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PHX MINERALS INC. - Annual Report: 2003 (Form 10-K)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Annual Report under Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended September 30, 2003

Commission File Number: 0-9116

PANHANDLE ROYALTY COMPANY


(Exact name of registrant as specified in its charter)
     
OKLAHOMA   73-1055775

 
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
     
Grand Centre, Suite 210, 5400 North Grand Blvd., Oklahoma City, OK   73112

 
(Address of principal executive offices)   (Zip code)

Registrant’s telephone number (405) 948-1560

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

     
CLASS A COMMON STOCK (VOTING)   AMERICAN STOCK EXCHANGE

 
(Title of Class)   (Name of each exchange on which registered)

Securities registered under Section 12(g) of the Act:

                     (Title of Class)

CLASS B COMMON STOCK (NON-VOTING) $1.00 par value

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act 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.

[X] Yes    [  ] No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicated by check mark whether the registrant is an accelerated filer (as defined in Rule 126-2 of the Act).

[  ] Yes    [X] No

The aggregate market value of the voting stock held by non-affiliates of the registrant, computed by using the closing price of registrant’s common stock, at March 31, 2003, was $31,122,979. As of December 4, 2003, 2,089,101 shares of Class A Common stock were outstanding.

Documents Incorporated By Reference

The definitive proxy statement for the registrant’s annual meeting of shareholders to be held in 2004 (to be filed within 120 days of the close of registrant’s fiscal year) is incorporated by reference into Part III, hereof.

 


TABLE OF CONTENTS

PART I
ITEM 1 BUSINESS
ITEM 2 PROPERTIES
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 SELECTED FINANCIAL DATA
ITEM 7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 7 A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
ITEM 8 FINANCIAL STATEMENTS
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9 A CONTROLS AND PROCEDURES
PART III
ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
SIGNATURES
EX-10 Amendment to Loan Agreement
EX-21 Subsidiaries
EX-31.1 Certification of Chief Executive Officer
EX-31.2 Certification of Chief Financial Officer
EX-32.1 Certification of Chief Executive Officer
EX-32.2 Certification of Chief Financial Officer


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TABLE OF CONTENTS

                 
            Page
           
PART I  
 
       
Item 1  
Business
    1-4  
Item 2  
Properties
    5-10  
Item 3  
Legal Proceedings
    10  
Item 4  
Submission of Matters to a Vote of Security Holders
    10  
PART II
Item 5  
Market for Registrants Common Equity and Related Stockholder Matters
    10-11  
Item 6  
Selected Financial Data
    11-12  
Item 7  
Management’s Discussion and Analysis of Financial Condition and Results of Operations
    12-17  
Item 7A  
Quantitative and Qualitative Disclosures about Market Risk
    17  
Item 8  
Financial Statements and Supplementary Data
    17-42  
Item 9  
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    43  
Item 9A  
Controls and Procedures
    43  
PART III
Item 10-14  
Incorporated by Reference to Proxy Statement
       
PART IV
Item 15  
Exhibits, Financial Statement Schedules and Reports on Form 8- K
    43  
Signature Page  
 
    44  
Exhibit 10  
 
    45-56  
Exhibit 21  
 
    57  
Exhibit 31.1-31.2  
 
    58-59  
Exhibit 32.1-32.2  
 
    60-61  

As used in this report, “SEC” means the United States Securities and Exchange Commission, “Bbl” means barrel, “Mcf” means thousand cubic feet, “Mcf/D” means thousand cubic feet per day, “Mcfe” means natural gas stated on an MCF basis and crude oil converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil to six Mcf of natural gas, “PV-10” means estimated pretax present value of future net revenues discounted at 10% using SEC rules, “gross” wells or acres are the wells or acres in which the Company has a working interest, and “net” wells or acres are determined by multiplying gross wells or acres by the Company’s net revenue interest in such wells or acres. References to years 2001-2004 refer to the Company’s fiscal years ended September 30, each year.

 


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PART I

ITEM 1 BUSINESS

     GENERAL

     Panhandle Royalty Company (“Panhandle” or the “Company”) is an Oklahoma Corporation, organized in 1926 as Panhandle Cooperative Royalty Company. In 1979, Panhandle Cooperative Royalty Company was merged into Panhandle Royalty Company. Panhandle’s authorized and registered stock consisted of 100,000 shares of $1.00 par value Class A common stock. In 1982, the Company split the stock on a 10-for-1 basis and reduced the par value to $.10, resulting in 1,000,000 shares of authorized Class A Common stock. In May 1999, the Company’s shareholders voted to increase the authorized Class A Common stock of the Company to 6,000,000 shares and to split the shares on a three-for-one basis. In addition, voting rights for the shares were changed from one vote per shareholder to one vote per share.

     Since its formation, the Company has been involved in the acquisition and management of mineral interests and the exploration for, and development of, oil and gas properties, principally involving wells located on the Company’s mineral interests. Panhandle’s mineral properties and other oil and gas interests are located primarily in Oklahoma, New Mexico and Texas. Properties are also located in nineteen other states. The majority of the Company’s oil and gas production is from wells located in Oklahoma and New Mexico. In 1988, the Company merged with New Mexico Osage Royalty Company, thus acquiring most of its New Mexico mineral interests.

     On October 1, 2001, Panhandle acquired privately held Wood Oil Company (Wood) of Tulsa, Oklahoma. The acquisition was made pursuant to an Agreement and Plan of Merger among Panhandle Royalty Company, PHC, Inc., and Wood, dated August 9, 2001. Wood merged with Panhandle’s wholly owned subsidiary PHC, Inc., on October 1, 2001, with Wood being the surviving Company. Prior to the acquisition, Wood was a privately held company engaged in oil and gas exploration and production and fee mineral ownership and owned interests in certain oil and gas and real estate partnerships and an office building in Tulsa. Wood is operating as a subsidiary of Panhandle. Wood and its shareholders were unrelated parties to Panhandle.

     The Company’s office is located at Grand Centre Suite 210, 5400 North Grand Blvd., Oklahoma City, OK 73112 (405)948-1560, FAX (405)948-2038. Its website is located at www.panra.com.

BUSINESS STRATEGY

     The majority of Panhandle’s revenues are derived from the production and sale of oil and natural gas. See “Item 8 — Financial Statements”. The Company’s oil and gas holdings, including its mineral interests and its interests in producing wells, both working interests and royalty interests, are centered in Oklahoma with activity, in recent years, in New Mexico and Texas. See “Item 2 — Description of Properties”. Exploration and development of the Company’s oil and gas properties are conducted in association with operating oil and gas companies, including major and independent companies. The Company does not operate any of its oil and gas properties. The Company has been an active participant for many years in wells drilled on the Company’s mineral properties and in third party drilling prospects. A large percentage of the Company’s recent drilling participations have been on properties in which the Company has mineral interests and in many cases already owns an interest in a producing well in the unit. This “increased density” drilling has accounted for a large part of the successful oil and gas wells

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completed during these years and has added significant reserves for the Company. The Company acquired additional mineral interest properties, both producing and non-producing and interests in approximately 2000 wells in the Wood acquisition. Several of the mineral properties and well interests were in areas where the Company had no mineral holdings, thus expanding the Company’s area of interest.

     PRINCIPAL PRODUCTS AND MARKETS

     The Company’s principal products are crude oil and natural gas. These products are sold to various purchasers, including pipeline and marketing companies, which are generally located in and service the areas where the Company’s producing wells are located. The Company does not act as operator for any of the properties in which it owns an interest, thus it relies on the operating expertise of numerous companies that operate in the area where the Company owns mineral interests. This expertise includes drilling operations and completions, producing well operations and, in some cases, the marketing or purchasing of the well’s production. Natural gas sales are principally handled by the well operator and are normally contracted on a monthly basis with third party gas marketers and pipeline companies. Payment for gas sold is received either from the contracted purchasers or the well operator. Crude oil sales are generally handled by the well operator and payment for oil sold is received from the well operator or from the crude oil purchaser.

     In general, prices of oil and gas are dependent on numerous factors beyond the control of the Company, such as competition, international events and circumstances (including actions taken by the Organization of Petroleum Exporting Countries (OPEC)), and economic, political and regulatory developments. Since demand for natural gas is generally highest during winter months, prices received for the Company’s natural gas are subject to seasonal variations.

     COMPETITIVE BUSINESS CONDITIONS

     The oil and gas industry is highly competitive, particularly in the search for new oil and gas reserves. There are many factors affecting Panhandle’s competitive position and the market for its products which are beyond its control. Some of these factors are the quantity and price of foreign oil imports, changes in prices received for its oil and gas production, business and consumer demand for refined oil products and natural gas, and the effects of federal and state regulation of the exploration, production and sales of oil and natural gas. Changes in existing economic conditions, weather patterns and actions taken by OPEC and other oil-producing countries have dramatic influence on the price Panhandle receives for its oil and gas production. The Company relies heavily on companies with greater resources, staff, equipment, research, and experience for operation of wells and the development and drilling of subsurface prospects. The Company uses its strong financial base and its mineral property ownership, coupled with it’s own geologic and economic evaluation to participate in drilling operations with these larger companies. This method allows the Company to effectively compete in drilling operations it could not undertake on its own due to financial and personnel limits and allows it to maintain low overhead costs.

     SOURCES AND AVAILABILITY OF RAW MATERIALS

     The existence of commercial oil and gas reserves is essential to the ultimate realization of value from the Company’s mineral properties and these mineral properties may be considered a raw material to its business. The production and sale of oil and natural gas from the Company’s oil and gas properties is essential to provide the cash flow necessary to sustain the ongoing viability of the Company.

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The Company continues to reinvest a portion of its cash flow in the purchase of oil and gas leasehold acreage and additional mineral properties to assure the continued availability of acreage with which to participate in exploration, drilling, and development operations and subsequently the production and sale of oil and gas. This participation in exploration and production and the purchasing of additional mineral interests will continue to supply the Company with the raw materials with which to generate additional cash flow. Mineral and leasehold purchases are made from varied owners, and the Company does not rely on any particular companies or individuals for these acquisitions.

     MAJOR CUSTOMERS

     The Company’s oil and gas production is sold by the well operators, in most cases, to many different purchasers on a well-by-well basis. During fiscal 2003, sales to ONEOK, through well operators, accounted for approximately 14% of the Company’s total revenues. Generally, if one purchaser declines to continue purchasing the Company’s oil and/or natural gas, several other purchasers can be located, especially in the current market environment for natural gas. Pricing is usually reasonably consistent from purchaser to purchaser.

