PHX Minerals - 10-Q quarterly report FY

 

(Exact name of registrant as specified in its charter)

(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 6, 2007: 8,422,529

 

 

INDEX

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(Information at June 30, 2007 is unaudited)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

PANHANDLE OIL AND GAS INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)
Nine Months Ended June 30, 2007

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(See accompanying notes)
PANHANDLE OIL AND GAS INC.

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 Oil and Gas Inc. (formerly 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 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

     Earnings per share is calculated using net income divided by the weighted average number of common shares outstanding (including unissued, vested directors’ shares (77,119 and 76,339 for the three months and nine months ended June 30, 2007, respectively and 69,436 and 67,973 for the three months and nine months ended June 30,2006, respectively) after October 19, 2005 – see Note 7) during the period.

NOTE 5: Long-term Debt

     In October 2006, the Company refinanced its credit facility with BancFirst of Oklahoma City, Oklahoma with a credit facility from Bank of Oklahoma (BOK). The BOK Agreement consisted of a term loan in the amount of $2,500,000 and a revolving loan in the amount of $50,000,000 which is subject to a semi-annual borrowing base determination. The current borrowing base under the BOK Agreement is $10,000,000. The term loan matures on September 1, 2007, and the revolving loan matures on October 31, 2009. Monthly payments, which began December 1, 2006, on the term loan are $250,000, plus accrued interest. Borrowings under the revolving loan are due at maturity. The term loan bears interest at 30 day LIBOR plus .75%. The revolving loan bears interest at the national prime rate minus from 1.375% to .75%, or 30 day LIBOR plus from 1.375% to 2.0%. The interest rate charged will be based on the percent of the value advanced of the calculated loan value of Panhandle’s oil and gas reserves. The interest rate spread from LIBOR or prime increases as a larger percent of the loan value of Panhandle’s oil and gas properties is advanced. At June 30, 2007 the interest rate for the term note was 6.07% and for the revolving loan was 6.695%.

NOTE 6: Deferred Compensation Plan for Directors

     No shares were issued under the Plan in the 2007 period. 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 reduced 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 $1,168,312 on exploratory wells which were drilling and/or testing at June 30, 2007.

NOTE 8: Derivatives

     The Company periodically utilizes certain derivative contracts, including collars, to reduce its exposure to unfavorable changes in natural gas prices. Volumes under such contracts do not exceed expected production. The Company’s collars contain a fixed floor price and a fixed ceiling price. If market prices exceed the ceiling price or fall below the floor, then the Company will receive the difference between the floor and market price or pay the difference between the ceiling and market price. If market prices are between the ceiling and the floor, then no payments or receipts related to the collars are required.

     The Company accounts for its derivative contracts under Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (SFAS No. 133). Under the provision of SFAS No. 133, the Company is required to recognize all derivative instruments as either assets or liabilities in the consolidated balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is required to be measured at least quarterly based on relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. For derivative instruments not designated as hedging instruments, the change in fair value is recognized in earnings during the period of change as a change in derivative fair value. Amounts recorded in unrealized gains (losses) on derivative activities do not represent cash gains or losses. Rather, these amounts are temporary valuation swings in contracts that are not entitled to receive hedge accounting treatment.

     The Company had not, through fiscal 2006, entered into derivative instruments to hedge the price risk on its oil or gas production. Beginning in fiscal year 2007, the Company has entered in costless collar arrangements intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. Collar contracts set a minimum price, or floor and provide for payments to the Company if the basis adjusted price falls below the floor or require payments by the Company if the basis adjusted price rises above the ceiling. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These economic hedging arrangements may expose the Company to risk of financial loss and limit the benefit of future increases in prices. The derivative instruments will settle based on the prices below which are tied to indexes for certain pipelines in Oklahoma.

     In December 2006, the Company entered into the following three natural gas collar contracts.

     In March 2007, the Company entered into the following three additional natural gas collar contracts.

     While the Company believes that its derivative contracts are effective in achieving the risk management objective for which they were intended, the Company has elected not to complete all of the documentation requirements necessary under SFAS No. 133 to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was $446,581 as of June 30, 2007 (none as of June 30, 2006) resulting in net unrealized gains of $446,581 and realized gains of $141,600 in the nine months ended June 30, 2007.

NOTE 9: Exploration Costs

     Certain non-producing leases (aggregate carrying value of $180,145) which have expired and certain non-producing leases (aggregate carrying value of $260,482) which have no future plan of development were fully impaired in fiscal 2007 and charged to exploration costs. In addition, one large cost exploratory dry hole ($493,776 in cost) was charged to exploration costs in 2007.

