U.S. SECURITIES AND EXCHANGE 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 September 30, 2004

 

o

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

 

Commission File Number 1-5103

 

BARNWELL INDUSTRIES, INC.

(Name of small business issuer in its charter)

 

Delaware

 

72-0496921

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

 

 

1100 Alakea Street, Suite 2900, Honolulu, Hawaii  96813-2833

(Address of principal executive offices)

 

(Zip code)

 

(808) 531-8400

(Issuer’s telephone number)

 

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock, par value
$0.50 per share

 

American Stock Exchange

 

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

 

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

 

Yes

ý

No

o

 

 

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

 

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

 

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

 

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

 

Documents Incorporated by Reference

 

1.                                             Proxy statement to be forwarded to shareholders on or about January 20, 2005 is incorporated by reference in Part III hereof.

 

Transitional Small Business Disclosure Format                                         Yes  o   No  ý

 

 



 

TABLE OF CONTENTS

 

PART I

 

 

Discussion of Forward-Looking Statements

 

 

Item 1.

Description of Business

 

 

 

 

General Development of Business

 

 

 

 

Financial Information about Industry Segments

 

 

 

 

Narrative Description of Business

 

 

 

 

Financial Information about Foreign and Domestic Operations and Export Sales

 

 

Item 2.

Description of Property

 

 

 

 Oil and Natural Gas Operations

 

 

 

 

General

 

 

 

 

Well Drilling Activities

 

 

 

 

Oil and Natural Gas Production

 

 

 

 

Productive Wells

 

 

 

 

Developed Acreage and Undeveloped Acreage

 

 

 

 

Reserves

 

 

 

 

Estimated Future Net Revenues

 

 

 

 

Marketing of Oil and Natural Gas

 

 

 

 

Governmental Regulation

 

 

 

 

Competition

 

 

 

 Contract Drilling Operations

 

 

 

 

Activity

 

 

 

 

Competition

 

 

 

 Land Investment Operations

 

 

 

 

Activity

 

 

 

 

Competition

 

 

 

Corporate Office

 

 

Item 3.

Legal Proceedings

 

 

Item 4.

Submission of Matters to a Vote of Security Holders

 

PART II

 

 

 

 

Item 5.

Market For Common Equity and Related Stockholder Matters

 

 

Item 6.

Management’s Discussion and Analysis or Plan of Operation

 

 

 

 

Results of Operations

 

 

 

 

Liquidity and Capital Resources

 

 

Item 7.

Financial Statements

 

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

 

 

Item 8.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

 

Item 8A.

Controls and Procedures

 

 

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

 

 

2



 

PART I

 

Forward-Looking Statements

 

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

 

Barnwell’s oil and natural gas operations are affected by domestic and international political, legislative, regulatory and legal actions.  Such actions may include changes in the policies of the Organization of Petroleum Exporting Countries or other developments involving or affecting oil-producing countries, including military conflict, embargoes, internal instability or actions or reactions of the government of the United States in anticipation of or in response to such developments.  Domestic and international economic conditions, such as recessionary trends, inflation, interest costs, monetary exchange rates and labor costs, as well as changes in the availability and market prices of crude oil, natural gas and other petroleum products, may also have a significant effect on Barnwell’s oil and natural gas operations.  While Barnwell maintains reserves for anticipated liabilities and carries various levels of insurance, Barnwell could be affected by civil, criminal, regulatory or administrative actions, claims or proceedings.  In addition, climate and weather can significantly affect Barnwell in several of its operations.  Barnwell’s oil and gas operations are also affected by political developments and laws and regulations, particularly in the United States and Canada, such as restrictions on production, restrictions on imports and exports, the maintenance of specified reserves, tax increases and retroactive tax claims, expropriation of property, cancellation of contract rights, environmental protection controls, environmental compliance requirements and laws pertaining to workers’ health and safety.  Costs of compliance with environmental laws are ingrained in Barnwell’s expenses and not distinguished from other costs and expenses.

 

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

 

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

 

3



 

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

 

Item 1.            Description of Business

(a)       General Development of Business

 

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

 

Barnwell’s oil and natural gas activities comprise its largest business segment.  Approximately 61% 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” revenues in the Consolidated Statements of Operations, accounted for 27% of Barnwell’s revenues in fiscal 2004; contract drilling activities comprised 10% of fiscal 2004 revenues; and other revenues comprised 2% of fiscal 2004 revenues.  Approximately 90% of Barnwell’s capital expenditures for the fiscal year ended September 30, 2004 were attributable to oil and natural gas activities and 10% were applicable to other activities.

 

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

 

(ii)               Contract Drilling. Barnwell’s wholly-owned subsidiary, Water Resources International, Inc., drills wells and installs and repairs water pumping systems in Hawaii.  Water Resources owns and operates four rotary drill rigs, pump installation and service equipment, leases one rotary drill/workover rig to an oil company, and maintains drilling materials and pump inventory in Hawaii.  Water Resources’ contracts are usually fixed price per lineal foot drilled or day rate contracts that are either negotiated with private entities or are obtained through competitive bidding with various private entities or local, state and federal agencies.  Barnwell’s contract drilling subsidiary derived 70%, 66% and 70% of its contract drilling revenues in fiscal 2004, 2003 and 2002, respectively, pursuant to Federal, State of Hawaii and county contracts.

 

(iii)          Land Investment. Barnwell owns a 77.6% controlling interest in Kaupulehu Developments, a Hawaii general partnership which owns interests in leasehold land and development rights for property located approximately six miles north of the Kona International Airport in the North Kona District of the Island of Hawaii.  Between 1986 and 1989, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of the Four Seasons Resort Hualalai at

 

4



 

Historic Ka’upulehu and Hualalai Golf Club, which opened in 1996, a second golf course, and single and multiple family residential units.  These projects were developed on leasehold land acquired from Kaupulehu Developments by Kaupulehu Makai Venture, an unrelated entity that is an affiliate of Kajima Corporation of Japan.  Kaupulehu Developments later obtained the state and county zoning changes necessary to permit development of single and multi-family residential units, a golf course and a limited commercial area on approximately 870 leasehold acres located adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka’upulehu.

 

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

 

(b)       Financial Information about Industry Segments

 

Revenues of each industry segment for the fiscal years ended September 30, 2004, 2003 and 2002 are summarized as follows (all revenues were 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 AND GEOGRAPHIC INFORMATION) and Note 14 (CONCENTRATIONS OF CREDIT RISK) of “Notes to Consolidated Financial Statements” in Item 7.

 

(c)       Narrative Description of Business

 

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

 

As of September 30, 2004, Barnwell employed 52 employees, 49 of which are on a full-time basis.  Twenty-five are employed in contract drilling activities, 16 are employed in oil and natural gas activities, and 11 are members of the corporate and administrative staff.

 

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

 

5



 

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

 

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

 

Item 2.            Description of Property

 

OIL AND NATURAL GAS OPERATIONS

 

General

 

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

 

Barnwell initiates and participates in exploratory and developmental operations for oil and natural gas on property in which it has an interest.  Barnwell also evaluates proposals by third parties for participation in other exploratory and developmental opportunities.  All exploratory and developmental operations are overseen by Barnwell’s Calgary, Alberta staff along with independent consultants as necessary.  In fiscal 2004, Barnwell participated in exploratory and developmental operations in the Canadian Provinces of Alberta and Saskatchewan, although Barnwell does not limit its consideration of exploratory and developmental operations to these areas.

 

Barnwell’s producing natural gas properties are located principally in Alberta.  A small number of producing properties are located in British Columbia and Saskatchewan.  The Province of Alberta determines its royalty share of natural gas by using a reference price that averages all natural gas sales in Alberta.  Royalty rates are calculated on a sliding scale basis, increasing as prices increase.  Additionally, Barnwell pays gross overriding royalties on a portion of its natural gas sales to other parties.

 

In fiscal 2004, the weighted average rate of all royalties paid to governments and others on natural gas from the Dunvegan Unit, Barnwell’s principal oil and natural gas property, before the Alberta Royalty Tax Credit, was approximately 30%.  The weighted average rate of royalties paid on all of Barnwell’s natural gas was approximately 27% in fiscal 2004, versus approximately 28% in fiscal 2003.

 

In fiscal 2004, virtually all of Barnwell’s oil production was from properties located in Alberta.  The Province of Alberta determines its royalty share of oil by using a reference price that averages all oil sales in Alberta.  Royalty rates are calculated on a sliding scale basis, increasing as prices increase.  Additionally, Barnwell pays gross overriding royalties and leasehold royalties on a portion of its oil sales to parties other than the Province of Alberta.  In fiscal 2004 and 2003, the weighted average royalty rate paid on oil was approximately 22% and 24%, respectively.  The decrease in the weighted average royalty rate on oil was primarily due to lower royalty rates on new oil production.

 

6



 

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

 

Well Drilling Activities

 

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

 

The following table sets forth more detailed information with respect to the number of exploratory (“Exp.”) and development (“Dev.”) wells drilled for the fiscal years ended September 30, 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

 

 


*                 The term “Gross” refers to the total number of wells in which Barnwell owns an interest, and “Net” refers to Barnwell’s aggregate interest therein.  For example, a 50% interest in a well represents 1 gross well, but 0.5 net well.  The gross figure includes interests owned of record by Barnwell and, in addition, the portion owned by others.

 

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

 

7



 

Capital expenditures totaled $1,740,000 in the Bonanza/Balsam area, where five gross wells (2.2 net wells) were drilled in fiscal 2004, as compared to $1,552,000 in fiscal 2003.  Two gross wells (0.7 net wells) were successful and tied in and producing at September 30, 2004, and three 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 net wells).  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 required on the well before it can be determined to be a successful well.

 

In the Wood River area, where capital expenditures totaled $615,000 in fiscal 2004, Barnwell drilled four gross wells (0.4 net wells).  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 expenditures totaled $550,000 in fiscal 2004, one unsuccessful well (0.5 net well) was drilled 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) were drilled, seven of which were producing at September 30, 2004.

 

Barnwell’s average net interest in wells drilled in fiscal 2004 was approximately 10%, as compared to 23% in fiscal 2003 and 34% in fiscal 2002.  The decrease in fiscal 2004, as compared to fiscal 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 drilling programs.  The average net interest in all other wells drilled in fiscal 2004 was 26%.  Of the wells drilled in fiscal 2004, 20 gross wells (7.9 net wells) were on prospects developed by Barnwell.

 

Oil and Natural Gas Production

 

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

 

8



 

 

 

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

 

 


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

**                                  Calculated on revenues before royalty expense and royalty tax credit divided by gross production.

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

 

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

 

In fiscal 2004, Barnwell’s net production after royalties for natural gas averaged 9,240 MCF per day, an increase of 6% from 8,700 MCF per day in fiscal 2003.  Gross natural gas production also increased 6% in fiscal 2004, as compared to fiscal 2003.  Dunvegan contributed approximately 44% of Barnwell’s net natural gas production in fiscal 2004, an increase from 43% in fiscal 2003.

 

Barnwell’s major oil producing properties are the Red Earth, Chauvin and Bonanza areas in Canada.  In fiscal 2004, net production after royalties for oil averaged 420 barrels per day, an increase of 8% from 390 barrels per day in fiscal 2003.  This increase was due to new production from the Bonanza and Wizard Lake areas, partially offset by decreases in production at certain older properties.

