423,000**  |   | $ | 4,026,000 |   | $ | 3,315,000 |   |
| Contract  drilling                                                     | ** ** | **98,000**                   |           | 88,000 |   | 118,000 |   |
| Other                                                                  | ** ** | **240,000**                  |           | 219,000 |   | 215,000 |   |
| Total                                                                  | ** ** | **$**                        | **6,761,000**  |   | $ | 4,333,000 |   | $ | 3,648,000 |   |
|                                                                   |       |                         |           |   |   |   |   |
| Operating profit  (loss) (before general and administrative expenses): |       |                         |           |   |   |   |   |
| Oil and natural  gas                                                   | ** ** | **$**                        | **11,444,000** |   | $ | 11,132,000 |   | $ | 4,897,000 |   |
| Contract  drilling                                                     | ** ** | **408,000**                  |           | 34,000 |   | 541,000 |   |
| Land investment,  net of minority interest                             | ** ** | **7,612,000**                |           | 669,000 |   | — |   |
| Other                                                                  | ** ** | **587,000**                  |           | 501,000 |   | 483,000 |   |
| Total                                                                  | ** ** | **20,051,000**               |           | 12,336,000 |   | 5,921,000 |   |
| General and  administrative expenses, net of minority interest         | ** ** | **(7,653,000**               | )              | (5,729,000 | ) | (4,286,000 | ) |
| Interest income                                                        | ** ** | **106,000**                  |           | 340,000 |   | 262,000 |   |
| Interest expense                                                       | ** ** | **(487,000**                 | )              | (442,000 | ) | (296,000 | ) |
| Earnings before  income taxes                                          | ** ** | **$**                        | **12,017,000** |   | $ | 6,505,000 |   | $ | 1,601,000 |   |
|                                                                   |       |                         |           |   |   |   |   |
| Capital  expenditures:                                                 |       |                         |           |   |   |   |   |
| Oil and natural  gas                                                   | ** ** | **$**                        | **11,876,000** |   | $ | 11,059,000 |   | $ | 4,581,000 |   |
| Land investment                                                        | ** ** | **—**                   |           | 45,000 |   | 944,000 |   |
| Contract  drilling                                                     | ** ** | **65,000**                   |           | 72,000 |   | 77,000 |   |
| Other                                                                  | ** ** | **1,191,000**                |           | 158,000 |   | 42,000 |   |
| Total                                                                  | ** ** | **$**                        | **13,132,000** |   | $ | 11,334,000 |   | $ | 5,644,000 |   |

 

Depletion per 1,000 cubicfeet (“MCF”) of natural gas and natural gas equivalent (“MCFE”), converted at arate of one barrel of oil and natural gas liquids to 5.8 MCFE, was $1.31 infiscal 2004, $0.90 in fiscal 2003, and $0.71 in fiscal 2002.  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 average exchange rate of the Canadiandollar to the U.S. dollar of 10% in fiscal 2004, as compared to fiscal 2003,and 7% in fiscal 2003 as compared to fiscal 2002.

 

69

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ASSETS BY SEGMENT:

 
| ** **                                              | ** ** | **September 30,** | ** **     |
|---------------------------------------------------------|------------|-------------------|----------------|
| ** **                                              | ** ** | **2004**          | ** **     | **2003** | ** ** | **2002** | ** ** |
| Oil and natural  gas (1)                                |       | **$**             | **50,658,000** | ** ** | **78** | **%** | $ | 40,638,000 |   | 77 | % | $ | 27,113,000 |   | 66 | % |
| Contract  drilling (2)                                  |       | **3,062,000**     | ** **     | **5** | **%** | 1,380,000 |   | 3 | % | 1,931,000 |   | 5 | % |
| Land investment  (2)                                    |       | **3,033,000**     | ** **     | **5** | **%** | 6,508,000 |   | 12 | % | 7,740,000 |   | 19 | % |
| Other:                                                  |       | ** **        | ** **     | ** ** | ** ** |   |   |   |   |   |   |   |   |
| Cash and cash  equivalents, and certificates of deposit |       | **5,884,000**     | ** **     | **9** | **%** | 1,648,000 |   | 3 | % | 1,489,000 |   | 4 | % |
| Corporate and  other                                    |       | **2,450,000**     | ** **     | **3** | **%** | 2,463,000 |   | 5 | % | 2,401,000 |   | 6 | % |
| Total                                                   |       | **$**             | **65,087,000** | ** ** | **100** | **%** | $ | 52,637,000 |   | 100 | % | $ | 40,674,000 |   | 100 | % |

 

----

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

(2)  Located in Hawaii.

