10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2012

Commission File Number: 001-31759

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

OKLAHOMA	73-1055775
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Grand Centre, Suite 300, 5400 N. Grand Blvd.,

Oklahoma City, OK 73112

(Address of principal executive offices) (Zip code)

Registrant’s telephone number: (405) 948-1560

Securities registered under Section 12(b) of the Act:

CLASS A COMMON STOCK (VOTING)	NEW YORK STOCK EXCHANGE
(Title of Class)	(Name of each exchange on which registered)

Securities registered under Section 12(g) of the Act:

(Title of Class)

CLASS B COMMON STOCK (NON-VOTING) $1.00 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     ¨  Yes    x  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    ¨  Yes    x  No

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.    x  Yes    ¨   No

(Facing Sheet Continued)

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.    x  Yes    ¨  No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

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

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    ¨  Yes    x  No

The aggregate market value of the voting stock held by non-affiliates of the registrant, computed by using the closing price of registrant's Common Stock, at March 31, 2012, was $206,798,928. As of December 1, 2012, 8,250,192 shares of Class A Common Stock were outstanding.

Documents Incorporated By Reference

The information required by Part III of this Report, to the extent not set forth herein, is incorporated by reference from the registrant’s Definitive Proxy Statement relating to the annual meeting of stockholders to be held on March 7, 2013, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Report relates.

T A B L E   O F   C O N T E N T S

		Page
PART I
Item 1	Business		1
Item 1B	Unresolved Staff Comments		11
Item 2	Properties		11
Item 3	Legal Proceedings		21
Item 4	Submission of Matters to a Vote of Security Holders		21
PART II
Item 5	Market for Common Equity, Related Stockholder Matters and Unregistered Sales of Equity Securities		22
Item 6	Selected Financial Data		24
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
Item 7A	Quantitative and Qualitative Disclosures about Market Risk		40
Item 8	Financial Statements and Supplementary Data		41
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		79
Item 9A	Controls and Procedures		79
Item 9B	Other Information		79
PART III
Item 10-14	Incorporated by Reference to Proxy Statement		80
PART IV
Item 15	Exhibits, Financial Statement Schedules and Reports on Form 8- K		80

DEFINITIONS

The following defined terms are used in this report:

“Bbl” means barrel;

“Bcf” means billion cubic feet;

“Board” means board of directors;

“BTU” means British Thermal Units;

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

“CEO” means Chief Executive Officer;

“CFO” means Chief Financial Officer;

“Company” refers to Panhandle Oil and Gas Inc.;

“COO” means Chief Operating Officer;

“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;

“gross wells” or “gross acres” are the wells or acres in which the Company has a working or royalty interest;

“Independent Consulting Petroleum Engineer(s)” or “Independent Consulting Petroleum Engineering Firm” refers to DeGolyer and MacNaughton of Dallas, Texas;

“LOE” means lease operating expense;

“Mcf” means thousand cubic feet;

“Mcfd” means thousand cubic feet per day;

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

“Mmbtu” means million BTU;

“Mmcf” means million cubic feet;

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

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

“NGL” means natural gas liquids;

“NYMEX” refers to the New York Mercantile Exchange;

“Panhandle” refers to Panhandle Oil and Gas Inc.;

“PDP” means proved developed producing;

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

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

“PUD” means proved undeveloped;

“PV-10” means estimated pre-tax present value of future net revenues discounted at 10% using SEC rules;

“royalty interest” refers to well interests in which the Company does not pay a share of the costs to drill, complete and operate a well, but receives a much smaller proportionate share (as compared to a working interest) of production;

“SEC” refers to 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.

Fiscal year references

All references to years in this report, unless otherwise noted, refer to the Company’s fiscal year end of September 30. For example, references to 2012 mean the fiscal year ended September 30, 2012.

References to natural gas

References to 2010 natural gas reserves, production, sales and prices include associated NGL.

References to oil and natural gas properties inherently include NGL associated with such properties.

PART I

ITEM 1 BUSINESS

GENERAL

Panhandle Oil and Gas Inc. was founded in Range, Texas County, Oklahoma, in 1926, as Panhandle Cooperative Royalty Company and operated as a cooperative until 1979, when the Company merged into Panhandle Royalty Company and its shares became publicly traded. On April 2, 2007, the Company’s name was changed to Panhandle Oil and Gas Inc. The name change was made to clear up confusion as to whether the Company was a royalty trust. Panhandle has never been a royalty trust.

While operating as a cooperative, the Company distributed most of its net income to shareholders as cash dividends. Upon conversion to a public company in 1979, although still paying dividends, the Company began to retain a substantial part of its cash flow to participate with a working interest in the drilling of wells on its mineral acreage and to purchase additional mineral acreage. Several acquisitions of additional mineral acreage and small companies were made in the ‘80s and ‘90s, and the acquisition of Wood Oil Company, as a wholly owned subsidiary, was consummated in October 2001. Wood Oil Company was merged into Panhandle Oil and Gas Inc. effective July 1, 2011.

In January 2006, the Company last split its Class A Common Stock on a two-for-one basis. In March 2007 the Company last increased its authorized Class A Common Stock from 12 million shares to 24 million shares.

The Company is involved in the acquisition, management and development of non-operated oil and natural gas properties, including wells located on the Company’s mineral and leasehold acreage. Panhandle’s mineral and leasehold properties are located primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas, with properties also located in several other states. The majority of the Company’s oil, NGL and natural gas production is from wells located in Oklahoma.

The Company’s office is located at Grand Centre, Suite 300, 5400 N. Grand Blvd., Oklahoma City, OK 73112; telephone – (405) 948-1560; facsimile – (405) 948-2038. The Company’s website is www.panhandleoilandgas.com.

The Company files periodic reports with the SEC on Forms 10-Q and 10-K. These Forms, the Company’s annual report to shareholders and current press releases are available free of charge through our website as soon as reasonably practicable after they are filed with the SEC. Also, the Company posts copies of its various corporate governance documents on the website. From time to time, the Company posts other important disclosures to investors in the “Press Release” or “Upcoming Events” section of the website, as allowed by SEC rules.

Materials filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet website at www.sec.gov that contains reports, proxy and information statements, and other information regarding the Company that has been filed electronically with the SEC, including this Form 10-K.

BUSINESS STRATEGY

Typically, most of Panhandle’s revenues are derived from the production and sale of oil, NGL and natural gas (see Item 8 - “Financial Statements and Supplementary Data”). The Company’s oil and natural gas properties, including its mineral acreage, leasehold acreage and working and royalty interests

(1)

in producing wells are mainly in Oklahoma with other significant holdings in Arkansas, New Mexico, North Dakota and Texas (see Item 2 – “Properties”). Exploration and development of the Company’s oil and natural gas properties are conducted in association with oil and natural gas exploration and production companies, primarily larger independent companies. The Company does not operate any of its oil and natural gas properties, but has been an active working interest participant for many years in wells drilled on the Company’s mineral properties and on third-party drilling prospects. A significant percentage of the Company’s recent drilling participations has been on properties in which the Company owns mineral acreage and, in many cases, already owns an interest in a producing well in the drilling and spacing unit. Most of these wells are in unconventional plays (shale gas) located in Oklahoma and Arkansas.

PRINCIPAL PRODUCTS AND MARKETS

The Company’s principal products are natural gas and, to a lesser extent, crude oil and NGL. These products are sold to various purchasers, including pipeline and marketing companies, which service the areas where the Company’s producing wells are located. Since the Company does not operate any of the wells in which it owns an interest, it relies on the operating expertise of numerous companies that operate wells in the areas where the Company owns interests. This includes expertise in the drilling and completion of new wells, producing well operations and, in most cases, the marketing or purchasing of production from the wells. Natural gas and NGL sales are principally handled by the well operator and are normally contracted on a monthly basis with third-party natural gas marketers and pipeline companies. Payment for natural gas and NGL sold is received by the Company from the well operator or the contracted purchaser. Crude oil sales are generally handled by the well operator and payment for oil sold is received by the Company from the well operator or from the crude oil purchaser.

Prices of oil, NGL and natural gas are dependent on numerous factors beyond the control of the Company, including competition, weather, international events and circumstances, supply and demand, actions taken by the Organization of Petroleum Exporting Countries (“OPEC”), and economic, political and regulatory developments. Since demand for natural gas is generally highest during winter months, prices received for the Company’s natural gas production are subject to seasonal variations.

The Company enters into price risk management financial instruments (derivatives) to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. The derivative contracts apply to 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 contracts expose the Company to risk of financial loss and may limit the benefit of future increases in oil and natural gas prices. A more thorough discussion of these derivative contracts, including risk of financial loss, is contained in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

COMPETITIVE BUSINESS CONDITIONS

The oil and natural gas industry is highly competitive, particularly in the search for new oil, NGL and natural gas reserves. Many factors affect Panhandle’s competitive position and the market for its products which are beyond its control. Some of these factors include the quantity and price of foreign oil imports; domestic supply of oil, NGL and natural gas; changes in prices received for oil, NGL and natural gas production; business and consumer demand for refined oil products, NGL and natural gas; and the effects of federal and state regulation of the exploration for, production of and sales of oil, NGL and natural gas. Changes in existing economic conditions, political developments, weather patterns and actions taken by OPEC and other oil-producing countries have a dramatic influence on the price Panhandle receives for its oil, NGL and natural gas production.

(2)

The Company does not operate any of the wells in which it has an interest; rather it relies on companies with greater resources, staff, equipment, research and experience for operation of wells both in the drilling and production phases. The Company’s business strategy is to use its strong financial base and its mineral and leasehold acreage ownership, coupled with its own geologic and economic evaluations, to elect to participate in drilling operations with these larger companies or to lease or farmout its mineral or leasehold acreage while retaining a royalty interest. This strategy allows the Company to compete effectively in drilling operations it could not undertake on its own due to financial and personnel limits while maintaining low overhead costs.

SOURCES AND AVAILABILITY OF RAW MATERIALS

The existence of recoverable oil, NGL and natural gas reserves in commercial quantities is essential to the ultimate realization of value from the Company’s mineral and leasehold acreage. These mineral and leasehold properties are essentially the raw materials to our business. The production and sale of oil, NGL and natural gas from the Company’s properties are essential to provide the cash flow necessary to sustain the ongoing viability of the Company. The Company reinvests a portion of its cash flow to purchase oil and natural gas mineral and leasehold acreage to assure the continued availability of acreage with which to participate in exploration, drilling and development operations and, subsequently, the production and sale of oil, NGL and natural gas. This participation in exploration and production activities and purchase of additional acreage is necessary to continue to supply the Company with the raw materials with which to generate additional cash flow. Mineral and leasehold acreage purchases are made from many owners. The Company does not rely on any particular companies or persons for the purchases of additional mineral and leasehold acreage.