 

In fiscal 2004, net production after royalties for natural gas liquids averaged 290 barrels per day, an increase of 26% from 230 barrels per day in fiscal 2003.  This increase was due to increased production from the Dunvegan area and to a fire in early October 2002 at a Dunvegan gas plant that prevented stripping of natural gas liquids from the natural gas, resulting in an approximately 6,000 barrel decline in liquids net production in fiscal 2003.

 

9



 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

10



 

The following table sets forth the gross and net number of productive wells Barnwell 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

 

 


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

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

 

Developed Acreage and Undeveloped Acreage

 

The following table sets forth certain information with respect to oil and natural gas properties of Barnwell as of September 30, 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

 

 


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

 

(2)                “Gross” also refers to the total number of acres or wells in which Barnwell owns an interest, and “Net” refers to Barnwell’s aggregate interest therein.  For example, a 50% interest in a 320 acre lease represents 320 Gross Acres and 160 Net Acres.  The gross acreage and well figures include interests owned of record by Barnwell and, in addition, the portion owned by others.

 

Barnwell’s leasehold interests in its undeveloped acreage expire over the next fiscal years, if not developed, as follows: 7% expire during fiscal 2005; 8% expire during fiscal 2006; 9% expire during fiscal 2007; 18% expire during fiscal 2008; 40% expire during fiscal 2009; and 3% expire during fiscal 2010.  Fifteen percent of Barnwell’s undeveloped acreage is not subject to expiration because they are

 

11



 

related to heavy oil and other areas where leases are allowed to continue indefinitely without having a well on the acreage.  There can be no assurance that Barnwell will be successful in renewing its leasehold interests in the event of expiration.

 

Barnwell’s undeveloped acreage includes major concentrations in Alberta, at Thornbury (5,584 net acres), Swalwell (4,045 net acres), 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 net acres), and Gere (1,507 net acres).

 

Reserves

 

The amounts set forth in the table below, prepared by Paddock Lindstrom & Associates Ltd., Barnwell’s independent reservoir engineering consultants, summarize the estimated net quantities of proved producing reserves and proved reserves of crude oil (including condensate and natural gas liquids) and natural gas as of September 30, 2004, 2003, and 2002 on all properties in which Barnwell has an interest.  These reserves are before deductions for indebtedness secured by the properties and are based on constant dollars.  No estimates of total proved net oil or natural gas reserves have been filed with or included in reports to any federal authority or agency since October 1, 2001.

 

Proved Producing Reserves

 

 

 

September 30,

 

 

 

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’s proved producing and total proved reserves were located in the Province of Alberta, with minor volumes located in the Provinces of Saskatchewan and British Columbia.

 

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

 

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The change in oil, condensate and natural gas liquids reserves was the net result of production during the year of 259,000 barrels, the addition of 115,000 barrels from the drilling of productive wells, the addition of 54,000 undeveloped barrels from the planned drilling of wells at Dunvegan in fiscal 2005, and the independent engineer’s 7,000 barrel downward revision of Barnwell’s oil reserves.

 

The change in natural gas reserves was the net result of production during the year of 3,383,000 MCF, the addition of 2,127,000 MCF from the drilling of productive natural gas wells, the addition of 1,571,000 undeveloped MCF from the planned drilling of wells at Dunvegan in fiscal 2005, and the independent engineer’s 1,129,000 MCF downward revision of Barnwell’s natural gas reserves.  543,000 MCF of the independent engineer’s downward revision was due to newly enacted regulations restricting the production of natural gas at Thornbury due to its possible negative impact on the future production of heavy oil in the area.

 

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

 

The following table sets forth Barnwell’s oil and natural gas reserves at September 30, 2004, by property name, based on information prepared by Paddock Lindstrom & Associates Ltd.  Gross reserves are before the deduction of royalties; net reserves are after the deduction of royalties net of the Alberta Royalty Tax Credit.  This table is based on constant dollars where reserve estimates are based on sales prices, costs and statutory tax rates in existence at the date of the projection.  Oil, which includes natural gas liquids, is shown in thousands of barrels (“MBBLS”) and natural gas is shown in millions of cubic feet (“MMCF”).

 

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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 unless otherwise noted.

 

14



 

Estimated Future Net Revenues

 

The following table sets forth Barnwell’s “Estimated Future Net Revenues” from total proved oil, natural gas and condensate reserves and the present value of Barnwell’s “Estimated Future Net Revenues” (discounted at 10%).  Estimated future net revenues for total proved reserves are net of estimated development costs.  Net revenues have been calculated using current sales prices and costs, after deducting all royalties net of the Alberta Royalty Tax Credit, operating costs, future estimated capital expenditures, and income taxes.

 

 

 

Proved Producing
Reserves

 

Total Proved
Reserves

 

Year ending September 30,

 

 

 

 

 

 

 

 

 

 

 

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

 

Natural gas sold by Barnwell is generally sold under both long-term and short-term contracts with prices indexed to market prices.  The price of natural gas and natural gas liquids is freely negotiated between buyers and sellers.  In 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 a producing property market the products on Barnwell’s behalf.

 

In fiscal 2004, natural gas production from the Dunvegan Unit was responsible for approximately 42% of Barnwell’s natural gas revenues, as compared to 41% in fiscal 2003.  In fiscal 2004, Barnwell had three individually significant customers that accounted for 53% of Barnwell’s oil and natural gas revenues.  A substantial portion of Barnwell’s Dunvegan natural gas production and natural gas production from other properties is sold to aggregators and marketers under various short-term and long-term contracts, with the price of natural gas determined by negotiations between the aggregators and the final purchasers.  In fiscal 2004, Barnwell continued its strategy to increase the volumes of natural gas sold into spot markets, reaching approximately 49% of natural gas volumes, to take advantage of new pipeline access to premium markets and higher prices.

 

Governmental Regulation

 

The jurisdictions in which the oil and natural gas properties of Barnwell are located have regulatory provisions relating to permits for the drilling of wells, the spacing of wells, the prevention of

 

15



 

oil and natural gas waste, allowable rates of production and other matters.  The amount of oil and natural gas produced is subject to control by regulatory agencies in each province and state that periodically assign allowable rates of production.  The Province of Alberta and Government of Canada also monitor and regulate the volume of natural gas that may be removed from the province and the conditions of removal.

 

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

 

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

 

Different royalty rates are imposed by the provincial governments, the Government of Canada and private interests with respect to the production and sale of crude oil, natural gas and liquids.  In addition, provincial governments receive additional revenue through the imposition of taxes on crude oil and natural gas owned by private interests within the province.  Essentially, provincial royalties are calculated as a percentage of revenue, and vary depending on production volumes, selling prices and the date of discovery.

 

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

 

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

 

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

 

16



 

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

 

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

 

Competition

 

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

 

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

 

 

CONTRACT DRILLING OPERATIONS

 

Barnwell owns 100% of Water Resources International, Inc. which drills water and exploratory wells and installs and repairs water pumping systems in Hawaii.  Water Resources owns and operates four Spencer-Harris portable rotary drill rigs ranging in drilling capacity from 3,500 feet to 7,000 feet, and leases an IDECO H-35 rotary drill/workover rig to an oil company.  Additionally, Water Resources leases a three-quarter of an acre maintenance facility in Honolulu and a one acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii, and maintains an inventory of drilling and pump supplies.  As of September 30, 2004, Water Resources employed 25 drilling, pump and administrative employees, none of whom are union members.

 

Water Resources drills water, water monitoring and geothermal wells of varying depths in Hawaii and also installs and repairs water pumps and is the State of Hawaii’s distributor for Floway pumps and equipment.  The demand for Water Resources’ services is primarily dependent upon land development activities in Hawaii.  Water Resources markets its services to land developers and government agencies, and identifies potential contracts through public notices, its officers’ involvement

 

17



 

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

 

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

 

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

 

Activity

 

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

 

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

 

The dollar amount of Barnwell’s backlog of firm well drilling and pump installation and repair contracts at November 30, 2004 and 2003 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

 

 

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

 

Competition

 

Water Resources utilizes rotary drill rigs and competes with other drilling contractors in Hawaii which use cable tool rigs, which require less labor to operate but generally drill slower, rotary drill rigs similar to Water Resources’ drilling rigs, and top head rotary drilling rigs that drill as quickly as Water Resources’ equipment but require less labor.  These competitors are also capable of installing and repairing vertical turbine and submersible water pumping systems in Hawaii.  These contractors compete actively with Water Resources for government and private contracts.  Pricing is Barnwell’s major method of competition; reliability of service is also a significant factor.

 

18



 

The number of available water well drilling jobs has increased from the prior year and Barnwell has been awarded more jobs in recent months.  Competitive pressures are expected to remain high, thus there is no assurance that the trend in available or awarded jobs will continue.

 

LAND INVESTMENT OPERATIONS

 

Barnwell owns a 77.6% controlling interest in Kaupulehu Developments, a Hawaii general partnership that owns interests in leasehold land and development rights for property located approximately six miles north of the Kona International Airport in the North Kona District of the Island of Hawaii.  Between 1986 and 1989, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of the Four Seasons Resort Hualalai at Historic Ka’upulehu and Hualalai Golf Club, which opened in 1996, a second golf course, and single and multiple family residential units.  These projects were developed on leasehold land acquired from Kaupulehu Developments by Kaupulehu Makai Venture, an unrelated entity that is an affiliate of Kajima Corporation of Japan.

 

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

 

Kaupulehu Developments holds development rights for residentially zoned leasehold land within and adjacent to the Hualalai Golf Club and are under option to Kaupulehu Makai Venture.

 

Activity

 

Interests in Leasehold Land

 

On February 13, 2004, Kaupulehu Developments entered into a Purchase and Sale Agreement with WB KD Acquisition LLC (“WB”) by which Kaupulehu Developments transferred its leasehold interest in the approximately 870 acres zoned for resort/residential development, in two increments, to WB.  There is no affiliation between Kaupulehu Developments and WB.  WB is an affiliate of Westbrook Partners, developers of the Kuki’o Resort.  The first increment (“Increment I”) is an area planned for approximately 80 single-family lots and a beach club on the portion of the property bordering the Pacific Ocean.  The purchasers of the 80 single-family lots will have the right to apply for membership in the Kuki’o Resort Golf and Beach Club, which is located adjacent to and south of the Four Seasons Resort Hualalai at Historic Ka’upulehu.  The second increment (“Increment II”) is the remaining portion of the approximately 870-acre property and is zoned for single-family and multi-family residential units and a golf course and clubhouse.

 

 With respect to Increment I, Kaupulehu Developments received a non-refundable $11,550,000 payment (“Closing Payment”) and is entitled to receive payment of the following percentages of the gross proceeds generated from the sale by WB of single-family lots in Increment I (“Percentage Payments”): 9% of the gross proceeds from single-family lot sales up to aggregate gross proceeds of $100,000,000; 10% of such aggregate gross proceeds greater than $100,000,000 but less than $300,000,000; and 14% of such aggregate gross proceeds in excess of $300,000,000.  If prior to

 

19



 

December 31, 2005, Kaupulehu Developments has not received Percentage Payments equal to or greater than $2,500,000 in the aggregate, WB will pay Kaupulehu Developments the amount by which the aggregate amount of all prior 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 (including payments in lieu of Percentage Payments as described in the immediately preceding sentence) equal to or greater than $5,000,000 in the aggregate, then WB will pay Kaupulehu Developments the amount by which the aggregate amount of all such payments is less than $5,000,000.  Additionally, WB agreed to pay Kaupulehu Developments non-refundable interim payments of $50,000 per month (“Interim Payments”), until the first to occur of the closing of the sale of the 40th single-family lot sold in Increment I or WB’s payment to Kaupulehu Developments of a total of $900,000 in Interim 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 Interim Payments or any Percentage Payments will be received.