 

LONG-LIVED ASSETS BYGEOGRAPHIC AREA:

 
| ** **    | ** ** | **September 30,** | ** **     |
|---------------|------------|-------------------|----------------|
| ** **    | ** ** | **2004**          | ** **     | **2003** | ** ** | **2002** | ** ** |
| United States | ** ** | **$**             | **4,847,000**  | ** ** | **10** | **%** | $ | 7,640,000 |   | 17 | % | $ | 8,962,000 |   | 27 | % |
| Canada        | ** ** | **46,038,000**    | ** **     | **90** | **%** | 37,816,000 |   | 83 | % | 24,606,000 |   | 73 | % |
| Total         | ** ** | **$**             | **50,885,000** | ** ** | **100** | **%** | $ | 45,456,000 |   | 100 | % | $ | 33,568,000 |   | 100 | % |

 

REVENUE BY GEOGRAPHICAREA:

 
| ** **                         | ** ** | **Year ended September 30,** | ** **     |
|------------------------------------|------------|------------------------------|----------------|
| ** **                         | ** ** | **2004**                     | ** **     | **2003** | ** ** | **2002** | ** ** |
| United States                      | ** ** | **$**                        | **14,051,000** |   | $ | 3,420,000 |   | $ | 3,766,000 |   |
| Canada                             | ** ** | **23,813,000**               |           | 19,920,000 |   | 11,852,000 |   |
| Total (excluding  interest income) | ** ** | **$**                        | **37,864,000** |   | $ | 23,340,000 |   | $ | 15,618,000 |   |

 

**13.****          FAIR VALUE OF FINANCIAL INSTRUMENTS**

 

The carrying amounts ofcash and cash equivalents, certificates of deposit, accounts receivable, andaccounts payable approximate fair value because of the short maturity of theseinstruments.  The carrying value oflong-term debt approximates fair value as the terms approximate current marketterms for similar debt instruments of comparable risk and maturities.

 

The differences betweenthe estimated fair values and carrying values of Barnwell’s financialinstruments are not material.

 

70

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**14.****          CONCENTRATIONS OF CREDIT RISK**

 

Barnwell’s oil and natural gas segment derived53% of its oil and natural gas revenues in fiscal 2004 from three individuallysignificant customers, ProGas Limited, Coral Energy Canada Inc., and PlainsMarketing Canada, L.P.  At September 30,2004, Barnwell had a total of $1,140,000 in receivables from these fourcustomers.  In fiscal 2003 Barnwellderived 64% of its oil and natural gas revenues from four individuallysignificant customers.  In fiscal 2002Barnwell derived 76% of its oil and natural gas revenues from five individuallysignificant customers.

 

Barnwell’s contract drilling subsidiary derived70%, 66%, and 70% of its contract drilling revenues in fiscal 2004, 2003, and2002, respectively, pursuant to Federal, State of Hawaii and countycontracts.  At September 30, 2004,Barnwell had accounts receivables from the Federal, State of Hawaii and countyentities totaling approximately $1,705,000. Barnwell has lien rights on wells drilled and pumps installed forFederal, State of Hawaii, and county governments.

 

Historically, Barnwellhas not incurred significant credit related losses on its trade receivables, andmanagement does not believe significant credit risk related to these tradereceivables exists at September 30, 2004.

 

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**15.****          SUPPLEMENTAL STATEMENTS OF CASH FLOWSINFORMATION**

 

