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

Grand Centre, Suite 305, 5400 North Grand Blvd., Oklahoma City, OK 73112

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:
          (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 12b-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, 2004, was $64,613,932. As of December 3, 2004, 4,189,783 shares of Class A Common stock were outstanding.

Documents Incorporated By Reference

The information required by Part III of this Report, to the extent not set forth herein, is incorporated by reference from the registrant’s definitive proxy statement relating to the annual meeting of stockholders to be held in February 2005, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Report relates.

TABLE OF CONTENTS

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 2001-2005 refer to the Company’s fiscal years ended September 30, each year.

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. In February 2004, the Company’s shareholders voted to increase the authorized Class A Common Stock of the Company to 12,000,000 shares and to split the shares on a two for one basis.

     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 305, 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 some activity 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

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density” drilling has accounted for a large part of the successful oil and gas wells 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 areas 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. The Company has not engaged in price hedging on its oil or gas production.

     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

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essential to provide the cash flow necessary to sustain the ongoing viability of the Company. 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 2004, sales to ONEOK, through well operators, accounted for approximately 10% of the Company’s total revenues. Generally, if one purchaser declines to continue purchasing the Company’s oil and 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. These 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

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oil, condensate and natural gas liquids, can be made at uncontrolled market prices, but Congress could reenact price controls at any time.

     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.

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     EMPLOYEES

     At September 30, 2004, Panhandle employed sixteen persons on a full-time basis and has no part-time employees. Four of the employees are executive officers and one is a director of the Company.

ITEM 2 PROPERTIES

     As of September 30, 2004, Panhandle’s principal properties consisted of perpetual ownership of 259,211 net mineral acres, held principally in tracts in Oklahoma, New Mexico and Texas and 19 other states. The Company also held leases on 18,781 net acres of minerals in Louisiana, Oklahoma and Texas. At September 30, 2004, Panhandle held small royalty and/or working interests in 5,022 producing oil or gas wells, and 78 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, 2004, 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

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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. Beginning in 1995 the Company directed its consulting 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 limited proved undeveloped reserve estimates for these areas. All reserve quantity estimates were prepared by Campbell & Associates, Inc., Norman, Oklahoma, a consulting petroleum engineering firm. The Company’s reserve estimates were not filed with any other federal agency. These reserves exclude approximately 1.2 mmcf of CO2 gas reserves for all years presented.

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     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, 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 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 CASH FLOWS

     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 10% 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, 2004, 2003, 2002 were as follows: 2004 -$44.68, $5.42; 2003 — $27.39, $4.43; 2002 — $27.76, $3.12. 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. The future net cash flows are net of $413,854 undiscounted and $253,842 discounted at 10% from CO2 reserves.

Estimated Future Net Cash Flows

10% Discounted Present Value of Estimated Future Net Cash Flows

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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.

     Gas production includes 176,605, 152,384 and 145,686 MCF of CO2 sold at average prices of $.41, $.32 and $.27 per MCF for the years ended September 30, 2004, 2003 and 2002, respectively.

Average Sales Prices and Production Costs

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

(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, 2004. 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, 2004, Panhandle owned 342,353 gross developed mineral acres and 39,458 net developed mineral acres. Panhandle has also leased from others 177,606 gross developed acres, which contain 16,695 net developed acres.

     UNDEVELOPED ACREAGE

     As of September 30, 2004, Panhandle owned 1,333,642 gross and 216,249 net undeveloped mineral acres, and leases on 28,399 gross and 2,086 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, 2004, 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, 2004.

PART II

ITEM 5 MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     The Company’s Class A Common Stock (“Common Stock”) is listed on the American Stock Exchange (symbol PHX). The following table sets forth the high and low trade prices of the Common Stock during the periods indicated (all share and per share amounts, are adjusted for a 2-for-1 stock split, which was effective April 16, 2004):

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     As of December 3, 2004, the approximate number of holders of shares of Panhandle Common Stock was:

     During the past two years, cash dividends have been paid as follows on the 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 and per share amounts, are adjusted for the effect of the 2-for-1 stock split which was effective April 16, 2004.

(A)		2002, 2003 and 2004 results included are consolidated amounts of Panhandle Royalty Company and its 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.

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

     Forward-looking statements for 2005 and later periods are made throughout this report. 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:

     RESULTS OF OPERATIONS

     2004 COMPARED TO 2003

     OVERVIEW

     The Company recorded a net income of $6,729,825 in 2004, compared to a net income of $5,961,622 in 2003. Total revenues were larger as a result of increased oil and gas sales revenues generated by increases in the average sales prices of oil and natural gas in 2004 as compared to 2003. It currently appears oil and gas sales prices will remain at the levels seen in 2004, or even slightly increased, for at least the next year.

     REVENUES

     Total revenues increased 10% to $24,606,609 in 2004 compared to $22,456,038 in 2003. The increase was due to increases in the average sales price for oil and natural gas in 2004. Production volumes were basically flat in 2004 compared to 2003. New production from the Company’s drilling activity almost replaced the normal production decline of existing gas wells, thus, gas production declined only 2%. Oil wells beginning production in 2004 replaced the decline of existing oil well production, and increased oil production 2%.