MAJOR CUSTOMERS

The Company’s oil, NGL and natural gas production is sold, in most cases, through its well operators to many different purchasers on a well-by-well basis. During 2012, sales through three separate well operators accounted for approximately 15%, 13% and 10% of the Company’s total oil, NGL and natural gas sales. During 2011, sales through two separate well operators accounted for approximately 15% and 14% of the Company’s total oil, NGL and natural gas sales. During 2010, sales through three separate well operators accounted for approximately 15%, 14% and 11% of the Company’s total oil, NGL and natural gas sales. Generally, if one purchaser declines to continue purchasing the Company’s production, several other purchasers can be located. Pricing is generally consistent from purchaser to purchaser.

PATENTS, TRADEMARKS, LICENSES, FRANCHISES AND ROYALTY AGREEMENTS

The Company does not own any patents, trademarks, licenses or franchises. Royalty agreements on wells producing oil, NGL and natural gas stemming from the Company’s ownership of mineral acreage generate a portion of the Company’s revenues. These royalties are tied to ownership of mineral acreage, and this ownership is perpetual, unless sold by the Company. Royalties are due and payable to the Company whenever oil, NGL and natural gas is produced and sold from wells located on the Company’s mineral acreage.

REGULATION

All of the Company’s well interests and non-producing properties are located onshore in the United States. Oil, NGL and natural gas production is subject to various taxes, such as gross production taxes and, in some cases, ad valorem taxes.

The State of Oklahoma and other states require permits for drilling operations, drilling bonds and

(3)

reports concerning operations and impose other regulations relating to the exploration for and production of oil, NGL and natural gas. These states also have regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties and the regulation of spacing, plugging and abandonment of wells. These regulations vary from state to state. As previously discussed, the Company relies on its well operators to comply with governmental regulations.

Various aspects of the Company’s oil and natural gas operations are regulated by agencies of the federal government. Transportation of natural gas in interstate commerce is generally regulated by the Federal Energy Regulatory Commission (“FERC”) pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 (“NGPA”). The intrastate transportation and gathering of natural gas (and operational and safety matters related thereto) may be subject to regulation by state and local governments.

FERC’s jurisdiction over interstate natural gas sales was substantially modified by the NGPA under which FERC continued to regulate the maximum selling prices of certain categories of natural gas sold in “first sales” in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas. Because “first sales” include typical wellhead sales by producers, all natural gas produced from the Company’s natural gas properties is sold at market prices, subject to the terms of any private contracts in effect. FERC’s jurisdiction over natural gas transportation was not affected by the Decontrol Act.

Sales of natural gas are affected by intrastate and interstate natural gas transportation regulation. Beginning in 1985, FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by FERC to foster competition by transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the primary role of natural gas transporters. As a result of the various omnibus rulemaking proceedings in the late 1980s and the individual pipeline restructuring proceedings of the early to mid-1990s, interstate pipelines must provide open and nondiscriminatory transportation and transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end users and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, FERC expanded the impact of open access regulations to intrastate commerce.

More recently, FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are: (1) permitting the large-scale divestiture of interstate pipeline-owned natural gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline’s demonstration of lack of market control in the relevant service market.

As a result of these changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are able to conduct business with a larger number of counter parties. These changes generally have improved the access to markets for natural gas while substantially increasing competition in the natural gas marketplace. The effect of future regulations by FERC and other regulatory agencies cannot be predicted.

Sales of oil are not regulated and are made at market prices. The price received from the sale of

(4)

oil is affected by the cost of transporting it to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. Over time, these regulations tend to increase the cost of transporting oil by interstate pipelines, although some annual adjustments may result in decreased rates for a given year. These regulations have generally been upheld on judicial review. Every five years, FERC will examine the relationship between the annual change in the applicable index and the actual cost changes experienced by the oil pipeline industry.

ENVIRONMENTAL MATTERS

As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local laws and regulations regarding environmental and ecological matters. Compliance with these laws and regulations may necessitate significant capital outlays; however, to date, the Company’s cost of compliance has been immaterial. The Company does not believe the existence of these environmental laws, as currently written and interpreted, will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future events or changes in laws, or the interpretation of laws, governing our industry. Current discussions involving the governance of hydraulic fracturing in the future could have a material impact on the Company. Since the Company does not operate any wells in which it owns an interest, actual compliance with environmental laws is controlled by the well operators, with Panhandle being responsible for its proportionate share of the costs involved. As such, to its knowledge, the Company is not aware of any instances of non-compliance with existing laws and regulations and that, absent an extraordinary event, any noncompliance will not have a material adverse effect on the financial condition of the Company. Although the Company is not fully insured against all environmental risks, insurance coverage is maintained at levels which are customary in the industry.

EMPLOYEES

At September 30, 2012, Panhandle employed 20 persons on a full-time basis with five of the employees serving as executive officers. The President and CEO is also a director of the Company.

RISK FACTORS

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating the Company’s business and future prospects. If any of the following risk factors should occur, the Company’s financial condition could be materially impacted and the holders of our securities could lose part or all of their investment in Panhandle. The risk factors described below are not necessarily exhaustive, and investors are encouraged to perform their own investigation with respect to the Company and its business. Investors should also read the other information in this Form 10-K, including the financial statements and related notes.

Economic conditions, worldwide and in the United States, may have a significant negative effect on operating results, liquidity and financial condition.

Effects of domestic and international economic conditions, could lead to: (1) a decline in demand for oil, NGL and natural gas resulting in decreased oil, NGL and natural gas reserves due to curtailed drilling activity; (2) a decline in oil, NGL and natural gas prices; (3) risk of insolvency of well operators and oil, NGL and natural gas purchasers; (4) limited availability of certain insurance coverage; and (5) limited access to derivative instruments. A decline in reserves would lead to a decline in production, and either a production decline, or a decrease in oil, NGL and natural gas prices, would have a negative impact on the Company’s cash flow, profitability and value.

(5)

Oil, NGL and natural gas prices are volatile. Volatility in these prices can adversely affect operating results and the price of the Company’s Common Stock. This volatility also makes valuation of oil and natural gas producing properties difficult and can disrupt markets.

Oil, NGL and natural gas prices have historically been, and will likely continue to be, volatile. The prices for oil, NGL and natural gas are subject to wide fluctuation in response to a number of factors, including:

• worldwide economic conditions;

• economic, political and regulatory developments;

• market uncertainty;

• relatively minor changes in the supply of and demand for oil, NGL and natural gas;

• availability and capacity of necessary transportation and processing facilities;

• commodity futures trading;

• weather conditions;

• political instability or armed conflicts in major oil and natural gas producing regions, particularly the Middle East and West Africa;

• actions taken by OPEC;

• competition from alternative sources of energy; and

• technological advancements affecting energy consumption and energy supply.

In recent years, oil, NGL and natural gas price volatility has been severe. Price volatility makes it difficult to budget and project the return on investment in exploration and development projects and to estimate with precision the value of producing properties that are owned or acquired by the Company. In addition, volatile prices often disrupt the market for oil and natural gas properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties. Revenues, results of operations and profitability may fluctuate significantly as a result of variations in oil, NGL and natural gas prices and production performance.

Lower oil, NGL and natural gas prices may also trigger significant impairment write-downs on a portion of the Company’s properties.

A substantial decline in oil, NGL and natural gas prices for an extended period of time would have a material adverse effect on the Company.

A substantial decline in oil, NGL and natural gas prices for an extended period of time would have a material adverse effect on the Company’s financial position, results of operations, access to capital and the quantities of oil, NGL and natural gas that may be economically produced. A significant decrease in price levels for an extended period would have a material negative effect in several ways, including:

• cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production;

• future undiscounted and discounted net cash flows from producing properties would decrease, possibly resulting in impairment expense that may be significant;

• certain reserves may no longer be economic to produce, leading to both lower proved reserves and cash flow; and

• access to sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable.

(6)

We cannot control activities on properties we do not operate.

The Company does not operate any of the properties in which it has an interest and has very limited ability to exercise influence over operations of these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and the limited ability to influence operations and associated costs could materially and adversely affect the realization of targeted returns on capital in drilling or acquisition activities and targeted production growth rates. The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond the Company’s control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of appropriate technology.

The Company’s derivative activities may reduce the cash flow received for oil and natural gas sales.

In order to manage exposure to price volatility on our oil and natural gas production, we enter into oil and natural gas derivative contracts for a portion of our expected production. Oil and natural gas price derivatives may limit the cash flow we actually realize and therefore reduce the Company’s ability to fund future projects. Also, the fair value of our oil and natural gas derivative contracts may vary significantly from period to period, therefore materially affecting reported earnings.

There is risk associated with our derivative contracts that involves the possibility that counterparties may be unable to satisfy contractual obligations to us. If any counterparty to our derivative instruments were to default or seek bankruptcy protection, it could subject a larger percentage of our future oil and natural gas production to commodity price changes and could have a negative effect on our ability to fund future projects.

The fair value of our oil and natural gas derivative instruments outstanding as of September 30, 2012, was a liability of $172,271.

A more thorough discussion of these derivative contracts, including risk of financial loss, is contained in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Lower oil, NGL and natural gas prices or negative adjustments to oil, NGL and natural gas reserves may result in significant impairment charges.

The Company has elected to utilize the successful efforts method of accounting for its oil and natural gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and development dry holes are capitalized and amortized by property using the unit-of-production method (the ratio of oil, NGL and natural gas volumes produced to total proved or proved developed reserves is used to amortize the remaining asset basis on each producing property) as oil, NGL and natural gas are produced.

All long-lived assets, principally the Company’s oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset on our books may be greater than its future net cash flows. The need to test a property for impairment may result from declines in oil, NGL and natural gas sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. Once assets are classified as held for sale, they are reviewed for impairment. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded. If an impairment charge is recognized, cash flow from operating activities is not impacted, but net income and, consequently, shareholders’ equity are reduced.

