PHX Minerals - 10-Q quarterly report FY

 

(Exact name of registrant as specified in its charter)

Grand Centre Suite 305, 5400 N Grand Blvd., Oklahoma City, Oklahoma 73112

(Address of principal executive offices)

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.

þ Yes            o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.
See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o       Accelerated filer þ       Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes            þ No

Outstanding shares of Class A Common stock (voting) at August 3, 2006: 8,410,886

 

 

INDEX

PANHANDLE ROYALTY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Information at June 30, 2006 is unaudited)

PANHANDLE ROYALTY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

PANHANDLE ROYALTY COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

Nine Months Ended June 30, 2006

PANHANDLE ROYALTY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(See accompanying notes)

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.

     Loss on Sale of Assets in the 2005 periods has been reclassified from Interest and Other Revenues to Costs and Expenses in this Form 10-Q

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 13, 2005, the Company’s Board of Directors declared a 2-for-1 stock split of outstanding Class A common stock. The Class A common stock split was effected in the form of a stock dividend, distributed on January 9, 2006 to shareholders of record on December 29, 2005.

     All references to number of shares and per share information in the accompanying consolidated financial statements have been adjusted to reflect the stock split.

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 fiscal 2005 have been restated to reflect the 2-for-1 stock split discussed in Note 3.

NOTE 5: Long-term Debt

     The Company has a loan agreement with BancFirst, Oklahoma City, OK (the Agreement). The Agreement provides for 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 revolving loan is $8,000,000 which can be re-determined semi-annually. The term loan matures on April 1, 2008, and the revolving loan matures on March 30, 2008. 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% (7.5% at June 30, 2006) or Libor (for one, three or six month periods), plus 1.80%. At June 30, 2006, the Company had $3,666,654 outstanding under the term loan and had no balance outstanding under the revolving loan.

NOTE 6: Deferred Compensation Plan for Directors

     No shares were issued under the Plan in the 2006 periods. Effective October 19, 2005 the Plan was amended such that upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director. This amendment removed the conversion to cash option available under the Plan, which eliminated the requirement to adjust the deferred compensation liability for changes in the market value of the Company’s common stock after October 19, 2005. The adjustment of the liability to market value of the shares at the closing price on October 19, 2005 resulted in a credit to general and administrative expense of approximately $288,000. This change will reduce volatility in the Company’s earnings resulting from the charges to expense caused by market value changes in the Company’s common stock. The deferred compensation obligation at the date of the Plan’s amendment was reclassified to stockholders’ equity.

NOTE 7: Capitalized Costs

     Oil and gas properties include costs of $556,275 on exploratory wells which were drilling and/or testing at June 30, 2006.

     Forward-looking statements for fiscal 2006 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, drilling and equipment cost risk, field services cost 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.

     At June 30, 2006, the Company had positive working capital of $3,918,035, as compared to positive working capital of $3,470,006 at September 30, 2005. The increase is a result of an income tax receivable created by the estimated federal income tax payment made in March 2006 and the directors’ deferred compensation liability being reclassified to equity in October 2005. These items were offset by an increase in accounts payable, which relates to increased drilling expenditures and a decline in oil and gas sales receivables. Capital expenditures are increasing as the Company continues to implement its strategy of increasing the average working interest in new wells drilled and as costs for drilling rigs, field services and equipment continue to increase.

     Cash flow from operating activities remains strong, increasing 34% over last year’s period. Capital expenditures for oil and gas activities for the 2006 nine-month period amounted to $17,357,602, as compared to $10,861,677 for the 2005 period. Management currently expects capital expenditures for oil and gas activities to be approximately $22,000,000 for fiscal 2006. This is after an announced increase of $6,000,000 in the 2006 capital expenditure budget. The substantial increase in capital expenditures is a result of increased drilling activity brought on by higher market prices for oil and gas in the last half of 2005 and early 2006 and increases in the costs of drilling and equipping wells. As drilling activity has increased, costs for drilling rigs, well equipment and services have increased, and are expected to remain so for the remainder of fiscal 2006. Any acquisitions of oil and gas properties would further increase the capital expenditure amount.

     The Company has historically funded capital expenditures, overhead costs and dividend payments from operating cash flow and has utilized, at times, the revolving line-of-credit facility to help fund these expenditures. With the recent decline in natural gas prices, which is expected to continue through the Company’s fiscal fourth quarter, some amounts may be borrowed on a temporary basis under the Company’s credit facility. The Company has substantial availability under its bank debt facility and the availability could be increased, if needed.

THREE MONTHS ENDED JUNE 30, 2006 — COMPARED TO THREE MONTHS ENDED JUNE 30, 2005

Overview:

     The Company recorded a third quarter 2006 net income of $2,078,878, or $.25 per diluted share, as compared to a net income of $3,419,419 or $.40 per diluted share in the 2005 quarter.