     PATENTS, TRADEMARKS, LICENSES, FRANCHISES AND ROYALTY AGREEMENTS

     The Company does not own any patents, trademarks, licenses or franchises. Royalty agreements on producing oil and gas wells stemming from the Company’s ownership of mineral interests generate a substantial portion of the Company’s revenues. These royalties are tied to the ownership of the mineral interests and this ownership is perpetual, unless sold by the Company. Royalties are due and payable to the Company whenever oil and/or gas is produced from wells located on the Company’s mineral properties.

     GOVERNMENTAL REGULATION

     Oil and gas production is subject to various taxes, such as gross production taxes and, in some cases, ad valorem taxes.

     The State of Oklahoma and other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. These statutes and regulations currently limit the rate at which oil and gas can be produced from certain of the Company’s properties. As previously discussed, the well operators are relied upon by Panhandle to comply with governmental regulations.

     Various aspects of the Company’s oil and gas operations are regulated by agencies of the federal government. The transportation of natural gas in interstate commerce is generally regulated by the Federal Energy Regulatory Commission (FERC) pursuant to the Natural Gas Act of 1938 (the NGA) and the Natural Gas Policy Act of 1978 (NGPA). The intrastate transportation and gathering of natural gas (and operational and safety matters related thereto) may be subject to regulation by state and local governments.

     In the past, the federal government regulated the prices at which the Company’s produced oil and gas could be sold. Currently, “first sales” of natural gas by producers and marketers, and all sales of crude oil, condensate and natural gas liquids, can be made at uncontrolled market prices, but Congress could reenact price controls at any time.

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     Within the past decade, the FERC has issued numerous orders and policy statements designed to create a more competitive environment in the national natural gas marketplace, including orders promoting “open access” transportation on natural gas pipelines subject to the FERC’s NGA and NGPA jurisdiction. The FERC’s “Order 636” was issued in April 1992 and was designed to restructure the interstate natural gas transportation and marketing system and to promote competition within all phases of the natural gas industry. Among other things, Order 636 required interstate pipelines to separate the transportation of gas from the sale of gas, to change the manner in which pipeline rates were designed and to implement other changes intended to promote the growth of market centers. Subsequent FERC initiatives have attempted to standardize interstate pipeline business practices and to allow pipelines to implement market-based, negotiated and incentive rates. The restructured services implemented by Order 636 and successor orders have now been in effect for a number of winter heating seasons and have significantly affected the manner in which natural gas (both domestic and foreign) is transported and sold to consumers.

     FERC has indicated that it remains committed to Order 636’s “fundamental goal” of “improving the competitive structure of the natural gas industry in order to maximize the benefits of wellhead decontrol,” the future regulatory goals and priorities of FERC may change, and it is not possible to predict the effect, if any, of future restructuring orders or policies on the Company’s operations.

     Federal tax law has allowed producers of “tight gas” to utilize an approximate $.52/MMBTU tax credit for gas produced from approved wells. The credit was a direct reduction of regular federal income tax. Panhandle began receiving revenues from “tight gas” wells during fiscal 1992. This credit was available for all tight gas sold prior to January 1, 2003.

     While Order 636 and related orders do not directly regulate either the production or sale of gas that may be produced from the Company’s properties, the increased competition and changes in business practices within the natural gas industry resulting from such orders have affected the terms and conditions under which the Company markets and transports its available gas supplies. To date, the FERC’s pro-competition policies have not materially affected the Company’s business or operations. On a prospective basis, however, such orders may substantially increase the burden on producers and transporters to accurately nominate and deliver on a daily basis specified volumes of natural gas, or to bear penalties or increased costs in the event scheduled deliveries are not made.

     ENVIRONMENTAL MATTERS

     As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays, however, to date the Company’s cost of compliance has been insignificant. The Company does not believe the existence of these environmental laws will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future events. Since the Company does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by others, with Panhandle being responsible for its proportionate share of the costs involved. Panhandle carries liability insurance and to the extent available at reasonable cost, pollution control coverage. However, all risks are not insured due to the availability and cost of insurance.

     EMPLOYEES

     At September 30, 2003, Panhandle employed fifteen persons on a full-time basis and has no part-time employees. Three of the employees are executive officers and one is also a director of the Company.

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ITEM 2 PROPERTIES

     As of September 30, 2003, Panhandle’s principal properties consisted of perpetual ownership of 259,390 net mineral acres, held principally in tracts in Oklahoma, New Mexico and Texas and 19 other states. The Company also held leases on 20,227 net acres of minerals in Louisiana, Oklahoma and Texas. At September 30, 2003, Panhandle held small royalty and/or working interests in 4,898 producing oil or gas wells, of which 98 were successfully completed but not yet producing wells, and 60 wells in the process of being drilled or completed.

     Panhandle does not have current abstracts or title opinions on all mineral properties owned and, therefore, cannot warrant that it has unencumbered title to all of its properties. In recent years, few challenges have been made against the Company’s fee title to its properties.

     Panhandle pays ad valorem taxes on its minerals owned in Arkansas, Colorado, Idaho, Indiana, Illinois, Kansas, Tennessee and Texas.

     ACREAGE

     The following table of mineral interests owned reflects, as of September 30, 2003, in each respective state, the number of net and gross acres, net and gross producing acres, net and gross acres leased, and net and gross acres open (unleased).

MINERAL INTERESTS

                                                                   
                      Net   Gross   Net   Gross   Net   Gross
      Net   Gross   Acres   Acres   Acres   Acres   Acres   Acres
      Acres   Acres   Prod’g   Prod’g   Leased   Leased   Open   Open
State           (1)   (1)   (2)   (2)   (3)   (3)

 
 
 
 
 
 
 
 
Alabama
    5       479                                       5       479  
Arkansas
    10,050       44,636       1,068       2,756                       8,982       41,880  
Colorado
    8,327       39,299       109       219                       8,217       39,080  
Florida
    6,901       13,849                                       6,901       13,849  
Idaho
    30       880                                       30       880  
Illinois
    1,068       5,038       40       320                       1,028       4,718  
Indiana
    27       262                                       27       262  
Kansas
    3,122       11,976       110       880                       3,012       11,096  
Louisiana
    17       17                                       17       17  
Missouri
    355       430                                       355       430  
Mississippi
    150       740                                       150       740  
Montana
    1,008       17,947                                       1,008       17,947  
Nebraska
    1,319       13,249                                       1,319       13,249  
North Dakota
    11,179       64,286                                       11,179       64,286  
New Mexico
    57,456       172,879       1,365       6,200       140       560       55,951       166,119  
Oklahoma
    113,146       949,467       27,914       201,465       1,538       3,167       83,693       737,608  
Oregon
    72       2,187                                       72       2,187  
South Dakota
    1,825       9,300                                       1,825       9,300  
Tennessee
    40       500                                       40       500  
Texas
    43,085       361,017       6,889       76,999       172       1,901       36,025       282,117  
Utah
    160       320                                       160       320  
Washington
    50       298                                       50       298  
 
   
     
     
     
     
     
     
     
 
 
Total:
    259,390       1,709,054       37,495       288,839       1,850       5,628       220,045       1,407,361  
 
   
     
     
     
     
     
     
     
 

(1)   “Producing” represents the mineral acres in which Panhandle owns a royalty or working interest in a producing well.
 
(2)   “Leased” represents the mineral acres, owned by Panhandle, that are leased to third parties but not producing.
 
(3)   “Open” represents mineral acres owned by Panhandle that are not leased or in production.

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     The following table reflects net mineral acres leased from others, lease expiration dates, and net leased acres held by production.

LEASES

                                         
                                    Net Acres
    Net   Lease Acres   Held by
State   Acres   Expiring   Production

 
 
 
            2004   2005   2006        
           
 
 
       
Kansas
    2,117                         2,117  
Oklahoma
    15,984       1,976       715       1,183       12,110  
Texas
    304                         304  
New Mexico
    494                         494  
Other
    1,328                         1,328  
 
   
     
     
     
     
 
TOTAL
    20,227       1,976       715       1,183       16,353  
 
   
     
     
     
     
 

     PROVED RESERVES

     The following table summarizes estimates of the proved reserves of oil and gas held by Panhandle. All reserves are located within the United States. Because the Company’s non-producing mineral and leasehold interests consist of various small interests in numerous tracts located primarily in Oklahoma, New Mexico and Texas and because the Company is a non-operator and must rely on third parties to propose and drill wells, it is not feasible to provide estimates of all proved undeveloped reserves and associated future net revenues. Prior to fiscal 1995, the Company did not provide estimates of any proved undeveloped reserves. The Company directs its independent petroleum engineering firm to include proved undeveloped reserves in certain significant areas in the scope of properties evaluated for the Company. The Company, expects drilling to continue in these areas for the next several years, and thus made the decision to provide proved undeveloped reserve estimates for these areas. All reserve quantity estimates were prepared by Campbell & Associates, Inc., an independent petroleum engineering firm. The Company’s reserve estimates were not filed with any other federal agency.

                 
    Barrels of Oil   MCF of Gas
   
 
Proved Developed Reserves
               
September 30, 2003
    703,400       23,599,473  
September 30, 2002
    820,790       22,896,330  
September 30, 2001
    412,705       13,236,455  
Proved Undeveloped Reserves
               
September 30, 2003
    132,575       4,670,400  
September 30, 2002
    294,415       5,219,570  
September 30, 2001
    263,386       4,451,895  
Total Proved Reserves
               
September 30, 2003
    835,978       28,269,873  
September 30, 2002
    1,115,205       28,115,900  
September 30, 2001
    676,091       17,688,350  

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     The major portion of the increase in total proved reserves at September 30, 2002 and 2003, as compared to September 30, 2001, is due to the addition of Wood Oil Company’s reserves. At September 30, 2002 and 2003, respectively, Wood’s total proved reserves were 521,442 barrels and 9,803,280 mcf and 368,831 barrels and 9,324,613 mcf. These reserves are net of approximately 1.2 mmcf of CO2 gas reserves owned by Wood Oil Company.

     Because the determination of reserves is a function of testing, evaluating, developing oil and gas reservoirs and establishing a production decline history, along with product price fluctuations, it would be expected that estimates will change as future information concerning those reservoirs is developed and as market conditions change. Estimated reserve quantities and future net revenues are affected by changes in product prices, and these prices have varied substantially in recent years. Proved developed reserves are those expected to be recovered through existing well bores under existing economic and operating conditions. Proved undeveloped reserves are reserves that may be recovered from undrilled acreage, but are usually limited to those sites directly offsetting established production units and have sufficient geological data to indicate a reasonable expectation of commercial success.

