PHX Minerals - 10-Q quarterly report FY

 

(Exact name of registrant as specified in its charter)

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            No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

o Yes            No o

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

     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 May 6, 2011:8,265,260

INDEX

The following defined terms are used in this report:

“Board” means board of directors;

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

“CEGT” means Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma;

“DD&A” means depreciation, depletion and amortization;

“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;

“LOE” means lease operating expense;

“Mcf” means thousand cubic feet;

“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;

All references to natural gas reserves, sales and prices include associated natural gas liquids.

PART 1 FINANCIAL INFORMATION
PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(Information at March 31, 2011 is unaudited)

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Information at and for the six months ended March 31, 2011 is unaudited)

(See accompanying notes)

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)

     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.

     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 March 31, 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.

     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. The unvested restricted stock discussed in NOTE 7 is not included in diluted earnings per share because the effect is not dilutive.

     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 has a borrowing base of $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $28,999,670 at March 31, 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 March 31, 2011, the Company was in compliance with the covenants of the BOK agreement.

     On December 8, 2010, the Company’s Board of Directors approved payment of a $.07 per share dividend to be paid on March 10, 2011 to shareholders of record on February 24, 2011.

     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.

     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.

     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. Dividends expected to be paid are $.07 per share each quarter. 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 non performance based awards on G&A expense in the quarter and six months ended March 31, 2011 was $12,028 and $32,515, respectively. There was no such expense in the corresponding 2010 periods. As of March 31, 2011, there was $429,820 of total unrecognized compensation cost related to these awards. The cost is to be recognized over a weighted average period of 3.47 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 six months ended March 31, 2011 was $14,303. As of March 31, 2011, there was $157,333 of total unrecognized compensation cost related to this performance-based, restricted stock. The cost is to be recognized over a weighted average period of 2.73 years.

     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 March 31, 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 March 31, 2011, held flat over the life of the properties. In accordance with SEC rules effective on March 31, 2010, current pricing of oil and natural gas on March 31, 2010, held flat over the life of the properties was used to estimate oil and natural gas reserves as of March 31, 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.

     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. The assessment through March 31, 2011 resulted in a charge to impairment of $828,019. As of the quarter and six months ended March 31, 2010, the Company’s test for impairment resulted in a charge to impairment of $12,370. 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.

     Oil and natural gas properties include costs of $406,674 on exploratory wells which were drilling and/or testing at March 31, 2011. The Company is expecting to have evaluation results on these wells within the next six months.

     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 March 31, 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 all of 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 $121,803 as of March 31, 2011 and an asset of $1,620,326 as of September 30, 2010. Realized and unrealized gains and (losses) for the periods ended March 31, 2011 and March 31, 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 March 31, 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.

     In the quarter and six month period ended March 31, 2011, lease expirations and leasehold impairments of $77,247 and $150,331, 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 six month period ended March 31, 2011, the Company also had additional costs of $213,106 and $427,127, respectively, related to exploratory dry hole adjustments. In the quarter ended March 31, 2010, lease expirations and impairments of $300,391 were charged to exploration costs as well as additional costs of $111 related to exploratory dry holes.

     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 March 31, 2011.

Level 2 — Market Approach — The fair values of the Company’s natural gas swaps are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas curves, or can be corroborated from active markets. These values are based upon, among other things, future prices and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

Level 3 — The fair values of the Company’s oil collar contracts are based on a pricing model which utilizes inputs that are unobservable or not readily available in the public market. These values are based upon, among other things, future prices, volatility, and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

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

(a) At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil and natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. As a result, the Company recorded $828,019 in impairment charges during 2011.

     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 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.

     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.

     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 $10,429,287 at March 31, 2011 compared to $10,098,861 at September 30, 2010.

     Cash and cash equivalents were $5,888,029 as of March 31, 2011 compared to $5,597,258 at September 30, 2010, an increase of $290,771. Cash flows for the six months ended March 31 are summarized as follows:

Net cash provided (used) by:

Operating activities:

The increase of $2,002,923 in cash provided by operating activities is primarily the effect of the following:

Increased collections of oil and natural gas sales for the 2011 period compared the 2010 period resulted in additional cash provided by operating activities of approximately $1.2 million.