Revenues:

     Total revenues decreased $2,008,485 or 21% for the 2006 quarter. The decrease was primarily the result of a $1,825,743 decrease in lease bonus revenues. The decrease in lease bonus revenue resulted from the Company leasing all of its non-producing mineral acreage in the state of Arkansas in the 2005 period. The total lease bonus for this transaction, net of associated basis, was $1,879,467. Oil and gas sales revenues decreased $171,977 or 2% principally due to a $.61 decrease in the average sales price for natural gas. Oil sales volumes decreased 7% while gas sales volumes increased 3%. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three month periods of fiscal 2006 and 2005:

     The continuing increase in drilling expenditures and the Company’s stated goal of increasing its working interests in new wells drilled is expected to result in increased production volumes for gas in fiscal 2006 as compared to fiscal 2005. The Company’s drilling continues to be concentrated on gas production. New wells coming on line have basically replaced the decline in production of older wells. The Company expects to continue to have additional production come on line in the last quarter of 2006.

     The Company is a non-operator and obtaining timely production data and sales price information from most operators is not possible. This causes the Company to utilize past production receipts and estimated sales price information to estimate its oil and gas sales revenue accrual at the end of each quarterly period. The oil and gas sales accrual estimates are impacted by many variables including the initial high production from and the possible rapid decline rates of certain new wells and rapidly changing market prices for natural gas. The Company records an accrual to actual adjustment in each succeeding quarter. In July, 2006 the Company determined that its oil and gas revenue accrual estimate at March 31, 2006 was higher than actual production proceeds that have been received to date for the accrual period. The higher than actual oil and gas revenue accrual estimate was a result of the above variables. The effect of the accrual estimate change for the three months ended March 31, 2006 was that revenues and net income were approximately $460,000 and $165,000 higher, respectively, than actual results for those periods. Likewise, for the three months ended June 30, 2006, revenues and net income were lower by such amounts.

Lease Operating Expenses (LOE):

     LOE increased $162,413 or 24% in the 2006 quarter. The increase is the result of new larger ownership interest wells going on line in the 2006 quarter. New wells have higher operating costs the first several months of production. Additionally the number of wells in which the Company has a working interest, and thus pays LOE, continues to increase and general oilfield prices are rapidly increasing.

Production Taxes:

     Production taxes decreased $36,103 or 8% in the 2006 quarter. The decrease is principally the result of lower oil and gas revenues in the 2006 quarter, as production taxes are paid as a percentage of these revenues, and the Company received production tax credits on some properties.

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

     DD&A increased $425,925 or 22% in the 2006 quarter. The increase is a result of higher costs on newly completed wells resulting from increased ownership percentages and general oilfield price increases, which must be depreciated. Impairment charges in the 2005 quarter were $144,009 as compared to $32,158 in the 2006 quarter.

Loss on Sale of Assets:

     In the 2005 quarter a partnership interest and the associated producing wells were sold back to the operator resulting in a loss of approximately $200,000.

Interest Expense:

     Interest expense decreased in the 2006 quarter due to lower outstanding debt balances.

Income Taxes:

     The 2006 quarter provision for income taxes decreased due to lower income before provision for income taxes for the period and a reduction in the estimate of income before provision for income taxes for fiscal 2006 as compared to estimates made in prior periods. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate. The effective tax rate estimate was 26% for the 2006 period and 32% for the 2005 period.

NINE MONTHS ENDED JUNE 30, 2006 — COMPARED TO NINE MONTHS ENDED JUNE 30, 2005

Overview:

     The Company recorded a nine month period 2006 net income of $9,626,756, or $1.14 per diluted share, as compared to a net income of $7,443,412 or $.88 per diluted share in the 2005 period. The improved results were due to increased sales prices for both oil and natural gas and a slight increase in gas sales volumes; offset by a decrease in oil sales volumes and a decrease of $1,698,511 in lease bonus revenue.

Revenues:

     Total revenues increased $4,057,973 or 17% for the 2006 period. The increase was the result of a $5,616,406 increase in oil and natural gas sales revenues offset by a decline in lease bonus revenues of $1,698,511. The increase in oil and gas sales revenues resulted from a 28% and 25% increase in the average sales price for oil and natural gas, respectively. The Company expects natural gas prices to trend lower through the summer months, with oil prices continuing at a high level. Oil sales volumes decreased 10% while gas sales volumes increased 2%. The decrease in lease bonus revenue results from the Company leasing all of its non-producing mineral acreage in the state of Arkansas in the 2005 period. The total lease bonus, net of associated basis, was $1,879,467 as compared to normal leasing activity in the 2006 period. The table below outlines the Company’s production and average sales prices for oil and natural gas for the nine month periods of fiscal 2006 and 2005:

     The continuing increase in drilling expenditures and the Company’s stated goal of increasing its working interests in new wells drilled is expected to result in increased production volumes for gas in fiscal 2006, as compared to fiscal 2005. The Company’s drilling continues to be concentrated on gas production. The shortage of well completion equipment has resulted in longer times from well spud to first sales for new wells in fiscal 2006. New wells put on line in the remainder of 2006 should continue to replace the decline of existing well production.