     ESTIMATED FUTURE NET REVENUES

     Set forth below are estimated future net cash flows with respect to Panhandle’s proved reserves (based on the estimated units set forth in the immediately preceding table) as of year ends, and the present value of such estimated future net cash flows, computed by applying a ten (10) percent discount factor as required by the rules and regulations of the Securities and Exchange Commission. Estimated future net cash flows have been computed by applying current year-end prices to future production of proved reserves less estimated future expenditures (based on costs as of year end) to be incurred with respect to the development and production of such reserves. Such pricing is based on SEC guidelines. No federal income taxes are included in estimated costs. However, the amounts are net of operating costs and production taxes levied by respective states. Prices used for determining future cash flows from oil and natural gas for the periods ended September 30, 2003, 2002, 2001 were as follows: 2003 - $27.39, $4.43; 2002 - $27.76, $3.12; 2001 - $24.03, $1.81. These future net cash flows should not be construed as the fair market value of the Company’s reserves. A market value determination would need to include many additional factors, including anticipated oil and gas price increases or decreases.

Estimated Future Net Cash Flows

                         
    9-30-03   9-30-02   9-30-01
   
 
 
Proved Developed
  $ 97,847,582     $ 76,081,978     $ 25,797,780  
Proved Undeveloped
  $ 17,893,760     $ 18,572,672     $ 10,141,828  
 
   
     
     
 
Total Proved (1)
  $ 115,741,342     $ 94,654,650     $ 35,939,608  

10% Discounted Present Value of Estimated Future Net Cash Flows

                         
    9-30-03   9-30-02   9-30-01
   
 
 
Proved Developed
  $ 63,591,623     $ 49,485,409     $ 17,533,672  
Proved Undeveloped
  $ 11,905,681     $ 11,868,812     $ 6,589,021  
 
   
     
     
 
Total Proved (1)
  $ 75,497,304     $ 61,354,221     $ 24,122,693  

  (1)   The increase from September 30, 2001 to September 30, 2002 and 2003 is primarily attributable to the addition of reserves from Wood Oil Company and the increased oil and gas prices used in the 2002 and 2003 reserve report (see above listed prices).

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     OIL AND GAS PRODUCTION

     The following table sets forth the Company’s net production of oil and gas for the fiscal periods indicated.

                         
    Year   Year   Year
    Ended   Ended   Ended
    9-30-03   9-30-02   9-30-01
   
 
 
Bbls - Oil
    112,746       132,514       68,530  
MCF - Gas
    3,926,124       3,897,084       2,208,238  

     The increase in production volumes from September 30, 2001 to September 30, 2002 and 2003 was substantially due to the production of 1,582,277 mcf and 74,294 barrels and 1,510,206 mcf and 69,243 barrels from the Wood Oil properties, respectively.

Average Sales Prices and Production Costs

     The following table sets forth unit price and cost data for the fiscal periods indicated.

                         
    Year   Year   Year
    Ended   Ended   Ended
Average Sales Price   9-30-03   9-30-02   9-30-01

 
 
 
Per Bbl. Oil
  $ 29.30     $ 22.48     $ 28.16  
Per MCF Gas
  $ 4.79     $ 2.59     $ 4.81  

Average Production (Lifting Cost)
(Per MCFE of Gas)

                         
(1)
  $ .46     $ .36     $ .27  
(2)
  $ .41     $ .28     $ .41  
 
   
     
     
 
 
  $ .87     $ .64     $ .68  

  (1)   Includes actual well operating costs only.
 
  (2)   Includes production taxes, compression, handling and marketing fees paid on natural gas sales and other minor expenses associated with well operations.

     A substantial number of the Company’s producing well interests are royalty interests, which bear no share of the operating costs.

     GROSS AND NET PRODUCTIVE WELLS AND DEVELOPED ACRES

     The following table sets forth Panhandle’s gross and net productive oil and gas wells as of September 30, 2003. Panhandle owns fractional royalty interests or fractional working interests in these wells. The Company does not operate any wells.

                 
    Gross Wells   Net Wells
   
 
Oil
    957       25.876996  
Gas
    3,941       78.647848  
 
   
     
 
TOTAL
    4,898       104.524844  

     Information on multiple completions is not available from Panhandle’s records, but the number of such is insignificant.

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     As of September 30, 2003, Panhandle owned 288,839 gross developed mineral acres and 37,495 net developed mineral acres. Panhandle has also leased from others 149,841 gross developed acres which contain 16,353 net developed acres.

     UNDEVELOPED ACREAGE

     As of September 30, 2003, Panhandle owned 1,420,215 gross and 221,895 net undeveloped mineral acres, and leases on 69,260 gross and 3,874 net acres.

     DRILLING ACTIVITY

     The following net productive development and exploratory wells and net dry development and exploratory wells, in which the Company had a fractional royalty or working interest, were drilled and completed during the fiscal years indicated. Also shown are the net wells purchased during these periods.

                   
      Net Productive   Net Dry
      Wells   Wells
     
 
Development Wells
               
 
Fiscal year ending September 30, 2001
    4.568279       .969404  
 
Fiscal year ending September 30, 2002
    4.059870       1.146157  
 
Fiscal year ending September 30, 2003
    4.986539       .462544  
Exploratory Wells
               
 
Fiscal year ending September 30, 2001
    1.806223       .676206  
 
Fiscal year ending September 30, 2002
    1.416253       .550419  
 
Fiscal year ending September 30, 2003
    1.117805       .541950  
Purchased Wells
               
 
Fiscal year ending September 30, 2001
    .040365       0  
 
Fiscal year ending September 30, 2002
    53.246100       0  
 
Fiscal year ending September 30, 2003
    .113069       0  

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PRESENT ACTIVITIES

     The following table sets forth the gross and net oil and gas wells drilling or testing as of September 30, 2003, in which Panhandle owns a royalty or working interest.

                 
    Gross Wells   Net Wells
   
 
Oil
    7       .108641  
Gas
    53       1.730527  

OTHER FACILITIES

     The Company leases approximately 8,189 square feet of office space in Oklahoma City, OK. The obligation under this lease will end in 2008.

ITEM 3 LEGAL PROCEEDINGS

     There were no material legal proceedings involving Panhandle or its subsidiary, as of the date of this report.

ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     No matters were submitted to a vote of Panhandle’s security holders during the fourth quarter of the fiscal year ended September 30, 2003.

PART II

ITEM 5 MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     The Company’s common stock is listed on the American Stock Exchange (symbol PHX). The following table sets forth the high and low trade prices of the Company’s common stock during the periods indicated:

                 
Quarter Ended   HIGH   LOW

 
 
December 31, 2001
  $ 18.00     $ 14.70  
March 31, 2002
  $ 15.15     $ 14.35  
June 30, 2002
  $ 15.90     $ 14.00  
September 30, 2002
  $ 14.95     $ 12.75  
December 31, 2002
  $ 20.20     $ 12.00  
March 31, 2003
  $ 18.13     $ 15.25  
June 30, 2003
  $ 23.84     $ 14.94  
September 30, 2003
  $ 23.91     $ 21.40  

As of December 4, 2003, the approximate number of holders of shares of Panhandle stock was:

         
Title of Class   Number of Holders

 
Class A Common (Voting)
    2,700  

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During the past two years, cash dividends have been paid as follows on the class A common stock:

         
DATE   RATE PER SHARE

 
December 2001
  $ .07  
March 2002
  $ .07  
June 2002
  $ .07  
September 2002
  $ .07  
December 2002
  $ .07  
March 2003
  $ .07  
June 2003
  $ .07  
September 2003
  $ .07  

     The Company’s line of credit loan agreement contains a provision limiting the paying or declaring of a cash dividend to fifty percent of cash flow, as defined, of the preceding twelve-month period. See Note 4 to the consolidated financial statements contained herein at “Item 8 — Financial Statements”, for a further discussion of the loan agreement.

ITEM 6 SELECTED FINANCIAL DATA

     The following table summarizes consolidated financial data of the Company and should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements of the Company, including the Notes thereto, included elsewhere in this report.

                                           
      Year Ended September 30,
     
      2003 (A)   2002 (A)   2001   2000   1999
     
 
 
 
 
Revenues
                                       
Oil & Gas Sales
  $ 22,098,198     $ 13,080,754     $ 12,546,055     $ 9,091,920     $ 5,077,240  
Lease Bonuses
    72,765       41,497       17,991       82,030       10,773  
Interest & Other
    285,075       469,146       231,876       104,024       29,462  
 
   
     
     
     
     
 
 
  $ 22,456,038     $ 13,591,397     $ 12,795,922     $ 9,277,974     $ 5,117,475  
 
   
     
     
     
     
 
Costs & Expenses
                                       
Lease Oper. Exp. & Prod. Taxes
  $ 4,013,572     $ 3,001,449     $ 1,771,789     $ 1,458,935     $ 963,804  
Exploration Costs (B)
    469,224       417,971       947,046       514,739       535,431  
Depr. Depl. Amortization
    5,783,457       5,845,779       1,670,961       1,789,491       1,379,562  
Provision for Impairment
    692,220       1,116,234       848,535       262,998       357,891  
Gen. & Administrative
    2,666,177       2,263,908       1,689,426       1,450,241       1,164,745  
Interest Expense
    699,266       895,997       779       15,643       16,943  
 
   
     
     
     
     
 
 
  $ 14,323,916     $ 13,541,338     $ 6,928,536     $ 5,492,047     $ 4,418,376  
 
   
     
     
     
     
 
Income before Provision (Benefit) for Income Taxes
  $ 8,132,122     $ 50,059     $ 5,867,386     $ 3,785,927     $ 699,099  
Cumulative effect of accounting changes, net of taxes of $28,500 (C)
    46,500                          
Provision (Benefit) for Income Taxes
    2,217,000       (293,000 )     1,600,000       925,000       (35,000 )
 
   
     
     
     
     
 
Net Income
  $ 5,961,622     $ 343,059     $ 4,267,386     $ 2,860,927     $ 734,099  
 
   
     
     
     
     
 

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      Year Ended September 30,
     
      2003 (A)   2002 (A)   2001   2000   1999
     
 
 
 
 
Diluted Earnings per Share
  $ 2.83     $ .16     $ 2.05     $ 1.38     $ .36  
Dividends Declared per share
  $ .28     $ .28     $ .35     $ .28     $ .27  
Weighted Average Shares Outstanding
                                       
 
Basic
    2,081,372       2,067,872       2,060,109       2,055,470       2,047,507  
 
Diluted
    2,103,713       2,089,972       2,085,044       2,077,430       2,063,906  
Net Cash Provided
                                       
 
By Operating Activities
  $ 13,198,368     $ 7,481,195     $ 9,302,965     $ 5,366,066     $ 2,836,783  
Total Assets
  $ 49,402,534     $ 44,837,068     $ 25,279,684     $ 16,210,327     $ 13,263,877  
Long-Term Debt
  $ 12,666,661     $ 14,024,000     $ 4,050,000     $ 0     $ 0  
Shareholders Equity
  $ 22,527,685     $ 16,953,294     $ 16,995,050     $ 13,353,814     $ 11,048,604  

All share per share amounts, are adjusted for the effect of the 3-for-1 stock split which was effective May 7, 1999.

