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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

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

Commission File Number: 0-9116

PANHANDLE ROYALTY COMPANY

Registrant’s telephone number (405) 948-1560

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

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

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.

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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

(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

     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.

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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

10% Discounted Present Value of Estimated Future Net Cash Flows

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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.

     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.

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

	(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.

     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.

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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.

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:

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

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

     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.

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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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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

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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