 

Kaupulehu Developments, WB and The Trustees of The Estate of Bernice Pauahi Bishop (“KS”) also entered into an agreement (the “Step-In Rights Agreement”) whereby if WB elects not to proceed with development of Increment 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 development rights and develop the property without any payment to WB.

 

In March 2004, WB commenced engineering of infrastructure, preparation of covenants, conditions and restrictions for a community association, and preparation of legal documents to enable real estate sales, and broke ground and graded several miles of access roads.  In late September 2004, WB began mass grading of the first phase of 38 lots for development.

 

For Increment II, Kaupulehu Developments and WB agreed to 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 of the first single-family lot in Increment I, an agreement with regards to the ownership and development of Increment II.  WB, however, may terminate such negotiations at any time without any further obligation. Under the terms of the Step-In Rights Agreement, if at the end of three years following the closing of the sale of the first single-family lot in Increment I the parties have not entered into a definitive agreement with respect to Increment II, the leasehold rights with respect to Increment II will revert 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 the cost and the estimated future costs related to the leasehold interest sold.  The revenue from the $11,550,000 Closing Payment plus $350,000 of post-closing Interim Payments received in March through 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 of previously capitalized costs relating to Increment I.  The $7,330,000 of net revenue from the Closing Payment and Interim Payments for the year ended September 30, 2004 is recorded in the Consolidated Statements of Operations as “Sale of interest in leasehold land, net.”  Operating profit on 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 leasehold land in the years ended September 30, 2003 and 2002.  As no sales price or agreement with regards to the ownership and development of Increment II has yet been determined, no revenues or cost of sales have been recognized on Increment II.

 

20



Development Rights

 

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

 

The total amount of remaining future option receipts 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 31 of years 2004 to 2010.  If any annual option payment is not made, the then remaining development right options will expire.  There is no assurance that any portion of the remaining options will be exercised.

 

Interests at September 30, 2004

 

The interests held by Kaupulehu Developments at September 30, 2004 include the development rights under option; the rights to receive Increment I percentage and interim payments; the leasehold land zoned for resort/residential development within Increment II, which is under a right of negotiation with WB; and approximately 1,000 acres of vacant leasehold land zoned conservation.

 

Competition

 

Barnwell’s land investment segment is subject to intense competition in all phases of its operations including the acquisition of new properties, the securing of approvals necessary for land rezoning, and the search for potential buyers of property interests presently owned.  The competition comes from numerous independent land development companies and other industries involved in land investment activities.  The principal factors affecting competition are the location of the project and pricing.  Kaupulehu Developments is a minor participant in the land development industry and competes in its land investment activities with many other entities having far greater financial and other resources.

 

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

 

21



 

CORPORATE OFFICE

 

In December 2003, Barnwell purchased the space it was leasing for its corporate offices located at 1100 Alakea Street, Suite 2900, Honolulu, Hawaii 96813 for $1,057,000, of which $883,000 was financed by a note payable to a Hawaii bank and the remainder was paid in cash.  The seller was A&B Alakea LLC, an independent third party.  The note was payable in monthly principal payments of approximately $3,000, plus interest, and was due in full in December 2006.  Barnwell repaid the note in full in fiscal 2004.  The space purchased has 4,662 useable square feet in an office building in downtown Honolulu, Hawaii.

 

Item 3.            Legal Proceedings

 

Barnwell is occasionally involved in routine litigation and is subject to governmental and regulatory controls that are incidental to the business.  Barnwell’s management believes that routine claims and litigation involving Barnwell are not likely to have a material adverse effect on its financial position, results of operations or liquidity.

 

Item 4.            Submission of Matters to a Vote of Security Holders

 

None.

 

PART II

 

Item 5.            Market For Common Equity and Related Stockholder Matters

 

The principal market on which Barnwell’s common stock is being traded is the American Stock Exchange.  The following tables present the quarterly high and low sales prices, on the American Stock Exchange, for Barnwell’s common stock during the periods indicated:

 

Quarter Ended

 

High

 

Low

 

Quarter Ended

 

High

 

Low

 

December 31, 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 December 20, 2004, there were 1,356,010 shares of common stock, par value $0.50, outstanding.  There were approximately 400 holders of the common stock of the registrant as of December 20, 2004.

 

On December 3, 2004, Barnwell declared a cash dividend of $0.25 per share payable January 5, 2005, to stockholders of record on December 20, 2004.

 

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

 

22



 

In August 2004, Barnwell declared a dividend of $0.15 per share payable September 15, 2004, to stockholders of record on August 27, 2004.

 

In February 2004, Barnwell declared a dividend of $0.50 per share payable March 12, 2004, to stockholders of record on February 27, 2004.

 

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

 

23



 

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

 

The following discussion is intended to assist in the understanding of the consolidated balance sheets of Barnwell Industries, Inc. and subsidiaries (collectively referred to herein as “Barnwell”) as of September 30, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended September 30, 2004.  This discussion should be read in conjunction with the Consolidated Financial Statements and related Notes To Consolidated Financial Statements included in this report.

 

USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities.  Actual results could differ significantly from those estimates.

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

 

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

 

Oil and natural gas properties

 

Barnwell uses the full cost method of accounting under which all costs incurred in the acquisition, exploration and development of oil and natural gas reserves, including unsuccessful wells, are capitalized until such time as the aggregate of such costs, on a country-by-country basis, equals the discounted present value (at 10%) of Barnwell’s estimated future net cash flows from estimated production of proved oil and natural gas reserves, from such country, as determined by independent petroleum engineers, less related income tax effects.  Any capitalized costs, net of oil and gas related deferred income taxes, in excess of the discounted present value of proved properties and the lower of cost or estimated fair value of unproved properties are charged to expense.  Depletion of all such costs, except costs related to major development projects, is provided by the unit-of-production method based upon proved oil and natural gas reserves of all properties on a country-by-country basis.  Investments in major development projects are not amortized until either proved reserves are associated with the projects or impairment has been determined.  At September 30, 2004, Barnwell had no investments in major oil and natural gas development projects that were not being amortized.  General and administrative costs related to oil and natural gas operations are expensed as incurred.  Estimated future site restoration and abandonment costs are capitalized as part of the carrying amount of oil and natural gas properties and depleted over the life of the related reserves.  Proceeds from the disposition of minor producing oil and natural gas properties are credited to the cost of oil and natural gas properties.  Gains or losses are recognized on the disposition of significant oil and natural gas properties.

 

24



 

Investment in land and revenue recognition

 

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

 

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

 

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

 

Contract drilling

 

Revenues, costs and profits applicable to contract drilling contracts are included in the consolidated statements of operations using the percentage of completion method, principally measured by the percentage of labor dollars incurred to date for each contract to total estimated labor dollars for each contract.  Contract losses are recognized in full in the period the losses are identified.  The performance of drilling contracts may extend over more than one year and, in the interim periods, estimates of total contract costs and profits are used to determine revenues and profits earned for reporting the results of contract drilling operations.  Revisions in the estimates required by subsequent performance and final contract settlements are included as adjustments to the results of operations in the period such revisions and settlements occur.  Contracts are normally less than one year in duration.

 

Income taxes

 

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

 

A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax asset will not be realized.  Barnwell has established a valuation allowance primarily for the U.S. tax effect of deferred Canadian taxes, foreign tax credits, accrued expenses and state of Hawaii net operating loss carryforwards which may not be realizable in future years as there can be no assurance of any specific level of earnings or that the timing of U.S. earnings will coincide with the payment of Canadian taxes to enable Canadian taxes to be fully deducted (or recoverable) for U.S. tax purposes.

 

25



 

Net deferred tax assets at September 30, 2004 of $3,093,000 consists of $1,165,000 related to the excess of the cost basis of investment in land for tax purposes over the cost basis of investment in land for book purposes and $1,812,000 related to the excess of liabilities accrued for book purposes over liabilities accrued for tax purposes.  The deferred tax assets are estimated to be realized through the deduction of the cost basis of investment in land and expenses for tax purposes against future proceeds from sales of interests in leasehold land and land development rights.  Additionally, at September 30, 2004, Barnwell had a deferred tax asset of $116,000 for alternative minimum tax credit carryforwards which are available to reduce future U.S. federal regular income taxes, if any, over an indefinite period.  The amount of deferred income tax assets considered realizable may be reduced if estimates of future taxable income are reduced.

 

Pension Plan

 

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

 

During and as of the end of fiscal 2004 and fiscal 2003, Barnwell assumed an expected long-term rate of return on plan assets of 8%.  The expected rate of future annual compensation increases utilized during and as of the end of fiscal 2004 and fiscal 2003 was 5%.

 

At the end of each year, Barnwell determines the discount rate to be used to calculate the present value of plan liabilities.  The discount rate is an estimate of the current interest rate at which the pension liabilities could be effectively settled at the end of the year.  In estimating this rate, Barnwell looks to rates of return on high-quality, fixed-income investments.  At September 30, 2004, Barnwell determined this rate to be 5.75%.

 

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

 

CONTRACTUAL OBLIGATIONS

 

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

 

26



 

 

 

 

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 will in fact extend the term of the facility on each renewal date or that the facility will be renewed at its current amount.  The following table lists the scheduled maturities of long-term debt assuming that the facility will not be renewed on the next renewal date and that Barnwell then elects to convert the revolving facility to term status, and scheduled minimum rental payments of non-cancelable operating leases for office space and leasehold land:

 

 

 

Payments Due by Fiscal Year

 

Contractual Obligations

 

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

 

OVERVIEW

 

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

 

Barnwell sells substantially all of its oil and condensate production under short-term contracts with marketers of oil.  The price of oil is freely negotiated between the buyers and sellers.  Natural gas sold by Barnwell is generally sold under both long-term and short-term contracts with prices indexed to market prices.  The price of natural gas and natural gas liquids is freely negotiated between buyers and sellers.  Market prices for petroleum products are dependent upon factors such as, but not limited to, changes in weather, storage levels, and output.  Petroleum and natural gas prices are very difficult to predict and fluctuate significantly.  For example, natural gas prices for Barnwell, based on quarterly averages during the three years ended September 30, 2004, have ranged from a low of $1.96 per thousand cubic feet to a high of $5.08 per thousand cubic feet, and tend to be higher in the winter season than in the summer due to increased demand.  Oil and natural gas costs generally follow trends in product market prices, thus in times of higher product prices the cost of exploration, development and operation of oil and natural gas properties will tend to escalate as well.  Barnwell’s oil and natural gas operations makes capital expenditures in the exploration, development, and production of oil and natural gas.  Cash outlays for capital expenditures are largely discretionary, however, a minimum level of capital

 

27



 

expenditures is required to replace depleting reserves.  Due to the nature of oil and natural gas exploration and development, uncertainty exists as to the ultimate success of any drilling effort.