  (A)  2002 and 2003 results included are consolidated amounts of Panhandle Royalty Company and wholly owned subsidiary Wood Oil Company, acquired October 1, 2001.

  (B)  The Company uses the successful efforts method of accounting for its oil and gas activities.

  (C)  Represents the income effect of the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations on October 1, 2003. See Note 1: Summary of Significant Accounting Policies of Notes to the Condensed Consolidated Financial Statements for a complete discussion.

ITEM 7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

    Forward-looking statements for 2004 and later periods are made throughout this document. Such statements represent estimates of management based on the Company’s historical operating trends, its proved oil and gas reserves and other information currently available to management. The Company cautions that the forward-looking statements provided herein are subject to all the risks and uncertainties incident to the acquisition, development and marketing of, and exploration for oil and gas reserves. These risks include, but are not limited to oil and natural gas price risk, environmental risk, drilling risk, reserve quantity risk and operations and production risks. For all the above reasons, actual results may vary materially from the forward-looking statements and there is no assurance that the assumptions used are necessarily the most likely to occur.

GENERAL

     The Company’s principal line of business is the production and sale of oil and natural gas. Results of operations are dependent upon the quantity of production and the price obtained for such production. Prices received by the Company for the sale of its oil and natural gas have fluctuated significantly from period to period. Such fluctuations affect the Company’s ability to maintain or increase its production from existing oil and gas properties and to explore, develop or acquire new properties.

     The following table reflects certain operating data for the periods presented:

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      For the Year Ended
      September 30,
     
      2003   2002   2001
     
 
 
Production:
                       
 
Oil (bbls)
    112,746       132,514       68,530  
 
Gas (mcf)
    3,926,124       3,897,084       2,208,238  
Average Sales Price:
                       
 
Oil (per bbl)
  $ 29.30     $ 22.48     $ 28.16  
 
Gas (per mcf)
  $ 4.79     $ 2.59     $ 4.81  

RESULTS OF OPERATIONS
2003 COMPARED TO 2002.

REVENUES

          Total revenues increased 65% to $22,456,038 in 2003 compared to $13,591,397 in 2002. The increase was due to a large increase in the average sales price for natural gas in 2002; offset some what by a 15% decrease in oil production volumes in 2003. Gas production volume was basically flat in 2003 compared to 2002. New production from the Company’s drilling activity replaced the normal decline of existing gas wells. Few oil wells have been drilled in recent years, thus, oil production continues to decline.

LEASE OPERATING EXPENSES AND PRODUCTION TAXES (LOE)

          LOE continues to increase each year as the Company increases the number of working interest wells in which it has an interest. The Company participated in a record number of working interest wells in 2003. Gross production taxes are paid as a percentage of oil and gas sales revenues and thus increased substantially in 2003 due to the large increase in oil and gas sales revenues.

EXPLORATION COSTS

          Exploration costs increased $51,253 or 12% in 2003 as compared to 2002. The increased costs were primarily dry hole costs. As previously mentioned, the Company participated in a record number of wells in 2003, several of which were exploratory. As the Company utilizes the successful efforts method of accounting for oil and gas operations, dry holes resulted in the expensing of all costs associated with those wells.

DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)

          DD&A declined $62,322 or 1% in 2003. The decline was principally due to decreased oil production volume in 2003; reducing the units of production DD&A on the Company’s oil properties.

PROVISION FOR IMPAIRMENT

          The provision for impairment of the Company’s oil and gas properties decreased $424,014, or 38% in 2003. This decrease can be principally attributed to the higher market price for natural gas at year-end 2003 as compared to year-end 2002.

GENERAL AND ADMINISTRATIVE COSTS (G&A)

          G&A costs increased $402,269 in 2003. Personnel related expenses (including salaries, payroll taxes, insurance expenses and ESOP expenses) increased approximately $137,000 in 2003. G&A expense related to the Non-Employee Directors Deferred Compensation Plan (“the Plan”) increased approximately $180,000 in 2003. This increase was a result of the Company recognizing a charge to

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general and administrative expense to adjust the potential shares in the Plan to market price at September 30, 2003, versus a minimal charge in 2002 for the same adjustment. The Non-Employee directors have taken these potential shares, rather than a cash payment for their director’s fees. In addition, the Company incurred expenses of approximately $50,000 upon listing its shares on the American Stock Exchange in 2003.

INTEREST EXPENSE

          Interest expense decreased $196,731 or 22% in 2003. The decrease was due to lower outstanding debt balances, and lower effective interest rates.

PROVISION FOR INCOME TAXES

          The provision for income taxes increased in 2003, due to a much larger income before taxes (as discussed above). The Company continued to be able to utilize tax credits from production of “tight gas sands” natural gas and excess percentage depletion on its oil and gas properties to reduce its tax liability, and its effective tax rate from the federal and state statutory rates. The effective tax rate was approximately 27% in 2003 and 2001 while a tax benefit was provided in 2002.

OVERVIEW

          The Company recorded a net income of $5,961,622 in 2003, compared to a net income of $343,059 in 2002. Total revenues were larger as a result of significantly increased oil and gas sales revenues generated by increases in the average sales prices of oil and natural gas in 2003 as compared to 2002.

LIQUIDITY AND CAPITAL RESOURCES

          At September 30, 2003, the Company had positive working capital of $1,335,344 as compared to negative working capital of $2,399,457 at September 30, 2002. The increase in working capital from September 30, 2002 to September 30, 2003, is the result of increased oil and gas sales revenues during 2003, which is discussed in Results of Operation above, and the reduction in the current portion of long-term debt by $2,000,000. This reduction in the current portion of long-term debt is the result of the restructuring of the Company’s bank debt in March 2003. The fixed monthly principal payment on the bank debt was reduced from $333,000 to $166,667. For a further discussion of the Company’s bank debt see Note 4: Long Term Debt of Notes to the Condensed Consolidated Financial Statements contained here-in. Cash flow from operating activities increased 76% to $13,198,368 for fiscal 2003, as compared to fiscal 2002, primarily due to a significant increase in product sales prices.

          Capital expenditures for oil and gas activities for 2003 amounted to $9,195,916, as compared to $6,967,767 for 2002, exclusive of $15,229,466 used to acquire Wood Oil Company.

          The Company has historically funded its capital expenditures, overhead costs and dividend payments from operating cash flow. Due to the increased capital expenditure level in 2003, the Company borrowed, early in the year, $1,525,000 on its revolving bank loan to help fund those expenditures. As a result of the increased cash flow from higher prices received for natural gas in the last three quarters of fiscal 2003, the Company made total principal payments of $4,878,335 on its bank debt. The Company has approximately $7.8 million available credit under the bank debt facility which is in place, for capital expenditures, acquisitions or any combination of uses. Further, the credit facility could be increased, if needed, for a large acquisition.

2002 Compared To 2001

REVENUES

Total revenues increased 6% to $13,591,397 in 2002, compared to $12,795,922 in 2001. The increase was a direct result of increased sales volumes for both oil and natural gas offset by dramatically reduced

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sales prices for both oil and natural gas, as outlined in the above table. The increased sales volume of both oil and natural gas is almost exclusively due to the addition of production from the Wood Oil acquisition properties. Wood Oil’s production volumes were 1,582,277 mcf (94% of the gas volume increase) and 74,294 barrels (100% of the oil volume increase). The reduction in average sales price was simply the result of world market conditions for crude oil and natural gas prices returning to more sustainable price levels from the ultra high prices of certain months in fiscal 2001.

LEASE OPERATING EXPENSES AND PRODUCTION TAXES (LOE)

          LOE increased $1,251,482 to $2,173,667 in 2002. 95% of the increase was due to LOE on the Wood acquisition properties. Gross production taxes are paid as a percentage of oil and gas sales revenues and thus fluctuate by increases in oil and gas sales revenues.

EXPLORATION COSTS

          Exploration costs declined 56% in 2002 as fewer exploratory wells were drilled in 2002, thus, reducing the chance of an exploratory well being a dry hole, which under the successful efforts accounting method are expensed as exploration costs.

DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)

          DD&A increased 250% in 2002 or $4,174,818. The majority of the increase, $3,099,085, was DD&A on the Wood acquisition properties. The DD&A on these properties was calculated using the fair value of the properties which was assigned in the purchase accounting done at the acquisition date. In addition, a full year of DD&A on many wells completed late in 2001 was recognized in 2002. Drilling and completion costs in fiscal 2001 were extremely high as drilling rigs and completion equipment enjoyed high utilization rates during the year. These high costs were thus being amortized in 2002.

PROVISION FOR IMPAIRMENT

          The provision for impairment of the Company’s oil and gas properties increased 32% or $267,699 in 2002. The increase is due again to the high costs of drilling and equipping wells in 2001 coupled with disappointing production volumes on several wells, resulting in impairment on those fields and several individual wells as those wells came on line in fiscal 2002.

GENERAL AND ADMINISTRATIVE COSTS (G&A)

          G&A increased $574,482 in 2002 or 34%. The majority of the increase was due to G&A associated with Wood Oil and the three employees retained from Wood. Additionally one other employee was hired during 2002 and personnel related expenses (including salaries, payroll taxes, insurance expense and ESOP expense) increased during the year.

INTEREST EXPENSE

          Interest expense increased by $895,218 in 2002. The increase is due to interest paid on the loan used to acquire Wood Oil. The acquisition was funded by a new $20,000,000 five-year term loan which requires monthly principal and interest payments. At September 30, 2002 the interest rate on the term loan was 4.5%.

