PHX Minerals - 10-Q quarterly report FY

 

 

(Exact name of registrant as specified in its charter)

(Address of principal executive offices)

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.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

 

 

INDEX

PANHANDLE ROYALTY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS
(Information at June 30, 2005 is unaudited)

PANHANDLE ROYALTY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

PANHANDLE ROYALTY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

(See accompanying notes)

PANHANDLE ROYALTY COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

     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.

     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.

     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 (see NOTE 5).

     In February 2005, 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, 2007. 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% (5.5% at June 30, 2005) or LIBOR (for one, three or six month periods), plus 1.80%. The Company at June 30, 2005, had elected the prime rate option. At June 30, 2005, the Company had $5,666,658 outstanding under the term loan and $1,400,000 outstanding under the revolving loan. The revolving loan was paid off in July, 2005.

     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 share’s market value subsequent to the date of grant until the conversion date. 11,067 shares were issued in the 2005 nine month period upon the retirement of two directors.

     In June 2005 the Company leased all of its non-producing fee mineral acreage in the state of Arkansas for approximately $2 million. The Company recorded this transaction as lease bonus revenue, net of associated basis, and reflected the receivable in lease bonus and other receivables. The receivable was collected in July 2005. The leasing covered 442 tracts of minerals and totaled approximately 9,000 acres.

     Forward-Looking Statements for fiscal 2005 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.

     At June 30, 2005, the Company had positive working capital of $3,440,298, as compared to positive working capital of $1,941,634 at September 30, 2004. Receivables have increased due to higher oil and natural gas prices and the leasing, in the fiscal third quarter, of all the Company’s non-producing mineral acreage in Arkansas for approximately $2 million. The funds were received in the fiscal fourth quarter.

     Capital expenditures for oil and gas activities for the 2005 nine-month period amounted to $10,861,676, as compared to $6,986,931 for the 2004 period. Management currently expects capital expenditures for oil and gas activities to be approximately $13,000,000 for fiscal 2005. The substantial increase in capital expenditures is a result of increased drilling activity brought on by higher market prices for oil and gas and increases in the costs of drilling and equipping wells. As activity has increased, daily costs for drilling rigs, well completion services and well equipment has increased, and are expected to remain so for the remainder of fiscal 2005 and into fiscal 2006. Acquisitions of oil and gas properties in the nine month period were approximately $1,000,000 and are included in the above capital expenditure number. Currently, no further material acquisitions are planned for the remainder of fiscal 2005.

     The Company has historically funded capital expenditures, overhead costs and dividend payments from operating cash flow. Due to the increased capital expenditure level of fiscal 2005 the Company has utilized, at times, the revolving line-of-credit facility to help fund these expenditures. However, the increased cash flow from higher prices being received for natural gas and oil allowed the Company to reduce net outstanding bank borrowings by approximately $3,450,000 during the nine months. Management currently does not expect to borrow substantial funds under the revolving loan during the remainder of fiscal 2005, but amounts may be borrowed on a short-term basis. The Company currently has approximately $15 million available under its bank debt facility and the availability could be increased, if needed, should a large unplanned acquisition become available.

THREE MONTHS ENDED JUNE 30, 2005 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2004

Overview:

     The Company recorded a third quarter 2005 net income of $3,419,419, or $.81 per diluted share, as compared to a net income of $2,130,484 or $.50 per diluted share in the 2004 quarter. The larger net income was due to the leasing of all the Company’s non-producing mineral acreage in Arkansas, increased sales prices for oil and natural gas, offset by increased costs and expenses and slightly decreased sales volumes for oil and natural gas.