(7)

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of oil, NGL and natural gas in an exact way. Oil, NGL and natural gas reserve engineering requires subjective estimates of underground accumulations of oil, NGL and natural gas and assumptions concerning future prices of these commodities, future production levels, and operating and development costs. In estimating our reserves, we and our Independent Consulting Petroleum Engineering Firm make certain assumptions that may prove to be incorrect, including assumptions relating to the level of oil, NGL and natural gas prices, future production levels, capital expenditures, operating and development costs, the effects of regulation and availability of funds. If these assumptions prove to be incorrect, our estimates of reserves (the economically recoverable quantities of oil, NGL and natural gas attributable to any particular group of properties), the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

Our standardized measure of oil and natural gas reserves is calculated using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-month period prior to September 30 held flat over the life of the properties and costs in effect as of the date of estimation, less future development, production and income tax expenses, and is discounted at 10% per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.

The reserve estimates made for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures. Further, our lack of knowledge of all individual well information known to the well operators such as incomplete well stimulation efforts, restricted production rates for various reasons and up to date well production data, etc. may cause differences in our reserve estimates.

Because forward-looking prices and costs are not used to estimate discounted future net cash flows from our estimated proved reserves, the standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil, NGL and natural gas reserves.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the FASB statement on oil and natural gas producing activities disclosures may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company, or the oil and natural gas industry in general.

Failure to find or acquire additional reserves will cause reserves and production to decline materially from their current levels.

The rate of production from oil and natural gas properties generally declines as reserves are

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depleted. The Company’s proved reserves will decline materially as reserves are produced except to the extent that the Company acquires additional properties containing proved reserves, conducts additional successful exploration and development drilling, successfully applies new technologies or identifies additional behind-pipe zones (different productive zones within existing producing well bores) or secondary recovery reserves. The above activities are conducted with well operators, as the Company does not operate any of its wells. Future oil, NGL and natural gas production is therefore highly dependent upon the level of success in acquiring or finding additional reserves.

Drilling for oil and natural gas invariably involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient reserves to return a profit after deducting drilling, operating and other costs. In addition, wells that are profitable may not achieve a targeted rate of return. The Company relies on the operators’ seismic data and other advanced technologies in identifying prospects and in conducting exploration and development activities. The seismic data and other technologies used do not allow operators to know conclusively prior to drilling a well whether oil, NGL or natural gas is present and may be commercially produced.

Cost factors can adversely affect the economics of any project, and ultimately the cost of drilling, completing and operating a well is controlled by well operators and existing market conditions. Further, drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, environmental and other governmental requirements, the cost and availability of drilling rigs, equipment and services and the expected sales price to be received for oil, NGL or natural gas produced from the wells.

Oil and natural gas drilling and producing operations involve various risks.

The Company is subject to all the risks normally incident to the operation and development of oil and natural gas properties including well blowouts, cratering and explosions, pipe failures, adverse weather conditions, fires, abnormal pressures, uncontrollable flows of oil and natural gas, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks.

Other risks of operations include oilfield services shortages, equipment shortages, shortages of qualified oilfield workers, pipeline and gathering system capacity constraints, transportation interruptions and lack of processing access to gas plants.

The Company maintains insurance against many potential losses or liabilities arising from well operations in accordance with customary industry practices and in amounts believed by management to be prudent. However, this insurance does not protect it against all operational and environmental risks. For example, the Company does not maintain business interruption insurance. Additionally, pollution and environmental risks generally are not fully insurable. These risks could give rise to significant uninsured costs that could have a material adverse effect on the Company’s financial results.

Debt level and interest rates may adversely affect our business.

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan with a limit in the amount of $80,000,000. As of September 30, 2012, the Company had a balance of $14,874,985 drawn on the facility. The facility has a current borrowing base of $35,000,000, is secured by certain of the Company’s properties and contains certain restrictive covenants.

Should the Company incur substantial indebtedness under its credit facility to fund capital projects or for other reasons, there is risk of it adversely affecting our business operations as follows:

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• cash flows from operating activities required to service indebtedness will not be available for other purposes;

• covenants contained in the Company’s borrowing agreement may limit our ability to borrow additional funds and pay dividends;

• any limitation on the borrowing of additional funds may affect our ability to fund capital projects and may also affect how we will be able to react to economic and industry changes; and

• a significant increase in the interest rate on our credit facility will limit funds available for other purposes.

The borrowing base of our corporate revolving bank credit facility is subject to periodic redetermination and is based in part on oil, NGL and natural gas prices. A lowering of our borrowing base because of lower oil, NGL or natural gas prices, or for other reasons, could require us to repay indebtedness in excess of the borrowing base, or we might need to further secure the debt with additional collateral. Our ability to meet any debt obligations depends on our future performance. General economic conditions, prices and financial, business and other factors affect our future performance, and many of these factors are beyond our control. In addition, our failure to comply with the restrictive covenants relating to our credit facility could result in a default, which could adversely affect our business, financial condition and results of operations.

Future legislative or regulatory changes may result in increased costs and decreased revenues, cash flows and liquidity.

Companies that operate wells in which Panhandle owns a working interest are subject to extensive federal, state and local regulation. Panhandle, as a working interest owner, is therefore indirectly subject to these same regulations. New or changed laws and regulations such as those described below could have an adverse effect on our business.

Federal Income Taxation

Proposals to repeal the expensing of intangible drilling costs, repeal the percentage depletion allowance and increase the amortization period of geological and geophysical expenses, if enacted, would increase and accelerate the Company’s payment of federal income taxes. As a result, these changes would decrease the Company’s cash flows available for developing its oil and natural gas properties.

Hydraulic Fracturing

The vast majority of oil and natural gas wells drilled in recent years have been, and future wells expected to be drilled are expected to be, hydraulically fractured as a part of the process of completing the wells and putting them on production. Some members of Congress have proposed legislation to either ban or further regulate the hydraulic fracturing process. We cannot predict whether any such legislation will be enacted or, if enacted, what its provisions would be. If legislation is passed to ban hydraulic fracturing, the number of wells drilled in the future will most likely drop dramatically, and the economic performance of those drilled will be negatively affected. Legislation imposing further regulation of hydraulic fracturing may result in increased costs to drill, complete and operate wells, as well as delays in obtaining permits to drill wells.

Climate Change

The EPA has proposed regulations for the purpose of restricting greenhouse gas emissions

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from stationary sources. Such regulatory and legislative proposals to restrict greenhouse gas emissions, or to generally address climate change, could increase the Company’s operating costs as operators of wells, in which the Company owns a working interest, incur costs to comply with new rules. The increase in costs to the well operators, and ultimately the Company, as a working interest owner, could include new or increased costs to install new emissions control equipment, operate and maintain existing equipment, obtain allowances to authorize greenhouse gas emissions and pay greenhouse gas related taxes. There also could be an adverse effect on demand for oil, NGL and natural gas in the market place.

Shortages of oilfield equipment, services, qualified personnel and resulting cost increases could adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, NGL and natural gas prices, causing periodic shortages. There have also been shortages of drilling rigs, hydraulic fracturing equipment and personnel and other oilfield equipment, as demand for rigs and equipment increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil, NGL and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. These shortages or price increases could adversely affect the Company’s profit margin, cash flow and operating results, or restrict its ability to drill wells and conduct ordinary operations.

Competition in the oil and natural gas industry is intense, and most of our competitors have greater financial and other resources than we do.

We compete in the highly competitive areas of oil and natural gas acquisition, development, exploration and production. We face intense competition from both major and independent oil and natural gas companies in seeking to acquire desirable producing properties, seeking new properties for future exploration and seeking the human resource expertise necessary to effectively develop properties. We also face similar competition in obtaining sufficient capital to maintain drilling rights in all drilling units.

A substantial number of our competitors have financial and other resources significantly greater than ours and some of them are fully integrated oil and natural gas companies. These companies are able to pay more for development prospects and productive oil and natural gas properties and are able to define, evaluate, bid for, purchase and subsequently drill a greater number of properties and prospects than our financial or human resources permit, effectively reducing our ability to participate in drilling on certain of our acreage as a working interest owner. Our ability to develop and exploit our oil and natural gas properties and to acquire additional quality properties in the future will depend upon our ability to successfully evaluate, select and acquire suitable properties and join in drilling with reputable operators in this highly competitive environment.

ITEM 1B UNRESOLVED STAFF COMMENTS

None

ITEM 2 PROPERTIES

At September 30, 2012, Panhandle’s principal properties consisted of (i) perpetual ownership of 255,012 net mineral acres, held principally in Arkansas, New Mexico, North Dakota, Oklahoma, Texas and six other states; (ii) leases on 20,177 net acres primarily in Oklahoma: and (iii) working interests, royalty interests or both in 5,666 producing oil and natural gas wells and 62 wells in the process of being drilled or completed.

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Consistent with industry practice, the Company does not have current abstracts or title opinions on all of its mineral properties and, therefore, cannot be certain that it has unencumbered title to all of these properties. In recent years, a few insignificant challenges have been made against the Company’s fee title to its properties.

The Company pays ad valorem taxes on minerals owned in ten states.

ACREAGE

Mineral Interests Owned

The following table of mineral interests owned reflects, in each respective state, the number of net and gross acres, net and gross producing acres, net and gross acres leased, and net and gross acres open (unleased) as of September 30, 2012.

State	Net Acres		Gross Acres		Net Acres Producing (1)		Gross Acres Producing (1)		Net Acres Leased to Others (2)		Gross Acres Leased to Others (2)		Net Acres Open (3)		Gross  Acres Open (3)
Arkansas		11,872		50,935		6,719		24,603		1,907		6,130		3,246		20,201
Colorado		8,217		39,080						224		447		7,993		38,633
Florida		3,832		8,212										3,832		8,212
Kansas		3,082		11,816		144		1,200						2,938		10,616
Montana		1,008		17,947										1,008		17,947
New Mexico		57,375		174,300		1,352		7,125		205		440		55,818		166,735
North Dakota		11,179		64,286		148		1,276		33		680		10,998		62,330
Oklahoma		113,399		950,832		39,751		322,635		4,645		32,320		69,003		595,796
South Dakota		1,825		9,300										1,825		9,300
Texas		43,196		360,025		7,933		70,781		244		5,285		35,019		283,959
Other		27		262										27		262
Total:		255,012		1,686,995		56,047		427,620		7,258		45,302		191,707		1,213,991

(1) “Producing” represents the mineral acres in which Panhandle owns a royalty or working interest in a producing well.