Higher realized gains on derivative contracts during 2011, compared to 2010, increased cash provided by operating activities by $1,674,450. Net realized gains on derivative contracts was $1,485,850 during the six months ended March 31, 2011, compared to net realized losses of $188,600 during the six months ended March 31, 2010.

Cash expenditures for lease operating expenses increased approximately $600,000 in the 2011 period compared to the 2010 period.

Investing activities:

Investing activities were comprised of capital expenditures of $11,065,925 and $5,109,510 for the six months ended March 31, 2011 and 2010, respectively. Capital expenditures increased $5,956,415, the result of increased drilling activity in areas where we own mineral and leasehold acreage (discussed in more detail below).

Financing activities:

The Company paid down its balance on the credit facility by $5,439,664 during the 2010 period. Having paid all of its previous borrowings under the credit facility in May 2010, no borrowings were made utilizing the Company’s credit facility during the six months ended March 31, 2011. The Company paid approximately $1,163,000 in dividends during both the 2010 and 2011 periods. Also, stock repurchases in the amount of $1,264,965 were made in the 2011 period, while no stock repurchases were made in the 2010 period.

     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, has resulted in an increase of $5,220,804 in oil and natural gas property and equipment additions in the 2011 six months, compared to the 2010 six months.

     Production for the six months of 2011 was flat compared to the six months of 2010. Production from wells drilled in the abovementioned areas during 2011 should result in production increases in late fiscal 2011 and continue into fiscal 2012.

     Additions to properties and equipment for oil and natural gas activities during fiscal 2011 are projected by management to be approximately $22 million. 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 associated capital expenditures, with certainty.

     We experienced moderate winter related increases in the price of natural gas; however, management expects natural gas prices to somewhat decrease during the spring and summer months. Therefore, we have executed fixed swap contracts covering 300,000 Mmbtu per month of our natural gas production from April 2011 through October 2011 at an average fixed price of $4.64.

     For the 2011 six months, cash provided by operating activities exceeded capital expenditures by $2,515,410. This excess allowed us to pay our regular $.07 per share quarterly dividend and to make stock repurchases in the amount of $1,264,965. 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, 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 March 31, 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, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund acquisitions, should the right opportunity be available.

THREE MONTHS ENDED MARCH 31, 2011 — COMPARED TO THREE MONTHS ENDED MARCH 31, 2010

Overview:

     The Company recorded a second quarter 2011 net income of $1,772,253, or $.21 per share, compared to a net income of $5,163,566, or $.61 per share, in the 2010 quarter. The decrease in net income was principally due to much lower gains on derivative contracts, decreased oil and natural gas revenues and increased impairment, partially offset by decreased DD&A expense and decreased provision for income taxes. These items are further discussed below.

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

     Oil and natural gas sales decreased $1,603,060 or 13% for the 2011 quarter. Oil and natural gas sales were down due to 23% lower natural gas prices offset by increases in average oil prices of 18% and oil volumes of 20%. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three month periods of fiscal 2011 and 2010:

     Since the second quarter of 2010, the Company had several new wells that were completed and put on line. Production from these newly completed wells has slightly exceeded the natural production decline from wells existing as of the second quarter of 2010.

     For the past two years, depressed natural gas prices have slowed drilling activity, principally in the “dry gas” areas (Southeast Oklahoma Woodford Shale) and limited the Company’s opportunities to participate in drilling new wells, and, among these opportunities, the Company has been very selective. The Company owns working interests in newly completed wells which are expected to significantly contribute to the Company’s natural gas production. Management expects natural gas prices for 2011 to be somewhat lower than those of 2010; however, drilling activity is expected to increase over current levels based on the recent level of proposals. Drilling activity in horizontal plays in western Oklahoma where the Company owns mineral acreage such as the Anadarko (Cana) Woodford Shale, Granite Wash, Cleveland and Tonkawa has increased and should provide more opportunity for the Company.

     Production for the last five quarters was as follows:

Gains (Losses) on Derivative Contracts:

     At March 31, 2011, the Company’s fair value of derivative contracts was an asset of $121,803; whereas at March 31, 2010, the Company’s fair value of derivative contracts was an asset of $3,304,814. The Company had a net gain on derivative contracts of $8,766 in the 2011 quarter as compared to a net gain of $4,226,309 recorded in the 2010 quarter.

