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
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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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
ITEM 3 LEGAL PROCEEDINGS
There were no material legal proceedings involving Panhandle or its subsidiary, as of the date of this report.
ITEM 4
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
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
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
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
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
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
(Continued on next page.)
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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, 2003, 2002 and 2001
1. Summary of Significant Accounting Policies
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of Panhandle Royalty Company and its wholly owned subsidiaries after elimination of all material intercompany transactions.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.
Oil and Gas Sales and Gas Imbalances
The Company sells oil and natural gas to various customers, recognizing revenues as oil and gas is produced and sold. The Company uses the sales method of accounting for gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a reservoir cannot be recouped through the production of remaining reserves. At September 30, 2003 and 2002, the Company had no material gas imbalances.
Charges for gathering and transportation are included in lease operating expenses and production taxes.
Concentration of Credit Risk
Substantially all of the Company’s accounts receivable are due from purchasers of oil and natural gas or operators of the oil and gas properties. Oil and natural gas sales are generally unsecured. The Company has not experienced significant credit losses in prior years and is not aware of any significant uncollectible accounts at September 30, 2003.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
Oil and Gas Producing Activities
The Company follows the successful efforts method of accounting for oil and gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income if and when the well is determined to be nonproductive. Oil and gas mineral and leasehold costs are capitalized when incurred.
Depreciation, Depletion, Amortization, and Impairment
Depreciation, depletion, and amortization of the costs of producing oil and gas properties are generally computed using the units of production method primarily on a separate property basis using proved reserves as estimated annually by an independent petroleum engineer. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.
Nonproducing oil and gas properties include nonproducing minerals, which have a net book value of $6,930,687 at September 30, 2003, consisting of perpetual ownership of mineral interests in several states, including Oklahoma, Texas and New Mexico. These costs are being amortized over a thirty-three year period using the straight-line method. An ultimate determination of whether these properties contain recoverable reserves in economical quantities is expected to be made within this time frame. Impairment of nonproducing oil and gas properties is recognized based on experience and management judgment.
In accordance with the provisions of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows. The Company’s oil and gas properties were reviewed for indicators of impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $692,220, $1,116,234, and $848,535, respectively, for 2003, 2002 and 2001. The majority of the impairment recognized in these years relates to fields comprised of a small number of properties or single wells on which the Company does not expect sufficient future net cash flow to recover its carrying cost.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
Asset Retirement Obligations
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method and the liability should be accreted to its face amount. The Company adopted SFAS No. 143 on October 1, 2002. The primary impact of this standard relates to oil and gas wells on which the Company has a legal obligation to plug and abandon the wells. Prior to SFAS No. 143, Company had not recorded an obligation for these plugging and abandonment costs due to its assumption that the salvage value of the surface equipment would offset the cost of dismantling the facilities and carrying out the necessary clean-up and reclamation activities. The adoption of SFAS No. 143 on October 1, 2002 resulted in a net increase to Property and Equipment and Asset Retirement Obligations of approximately $481,000 and $406,000, respectively, as a result of the Company separately accounting for salvage values and recording the estimated fair value of its plugging and abandonment obligations on the balance sheet. The increase in expense resulting from the accretion of the asset retirement obligation and the depreciation of the additional capitalized well costs was substantially offset by the decrease in depreciation from the Company’s consideration of the estimated salvage values in the calculation.
Environmental Costs
Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2003, there were no such costs accrued.
Earnings Per Share of Common Stock
Basic earnings per share (EPS) is calculated using net income divided by the weighted average of common shares outstanding during the year. Diluted EPS is similar to basic EPS except that the weighted average common shares outstanding is increased to include the number of additional common shares that would have been outstanding if the dilutive potential common shares had been issued. The treasury stock method is used to calculate dilutive shares, which reduces the gross number of dilutive shares (see Note 5).
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
Stock-based Compensation
The Company applies APB Opinion No. 25 in accounting for its Deferred Compensation Plan for Outside Directors. Under APB No. 25, compensation cost is recognized for changes in the fair value of the stock credited to each director’s account at the fair market value of the stock at the date of grant. The shares are then adjusted for changes in the shares market value subsequent to the date of grant until the conversion date (see Note 7).
Fair Values of Financial Instruments
The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, prepaid expenses, accounts payable, and accrued liabilities approximate their fair values due to the short maturity of these instruments. The fair value of Company’s long-term debt approximates its carrying amount due to the interest rate on the Company’s term-loan being a fixed rate which approximated market rates at September 30, 2003, the remaining borrowings bear interest at a variable rate.