The following details theeffect of changes in current assets and liabilities on the consolidatedstatements of cash flows, and presents supplemental cash flow information:

 
| ** **                                                                   | ** ** | **Year ended September 30,** | ** **     |
|------------------------------------------------------------------------------|------------|------------------------------|----------------|
| ** **                                                                   | ** ** | **2004**                     | ** **     | **2003** | ** ** | **2002** | ** ** |
| Increase  (decrease) from changes in:                                        |       |                         |           |   |   |   |   |
|                                                                         |       |                         |           |   |   |   |   |
| Receivables                                                                  |       | **$**                        | **(2,439,000** | **)** | $ | 548,000 |   | $ | (622,000 | ) |
| Costs and  estimated earnings in excess of billings on uncompleted contracts |       | **(327,000**                 | **)**          | 8,000 |   | 206,000 |   |
| Other current  assets                                                        |       | **(429,000**                 | **)**          | 210,000 |   | (338,000 | ) |
| Accounts payable                                                             |       | **(328,000**                 | **)**          | (84,000 | ) | 148,000 |   |
| Accrued  liabilities                                                         |       | **2,153,000**                | ** **     | 679,000 |   | 21,000 |   |
| Billings in  excess of costs and estimated earnings on uncompleted contracts |       | **378,000**                  | ** **     | (85,000 | ) | (94,000 | ) |
| Payable to joint  interest owners                                            |       | **(42,000**                  | **)**          | (198,000 | ) | 403,000 |   |
| Income taxes  payable                                                        |       | **(323,000**                 | **)**          | 401,000 |   | (2,311,000 | ) |
| Increase  (decrease) from changes in current assets and liabilities          |       | **$**                        | **(1,357,000** | **)** | $ | 1,479,000 |   | $ | (2,587,000 | ) |
|                                                                         |       | ** **                   | ** **     |   |   |   |   |
| Supplemental  disclosure of cash flow information:                           |       | ** **                   | ** **     |   |   |   |   |
|                                                                         |       | ** **                   | ** **     |   |   |   |   |
| Cash paid during  the year for:                                              |       | ** **                   | ** **     |   |   |   |   |
| Interest (net of  amounts capitalized)                                       |       | **$**                        | **448,000**    | ** ** | $ | 454,000 |   | $ | 303,000 |   |
| Income taxes                                                                 |       | **$**                        | **4,495,000**  | ** ** | $ | 2,961,000 |   | $ | 3,812,000 |   |

 

Supplemental Disclosureof Non-cash Investing and Financing Activities:

In December 2003,Barnwell purchased the premises and associated fee simple land interest of itscorporate office in Honolulu, Hawaii, for $1,057,000, of which $883,000 wasfinanced by long-term debt; the debt was subsequently repaid in full in June2004.

 

On October 1, 2002, netoil and natural gas properties and the asset retirement obligation increased$1,110,000 as a result of adoption of Statement of Financial AccountingStandards No. 143.

 

**16.****          SUBSEQUENT EVENTS**

 

On December 3, 2004, Barnwell declared a cashdividend of $0.25 per share payable January 5, 2005, to stockholders of recordon December 20, 2004.

 

Also on December 3, 2004,Barnwell declared a two-for-one stock split in the form of a stockdividend.  The new shares will bedistributed on January 28, 2005 to all shareholders of record as of January 11,2005.

 

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

 

The following tables summarize informationrelative to Barnwell’s oil and natural gas operations, which are substantiallyconducted in Canada.  Proved reserves arethe estimated quantities of crude oil, condensate and natural gas whichgeological and engineering data demonstrate with reasonable certainty to berecoverable in future years from known reservoirs under existing economic andoperating conditions.  Proved producingoil and natural gas reserves are reserves that can be expected to be recoveredthrough existing wells with existing equipment and operating methods.  The estimated net interests in total provedand proved producing reserves are based upon subjective engineering judgmentsand may be affected by the limitations inherent in such estimations.  The process of estimating reserves is subjectto continual revision as additional information becomes available as a resultof drilling, testing, reservoir studies and production history.  There can be no assurance that such estimateswill not be materially revised in subsequent periods.

 

(A)          Oiland Natural Gas Reserves

 

The following table,based on information prepared by independent petroleum engineers, PaddockLindstrom & Associates Ltd., summarizes changes in the estimates ofBarnwell’s net interests in total proved reserves of crude oil and natural gasliquids and natural gas (“MCF” means 1,000 cubic feet of natural gas) which areall in Canada:

 
| ** **                                         | ** ** | **OIL  (Barrels)** | ** ** | **GAS  (MCF)** | ** ** |
|----------------------------------------------------|------------|--------------------|------------|----------------|------------|
| Balance at  September 30, 2001                     |       | 1,536,000          |       | 28,371,000     |       |
|                                               |       |               |       |           |       |
| Revisions of  previous estimates                   |       | 184,000            |       | 985,000        |       |
| Extensions,  discoveries and other additions       |       | 49,000             |       | 1,087,000      |       |
| Less production                                    |       | (242,000           | )          | (3,277,000     | )          |
| Balance at  September 30, 2002                     |       | 1,527,000          |       | 27,166,000     |       |
|                                               |       |               |       |           |       |
| Revisions of  previous estimates                   |       | (35,000            | )          | (1,035,000     | )          |
| Extensions,  discoveries and other additions       |       | 136,000            |       | 4,683,000      |       |
| Less production                                    |       | (227,000           | )          | (3,175,000     | )          |
| Balance at September 30, 2003                      |       | 1,401,000          |       | 27,639,000     |       |
| ** **                                         | ** ** | ** **         | ** ** | ** **     | ** ** |
| 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** | ** ** |

 

----

*  Theseamounts represent proved undeveloped reserves at Dunvegan added by PaddockLindstrom & Associates, Ltd. based on the planned fiscal 2005 drillingprogram.  As of September 30, 2003,Paddock Lindstrom & Associates, Ltd. reported no proved undevelopedreserves at Dunvegan.

 

73

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| ** **                     | ** ** | **OIL  (Barrels)** | ** ** | **GAS  (MCF)** | ** ** |
|--------------------------------|------------|--------------------|------------|----------------|------------|
| Proved producing  reserves at: |       |               |       |           |       |
| September 30,  2001            |       | 1,327,000          |       | 21,847,000     |       |
| September 30,  2002            |       | 1,303,000          |       | 19,612,000     |       |
| September 30,  2003            |       | 1,262,000          |       | 21,463,000     |       |
| **September  30, 2004**        | ** ** | **1,135,000**      | ** ** | **21,614,000** | ** ** |

 

 

(B)           CapitalizedCosts Relating to Oil and Natural Gas Producing Activities

 

 
| ** **                                   | ** ** | **September 30,** | ** **     |
|----------------------------------------------|------------|-------------------|----------------|
| ** **                                   | ** ** | **2004**          | ** **     | **2003** | ** ** | **2002** | ** ** |
| Proved  properties                           | ** ** | **$**             | **93,732,000** |   | $ | 77,913,000 |   | $ | 56,959,000 |   |
| Unproved  properties                         | ** ** | **5,100,000**     |           | 2,950,000 |   | 1,149,000 |   |
| Total  capitalized costs                     | ** ** | **98,832,000**    |           | 80,863,000 |   | 58,108,000 |   |
| Accumulated  depletion and depreciation | ** ** | **53,108,000**    |           | 43,404,000 |   | 33,796,000 |   |
| Net capitalized  costs                       | ** ** | **$**             | **45,724,000** |   | $ | 37,459,000 |   | $ | 24,312,000 |   |

 

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

 
| ** **                  | ** ** | **Year ended September 30,** | ** **    |
|-----------------------------|------------|------------------------------|---------------|
| ** **                  | ** ** | **2004**                     | ** **    | **2003** | ** ** | **2002** | ** ** |
| Acquisition of  properties: |       |                         |          |   |   |   |   |
| Unproved                    | ** ** | **$**                        | **1,882,000** | ** ** | **$** | **715,000** |   | $ | 262,000 |   |
|                        |       |                         |          |   |   |   |   |
| Proved                      | ** ** | **$**                        | **—**    | ** ** | **$** | **635,000** | ** ** | **$** | **—** | ** ** |
|                        |       |                         |          |   |   |   |   |
| Exploration  costs          | ** ** | **$**                        | **3,460,000** | ** ** | **$** | **2,567,000** |   | $ | 1,007,000 |   |
|                        |       |                         |          |   |   |   |   |
| Development  costs          | ** ** | **$**                        | **6,534,000** | ** ** | **$** | **7,142,000** |   | $ | 3,312,000 |   |

 