PROVISION FOR INCOME TAXES

          The provision for income taxes decreased in 2002 due to a much lower income before taxes. The Company continues to be able to utilize tax credits from production of “tight gas sands” natural gas and excess percentage depletion on its oil and gas properties. The effective tax rate was approximately

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27% in 2001. The aggregate income tax benefit of $293,000 in 2002, was primarily a result of percentage depletion and “tight gas sands” credits reducing the expected federal income tax expense by approximately $279,000.

OVERVIEW

          The Company recorded a net income of $343,059 in 2002, compared to net income of $4,267,386 in 2001. This decrease was the result of lower oil and natural gas sales prices and increased LOE, DD&A, impairment, G&A and interest expense. The increased expenses, for the most part, were a result of the Wood Oil acquisition.

CRITICAL ACCOUNTING POLICIES

          Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change the Company’s reported cash flows or liquidity. Generally, accounting rules do not involve a selection among alternatives, but involve a selection of the appropriate policies for applying the basic principles. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to the Company.

          The more significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimation, impairment of assets and tax accruals. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

OIL AND GAS RESERVES

          Of these judgments and estimates, management considers the estimation of crude oil and natural gas reserves to be the most significant. Changes in crude oil and natural gas reserve estimates affect the Company’s calculation of depreciation and depletion, provision for abandonment and assessment of the need for asset impairments. The Company’s consulting engineer with assistance from Company geologists prepares estimates of crude oil and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. As required by the guidelines and definitions established by the Securities and Exchange Commission, these estimates are based on current crude oil and natural gas pricing. As previously discussed, crude oil and natural gas prices are volatile and largely affected by worldwide consumption and are outside the control of management. Projected future crude oil and natural gas pricing assumptions are used by management to prepare estimates of crude oil and natural gas reserves used in formulating managements overall operating decisions in the exploration and production segment.

SUCCESSFUL EFFORTS METHOD OF ACCOUNTING

          The Company has elected to utilize the successful efforts method of accounting for its oil and gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by field using the unit-of-production method as oil and gas is produced. The accounting method may yield significantly different operating results than the full cost method.

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IMPAIRMENT OF ASSETS

          All long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its future net cash flows. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil and gas, future costs to produce these products, estimates of future oil and gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or unfavorable adjustments to oil and gas reserves. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.

TAX ACCRUALS

          The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.

          The above description of the Company’s critical accounting policies is not intended to be an all-inclusive discussion of the uncertainties considered and estimates made by management in applying accounting principles and policies. Results may vary significantly if different policies were used or required and if new or different information becomes known to management.

ITEM 7 A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

          The Company’s results of operations and operating cash flows are impacted by changes in market prices for oil and gas. Operations and cash flows are also impacted by changes in the market interest rates related to the revolving credit facility which bears interest at an annual variable interest rate equal to the national prime rate minus -3/4% or LIBOR for one, three or six month periods, plus 1.8%. At September 30, 2003 a one percent change in the prime interest rate would result in approximately a $55,000 change in annual interest expense. The Company has a $10,000,000 term loan (remaining balance of $9,166,665 at September 30, 2003) which matures on April 1, 2008. The interest rate is fixed at 4.56% until maturity.

ITEM 8 FINANCIAL STATEMENTS

         
Report of Independent Auditors
    18  
Consolidated Balance Sheets
As of September 30, 2003 and 2002
    19-20  
Consolidated Statements of Income for the
Years Ended September 30, 2003, 2002 and 2001
    21  
Consolidated Statements of Stockholders’ Equity for
the Years Ended September 30, 2003, 2002 and 2001
    22  
Consolidated Statements of Cash Flows for
the Years Ended September 30, 2003, 2002 and 2001
    23-24  
Notes to Consolidated Financial Statements
    25-42  

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Report of Independent Auditors

Board of Directors and Stockholders
Panhandle Royalty Company

We have audited the accompanying consolidated balance sheets of Panhandle Royalty Company (the Company) as of September 30, 2003 and 2002, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Panhandle Royalty Company at September 30, 2003 and 2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2003, in conformity with accounting principles generally accepted in the United States.

Ernst & Young, LLP
Oklahoma City, Oklahoma
December 5, 2003

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Panhandle Royalty Company

Consolidated Balance Sheets

                     
        September 30
        2003   2002
       
 
Assets
               
Current assets:
               
 
Cash and cash equivalents
  $ 593,006     $ 242,836  
 
Oil and gas sales receivable
    3,989,877       2,533,249  
 
Prepaid expenses and other
    117,422       5,709  
 
   
     
 
Total current assets
    4,700,305       2,781,794  
Property and equipment at cost, based on successful efforts accounting:
               
   
Producing oil and gas properties
    65,342,062       58,697,095  
   
Nonproducing oil and gas properties
    9,610,757       9,754,336  
   
Furniture and fixtures
    405,514       360,784  
 
   
     
 
 
    75,358,333       68,812,215  
   
Less accumulated depreciation, depletion, and amortization
    31,685,848       27,860,713  
 
   
     
 
Net properties and equipment
    43,672,485       40,951,502  
Investment in partnerships, at equity
    782,587       856,607  
Other
    247,157       247,157  
 
   
     
 
Total assets
  $ 49,402,534     $ 44,837,060  
 
   
     
 

(Continued on next page.)

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Table of Contents

                     
        September 30
        2003   2002
       
 
Liabilities and Stockholders’ Equity
               
Current liabilities:
               
 
Accounts payable
  $ 552,201     $ 653,758  
 
Accrued liabilities:
               
   
Deferred compensation
    519,783       321,555  
   
Interest
    40,213       66,567  
   
Other
    121,972       133,308  
 
Income taxes payable
    130,788       10,063  
 
Long-term debt due within one year
    2,000,004       3,996,000  
 
   
     
 
Total current liabilities
    3,364,961       5,181,251  
Long-term debt
    12,666,661       14,024,000  
Deferred income taxes
    10,315,000       8,639,000  
Asset retirement obligation and other noncurrent liabilities
    528,227       39,515  
Stockholders’ equity:
               
 
Class A voting common stock, $.0333 par value; 6,000,000 shares authorized, 2,089,101 issued and outstanding (2,079,423 in 2002)
    69,637       69,314  
 
Capital in excess of par value
    1,091,886       896,643  
 
Retained earnings
    21,366,162       15,987,337  
 
   
     
 
Total stockholders’ equity
    22,527,685       16,953,294  
 
   
     
 
Total liabilities and stockholders’ equity
  $ 49,402,534     $ 44,837,060  
 
   
     
 

See accompanying notes.

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Table of Contents

Panhandle Royalty Company

Consolidated Statements of Income

                           
      Year ended September 30
      2003   2002   2001
     
 
 
Revenues:
                       
 
Oil and gas sales
  $ 22,098,198     $ 13,080,754     $ 12,546,055  
 
Lease bonuses and rentals
    72,765       41,497       17,991  
 
Interest
    13,580       36,743       47,141  
 
Income from partnerships and other
    271,495       432,403       184,735  
 
   
     
     
 
 
    22,456,038       13,591,397       12,795,922  
Costs and expenses:
                       
 
Lease operating expenses and production taxes
    4,013,572       3,001,449       1,771,789  
 
Exploration costs
    469,224       417,971       947,046  
 
Depreciation, depletion, and amortization
    5,783,457       5,845,779       1,670,961  
 
Provision for impairment
    692,220       1,116,234       848,535  
 
General and administrative
    2,666,177       2,263,908       1,689,426  
 
Interest expense
    699,266       895,997       779  
 
   
     
     
 
 
    14,323,916       13,541,338       6,928,536  
 
   
     
     
 
Income before provision for income taxes and cumulative effect of accounting change
    8,132,122       50,059       5,867,386  
Provision (benefit) for income taxes
    2,217,000       (293,000 )     1,600,000  
 
   
     
     
 
Net income before cumulative effect of accounting change
    5,915,122       343,059       4,267,386  
 
   
     
     
 
Cumulative effect of accounting changes, net of taxes of $28,500
    46,500              
 
   
     
     
 
Net income
  $ 5,961,622     $ 343,059     $ 4,267,386  
 
   
     
     
 
Basic earnings per common share
Income before cumulative effect of accounting change
  $ 2.84     $ .17     $ 2.07  
Cumulative effect of accounting change
    .02              
 
   
     
     
 
Net income
  $ 2.86     $ .17     $ 2.07  
 
   
     
     
 
Diluted earnings per common share
Income before cumulative effect of accounting change
  $ 2.81     $ .16     $ 2.05  
Cumulative effect of accounting change
    .02              
 
   
     
     
 
Net income
  $ 2.83     $ .16     $ 2.05  
 
   
     
     
 

See accompanying notes.

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Table of Contents

Panhandle Royalty Company

Consolidated Statements of Stockholders’ Equity

                                         
    Common Stock   Capital in          
   
  Excess of   Retained        
    Shares   Amount   Par Value   Earnings   Total
   
 
 
 
 
Balances at September 30, 2001
    2,066,441     $ 68,881     $ 702,948     $ 16,223,221     $ 16,995,050  
Purchases and cancellation of common shares
    (291 )     (10 )     (4,100 )           (4,110 )
Issuance of common shares to ESOP
    8,157       272       118,412             118,684  
Issuance of common shares to directors for services
    5,116       171       79,383             79,554  
Dividends declared ($.28 per share)
                      (578,943 )     (578,943 )
Net income
                      343,059       343,059  
 
   
     
     
     
     
 
Balances at September 30, 2002
    2,079,423       69,314       896,643       15,987,337       16,953,294  
Purchases and cancellation of common shares
    (54 )     (2 )     (776 )           (778 )
Issuance of common shares to ESOP
    6,642       222       152,676             152,898  
Issuance of common shares to directors for services
    3,090       103       43,343             43,446  
Dividends declared ($.28 per share)
                      (582,797 )     (582,797 )
Net income
                      5,961,622       5,961,622  
 
   
     
     
     
     
 
Balances at September 30, 2003
    2,089,101     $ 69,637     $ 1,091,886     $ 21,366,162     $ 22,527,685  
 
   
     
     
     
     
 

See accompanying notes.