NOTE 10: Reserve Estimation

     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 semi-annual update, the Company’s consulting engineer (the Company employed a new consulting engineer beginning with the March 31, 2007 semi-annual update), with assistance from Company geologists, prepares estimates of crude oil and natural gas reserves. 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.

     In the March 31, 2007 reserve report, changes in approximately fifty of the Company’s over 1,250 working interest wells reserve evaluations were reduced significantly enough by the Company’s new consulting engineer to result in significant additional DD&A charges on those wells.

     The net carrying value of the Company’s oil and gas properties is compared to the estimated future net cash flows from those properties on a field by field basis. Those fields on which the carrying value exceeds the estimated future net cash flows are then impaired to the 10% discounted amount of the estimated future net cash flows, the Company’s assumed fair value of those fields. Projected future crude oil and natural gas pricing assumptions are based on NYMEX futures contract prices adjusted for an average Oklahoma sales price differential. These prices are then used in the above discussed calculation of estimated future net cash flows. Lower reserve estimates, and associated estimated future net cash flow, on certain wells with declining production resulted in $1,100,000 of impairment on one western Oklahoma field.

     Forward-Looking Statements for fiscal 2007 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, 2007, the Company had positive working capital of $6,003,932, as compared to positive working capital of $4,997,714 at September 30, 2006. The increase results from increased cash and oil and gas sales receivable and a decrease in debt due within one year, offset by increased accounts payable which is the result of increased capital spending for oil and gas activities.

     Cash flow remains strong. Additions to properties and equipment for oil and gas activities for the 2007 nine-month period amounted to $19,742,549. Management currently expects capital expenditures for oil and gas activities of approximately $29,000,000 for fiscal 2007. The substantial increase in capital spending is a result of elevated drilling activity combined with the continuation of management’s strategy to participate in new wells with larger working interests resulting in an increase in the Company’s average overall working interest percentage. Drilling in the Woodford Shale unconventional resource play in southeast Oklahoma and in the Atoka play in the Dill City, Oklahoma area are and will continue to be a large component of expected capital additions for the next several years. As drilling activity remains high, costs for drilling rigs, well equipment and services remain high, and are expected to remain so for the remainder of fiscal 2007. Any acquisitions of oil and gas properties would further increase the capital addition amount.

     The Company has historically funded capital additions, overhead costs and dividend payments from operating cash flow and has utilized, at times, its revolving line-of-credit facility to help fund these expenditures. With the uncertainty of natural gas prices, and their effect on cash flow, some amounts have been and will be in the next several quarters 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. In addition, the Company has entered into natural gas collar contracts (discussed in Note 8 above) to help guard against potential negative price fluctuations which would reduce capital available for drilling new oil and gas wells.

THREE MONTHS ENDED JUNE 30, 2007 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2006

Overview:

     The Company recorded a third quarter 2007 net income of $2,904,078, or $.34 per share, as compared to a net income of $2,078,878 or $.25 per share in the 2006 quarter.

Revenues:

     Total revenues increased $3,573,740 or 48% for the 2007 quarter. The increase was primarily the result of a $3,096,312 increase in oil and gas sales resulting from a 24% increase in gas sales volumes for the 2007 quarter combined with an 18% increase in gas sales prices. Oil sales volumes increased 45% in the 2007 quarter, partially offset by an 8% decline in oil prices. Realized and unrealized gains on natural gas collar contracts amounted to $560,972 of the increase. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three month periods of fiscal 2007 and 2006:

     The continuing increase in drilling expenditures and the Company’s stated goal of increasing its working interests in new wells drilled continues to result in increased production volumes for gas, as compared to fiscal 2006. The completion of the Thomas 1-7 well (located in the Dill City, Oklahoma area) during the third quarter of 2007 added 8,700 barrels of oil and 153,000 mcf of gas sold for the third quarter 2007, comprising 89% and 64%, respectively, of the oil and gas volume increases over the 2006 period. The Company’s drilling continues to be concentrated on gas production. New wells coming on line are replacing the decline in production of older wells, and the Company expects to continue to have additional new production come on line in future periods.

     Production by quarter for the last five quarters was as follows:

Realized and Unrealized Gains on Natural Gas Collar Contracts:

     The Company’s fair value of derivative contracts was $446,581 as of June 30, 2007 (none as of June 30, 2006) resulting in an unrealized gain of $468,572 in the three months ended June 30, 2007. The Company received cash payments of $92,400 (realized gains) in the three months ended June 30, 2007 under the contracts.

Gain on asset sales, interest, income of partnerships and other:

     These items increased $54,196 in the 2007 period. Settlement of the L. Kelly 1-19 lawsuit at an amount less than the amount accrued resulted in income of $71,903. Partnership income increased $15,172 in the 2007 quarter due to higher natural gas prices. Gains on asset sales in the 2006 quarter partially offset these 2007 increases.

Lease Operating Expenses (LOE):

     LOE increased $59,793 or 7% in the 2007 quarter. LOE per mcfe decreased to $.62 per mcfe, as compared to $.73 per mcfe in the 2006 quarter. The increase in LOE is the result of additional completed wells being added over the last year. The decrease in per mcfe amounts result from significant production increases in the 2007 quarter more than offsetting continued high general oilfield service and supply prices.

Production Taxes:

     Production taxes increased $322,052 or 81% in the 2007 quarter. The increase is the result of approximately $66,000 of production tax credits received in the 2006 quarter compared to approximately $7,000 in the 2007 quarter. The remainder of the increase is the result of higher oil and gas revenues in the 2007 quarter, as production taxes are paid as a percentage of these revenues.

Exploration Costs:

     These costs increased $194,789 in the 2007 quarter. The 2007 and 2006 costs relate to non-producing leasehold that has either expired or is abandoned. No exploratory dry holes were recorded in the 2007 or 2006 period.

Depreciation, Depletion and Amortization (DD&A):

     DD&A increased $1,243,439 or 52% in the 2007 quarter to $2.54 per mcfe as compared to $2.12 per mcfe in the 2006 quarter. Due to significant reserve reductions on approximately fifty of the Company’s working interest wells, elevated DD&A costs are being experienced on these wells and are expected to continue through the remainder of fiscal 2007. The additional DD&A for the third quarter 2007 on these wells is approximately $500,000. In addition, the overall general price increases in drilling costs, completion costs and equipment costs the last few years continues to increase per mcfe DD&A costs.

Provision for Impairment:

     The provision for impairment increased $365,875 in the 2007 quarter. Approximately $390,000 of the 2007 quarter impairment provision relates to a Wolfcamp field in New Mexico which has thus far been uneconomical. In the 2006 quarter, one field consisting of one well was impaired approximately $32,000.

General and Administrative Costs (G&A):

     G&A costs increased $84,869 or 10% in the 2007 quarter principally due to increased personnel related costs.

Income Taxes:

     The 2007 quarter provision for income taxes increased due to higher income before provision for income taxes and an increase in the effective tax rate from 26% in the 2006 quarter to 30% for the 2007 quarter. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate.

NINE MONTHS ENDED JUNE 30, 2007 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2006

Overview:

     The Company recorded a nine month period 2007 net income of $4,668,826, or $.55 per share, as compared to a net income of $9,626,756 or $1.14 per share in the 2006 period.

Revenues:

     Total revenues decreased $286,817 or 1% for the 2007 period. The decrease is principally the result of a 17% decline in the average sales price for natural gas in the 2007 period somewhat offset by a 17% increase in natural gas sales volumes in the 2007 period. The Company currently expects natural gas prices to remain somewhat lower for the upcoming summer months with oil prices expected to somewhat trend upward during the summer months. Oil sales volumes increased 7% and the average sales price decreased 5%. The table below outlines the Company’s production and average sales prices for oil and natural gas for the nine month periods of fiscal 2007 and 2006:

     The continuing increase in drilling activities and the Company’s stated goal of increasing its working interests in new wells drilled is expected to continue to result in increased production volumes of natural gas in fiscal 2007 as compared to fiscal 2006. The completion of the Thomas 1-7 well (located in the Dill City, Oklahoma area) during the third quarter of 2007 added 8,700 barrels of oil and 153,000 mcf of gas sold for the 2007 period. New drilling continues to be concentrated on gas reserves. During the last year, new wells coming on line have more than replaced the decline in production of older wells. The Company expects to continue to have additional production come on line in future periods.

Realized and Unrealized Gains on Natural Gas Collar Contracts:

     The Company’s fair value of derivative contracts was $446,581 as of June 30, 2007 (none as of June 30, 2006) resulting in unrealized gains of $446,581 in the nine months ended June 30, 2007. The Company received cash payments of $141,600 (realized gains) in the nine months ended June 30, 2007 under the contracts.

Gain on asset sales, interest, income of partnerships and other:

     These items decreased $280,628 in the 2007 period as compared to the 2006 period as certain fee mineral acreage was sold in the 2006 period resulting in a gain of approximately $134,000. Partnership income decreased $151,206 in 2007 due to lower natural gas prices.

Lease Operating Expenses (LOE):

     LOE increased $271,187 or 12% in the 2007 period. LOE per mcfe decreased to $.64 per mcfe, as compared to $.67 per mcfe in the 2006 period. The increase in LOE is primarily the result of newly completed wells added in the 2007 period. The LOE per mcfe decrease is due to newly completed high production wells which have added a greater proportion of production volume than LOE.

Production Taxes:

     Production taxes increased $108,812 or 7% in the 2007 period. The increase is the result of 2006 expense being reduced by production tax credits received in the 2006 period.

Exploration Costs:

     These costs increased $732,409 in the 2007 period. This increase is principally the result of one exploratory dry hole drilled in the 2007 period in the Mystic Bayou prospect in Louisiana at an expense of approximately $475,000 versus one exploratory dry hole drilled in the 2006 period at an expense of approximately $126,000. The remaining increase is due to 2007 charges for expired and abandoned leasehold of approximately $460,000 versus approximately $76,000 for the 2006 period.

Depreciation, Depletion and Amortization (DD&A):

     DD&A increased $3,515,187 or 50% in the 2007 period to $2.58 per mcfe as compared to $1.99 per mcfe in the 2006 period. In the period ended March 31, 2007, approximately fifty of the Company’s over 1,250 working interest wells reserve evaluations were reduced significantly by the Company’s consulting engineer resulting in significant additional DD&A charges on those wells totaling approximately $2,000,000 through June 30, 2007. Due to these reserve reductions, elevated DD&A costs are expected on these wells through the remainder of fiscal 2007. In addition, overall general price increases in drilling costs, completion costs and equipment costs the last few years continues to increase per mcfe DD&A costs.

Provision for Impairment:

     The provision for impairment increased $1,859,313 in the 2007 period. Approximately $1,100,000 of the impairment provision relates to one field in western Oklahoma, in which the majority of the wells were drilled in the 2003-2006 time period. These wells continue to suffer production declines, and thus lower reserve estimates, which decreases future cash flow estimates resulting in the asset carrying value impairment. Additionally, one New Mexico field was impaired in the 2007 period for approximately $390,000.

General and Administrative Costs (G&A):

     G&A costs increased $510,924 or 20% in the 2007 period. The increase is principally 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 $282,000 in the 2006 period. In addition, the deferred compensation liability after the October 19, 2005 adjustment was reclassified to stockholders’ equity. Other G&A costs increasing in the 2007 period included personnel related costs of $121,261 and professional fees of $82,445.

Income Taxes:

     The 2007 period provision for income taxes decreased due to reduced 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 was 31% for the 2007 period and 32% for the 2006 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 semi- annual update, the Company’s consulting engineer (the Company employed a new consulting engineer beginning with the March 31, 2007 semi-annual update), 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 estimated 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 can not 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 2006 production, a $.10 per Mcf change in the price received for natural gas production would result in a corresponding $430,000 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 $97,100 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 the national prime rate minus from 1.375% to .75% or 30 day LIBOR plus from 1.375% to 2.0%. At June 30, 2007 the Company had $2,779,967 outstanding under this facility. The Company has a $2,500,000 term loan with an outstanding balance of $749,946 at June 30, 2007 maturing on September 1,

2007. The interest rate is 30 day LIBOR plus .75%. Based on total debt outstanding at June 30, 2007 a .5% change in interest rates would result in a $17,600 annual change in pre-tax operating cash flow.

     The Company periodically utilizes certain derivative contracts, including collars, to reduce its exposure to unfavorable changes in natural gas prices. Volumes under such contracts do not exceed expected production. The Company’s collars contain a fixed floor price and a fixed ceiling price. If market prices exceed the ceiling price or fall below the floor, then the Company will receive the difference between the floor and market price or pay the difference between the ceiling and market price. If market prices are between the ceiling and the floor, then no payments or receipts related to the collars are required. The Company had not, through fiscal 2006, entered into derivative instruments to hedge the price risk on its oil or gas production. Beginning in fiscal year 2007, the Company has entered in costless collar arrangements intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. Collar contracts set a minimum price, or floor and provide for payments to the Company if the basis adjusted price falls below the floor or require payments by the Company if the basis adjusted price rises above the ceiling. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These economic hedging arrangements may expose the Company to risk of financial loss and limit the benefit of future increases in prices.

     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 Executive 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.