(2) “Leased” represents the mineral acres owned by Panhandle that are leased to third parties but not producing.

(3) “Open” represents mineral acres owned by Panhandle that are not leased or in production.

Leases

The following table reflects net mineral acres leased from others, lease expiration dates, and net leased acres held by production as of September 30, 2012.

State	Net Acres		Net Acres Expiring										Net Acres Held by Production
			2013		2014		2015		2016		2017
Arkansas		1,931		235		108		91				28		1,469
Kansas		2,117												2,117
Oklahoma		14,526		1,064		727		20						12,715
Other		1,603												1,603
TOTAL		20,177		1,299		835		111		0		28		17,904

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PROVED RESERVES

The following table summarizes estimates of proved reserves of oil, NGL and natural gas held by Panhandle as of September 30, 2012. All proved reserves are located onshore within the United States and are principally made up of small interests in 5,666 wells, predominately all of which are located in the Mid-Continent region. Other than this report, the Company’s reserve estimates are not filed with any other federal agency.

	Barrels of Oil		Barrels of NGL (1)		Mcf of Natural Gas		Mcfe
Net Proved Developed Reserves
September 30, 2012		849,548		494,160		65,733,119		73,795,367
September 30, 2011		759,989		386,774		60,193,878		67,074,456
September 30, 2010		861,240		—		57,344,190		62,511,630
Net Proved Undeveloped Reserves
September 30, 2012		222,771		294,582		47,780,937		50,885,055
September 30, 2011		83,749		404,874		41,644,106		44,575,844
September 30, 2010		63,769		—		40,826,265		41,208,879
Net Total Proved Reserves
September 30, 2012		1,072,319		788,742		113,514,056		124,680,422
September 30, 2011		843,738		791,648		101,837,984		111,650,300
September 30, 2010		925,009		—		98,170,455		103,720,509

(1) 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure. These NGL are associated with the rapid increase in drilling activity in western Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and the Anadarko Basin Woodford Shale) producing significant volumes of NGL.

The 13.0 Bcfe increase in total proved reserves from 2011 to 2012 is a combination of the following factors:

(1) Positive performance revisions of 3.6 Bcfe, of which 1.6 Bcfe were proved developed revisions principally attributable to properties in western Oklahoma. The remaining 2.0 Bcfe were proved undeveloped revisions principally attributable to higher proved reserves per well in the Company’s shale resource plays including the Fayetteville Shale, Southeastern Oklahoma Woodford Shale and the Anadarko Basin Woodford Shale.

(2) Negative pricing revisions (principally natural gas pricing) of 31.4 Bcfe, include 7.1 Bcfe of negative revisions due to proved developed wells reaching their economic limits earlier than previously projected resulting from current product prices. Negative revisions of 24.3 Bcfe were due to certain proved undeveloped locations, primarily in the Fayetteville Shale, Southeastern Oklahoma Woodford Shale and the Anadarko Basin Woodford Shale, becoming uneconomic at current product prices.

(3) Proved developed reserve additions of 7.8 Bcfe resulting from:

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a) The Company’s ongoing development of conventional oil, NGL and natural gas plays utilizing horizontal drilling, including the Granite Wash and Cleveland plays in western Oklahoma and the Texas Panhandle, as well as the Marmaton and Tonkawa plays in western Oklahoma.

b) The Company’s ongoing development of unconventional natural gas plays utilizing horizontal drilling, including the Arkansas Fayetteville Shale and, to a much lesser extent, the Southeastern Oklahoma Woodford Shale.

c) The Company’s ongoing development of unconventional oil, NGL and natural gas plays utilizing horizontal drilling in the Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale in western and southern Oklahoma.

(4) PUD additions of 24.5 Bcfe principally in the Fayetteville Shale play in Arkansas and the Anadarko Basin Woodford Shale play in western Oklahoma.

(5) Property purchases of 19.1 Bcfe primarily in the Fayetteville Shale play in Arkansas.

(6) Production of 10.6 Bcfe.

The following details the changes in proved undeveloped reserves for 2012 (Mcfe):

Beginning proved undeveloped reserves	44,575,844
Proved undeveloped reserves transferred to proved developed	(5,393,421	)
Revisions	(22,369,152	)
Extensions and discoveries	24,458,980
Purchases	9,612,804
Ending proved undeveloped reserves	50,885,055

The beginning PUD reserves were 44.6 Bcfe. A total of 5.4 Bcfe (12% of the beginning balance) were transferred to proved developed producing during 2012. An additional 24.3 Bcfe (55% of the beginning balance) were removed during 2012 as the result of becoming uneconomic at 2012 prices. A total of 29.7 Bcfe (67% of the beginning balance) of PUD reserves were moved out of the category during 2012 as either the result of being transferred to proved developed or removed as uneconomic. Only one PUD location from 2008, representing 1% of total 2012 PUD reserves remains in the PUD category while 45 PUD locations from 2009, representing 11% of total 2012 PUD reserves remain in the PUD category. The 46 PUD locations from 2008 and 2009 represent 8% of the Company’s current total of 589 PUD locations. We anticipate that all the Company’s PUD locations will be drilled and converted to PDP within five years of the date they were added. However, in the event that there are undrilled PUD locations at the end of the five-year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions.

The determination of reserve estimates is a function of testing and evaluating the production and development of oil and natural gas reservoirs in order to establish a production decline curve. The established production decline curves, in conjunction with oil and natural gas prices, development costs, production taxes and operating expenses, are used to estimate oil and natural gas reserve quantities and associated future net cash flows. As information is processed, over time, regarding the development of individual reservoirs and as market conditions change, estimated reserve quantities and future net cash flows will change as well. Estimated reserve quantities and future net cash flows are affected by changes in product prices. These prices have varied substantially in recent years and are expected to vary substantially from current pricing in the future.

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In January 2010, the FASB updated its oil and natural gas estimation and disclosure requirements to align its requirements with the SEC’s modernized oil and natural gas reporting rules, which were effective for annual reports on Form 10–K for fiscal years ending on or after December 31, 2009. The update included the following changes: (1) permitting use of new technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; (2) enabling companies to additionally disclose their probable and possible reserves to investors, in addition to their proved reserves; (3) allowing previously excluded resources, such as oil sands, to be classified as oil and natural gas reserves rather than mining reserves; (4) requiring companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria; (5) requiring the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; and (6) requiring companies to report oil and natural gas reserves using an average price based upon the prior 12-month period, rather than year-end prices. The update was applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and was effective for entities with annual reporting periods ending on or after December 31, 2009. Effective September 30, 2010, the Company adopted the new requirements. See Note 11 to the financial statements in Item 8 – “Financial Statements and Supplementary Data” for disclosures regarding our oil and natural gas reserves.

Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves, which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection), are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserve estimate, if the extraction is by means not involving a well.

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Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2012, 2011 and 2010 (see Exhibits 23 and 99).

The Company’s net proved oil, NGL and natural gas reserves (including certain undeveloped reserves described above) are located onshore in the United States. All studies have been prepared in accordance with regulations prescribed by the Securities and Exchange Commission. The reserve estimates were based on economic and operating conditions existing at September 30, 2012, 2011 and 2010. Since the determination and valuation of proved reserves is a function of testing and estimation, the reserves presented should be expected to change as future information becomes available.

ESTIMATED FUTURE NET CASH FLOWS

Set forth below are estimated future net cash flows with respect to Panhandle’s net proved reserves (based on the estimated units set forth above in Proved Reserves) for the year indicated, and the present value of such estimated future net cash flows, computed by applying a 10% discount factor as required by SEC rules and regulations. As of September 30, 2010, the Company adopted the SEC Rule, Modernization of Oil and Gas Reporting Requirements. In accordance with the SEC rule, the estimated future net cash flows were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-month period prior to September 30 held flat over the life of the properties and applied to future production of proved reserves less estimated future development and production expenditures for these reserves. The amounts presented are net of operating costs and production taxes levied by the respective states. The Company reported NGL reserves for the first time in the 2011 year-end report. Increased drilling activity over the last two years in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL production and reserves for the Company, necessitating inclusion in the reserve calculation. Prices used for determining future cash flows from oil, NGL and natural gas as of September 30, 2012 and 2011, were as follows: $89.41/Bbl, $35.70/Bbl, $2.51/Mcf ; $90.28/Bbl, $38.91/Bbl, $3.81/Mcf, respectively. Prices used for determining future cash flows from oil and natural gas as of September 30, 2010, were as follows: $69.23/Bbl, $4.33/Mcf. These future net cash flows based on SEC pricing rules should not be construed as the fair market value of the Company’s reserves. A market value determination would need to include many additional factors, including anticipated oil, NGL and natural gas price and production cost increases or decreases, which could affect the economic life of the properties.

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Estimated Future Net Cash Flows
	9-30-12		9-30-11		9-30-10
Proved Developed	$	165,036,044	$	211,851,992	$	202,056,455
Proved Undeveloped		72,851,862		91,232,949		84,200,597
Income Tax Expense		83,543,516		107,111,317		99,118,090
Total Proved	$	154,344,390	$	195,973,624	$	187,138,962
10% Discounted Present Value of Estimated Future Net Cash Flows
	9-30-12		9-30-11		9-30-10
Proved Developed	$	87,587,058	$	106,464,138	$	103,270,565
Proved Undeveloped		27,151,132		29,977,891		21,960,347
Income Tax Expense		47,323,902		58,059,595		52,730,503
Total Proved	$	67,414,288	$	78,382,434	$	72,500,409

OIL, NGL AND NATURAL GAS PRODUCTION

The following table sets forth the Company’s net production of oil, NGL and natural gas for the fiscal periods indicated.

	Year Ended		Year Ended		Year Ended
	9-30-12		9-30-11 (1)		9-30-10 (1)
Bbls - Oil		153,143		104,141		102,379
Bbls - NGL		98,714		*		*
Mcf - Natural Gas		9,072,298		8,297,657		8,302,342
Mcfe		10,583,440		8,922,503		8,916,616

(1) Natural gas production includes NGL volumes.

AVERAGE SALES PRICES AND PRODUCTION COSTS

The following tables set forth unit price and cost data for the fiscal periods indicated.