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

 
| ** **                      | ** ** | **Year ended September 30,** | ** **     |
|---------------------------------|------------|------------------------------|----------------|
| ** **                      | ** ** | **2004**                     | ** **     | **2003** | ** ** | **2002** | ** ** |
| Gross revenues                  | ** ** | **$**                        | **31,206,000** |   | $ | 26,234,000 |   | $ | 14,896,000 |   |
| Royalties, net  of credit       | ** ** | **7,936,000**                |           | 6,884,000 |   | 3,576,000 |   |
| Net revenues                    | ** ** | **23,270,000**               |           | 19,350,000 |   | 11,320,000 |   |
| Production costs                | ** ** | **5,403,000**                |           | 4,192,000 |   | 3,108,000 |   |
| Depletion and  depreciation     | ** ** | **6,423,000**                |           | 4,026,000 |   | 3,315,000 |   |
| Pre-tax results  of operations* | ** ** | **11,444,000**               |           | 11,132,000 |   | 4,897,000 |   |
| Estimated income  tax expense   | ** ** | **5,489,000**                |           | 5,665,000 |   | 2,450,000 |   |
| Results of  operations*         | ** ** | **$**                        | **5,955,000**  |   | $ | 5,467,000 |   | $ | 2,447,000 |   |

 

----

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

 

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

 

The following tables havebeen developed pursuant to procedures prescribed by SFAS No. 69, and utilizereserve and production data estimated by petroleum engineers.  The information may be useful for certaincomparison purposes but should not be solely relied upon in evaluating Barnwellor its performance.  Moreover, theprojections should not be construed as realistic estimates of future cashflows, nor should the standardized measure be viewed as representing currentvalue.

 

The estimated future cashflows are based on sales prices, costs, and statutory income tax rates inexistence at the dates of the projections. Material revisions to reserve estimates may occur in the future,development and production of the oil and natural gas reserves may not occur inthe periods assumed and actual prices realized and actual costs incurred areexpected to vary significantly from those used. Management does not rely upon this information in making investment andoperating decisions; rather, those decisions are based upon a wide range of factors,including estimates of probable reserves as well as proved reserves and priceand cost assumptions different than those reflected herein.

 

Standardized Measure ofEstimated Discounted Future Net Cash Flows

 
| ** **                                                          | ** ** | **As of September 30,** | ** **      |
|---------------------------------------------------------------------|------------|-------------------------|-----------------|
| ** **                                                          | ** ** | **2004**                | ** **      | **2003** | ** ** | **2002** | ** ** |
| Future cash  inflows                                                |       | **$**                   | **168,526,000** | ** ** | $ | 141,809,000 |   | $ | 101,448,000 |   |
|                                                                |       | ** **              | ** **      |   |   |   |   |
| Future  production costs                                            |       | **(40,351,000**         | **)**           | (37,439,000 | ) | (30,537,000 | ) |
|                                                                |       | ** **              | ** **      |   |   |   |   |
| Future  development costs                                           |       | **(3,956,000**          | **)**           | (1,231,000 | ) | (1,263,000 | ) |
| Future net cash  flows before income taxes                          |       | **124,219,000**         | ** **      | 103,139,000 |   | 69,648,000 |   |
|                                                                |       | ** **              | ** **      |   |   |   |   |
| Future income  tax expenses                                         |       | **(35,937,000**         | **)**           | (32,604,000 | ) | (17,442,000 | ) |
|                                                                |       | ** **              | ** **      |   |   |   |   |
| Future net cash  flows                                              |       | **88,282,000**          | ** **      | 70,535,000 |   | 52,206,000 |   |
|                                                                |       | ** **              | ** **      |   |   |   |   |
| 10% annual  discount for timing of cash flows                       |       | **(27,272,000**         | **)**           | (20,998,000 | ) | (19,587,000 | ) |
|                                                                |       | ** **              | ** **      |   |   |   |   |
| Standardized  measure of estimated discounted future net cash flows |       | **$**                   | **61,010,000**  | ** ** | $ | 49,537,000 |   | $ | 32,619,000 |   |
|                                                                     |            |                         |                 |  |  |  |  |  |  |  |  |

 