 

Barnwell owns a 77.6% controlling interest in Kaupulehu Developments, a Hawaii general partnership which owns interests in leasehold land and development rights for property located approximately six miles north of the Kona International Airport in the North Kona District of the Island of Hawaii, adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka’upulehu, between the Queen Kaahumanu Highway and the Pacific Ocean.  Kaupulehu Developments’ development rights are under option to a developer and revenues are recognized when options are exercised.  The remaining options are comprised of seven payments of $2,656,250 due on each December 31 of years 2004 to 2010.  In February 2004, Kaupulehu Developments entered into a Purchase and Sale Agreement with WB KD Acquisition LLC (“WB”) by which Kaupulehu Developments transferred its leasehold interest in approximately 870 acres zoned for resort/residential development, in two increments, to WB.  For the first increment, Kaupulehu Developments received an $11,550,000 cash closing payment and is also entitled to receive future payments from the buyer based on the following percentages of gross receipts from the developer’s sales of single-family residential lots in the first increment: 9% of the gross proceeds from single-family lot sales up to aggregate gross proceeds of $100,000,000; 10% of such aggregate gross proceeds greater than $100,000,000 but less than $300,000,000; and 14% of such aggregate gross proceeds in excess of $300,000,000.  For the second increment, Kaupulehu Developments and WB agreed to 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 of the first single-family lot in Increment I, an agreement 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 residential real estate in recent years, however there is no assurance that any future percentage or development rights payments will be received.

 

Barnwell also drills wells and installs and repairs water pumping systems in Hawaii.  Contract drilling results in fiscal 2003 and for the first quarter of fiscal 2004 reflected the impact of a decrease in activity due to cyclical changes in the timing of jobs put out for bid by governmental and private entities.  During the remainder of fiscal 2004, however, activity increased as the number and value of contracts awarded has increased in recent months.  While progress on these contracts will continue through a portion of fiscal 2005, there is no assurance that this trend 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 increase was the result of an increase in land investment operating profit due to the sale of an interest in leasehold land, higher operating profit from the sale of development rights, and deferred income tax benefits of $1,740,000 resulting from a reduction in Canadian income tax rates.

 

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

 

28



 

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

 

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

 

Oil and Natural Gas Revenues

 

Selected Operating Statistics

 

The following tables set forth Barnwell’s annual net production and annual average price per unit of production for fiscal 2004 as compared to fiscal 2003, and fiscal 2003 as compared to fiscal 2002.  Production amounts 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

%

 

29



 

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

%

 


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

**MCF = 1,000 cubic 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 petroleum products.  Natural gas prices increased 8%, and natural gas production increased 7%.  The increase in natural gas production was due to both new production from the Bonanza, Foley Lake, South Pouce Coupe and Leduc areas and natural gas production from the Dunvegan property which increased approximately 7% as a result of an infill drilling program in fiscal 2004 and late fiscal 2003 which added 39 gross development wells (3.4 net wells).  The increase in natural gas production was partially offset by production declines at the Thornbury, Pouce Coupe, Progress, and Pollockville areas.  Oil prices increased 20%, and oil production increased 8% due to new production from the Wizard Lake and Bonanza areas, partially offset by a decrease in production from older oil properties.  Natural gas liquids prices increased 12%, and natural gas liquids production increased 24% due to the abovementioned infill drilling program at the Dunvegan area and due to the fact that fiscal 2003 natural gas liquids production was impacted by a fire in early October 2002 at a Dunvegan gas plant which prevented stripping of natural gas liquids from the natural gas; this resulted in an approximately 6,000 barrel lower liquids net production in fiscal 2003, as compared to fiscal 2004.

 

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

 

30



 

Oil and Natural 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 for repair, maintenance and cleaning, and inflationary pressures on oil field service costs.  Also contributing to the increase was a 10% increase in the average exchange rate of the Canadian dollar to 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 fiscal 2002.  The increase was partly attributable to an oil and natural gas operating expense credit recorded in the fourth quarter of fiscal 2002 for the settlement of overcharges of operating expenses for fiscal years 1998 through 2001 from the operator of the Dunvegan property that reduced fiscal 2002 operating expenses by approximately $470,000.  Also contributing to the increase were increases in well repair and maintenance, electricity, fuel, insurance, and general maintenance costs.

 

Sale of Interest in Leasehold Land, Sale of Development Rights, and Minority Interest in Earnings

 

On February 13, 2004, Kaupulehu Developments, a land development general partnership in which Barnwell owns a 77.6% controlling interest, entered into a Purchase and Sale Agreement with WB by which Kaupulehu Developments transferred its leasehold interest in approximately 870 acres zoned for resort/residential development, in two increments, to WB.  There is no affiliation between Kaupulehu Developments and WB.  Increment I is an area planned for approximately 80 single-family lots and a beach club on the portion of the property bordering the Pacific Ocean.  The purchasers of the 80 single-family lots will have the right to apply for membership in the Kuki’o Resort Golf and Beach Club, which is located adjacent to and south of the Four Seasons Resort Hualalai at Historic Ka’upulehu.  Increment II is the remaining portion of the approximately 870-acre property and is zoned for single-family and multi-family residential units and a golf course and clubhouse.

 

With respect to Increment I, Kaupulehu Developments received a non-refundable $11,550,000 payment (“Closing Payment”) and is entitled to receive payment of the following percentages of the gross proceeds generated from the sale by WB of single-family lots in Increment I (“Percentage Payments”): 9% of the gross proceeds from single-family lot sales up to aggregate gross proceeds of $100,000,000; 10% of such aggregate gross proceeds greater than $100,000,000 but less than $300,000,000; and 14% of such aggregate gross proceeds in excess of $300,000,000.  If prior to December 31, 2005, Kaupulehu Developments has not received Percentage Payments equal to or greater than $2,500,000 in the aggregate, WB will pay Kaupulehu Developments the amount by which the aggregate amount of all prior 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 (including payments in lieu of Percentage Payments as described in the immediately preceding sentence) equal to or greater than $5,000,000 in the aggregate, then WB will pay Kaupulehu Developments the amount by which the aggregate amount of all such payments is less than $5,000,000.  Additionally, WB agreed to pay Kaupulehu Developments non-refundable interim payments of $50,000 per month (“Interim Payments”), until the first to occur of the closing of the sale of the 40th single-family lot sold in Increment I or WB’s payment to Kaupulehu Developments of a total of $900,000 in Interim 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 Interim Payments or any Percentage Payments will be received.

 

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Kaupulehu Developments, WB and The Trustees of The Estate of Bernice Pauahi Bishop (“KS”) also entered into an agreement (the “Step-In Rights Agreement”) whereby if WB elects not to proceed with development of Increment 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 development rights and develop the property without any payment to WB.

 

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

 

For Increment II, Kaupulehu Developments and WB agreed to 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 of the first single-family lot in Increment I, an agreement with regards to the ownership and development of Increment II.  WB, however, may terminate such negotiations at any time without any further obligation.  Under the terms of the Step-In Rights Agreement, if at the end of three years following the closing of the sale of the first single-family lot in Increment I the parties have not entered into a definitive agreement with respect to Increment II, the leasehold rights with respect to Increment II will revert 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 the cost and the estimated future costs related to the leasehold interest sold.  The revenue from the $11,550,000 Closing Payment plus $350,000 of post-closing Interim Payments received in March through 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 of previously capitalized costs relating to Increment I.  The $7,330,000 of net revenue from the Closing Payment and Interim Payments for the year ended September 30, 2004 is recorded in the Consolidated Statements of Operations as “Sale of interest in leasehold land, net.”  Operating profit on 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 leasehold land in the years ended September 30, 2003 or 2002.  As no sales price or agreement with regards to the ownership and development of Increment II has yet been determined, no revenues or cost of sales have been recognized on Increment II.

 

The development rights held by Kaupulehu Developments are for residentially zoned leasehold land within and adjacent to the Hualalai Golf Club and are under option to Kaupulehu Makai Venture, an unrelated entity that is an affiliate of Kajima Corporation of Japan.  Net revenues from the sale of development rights 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 Venture exercised the portion of its development rights option expiring on that date and sent Kaupulehu Developments the required $2,656,000 option payment, which was received by Kaupulehu Developments in January 2004.  Revenue from the option exercise was reduced by $159,000 of fees related to the sale, resulting in net revenues of $2,497,000 and a $1,950,000 operating profit, after minority interest, on the transaction.  There were no other costs deducted from revenues from the sale of development rights in the year ended September 30, 2004 as all capitalized costs associated with the

 

32



 

development rights were expensed 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 to the development rights, resulting in net revenues of $720,000 and a $280,000 operating profit, after minority interest, on the transaction.  On December 31, 2001, Kaupulehu Makai Venture exercised the portion of its development rights option due on that date and paid Kaupulehu Developments $2,125,000.  Under the cost recovery method, $1,877,000 of investment in land was expensed as a result of this option exercise, reducing operating profit, after minority interest, to zero in fiscal 2002.

 

The total amount of remaining future development right option receipts 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 31 of years 2004 to 2010.  If any annual option payment is not made, the then remaining development right options will expire.  There is no assurance that any portion of the remaining options will be exercised.

 

The aforementioned $159,000 in fees ($112,000, net of minority 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 of interest in leasehold land for the year ended September 30, 2004 were paid to Nearco, Inc., a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 21.8% owner of Kaupulehu Developments.  Under an agreement entered into in 1987, prior to Mr. Johnston’s election to Barnwell’s Board of Directors, Barnwell is obligated to pay Nearco 2% of Kaupulehu Developments’ gross receipts from the sale of real estate interests, and Cambridge Hawaii Limited Partnership, a 49.9% partner of Kaupulehu Developments in which Barnwell purchased a 55.2% interest in April 2001, is obligated under an agreement entered into in 1987 to pay Nearco 4% of Kaupulehu Developments’ gross receipts from the sale of real estate interests.  Fees of $128,000 ($89,000, net of minority interest) on the proceeds from sales of development rights were paid in each of the years ended September 30, 2003 and 2002.  The fees represent compensation for promotion and marketing of Kaupulehu Developments’ property and were determined based on the estimated fair value of such services.  Barnwell believes the fees are fair and reasonable compensation for such services.

 

Fees were also paid to Nearco for consulting services related to Kaupulehu Developments’ leasehold land.  In fiscal 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 administrative expenses.  In addition, $52,000 of fees were paid to Nearco in fiscal 2004 for services related to the closing of the February 2004 sale of an interest in leasehold land.   These fees were a direct cost of the sale and accordingly reduced the revenues recognized from the sale under the cost recovery method.  Barnwell believes the fees are fair and reasonable compensation for such services.

 

Contract Drilling

 

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

 

Contract drilling revenues increased $1,640,000 (80%) to $3,690,000 in fiscal 2004, as compared to $2,050,000 in fiscal 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 fiscal 2003.  Operating profit before depreciation increased $384,000 (315%) from $122,000 in fiscal 2003 to $506,000 in fiscal 2004.  The increases were due to an increase in water well drilling activity as there were four drilling rigs operating

 

33



 

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 not seasonal in nature but can fluctuate significantly based on the awarding and timing 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 and repair contracts, five and two of which were in progress as of September 30, 2004.  The backlog of contract drilling revenues 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 in fiscal 2002, and contract drilling operating expenses decreased $893,000 (32%) to $1,928,000 in fiscal 2003, as compared to $2,821,000 in fiscal 2002.  Operating profit before depreciation decreased $537,000 (81%) from $659,000 in fiscal 2002 to $122,000 in fiscal 2003.  The decreases were due to a decreased number of available water well drilling and pump installation contracts and lower contract margins resulting from higher competition for those contracts.

