PHX MINERALS INC. - Quarter Report: 2004 June (Form 10-Q)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

Commission File Number 0-9116

PANHANDLE ROYALTY COMPANY

     Grand Centre Suite 210, 5400 N Grand Blvd., Oklahoma City, Oklahoma 73112

Registrant’s telephone number including area code (405) 948-1560

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 of 1934 during the preceding 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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

(    ) Yes     ( X ) No

Outstanding shares of Class A Common stock (voting) at August 4, 2004: 4,179,725

INDEX

PART I. FINANCIAL INFORMATION

PANHANDLE ROYALTY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

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PANHANDLE ROYALTY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

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PANHANDLE ROYALTY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(See accompanying notes)

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PANHANDLE ROYALTY COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1: Accounting Principles and Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission, and include the Company’s wholly owned subsidiary, Wood Oil Company (Wood). Management of Panhandle Royalty Company believes that all adjustments necessary for a fair presentation of the consolidated financial position and results of operations for the periods have been included. All such adjustments are of a normal recurring nature. The consolidated results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1, through September 30.

NOTE 2: Income Taxes

The Company’s provision for income taxes is reflective of excess percentage depletion, reducing the Company’s effective tax rate from the federal statutory rate.

NOTE 3: Stockholders’ Equity

On December 18, 2003, the Company’s Board of Directors approved a proposal to (i) amend the Company’s Articles of Incorporation to increase the number of authorized shares of Class A common stock from 6,000,000 to 12,000,000 shares and (ii) effect a 2-for-1 stock split of outstanding Class A common stock and a corresponding reduction of the par-value per share from $.0333 to $.0166. On February 27, 2004, these proposals were put forth to a vote of the stockholders, for which a majority of the stockholders voted in favor of each proposal, causing these proposals to become effective on such date. The Class A common stock split was affected in the form of a stock dividend, distributed on April 15, 2004 to shareholders of record on April 1, 2004.

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.

NOTE 4: Earnings per Share

The following table sets forth the number of shares utilized in the computation of basic and diluted earnings per share, giving consideration to certain shares that may be issued under the Non-Employee Directors Deferred Compensation Plan, to the extent dilutive. The weighted average shares outstanding, potentially dilutive shares and earnings per share for 2003 have been restated to effect the 2-for-1 stock split discussed in Note 3.

NOTE 5: Long-term Debt

On March 25, 2003, the Company amended its Loan Agreement with BancFirst, Oklahoma City, OK. 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 agreements is $22,500,000 which can be re-determined semi-annually. 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. 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 June 30, 2004) or Libor (for one, three or six month periods), plus 1.80%. The Company at March 31, 2004, elected a six-month Libor rate (aggregate of 2.95%). At June 30, 2004, the Company had $7,666,662 outstanding under the term loan and $3,175,000 outstanding under the revolving loan.

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NOTE 6: Asset Retirement Obligation

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, the 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 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.

NOTE 7: 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.

ITEM 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

     Forward-Looking Statements for fiscal 2004 and later periods are made in this document. Such statements represent estimates by 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 risks, drilling risk, reserve quantity risk and operations and production risk. 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.

LIQUIDITY AND CAPITAL RESOURCES

     At June 30, 2004, the Company had positive working capital of $1,105,299, as compared to positive working capital of $1,335,344 at September 30, 2003. Oil and gas sales receivable has increased due to higher oil and natural gas prices, but is more than offset by an increase in income taxes payable and an increase in the liability for deferred compensation for outside directors. The provision for income taxes increased as the result of higher earnings and the exhaustion of tax depletion carry forward deductions. Deferred compensation for outside directors increased as the Company’s stock price, to which the deferred compensation is tied, increased significantly during the 2004 fiscal year.

     Capital expenditures for oil and gas activities for the 2004 nine-month period amounted to $6,986,931, as compared to $7,523,226 for the 2003 period. Management currently expects capital expenditures for oil and gas activities to be approximately $9,000,000 for fiscal 2004. Any acquisitions of oil and gas properties would add to the capital expenditure amount.