Lease Operating Expenses (LOE):

     LOE increased $199,386 or 9% in the 2006 period. The increase is a result of new larger ownership interest wells going on line in the 2006 period, as new wells normally have higher operating costs the first several months of production, the continuing increase in the number of wells in which the Company has an interest and general oilfield price increases. In addition water disposal costs on one new well have been disproportionately high.

Production Taxes:

     Production taxes increased $282,957 or 21% in the 2006 period. The increase is the result of the higher oil and gas revenues in the 2006 period, as production taxes are paid as a percentage of these revenues.

Exploration Costs:

     These costs decreased $133,776 in the 2006 period. This decrease is principally the result of two higher cost exploratory dry holes drilled in the 2005 period as compared to one in the 2006 period. Also, the Company’s charge to exploration costs for leasehold deemed worthless or the lease term expired in the 2005 period exceeded the 2006 period by approximately $31,000.

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

     DD&A increased $1,481,265 or 27% in the 2006 period. The increase is a result of higher costs on newly completed wells resulting from increased ownership percentages and general oilfield price increases. These higher costs then must be depreciated. In addition, projected remaining production volumes were reduced on some wells, thus increasing current DD&A costs. One well with remaining basis of approximately $166,000 was fully amortized during the 2006 period as it was abandoned due to continued uneconomic production volumes. Impairment charges in the 2005 period were $185,703 as compared to $168,553 in the 2006 period.

General and Administrative Costs (G&A):

     G&A costs decreased $698,403 or 22% in the 2006 period. The decrease is the result of an amendment to the Directors’ Deferred Compensation Plan (the Plan). Effective October 19, 2005 the Plan was amended such that upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director. This amendment removed the conversion to cash option available under the Plan, which eliminated the requirement to adjust the deferred compensation liability for changes in the market value of the Company’s common stock after October 19, 2005. The adjustment of the liability to market value of the shares at the closing price on October 19, 2005 resulted in a credit to G&A of approximately $288,000 as compared to a charge of approximately $543,000 in the 2005 period. In addition, the deferred compensation liability after the October 19, 2005 adjustment was reclassified to stockholders’ equity. Personnel related costs increased in the 2006 period approximately $116,000.

Interest Expense:

     Interest expense decreased in the 2006 period due to lower outstanding debt balances.

Income Taxes:

     The 2006 period provision for income taxes increased due to increased income before provision for income taxes. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate. The effective tax rate estimate was 32% for the 2006 period and 32% for the 2005 period.

     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 provision for income tax. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists, consultants and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. The oil and gas sales revenue accrual is particularly subject to estimates due to the Company’s status as a non-operator on all of its properties. Production information obtained from well operators is substantially delayed. This causes the estimation of recent production, used in the oil and gas revenue accrual, to be subject to some variations.

Oil and Gas Reserves

     Of these judgments and estimates, management considers the estimation of crude oil and nature gas reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. Changes in crude oil and natural gas reserve estimates affect the Company’s calculation of depreciation, depletion and amortization, 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 SEC,

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 production and 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 property 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, principally oil and gas properties, 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 significant judgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil and gas, future production costs, 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.

Oil and Gas Sales Revenue Accrual

     The Company does not operate any of its oil and gas properties, and it primarily holds small interests in several thousand wells. Thus, obtaining timely production data from the well operators is extremely difficult. This requires the Company to utilize past production receipts and estimated sales price information to estimate its oil and gas sales revenue accrual at the end of each quarterly period. The oil and gas accrual can be impacted by many variables, including initial high production rates of new wells and subsequent rapid decline rates of those wells and rapidly changing market prices for natural gas. This could lead to an over or under accrual of oil and gas sales at the end of any particular quarter. Based on past history, the estimated accrual has been materially accurate.

Income Taxes

     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.

     The Company’s results of operations and operating cash flows can be significantly impacted by changes in market prices for oil and gas. Based on the Company’s 2005 production, a $.10 per Mcf change in the price received for natural gas production would result in a corresponding $401,000 annual change in pre-tax operating cash flow. A $1.00 per barrel change in the price received for oil production would result in a corresponding $101,500 annual change in pre-tax operating cash flow. Cash flows could also be impacted, to a lesser extent, 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%. However, at June 30, 2006, the Company had no balance outstanding under this facility. The Company has a $10,000,000 term loan with an outstanding balance of $3,666,654 at June 30, 2006 maturing on April 1, 2008. The interest rate is fixed at 4.56% until maturity.

     The Company maintains “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the

Exchange Act, that are designed to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including the Company’s Co-President/Chief Operating Officer and Co-President/Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The Company’s disclosure controls and procedures have been designed to meet, and management believes that they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this report, the Chief Operating Officer and Chief Financial Officer have concluded that, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure that material information relating to the Company, including its consolidated subsidiary, is made known to them. There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter or subsequent to the date the assessment was completed.

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.