 

Gas Processing and Other Income

 

Gas processing and other income decreased $377,000 (24%) to $1,183,000 in fiscal 2004, as compared to $1,560,000 in fiscal 2003.  In fiscal 2004, Kaupulehu Developments received $250,000 in income related to negotiations on the development of Kaupulehu Developments’ resort/residential acreage, as compared to $500,000 in fiscal 2003, a decrease of $250,000; these revenues discontinued with the consummation of Kaupulehu Developments’ sale of an interest in leasehold land in February 2004.  In addition, interest income decreased in fiscal 2004, as compared to fiscal 2003, as fiscal 2003 interest income included $102,000 of interest on an income tax refund from the Canadian government relating to Barnwell’s fiscal 1994 tax return (there was no such income in fiscal 2004), and as a note receivable that was outstanding during all of fiscal 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 in fiscal 2004 from a $139,000 gain from the sale of an approximately two and one-quarter acre parcel of fee simple vacant land located in the Hilo district of the Island of Hawaii for $440,000, net of costs related to the sale, in March 2004; the property was formerly used as a storage and maintenance yard by Barnwell’s contract drilling segment.  The remainder of the decrease was primarily due to a $30,000 decrease in gas processing fees due to a decrease in the processing of third-party gas, as compared to the prior year.

 

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

 

General and Administrative Expenses

 

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

 

34



 

$765,000 as compared to the prior year, $733,000 of bonuses issued in conjunction with the consummation of Kaupulehu 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 expenses include fees paid to Nearco, Inc., an entity controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 21.8% owner of Kaupulehu Developments, for consulting services related to Kaupulehu Developments’ leasehold land.  In fiscal 2004 and fiscal 2003, fees paid to Nearco, Inc. totaled $273,000 and $218,000, respectively.  As previously stated, Barnwell believes the fees are fair and reasonable compensation for such services.

 

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

 

Depletion, Depreciation and Amortization

 

Depletion, depreciation and amortization increased $2,428,000 (56%) to $6,761,000 in fiscal 2004, as compared to $4,333,000 in fiscal 2003, due to a 33% increase in the depletion rate, a 9% increase in production (in MCF equivalents where one barrel 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 Canadian dollar to the U.S. dollar.

 

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

 

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

 

35



 

Interest Expense

 

Interest expense 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 fiscal 2004, as compared to $45,000 of capitalized interest in fiscal 2003.

 

Interest costs for the years 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

 

 

The average interest rate incurred during fiscal 2004 on Barnwell’s borrowings from the Royal Bank of Canada decreased to 3.67%, as compared to 3.84% in fiscal 2003, and the weighted average balance of outstanding borrowings from the Royal Bank of Canada increased from approximately $10,100,000 in fiscal 2003 to approximately $10,305,000 in fiscal 2004, due to an increase in the exchange rate of Canadian dollar to the U.S. dollar.

 

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

 

Foreign Currency Fluctuations

 

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

 

The fiscal year average exchange rate of the Canadian dollar to the U.S. dollar increased 10% in fiscal 2004, as compared to fiscal 2003, and the exchange rate of the Canadian dollar to the U.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’s subsidiaries operating in Canada have increased.  Barnwell’s Canadian dollar assets are greater than its Canadian dollar liabilities; therefore, increases in value of the Canadian dollar to the U.S. dollar generate other comprehensive income.  The fiscal year average exchange rate of the Canadian dollar to the U.S. dollar increased 8% in fiscal 2003, as compared to fiscal 2002, and the exchange rate of the Canadian dollar to the U.S. dollar increased 17% at September 30, 2003, as compared to September 30, 2002.  Other comprehensive income due to foreign currency translation adjustments for fiscal 2004 was $1,660,000, a $732,000 decrease from other comprehensive income of $2,392,000 in fiscal 2003.

 

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

 

36



 

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

 

Income Taxes

 

In November 2003, Royal Assent was received on a bill passed by the Parliament of Canada, which was then enacted into law, to reduce Canada’s corporate tax rate on “resource” income (income derived from oil and natural gas operations) over a four-year period beginning January 1, 2003 from 29% to 21% with the 21% tax rate commencing on January 1, 2007.  Additionally, the bill phases in over the same four-year period tax deductions for royalties, which previously were not tax deductible, and phases out the Resource Allowance deduction along with other changes.  Accordingly, during fiscal 2004, Barnwell’s Canadian deferred income tax liabilities were reduced by approximately $1,440,000 due to the reduction in Canada’s corporate tax rate.  There was no benefit attributable to changes in Canada’s Federal corporate tax rate on “resource” income in fiscal 2003 or fiscal 2002.

 

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

 

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

 

Included in the provisions for deferred income 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 development rights in December 2002 and 2001, respectively.  The sales of land development rights in fiscal 2003 and 2002 created temporary differences due to the excess of expenses recognized under the cost recovery method for books over expenses deductible for tax purposes.

 

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

 

Environmental Matters

 

Federal, state, and Canadian governmental agencies issue rules and regulations and enforce laws to protect the environment which are often difficult and costly to comply with and which carry substantial penalties for failure to comply, particularly in regard to the discharge of materials into the environment.  The regulatory burden on the oil and gas industry increases its cost of doing business.

 

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

 

Inflation

 

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

 

Recent Accounting Pronouncements

 

In 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,” establishing additional annual disclosures about plan assets, investment strategy, measurement date, plan obligations and cash flows.  In addition, the revised standard established interim disclosure requirements related to the net periodic benefit cost recognized and contributions paid or expected to be paid during the current fiscal year.  The new annual disclosures are effective for financial statements with fiscal years ending after December 15, 2003 and the interim-period disclosures are effective for interim periods beginning 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 to SFAS No. 132 had no impact on Barnwell’s financial condition, results of operations or liquidity.

 

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

 

LIQUIDITY AND CAPITAL RESOURCES

 

Cash Flows, Debt and Available Credit

 

Cash flows provided by operations totaled $6,148,000 for fiscal 2004, a decrease of $2,367,000 as compared to $8,515,000 of cash flows provided by operations for the same period in the prior year.  The decrease was primarily due to an increase in income tax payments in the current period as compared to the same period in the prior year.  Income taxes of $4,495,000 were paid in fiscal 2004, including $430,000 for taxes due for fiscal 2003, as compared to $2,961,000 in fiscal 2003, an increase of $1,534,000.  Income tax payments also include $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 reported under cash flows provided by investing activities.  Cash flow from operations also decreased due to $733,000 of bonuses issued in conjunction with the consummation of Kaupulehu Developments’ sale of an interest in leasehold land in February 2004.  Partially offsetting these decreases in cash flows provided by operations was an increase in pre-tax operational cash flows generated by the oil and natural gas segment.

 

Cash flows provided by investing activities totaled $1,557,000 for fiscal 2004, an increase of $9,306,000 from cash used in investing activities of $7,749,000 in fiscal 2003.  The increase is due primarily 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 Kaupulehu Developments’ 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 the same period in the prior year.  Barnwell also fully collected a $1,311,000 note receivable, and received $440,000 of proceeds, net of associated costs, from the sale of land that was previously utilized as a contract drilling storage yard.  Partially offsetting the increase was a $2,293,000 increase in capital expenditures, primarily oil and natural gas capital expenditures, as compared to the prior year period, and $1,387,000 of investments in six-month and one-year certificates of deposit at various financial institutions, net of proceeds from matured certificates of deposit, in fiscal 2004; there were no such investments in the same period of the prior year.

 

During fiscal 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 bank and the remainder was paid in cash.  The note was payable in monthly principal payments of approximately $3,000, plus interest, and was due in full in December 2006.  Barnwell repaid the note in full in fiscal 2004.  The space purchased has 4,662 useable square feet in an office building in downtown Honolulu.

 

During fiscal 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 minority interests resulting from Kaupulehu Developments’ sales of leasehold land interest and development rights, a $2,358,000 increase in minority distributions from $275,000 during the same period of the prior year.  Barnwell also made $1,408,000 of long-term debt repayments, a $1,048,000 increase from debt repayments of $360,000 in the same period of the prior year; of the $1,408,000 in current period debt net repayments, $883,000 was for the full repayment of the note payable to a Hawaii bank and $525,000 was paid toward the credit facility with the Royal Bank of Canada.  Barnwell also paid $1,123,000 in dividends (no dividends were paid in the prior year period), and collected $218,000 in proceeds from employees’ exercise of stock options (no stock options were exercised in the prior year period).

 

Dividends paid 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

 

 

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The Royal Bank of Canada has renewed Barnwell’s credit facility through April 2005 at 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. dollar denominated borrowings from the London Interbank Offer Rate plus 1-3/4% to the London Interbank Offer Rate plus 2%.

 

At September 30, 2004, Barnwell had $4,497,000 in cash and cash equivalents, $1,387,000 in certificates of deposit with maturity dates ranging from October 2004 to April 2005, $1,331,000 in working capital, and approximately $4,800,000 of available credit under its credit facility with the Royal Bank of Canada.  Barnwell believes its current cash balances, certificates of deposit, future cash flows from operations, land segment sales, and available credit will be sufficient to fund its estimated capital expenditures for at least the next twelve months and meet the repayment schedule on its long-term debt.  However, if oil and natural gas production remains at or declines from current levels or oil and natural gas prices decline from current levels, current working capital balances and cash flows generated by operations may not be sufficient to fund Barnwell’s current projected level of oil and natural gas capital expenditures, in which case Barnwell may fund capital expenditures with funds generated by land segment sales, long-term debt borrowings, or it may reduce future oil and natural gas capital expenditures.  Additionally, if Barnwell’s credit facility with a Canadian bank is reduced below the current level of borrowings under the facility after the April 2005 review, Barnwell may be required to reduce expenditures or seek alternative sources of financing to make any required payments under the facility.

 

Oil and Natural Gas Capital Expenditures

 

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

 

40



 

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

 

 

 

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 capital expenditures for fiscal 2005 will range from $12,500,000 to $14,000,000.  This estimated amount may increase or decrease as dictated by management’s assessment of the oil and gas environment and prospects.

 

41



 

Item 7. FINANCIAL STATEMENTS

 

 

Report of Independent Registered Public Accounting Firm

 

 

The Board of Directors

Barnwell Industries, Inc.:

 

We have audited the accompanying consolidated balance sheets of Barnwell Industries, Inc. and subsidiaries as of September 30, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended September 30, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

 

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

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Barnwell Industries, Inc. and subsidiaries as of September 30, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended September 30, 2004, in conformity with U.S. generally accepted accounting principles.