75

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Changes in theStandardized Measure of Estimated Discounted Future Net Cash Flows

 
| ** **                                                                       | ** ** | **Year ended September 30,** | ** **     |
|----------------------------------------------------------------------------------|------------|------------------------------|----------------|
| ** **                                                                       | ** ** | **2004**                     | ** **     | **2003** | ** ** | **2002** | ** ** |
|                                                                             |       |                         |           |   |   |   |   |
| Beginning of  year                                                               |       | **$**                        | **49,537,000** | ** ** | $ | 32,619,000 |   | $ | 21,273,000 |   |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Sales of oil and  natural gas produced, net of production costs                  |       | **(17,875,000**              | **)**          | (15,107,000 | ) | (8,210,000 | ) |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Net changes in  prices and production costs, net of royalties and wellhead taxes |       | **16,363,000**               | ** **     | 18,878,000 |   | 12,469,000 |   |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Extensions and  discoveries                                                      |       | **13,304,000**               | *****          | 12,673,000 |   | 1,989,000 |   |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Purchases of properties                                                          |       | **—**                   | ** **     | 971,000 |   | — |   |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Revisions of  previous quantity estimates                                   |       | **(2,294,000**               | **)**          | 771,000 |   | 2,657,000 |   |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Net change in  Canadian dollar translation rate                                  |       | **2,529,000**                | ** **     | 4,441,000 |   | (41,000 | ) |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Changes in the  timing of future production and other                            |       | **(1,899,000**               | **)**          | (711,000 | ) | (1,224,000 | ) |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Net change in  income taxes                                                      |       | **(3,956,000**               | **)**          | (7,680,000 | ) | 1,957,000 |   |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Accretion of  discount                                                           |       | **5,301,000**                | ** **     | 2,682,000 |   | 1,749,000 |   |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| Net change                                                                       |       | **11,473,000**               | ** **     | 16,918,000 |   | 11,346,000 |   |
|                                                                             |       | ** **                   | ** **     |   |   |   |   |
| End of year                                                                      |       | **$**                        | **61,010,000** | ** ** | $ | 49,537,000 |   | $ | 32,619,000 |   |
|                                                                                  |            |                              |                |  |  |  |  |  |  |  |  |

 

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*  $3,260,000of this amount is derived from proved undeveloped reserves at Dunvegan added byPaddock Lindstrom & Associates, Ltd. based on the planned fiscal 2005drilling program.  As of September 30,2003, Paddock Lindstrom & Associates, Ltd. reported no proved undevelopedreserves at Dunvegan.

 

Item 7A.                 Quantitativeand Qualitative Disclosures About Market Risk

 

Barnwell’s primary marketrisk exposure is interest rate risk. Barnwell’s exposure to market risk for changes in interest rates relatesto its debt obligations under a floating interest rate loan.  Assuming variable rate debt at September 30,2004, a change of one hundred basis points in interest rates would impactannual net interest expense payments by $102,000.  Barnwell does not use derivative financialinstruments to manage interest rate risk. Partially mitigating this risk is the interest earned on Barnwell’scash, cash equivalents and certificates of deposit.

 

76

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Item 8.                    Changesin and Disagreements with Accountants on Accounting and Financial Disclosure

 

None.

 

Item 8A.**                **Controlsand Procedures

 

As of September 30, 2004,an evaluation was carried out by Barnwell’s Chief Executive Officer and ChiefFinancial Officer of the effectiveness of Barnwell’s disclosure controls andprocedures.  Based on that evaluation,the Chief Executive Officer and Chief Financial Officer have concluded thatBarnwell’s disclosure controls and procedures are effective to ensure thatinformation required to be disclosed by Barnwell in reports that it files orsubmits under the Securities and Exchange Act of 1934 is recorded, processed,summarized and reported within the time periods specified in the Securities andExchange Act of 1934 and the rules thereunder. There was no change in Barnwell's internal control over financialreporting during the quarter ended September 30, 2004, that materiallyaffected, or is reasonably likely to materially affect, Barnwell's internalcontrol over financial reporting.

 

Item 8B.**                 **OtherInformation 

 

None.

 

PART III

 

Item 9.                    Directors,Executive Officers, Promoters and Control Persons, Compliance With Section16(a) of the Exchange Act 

 

The information requiredis omitted pursuant to General Instruction E.3. of Form 10-KSB, since theRegistrant will file its definitive proxy statement for the 2004 Annual Meetingof Stockholder no later than 120 days after the close of its fiscal year endedSeptember 30, 2004, which proxy statement is incorporated herein by reference.

 

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

 

Item 10.                  ExecutiveCompensation

 

The information requiredis omitted pursuant to General Instruction E.3. of Form 10-KSB, since theRegistrant will file its definitive proxy statement for the 2004 Annual Meetingof Stockholder no later than 120 days after the close of its fiscal year endedSeptember 30, 2004, which proxy statement is incorporated herein by reference.

 

Item 11.                  SecurityOwnership of Certain Beneficial Owners and Management

 

The information requiredis omitted pursuant to General Instruction E.3. of Form 10-KSB, since theRegistrant will file its definitive proxy statement for the 2004 Annual Meetingof Stockholder no later than 120 days after the close of its fiscal year endedSeptember 30, 2004, which proxy statement is incorporated herein by reference.

 

77

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#### EquityCompensation Plan Information

 

The following table provides information aboutBarnwell’s common stock that may be issued upon exercise of options and rightsunder all of Barnwell’s existing equity compensation plans as of September 30,2004:

 
| **Plan Category**                                           | ** ** | **(a)  Number of  securities  to be issued  upon exercise  of outstanding  options, warrants  and rights** | ** ** | **(b)  Weighted-  average  price of  outstanding  options,  warrants  and rights** | ** ** | **(c)  Number of securities  remaining available  for future issuance  under equity  compensation plans  (excluding securities  reflected in column (a))** | ** ** |
|-------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| Equity  compensation plans approved by security holders     |       | 75,500                                                                                                     |       | $                                                                                  | 12.21      |                                                                                                                                                       | 36,000     |   |
| Equity  compensation plans not approved by security holders |       | 37,000                                                                                                     |       | $                                                                                  | 16.38      |                                                                                                                                                       | —     |   |
| Total                                                       |       | 112,500                                                                                                    |       | $                                                                                  | 13.58      |                                                                                                                                                       | 36,000     |   |

 

Equity compensation plansnot approved by security holders are comprised of the following plans:

 

In March 1995, Barnwellgranted 20,000 stock options to an officer and director of Barnwell under anon-qualified plan at a purchase price of $19.625 per share (market price ondate of grant), with 4,000 of such options vesting annually commencing one yearfrom the date of grant.  These optionshave stock appreciation rights that permit the holder to receive stock, cash ora combination thereof equal to the amount by which the fair market value, atthe time of exercise of the option, exceeds the option price.  The options expire in March 2005.  During the year ended September 30, 2004, theofficer and director exercised his right to receive in cash the value of 13,000shares of these non-qualified stock options (stock appreciation rights) at anexercise price of $19.625 per share.  Thedifference between the exercise price and the price per share on the dates ofexercise (ranging from $41.95 to $45.00 per share) was paid to this employee incash by Barnwell.

 

In June 1998, Barnwellgranted 30,000 stock options to an officer of Barnwell’s oil and gas segmentunder a non-qualified plan at a purchase price of $15.625 per share (marketprice on date of grant), with 6,000 of such options vesting annually commencingone year from the date of grant.  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.  The options expire in May 2008.

 

Item 12.                  CertainRelationships and Related Transactions

 

The information requiredis omitted pursuant to General Instruction E.3. of Form 10-KSB, since theRegistrant will file its definitive proxy statement for the 2004 Annual Meetingof Stockholder no later than 120 days after the close of its fiscal year endedSeptember 30, 2004, which proxy statement is incorporated herein by reference.

 

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Item 13.                  Exhibits,List and Reports on Form 8-K

 

(A)          FinancialStatements

 

The followingconsolidated financial statements of Barnwell Industries, Inc. and itssubsidiaries are included in Part II, Item 7:

 
| Report of Independent Registered  Public Accounting Firm – KPMG LLP                                                            |   |
|-------------------------------------------------------------------------------------------------------------------------------------|--------|
|                                                                                                                                |   |
| Consolidated Balance Sheets  – September 30, 2004 and 2003                                                                     |   |
|                                                                                                                                |   |
| Consolidated  Statements of Operations – for the three years ended September 30, 2004                                          |   |
|                                                                                                                                |   |
| Consolidated  Statements of Cash Flows – for the three years ended September 30, 2004                                          |   |
|                                                                                                                                |   |
| Consolidated Statements of  Stockholders’ Equity and Comprehensive Income (Loss) for the three years  ended September 30, 2004 |   |
|                                                                                                                                |   |
| 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)           Reportson Form 8-K

 

None.