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Table of Contents

Panhandle Royalty Company

Consolidated Statements of Cash Flows

                             
        Year ended September 30
        2003   2002   2001
       
 
 
Operating Activities
                       
Net income
  $ 5,961,622     $ 343,059     $ 4,267,386  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
 
Cumulative effect of accounting change
    (46,500 )            
 
Depreciation, depletion, amortization, and impairment
    6,475,677       6,962,013       2,519,496  
 
Deferred income taxes
    1,676,000       (453,000 )     1,444,000  
 
Deferred lease bonus
    67,673       8,744       30,771  
 
Exploration costs
    469,224       417,971       947,046  
 
Gain on sale of assets
    (38,378 )     (179,037 )      
 
Equity in earnings of partnerships
    (133,836 )     (77,015 )      
 
Common stock issued to Employee Stock Ownership Plan
    152,898       118,684       96,736  
 
Cash provided (used) by changes in assets and liabilities, net of amounts acquired in Wood Oil acquisition:
                       
   
Oil and gas sales receivables
    (1,456,628 )     191,908       389,052  
   
Prepaid expenses and other
    (111,713 )     655,501       (294,872 )
   
Accounts payable and accrued liabilities
    61,604       (517,696 )     152,677  
   
Income taxes payable
    120,725       10,063       (249,327 )
 
   
     
     
 
Total adjustments
    7,236,746       7,138,136       5,035,579  
 
   
     
     
 
Net cash provided by operating activities
    13,198,368       7,481,195       9,302,965  
Investing Activities
                       
Capital expenditures, including dry hole costs
    (9,195,916 )     (6,967,767 )     (9,486,994 )
Acquisition of Wood, net of cash acquired
          (15,229,466 )      
Distributions received from partnerships
    252,856       191,685        
Investment in partnerships
    (45,000 )     (90,000 )      
Proceeds from sale of assets
    76,772       1,371,272        
Escrow deposit and payments related to Wood Oil acquisition
                (3,860,027 )
 
   
     
     
 
Net cash used in investing activities
    (8,911,288 )     (20,724,276 )     (13,347,021 )

Continued on next page.

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Table of Contents

Panhandle Royalty Company

Consolidated Statements of Cash Flows (continued)

                         
    Year ended September 30
    2003   2002   2001
   
 
 
Financing Activities
                       
Borrowings under debt agreement
  $ 1,525,000     $ 18,100,000     $ 4,050,000  
Payments of loan principal
    (4,878,335 )     (4,130,000 )      
Purchase and cancellation of common shares
    (778 )     (4,110 )     (1,860 )
Payments of dividends
    (582,797 )     (578,943 )     (721,026 )
 
   
     
     
 
Net cash provided by (used in) financing activities
    (3,936,910 )     13,386,947       3,327,114  
 
   
     
     
 
Increase (decrease) in cash and cash equivalents
    350,170       143,866       (716,942 )
Cash and cash equivalents at beginning of year
    242,836       98,970       815,912  
 
   
     
     
 
Cash and cash equivalents at end of year
  $ 593,006     $ 242,836     $ 98,970  
 
   
     
     
 
Supplemental Disclosures of Cash Flow Information
                       
Interest paid
  $ 727,153     $ 829,430     $ 36,798  
Income taxes paid, net of refunds received
    456,338       (215,687 )     699,464  

See accompanying notes.

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements

September 30, 2003, 2002 and 2001

1. Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Panhandle Royalty Company and its wholly owned subsidiaries after elimination of all material intercompany transactions.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.

Oil and Gas Sales and Gas Imbalances

The Company sells oil and natural gas to various customers, recognizing revenues as oil and gas is produced and sold. The Company uses the sales method of accounting for gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a reservoir cannot be recouped through the production of remaining reserves. At September 30, 2003 and 2002, the Company had no material gas imbalances.

Charges for gathering and transportation are included in lease operating expenses and production taxes.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers of oil and natural gas or operators of the oil and gas properties. Oil and natural gas sales are generally unsecured. The Company has not experienced significant credit losses in prior years and is not aware of any significant uncollectible accounts at September 30, 2003.

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

1. Summary of Significant Accounting Policies (continued)

Oil and Gas Producing Activities

The Company follows the successful efforts method of accounting for oil and gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income if and when the well is determined to be nonproductive. Oil and gas mineral and leasehold costs are capitalized when incurred.

Depreciation, Depletion, Amortization, and Impairment

Depreciation, depletion, and amortization of the costs of producing oil and gas properties are generally computed using the units of production method primarily on a separate property basis using proved reserves as estimated annually by an independent petroleum engineer. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.

Nonproducing oil and gas properties include nonproducing minerals, which have a net book value of $6,930,687 at September 30, 2003, consisting of perpetual ownership of mineral interests in several states, including Oklahoma, Texas and New Mexico. These costs are being amortized over a thirty-three year period using the straight-line method. An ultimate determination of whether these properties contain recoverable reserves in economical quantities is expected to be made within this time frame. Impairment of nonproducing oil and gas properties is recognized based on experience and management judgment.

In accordance with the provisions of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows. The Company’s oil and gas properties were reviewed for indicators of impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $692,220, $1,116,234, and $848,535, respectively, for 2003, 2002 and 2001. The majority of the impairment recognized in these years relates to fields comprised of a small number of properties or single wells on which the Company does not expect sufficient future net cash flow to recover its carrying cost.

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

1. Summary of Significant Accounting Policies (continued)

Asset Retirement Obligations

In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method and the liability should be accreted to its face amount. The Company adopted SFAS No. 143 on October 1, 2002. The primary impact of this standard relates to oil and gas wells on which the Company has a legal obligation to plug and abandon the wells. Prior to SFAS No. 143, Company had not recorded an obligation for these plugging and abandonment costs due to its assumption that the salvage value of the surface equipment would offset the cost of dismantling the facilities and carrying out the necessary clean-up and reclamation activities. The adoption of SFAS No. 143 on October 1, 2002 resulted in a net increase to Property and Equipment and Asset Retirement Obligations of approximately $481,000 and $406,000, respectively, as a result of the Company separately accounting for salvage values and recording the estimated fair value of its plugging and abandonment obligations on the balance sheet. The increase in expense resulting from the accretion of the asset retirement obligation and the depreciation of the additional capitalized well costs was substantially offset by the decrease in depreciation from the Company’s consideration of the estimated salvage values in the calculation.

Environmental Costs

Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2003, there were no such costs accrued.

Earnings Per Share of Common Stock

Basic earnings per share (EPS) is calculated using net income divided by the weighted average of common shares outstanding during the year. Diluted EPS is similar to basic EPS except that the weighted average common shares outstanding is increased to include the number of additional common shares that would have been outstanding if the dilutive potential common shares had been issued. The treasury stock method is used to calculate dilutive shares, which reduces the gross number of dilutive shares (see Note 5).

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

1. Summary of Significant Accounting Policies (continued)

Stock-based Compensation

The Company applies APB Opinion No. 25 in accounting for its Deferred Compensation Plan for Outside Directors. Under APB No. 25, compensation cost is recognized for changes in the fair value of the stock credited to each director’s account at the fair market value of the stock at the date of grant. The shares are then adjusted for changes in the shares market value subsequent to the date of grant until the conversion date (see Note 7).

Fair Values of Financial Instruments

The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, prepaid expenses, accounts payable, and accrued liabilities approximate their fair values due to the short maturity of these instruments. The fair value of Company’s long-term debt approximates its carrying amount due to the interest rate on the Company’s term-loan being a fixed rate which approximated market rates at September 30, 2003, the remaining borrowings bear interest at a variable rate.

Recently Issued Accounting Pronouncements

In June 2002, FASB issued SFAS 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity. The pronouncement is effective for exit or disposal activities initiated after December 31, 2002. The adoption of SFAS 146 had no material impact on the Company’s financial position or results of operations and is currently expected to in the near term.

In April 2003, the FASB issued FAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This Statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement is effective for contracts entered into or modified after June 30, 2003. Adoption of this Statement had no impact on the financial position or results of operation of the Company and is currently not expected to in the near term.

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

1. Summary of Significant Accounting Policies (continued)

In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS 150 establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Under SFAS 150, mandatorily redeemable financial instruments, obligations to repurchase the issuer’s shares by transferring assets and certain obligations to issue a variable number of shares to settle that obligation must be classified as liabilities on the balance sheet and initially recorded at fair value. SFAS 150 is effective for the Company for financial instruments entered into or modified after May 31, 2003, and on July 1, 2003 for most previously existing financial instruments. In November 2003, the FASB voted to defer indefinitely the effective date for certain mandatorily redeemable non-controlling interests (MRNI) associated with finite-lived subsidiaries. For all other MRNIs, the effective date was deferred to November 5, 2003. The adoption of SFAS 150 did not impact our financial position, results of operations or net cash flows as the Company currently does not use any of the financial instruments subject to this statement.

In November 2002, the FASB issued FASB Interpretation (FIN) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45 clarifies the requirements of SFAS 5, Accounting For Obligations, relating to a guarantor’s accounting for, and disclosure of the issuance of certain types of guarantees. The adoption of FIN 45 did not impact the Company’s financial position, results of operations or net cash flows as the Company currently does not have any guarantees.

In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when and which business enterprises should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. FIN 46 applies immediately to VIEs created after January 31, 2003 or to VIEs obtained after that date. For variable interests held in VIEs acquired prior to February 1, 2003, FIN 46 was originally effective July 1, 2003. However, in October 2003, the FASB deferred the effective date of FIN 46 for VIEs created prior to February 1, 2003 to the first reporting period after December 15, 2003. The adoption of this interpretation is not

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

1. Summary of Significant Accounting Policies (continued)

anticipated to have a material impact on the Company’s financial position, results of operations or net cash flows because the Company currently is not a primary beneficiary of a VIE.

2. Acquisition of Wood Oil Company

On October 1, 2001, the Company acquired 100% of the outstanding common stock of Wood Oil Company (Wood). The acquisition was made pursuant to an Agreement and Plan of Merger among the Company, PHC, Inc. and Wood Oil Company, dated August 9, 2001. Wood merged with Panhandle’s wholly owned subsidiary PHC, Inc., on October 1, 2001, with Wood being the surviving Company. Prior to the acquisition, Wood was a privately held company engaged in oil and gas exploration and production and fee mineral ownership and owned interests in certain oil and gas and real estate partnerships and owned an office building in Tulsa, Oklahoma. Subsequent to the acquisition, Wood has continued to operate as a subsidiary of Panhandle and personnel were moved to Oklahoma City in early 2002. Wood and its shareholders were unrelated parties to Panhandle.

The Company’s decision to acquire Wood was the result of desired growth in the Company’s asset base of producing oil and gas reserves and fee mineral acreage. Wood’s oil and gas activity, fee minerals and operating philosophy, in general, had been very similar to the Company’s.