Lease Operating Expenses (LOE):

     LOE decreased $95,997 or 4% in the 2011 quarter as compared to the 2010 quarter, and LOE per Mcfe decreased in the 2011 quarter to $.97 per Mcfe from $1.04 per Mcfe in the 2010 quarter. Value based fees (primarily gathering, transportation and marketing costs) decreased approximately $127,000 in the 2011 quarter compared to the 2010 quarter as a result of lower natural gas sales. On a per Mcfe basis, these fees were down $.08 due to lower natural gas prices creating lower value per Mcfe on which the fees are based. Value based fees are charged as a percentage of natural gas sales.

Production Taxes:

     Production taxes decreased $27,475 or 6% in the 2011 quarter as compared to the 2010 quarter. Production taxes as a percentage of oil and natural gas sales increased from 3.6% in the 2010 quarter to 3.9% in the 2011 quarter. Although oil and natural gas sales decreased 13%, production taxes only declined 6% as the production tax rate increased slightly due to some wells no longer being eligible for production tax credits or reductions. As wells receiving these production tax benefits pay out, or reach four years of having received production tax benefits, the wells are no longer eligible to receive the production tax credits or reductions.

Exploration Costs:

     Exploration costs decreased $10,149 in the 2011 quarter as compared to the 2010 quarter. During the 2011 quarter, leasehold impairment and expired leasehold totaled $77,246 compared to $300,391 during the 2010 quarter, a $223,145 decrease. Charges on one exploratory dry hole totaled $202,731 during the 2011 quarter; whereas, in the 2010 quarter no exploratory dry holes were drilled.

Depreciation, Depletion and Amortization (DD&A):

     DD&A decreased $1,852,695 or 34% in the 2011 quarter. DD&A in the 2011 quarter was $1.69 per Mcfe as compared to $2.62 per Mcfe in the 2010 quarter. DD&A decreased approximately $2,015,000 due to a $.93 decline in the DD&A rate per Mcfe. This rate decline was a result of an increase in the Company’s oil and natural gas reserves as of March 31, 2011, as compared to March 31, 2010. The remaining change was caused by oil and natural gas production increasing 3% in the 2011 quarter accounting for an increase of approximately $162,000.

Provision for Impairment:

     The provision for impairment increased $815,649 in the 2011 quarter compared to the 2010 quarter. During the 2010 quarter, impairment of $12,370 was recorded on one field. During the 2011 period, impairment of $828,019 was recorded on four 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.

     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 March 31, 2011, this well had a net book value of $751,217 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.

Income Taxes:

     Provision for income taxes decreased in the 2011 quarter by $1,302,000, the result of a $4,693,313 decrease 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 22% and 26%, respectively. Excess percentage depletion, which is a permanent tax benefit, and adjustments to Oklahoma net operating loss benefits reduced the effective tax rate below the statutory rate for both quarters.

SIX MONTHS ENDED MARCH 31, 2011 — COMPARED TO SIX MONTHS ENDED MARCH 31, 2010

Overview:

     The Company recorded a six month period 2011 net income of $3,199,102, or $.38 per share, as compared to a net income of $6,871,944, or $.82 per share, in the 2010 period. The decrease in net income was principally due to much lower gains on derivative contracts and decreased oil and natural gas revenues, 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 $2,681,918 as a result of decreases in average natural gas prices of 17%, partially offset by increases in average oil prices of 15% and oil volumes of 4%. The table below outlines the Company’s sales volumes and average sales prices for oil and natural gas for the six month periods of fiscal 2011 and 2010:

     Decreased drilling activity beginning in 2009 and continuing through most of fiscal 2010, has resulted in an expected production decline. The natural production decline of existing wells is slightly exceeding production from newly completed wells.

