1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Since its formation, the Company has been involved in the acquisition and management of fee mineral acreage and the exploration for, and development of, oil and natural gas properties, principally involving drilling wells located on the Company’s mineral acreage. Panhandle’s mineral properties and other oil and natural gas interests are all located in the United States, primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. The Company is not the operator of any wells. The Company’s oil, NGL and natural gas production is from interests in 6,105 wells located principally in Oklahoma and Arkansas. Approximately 60% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2013. Approximately 84% of the Company’s total sales volumes in 2013 were derived from natural gas. Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells. The Company from time to time disposes of certain non-material, non-core or small-interest oil and natural gas properties in the normal course of business.

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of crude oil, NGL and natural gas reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of crude oil, NGL 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. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates were based on average individual product prices during the 12-month period prior to September 30 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. For impairment purposes, projected future crude oil, NGL and natural gas prices as estimated by management are used. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves used in formulating management’s overall operating decisions.

The Company does not operate its oil and natural gas properties and, therefore, receives actual oil, NGL and natural gas sales volumes and prices (in the normal course of business) over a month later than the information is available to the operators of the wells. This being the case, on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, and oil, NGL and natural gas index prices local to each well are used to estimate the accrual of revenue on these wells. Timely obtaining production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The oil, NGL and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, NGL and natural gas. These variables could lead to an over or under accrual of oil, NGL and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

The Company sells oil, NGL and natural gas to various customers, recognizing revenues as oil, NGL and natural gas is produced and sold. Charges for compression, marketing, gathering and transportation of natural gas are included in lease operating expenses.

The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves. At September 30, 2013 and 2012, the Company had no material natural gas imbalances.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers of oil, NGL and natural gas or operators of the oil and natural gas properties. Oil, NGL and natural gas sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our oil, NGL and natural gas and the operators of the properties we have an interest in may be similarly affected by changes in economic, industry or other conditions. During 2013 and 2012, we did not recognize a reserve for bad debt expense.

Oil and Natural Gas Producing Activities

The Company follows the successful efforts method of accounting for oil and natural gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income if and when the well is determined to be nonproductive. Oil and natural gas mineral and leasehold costs are capitalized when incurred.

Non-producing oil and natural gas leases are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when recognized. As of September 30, 2013, the remaining carrying cost of non-producing oil and natural gas leases was $285,752.

It is common business practice in the petroleum industry for drilling costs to be prepaid before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2013, the Company had no outstanding letters of credit.

Leasing of Mineral Rights

When the Company leases its mineral acreage to third-party exploration and production companies, it retains a royalty interest in any future revenues from the production and sale of oil, NGL or natural gas, and often receives an up-front, non-refundable, cash payment (lease bonus) in addition to the retained royalty interest. A royalty interest does not bear any portion of the cost of drilling, completing or operating a well; these costs are borne by the working interest owner. The Company sometimes leases only a portion of its mineral acres in a tract and retains the right to participate as a working interest owner with the remainder.

The Company recognizes revenue from mineral lease bonus payments when it has received an executed lease agreement with the exploration company transferring the rights to explore for and produce any oil or natural gas they may find within the term of the lease, the payment has been collected, and the Company has no obligation to refund the payment. The Company accounts for its lease bonuses in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above the mineral basis being treated as a gain. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rentals line item on the Company’s Statements of Operations.

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. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. 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. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL historically). 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. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured. The derivative instruments have settled or will settle based on the prices below, which are adjusted for location differentials and tied to certain pipelines.

Derivative contracts in place as of September 30, 2012

(prices below reflect the Company’s net price from the listed pipelines)



	Production volume	Indexed
Contract period	covered per month	Pipeline	Fixed price
Natural gas basis protection swaps
January - December 2012	50,000 Mmbtu	CEGT	NYMEX -$.29
January - December 2012	40,000 Mmbtu	CEGT	NYMEX -$.30
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.29
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.30

Natural gas costless collars
March - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.25 ceiling
April - October 2012	120,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.10 ceiling
April - October 2012	60,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.45 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.30 ceiling
August - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.30 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.70 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.70 ceiling
November 2012 - January 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.65 ceiling

Oil costless collars
January - December 2012	2,000 Bbls	NYMEX WTI	$90 floor/$105 ceiling
February - December 2012	3,000 Bbls	NYMEX WTI	$90 floor/$110 ceiling
May - December 2012	2,000 Bbls	NYMEX WTI	$90 floor/$114 ceiling