Revenues:

     Oil and gas sales revenues increased by $867,748 for the 2005 quarter. Sales volumes of oil and natural gas decreased slightly, however the average sales price of oil increased 36% while the average sales price of natural gas increased 13%. Lease bonus revenue increased $1,956,285 substantially all of which is due to the leasing of all of the Company’s non-producing mineral acreage in the state of Arkansas. The total lease bonus, net of associated basis, for the approximate 9,000 Arkansas acres was $1,879,467. Other revenues decreased due to the recording of a net loss on the disposition of certain insignificant assets. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three month periods of fiscal 2005 and 2004:

     Gas production volumes remained basically flat. Several gas wells completed in 2005 have begun production and have replaced production lost from normal production decline rates on the Company’s older wells. Also, the sale of the Company’s 1% interest in a New Mexico gas field in early fiscal 2005 has reduced 2005 gas sales volumes approximately 27,000 mcf for the quarter. Oil production volumes continue to decrease as most of the Company’s new drilling is for gas.

     The Company is a non-operator and obtaining timely production data from most operators is not possible. This causes the Company to utilize past production receipts to estimate its oil and gas sales revenue accrual at the end of each quarterly period. The oil and gas sales accrual estimates will be impacted by many variables including the initial high production from and the possible rapid decline rates of certain new wells and varying prices for oil and gas. Management believes the oil and gas sales accrual to be materially accurate.

Lease Operating Expenses (LOE):

     LOE increased $27,265 or 4% in the 2005 quarter. The increase is a result of additional wells going on line in the 2005 quarter resulting in the continuing increase in the number of wells in which the Company has an interest, general oil field price increases, and wells having production enhancement procedures done to maximize current production rates.

Production Taxes:

     Production taxes increased $17,593 in the 2005 quarter. The increase is the result of larger oil and gas sales revenues in the 2005 quarter, as production taxes are paid as a percentage of these revenues.

Exploration Costs:

     These costs decreased $147,799 in the 2005 quarter. This decrease is principally the result of two exploratory dry holes which were drilled in the fiscal 2004 quarter as compared to the 2005 quarter in which the Company had only one small interest exploratory well which resulted in a dry hole.

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

     DD&A increased $613,168 or 41% in the 2005 quarter. The increase is a result of rapid decline rates on many wells which have been drilled and gone on production in the last two years coupled with significantly higher costs on recently completed wells, which must then be depreciated. Additionally, the Company has larger interests in many of these wells. DD&A includes impairment charges of $144,009 for the 2005 quarter as compared to $45,091 in the 2004 quarter. The 2005 amount included impairment charges on one older field. A new well drilled to try to further develop the field proved to be uneconomical.

General and Administrative Costs (G&A):

     G&A costs increased $238,682 or 41% in the 2005 period. Approximately $160,000 of the increase was due to the Directors’ Deferred Compensation Plan. Panhandle’s share price increased during the 2005 quarter, thus, an increase on the potential shares in the plan was recognized as an expense in the quarter. Additionally, in the 2005 quarter costs for professional services increased approximately $40,000 and personnel related costs increased $30,000.

Interest Expense:

     Interest expense decreased in the 2005 quarter due to lower average outstanding debt balances.

Income Taxes:

     The 2005 quarter provision for income taxes increased due to larger income before provision for income taxes. The use of an excess percentage depletion election causes a reduction of the Company’s effective tax rate from the federal statutory rate. The effective tax rate estimate was 32% for the 2005 period and 37% for the 2004 period.

NINE MONTHS ENDED JUNE 30, 2005 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2004

Overview:

     The Company recorded a nine month 2005 net income of $7,443,412, or $1.76 per diluted share, as compared to a net income of $5,018,354 or $1.19 per diluted share in the 2004 period. The improved results were due to increased sales prices for both oil and natural gas, and increased gas sales volumes, offset by a 25% increase in costs and expenses and a 34% increase in the provision for income taxes. In addition the Company leased all of its non-producing mineral acreage in Arkansas in June 2005 for approximately $2 million.