     The Company has historically funded capital expenditures, overhead expenditures and dividend payments from operating cash flow. Due to the increased capital expenditure level of fiscal 2003 and continuing into fiscal 2004, the Company has utilized the revolving line-of-credit facility to help fund these expenditures. As a result of the increased cash flow from higher prices being received for natural gas in late fiscal 2003, and continuing into fiscal 2004, the Company has been able to reduce outstanding bank borrowings by $3,825,000 in fiscal 2004. Management currently does not expect to borrow substantial funds under the revolving loan during the remainder of fiscal 2004, but small amounts may be borrowed on a temporary basis. The Company has in excess of $11 million available under the bank debt facility and the availability could be increased if needed.

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RESULTS OF OPERATIONS

     NINE MONTHS ENDED JUNE 30, 2004 - COMPARED TO NINE MONTHS ENDED JUNE 30, 2003

Revenues:

     Total revenues increased $861,011 or 5% for the 2004 period. The increase was principally the result of a $439,997 increase in oil and natural gas sales revenues and a $304,538 increase in other revenues. The increase in oil and gas sales revenues resulted from a 2.5% and a 15% increase in the average sales price of natural gas and oil, respectively. These increases were partially offset by a 2% decrease in natural gas production. The increase in other revenues consists of a $224,859 lawsuit settlement received on the McElmo Dome CO2 Unit and a $49,000 payment received from the initiation of stage 2 development on the Witcher Waterflood Unit.

     The table below outlines the Company’s production and average sales prices for oil and natural gas for the nine-month periods of fiscal 2004 and 2003:

     The increase in oil sales volumes for the 2004 period was principally the result of production from two new oil wells. The slight decrease in gas production was the result of normal production decline.

Lease Operating Expenses (LOE):

     Lease operating expenses decreased $6,688 or less than 1% in the 2004 period. The decrease is a result of fewer new wells going on line in the 2004, as new wells normally have higher operating costs the first several months of production.

Production Taxes:

     Production taxes increased $29,996 or 3% in the 2004 period. The increase is the result of larger oil and natural gas sales for the period in 2004, as production taxes are paid as a percentage of oil and natural gas revenues.

Exploration Costs:

     These costs decreased $234,602 in the 2004 period. Exploration costs are principally dry hole costs resulting from the drilling of exploratory dry holes. In the 2004 period, the Company had only two high cost exploratory wells which resulted in dry holes, as compared to the 2003 period which had several.

Depreciation, Depletion, Amortization and Impairment (DD&A):

     DD&A decreased $191,722 or 4% in the 2004 period. The decrease is due to impairment recognized on the Company’s oil and gas properties declining approximately $91,000 in the 2004 period and DD&A expenses on many of the wells acquired in the Wood Oil acquisition continue to decline as production volumes continue their natural decline.

General and Administrative Costs (G&A):

     G&A costs increased $279,203 or 14% in the 2004 period. In the 2004 period, personnel related expenses increased over 2003 amounts by approximately $136,000. The increase of $61,000 is due to costs related to the Directors’ Deferred Compensation Plan. Also, costs related to Panhandle Royalty Company’s stock listing have increased by approximately $45,000 in the 2004 period due to listing on the AMEX in late 2003.

Interest Expense:

     Interest expense decreased in the 2004 period due to lower outstanding debt balances.

Income Taxes:

     The 2004 provision for income taxes increased $581,231. This increase is due to increased income before provision for income taxes of $1,135,347 and the exhaustion of depletion deduction carry forwards. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate. The effective tax rate for the 2004 period is 33% vs. 30% for the 2003 period.

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Overview:

     The Company recorded a nine-month 2004 net income of $5,018,354, or $1.19 per share, as compared to a net income $4,510,738 or $1.07 per share in the 2003 period. The increased results were due to increases in sales prices for both oil and natural gas, increased other income and a 2.5% decline in costs and expenses offset by a significant increase in income tax.