Average Sales Price	Year  Ended 9-30-12		Year Ended 9-30-11 (1)		Year Ended 9-30-10 (1)
Per Bbl, Oil	$	90.13	$	88.00	$	72.83
Per Bbl, NGL	$	33.23		*		*
Per Mcf, Natural Gas	$	2.62	$	4.13	$	4.41
Per Mcfe	$	3.86	$	4.87	$	4.94

(1) Proceeds from the sale of NGL have been included in natural gas sales and are therefore included in the price per Mcf of natural gas.

* The Company reported NGL reserves for the first time in its 2011 year-end reserve report. Increased drilling activity over the last two years in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL reserves and production for the Company. These reserve and production increases necessitated inclusion of NGL in the 2011 year-end reserve calculation and 2012 production volumes. In quarters prior to 2012, all NGL sales revenues were included with natural gas sales revenues.

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Average Production (lifting costs)	Year Ended 9-30-12		Year Ended 9-30-11		Year Ended 9-30-10
(Per Mcfe)
Well Operating Costs (1)	$	0.86	$	0.95	$	0.92
Production Taxes (2)		0.14		0.16		0.16
	$	1.00	$	1.11	$	1.08

(1) Includes actual well operating costs, compression, handling and marketing fees paid on natural gas sales and other minor expenses associated with well operations.

(2) Includes production taxes only.

Approximately 30% of the Company’s oil, NGL and natural gas revenue is generated from royalty payments on its mineral acreage. Royalty interests bear no share of the operating costs on those producing wells.

GROSS AND NET PRODUCTIVE WELLS AND DEVELOPED ACRES

The following table sets forth Panhandle’s gross and net productive oil and natural gas wells as of September 30, 2012. Panhandle owns either working interests, royalty interests or both in these wells. The Company does not operate any wells.

	Gross Working Interest Wells		Net Working Interest Wells		Gross Royalty Only Wells		Total Gross Wells
Oil		206		14.89		937		1,143
Natural Gas		1,648		80.42		2,875		4,523
Total		1,854		95.31		3,812		5,666

Panhandle’s average interest in royalty interest only wells is 0.86%. Panhandle’s average interest in working interest wells is 5.14% working interest and 4.97% net revenue interest.

Information on multiple completions is not available from Panhandle’s records, but the number is not believed to be significant.

As of September 30, 2012, Panhandle owned 427,620 gross developed mineral acres and 56,047 net developed mineral acres. Panhandle has also leased from others 135,526 gross developed acres containing 17,904 net developed acres.

UNDEVELOPED ACREAGE

As of September 30, 2012, Panhandle owned 1,259,293 gross and 198,965 net undeveloped mineral acres, and leases on 19,852 gross and 2,273 net undeveloped acres.

DRILLING ACTIVITY

The following net productive development, exploratory and purchased wells and net dry development, exploratory and purchased wells in which the Company had either a working interest, a royalty interest or both were drilled and completed during the fiscal years indicated.

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	Net Productive  Working Interest Wells		Net Productive Royalty Interest Wells		Net Dry Wells
Development Wells
Fiscal years ended:
September 30, 2012		5.376408		1.225832		0.093438
September 30, 2011		2.573391		0.907650		0.062188
September 30, 2010		2.953777		0.868179		0.057282
Exploratory Wells
Fiscal years ended:
September 30, 2012		0.298974		0.090654		0.531250
September 30, 2011		0.510643		0.372957		0.007813
September 30, 2010		0.029688		0.338320		0.000000
Purchased Wells
Fiscal years ended:
September 30, 2012		4.300626		0.231430		0.000000
September 30, 2011		0.000000		0.235058		0.000000
September 30, 2010		0.000000		0.000000		0.000000

PRESENT ACTIVITIES

The following table sets forth the gross and net oil and natural gas wells drilling or testing as of September 30, 2012, in which Panhandle owns either a working interest, a royalty interest or both. These wells were not producing at September 30, 2012.

	Gross Wells		Net Wells
Oil		6		0.18
Natural Gas		56		2.00

OTHER FACILITIES

The Company has a lease on 12,369 square feet for its office in Oklahoma City, Oklahoma, which ends April 30, 2015.

SAFE HARBOR STATEMENT

This report, including information included in, or incorporated by reference from, future filings by the Company with the SEC, as well as information contained in written material, press releases and oral statements, contains, or may contain, certain statements that are “forward-looking statements,” within the meaning of the federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address activities, events or developments which are expected to, or anticipated will, or may, occur in the future, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts” and similar expressions are used to identify forward-looking statements.

These forward-looking statements include, among others, such things as: the amount and nature

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of our future capital expenditures; wells to be drilled or reworked; prices for oil, NGL and natural gas; demand for oil, NGL and natural gas; estimates of proved oil, NGL and natural gas reserves; development and infill drilling potential; drilling prospects; business strategy; production of oil, NGL and natural gas reserves; and expansion and growth of our business and operations.

These statements are based on certain assumptions and analyses made by the Company in light of experience and perception of historical trends, current conditions and expected future developments as well as other factors believed appropriate in the circumstances. However, whether actual results and development will conform to our expectations and predictions is subject to a number of risks and uncertainties, which could cause actual results to differ materially from our expectations.

One should not place undue reliance on any of these forward-looking statements. The Company does not currently intend to update forward-looking information and to release publicly the results of any future revisions made to forward-looking statements to reflect events or circumstances, which reflect the occurrence of unanticipated events, after the date of this report.

In order to provide a more thorough understanding of the possible effects of some of these influences on any forward-looking statements made, the following discussion outlines certain factors that in the future could cause results for 2013 and beyond to differ materially from those that may be presented in any such forward-looking statement made by or on behalf of the Company.

Commodity Prices. The prices received for oil, NGL and natural gas production have a direct impact on the Company’s revenues, profitability and cash flows as well as the ability to meet its projected financial and operational goals. The prices for crude oil, NGL and natural gas are dependent on a number of factors beyond the Company’s control, including: the demand for oil, NGL and natural gas; weather conditions in the continental United States (which can greatly influence the demand for natural gas at any given time as well as the price we receive for such natural gas); and the ability of current distribution systems in the United States to effectively meet the demand for oil, NGL and natural gas at any given time, particularly in times of peak demand which may result because of adverse weather conditions.

Oil prices are sensitive to foreign influences based on political, social or economic factors, any one of which could have an immediate and significant effect on the price and supply of oil. In addition, prices of both natural gas and oil are becoming more and more influenced by trading on the commodities markets, which has, at times, increased the volatility associated with these prices.

Uncertainty of Oil, NGL and Natural Gas Reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and their values, including many factors beyond the Company’s control. The oil, NGL and natural gas reserve data included in this report represents only an estimate of these reserves. Oil and natural gas reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil, NGL and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil, NGL and natural gas reserves depend on a number of variable factors, including historical production from the area compared with production from other producing areas and assumptions concerning future oil, NGL and natural gas prices, future operating costs, severance and excise taxes, development costs, and workover and remedial costs.

Some or all of these assumptions may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil, NGL and natural gas and estimates of the future net cash flows from oil, NGL and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, oil, NGL and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual production, revenues and expenditures with respect to oil, NGL and natural gas reserves will vary from estimates, and those variances can be material.

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The Company does not operate any of the properties in which it has an interest and has very limited ability to exercise influence over operations for these properties or their associated costs. Dependence on the operator and other working interest owners for these projects and the limited ability to influence operations and associated costs could materially and adversely affect the realization of targeted returns on capital in drilling or acquisition activities and targeted production growth rates.

The information regarding discounted future net cash flows included in this report is not necessarily the current market value of the estimated oil, NGL and natural gas reserves attributable to the Company’s properties. As required by the SEC, the estimated discounted future net cash flows from proved oil, NGL and natural gas reserves are determined based on the fiscal year’s 12-month average of the first-day-of-the-month individual product prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Actual future net cash flows are also affected, in part, by the amount and timing of oil, NGL and natural gas production, supply and demand for oil, NGL and natural gas and increases or decreases in consumption.

In addition, the 10% discount factor required by the SEC used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and the risks associated with operations of the oil and natural gas industry in general.

ITEM 3 LEGAL PROCEEDINGS

There were no material legal proceedings involving Panhandle on September 30, 2012, or at the date of this report.

ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of Panhandle’s security holders during the fourth quarter of the fiscal year ended September 30, 2012.

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PART II

ITEM 5 MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND UNREGISTERED SALES OF EQUITY SECURITIES

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among Panhandle Oil & Gas Inc, the S&P Smallcap 600 Index,

and the S&P Oil & Gas Exploration & Production Index

* $100 invested on 9/30/07 in stock or index, including reinvestment of dividends.

Fiscal year ending September 30.

Copyright^© 2012 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

The above graph compares the 5-year cumulative total return provided shareholders on our Class A Common Stock (“Common Stock”) relative to the cumulative total returns of the S&P Smallcap 600 Index and the S&P Oil & Gas Exploration & Production Index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our Common Stock and in each of the indexes on September 30, 2007, and its relative performance is tracked through September 30, 2012.

Since July 22, 2008, the Company’s Common Stock has been listed and traded on the New York Stock Exchange (symbol PHX). The following table sets forth the high and low trade prices of the Common Stock during the periods indicated:

Quarter Ended	High		Low
December 31, 2010	$	28.70	$	23.75
March 31, 2011	$	31.88	$	25.60
June 30, 2011	$	32.50	$	27.30
September 30, 2011	$	36.25	$	26.36
December 31, 2011	$	36.00	$	26.18
March 31, 2012	$	33.74	$	28.05
June 30, 2012	$	30.57	$	24.16
September 30, 2012	$	33.49	$	27.85

At November 26, 2012, there were 1,539 holders of record of Panhandle’s Class A Common Stock and approximately 3,900 beneficial owners.

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During the past two years, the Company has paid quarterly dividends of $.07 per share on its Common Stock. Approval by the Company’s Board is required before the declaration and payment of any dividends.

While the Company anticipates it will continue to pay dividends on its Common Stock, the payment and amount of future cash dividends will depend upon, among other things, financial condition, funds from operations, the level of capital and development expenditures, future business prospects, contractual restrictions and any other factors considered relevant by the Board.

The Company’s credit facility also contains a provision limiting the paying or declaring of a cash dividend to 15% of net cash flow provided by operating activities from the Statement of Cash Flows of the preceding 12-month period. See Note 4 to the financial statements in Item 8 – “Financial Statements and Supplementary Data” for a further discussion of the credit facility.