Revenues:

     Total revenues increased $6,014,348 or 33% for the 2005 period. The increase was principally the result of a $4,217,796 increase in oil and natural gas sales revenues. The increase in oil and gas sales revenues primarily resulted from an 18% increase in the average sales price and a sales volume increase of 4% for natural gas. Oil production decreased 9%, however the average sales price increased 44%. The table below outlines the Company’s production and average sales prices for oil and natural gas for the nine month periods of fiscal 2005 and 2004:

     The decline in oil production is due to normal production declines of existing wells. New drilling is focused principally on gas. The increase in gas production is the result of a continuing increase in drilling activity brought on by higher product prices. Several wells that went on production in the period are expected to continue to generate production increases into fiscal 2006. The sale of the Company’s minor interest in a New Mexico gas field in early fiscal 2005 reduced the Company’s 2005 gas production volumes approximately 70,000 mcf.

     Lease bonus revenue increased $1,980,531 which was principally due to the leasing of all of the Company’s non-producing mineral acreage in the state of Arkansas. The total lease bonus, net of associated basis, for the approximate 9,000 Arkansas acres was $1,879,467.

Lease Operating Expenses (LOE):

     LOE increased $222,514 or 12% in the 2005 period. The increase is a result of additional wells going on line in the 2005 period, resulting in the continuing growth in the number of wells in which the Company has an interest, general oil field price increases, and wells having production enhancement procedures performed to maximize current production rates.

Production Taxes:

     Production taxes increased $247,379 or 22% in the 2005 period. The increase is the result of larger oil and gas revenues in the 2005 period, as production taxes are paid as a percentage of these revenues.

Exploration Costs:

     These costs increased $161,484 in the 2005 period. This increase is principally the result of one exploratory dry hole drilled early in the fiscal 2005 period with costs of $179,467 and certain of the Company’s leasehold was deemed worthless or the lease term expired in the 2005 period. In the 2004 period the Company had no high cost exploratory wells which resulted in dry holes.

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

     DD&A increased $1,165,900 or 26% in the 2005 period. The increase is a result of rapid decline rates on many wells which have been drilled and gone on production in the last two years coupled with higher costs on recently completed wells, which must then be depreciated. In addition, the Company has larger interests in many of those wells. Impairment charges were $185,703 for the 2005 period as compared to $289,659 in the 2004 period. The 2004 amount included impairment charges for two fields and one individual well. Increased market prices for oil and natural gas continue to lessen impairment charges.

General and Administrative Costs (G&A):

     G&A costs increased $906,480 or 39% in the 2005 period. Approximately $325,000 of the increase was due to the Directors’ Deferred Compensation Plan. Panhandle’s share price increased during the 2005 period, thus, an increase on the potential shares in the plan was recognized as an expense in the period. Additionally, in the 2005 period costs for professional services increased approximately $100,000 and personnel related costs increased approximately $200,000 (which included two new employees and general salary increases).

Interest Expense:

     Interest expense decreased in the 2005 period due to lower average outstanding debt balances.

Income Taxes:

     The 2005 period provision for income taxes increased due to larger income before provision for income taxes. The use of an excess percentage depletion election causes a reduction of the Company’s effective tax rate from the federal statutory rate. The effective tax rate estimate was 32% for the 2005 period and 33% for the 2004 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 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. 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. 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 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 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 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.

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 causes the Company to utilize past production receipts 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 and subsequent rapid decline rates of new wells.

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 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%. A one percent change in the prime interest rate would result in approximately a $14,000 change in annual interest expense.

     The Company has a $10,000,000 term loan, with a balance of $5,666,658 outstanding at June 30, 2005, which matures on April 1, 2008. The interest rate is fixed at 4.56% until maturity.

     The Company has not entered into hedging contracts on its oil and/or gas production in the past. However, going forward the Company may consider entering into hedging contracts if pricing is considered to be advantageous.

     Panhandle Royalty Company’s management, under the supervision of and with the participation of the Chief Executive Officer and Chief Financial Officer, has 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. The Company is working on its Sarbanes-Oxley Section 404 internal control review. As a result of the review several minor changes to internal controls are being implemented. However, there were no changes in internal controls that 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 Chief Executive Officer and Chief Financial Officer completed their evaluation.

     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.