     THREE MONTHS ENDED JUNE 30, 2004 - COMPARED TO THREE MONTHS ENDED JUNE 30, 2003

Revenues:

     Total revenues increased $1,147,631 or 20% for the 2004 quarter. The increase was principally the result of an $849,936 increase in oil and natural gas sales revenues. The increase in oil and gas sales revenues resulted from a 15% and a 34% increase in the average sales price for natural gas and oil, respectively, offset by a 2% reduction in natural gas sales volumes and a 5% reduction in oil sales volumes. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three-month periods of fiscal 2004 and 2003:

     The decrease in natural gas and oil production was the result of normal production decline.

Lease Operating Expenses (LOE):

     Lease operating expenses increased $35,411 or 6% in the 2004 quarter. The increase is a result of the Company having increased the number of wells in which it has a working interest and several wells having higher operating costs with gas compressors on-site.

Production Taxes:

     Production taxes increased $17,103 or 4% in the 2004 quarter. The increase is principally the result of larger oil and natural gas revenues in the 2004 quarter, as production taxes are paid as a percentage of these revenues. This increase was partially offset by production tax refunds received on wells that qualify for state production tax incentive programs.

Exploration Costs:

     These costs increased $162,828 in the 2004 quarter. These costs are principally dry hole costs resulting from exploratory dry holes drilled and expired leasehold interests. In the 2004 quarter the Company had two high cost exploratory wells totaling $106,295 which resulted in dry holes, as compared to the 2003 quarter which had none that were high cost. Expired leases totaled $44,632 in the 2004 quarter vs. $408 in the 2003 quarter.

Depreciation, Depletion, Amortization (DD&A) and Impairment:

     DD&A and Impairment decreased $29,095 or 2% in the 2004 quarter. The decrease was a result of lower impairment costs partially offset by a slight increase in DD&A.

General and Administrative Costs (G&A):

     G&A costs decreased $163,248 or 22% in the 2004 quarter as a result of a $224,202 decrease in Deferred Directors’ Compensation offset by an increase of $50,912 in personnel related expenses. The decrease in Deferred Directors’ Compensation is the result of Panhandle’s share price decreasing $1.88 per share during the 2004 quarter. When the price decrease is applied to the approximate 49,000 potential shares in the plan, expense in the 2004 quarter is reduced as compared to the 2003 quarter where the share price increased $3.20 per share and an increase in expense was recognized on the approximate 45,000 shares in the plan.

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Interest Expense:

     Interest expense decreased in the 2004 quarter due to lower outstanding debt balances.

Income Taxes:

     The 2004 provision for income taxes increased $589,000 due to a higher income before provision for income taxes and the exhaustion of depletion deduction carry forwards. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate. The effective tax rate for the 2004 period is 37% vs. 30% for the 2003 period.

Overview:

     The Company recorded a third quarter 2004 net income of $2,130,484, or $.50 per share, as compared to a net income of $1,538,583 or $.37 per share in the 2003 quarter. The increased net income was due to increased sales prices for natural gas and oil offset by increased income taxes.

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, oil and gas sales revenue accruals 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. On an annual basis, with a limited scope semi-annual update, 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. 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 management’s 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.

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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 property 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 as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. 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 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES 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 ¾% or Libor for one, three or six month periods, plus 1.8%. A one percent change in the prime interest rate would result in approximately a $32,000 change in annual interest expense.

     The Company has a $10,000,000 term loan, with a balance of $7,666,662 outstanding at June 30, 2004, which matures on April 1, 2008. The interest rate is fixed at 4.56% until maturity.

ITEM 4 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 ensuring that all material information required to be filed in this quarterly 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.

PART II OTHER INFORMATION

ITEM 6 EXHIBITS AND REPORT ON FORM 8-K

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SIGNATURES

     Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PANHANDLE ROYALTY COMPANY

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