Derivative contracts in place as of September 30, 2013

(prices below reflect the Company’s net price from the listed pipelines)



	Production volume	Indexed
Contract period	covered per month	pipeline	Fixed price
Natural gas costless collars
February - December 2013	80,000 Mmbtu	NYMEX Henry Hub	$3.75 floor/$4.25 ceiling
February - December 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.75 floor/$4.30 ceiling
February - December 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.75 floor/$4.05 ceiling
November 2013 - April 2014	160,000 Mmbtu	NYMEX Henry Hub	$4.00 floor/$4.55 ceiling

Natural gas fixed price swaps
March - October 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.505
March - October 2013	70,000 Mmbtu	NYMEX Henry Hub	$3.400
April - December 2013	40,000 Mmbtu	NYMEX Henry Hub	$3.655
May - November 2013	100,000 Mmbtu	NYMEX Henry Hub	$4.320

Oil costless collars
March - December 2013	3,000 Bbls	NYMEX WTI	$90.00 floor/$102.00 ceiling
March - December 2013	4,000 Bbls	NYMEX WTI	$90.00 floor/$101.50 ceiling
May - December 2013	2,000 Bbls	NYMEX WTI	$90.00 floor/$97.50 ceiling
January - June 2014	4,000 Bbls	NYMEX WTI	$90.00 floor/$101.50 ceiling

Oil fixed price swaps
September - December 2013	4,000 Bbls	NYMEX WTI	$105.250

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 a net asset of $425,198 as of September 30, 2013, and a net liability of $172,271 as of September 30, 2012. Realized and unrealized gains and (losses) are scheduled below:



Gains (losses) on natural gas	Fiscal year ended
derivative contracts	9/30/2013		9/30/2012		9/30/2011
Realized	$	13,555	$	462,033	$	2,138,685
Increase (decrease) in fair value		597,469		(388,211)		(1,404,386)
Total	$	611,024	$	73,822	$	734,299

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Balance Sheets. The Company has chosen to present the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Condensed Balance Sheets at September 30, 2013, and September 30, 2012. The Company adopted the accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at September 30, 2013, and September 30, 2012.



	9/30/2013				9/30/2012
	Fair Value (a)				Fair Value (a)
	Commodity Contracts				Commodity Contracts
	Current Assets		Current Liabilities		Current Assets		Current Liabilities
Gross amounts recognized	$	665,099	$	239,901	$	51,530	$	223,801
Offsetting adjustments		(239,901)		(239,901)		(51,530)		(51,530)
Net presentation on Condensed Balance Sheets	$	425,198	$	-	$	-	$	172,271

(a)See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

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

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.



	Fair Value Measurement at September 30, 2013
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	182,296	$	-	$	182,296
Derivative Contracts - Collars	$	-	$	-	$	242,902	$	242,902



	Fair Value Measurement at September 30, 2012
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(75,334)	$	-	$	(75,334)
Derivative Contracts - Collars	$	-	$	-	$	(96,937)	$	(96,937)

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 future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

Level 3 – The fair values of the Company’s costless 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 future prices, volatility, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of oil and natural gas, market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the forward prices and volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives, and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.

The following table represents quantitative disclosures about unobservable inputs for Level 3 Fair Value Measurements.



Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value September 30, 2013

Oil Collars	Oil price volatility curve	0% - 17.56%	10.27%	$	(233,041)
Natural Gas Collars	Natural gas price volatility curve	0% - 19.67%	12.00%	$	475,943

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



	Derivatives
Balance of Level 3 as of October 1, 2012	$	(96,937)
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		242,435
Unrealized		97,404
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		-
Transfers in and out of Level 3		-
Balance of Level 3 as of September 30, 2013	$	242,902

The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.



	Year Ended September 30,
	2013				2012
	Fair Value		Impairment		Fair Value		Impairment

Producing Properties	$	356,855	$	530,670	$	1,301,951	$	826,508	(a)

(a)

At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil, NGL 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.

At September 30, 2013, and September 30, 2012, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

Depreciation, Depletion, Amortization and Impairment

Depreciation, depletion and amortization of the costs of producing oil and natural gas properties are generally computed using the unit-of-production method primarily on an individual property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s capitalized costs of drilling and equipping all development wells and those exploratory wells that have found proved reserves are amortized on a unit-of-production basis over the remaining life of associated proved developed reserves. Lease costs are amortized on a unit-of-production basis over the remaining life of associated total proved reserves. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.