Wood’s mineral acreage ownership and leasehold position as well as its producing oil and gas properties are located in the same general areas as the Company’s. In several cases, both companies owned interests in existing producing wells and several developing fields. The Company intends to actively pursue drilling opportunities on Wood’s properties.

Funding for the acquisition was obtained from Banc First of Oklahoma City, Oklahoma in the form of a $20 million five-year term loan. Three million of Wood’s cash was used to reduce Panhandle’s debt on the date of closing.

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

2. Acquisition of Wood Oil Company (continued)

The operations of Wood, since October 1, 2001, are included in the accompanying consolidated financial statements.

The following table sets forth the allocation of the purchase price to the assets and liabilities acquired:

           
Cash
  $ 3,759,000  
Other current assets
    1,260,000  
Land and buildings held for sale
    750,000  
Oil and gas properties – proved
    17,550,000  
Minerals:
       
 
Producing
    925,000  
 
Nonproducing
    3,491,000  
Other property and equipment
    43,000  
Investments in partnerships and other assets
    1,731,000  
 
   
 
Total assets acquired
    29,509,000  
Current liabilities
    (853,000 )
Deferred income taxes
    (5,808,000 )
 
   
 
Total liabilities assumed
    (6,661,000 )
 
   
 
Net assets acquired
  $ 22,848,000  
 
   
 

In April 2002, the Company sold the land and building and its interest in two partnerships resulting in net proceeds of approximately $1.4 million of which $800,000 were used to pay down long term debt. Other revenues in the accompanying consolidated income statement include a gain of $56,487 on the sale of the building and a gain of $122,550 on the sale of the two partnerships.

The following unaudited proforma results of operations give effect to the acquisition as if consummated on October 1, 2000. The data reflects adjustments of the historical Wood results for depreciation and amortization of the property and equipment acquired, adjustments of expenses resulting from contractual requirements of the acquisition agreement, incremental interest expense relating to bank borrowing used to finance the purchase and income taxes. Total revenues for 2001 include non-recurring gains on asset sales of $2.1 million. The pro forma adjustments are based upon available information and assumptions that management of the Company believes are reasonable. The pro forma results of operations data does

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

2. Acquisition of Wood Oil Company (continued)

not purport to represent the results of operations that would have occurred had such transaction been consummated on October 1, 2000 or the Company’s results of operation for any future date or period.

         
    Year ended
    September 30,
    2001
   
Total revenues
  $ 25,234,054  
Net income
  $ 8,927,780  
Diluted earnings per share
  $ 4.27  

3. Income Taxes

The Company’s provision for income taxes is detailed as follows:

                           
      2003   2002   2001
     
 
 
Current:
                       
 
Federal
  $ 521,000     $ 150,000     $ 160,000  
 
State
    20,000       10,000       (4,000 )
 
 
   
     
     
 
 
    541,000       160,000       156,000  
Deferred:
                       
 
Federal
    1,607,000       (390,000 )     1,232,000  
 
State
    69,000       (63,000 )     212,000  
 
 
   
     
     
 
 
    1,676,000       (453,000 )     1,444,000  
 
 
   
     
     
 
 
  $ 2,217,000     $ (293,000 )   $ 1,600,000  
 
 
   
     
     
 

The difference between the provision for income taxes and the amount which would result from the application of the federal statutory rate to income before provision for income taxes is analyzed below:

                         
    2003   2002   2001
   
 
 
Provision for income taxes at statutory rate
  $ 2,762,324     $ 17,521     $ 2,053,587  
Percentage depletion
    (653,947 )     (201,600 )     (559,668 )
Tight-sands gas credits
    (20,000 )     (77,404 )     (47,114 )
State income taxes, net of federal benefit
    57,850       (34,419 )     141,099  
Other
    70,773       2,902       12,096  
 
   
     
     
 
 
  $ 2,217,000     $ (293,000 )   $ 1,600,000  
 
   
     
     
 

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

3. Income Taxes (continued)

Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax bases of assets and liabilities, consist of the following:

                   
      2003   2002
     
 
Deferred tax liabilities:
               
 
Financial bases in excess of tax bases, including intangible drilling costs capitalized for financial purposes and expensed for tax purposes
  $ 11,744,000     $ 11,210,000  
Deferred tax assets:
               
 
Percentage depletion and alternative minimum tax credit carry forwards
    991,000       1,950,000  
 
Financial charges which are deferred for tax purposes
    438,000       621,000  
 
 
   
     
 
 
    1,429,000       2,571,000  
 
 
   
     
 
Net deferred tax liabilities
  $ 10,315,000     $ 8,639,000  
 
 
   
     
 

4. Long-Term Debt

Long-term debt consisted of the following at September 30:

                 
    2003   2002
   
 
Revolving line of credit
  $ 5,500,000     $ 1,350,000  
Term loan
    9,166,665       16,670,000  
 
   
     
 
 
    14,666,665       18,020,000  
Current maturities of long-term debt
    2,000,004       3,996,000  
 
   
     
 
 
  $ 12,666,661     $ 14,024,000  
 
   
     
 

On March 25, 2003, the Company amended its Loan Agreement with BancFirst of Oklahoma City, Oklahoma. The Agreement consists of a term loan in the amount of $10,000,000 and a revolving loan in the amount of $15,000,000, which is subject to a semi-annual borrowing base determination. The current borrowing base under the

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

4. Long-Term Debt (continued)

Agreement is $22,500,000. The term loan matures on April 1, 2008, and the revolving loan matures on April 1, 2005. Monthly payments on the term loan are $166,667, plus accrued interest, beginning on May 1, 2003. Borrowings under the revolving loan are due at maturity. Interest on the term loan is fixed at 4.56% until maturity. The revolving loan bears interest at the national prime rate minus -3/4% (3.25% at September 30, 2003) or LIBOR (for one, three or six month periods), plus 1.80%. The Company, at September 30, 2003, has elected a six month LIBOR rate (aggregate of 2.98%).

The total outstanding borrowings under both the term loan and the revolving line of credit may not exceed the borrowing base which is $22.5 million as of September 30, 2003. Subsequent determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2003 the Company was in compliance with the covenants. Certain of the Company’s oil and gas properties secure the debt.

The amount of required principal payments for the next five years as of September 30, 2003, are as follows: 2004 – $2,000,004, 2005 – $7,500,004, 2006 - $2,000,004, 2007 – $2,000,004 and 2008 – $1,166,649.

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

5. Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share. The Company’s diluted earnings per share calculation takes into account certain shares that may be issued under the Non-Employee Directors’ Deferred Compensation Plan (see Note 7).

                             
        Year ended September 30,
        2003   2002   2001
       
 
 
Numerator for primary and diluted earnings per share:
                       
 
Net income
  $ 5,961,622     $ 343,059     $ 4,267,386  
 
   
     
     
 
Denominator:
                       
 
For basic earnings per share—weighted average shares
    2,081,372       2,067,872       2,060,109  
 
Effect of potential diluted shares:
                       
   
Directors’ deferred compensation shares
    22,341       22,100       24,935  
 
 
   
     
     
 
Denominator for diluted earnings per share—adjusted weighted average shares and potential shares
    2,103,713       2,089,972       2,085,044  
 
 
   
     
     
 

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

6. Employee Stock Ownership Plan

The Company has an employee stock ownership plan that covers substantially all employees and is established to provide such employees with a retirement benefit. These benefits become fully vested after three years of employment. Contributions to the plan are at the discretion of the Board of Directors and can be made in cash (none in 2003, 2002 or 2001) or the Company’s common stock. For contributions of common stock, the Company records as expense, the fair market value of the stock at the time of contribution. The 129,904 shares of the Company’s common stock held by the plan as of September 30, 2003, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings per share computations and receive dividends. Contributions to the plan consisted of:

                 
Year   Shares   Amount

 
 
2003
    6,911     $ 156,978  
2002
    8,157     $ 118,684  
2001
    6,381     $ 96,736  

7. Deferred Compensation Plan for Directors

Effective November 1, 1994, the Company formed the Panhandle Royalty Company Deferred Compensation Plan for Non-Employee Directors (the Plan). The Plan provides that each eligible director can individually elect to receive shares of Company stock rather than cash for board meeting fees and board committee meeting fees. These shares are unissued and vest at the date of grant. The shares are credited to each director’s deferred fee account at the fair market value of the stock at the date of grant and are adjusted for changes in market value subsequent thereto. Upon retirement, termination or death of the director, or upon change in control of the Company, the shares accrued under the Plan will be either issued to the director or may be converted to cash, at the director’s discretion, for the fair market value of the shares on the conversion date as defined by the Plan. As of September 30, 2003, 22,908 shares (22,100 shares at September 30, 2002) are included in the Plan. The Company has accrued $519,783 at September 30, 2003 ($321,555 at September 30, 2002) in connection with the Plan ($241,673, $23,095, and $70,570 was charged to the results of operations for the years ended September 30, 2003, 2002 and 2001, respectively, and is included in general and administrative expense in the accompanying income statement).

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

8. Information on Oil and Gas Producing Activities

All oil and gas producing activities of the Company are conducted within the United States (principally in Oklahoma) and represent substantially all of the business activities of the Company.

During 2003, 2002 and 2001 approximately 14%, 17%, and 23%, respectively, of the Company’s total revenues were derived from gas sales to ONEOK, Inc. The Company also has interests in a field of properties, the production on which accounted for approximately 9%, 12%, and 15% of the Company’s revenues in 2003, 2002 and 2001, respectively.

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil and gas properties and related accumulated depreciation, depletion, and amortization as of September 30 is as follows:

                 
    2003   2002
   
 
Producing properties
  $ 65,342,062     $ 58,697,095  
Nonproducing properties
    9,610,757       9,754,336  
 
   
     
 
 
    74,952,819       68,451,431  
Accumulated depreciation, depletion and amortization
    (31,386,538 )     (27,583,242 )
 
   
     
 
Net capitalized costs
  $ 43,566,281     $ 40,868,189  
 
   
     
 

Costs Incurred

During the reporting period, the Company incurred the following costs in oil and gas producing activities:

                         
    2003   2002   2001
   
 
 
Property acquisition costs (A)
  $ 127,058     $ 219,306     $ 194,645  
Exploration costs
    1,412,653       1,080,951       3,839,009  
Development costs
    7,818,988       5,637,430       5,447,423  
 
   
     
     
 
 
  $ 9,358,699     $ 6,937,687     $ 9,481,077  
 
   
     
     
 

(A)   Excludes Wood Oil acquisition in 2002 as set forth in Note 2, the cost of which, net of cash acquired, was $15,229,466.

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

9. Supplementary Information on Oil and Gas Reserves (Unaudited)

The following unaudited information regarding the Company’s oil and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission (SEC) and SFAS No. 69, Disclosures About Oil and Gas Producing Activities.

Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Because the Company’s nonproducing mineral and leasehold interests consist of various small interests in numerous tracts located primarily in Oklahoma, New Mexico, and Texas, it is not economically feasible for the Company to provide estimates of all proved undeveloped reserves. The Company directs its independent petroleum engineering firm to include proved undeveloped reserves in certain areas of Oklahoma and New Mexico in the scope of properties which are evaluated for the Company.

The Company’s net proved (including certain undeveloped reserves described above) oil and gas reserves, all of which are located in the United States, as of September 30, 2003, 2002 and 2001, have been estimated by Campbell & Associates, Inc., an independent petroleum engineering firm. All studies have been prepared in accordance with regulations prescribed by the Securities and Exchange Commission. The reserve estimates were based on economic and operating conditions existing at September 30, 2003, 2002 and 2001. Since the determination and valuation of proved reserves is a function of testing and estimation, the reserves presented should be expected to change as future information becomes available.

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

9. Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)

Estimated Quantities of Proved Oil and Gas Reserves

Net quantities of proved, developed, and undeveloped oil and gas reserves are summarized as follows:

                 
    Proved Reserves
   
    Oil   Gas
    (Mbarrels)   (Mmcf)
   
 
September 30, 2000
    660       14,389  
Revisions of previous estimates
    (47 )     (2,178 )
Extensions and discoveries
    132       7,685  
Production
    (69 )     (2,208 )
 
   
     
 
September 30, 2001
    676       17,688  
Revisions of previous estimates
    (38 )     745  
Purchases of reserves in place
    487       8,519  
Extensions and discoveries
    123       5,061  
Production
    (133 )     (3,897 )
 
   
     
 
September 30, 2002
    1,115       28,116  
Revisions of previous estimates (1)
    (289 )     (1,953 )
Extensions and discoveries
    123       6,033  
Production
    (113 )     (3,926 )
 
   
     
 
September 30, 2003
    836       28,270  
 
   
     
 

(1)   Revisions of oil reserves and some associated gas reserves were principally a result of changes in reserves associated with properties in the Dagger Draw Field of New Mexico, which will be converted to a waterflood in 2004. Gas reserve revisions resulted from properties which were drilled in the prior year and now have actual performance to guide the projections, rather than the limited data available in the first few months a property comes on production.

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

9. Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)

                                 
    Proved Developed Reserves   Proved Undeveloped Reserves
   
 
    Oil   Gas   Oil   Gas
    (Mbarrels)   (Mmcf)   (Mbarrels)   (Mmcf)
   
 
 
 
September 30, 2000
    409       11,585       251       2,804  
 
   
     
     
     
 
September 30, 2001
    413       13,236       263       4,452  
 
   
     
     
     
 
September 30, 2002
    821       22,896       294       5,220  
 
   
     
     
     
 
September 30, 2003
    703       23,600       133       4,670  
 
   
     
     
     
 

The above reserve numbers are net of approximately 1.2 mmcf of CO2 gas reserves owned by Wood Oil Company.

Standardized Measure of Discounted Future Net Cash Flows

Estimates of future cash flows from proved oil and gas reserves, based on current prices and costs, as of September 30 are shown in the following table. Estimated income taxes are calculated by (i) applying the appropriate year-end tax rates to the estimated future pretax net cash flows less depreciation of the tax basis of properties and statutory depletion allowances and (ii) reducing the amount in (i) for estimated tax credits to be realized in the future for gas produced from “tight-sands” through December 31, 2002.

                         
    2003   2002   2001
   
 
 
Future cash inflows
  $ 148,633,837     $ 123,668,010     $ 48,294,240  
Future production costs
    29,036,188       25,022,170       9,355,230  
Future development costs
    3,856,341       3,991,185       2,999,402  
 
   
     
     
 
Future net cash inflows before future income tax expenses
    115,741,308       94,654,655       35,939,608  
Future income tax expense
    31,736,989       25,831,291       9,381,868  
 
   
     
     
 
Future net cash flows
    84,004,319       68,823,364       26,557,740  
10% annual discount
    30,034,435       24,878,417       8,927,795  
 
   
     
     
 
Standardized measure of discounted future net cash flows
  $ 53,969,884     $ 43,944,947     $ 17,629,945  
 
   
     
     
 

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

9. Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)

Changes in the standardized measure of discounted future net cash flows are as follows:

                           
      2003   2002   2001
     
 
 
Beginning of year
  $ 43,944,947     $ 17,629,945     $ 30,861,314  
Changes resulting from:
                       
 
Sales of oil and gas, net of production costs
    (18,084,626 )     (10,079,305 )     (10,774,266 )
 
Net change in sales prices and production costs
    20,300,852       15,794,503       (17,851,098 )
 
Net change in future development costs
    87,405       (665,685 )     (1,154,469 )
 
Extensions and discoveries
    15,315,189       10,313,163       10,190,264  
 
Revisions of quantity estimates
    (8,291,358 )     885,028       (2,981,154 )
 
Purchases of reserves-in-place
          19,370,609        
 
Accretion of discount
    6,135,420       2,412,266       4,295,702  
 
Net change in income taxes
    (4,134,614 )     (10,933,161 )     6,185,986  
 
Change in timing and other, net
    (1,303,331 )     (782,416 )     (1,142,334 )
 
   
     
     
 
Net change
    10,024,937       26,315,002       (13,231,369 )
 
   
     
     
 
End of year
  $ 53,969,884     $ 43,944,947     $ 17,629,945  
 
   
     
     
 

10. Quarterly Results of Operations (Unaudited)

The following is a summary of the Company’s unaudited quarterly results of operations.

                                 
    Fiscal 2003
   
    Quarter Ended
   
    December 31   March 31   June 30   September 30
   
 
 
 
Revenues
  $ 4,463,748     $ 6,980,939     $ 5,662,139     $ 5,349,212  
Income before provision for income taxes and cumulative effect of accounting change
    829,981       3,323,674       2,193,583       1,777,244  
Income before cumulative effect of accounting change
    604,981       2,320,674       1,538,583       1,443,244  
Net income
    651,481       2,320,674       1,538,583       1,450,884  
Basic earnings per share
  $ .31     $ 1.12     $ .74     $ .69  
Diluted earnings per share
  $ .31     $ 1.10     $ .73     $ .69  

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Table of Contents

Panhandle Royalty Company

Notes to Consolidated Financial Statements (continued)

10. Quarterly Results of Operations (Unaudited) (continued)

                                 
    Fiscal 2002
   
    Quarter Ended
   
    December 31   March 31   June 30   September 30
   
 
 
 
Revenues
  $ 3,330,561     $ 2,745,824     $ 3,792,994     $ 3,722,018  
Income (loss) before provision for income taxes
    (102,237 )     (397,025 )     623,684       (74,363 )
Net income (loss) (A)
    (76,856 )     (287,123 )     453,684       253,354  
Basic earnings (loss) per share
  $ (.04 )   $ (.14 )   $ .22     $ .13  
Diluted earnings (loss) per share
  $ (.04 )   $ (.14 )   $ .22     $ .12  

(A)   The quarter ended September 30, 2002, reflects a change in estimate associated with the Company’s income tax provision resulting from the determination of actual percentage depletion and tight sands gas credits available to reduce the Company’s taxable income.

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Table of Contents

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

N O N E

ITEM 9 A CONTROLS AND PROCEDURES

     Panhandle Royalty Company management, under the supervision of and with the participation of the Chief Executive Officer and Chief Financial Officer have conducted an evaluation of the effectiveness of disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in insuring that all material information required to be filed in this annual report has been made known to them in a timely fashion. There have been no significant changes in our internal controls or in factors that could significantly affect internal controls, subsequent to the date the Chief Executive Officer and Chief Financial Officer completed their evaluation.

     In accordance with General Instruction G (3) to Form 10-K, Part III, Items 10.-14. of this Report are omitted because the Company will file with the Securities and Exchange Commission not later than 120 days after the end of the fiscal year ended September 30, 2003, a definitive proxy statement pursuant to Regulation 14A involving the election of directors, which proxy statement is incorporated herein by reference.

PART III

ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

  (3)   Amended Certificate of Incorporation (Incorporated by reference to Exhibit attached to Form 10 filed January 27, 1980, and to Forms 8-K dated June 1, 1982, December 3, 1982 and to Form 10-QSB dated March 31, 1999).
 
      By-Laws as amended (Incorporated by reference to Form 8-K dated October 31, 1994)
 
  (4)   Instruments defining the rights of security holders (Incorporated by reference to Certificate of Incorporation and By-Laws listed above)
 
  (10)   Amendment to Loan Agreement
  (10)   Agreement indemnifying directors and officers (Incorporated by reference to Form 10-K dated September 30, 1989)
 
  (21)   Subsidiaries of the Registrant
 
  (31.1)   Certification of Chief Executive Officer
 
  (31.2)   Certification of Chief Financial Officer
 
  (32.1)   Certification of Chief Executive Officer
 
  (32.2)   Certification of Chief Financial Officer

     REPORTS ON FORM 8-K

     Form 8-K dated August 13, 2003, Regulation FD disclosure of Company’s earnings release for the third quarter of fiscal 2003.

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Table of Contents

SIGNATURES

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

         
    PANHANDLE ROYALTY COMPANY
         
    By:        /s/ H W Peace II
       
        H W Peace II, Chief
        Executive Officer,
        President, Director
        (Principal Executive Officer)
         
    Date: December 18, 2002

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

     
/s/ Jerry L. Smith   /s/ E. Chris Kauffman

 
Jerry L. Smith, Chairman of Board   E. Chris Kauffman, Director
     
Date December 17, 2003   Date December 17, 2003
     
/s/ Robert A. Reece   /s/ Michael A. Cawley

 
Robert A. Reece, Director   Michael A. Cawley, Director
     
Date December 17, 2003   Date December 17, 2003
     
/s/ H. Grant Swartzwelder   /s/ Ben D. Hare

 
H. Grant Swartzwelder, Director   Ben D. Hare, Director
     
Date December 17, 2003   Date December 17, 2003
     
/s/ Robert O. Lorenz   /s/ Michael C. Coffman

 
Robert O. Lorenz, Director   Michael C. Coffman, Vice President
    Treasurer and Secretary (Principal Financial and
Date December 17, 2003   Accounting Officer)
     
    Date December 17, 2003

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