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     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 and due to normal inflation of costs. Gross production taxes are paid as a percentage of oil and gas sales revenues and thus, increased in 2004 due to the increase in oil and gas sales revenues.

     EXPLORATION COSTS

     Exploration costs decreased $232,285 or 50% in 2004 as compared to 2003. The Company utilizes the successful efforts method of accounting for oil and gas operations thus, only exploratory dry holes result in their costs being charged to exploration costs. In fiscal 2004, there were no high cost exploratory dry holes.

     DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)

     DD&A increased $332,043 or 6% in 2004 as compared to 2003. The increase is due to several new wells, with large cost basis, going on production in 2004 and having high initial production rates. These production rates and the large cost basis resulted in the increase in DD&A.

     PROVISON FOR IMPAIRMENT

     The provision for impairment increased $149,467 or 22% in 2004 as compared to 2003. This increase was the result of several older fields’ fair values being reduced along with several individual wells, which were completed and began production in 2004, having a fair value at year-end less than their book value, as their initial production rates were substantially less than expected.

     GENERAL AND ADMINISTRATIVE COSTS (G&A)

     G&A costs increased $367,260 or 14% in 2004. Personnel related expenses (including salaries, payroll taxes, insurance and ESOP expenses) increased approximately $203,000 in 2004. G&A expense related to the Non-Employee Directors Deferred Compensation Plan (the “Plan”) increased approximately $130,000 in 2004. The increase resulted from the Company recognizing a charge to G&A to adjust the potential shares in the Plan to market price at September 30, 2004. The non-employee directors have taken these potential shares, rather than a cash payment for their directors fees.

     INTEREST EXPENSE

     Interest expense decreased $211,169 or 30% in 2004. The decrease was due to lower average outstanding debt balances during 2004.

     PROVISION FOR INCOME TAXES

     The provision for income taxes increased in 2004, due to increased income before taxes (as discussed above). The Company continued to be able to utilize 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 31% in 2004, 27% in 2003, while a tax benefit was provided in 2002.

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     LIQUIDITY AND CAPITAL RESOURCES

     At September 30, 2004, the Company had positive working capital of $1,941,634 as compared to $1,335,344 at September 30, 2003. The increase in working capital at September 30, 2004 compared to September 30, 2003, is the result of increased oil and gas sales revenues during 2004, which is discussed in Results of Operation above. Cash flow from operating activities increased 16% to $15,529,639 for fiscal 2004, as compared to fiscal 2003, primarily due to the increase in oil and gas sales prices.

     Capital expenditures for oil and gas activities for 2004 amounted to $10,960,810, as compared to $9,195,916 for 2003. 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 2004, the Company borrowed on its revolving bank loan to help fund those expenditures. However, as a result of the increased cash flow from higher prices received for natural gas in fiscal 2004, the Company was able to reduce its bank debt by a net of $4,150,004. Approximately $12 million is available under the Company’s current bank debt facility for capital expenditures, acquisitions or any combination of uses. Further, the credit facility could be increased, if needed, for a large acquisition. The Company expects to increase its capital expenditure level to approximately $12 million in 2005. Funds for this level of expenditures will come from cash flow and/or bank debt, if required.

     CONTRACTUAL OBLIGATIONS

     The Company has a credit facility with BancFirst of Oklahoma City, Oklahoma. The facility 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 facility is $22,500,000. The term loan matures on April 1, 2008, and the revolving loan matures on March 31, 2006. 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% (4.0% at September 30, 2004) or LIBOR (for one, three or six month periods), plus 1,80%. The Company, at September 30, 2004, has elected the prime rate option.

     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, 2004. 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, 2004 the Company was in compliance with the covenants.

     The table below summarizes the Company’s contractual obligations as of September 30, 2004:

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     2003 COMPARED TO 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.

     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 2003; 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 production decline of existing gas wells allowing gas production to remain flat. Fewer oil wells have been drilled in recent years, thus, oil production continues to decline as existing wells production continues its normal 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 and due to normal inflation of costs. 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 wells. As the Company utilizes the successful efforts method of accounting for oil and gas operations exploratory dry holes result in the expensing of all costs associated with those wells. Several of the exploratory wells drilled in 2003 were dry holes.

     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.

     PROVISON 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, which increased the fair value of the Company’s oil and gas properties in 2003 as compared to the carrying amount of the properties.

     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

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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 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.

     INTERST 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.

     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. 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.

     CRITICAL ACCOUNTING POLICIES

     Preparation of financial statements in conformity with accounting principles generally accepted in

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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. This accounting method may yield significantly different operating results than the full cost method.