Recently Issued Accounting Pronouncements
In June 2002, FASB issued SFAS 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity. The pronouncement is effective for exit or disposal activities initiated after December 31, 2002. The adoption of SFAS 146 had no material impact on the Company’s financial position or results of operations and is currently expected to in the near term.
In April 2003, the FASB issued FAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This Statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement is effective for contracts entered into or modified after June 30, 2003. Adoption of this Statement had no impact on the financial position or results of operation of the Company and is currently not expected to in the near term.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS 150 establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Under SFAS 150, mandatorily redeemable financial instruments, obligations to repurchase the issuer’s shares by transferring assets and certain obligations to issue a variable number of shares to settle that obligation must be classified as liabilities on the balance sheet and initially recorded at fair value. SFAS 150 is effective for the Company for financial instruments entered into or modified after May 31, 2003, and on July 1, 2003 for most previously existing financial instruments. In November 2003, the FASB voted to defer indefinitely the effective date for certain mandatorily redeemable non-controlling interests (MRNI) associated with finite-lived subsidiaries. For all other MRNIs, the effective date was deferred to November 5, 2003. The adoption of SFAS 150 did not impact our financial position, results of operations or net cash flows as the Company currently does not use any of the financial instruments subject to this statement.
In November 2002, the FASB issued FASB Interpretation (FIN) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45 clarifies the requirements of SFAS 5, Accounting For Obligations, relating to a guarantor’s accounting for, and disclosure of the issuance of certain types of guarantees. The adoption of FIN 45 did not impact the Company’s financial position, results of operations or net cash flows as the Company currently does not have any guarantees.
In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when and which business enterprises should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. FIN 46 applies immediately to VIEs created after January 31, 2003 or to VIEs obtained after that date. For variable interests held in VIEs acquired prior to February 1, 2003, FIN 46 was originally effective July 1, 2003. However, in October 2003, the FASB deferred the effective date of FIN 46 for VIEs created prior to February 1, 2003 to the first reporting period after December 15, 2003. The adoption of this interpretation is not
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
anticipated to have a material impact on the Company’s financial position, results of operations or net cash flows because the Company currently is not a primary beneficiary of a VIE.
2. Acquisition of Wood Oil Company
On October 1, 2001, the Company acquired 100% of the outstanding common stock of Wood Oil Company (Wood). The acquisition was made pursuant to an Agreement and Plan of Merger among the Company, PHC, Inc. and Wood Oil Company, dated August 9, 2001. Wood merged with Panhandle’s wholly owned subsidiary PHC, Inc., on October 1, 2001, with Wood being the surviving Company. Prior to the acquisition, Wood was a privately held company engaged in oil and gas exploration and production and fee mineral ownership and owned interests in certain oil and gas and real estate partnerships and owned an office building in Tulsa, Oklahoma. Subsequent to the acquisition, Wood has continued to operate as a subsidiary of Panhandle and personnel were moved to Oklahoma City in early 2002. Wood and its shareholders were unrelated parties to Panhandle.
The Company’s decision to acquire Wood was the result of desired growth in the Company’s asset base of producing oil and gas reserves and fee mineral acreage. Wood’s oil and gas activity, fee minerals and operating philosophy, in general, had been very similar to the Company’s.
Wood’s mineral acreage ownership and leasehold position as well as its producing oil and gas properties are located in the same general areas as the Company’s. In several cases, both companies owned interests in existing producing wells and several developing fields. The Company intends to actively pursue drilling opportunities on Wood’s properties.
Funding for the acquisition was obtained from Banc First of Oklahoma City, Oklahoma in the form of a $20 million five-year term loan. Three million of Wood’s cash was used to reduce Panhandle’s debt on the date of closing.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
2. Acquisition of Wood Oil Company (continued)
The operations of Wood, since October 1, 2001, are included in the accompanying consolidated financial statements.
The following table sets forth the allocation of the purchase price to the assets and liabilities acquired:
In April 2002, the Company sold the land and building and its interest in two partnerships resulting in net proceeds of approximately $1.4 million of which $800,000 were used to pay down long term debt. Other revenues in the accompanying consolidated income statement include a gain of $56,487 on the sale of the building and a gain of $122,550 on the sale of the two partnerships.