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board approved the purchase 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. The Board’s approval included an initial authorization to purchase up to $1.5 million of Common Stock, with a provision for subsequent authorizations without specific action by the Board. As the amount of Common Stock purchased under any authorization reaches $1.5 million, another $1.5 million is automatically authorized for Common Stock purchases unless the Board determines otherwise. Pursuant to these resolutions adopted by the Board, the purchase of additional $1.5 million increments of the Company’s Common Stock became authorized and approved effective March 29, 2011, and March 14, 2012. The shares are held in treasury and are accounted for using the cost method. There were no Common Stock purchases in the fourth quarter of fiscal year 2012. At September 30, 2012, and September 30, 2011, 10,660 and 10,710 (respectively) treasury shares were contributed to the Company’s ESOP on behalf of the ESOP participants.

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ITEM 6 SELECTED FINANCIAL DATA

The following table summarizes financial data of the Company for its last five fiscal years and should be read in conjunction with Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Financial Statements of the Company, including the Notes thereto, included elsewhere in this report.

	As of and for the year ended September 30,
	2012		2011			2010			2009			2008
Revenues
Oil, NGL and natural gas sales	$	40,818,434	$	43,469,130		$	44,068,947		$	37,421,688		$	69,026,785
Lease bonuses and rentals		7,152,991		352,757			1,120,674			188,906			167,559
Gains (losses) on derivative contracts		73,822		734,299			6,343,661			(661,828	)		(940,823	)
Income from partnerships		487,070		420,465			405,134			323,848			631,891
		48,532,317		44,976,651			51,938,416			37,272,614			68,885,412
Costs and expenses
Lease operating expense		9,141,970		8,441,754			8,193,319			7,696,026			6,629,170
Production taxes		1,449,537		1,456,755			1,446,545			1,201,209			3,426,592
Exploration costs		979,718		1,025,542			1,583,773			711,582			455,943
Depreciation, depletion and amortization		19,061,239		14,712,188			19,222,123			28,168,933			19,784,660
Provision for impairment		826,508		1,728,162			605,615			2,464,520			526,380
Loss (gain) on asset sales, int. & other		39,493		(68,325	)		(1,028,148	)		(2,677,407	)		14,826
Gen. and administrative		6,388,856		5,994,663			5,594,499			4,866,044			5,006,512
Bad debt expense (recovery)		—		—			—			(185,272	)		591,258
		37,887,321		33,290,739			35,617,726			42,245,635			36,435,341
Income (loss) before provision (benefit) for income taxes		10,644,996		11,685,912			16,320,690			(4,973,021	)		32,450,071
Provision (benefit) for income taxes		3,274,000		3,192,000			4,901,000			(2,568,000	)		10,894,302
Net income (loss)	$	7,370,996	$	8,493,912		$	11,419,690		$	(2,405,021	)	$	21,555,769
Basic and diluted earnings (loss) per share	$	0.88	$	1.01		$	1.36		$	(0.29	)	$	2.54
Dividends declared per share	$	0.28	$	0.28		$	0.28		$	0.28		$	0.28
Weighted average shares outstanding
Basic and diluted		8,360,931		8,393,890			8,422,387			8,397,337			8,492,378
Net cash provided by (used in):
Operating activities	$	25,371,195	$	29,283,929		$	27,806,475		$	37,710,606		$	40,063,896
Investing activities	$	38,288,959	$	(27,200,816	)	$	(9,845,516	)	$	(36,322,992	)	$	(37,846,172	)
Financing activities	$	11,394,864	$	(4,173,372	)	$	(13,003,609	)	$	(1,643,414	)	$	(2,311,376	)
Total assets	$	135,186,730	$	111,424,193		$	105,124,839		$	108,549,632		$	122,007,183
Long-term debt	$	14,874,985	$	—		$	—		$	10,384,722		$	9,704,100
Shareholders’ equity	$	83,852,146	$	78,802,317		$	73,581,996		$	64,122,343		$	68,348,901

ITEM 7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS OVERVIEW

The Company’s principal line of business is to explore for, develop, produce and sell oil, NGL and natural gas. Results of operations are dependent primarily upon: reserve quantities and associated exploration and development costs in finding new reserves; production quantities and related production costs; and oil, NGL and natural gas sales prices. In the 2012 first quarter the Company acquired certain assets in the core of the Fayetteville Shale which included an average working interest of 2.3% in 193 producing non-operated natural gas wells and 1,531 acres of leasehold containing approximately 240 future infill drilling locations. This acquisition contributed to both increased drilling activity and increased natural gas production during 2012. During 2012, net wells drilled increased 69% over net wells drilled in 2011. However, capital expenditures only increased approximately 11% due to the average drilling and completion cost per well being lower in 2012 than in 2011. The lower drilling cost per well is primarily the result of drilling more wells in the Arkansas Fayetteville Shale during 2012 and less wells in the Anadarko Woodford Shale play where a typical well costs two and one half to three times that of a typical Fayetteville Shale well.

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Natural gas production was 9% higher in 2012 than in 2011. This production increase is the combined effect of added natural gas production from Fayetteville Shale acquisitions and continued drilling on the Company’s mineral and leasehold acreage.

Ongoing development in the following oily plays has resulted in a 47% increase in 2012 oil production, as compared to 2011:

• Horizontal Granite Wash in western Oklahoma and the Texas Panhandle

• Horizontal Cleveland in western Oklahoma and the Texas Panhandle

• Horizontal Marmaton in western Oklahoma

• Horizontal Tonkawa in western Oklahoma

• Vertical Mississippian in northern Oklahoma

• Vertical Spraberry in West Texas

• Vertical Yeso in southeastern New Mexico

• Horizontal Anadarko Basin Woodford Shale in western Oklahoma

• Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

As of September 30, 2012, the Company owned an average 3.6% net revenue interest in 62 wells that were drilling or testing. As these wells begin producing and other scheduled wells are drilled and completed in the abovementioned plays, the Company expects fiscal 2013 oil and natural gas production to increase over that of 2012.

Although oil, NGL and natural gas production increased in 2012, oil, NGL and natural gas sales revenues decreased 6% as a result of sharply lower natural gas prices, partially offset by a slight increase in oil prices. Based on recent forward strip pricing for 2013, the Company expects average natural gas prices to be higher and average oil prices to be slightly lower than the average prices of 2012.

The Company’s proved developed oil, NGL and natural gas reserves increased in 2012, compared to 2011, by 6.7 Bcfe. The increase is due to the Fayetteville Shale acquisitions and successful drilling of exploratory and developmental wells (in excess of PUD reserves previously presented), partially offset by negative natural gas pricing revisions. The overall increase in oil, NGL and natural gas production combined with the negative price revisions to 2012 proved developed natural gas reserves and higher finding cost experienced in the oil and liquids-rich areas resulted in higher DD&A in 2012.

Management currently expects drilling on the Company’s acreage to result in capital expenditures for oil and natural gas activities of approximately $25 million during 2013. The Company will also continue to evaluate opportunities to acquire mineral acreage or producing properties. Acquisitions, if any, will be financed by a combination of cash flows and the bank credit facility.

The Company had no off balance sheet arrangements during 2012 or prior years.

The following table reflects certain operating data for the periods presented:

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	For the Year Ended September 30,
			Percent					Percent
	2012		Incr. or (Decr.)			2011		Incr. or (Decr.)			2010
Production:
Oil (Bbls)		153,143		47	%		104,141		2	%		102,379
NGL (Bbls)		98,714		—			*		—			*
Natural Gas (Mcf)		9,072,298		9	%		8,297,657		0	%		8,302,342
Mcfe		10,583,440		19	%		8,922,503		0	%		8,916,616
Average Sales Price:
Oil (per Bbl)	$	90.13		2	%	$	88.00		21	%	$	72.83
NGL (per Bbl)	$	33.23		—			*		—			*
Natural Gas (Mcf) (1)	$	2.62		-37	%	$	4.13		-6	%	$	4.41
Mcfe	$	3.86		-21	%	$	4.87		-1	%	$	4.94

(1) Proceeds from the sale of NGL in 2011 and 2010 were included in natural gas sales, and were therefore included in the price per Mcf of natural gas.

* The Company reported NGL reserves for the first time in its 2011 year-end reserve report. Increased drilling activity over the last two years in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL reserves and production for the Company. These reserve and production increases necessitated inclusion of NGL in the 2011 year-end reserve calculation and 2012 production volumes. In quarters prior to 2012, all NGL sales revenues were included with natural gas sales revenues.

RESULTS OF OPERATIONS

Fiscal Year 2012 Compared to Fiscal Year 2011

Overview

The Company recorded net income of $7,370,996, or $0.88 per share, in 2012, compared to net income of $8,493,912, or $1.01 per share, in 2011. Revenues increased in 2012 primarily due to increased lease bonuses and higher oil and natural gas sales volumes, partially offset by lower natural gas prices.

Expenses increased due to higher DD&A, LOE and G&A in 2012, partially offset by decreases in the provision for impairment and exploration costs. Significant well additions through acquisition and drilling in 2012 increased production volumes and lifting costs, resulting in higher DD&A and LOE in 2012.

Oil, NGL and Natural Gas Sales

Oil, NGL and natural gas sales revenues decreased $2,650,696 or 6% for 2012, as compared to 2011. The decrease was due to lower natural gas prices of 37%, partially offset by increased oil volumes of 47%, increased natural gas volumes of 9% and a 2% increase in oil prices in 2012.

The oil production increase is due to continued drilling in western Oklahoma oily plays such as the horizontal Granite Wash, Cleveland, Tonkawa, Marmaton, Anadarko Basin Woodford Shale and other plays in Oklahoma, West Texas, Texas Panhandle and southeastern New Mexico. The natural gas production increase is mainly a result of production attributable to the acquisition in the Fayetteville Shale in Arkansas that the Company completed effective October 25, 2011. As of September 30, 2012, the Company owned an average 3.6% net revenue interest in 62 wells that were drilling or testing.