     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

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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 either the national prime rate minus 3/4% or LIBOR for one, three or six month periods, plus 1.8%. At September 30, 2004, a 1% change in the prime interest rate would result in approximately a $33,500 change in annual interest expense. The Company has a $10,000,000 term loan (outstanding balance of $7,166,661 at September 30, 2004) 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 Registered Public Accounting Firm

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, 2004 and 2003, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Panhandle Royalty Company at September 30, 2004 and 2003, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2004, in conformity with accounting principles generally accepted in the United States.

Ernst & Young, LLP
Oklahoma City, Oklahoma
December 6, 2004

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Panhandle Royalty Company
Consolidated Balance Sheets

(Continued on next page.)

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Panhandle Royalty Company
Consolidated Balance Sheets

See accompanying notes.

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Panhandle Royalty Company
Consolidated Statements of Income

See accompanying notes.

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Panhandle Royalty Company
Consolidated Statements of Stockholders’ Equity

See accompanying notes.

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Panhandle Royalty Company
Consolidated Statements of Cash Flows

Continued on next page.

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Panhandle Royalty Company
Consolidated Statements of Cash Flows (continued)

See accompanying notes.

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Panhandle Royalty Company
Notes to Consolidated Financial Statements

September 30, 2004, 2003 and 2002

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, 2004 and 2003, 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, 2004.

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.

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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

1. Summary of Significant Accounting Policies (continued)

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.

Non-producing oil and gas properties include non-producing minerals, which have a net book value of $6,593,777 at September 30, 2004, 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 non-producing 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 $841,687, $692,220, and, $1,116,234 respectively, for 2004, 2003 and 2002. 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.

Asset Retirement Obligations

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. At September 30, 2004 the net increase to Property and Equipment had increased to $728,037 and the Asset Retirement Obligation increased to $602,979.

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, 2004, there were no such costs accrued.

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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

1. Summary of Significant Accounting Policies (continued)

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).

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).

The Company applies SOP 93-6 in accounting for its non-leveraged Employee Stock Ownership Plan. Under SOP 93-6 the Company records as expense, the fair market value of the stock at the time of contribution.

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, 2004, the remaining borrowings bear interest at a variable rate.

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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

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.

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

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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

3. Income Taxes

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

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:

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

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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

4. Long-Term Debt

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

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 Agreement is $22,500,000. The term loan matures on April 1, 2008, and the revolving loan matures on March 31, 2006. 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% (4.0% at September 30, 2004) or LIBOR (for one, three or six month periods), plus 1.80%. The Company, at September 30, 2004, has elected the prime rate option.

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, 2004. 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, 2004 the Company was in compliance with the covenants.

The amount of required principal payments for the next five years as of September 30, 2004, are as follows: 2005–$2,000,004, 2006–$5,350,004, 2007–$2,000,004 and 2008–$1,166,649.

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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

5. Shareholders’ Equity

On December 18, 2003, the Company’s Board of Directors approved a proposal to amend the Company’s Articles of Incorporation to increase the number of authorized shares of Class A Common Stock from 6,000,000 shares to 12,000,000 shares and effect a 2-for-1 stock split of the outstanding Class A Common Stock and a corresponding reduction of the par value per share from $.03333 to $.01666. On February 27, 2004, these proposals were put forth to a vote of the shareholders, for which a majority of the shareholders voted in favor of each proposal, causing these proposals to become effective on such date. The Class A Common Stock split was effected in the form of a stock dividend, distributed on April 15, 2004, to stockholders of record on April 1, 2004.

All agreements concerning Common Stock of the Company, including the Company’s Employee Stock Ownership Plan and the Company’s commitment under the Deferred Compensation Plan for Non-Employee Directors, provide for the issuance or commitment, respectively, of additional shares of the Company’s stock due to the declaration of the stock split. All references to number of shares, per share, and authorized share information in the accompanying consolidated financial statements have been adjusted to reflect the stock split and increase in authorized shares approved on February 27, 2004, at the Annual Meeting of the Stockholders of the Company.

6. 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).

The weighted average shares outstanding, potentially dilutive shares, and earnings per share for 2002 and 2003 have been restated to affect the 2-for-1 stock split discussed in Note 5.

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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

7. 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 2004, 2003 or 2002) 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 249,847 shares of the Company’s common stock held by the plan as of September 30, 2004, 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:

8. 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, 2004, 50,251 shares (45,816 shares at September 30, 2003) are included in the Plan. The Company has accrued $864,334 at September 30, 2004 ($519,783 at September 30, 2003) in connection with the Plan ($344,551, $241,673 and $23,095 was charged to the results of operations for the years ended September 30, 2004, 2003 and 2002, respectively, and is included in general and administrative expense in the accompanying income statement).

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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

9. 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 2004, 2003 and 2002 approximately 10%, 14%, and 17%, 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 7%, 9%, and 12% of the Company’s revenues in 2004, 2003 and 2002, 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:

Costs Incurred

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

(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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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

10. 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 non-producing 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 consulting 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, 2004, 2003 and 2002, have been estimated by Campbell & Associates, Inc., a consulting 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, 2004, 2003 and 2002. 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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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)

10. 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: