PHX Minerals - 10-Q quarterly report FY2011 Q3

 

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INDEX

“Btu” means British thermal units, a measure of the heat value or energy content of fuel, particularly natural gas in this report;

“ESOP” refers to the Panhandle Oil and Gas Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan;

“FASB” means the Financial Accounting Standards Board;

“Independent Consulting Petroleum Engineer(s)” or “Independent Consulting Petroleum Engineering Firm(s)” refers to DeGolyer and MacNaughton of Dallas, Texas, for proved reserves calculated as of March 31, 2011, or to Pinnacle Energy Services, L.L.C. of Oklahoma City, Oklahoma, for proved reserves calculated as of March 31, 2010;

“Mcfe” means natural gas stated on an Mcf basis and crude oil converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil to six Mcf of natural gas;

“minerals”, “mineral acres” or “mineral interests” refers to fee mineral acreage owned in perpetuity by the Company;

“Mmbtu” means million Btu;

“NYMEX” refers to the New York Mercantile Exchange;

“PEPL” means Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline;

“play” is a term applied to identified areas with potential oil and/or natural gas reserves;

“SEC” means the United States Securities and Exchange Commission;

“working interest” refers to well interests in which the Company pays a share of the costs to drill, complete and operate a well and receives a proportionate share of production.

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Nine Months Ended June 30, 2011

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

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 of Panhandle Oil and Gas Inc. (the Company) have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission (SEC), and include the Company’s wholly-owned subsidiary, Wood Oil Company (Wood). Management of the Company believes that all adjustments necessary for a fair presentation of the consolidated financial position and results of operations and cash flows 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.

     Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes thereto included in the Company’s 2010 Annual Report on Form 10-K.

NOTE 2: Income Taxes

     The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits.

     Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume or income, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with the detail well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion benefits, when a provision for income taxes is recorded, decrease the effective tax rate (as is the case as of June 30, 2011 and 2010), while the effect is to increase the effective tax rate when a benefit for income taxes is recorded. The benefits of federal and Oklahoma excess percentage depletion are not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant.

NOTE 3: Basic and Diluted Earnings per Share

     Basic and diluted earnings per share is calculated using net income divided by the weighted average number of voting common shares outstanding, including unissued directors’ deferred compensation shares during the period.

NOTE 4: Long-term Debt

     The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan in the amount of $80,000,000 which is subject to a semi-annual borrowing base determination, wherein BOK applies their own current pricing forecast and a 9% discount rate to the Company’s proved reserves as calculated by the Company’s Independent Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to risk all proved non-producing and proved undeveloped reserves. The facility, which was undrawn at both June 30, 2011 and September 30, 2010, has a borrowing base of $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $28,094,833 at June 30, 2011. The facility matures on November 30, 2014. The interest rate is based on national prime plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced. The interest rate spread from national prime or LIBOR will be charged based on the percent of the value advanced of the calculated loan value of the Company’s oil and natural gas properties.

     Since the bank charges a customary non-use fee of .25% annually of the unused portion of the borrowing base, the Company has not requested the bank to increase its borrowing base beyond $35 million. Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At June 30, 2011, the Company was in compliance with the covenants of the BOK agreement.

NOTE 5: Deferred Compensation Plan for Directors

     The Company has a deferred compensation plan for non-employee directors (the Plan). The Plan provides that each eligible director can individually elect to receive shares of Company stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These shares are unissued and are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. 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.

NOTE 6: Restricted Stock Plan

     On March 11, 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 100,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. The 2010 Stock Plan is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

     In June 2010, the Company awarded 8,500 shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of five years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares at the time of their award, based on the closing price of the shares on their award date, was $240,550 and will be recognized as compensation expense ratably over the vesting period.

     On December 21, 2010, the Company awarded 8,780 shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of three years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares at the time of their award, based on the closing price of the shares on their award date, was $245,840 and will be recognized as compensation expense ratably over the vesting period.

     The impact of these awards on G&A expense in the quarter and nine months ended June 30, 2011 was $32,515 and $77,058, respectively. There was no such expense in the corresponding 2010 periods. As of June 30, 2011, there was $397,305 of total unrecognized compensation cost related to these awards. The cost is to be recognized over a weighted average period of 3.22 years. Upon vesting, shares are expected to be issued out of shares held in treasury.

     A summary of the status of unvested shares of restricted stock awards and changes during 2011 is presented below:

     On December 21, 2010, the Company also awarded 8,782 shares of the Company’s common stock, subject to certain share price performance standards, as restricted stock to certain officers. Vesting of these shares is based on the performance of the market price of the common stock over the vesting period (three years). The fair value of the performance shares was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period (three years) regardless of whether performance shares are awarded at the end of the vesting period. The impact of these awards on G&A expense in the quarter and nine months ended June 30, 2011 was $14,303 and $28,606, respectively. As of June 30, 2011, there was $143,030 of total unrecognized compensation cost related to this performance-based, restricted stock. The cost is to be recognized over a weighted average period of 2.49 years.

NOTE 7: Oil and Natural Gas Reserves

     Management considers the estimation of the Company’s crude oil and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a semi-annual

update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, 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. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing prices current with the period. As of September 30, 2010, the Company adopted the SEC Rule, Modernization of Oil and Gas Reporting Requirements. Accordingly, the estimated oil and natural gas reserves at June 30, 2011, were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil and natural gas price for each month within the 12-month period prior to June 30, 2011, held flat over the life of the properties. In accordance with SEC rules effective on June 30, 2010, current pricing of oil and natural gas on June 30, 2010, held flat over the life of the properties was used to estimate oil and natural gas reserves as of June 30, 2010. Crude oil and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. However, projected future crude oil and natural gas pricing assumptions are used by management to prepare estimates of crude oil and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.

NOTE 8: Impairment

     All long-lived assets, principally oil and natural 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 natural gas, future production costs, estimates of future oil and natural 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 natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing updated projected future price decks current with the period. As of the quarter and nine months ended June 30, 2011, the Company’s test for impairment resulted in a charge to impairment of $2,927 and $830,946, respectively. As of the quarter and nine months ended June 30, 2010, the Company’s test for impairment resulted in a charge to impairment of $0 and $12,370, respectively. A reduction in oil and natural gas prices or a decline in reserve volumes could lead to additional impairment that may be material to the Company.

NOTE 9: Derivatives

     The Company has entered into fixed swap contracts, basis protection swaps and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s natural gas production and provide only partial price protection against declines in natural gas prices. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL currently). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. Collar contracts set a fixed floor price and a fixed ceiling price 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 derivative instruments may expose the Company to risk of financial loss and limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are unsecured. The derivative instruments have settled or will settle based on the prices below which are adjusted for location differentials and tied to certain pipelines in Oklahoma.

Derivative contracts in place as of June 30, 2011
(prices below reflect the Company’s net price from the listed Oklahoma pipelines)

Derivative contracts in place as of September 30, 2010
(prices below reflect the Company’s net price from the listed Oklahoma pipelines)

     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 the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was

an asset of $271,449 as of June 30, 2011 and an asset of $1,620,326 as of September 30, 2010. Realized and unrealized gains and (losses) for the periods ended June 30, 2011 and June 30, 2010 are scheduled below:

     To the extent that a legal offset exists, the Company nets the fair value of its derivative contracts with the same counterparty in the accompanying balance sheets. The following table summarizes the Company’s derivative contracts as of June 30, 2011 and September 30, 2010:

     The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented.

NOTE 10: Exploration Costs

     In the quarter and nine month periods ended June 30, 2011, lease expirations and leasehold impairments of $305,156 and $455,486, respectively, were charged to exploration costs. Leasehold impairments are recorded for individually insignificant non-producing leases which the Company believes will not be transferred to proved properties over the remaining lives of the leases. In the quarter and nine month periods ended June 30, 2011, the Company also had additional costs of $112,899 and $540,026, respectively, related to exploratory dry hole expenses. In the quarter and nine months ended June 30, 2010, lease expirations and impairments of $163,131 and $1,040,055, respectively, were charged to exploration costs as well as additional costs of $375,131 related to exploratory geological and geophysical expenses and dry holes.

     Oil and natural gas properties include capitalized costs of $1,751,766 on exploratory wells which were drilling and/or testing at June 30, 2011. These wells are located in western Oklahoma where drilling has continued to increase in natural gas liquids-rich areas. The Company is expecting to have evaluation results on these wells within the next six months.

NOTE 11: Fair Value Measurements

     Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

     The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2011.

     A reconciliation of the Company’s assets classified as Level 3 measurements is presented below.

NOTE 12: Fair Values of Financial Instruments

     The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, refundable income taxes, accounts payable and accrued liabilities approximate their fair values due to the short maturity of these instruments. The fair value of the Company’s debt approximates its carrying amount, if any, due to the interest rates on the Company’s revolving line of credit being rates which are approximately equivalent to market rates for similar type debt based on the Company’s

credit worthiness.

NOTE 13: Recently Adopted Accounting Pronouncements

     In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-03 (“ASU 2010-03”) to align the oil and natural gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Industries — Oil and Gas, with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and was adopted on a prospective basis beginning in the fourth quarter of our fiscal year ended September 30, 2010. The Company implemented ASU 2010-03 prospectively as a change in accounting principle inseparable from a change in accounting estimate.

     Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the consolidated financial statements upon adoption.

NOTE 14: Subsequent Events

     Effective July 1, 2011, the Company’s wholly-owned subsidiary, Wood Oil Company (Wood) was merged into Panhandle Oil and Gas Inc. (Panhandle) and Panhandle will be the surviving corporation. The resolutions of Merger were approved and adopted by the Board of Directors of the Company on May 18, 2011.

     On July 29, 2011, the Company closed a $3.5 million acquisition of mineral acreage in the Fayetteville Shale resource play in Arkansas.

     Forward-Looking Statements for fiscal 2011 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 natural 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 natural gas reserves. Investors should also read the other information in this Form 10-Q and the Company’s 2010 Annual Report on Form 10-K where risk factors are presented and further discussed. 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.

     The Company had positive working capital of $9,026,717 at June 30, 2011 compared to $10,098,861 at September 30, 2010.

     Cash and cash equivalents were $5,623,125 as of June 30, 2011 compared to $5,597,258 at September 30, 2010, an increase of $25,867. Cash flows for the nine months ended June 30 are summarized as follows:

     Net cash provided (used) by:

     An increase of $10,277,032 in oil and natural gas property and equipment additions in the 2011 nine months, compared to the 2010 nine months is primarily the result of the continuing increase in drilling activity in western Oklahoma where we own substantial mineral and leasehold acreage in oil and natural gas liquids-rich areas such as the Anadarko (Cana) Woodford Shale, Horizontal Granite Wash, Cleveland, Tonkawa and other plays, combined with continued steady drilling activity in the Arkansas Fayetteville Shale area.

     Production for the nine months of 2011 was down approximately 2% compared to the nine months of 2010. Though we have experienced an increase in drilling activity in fiscal 2011, especially in the areas noted above, the increase has been slower materializing than anticipated. Thus, the normal decline of existing wells is exceeding new production coming on line at this point. However, as wells that are completing or drilling come on line, the new production from these wells is expected to move the Company’s production back to an upward trend. We expect this to occur either during the fourth quarter of 2011 or the first quarter of 2012.

     The Company has recently begun to pursue the purchase of additional mineral acreage, primarily within our core activity areas. The Company anticipates purchasing $5,000,000 - $8,000,000 of mineral acreage during the 2011 fourth quarter and to continue allocating capital for the purchase of mineral acreage in fiscal 2012. Therefore, management now expects additions to properties and equipment for oil and natural gas activities, which will include mineral acreage purchases, during fiscal 2011 to be in the upper $20 million range. It is important to note that, due to the Company not being the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of participation in drilling and completing new wells, and our associated capital expenditures, with certainty.

     We have executed fixed swap contracts covering 350,000 Mmbtu per month of our natural gas production from April 2011 through October 2011 at an average fixed price of $4.64 and have costless collar contracts covering 5,000 barrels per month of our crude oil production from April 2011 through December 2011 with a floor price of $100 per barrel and a ceiling price of $112 per barrel. Our expectation over the next six to eighteen months is for the price of natural gas per Mcf to average in the mid four dollar range. Based on the derivative contracts in place, combined with our price expectations, management continues to evaluate opportunities for product price protection by hedging the Company’s future oil and natural gas production.

     For the 2011 nine months, cash provided by operating activities exceeded capital expenditures by $3,482,704. This excess allowed us to pay our regular $.07 per share quarterly dividend and to make stock repurchases in the amount of $1,851,290. Looking forward, the Company expects to fund overhead costs, capital additions, stock repurchases and dividend payments primarily from cash flow and cash on hand. However, during times of oil and natural gas price decreases, or

increased expenditures for drilling, the Company has utilized its revolving line-of-credit facility to help fund these expenditures. The Company’s continued drilling activity and mineral acreage purchases, combined with normal delays in receiving first payments from new production, could result in future borrowings under the Company’s credit facility. The Company has availability ($35 million at June 30, 2011) under its revolving credit facility and is in compliance of its debt covenants (current ratio, debt to EBITDA, tangible net worth and dividends as a percent of operating cash flow). While the Company believes the availability could be increased (if needed) by placing more of the Company’s properties as security under the revolving credit facility, increases are at the discretion of the bank.

     Based on expected capital expenditure levels and anticipated cash flows for the remainder of fiscal 2011 and 2012, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund any acquisitions.

THREE MONTHS ENDED JUNE 30, 2011 - COMPARED TO THREE MONTHS ENDED JUNE 30, 2010

Overview:

     The Company recorded a third quarter 2011 net income of $2,650,429, or $.32 per share, compared to a net income of $1,511,300, or $.18 per share, in the 2010 quarter. The net income increase was due to increased oil and natural gas revenues, higher gains on derivative contracts and decreased DD&A partially offset by decreased lease bonuses, increased lease operating expenses and the recording of a benefit from the settlement of a lawsuit (recorded as a part of loss (gain) on asset sales, interest and other) in the 2010 third quarter. These items are further discussed below.

Oil and Natural Gas (and associated natural gas liquids) Sales:

     Oil and natural gas sales increased $1,530,679 or 16% for the 2011 quarter. Oil and natural gas sales were up due to 20% higher average natural gas prices and 31% higher average oil prices offset by decreases in natural gas volumes of 5% and oil volumes of 6%. The table below outlines the Company’s sales volumes and average sales prices for oil and natural gas for the three month periods of fiscal 2011 and 2010:

     Though we have been experiencing an increase in drilling activity, especially in horizontal western Oklahoma plays such as the Anadarko (Cana) Woodford Shale, Granite Wash, Cleveland and Tonkawa, the increase has been slower materializing than anticipated. Normal decline of existing wells is exceeding new production coming on line at this point in time; however, as wells that are completing or drilling come on line, new production from these wells is expected to move the Company’s production back to an upward trend. We expect this to occur either during the fourth quarter of 2011 or the first quarter of 2012.

     Production for the last five quarters was as follows:

Gains (Losses) on Derivative Contracts:

     At June 30, 2011, the Company’s fair value of derivative contracts was an asset of $271,449; whereas at June 30, 2010, the Company’s fair value of derivative contracts was an asset of $1,788,379. The Company had a net gain on derivative contracts of $344,856 in the 2011 quarter as compared to a net loss of $218,935 recorded in the 2010 quarter.

Lease Operating Expenses (LOE):

     LOE increased $530,199 or 32% in the 2011 quarter as compared to the 2010 quarter, and LOE per Mcfe increased in the 2011 quarter to $1.04 per Mcfe from $.75 per Mcfe in the 2010 quarter. Value based fees (primarily gathering, transportation and marketing costs) increased approximately $362,000 in the 2011 quarter compared to the 2010 quarter as a result of higher natural gas sales prices in the 2011 quarter compared to the 2010 quarter, combined with lower value based fees in the 2010 quarter. The 2010 quarter value based fees were lower due to the temporary shut-in of certain wells which normally incur high value based fees. The overall result was a $.19 per Mcfe increase in LOE related to value based fees. Value based fees are charged as a percentage of natural gas sales.

     The remaining LOE increase of approximately $168,000 relates to workover costs incurred during the 2011 quarter on several Arkansas Fayetteville Shale and Southeast Oklahoma Woodford Shale wells.

Production Taxes:

     Production taxes increased $31,632 or 13% in the 2011 quarter as compared to the 2010 quarter. Production taxes as a percentage of oil and natural gas sales decreased slightly from 2.5% in the 2010 quarter to 2.4% in the 2011 quarter. The low overall production tax rate is due to a large proportion of the Company’s natural gas revenues coming from horizontally drilled wells, which are eligible for either Oklahoma production tax credits or reduced Arkansas production tax rates.

     The production tax as a percentage of oil and natural gas sales was lower than normal for both the 2011 and 2010 quarters due to production tax refunds received during both quarters related to deep well production tax exemptions allowed by the state of Oklahoma. We do not accrue for these deep well production tax exemptions as the state of Oklahoma caps the refunds in total and proportionally allocates the total amount to all qualified deep wells in the state. Thus, estimation of a refund is impractical. Absent these refunds, the production tax as a percentage of oil and natural gas sales would have been 3.5% in the 2011 quarter and 3.4% in the 2010 quarter.

Exploration Costs:

     Exploration costs decreased $120,207 in the 2011 quarter as compared to the 2010 quarter. During the 2011 quarter, leasehold impairment and expired leasehold totaled $305,156 compared to $163,131 during the 2010 quarter, a $142,025 increase. Additional charges totaling $112,899 were recorded on two exploratory dry holes (which had exploration costs charged to them in previous quarters) during the 2011 quarter; whereas, in the 2010 quarter no exploratory dry holes were drilled. During the 2010 quarter, approximately $375,000 was charged to exploration costs related to geological and geophysical costs paid upon the execution of a joint exploration agreement with a privately held independent operator to explore for oil in eastern Oklahoma.

Depreciation, Depletion and Amortization (DD&A):

     DD&A decreased $1,505,263 or 29% in the 2011 quarter. DD&A in the 2011 quarter was $1.75 per Mcfe as compared to $2.34 per Mcfe in the 2010 quarter. DD&A decreased approximately $1,255,000 due to a $.59 decline in the DD&A rate per Mcfe. This rate decline was the result of an increase in the Company’s oil and natural gas reserves as of June 30, 2011, as compared to June 30, 2010. The oil and natural gas reserves increase resulted from upward performance revisions compared to a year ago combined with new additions to oil and natural gas reserve from newly completed wells with lower finding costs. The remaining change was caused by oil and natural gas production decreasing 5% in the 2011 quarter accounting for a decrease of approximately $250,000.

Income Taxes:

     Provision for income taxes increased in the 2011 quarter by $288,000, the result of a $1,427,129 increase in income before income taxes in the 2011 quarter, compared to the 2010 quarter. The effective tax rate for the 2011 and 2010 quarters was 28% and 33%, respectively. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both quarters.

NINE MONTHS ENDED JUNE 30, 2011 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2010

Overview:

     The Company recorded a nine month period 2011 net income of $5,849,531, or $.70 per share, as compared to a net income of $8,383,244, or $1.00 per share, in the 2010 period. The decrease in net income was principally due to substantially lower gains on derivative contracts, decreased lease bonuses and an increased provision for impairment. These items were partially offset by a decrease in DD&A expense and a decrease in provision for income taxes. These items are further

discussed below.

Oil and Natural Gas (and associated natural gas liquids) Sales:

     Oil and natural gas revenues decreased $1,151,239 as a result of reductions in average natural gas prices of 7% and natural gas volumes of 2%, partially offset by increases in average oil prices of 20% and oil volumes of 1%. The table below outlines the Company’s sales volumes and average sales prices for oil and natural gas for the nine month periods of fiscal 2011 and 2010:

     Though we have been experiencing an increase in drilling activity, especially in horizontal western Oklahoma plays such as the Anadarko (Cana) Woodford Shale, Granite Wash, Cleveland and Tonkawa, the increase has been slower materializing than anticipated. Normal decline of existing wells is exceeding new production coming on line at this point in time; however, as wells that are completing or drilling come on line, new production from these wells is expected to move the Company’s production back to an upward trend. We expect this to occur either during the fourth quarter of 2011 or the first quarter of 2012.

Gains (Losses) on Derivative Contracts:

     The fair value of derivative contracts was $271,449 as of June 30, 2011 and $1,788,379 as of June 30, 2010. The Company had a net gain of $332,183 in the nine months ended June 30, 2011 compared to a gain of $5,410,714 for the nine months ended June 30, 2010. The Company received net cash payments (realized gains) of $1,681,060 and $1,108,900 for the 2011 and 2010 periods, respectively.

Lease Operating Expenses (LOE):

     LOE increased $325,528 or 5% in the 2011 period. LOE increased in the fiscal 2011 period to $1.00 per Mcfe compared to $.93 per Mcfe in the 2010 period. The total LOE increase and the LOE per Mcfe increase are primarily related to increased field operating costs of approximately $270,000 in the 2011 period compared to the 2010 period. Field operating costs were $.46 per Mcfe in the 2011 period compared to $.41 per Mcfe in the 2010 period, a 12% increase. These increases are due to several workovers experienced in the 2011 period.

     Value based fees increased $.02 per Mcfe in the 2011 period to $.54 per Mcfe, which accounts for the remaining LOE increase of approximately $56,000.

Exploration Costs:

     Exploration costs decreased $419,513 in the 2011 period compared to the 2010 period. During the 2011 period, leasehold impairment and expired leasehold totaled $455,486 compared to $1,040,055 during the 2010 period, a $584,569 decrease. The decline was driven by lower expected future lease expirations as of June 30, 2011, as compared to June 30, 2010. Charges on two exploratory dry holes totaled $540,026 during the 2011 period; whereas, in the 2010 period the Company recorded a credit to exploratory dry holes of $150. During the 2010 quarter, approximately $375,000 was charged to exploration costs related to geological and geophysical costs paid upon the execution of a joint exploration agreement with a privately held independent operator to explore for oil in eastern Oklahoma.

Depreciation, Depletion and Amortization (DD&A):

     DD&A decreased $5,215,842 or 33% in the 2011 period. DD&A was $1.66 per Mcfe in the 2011 period compared to $2.42 per Mcfe in the 2010 period. The majority of the DD&A decrease (approximately $4,937,000) is attributable to the $.76 decline in the DD&A rate per Mcfe. This rate decline was a result of increased oil and natural gas reserves as of June 30, 2011, as compared to June 30, 2010. The oil and natural gas reserves increase resulted from upward performance revisions compared to a year ago combined with new additions to oil and natural gas reserve from newly completed wells with lower finding costs.

Provision for Impairment:

     The provision for impairment increased $818,576 in the 2011 period compared to the 2010 period. During the 2011 period, impairment of $830,946 was recorded on five fields in Oklahoma and Texas. These fields have few wells and are more

susceptible to impairment when a well in the field experiences downward reserve revisions. During the 2010 period, impairment of $12,370 was recorded on one field.

     Included in the 2011 total above, is an impairment charge of $434,307 on the Joiner City prospect, a horizontal Woodford Shale prospect in the oil and natural gas liquids-rich Marietta Basin in southern Oklahoma. The first well was drilled and completed during the first quarter of 2011 and is currently producing commercial quantities of oil and natural gas and production volumes are being evaluated. As of June 30, 2011, this well had a net book value of $888,816 after impairment. Costs on this well were extraordinarily high due to this well being the first horizontal well drilled in the field. Continued development in the field is currently being evaluated.

General and Administrative Costs (G&A):

     G&A costs increased $175,695 or 4% in the 2011 period. The increase is primarily related to increases in the following expense categories: personnel $208,962, computer consulting fees $35,000 and reservoir engineering fees $58,225, partially offset by a decrease in legal fees of $87,073.

Income Taxes:

     The fiscal 2011 period provision for income taxes of $2,116,000 was a result of a pre-tax income of $7,965,531 as compared to a provision for income taxes of $3,257,000 in the fiscal 2010 period resulting from a pre-tax income of $11,640,244. The $1,141,000 income tax provision decrease is primarily due to a $3,674,713 decrease in income before provision for income taxes in the 2011 period compared to the 2010 period. The effective tax rates for the 2011 and 2010 periods were 27% and 28%, respectively. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both the 2011 and the 2010 periods.

     Critical accounting policies are those the Company believes are most important to portraying its financial conditions and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. There have been no material changes to the critical accounting policies previously disclosed in the Company’s Form 10-K for the fiscal year ended September 30, 2010.

     Market Risk

     Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of natural gas and oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in oil or natural gas liquids prices. Longer term natural gas prices will be determined by the supply of and demand for natural gas as well as the prices of competing fuels, such as crude oil and coal. The market price of natural gas, oil and natural gas liquids in 2011 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2011 derivative contracts, based on the Company’s estimated natural gas volumes for 2011, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $855,000 of pre-tax operating income. Based on the Company’s estimated oil volumes for 2011, the price sensitivity in 2011 for each $1.00 per barrel change in wellhead oil price is approximately $123,000 of pre-tax operating income.

     Commodity Price Risk

     The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. As of June 30, 2011, the Company has fixed price swaps, basis protection swaps and oil collars in place. All of our outstanding derivative contracts are with one counterparty and are unsecured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas and oil prices. These derivative contracts may expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s fixed price swaps, a change of $.10 in the forward strip prices would result in a change to pre-tax operating income of approximately $139,000. For the Company’s basis protection swaps, a change of $.10 in the basis differential from NYMEX and the indexed pipelines would result in a change to pre-tax operating income of approximately $382,000. For the Company’s oil collars, a change of $1.00 in the forward strip prices would result in a change to pre-tax operating income of approximately $27,000.

     Financial Market Risk

     Operating income could also be impacted by changes in the market interest rates related to the Company’s credit facilities if borrowing becomes necessary to fund expenditures. The revolving loan bears interest at the national prime rate plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. At June 30, 2011, the Company had $0 outstanding under these facilities. At this point, the Company does not believe that its liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that its liquidity will be impacted in the near future.

     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 President/Chief Executive Officer and Vice 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 Executive Officer and Chief Financial Officer have concluded that, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective, at the reasonable assurance level, 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.

          During the three months ended June 30, 2011, the Company repurchased shares of the Company’s common stock as summarized in the table below.

          Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board of Directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. Pursuant to previously adopted board resolutions, the purchase of an additional $1.5 million of the Company’s common stock became authorized and approved effective March 29, 2011. The shares are held in treasury and are accounted for using the cost method.

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.