Non-producing oil and natural gas properties include non-producing minerals, which had a net book value of $4,702,285 and $5,374,868 at September 30, 2013 and 2012, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 87-year life of the Company. There are approximately 196,768 net acres of non-producing minerals in more than 6,818 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $43. Since inception, the Company has continually generated an interest in several thousand oil and natural gas wells using its ownership of the fee mineral acres as an ownership basis. There continues to be significant drilling activity each year on these mineral interests. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (as do oil and natural gas leases). Given the above, it was concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company's estimate of fair value of its oil and natural gas properties at September 30, 2013, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $530,670, $826,508 and $1,728,162, respectively, for 2013, 2012 and 2011. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes would likely lead to additional impairment in future periods that may be material to the Company.

Capitalized Interest

During 2013, 2012 and 2011, interest of $121,418, $129,172 and $0, respectively, was included in the Company’s capital expenditures. Interest of $157,558, $127,970 and $0, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the

Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using unit-of-production method.

Investments

Insignificant investments in partnerships and limited liability companies (LLC) that maintain specific ownership accounts for each investor and where the Company holds an interest of 5% or greater, but does not have control of the partnership or LLC, are accounted for using the equity method of accounting.

Asset Retirement Obligations

The Company owns interests in oil and natural gas properties, which may require expenditures to plug and abandon the wells when the oil, NGL and natural gas reserves in the wells are depleted. The fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties and equipment is depreciated over the useful life of the remaining asset. The Company does not have any assets restricted for the purpose of settling the asset retirement obligations.

The following table shows the activity for the years ended September 30, 2013 and 2012, relating to the Company’s asset retirement obligations:



	2013		2012
Asset Retirement Obligations as of beginning of the year	$	2,122,950	$	1,843,875
Accretion of Discount		122,391		121,112
New Wells Placed on Production		167,609		184,027
Wells Sold or Plugged		(19,760)		(26,064)
Asset Retirement Obligations as of end of the year	$	2,393,190	$	2,122,950

Environmental Costs

As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays; however, to date the Company’s cost of compliance has been insignificant. The Company does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future effects on the Company of new laws or interpretations thereof. Since the Company does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by others, with Panhandle being responsible for its proportionate share of the costs involved. Panhandle carries liability insurance and pollution control coverage. However, all risks are not insured due to the availability and cost of insurance.

Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2013 and 2012, there were no such costs accrued.

Earnings (Loss) Per Share of Common Stock

Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period.

Share-based Compensation

The Company recognizes current compensation costs for its Deferred Compensation Plan for Non-Employee Directors (the “Plan”). Compensation cost is recognized for the requisite directors’ fees as earned and unissued stock is added to each director’s account based on the fair market value of the stock at the date earned. The Plan’s structure is that upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director.

In accordance with guidance on accounting for employee stock ownership plans, the Company records as expense the fair market value of the stock at the time of contribution into its ESOP.

Restricted stock awards to certain officers provide for cliff vesting at the end of three or five years from the date of the awards. The fair value of the awards is ratably expensed over the vesting period in accordance with accounting guidance.

Income Taxes

The estimation of amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax regulations. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities.

The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2010.

The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Operations. For fiscal September 30, 2013, 2012 and 2011, the Company recorded interest and penalties of $927, $0 and $21,000, respectively. The Company does not believe it has any significant uncertain tax positions.

New Accounting Standards

In December 2011, the Financial Accounting Standards Board issued "Balance Sheet: Disclosures about Offsetting Assets and Liabilities." The new standard requires entities to disclose information about financial instruments and derivative instruments that are either offset on the balance sheet or are subject to a master netting arrangement, including providing both gross information and net information for recognized assets and liabilities, the net amounts presented on an entity's balance sheet and a description of the rights of offset associated with these assets and liabilities. The new standard is applicable for all entities that have financial instruments and derivative instruments shown using a net presentation on an entity's balance sheet or are subject to a master netting arrangement. The new standard is effective for interim and annual reporting periods for fiscal years beginning on or after January 1, 2013, and should be applied retrospectively for all periods presented. The Company adopted this new standard effective January 1, 2013.

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 financial statements upon adoption.