     Depressed natural gas prices experienced in fiscal 2009, 2010, and to some degree continuing into fiscal 2011, have resulted in fewer new well proposals to the Company. Also, the Company has been very selective, only participating as a working interest owner in proposed wells with acceptable projected rates of return. Although drilling opportunities have decreased through much of the last two years, the Company does own working interests in newly completed wells which are expected to contribute to the Company’s natural gas production and increase production volumes in late 2011 and into 2012. Management expects natural gas prices for 2011 to be somewhat lower than those of 2010; however, drilling activity is expected to increase over current levels based on the recent level of proposals. Drilling activity in horizontal plays in western Oklahoma where the Company owns mineral acreage such as the Anadarko (Cana) Woodford Shale, Granite Wash, Cleveland and Tonkawa is increasing and should provide additional drilling opportunity for the Company.

Gains (Losses) on Derivative Contracts:

     The fair value of derivative contracts was $121,803 as of March 31, 2011 and $3,304,814 as of March 31, 2010. The Company had a net loss of $12,673 in the six months ended March 31, 2011 compared to a gain of $5,629,649 for the six months ended March 31, 2010. The Company received net cash payments of $1,485,850 (realized gains) and made net cash payments of $188,600 (realized losses) for the 2011 and 2010 periods, respectively.

Lease Operating Expenses (LOE):

     LOE decreased $204,671 or 5% in the 2011 period. LOE decreased in the fiscal 2011 period to $.98 per Mcfe compared to $1.03 per Mcfe in the 2010 period. The total LOE decrease and the LOE per Mcfe decrease are primarily due to decreased natural gas prices which decreased value based fees (primarily gathering, transportation, and marketing costs). Value based fees are charged as a percent of natural gas revenues. Value based fees decreased $322,808 in the 2011 period or 12%, compared to the 2010 period. Value based fees per Mcfe decreased $.07 in the 2011 period or 12%, compared to the 2010 period.

     Partially offsetting the decrease in value based fees, LOE related to field operating costs increased $118,137 in the 2011 period compared to the 2010 period, a 6% increase. Field operating costs were $.45 per Mcfe in the 2011 period compared to $.42 per Mcfe in the 2010 period, a 7% increase. These increases are due to several workovers experienced in the 2011 period.

Production Taxes:

     Production taxes decreased $37,873 or 5% in the 2011 period. The decrease is the result of decreased oil and natural gas revenues, partially offset by an increase in the overall production tax rate due to some wells no longer being eligible for production tax credits or reductions. As wells receiving these production tax benefits pay out, or reach four years of having received production tax benefits, the wells are no longer eligible to receive the production tax credits or reductions.

Exploration Costs:

     Exploration costs decreased $299,306 in the 2011 period compared to the 2010 period. During the 2011 period, leasehold impairment and expired leasehold totaled $150,330 compared to $876,924 during the 2010 period, a $726,594 decrease. The decline was driven by lower expected future lease expirations as of March 31, 2011, as compared to March 31, 2010. Charges on two exploratory dry holes totaled $405,298 during the 2011 period; whereas, in the 2010 period the Company recorded a credit to exploratory dry holes of $161.

Depreciation, Depletion and Amortization (DD&A):

     DD&A decreased $3,710,579 or 34% in the 2011 period. DD&A was $1.62 per Mcfe in the 2011 period compared to $2.47 per Mcfe in the 2010 period. The majority of the DD&A decrease ($3,691,000) is attributable to the $.85 decline in the DD&A rate per Mcfe. This rate declined as a result of increased oil and natural gas reserves as of March 31, 2011, as compared to March 31, 2010.

Provision for Impairment:

     The provision for impairment increased $815,649 in the 2011 period compared to the 2010 period. During the 2011 period, impairment of $828,019 was recorded on four 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 March 31, 2011, this well had a net book value of $751,217 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 $260,438 or 9% in the 2011 period. The increase is primarily related to increases in the following expense categories: personnel $68,519, board of directors fees $44,521, computer consulting fees $35,000 and reservoir engineering fees $58,225.

Income Taxes:

     The fiscal 2011 period provision for income taxes of $1,075,000 was a result of a pre-tax income of $4,274,102 as compared to a provision for income taxes of $2,504,000 in the fiscal 2010 period resulting from a pre-tax income of $9,375,944. The $1,429,000 income tax provision decrease is primarily due to a $5,101,842 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 25% and 27%, 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 March 31, 2011, the Company has basis protection swaps, fixed price 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 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 $199,000. 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 $461,000. 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 $29,000.

     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 March 31, 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 March 31, 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.