 

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

 

 

/s/KPMG LLP

 

 

Honolulu, Hawaii

December 6, 2004

 

42



 

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

 

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 to Consolidated Financial Statements

 

43



 

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF 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 Consolidated Financial Statements

 

44



 

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS 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



 

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

 

 

 

 

46

 

(Continued on next page)

 



 

BARNWELL INDUSTRIES, INC. AND SUBSIDARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS)

Years ended September 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

 

 

47

 

(Continued on next page)

 



 

BARNWELL INDUSTRIES, INC. AND SUBSIDARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS)

Years ended September 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

 

48



 

BARNWELL INDUSTRIES, INC.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002

 

1.             DESCRIPTION OF THE REPORTING ENTITY AND BUSINESS

 

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

 

During its last three fiscal years, Barnwell was engaged in exploring for, developing, producing and selling oil and natural gas in Canada, investing in leasehold land in Hawaii, and drilling wells and installing and repairing water pumping systems in Hawaii.  Barnwell’s oil and natural gas activities comprise its largest business segment.  Approximately 61% of Barnwell’s revenues and 90% of Barnwell’s capital expenditures 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” revenues in the Consolidated Statements of Operations, accounted for 27% of fiscal 2004 revenues; Barnwell’s contract drilling activities accounted for 10% of fiscal 2004 revenues; and other revenues comprised 2% of fiscal 2004 revenues.

 

2.             SIGNIFICANT ACCOUNTING POLICIES

 

Cash and Cash Equivalents and Certificates of Deposit

 

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

 

Trade Accounts Receivable

 

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

 

Oil and Natural Gas Properties

 

Barnwell uses the full cost method of accounting under which all costs incurred in the acquisition, exploration and development of oil and natural gas reserves, including unsuccessful wells,

 

49



 

are capitalized until such time as the aggregate of such costs, on a country-by-country basis, equals the discounted present value (at 10%) of Barnwell’s estimated future net cash flows from estimated production of proved oil and natural gas reserves, as determined by independent petroleum engineers, less related income tax effects.  Any capitalized costs, net of oil and gas related deferred income taxes, in excess of the discounted present value of proved properties and the lower of cost or estimated fair value of unproved properties are charged to expense.  Depletion of all such costs, except costs related to major development projects, is provided by the unit-of-production method based upon proved oil and natural gas reserves of all properties on a country-by-country basis.  Investments in major development projects are not amortized until either proved reserves are associated with the projects or impairment has been determined.  At September 30, 2004, Barnwell had no investments in major oil and natural gas development projects that were not being amortized.  General and administrative costs related to oil and natural gas operations are expensed as incurred.  Estimated future site restoration and abandonment costs are capitalized as part of the carrying amount of oil and natural gas properties and depleted over the life of the related reserves.  Proceeds from the disposition of minor producing oil and natural gas properties are credited to the cost of oil and natural gas properties.  Gains or losses are recognized on the disposition of significant oil and natural gas properties.

 

Investment in Land and Revenue Recognition

 

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

 

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

 

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

 

Contract Drilling

 

Revenues, costs and profits applicable to contract drilling contracts are included in the consolidated statements of operations using the percentage of completion method, principally measured by the percentage of labor dollars incurred to date for each contract to total estimated labor dollars for each contract.  Contract losses are recognized in full in the period the losses are identified.  The performance of drilling contracts may extend over more than one year and, in the interim periods, estimates of total contract costs and profits are used to determine revenues and profits earned for reporting the results of contract drilling operations.  Revisions in the estimates required by subsequent performance and final contract settlements are included as adjustments to the results of operations in the period such revisions and settlements occur.  Contracts are normally less than one year in duration.

 

50



 

Long-lived Assets

 

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

 

Drilling Rigs, Other Property and Equipment

 

Drilling rigs and other property and equipment are stated at cost.  Depreciation is computed using the straight-line method based on estimated useful lives.

 

Inventories

 

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

 

Environmental

 

Barnwell is subject to extensive environmental laws and regulations.  These laws, which are constantly changing, regulate the discharge of materials into the environment and maintenance of surface conditions and may require Barnwell to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.  Environmental expenditures are expensed or capitalized depending on their future economic benefit.  Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed.  Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

 

Asset Retirement Obligation

 

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

 

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

 

51



 

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

 

Income Taxes

 

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

 

Earnings Per Common Share

 

Basic earnings per share excludes dilution and is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period.  Diluted earnings per share includes the potentially dilutive effect of outstanding common stock options and securities which are convertible to common shares.

 

Reconciliations between the numerator and denominator of the basic and diluted earnings per share computations for the years ended September 30, 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

 

 

52



 

Assumed conversion of convertible debentures to 6,750 shares of common stock was excluded from the computation of diluted earnings per share for the period that the debentures were outstanding during the year ended September 30, 2003 because the effect would have been antidilutive (the convertible debentures were repaid in full on June 30, 2003).  Assumed conversion of convertible debentures to acquire 18,000 shares of common stock at September 30, 2002 was excluded from the computation of diluted earnings per share for the year ended September 30, 2002 because the effect would have been antidilutive.

 

Stock-Based Compensation

 

Barnwell applies the provisions of Accounting Principles Board Opinion No. 25 in accounting for stock-based compensation and adopted the disclosure-only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.”  Had compensation cost for stock options granted since October 1, 1995 been determined based on the fair value method of measuring stock-based compensation provisions of SFAS No. 123, Barnwell’s net earnings (loss) and basic and diluted earnings (loss) per share would have been as 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 of the options was based on a option-pricing model which included assumptions of a weighted average expected life of 5.97 years, expected volatility of 30%, weighted average risk-free interest rate of 6.12%, and an expected dividend yield of 0%.

 

Foreign Currency Translation

 

Assets and liabilities of foreign operations and subsidiaries are translated at the year-end exchange rate and resulting translation gains or losses are accounted for in a stockholders’ equity account entitled “accumulated other comprehensive income (loss) - foreign currency translation adjustments.”  Operating results of foreign subsidiaries are translated at average exchange rates during the period. Realized foreign currency transaction gains or losses were not material in fiscal years 2004, 2003, and 2002.

 

53



 

Use of Estimates in the Preparation of Financial Statements

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities.  Actual results could differ significantly from those estimates.  Significant assumptions are required in the valuation of deferred tax assets and proved oil and natural gas reserves, and such assumptions may impact the amount at which deferred tax assets and oil and natural gas properties are recorded.

 

Reclassification

 

Certain reclassifications have been made to the September 30, 2003 consolidated balance sheet to conform to classifications used in the September 30, 2004  consolidated balance sheet.

 

3.             ACCOUNTS RECEIVABLE AND CONTRACT COSTS

 

Accounts receivable are net of allowances for doubtful accounts of $10,000 as of September 30, 2004 and 2003.  Included in accounts receivable are contract retainage balances of $242,000 and $96,000 as of September 30, 2004 and 2003, respectively.  These balances are expected to be collected within one year, generally within 45 days after the related contracts have received final acceptance and approval.

 

Costs and estimated earnings on uncompleted contracts are as follows:

 

 

 

September 30,

 

 

 

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 contracts are 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

 

 

54



 

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 partnership that owns interests in leasehold land and development rights for property located approximately six miles north of the Kona International Airport in the North Kona District of the Island of Hawaii.  Between 1986 and 1989, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of the Four Seasons Resort Hualalai at Historic Ka’upulehu and Hualalai Golf Club, which opened in 1996, a second golf course, and single and multiple family residential units.  These projects were developed on leasehold land acquired from Kaupulehu Developments by Kaupulehu Makai Venture, an unrelated entity that is an affiliate of Kajima Corporation of Japan.

 

Rezoning and Partial Sale of Interest in Leasehold Land

 

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

 

On February 13, 2004, Kaupulehu Developments entered into a Purchase and Sale Agreement with WB KD Acquisition LLC (“WB”) by which Kaupulehu Developments transferred its leasehold interest in the approximately 870 acres zoned for resort/residential development, in two increments, to WB.  There is no affiliation between Kaupulehu Developments and WB.  WB is an affiliate of Westbrook Partners LLC, an affiliate of the developers of the Kuki’o Resort.  The first increment (“Increment I”) is an area planned for approximately 80 single-family lots and a beach club on the portion of the property bordering the Pacific Ocean.  The purchasers of the 80 single-family lots will have the right to apply for membership in the Kuki’o Resort Golf and Beach Club, which is located adjacent to and south of the Four Seasons Resort Hualalai at Historic Ka’upulehu.  The second increment (“Increment II”) is the remaining portion of the approximately 870-acre property and is zoned for single-family and multi-family residential units and a golf course and clubhouse.

 

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

 

55



 

than $2,500,000.  If prior to December 31, 2006, Kaupulehu Developments has not received Percentage Payments (including payments in lieu of Percentage Payments as described in the immediately preceding sentence) equal to or greater than $5,000,000 in the aggregate, then WB will pay Kaupulehu Developments the amount by which the aggregate amount of all such payments is less than $5,000,000.  Additionally, WB agreed to pay Kaupulehu Developments non-refundable interim payments of $50,000 per month (“Interim Payments”), until the first to occur of the closing of the sale of the 40th single-family lot sold in Increment I or WB’s payment to Kaupulehu Developments of a total of $900,000 in Interim 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 Interim Payments or any Percentage Payments will be received.

 

Kaupulehu Developments, WB and The Trustees of The Estate of Bernice Pauahi Bishop (“KS”) also entered into an agreement (the “Step-In Rights Agreement”) whereby if WB elects not to proceed with development of Increment 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 development rights and develop the property without any payment to WB.

 

In March 2004, WB commenced engineering of infrastructure, preparation of covenants, conditions and restrictions for a community association, and preparation of legal documents to enable real estate sales, and broke ground and graded several miles of access roads.  In late September 2004, WB began mass grading of the first phase of 38 lots for development.

 

For Increment II, Kaupulehu Developments and WB agreed to 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 of the first single-family lot in Increment I, an agreement with regards to the ownership and development of Increment II.  WB, however, may terminate such negotiations at any time without any further obligation. Under the terms of the Step-In Rights Agreement, if at the end of three years following the closing of the sale of the first single-family lot in Increment I the parties have not entered into a definitive agreement with respect to Increment II, the leasehold rights with respect to Increment II will revert 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 the cost and the estimated future costs related to the leasehold interest sold.  The revenue from the $11,550,000 Closing Payment plus $350,000 of post-closing Interim Payments received in March through 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 of previously capitalized costs relating to Increment I.  The $7,330,000 of net revenue from the Closing Payment and Interim Payments for the year ended September 30, 2004 is recorded in the Consolidated Statements of Operations as “Sale of interest in leasehold land, net.”  Operating profit on 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 leasehold land in the years ended September 30, 2003 and 2002.  As no sales price or agreement with regards to the ownership and development of Increment II has yet been determined, no revenues or cost of sales have been recognized on Increment II.

 

56



 

Development Rights Under Option

 

The development rights held by Kaupulehu Developments are for residentially zoned leasehold land within and adjacent to the Hualalai Golf Club and are under option to Kaupulehu Makai Venture, an unrelated entity that is an affiliate of Kajima Corporation of Japan.  On December 31, 2001, 2002 and 2003, Kaupulehu Makai Venture exercised the portion of its development 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 100 acres remain under option.  Barnwell accounts for sales of development rights under option by use of the cost recovery method.  Under the cost recovery method, no operating profit is recognized until cash received exceeds the cost and the estimated future costs related to development rights sold.  In fiscal 2002, approximately $1,877,000 of the proceeds from the sales of development rights were applied to reduce the carrying value of the underlying investment in land.  Sales of development rights were further reduced in fiscal 2002 by $128,000 of fees related to the sale, and the remaining $120,000 of sales proceeds is recorded in the Consolidated Statements of Operations for fiscal 2002 as “Sale of development rights, net.”   In fiscal 2003, $1,277,000 of the proceeds from the sales of development rights were applied to reduce the carrying value of the underlying development rights recorded on the Condensed Consolidated Balance Sheets under the caption “Investment in land” to zero.  Sales of development rights were further reduced in fiscal 2003 by $128,000 of fees related to the sale and the remaining $720,000 of sales proceeds is recorded in the Consolidated Statements of Operations for fiscal 2003 as “Sale of development rights, net.”  In fiscal 2004, $2,656,000 of revenues attributable to the development rights sale  were reduced by $159,000 of fees related to the sale, resulting in net revenues of $2,497,000 and a $1,950,000 operating profit, after minority interest, on the transaction.  There were no other costs deducted from revenues from the sale of development rights in fiscal 2004 as all capitalized costs associated with the development rights were expensed in previous years under the cost recovery method.

 

The total amount of remaining future option receipts 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 31 of years 2004 to 2010.  If any annual option payment is not made, the then remaining development right options will expire.  There is no assurance that any portion of the remaining options will be exercised.

 

Fees

 

The aforementioned $159,000 in fees ($112,000, net of minority 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 of interest in leasehold land for the year ended September 30, 2004 were paid to Nearco, Inc., a company controlled by Mr. Terry Johnston, a director of Barnwell and an indirect 21.8% owner of Kaupulehu Developments.  Under an agreement entered into in 1987, prior to Mr. Johnston’s election to Barnwell’s Board of Directors, Barnwell is obligated to pay Nearco 2% of Kaupulehu Developments’ gross receipts from the sale of real estate interests, and Cambridge Hawaii Limited Partnership, a 49.9% partner of Kaupulehu Developments in which Barnwell purchased a 55.2% interest in April 2001, is obligated under an agreement entered into in 1987 to pay Nearco 4% of Kaupulehu Developments’ gross receipts from the sale of real estate interests.  Fees of $128,000 ($89,000, net of minority interest) on the proceeds from sales of development rights were paid in each of the years ended September 30, 2003 and 2002.  The fees represent compensation for promotion and marketing of Kaupulehu Developments’ property and were determined based on the estimated fair value of such services.  Barnwell believes the fees are fair and reasonable compensation for such services.

 

Fees were also paid to Nearco for consulting services related to Kaupulehu Developments’

 

57



 

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 administrative expenses.  In addition, $52,000 of fees were paid to Nearco in fiscal 2004 for services related to the closing of the February 2004 sale of an interest in leasehold land.   These fees were a direct cost of the sale and accordingly reduced the revenues recognized from the sale under the cost recovery method.  Barnwell believes the fees are fair and reasonable compensation for such services.

 

Interests at September 30, 2004

 

The interests held by Kaupulehu Developments at September 30, 2004 include the development rights under option; the rights to receive Increment I percentage and interim payments; the leasehold land zoned for resort/residential development within Increment II, which is under a right of negotiation with WB; and approximately 1,000 acres of vacant leasehold land zoned conservation.  These interests relate to land located adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka’upulehu, between the Queen Kaahumanu Highway and the Pacific Ocean.  Barnwell’s cost of Kaupulehu Developments’ interests is included in the September 30, 2004 and 2003 consolidated balance sheets under the caption “Investment in Land” and consisted 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

 

 

58



 

6.             PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION

 

Barnwell’s property and equipment is detailed as follows:

 

 

 

Estimated
Useful
Lives

 

Gross
Property and
Equipment

 

Accumulated
Depreciation,
Depletion and
Amortization

 

Net
Property and
Equipment

 

At September 30, 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 of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made.  Adoption of SFAS No. 143 increased gross oil and natural gas properties by $564,000, decreased accumulated depletion by $546,000, and increased the asset retirement obligation by $1,110,000 on October 1, 2002.

 

Following the initial implementation of SFAS No. 143, the asset retirement obligation was increased during the year ended September 30, 2003 by $39,000 to reflect obligations incurred on new wells drilled, by $85,000 for accretion of the asset retirement obligation, and by $198,000 for changes in foreign currency translation rates.  During the year ended September 30, 2004, the asset retirement obligation was increased by $133,000 to reflect obligations incurred on new wells drilled and changes in the timing and amount of estimated future expenditures, by $100,000 for accretion of the asset retirement obligation, and by $110,000 for changes in foreign currency translation rates.

 

In December 2003, Barnwell purchased the space it was leasing for its corporate offices in Honolulu, Hawaii for $1,057,000, of which $883,000 was financed by a note payable to a Hawaii bank and the remainder was paid in cash.  The note was payable in monthly principal payments of approximately $3,000, plus interest, and was due in full in December 2006.  Barnwell repaid the note in full in fiscal 2004.  The space purchased has 4,662 useable square feet in an office building in downtown Honolulu, Hawaii.

 

59



 

7.             LONG-TERM DEBT

 

Barnwell has a credit facility 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 at September 30, 2004 and 2003, respectively, and are included in long-term debt.  At September 30, 2004, Barnwell had unused credit available under this facility of approximately $4,800,000.

 

The facility is available in U.S. dollars at the London Interbank Offer Rate plus 2%, at U.S. prime plus 1%, or in Canadian dollars at Canadian prime plus 1%.  A standby fee of 1% per annum is charged on the unused facility balance.  Under the financing agreement, the facility is reviewed annually, with the next review planned for April 2005.  Subject to that review, the facility may be extended one year with no required debt repayments for one year or converted to a 2-year term loan by the bank.  If the facility is converted to a 2-year term loan, Barnwell has agreed to the following repayment schedule of the then outstanding loan balance:  first year of the term period – 20% (5% per quarter), and in the second year of the term period  – 80% (5% per quarter for the first three quarters and 65% in the final quarter).

 

Barnwell has the option to change the currency denomination and interest rate applicable to the loan at periodic intervals during the term of the loan.  During the year ended September 30, 2004, Barnwell paid interest at rates ranging from 2.69% to 5.50%.  The weighted average interest rate on the facility at September 30, 2004 was 3.65%.  The facility is collateralized by Barnwell’s interests in its major oil and natural gas properties and a negative pledge on its remaining oil and natural gas properties.  The facility is reviewed annually with a primary focus on the future cash flows that will be generated by Barnwell’s Canadian oil and natural gas properties.  No compensating bank balances are required for this facility.

 

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

 

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

 

Interest costs for the years ended September 30, 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

 

 

60



8.             TAXES ON INCOME

 

The components of earnings 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 the provision (benefit) for income taxes related to the above earnings (loss) are as 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 Canadian deferred tax benefit of $915,000 for fiscal 2004 was due to reductions in Canadian Federal and Provincial tax rates, partially offset by Barnwell’s $825,000 Canadian deferred tax provision resulting from changes in differences between Canadian assets and liabilities for book purposes versus Canadian assets and liabilities for Canadian tax purposes.  In November 2003, Royal Assent was received on a bill passed by the Parliament of Canada, which was then enacted into law, to reduce Canada’s corporate tax rate on “resource” income (income derived from oil and natural gas operations) over a four-year period beginning January 1, 2003 from 29% to 21% with the 21% tax rate commencing on January 1, 2007.  Additionally, the bill phases in over the same four-year period tax deductions for royalties, which previously were not tax deductible, and phases out the Resource Allowance deduction along with other changes.  Accordingly, during fiscal 2004, Barnwell’s Canadian deferred income tax liabilities were reduced by approximately $1,440,000 due to the reduction in Canada’s Federal corporate tax rate.  There was no benefit attributable to changes in Canada’s corporate tax rate on “resource” income in fiscal 2003 or fiscal 2002.

 

Barnwell’s Canadian deferred income tax liabilities were also reduced by approximately $300,000 in fiscal 2004 as a result of the Province of Alberta’s reduction of the province’s corporate tax rate from 13.0% to 12.5%, effective April 1, 2003 (enacted into law in December 2003), and from 12.5% to 11.5%, effective April 1, 2004 (enacted into law in May 2004).  In April 2002, the legislative assembly of the Province of Alberta passed a bill to reduce the province’s corporate tax rate from 13.5% to 13.0%, effective April 1, 2002.  The bill was enacted into law in December 2002.  The reduction in

 

61



 

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

 

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

 

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

 

Included in the provisions for deferred income 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 development rights in December 2002 and 2001, respectively.  The sales of land development rights in fiscal 2003 and 2002 created temporary differences due to the excess of expenses recognized under the cost recovery method for books over expenses deductible for tax purposes.

 

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

 

 

 

Year ended September 30,

 

 

 

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

 

 

62



 

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities 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 $929,000 for the year ended September 30, 2004 and increased $1,790,000, and $730,000 for the years ended September 30, 2003 and 2002, respectively.  The changes relate primarily to foreign tax credit carryforwards for which it is more likely than not that such carryforwards will not be utilized to reduce Barnwell’s U.S. tax obligation.

 

A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax asset will not be realized.  Barnwell has established a valuation allowance primarily for the U.S. tax effect of deferred Canadian taxes, foreign tax credits, accrued expenses and state of Hawaii net operating loss carryforwards which may not be realizable in future years as there can be no assurance of any specific level of earnings or that the timing of U.S. earnings will coincide with the payment of Canadian taxes to enable Canadian taxes to be fully deducted (or recoverable) for U.S. tax purposes.

 

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

 

63



 

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

 

9.             PENSION PLAN

 

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

 

The overall investment objective of the plan is to provide growth in the assets of the plan to fund future benefit obligations while managing risk in order to meet current benefit obligations.  Generally, principal repayments and interest received on government mortgage securities provide cash flows to fund current benefit obligations.  Longer-term obligations are generally estimated to be provided for by growth in equity securities.  The plan assets at September 30, 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 were invested as follows: 7% in cash and cash equivalents, 34% in debt securities, and 59% in equity securities.  Target asset allocations are not used, and allocations are adjusted from time to time as dictated by current and anticipated market conditions and required cash flows.

 

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

 

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

 

 

 

September 30,

 

 

 

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



 

The accumulated benefit obligation for the pension plan 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 expected long-term rate of return on assets assumption, historical returns and the future expectations for returns for each asset class were considered.

 

Expected Benefit Payments:

 

 

 

Fiscal year ending September 30, 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 that it will contribute the maximum tax-deductible amount of approximately $80,000 to the plan during fiscal 2005.

 

10.          STOCK OPTIONS

 

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

 

65



 

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 ended September 30, 2004, 2003 and 2002, respectively.

 

In June 1998, Barnwell granted 30,000 stock options to an officer of Barnwell’s oil and gas segment under a non-qualified plan at a purchase price of $15.625 per share (market price on date of grant), with 6,000 of such options vesting annually commencing one year from the date of grant.  These options have stock appreciation rights that permit the holder to receive stock, cash or a combination thereof equal to the amount by which the fair market value, at the time of exercise of the option, exceeds the option price.  The options expire in May 2008.  Barnwell recognized $599,000, $125,000 and $43,000 of compensation costs relating to these options in the years ended September 30, 2004, 2003 and 2002, respectively.