The following unaudited proforma results of operations give effect to the acquisition as if consummated on October 1, 2000. The data reflects adjustments of the historical Wood results for depreciation and amortization of the property and equipment acquired, adjustments of expenses resulting from contractual requirements of the acquisition agreement, incremental interest expense relating to bank borrowing used to finance the purchase and income taxes. Total revenues for 2001 include non-recurring gains on asset sales of $2.1 million. The pro forma adjustments are based upon available information and assumptions that management of the Company believes are reasonable. The pro forma results of operations data does
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
2. Acquisition of Wood Oil Company (continued)
not purport to represent the results of operations that would have occurred had such transaction been consummated on October 1, 2000 or the Company’s results of operation for any future date or period.
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:
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
3. Income Taxes (continued)
Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax bases of assets and liabilities, consist of the following:
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
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
4. Long-Term Debt (continued)
Agreement is $22,500,000. The term loan matures on April 1, 2008, and the revolving loan matures on April 1, 2005. Monthly payments on the term loan are $166,667, plus accrued interest, beginning on May 1, 2003. Borrowings under the revolving loan are due at maturity. Interest on the term loan is fixed at 4.56% until maturity. The revolving loan bears interest at the national prime rate minus -3/4% (3.25% at September 30, 2003) or LIBOR (for one, three or six month periods), plus 1.80%. The Company, at September 30, 2003, has elected a six month LIBOR rate (aggregate of 2.98%).
The total outstanding borrowings under both the term loan and the revolving line of credit may not exceed the borrowing base which is $22.5 million as of September 30, 2003. Subsequent determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2003 the Company was in compliance with the covenants. Certain of the Company’s oil and gas properties secure the debt.
The amount of required principal payments for the next five years as of September 30, 2003, are as follows: 2004 - $2,000,004, 2005 - $7,500,004, 2006 - $2,000,004, 2007 - $2,000,004 and 2008 - $1,166,649.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
5. Earnings Per Share
The following table sets forth the computation of basic and diluted earnings per share. The Company’s diluted earnings per share calculation takes into account certain shares that may be issued under the Non-Employee Directors’ Deferred Compensation Plan (see Note 7).
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
6. Employee Stock Ownership Plan
The Company has an employee stock ownership plan that covers substantially all employees and is established to provide such employees with a retirement benefit. These benefits become fully vested after three years of employment. Contributions to the plan are at the discretion of the Board of Directors and can be made in cash (none in 2003, 2002 or 2001) or the Company’s common stock. For contributions of common stock, the Company records as expense, the fair market value of the stock at the time of contribution. The 129,904 shares of the Company’s common stock held by the plan as of September 30, 2003, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings per share computations and receive dividends. Contributions to the plan consisted of:
7. Deferred Compensation Plan for Directors
Effective November 1, 1994, the Company formed the Panhandle Royalty Company Deferred Compensation Plan for Non-Employee Directors (the Plan). The Plan provides that each eligible director can individually elect to receive shares of Company stock rather than cash for board meeting fees and board committee meeting fees. These shares are unissued and vest at the date of grant. The shares are credited to each director’s deferred fee account at the fair market value of the stock at the date of grant and are adjusted for changes in market value subsequent thereto. Upon retirement, termination or death of the director, or upon change in control of the Company, the shares accrued under the Plan will be either issued to the director or may be converted to cash, at the director’s discretion, for the fair market value of the shares on the conversion date as defined by the Plan. As of September 30, 2003, 22,908 shares (22,100 shares at September 30, 2002) are included in the Plan. The Company has accrued $519,783 at September 30, 2003 ($321,555 at September 30, 2002) in connection with the Plan ($241,673, $23,095, and $70,570 was charged to the results of operations for the years ended September 30, 2003, 2002 and 2001, respectively, and is included in general and administrative expense in the accompanying income statement).
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
8. Information on Oil and Gas Producing Activities
All oil and gas producing activities of the Company are conducted within the United States (principally in Oklahoma) and represent substantially all of the business activities of the Company.
During 2003, 2002 and 2001 approximately 14%, 17%, and 23%, respectively, of the Company’s total revenues were derived from gas sales to ONEOK, Inc. The Company also has interests in a field of properties, the production on which accounted for approximately 9%, 12%, and 15% of the Company’s revenues in 2003, 2002 and 2001, respectively.
Aggregate Capitalized Costs
The aggregate amount of capitalized costs of oil and gas properties and related accumulated depreciation, depletion, and amortization as of September 30 is as follows:
Costs Incurred
During the reporting period, the Company incurred the following costs in oil and gas producing activities:
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
9. Supplementary Information on Oil and Gas Reserves (Unaudited)
The following unaudited information regarding the Company’s oil and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission (SEC) and SFAS No. 69, Disclosures About Oil and Gas Producing Activities.
Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Because the Company’s nonproducing mineral and leasehold interests consist of various small interests in numerous tracts located primarily in Oklahoma, New Mexico, and Texas, it is not economically feasible for the Company to provide estimates of all proved undeveloped reserves. The Company directs its independent petroleum engineering firm to include proved undeveloped reserves in certain areas of Oklahoma and New Mexico in the scope of properties which are evaluated for the Company.
The Company’s net proved (including certain undeveloped reserves described above) oil and gas reserves, all of which are located in the United States, as of September 30, 2003, 2002 and 2001, have been estimated by Campbell & Associates, Inc., an independent petroleum engineering firm. All studies have been prepared in accordance with regulations prescribed by the Securities and Exchange Commission. The reserve estimates were based on economic and operating conditions existing at September 30, 2003, 2002 and 2001. Since the determination and valuation of proved reserves is a function of testing and estimation, the reserves presented should be expected to change as future information becomes available.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
9. Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)
Estimated Quantities of Proved Oil and Gas Reserves
Net quantities of proved, developed, and undeveloped oil and gas reserves are summarized as follows:
(1)
Revisions of oil reserves and some associated gas reserves were principally a result of changes in reserves associated with properties in the Dagger Draw Field of New Mexico, which will be converted to a waterflood in 2004. Gas reserve revisions resulted from properties which were drilled in the prior year and now have actual performance to guide the projections, rather than the limited data available in the first few months a property comes on production.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
9. Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)
The above reserve numbers are net of approximately 1.2 mmcf of CO2 gas reserves owned by Wood Oil Company.
Standardized Measure of Discounted Future Net Cash Flows
Estimates of future cash flows from proved oil and gas reserves, based on current prices and costs, as of September 30 are shown in the following table. Estimated income taxes are calculated by (i) applying the appropriate year-end tax rates to the estimated future pretax net cash flows less depreciation of the tax basis of properties and statutory depletion allowances and (ii) reducing the amount in (i) for estimated tax credits to be realized in the future for gas produced from “tight-sands” through December 31, 2002.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
9. Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)
Changes in the standardized measure of discounted future net cash flows are as follows:
10. Quarterly Results of Operations (Unaudited)
The following is a summary of the Company’s unaudited quarterly results of operations.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
10. Quarterly Results of Operations (Unaudited) (continued)
(A)
The quarter ended September 30, 2002, reflects a change in estimate associated with the Company’s income tax provision resulting from the determination of actual percentage depletion and tight sands gas credits available to reduce the Company’s taxable income.
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ITEM 9
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
N O N E
ITEM 9 A
ITEM 9 A CONTROLS AND PROCEDURES
Panhandle Royalty Company management, under the supervision of and with the participation of the Chief Executive Officer and Chief Financial Officer have conducted an evaluation of the effectiveness of disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in insuring that all material information required to be filed in this annual report has been made known to them in a timely fashion. There have been no significant changes in our internal controls or in factors that could significantly affect internal controls, subsequent to the date the Chief Executive Officer and Chief Financial Officer completed their evaluation.
In accordance with General Instruction G (3) to Form 10-K, Part III, Items 10.-14. of this Report are omitted because the Company will file with the Securities and Exchange Commission not later than 120 days after the end of the fiscal year ended September 30, 2003, a definitive proxy statement pursuant to Regulation 14A involving the election of directors, which proxy statement is incorporated herein by reference.
PART III
ITEM 15
ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
REPORTS ON FORM 8-K
Form 8-K dated August 13, 2003, Regulation FD disclosure of Company’s earnings release for the third quarter of fiscal 2003.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ Jerry L. Smith
/s/ E. Chris Kauffman
Jerry L. Smith, Chairman of Board
E. Chris Kauffman, Director
Date December 17, 2003
Date December 17, 2003
/s/ Robert A. Reece
/s/ Michael A. Cawley
Robert A. Reece, Director
Michael A. Cawley, Director
Date December 17, 2003
Date December 17, 2003
/s/ H. Grant Swartzwelder
/s/ Ben D. Hare
H. Grant Swartzwelder, Director
Ben D. Hare, Director
Date December 17, 2003
Date December 17, 2003
/s/ Robert O. Lorenz
/s/ Michael C. Coffman
Robert O. Lorenz, Director
Michael C. Coffman, Vice President
Treasurer and Secretary (Principal Financial and
Date December 17, 2003
Accounting Officer)
Date December 17, 2003
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