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Production by quarter for 2012 and 2011 was as follows:

	2012			2011
First quarter		2,559,524	Mcfe		2,208,218	Mcfe
Second quarter		2,654,485	Mcfe		2,152,011	Mcfe
Third quarter		2,649,351	Mcfe		2,129,160	Mcfe
Fourth quarter		2,720,080	Mcfe		2,433,114	Mcfe
Total		10,583,440	Mcfe		8,922,503	Mcfe

Lease Bonus and Rentals

Lease bonuses and rentals increased $6,800,234 in 2012. The increase was mainly due to the Company leasing 2,743 net mineral acres in Roger Mills County, Oklahoma, for $4.8 million. The rights leased were from the surface to 100 feet below the base of the Virgilian (commonly referred to as the Tonkawa). The Company also leased 2,431 net mineral acres in the horizontal Mississippian play in northern Oklahoma for $1.7 million. There were no large leases of the Company’s mineral acreage in 2011.

Gains (Losses) on Derivative Contracts

Realized and unrealized gains and losses are scheduled below:

Gains (Losses) on
Derivative Contracts	2012			2011
Realized	$	462,033		$	2,138,685
Unrealized		(388,211	)		(1,404,386	)
Total	$	73,822		$	734,299

The decrease in gains was mainly due to the natural gas basis protection swaps being less beneficial in 2012, as the basis differentials between NYMEX and CEGT and PEPL declined significantly. As of September 30, 2012, the Company’s natural gas basis protection swaps have expiration dates of December 2012; the natural gas costless collar contracts have expiration dates of October 2012 and January 2013; the oil costless collar contracts have expiration dates of December 2012.

Lease Operating Expenses (LOE) and Production Taxes

LOE increased $700,216 or 8% in 2012. LOE costs per Mcfe of production decreased from $.95 in 2011 to $.86 in 2012. The total LOE increase is primarily related to increased field operating costs of $487,388 in 2012 compared to 2011. Field operating costs increased mainly due to the large addition of wells through acquisition and drilling in 2012. Field operating costs were $.42 per Mcfe in 2012 compared to $.44 per Mcfe in 2011, a 5% decrease. This decrease in rate is principally the result of fewer well workovers performed in 2012.

The increase in LOE related to field operating costs was also coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) on natural gas of $212,828 in 2012, as compared to 2011. On a per Mcfe basis, these fees were down $.06 due to lower natural gas prices and the addition of significant oil production, which is unencumbered by these fees. Handling fees are mainly charged as a percent of natural gas sales but can also be charged based on natural gas production volumes.

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Exploration Costs

Exploration costs were $979,718 in 2012 compared to $1,025,542 in 2011, a $45,824 decrease. During 2012, leasehold impairment and expired leasehold totaled $377,942 compared to $482,491 during 2011, a $104,549 decrease. The decline was driven by lower provisions for expected lease expirations in 2012, as compared to 2011. Charges on three exploratory dry holes totaled $601,776 during 2012; whereas, in 2011 the Company incurred exploratory dry hole costs on two wells totaling $543,051.

Depreciation, Depletion and Amortization (DD&A)

DD&A increased $4,349,051 or 30% in 2012. DD&A per Mcfe was $1.80 in 2012 compared to $1.65 in 2011. DD&A increased $2,738,695 due to oil, NGL and natural gas production volumes increasing 19% in the 2012 period compared to the 2011 period. The remaining increase of $1,610,356 was caused by a $.15 increase in the DD&A rate. This rate increase is mainly due to negative price revisions reducing ultimate reserves on a significant number of wells in reserves reported at September 30, 2012, as well as higher finding cost experienced in oil and liquids-rich areas where the Company is drilling and has had new wells come on line.

Provision for Impairment

The provision for impairment decreased $901,654 in 2012, as compared to 2011. During 2012, impairment of $826,508 was recorded on twelve small fields in Oklahoma. These fields have one to a few wells and are more susceptible to impairment when a well in the field experiences downward reserve revisions, or when a newly completed well with little production history is added to one of these fields. During the 2011 period, impairment of $1,728,162 was recorded on nine small fields in Oklahoma and Texas.

General and Administrative Costs (G&A)

G&A increased $394,193 or 7% in 2012. The increase is primarily related to increases in the following expense categories: personnel $419,166 and legal fees $118,245. These were partially offset by decreases in technical consulting, Board fees, company insurance and other expenses of $143,218 in 2012. The increase in 2012 personnel related expenses was the result of additional employees and annual increases in salaries and bonuses totaling $206,806, restricted stock expense increase of $178,441 and higher ESOP expense of $25,475. The increase in legal expenses resulted from increased acquisition activity and a quiet title defense settlement in 2012.

Provision (Benefit) for Income Taxes

The 2012 provision for income taxes of $3,274,000 was based on a pre-tax income of $10,644,996, as compared to a provision for income taxes of $3,192,000 in 2011, based on a pre-tax income of $11,685,912. The effective tax rate for 2012 was 31%, compared to an effective tax rate for 2011 of 27%. The 2012 effective tax rate increase of 4% was due to increased state income taxes of $553,926, partially offset by an excess percentage depletion benefit increase of $112,524. The 2012 state income tax increase was a result of significantly higher lease bonus income in Oklahoma, combined with lower intangible drilling cost deductions from Oklahoma taxable income. The Company’s utilization of excess percentage depletion (which is a permanent tax benefit) decreases the provision for income taxes. The benefit of excess percentage depletion is not directly related to the amount of recorded income or loss. Accordingly, in cases where the recorded income or loss is relatively small, the proportional effect of the excess percentage depletion on the effective tax rate may become significant.

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Fiscal Year 2011 Compared to Fiscal Year 2010

Overview

The Company recorded net income of $8,493,912, or $1.01 per share, in 2011, compared to net income of $11,419,690, or $1.36 per share, in 2010. Decreased revenues in 2011 were primarily due to lower realized and unrealized gains on derivative contracts and lower lease bonuses and rentals. Actual and forward looking prices were lower than the Company’s derivative contracts during 2011, resulting in net gains on derivative contracts; however, the variation during 2011 was not as significant as in 2010, therefore, gains on derivative contracts during 2011 were significantly less. The renewal of leases on certain of the Company’s Arkansas undeveloped mineral acreage generated significant lease bonuses during 2010; whereas there were no such renewals in 2011.

Expenses decreased due to lower DD&A and exploration costs in 2011, partially offset by increases in the provision for impairment, general and administrative costs and a decrease in gain on asset sales, interest and other. The positive performance revisions recognized in the reserves reported at September 30, 2010, resulted in lower 2011 DD&A.

Oil and Natural Gas Sales

Oil and natural gas sales revenues decreased $599,817 or 1% for 2011, as compared to 2010. A decline in natural gas prices of 6% from 2010 to 2011, partially offset by a 21% increase in oil prices in 2011, caused the reduction of oil and natural gas sales revenues. Production from wells that came on line in 2011 offset the natural decline of existing wells such that oil and natural gas production volume in 2011 was relatively flat compared to 2010 volumes.

Drilling activity increased during the last quarter of 2010 and continued at a much higher rate throughout 2011, as compared to the first nine months of fiscal 2010. This increase in drilling activity resulted in 2011 production volumes (on an Mcfe basis) that were flat compared to those of 2010. The increased drilling activity is primarily on the Company’s mineral acreage in the Arkansas Fayetteville Shale and in the oil and natural gas liquids-rich plays such as the Anadarko Woodford Shale, Horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and other similar plays in western Oklahoma. As of September 30, 2011, the Company owned an average 2.6% net revenue interest in 48 wells that were drilling or testing.

Production by quarter for 2011 and 2010 was as follows:

	2011			2010
First quarter		2,208,218	Mcfe		2,278,133	Mcfe
Second quarter		2,152,011	Mcfe		2,090,154	Mcfe
Third quarter		2,129,160	Mcfe		2,236,236	Mcfe
Fourth quarter		2,433,114	Mcfe		2,312,093	Mcfe
Total		8,922,503	Mcfe		8,916,616	Mcfe

Lease Bonus and Rentals

Lease bonus and rentals decreased $767,917 for 2011, as compared to 2010. Lease bonus and rental revenues in 2010 included lease bonuses of approximately $723,000 from certain of the Company’s Arkansas mineral acreage, whereas there were no large leases of Company acreage in 2011.

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Gains (Losses) on Derivative Contracts

Realized and unrealized gains and losses are scheduled below:

Gains (Losses) on
Derivative Contracts	2011			2010
Realized	$	2,138,685		$	2,209,900
Unrealized		(1,404,386	)		4,133,761
Total	$	734,299		$	6,343,661

The Company’s natural gas fixed price swap contracts had expiration dates of October 2011; the oil costless collar contracts have expiration dates of December 2011; the natural gas basis protection swaps have expiration dates of December 2011 and December 2012.

Lease Operating Expenses (LOE) and Production Taxes

LOE increased $248,435 or 3% in 2011. LOE costs per Mcfe of production increased from $.92 in 2010 to $.95 in 2011. The total LOE increase and the LOE per Mcfe increase were primarily related to increased field operating costs of approximately $276,000 in 2011 compared to 2010. Field operating costs were $.44 per Mcfe in 2011 compared to $.41 per Mcfe in 2010, a 7% increase. These increases were principally the result of well workovers performed in 2011.

Handling fees (primarily gathering, transportation and marketing costs) on natural gas in 2011 were slightly less than those of 2010. These fees decreased LOE approximately $28,000 in 2011.

Production taxes increased $10,210 or 1% in 2011. Some wells previously eligible for production tax credits or reductions, primarily in Oklahoma and Arkansas, lost their eligibility during 2011 due to meeting either time or payout thresholds stipulated in Oklahoma and Arkansas production tax laws.

Exploration Costs

Exploration costs were $1,025,542 in 2011 compared to $1,583,773 in 2010, a $558,231 decrease. During 2011, leasehold impairment and expired leasehold totaled $482,491 compared to $1,191,598 during 2010, a $709,107 decrease. The decline was driven by lower provisions for expected lease expirations in 2011, as compared to 2010. Charges on two exploratory dry holes totaled $543,051 during 2011; whereas, in 2010 the Company incurred minor exploratory dry hole costs totaling $4,541. During 2010, $387,634 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)

Total DD&A decreased $4,509,935 or 24% in 2011, while DD&A per Mcfe decreased to $1.65 in 2011, as compared to $2.16 in 2010. The DD&A decrease was attributable to the $.51 decline in the DD&A rate per Mcfe. This rate decline in 2011 was due to the positive performance revisions recognized in the reserves reported at September 30, 2010.