 

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

 

Stock options at September 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 at September 30, 2003 were as follows:

 

 

 

Options outstanding

 

Options exercisable

 

Range of
exercise prices

 

Number of
Shares

 

Weighted
Average
Remaining
Contractual
Life

 

Weighted
Average
Exercise
Price

 

Number of
Shares

 

Weighted
Average
Exercise
Price

 

$11.875 - $15.625

 

123,000

 

4.6 years

 

$

13.07

 

99,750

 

$

13.26

 

$19.625

 

20,000

 

1.4 years

 

$

19.63

 

20,000

 

$

19.63

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$11.875 - $19.625

 

143,000

 

4.2 years

 

$

13.99

 

119,750

 

$

14.32

 

 

66



 

Stock options at September 30, 2002 were as follows:

 

 

 

Options outstanding

 

Options exercisable

 

Range of
exercise prices

 

Number of
Shares

 

Weighted
Average
Remaining
Contractual
Life

 

Weighted
Average
Exercise
Price

 

Number of
Shares

 

Weighted
Average
Exercise
Price

 

$11.875 - $15.625

 

123,000

 

5.6 years

 

$

13.07

 

70,500

 

$

13.40

 

$19.625

 

20,000

 

2.4 years

 

$

19.63

 

20,000

 

$

19.63

 

 

 

 

 

 

 

 

 

 

 

 

 

$11.875 - $19.625

 

143,000

 

5.2 years

 

$

13.99

 

90,500

 

$

14.77

 

 

In December 2001, approximately $71,000 of convertible debentures, including accrued interest, was converted to 3,558 shares of Barnwell’s stock at $20 per share; these shares were issued from Barnwell’s treasury stock.  There were no conversions or repurchases of Barnwell’s stock in the year ended September 30, 2004.  Barnwell plans to repurchase additional shares from time to time in the open market or in privately negotiated transactions, depending on market conditions.  At September 30, 2004, Barnwell could purchase an additional 93,000 shares under the March 2000 repurchase authorization.

 

11.          COMMITMENTS AND CONTINGENCIES

 

Barnwell has committed to compensate its Vice President of Canadian Operations pursuant to an incentive compensation plan, the value of which directly relates to Barnwell’s oil and natural gas segment’s net income and the change in the value of Barnwell’s oil and gas reserves since 1998 with adjustments for changes in natural gas and oil prices and subject to other terms and conditions.  Barnwell recognized $60,000 and $166,000 of compensation expense pursuant to this incentive plan in fiscal 2004 and fiscal 2003, respectively.  In fiscal 2002, Barnwell recognized a $48,000 reduction in compensation expense pursuant to this incentive plan.

 

Barnwell has also committed to compensate certain Canadian personnel pursuant to an incentive compensation plan, the value of which directly relates to Barnwell’s oil and natural gas segment’s net income and the value of Barnwell’s oil and gas reserves discovered, commencing in fiscal 2002, for projects developed by such personnel.  Barnwell recognized approximately $190,000 of compensation costs pursuant to this plan in fiscal 2004, of which approximately $50,000 was expensed and approximately $140,000, the portion related to in-house geologists, was capitalized as oil and natural gas capital expenditures.  In fiscal 2003, Barnwell recognized approximately $80,000 of compensation costs pursuant to this plan, of which approximately $30,000 was expensed and approximately $50,000, the portion related to in-house geologists, was capitalized as oil and natural gas capital expenditures.  Barnwell recognized no compensation expense pursuant to this plan in fiscal 2002.

 

Barnwell has several non-cancelable operating leases for office space and leasehold land.  Rental expense was $444,000 in 2004, $474,000 in 2003, and $467,000 in 2002.  Barnwell is committed under these leases for minimum rental payments summarized by fiscal 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 land are subject to renegotiation after December 31,

 

67



 

2005; the future rental payment disclosures above assume the minimum lease payments for land in effect at December 31, 2005 remain unchanged through 2025, the end of the lease term. 

 

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

 

12.          SEGMENT AND GEOGRAPHIC INFORMATION

 

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

 

68



 

Barnwell does not allocate general and administrative expenses, interest expense, interest income or income taxes to segments, and there are no transactions between segments that affect segment profit or loss.

 

 

 

Year ended September 30,

 

 

 

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 cubic feet (“MCF”) of natural gas and natural gas equivalent (“MCFE”), converted at a rate of one barrel of oil and natural gas liquids to 5.8 MCFE, was $1.31 in fiscal 2004, $0.90 in fiscal 2003, and $0.71 in fiscal 2002.  The escalating depletion rate is the result of increased costs of finding and developing proven reserves, as compared to prior years, as well as increases in the average exchange rate of the Canadian dollar to the U.S. dollar of 10% in fiscal 2004, as compared to fiscal 2003, and 7% in fiscal 2003 as compared to fiscal 2002.

 

69



 

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 BY GEOGRAPHIC 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 GEOGRAPHIC AREA:

 

 

 

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

 

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

 

70



 

14.          CONCENTRATIONS OF CREDIT RISK

 

Barnwell’s oil and natural gas segment derived 53% of its oil and natural gas revenues in fiscal 2004 from three individually significant customers, ProGas Limited, Coral Energy Canada Inc., and Plains Marketing Canada, L.P.  At September 30, 2004, Barnwell had a total of $1,140,000 in receivables from these four customers.  In fiscal 2003 Barnwell derived 64% of its oil and natural gas revenues from four individually significant customers.  In fiscal 2002 Barnwell derived 76% of its oil and natural gas revenues from five individually significant customers.

 

Barnwell’s contract drilling subsidiary derived 70%, 66%, and 70% of its contract drilling revenues in fiscal 2004, 2003, and 2002, respectively, pursuant to Federal, State of Hawaii and county contracts.  At September 30, 2004, Barnwell had accounts receivables from the Federal, State of Hawaii and county entities totaling approximately $1,705,000.  Barnwell has lien rights on wells drilled and pumps installed for Federal, State of Hawaii, and county governments.

 

Historically, Barnwell has not incurred significant credit related losses on its trade receivables, and management does not believe significant credit risk related to these trade receivables exists at September 30, 2004.

 

71



 

15.          SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION

 

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

 

 

 

Year ended September 30,

 

 

 

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 Disclosure of Non-cash Investing and Financing Activities:

In December 2003, Barnwell purchased the premises and associated fee simple land interest of its corporate office in Honolulu, Hawaii, for $1,057,000, of which $883,000 was financed by long-term debt; the debt was subsequently repaid in full in June 2004.

 

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

 

16.          SUBSEQUENT EVENTS

 

On December 3, 2004, Barnwell declared a cash dividend of $0.25 per share payable January 5, 2005, to stockholders of record on December 20, 2004.

 

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

 

72



 

17.          SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)

 

The following tables summarize information relative to Barnwell’s oil and natural gas operations, which are substantially conducted in Canada.  Proved reserves are the estimated quantities of crude oil, condensate and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Proved producing oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  The estimated net interests in total proved and proved producing reserves are based upon subjective engineering judgments and may be affected by the limitations inherent in such estimations.  The process of estimating reserves is subject to continual revision as additional information becomes available as a result of drilling, testing, reservoir studies and production history.  There can be no assurance that such estimates will not be materially revised in subsequent periods.

 

(A)          Oil and Natural Gas Reserves

 

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

 

 

 

OIL
(Barrels)

 

GAS
(MCF)

 

Balance at September 30, 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

 

 


*  These amounts represent proved undeveloped reserves at Dunvegan added by Paddock Lindstrom & Associates, Ltd. based on the planned fiscal 2005 drilling program.  As of September 30, 2003, Paddock Lindstrom & Associates, Ltd. reported no proved undeveloped reserves at Dunvegan.

 

73



 

 

 

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)           Capitalized Costs 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)           Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

 

 

 

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)          The Results 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 and administrative expenses, interest expense, and foreign exchange losses.

 

74



 

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

 

The following tables have been developed pursuant to procedures prescribed by SFAS No. 69, and utilize reserve and production data estimated by petroleum engineers.  The information may be useful for certain comparison purposes but should not be solely relied upon in evaluating Barnwell or its performance.  Moreover, the projections should not be construed as realistic estimates of future cash flows, nor should the standardized measure be viewed as representing current value.

 

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

 

Standardized Measure of Estimated Discounted Future Net Cash Flows

 

 

 

As of September 30,

 

 

 

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



 

Changes in the Standardized 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

 

 


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

 

Item 7A.                 Quantitative and Qualitative Disclosures About Market Risk

 

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

 

76



 

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

 

None.

 

Item 8A.                 Controls and Procedures

 

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

 

Item 8B.                  Other Information

 

None.

 

PART III

 

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

 

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

 

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

 

Item 10.                  Executive Compensation

 

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

 

Item 11.                  Security Ownership of Certain Beneficial Owners and Management

 

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

 

77



 

Equity Compensation Plan Information

 

The following table provides information about Barnwell’s common stock that may be issued upon exercise of options and rights under all of Barnwell’s existing equity compensation plans as of September 30, 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 plans not approved by security holders are comprised of the following plans:

 

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

 

In June 1998, Barnwell granted 30,000 stock options to an officer of Barnwell’s oil and gas segment under a non-qualified plan at a purchase price of $15.625 per share (market price on date of grant), with 6,000 of such options vesting annually commencing one year from the date of grant.  These options have stock appreciation rights that permit the holder to receive stock, cash or a combination thereof equal to the amount by which the fair market value, at the time of exercise of the option, exceeds the option price.  The options expire in May 2008.

 

Item 12.                  Certain Relationships and Related Transactions

 

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

 

78



 

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

 

(A)          Financial Statements

 

The following consolidated financial statements of Barnwell Industries, Inc. and its subsidiaries are included in Part II, Item 7:

 

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 been omitted because they were not applicable, not required, or the information is included in the consolidated financial statements or notes thereto.

 

(B)           Reports on Form 8-K

 

None.

 

(C)           Exhibits

 

No. 3.1

Certificate of Incorporation(1)

 

 

 

 

No. 3.2

Amended and Restated By-Laws(1)

 

 

 

 

No. 4.0

Form of the Registrant’s certificate of common stock, par value $.50 per share.(2)

 

 

 

 

No. 10.1

The Barnwell Industries, Inc. Employees’ Pension Plan (restated as of October 1, 1989).(3)

 

 

 

 

No. 10.2

Phase I Makai Development Agreement dated June 30, 1992, by and between Kaupulehu Makai Venture and Kaupulehu Developments.(4)

 

 

 

 

No. 10.3

KD/KMV Agreement dated June 30, 1992 by and between Kaupulehu Makai Venture and Kaupulehu Developments.(4)

 

 

 

 

No. 10.4

Barnwell Industries, Inc.’s letter to Warren D. Steckley dated May 6, 1998, regarding certain terms of employment.(5)

 

 

 

 

No. 21

List of Subsidiaries

 

 

 

 

No. 31.1

Section 302 Certification by Morton H. Kinzler, Chief Executive Officer

 

 

 

 

No. 31.2

Section 302 Certification by Russell M. Gifford, Chief Financial Officer

 

 

 

 

No. 32

Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

 

 


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

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

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

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

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

 

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Item 14.                  Principal Accountant Fees and Services

 

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

 

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SIGNATURES

 

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

 

BARNWELL INDUSTRIES, INC.

 

(Registrant)

 

 

 

 

 

 

/s/ Russell M. Gifford

 

 

By:

Russell M. Gifford

 

 

Chief Financial Officer,

 

 

Executive Vice President,

 

 

Treasurer and Secretary

 

Date:

December 3, 2004

 

 

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

 

/s/ Morton H. Kinzler

 

 

MORTON H. KINZLER

 

Chief Executive Officer and

 

Chairman of the Board

 

Date: December 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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