 

(C)           Exhibits

 
| No. 3.1  | Certificate of Incorporation(1)                                                                                                                                        |   |
|----------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
|     |                                                                                                                                                                   |   |
| No. 3.2  | Amended and Restated By-Laws(1)                                                                                                                                        |   |
|     |                                                                                                                                                                   |   |
| No. 4.0  | Form of the Registrant’s certificate of common  stock, par value $.50 per share.(2)                                                                               |   |
|     |                                                                                                                                                                   |   |
| No. 10.1 | The Barnwell Industries, Inc. Employees’ Pension  Plan (restated as of October 1, 1989).(3)                                                             |   |
|     |                                                                                                                                                                   |   |
| No. 10.2 | Phase I Makai Development Agreement dated June 30,  1992, by and between Kaupulehu Makai Venture and Kaupulehu Developments.(4)                                        |   |
|     |                                                                                                                                                                   |   |
| No. 10.3 | KD/KMV Agreement dated June 30, 1992 by and between  Kaupulehu Makai Venture and Kaupulehu Developments.(4)                                                            |   |
|     |                                                                                                                                                                   |   |
| No. 10.4 | Barnwell Industries, Inc.’s letter to Warren D.  Steckley dated May 6, 1998, regarding certain terms of employment.(5)                                            |   |
|     |                                                                                                                                                                   |   |
| No. 21   | List of Subsidiaries                                                                                                                                                   |   |
|     |                                                                                                                                                                   |   |
| No. 31.1 | Section 302 Certification by Morton H. Kinzler,  Chief Executive Officer                                                                                               |   |
|     |                                                                                                                                                                   |   |
| No. 31.2 | Section 302 Certification by Russell M. Gifford,  Chief Financial Officer                                                                                              |   |
|     |                                                                                                                                                                   |   |
| No. 32   | Certification of Chief Executive Officer and Chief  Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted by Section  906 of the Sarbanes-Oxley Act of 2002 |   |

 

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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 filed by theRegistrant January 29, 1957 and as amended February 15, 1957 andFebruary 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.

 

79

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Item14.                  PrincipalAccountant Fees and Services

 

The information requiredis omitted pursuant to General Instruction E.3. of Form 10-KSB, since theRegistrant will file its definitive proxy statement for the 2004 Annual Meetingof Stockholder no later than 120 days after the close of its fiscal year endedSeptember 30, 2004, which proxy statement is incorporated herein by reference.

 

80

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SIGNATURES

 

In accordance with Section 13 or 15(d) of theSecurities Act, the registrant has this report to be signed on its behalf bythe undersigned, thereunto duly authorized.

 
| BARNWELL INDUSTRIES,  INC. |                       |
|----------------------------|----------------------------|
| (Registrant)               |                       |
|                       |                       |
|                       |                       |
|                       | /s/ Russell M. Gifford     |   |   |
| By:                        | Russell M. Gifford         |   |
|                       | Chief Financial  Officer,  |   |
|                       | Executive Vice  President, |   |
|                       | Treasurer and Secretary    |   |
| Date:                      | December 3, 2004           |   |
|                            |                            |  |  |  |

 

In accordance with Exchange Act the 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 3, 2004        |                                 |
|                          |                                 |
| /s/  Martin Anderson          |                                 | /s/  Terry Johnston       |   |
| MARTIN ANDERSON,  Director    | TERRY JOHNSTON,  Director            |
| Date: December 3, 2004        | Date: December 3, 2004               |
|                          |                                 |
| /s/  Murray C. Gardner        |                                 | /s/  Diane G. Kranz       |   |
| MURRAY C. GARDNER,  Director  | DIANE G. KRANZ,  Director            |
| Date: December 3, 2004        | Date: December 3, 2004               |
|                          |                                 |
| /s/  Erik Hazelhoff-Roelfzema |                                 | /s/  Alexander C. Kinzler |   |
| ERIK  HAZELHOFF-ROELFZEMA     | ALEXANDER C. KINZLER                 |
| Director                      | President, Chief  Operating Officer, |
| Date: December 3, 2004        | General Counsel and  Director        |
|                          | Date: December 3, 2004               |
|                          |                                 |
| /s/  Alan D. Hunter           |                                 | /s/  Russell M. Gifford   |   |
| ALAN D. HUNTER,  Director     | RUSSELL M. GIFFORD                   |
| Date: December 3, 2004        | Executive Vice  President,           |
|                          | Chief Financial  Officer, Treasurer  |
|                          | Secretary and Director               |
|                          | Date: December 3, 2004               |

 

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