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Provision for Impairment

The provision for impairment increased $1,122,547 in 2011, as compared to 2010. During 2011, impairment of $1,728,162 was recorded on nine small fields in Oklahoma and Texas. These fields had few wells and are more susceptible to impairment when a well in the field experiences downward reserve revisions, or when a newly completed well with little production history is added to one of these fields. On one of these fields, a new material well began production on September 27, 2011. The well’s early production was significantly impacted by the recovery of large volumes of water utilized in the fracture treatment. Since the well’s early production had been low, while at the same time producing large volumes of load water, the calculated reserves and future net cash flows were calculated to be significantly less than was previously attributed to the well, resulting in a material impairment to the field of $590,629. Wells such as this are subject to performance revisions going forward as more is known of their production history and pattern. During the 2010 period, impairment of $605,615 was recorded on six small fields.

Included in the 2011 total above, was an impairment charge of $716,448 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. As of September 30, 2011, this well had a net book value of $503,960 after impairment. Costs on this well were extraordinarily high due to this well being the first and only horizontal well drilled in the field.

Loss (Gain) on Asset Sales, Interest and Other

In 2010, the Company received $1,124,682 from the settlement of a lawsuit related to one well in western Oklahoma. No interest expense was incurred during 2011, compared to interest expense of $60,912 recorded in 2010.

General and Administrative Costs (G&A)

G&A increased $400,164 or 7% in 2011. The increase was primarily related to increases in the following expense categories: personnel $346,331; Board fees $92,674; computer consulting fees $20,000; and reservoir engineering fees $71,000. The above were partially offset by a decrease in legal fees of $228,837 in 2011. The increase in 2011 personnel related expenses was the result of annual increases in salaries and bonuses totaling approximately $113,000, a restricted stock expense increase of $140,454, a rise in employee insurance costs of $22,713 and higher ESOP expense of $20,220. The increase in Board fees resulted from the addition of one director in May 2010 (resulting in partial year retainer and meeting fees during 2010, but a full year’s fees during 2011) combined with increases in annual retainer fees and meeting fees paid to directors during 2011.

Non-recurring legal fees of approximately $230,000 were expensed during 2010 related to a lawsuit on one well in western Oklahoma and to the 2008 bankruptcy of SemGroup, L.P., which owed the Company for crude oil they had purchased.

Provision (Benefit) for Income Taxes

The 2011 provision for income taxes of $3,192,000 was based on a pre-tax income of $11,685,912, as compared to a provision for income taxes of $4,901,000 in 2010, based on a pre-tax income of $16,320,690. Income taxes in 2010 were reduced by the removal of the $278,000 valuation allowance on Oklahoma NOLs which reduced the effective tax rate by 2%. The effective tax rate for 2011 was 27%, compared to an effective tax rate for 2010 of 30%. The Company’s utilization of excess percentage depletion (which is a permanent tax benefit) decreases the provision for income taxes. The benefit of excess percentage depletion is not directly related to the amount of recorded income or loss. Accordingly, in cases where the recorded income or loss is relatively small, the proportional effect of the excess percentage depletion on the effective tax rate may become significant.

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LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2012, the Company had positive working capital of $3,995,103, as compared to positive working capital of $7,314,096 at September 30, 2011.

Liquidity

Cash and cash equivalents were $1,984,099 as of September 30, 2012, compared to $3,506,999 at September 30, 2011, a decrease of $1,522,900. Cash flows for the 12 months ended September 30 are summarized as follows:

Net cash provided (used) by:

	2012			2011			Change
Operating activities	$	25,371,195		$	29,283,929		$	(3,912,734	)
Investing activities	$	(38,288,959	)	$	(27,200,816	)	$	(11,088,143	)
Financing activities	$	11,394,864		$	(4,173,372	)	$	15,568,236
Increase (decrease) in cash and cash equivalents	$	(1,522,900	)	$	(2,090,259	)	$	567,359

Operating activities:

The decrease of $3,912,734 in cash provided by operating activities is primarily the effect of the following:

Decreased collections of oil, NGL and natural gas sales (net of withheld production taxes and handling fees) for the 2012 period compared to the 2011 period resulted in less cash provided by operating activities of $2,436,566.

Realized gains on derivative contracts decreased $1,676,652 in 2012, as compared to 2011.

Income tax payments in 2012 were $1,356,706 compared to payments of $2,584,172 in 2011, a decrease of $1,227,466.

Cash expenditures for lease operating expenses (other than handling fees) increased $841,408 in 2012 compared to 2011.

Expenditures for G&A, interest and other expenses during 2012 increased $343,927, as compared to the 2011. These expenditures were the result of higher personnel, technical consulting, auditing, tax preparation and legal costs.

Investing activities:

Net cash used in investing activities increased $11,088,143 during the 2012 period, the result of the following:

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Capital expenditures for drilling activity increased $2,407,398 from $22,739,908 in 2011 to $25,147,306 in 2012.

The Company acquired producing properties, leasehold and mineral acreage in Arkansas and Oklahoma totaling $20,144,121 during 2012, as compared to $4,805,440 during 2011, a $15,338,681 increase.

Lease bonus payments received increased $6,876,001 during 2012, as compared to 2011. In December 2011, the Company leased 2,431 net mineral acres in the horizontal Mississippian play in northern Oklahoma and received $1,713,717 in lease bonus payments. In April 2012, lease bonus payments of $4,800,461 were received by the Company as a result of leasing partial rights on 2,743 of its net mineral acres in Roger Mills County, Oklahoma.

Financing activities:

Net cash provided by financing activities in 2012 was $11,394,864, as compared to 2011 net cash used in financing activities of $4,173,372. The net cash provided increase of $15,568,236 is explained as follows:

The Company financed the acquisitions of producing properties, mineral acreage and leasehold in Arkansas and Oklahoma utilizing its credit facility with Bank of Oklahoma and cash. These acquisitions and higher expenditures to drill and complete wells in 2012, as compared to 2011, resulted in cash provided by financing activities through net borrowings during 2012 of $14,874,985, as compared to $0 in 2011.

Treasury stock purchases in the 2012 period totaled $1,158,957, as compared to $1,851,290 in the 2011 period, resulting in a $692,333 decrease of cash used.

Capital Resources

Capital expenditures for drilling increased approximately $2.4 million (11%) from 2011 to 2012 as drilling activity, primarily in the Fayetteville Shale, western Oklahoma and the Texas Panhandle continued at a relatively steady pace during the first three quarters of 2012 and then increased significantly during the 2012 fourth quarter and thus far into 2013. A significant portion of the Fayetteville Shale drilling continued to be on the acreage acquired during the 2012 first quarter. In western Oklahoma, the Texas Panhandle and other areas drilling continues to be very active where the Company owns substantial mineral and leasehold acreage in oil and liquids-rich areas, which include the following horizontal and vertical plays:

• Horizontal Granite Wash in western Oklahoma and the Texas Panhandle

• Horizontal Cleveland in western Oklahoma and the Texas Panhandle

• Horizontal Marmaton in western Oklahoma

• Horizontal Tonkawa in western Oklahoma

• Vertical Mississippian in northern Oklahoma

• Vertical Spraberry in West Texas

• Vertical Yeso in southeastern New Mexico

• Horizontal Anadarko Basin Woodford Shale in western Oklahoma

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• Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

Capital expenditures for drilling projects in 2012 were $25,147,306, while 2012 asset acquisitions totaled $20,144,121, a combined $45,291,427. Capital expenditures for drilling projects in 2013 are expected to be approximately $25 million. Although there may be decreases in oil, NGL and natural gas production from quarter to quarter (depending on the timing of new wells coming on line), we expect these capital outlays to result in an overall continued trend of production increases for 2013. We will also continue to evaluate opportunities to acquire additional production or acreage.

Please note, since the Company is not the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of future participation in drilling and completing new wells and associated capital expenditures.

In April 2012, a transaction was completed in which the Company leased partial rights on its mineral acres located in Roger Mills County, Oklahoma, to a large independent exploration and production company. The lease term is three years and the Company received an upfront cash bonus and retained a three-sixteenths non-cost bearing royalty interest in all production from future wells drilled on these leased rights. After post-closing adjustments, the net mineral acres leased totaled 2,743 and the cash bonus received was $4,800,461. The rights leased were from the surface to 100 feet below the base of the Virgilian (the base of the Virgilian is equivalent to the base of the Tonkawa). The Company retained the rights to deeper formations including the Granite Wash, Hogshooter Wash, Cleveland and Marmaton, which are expected to yield better and more predictable well results. This transaction does not include any of the Company’s existing production or current proved oil, NGL or natural gas reserves. The Company retained its perpetual mineral ownership in the acreage. Panhandle routinely weighs the value of leasing our mineral rights against participation with a working interest in drilling opportunities, whether it is well-by-well or on a broader scope, to determine the optimum method to maximize the value of Panhandle’s assets.

Production of oil, NGL and natural gas increased 19% on an Mcfe basis during 2012, as compared to 2011. The Company first reported NGL production in the first quarter of 2012. Increased drilling activity over the last two years in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL production and reserves for the Company, necessitating the inclusion of NGL production beginning with the first quarter of 2012. The inclusion of NGL in the reserve calculation began with the 2011 year-end reserve report. Prior to then, the quarterly reports and reserve calculations included NGL sales revenues with natural gas sales revenues. Production increased in 2012 as a result of the addition of acquired wells and new wells production exceeding the natural production decline of existing wells. Looking forward, we expect 2013 production to exceed 2012 production as wells continue to come on line throughout fiscal 2013.

Natural gas prices received by the Company declined through May 2012 to below $2.00 per Mmbtu, but rebounded to approximately $2.40 per Mmbtu during September 2012. NYMEX natural gas futures prices (the Company receives on average approximately 93% of NYMEX price for its natural gas sales) indicate price improvement to the mid $3.00 per Mmbtu level as an average for fiscal 2013. As of September 30, 2012, the Company had costless collar contracts covering 7,000 barrels per month of oil production through December 2012, 430,000 Mmbtu per month of natural gas production through October 2012, 350,000 Mmbtu per month of natural gas production from November 2012 through January 2013, and basis protection swap contracts covering 190,000 Mmbtu per month of natural gas production through December 2012. With continued oil and natural gas price volatility, management continues to evaluate opportunities for product price protection by hedging a portion of the Company’s future oil and natural gas production.

Cash provided by operating activities during 2012 of $25,371,196 funded capital expenditures for

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drilling and equipping wells of $25,147,306. After payment of our regular $.07 per share quarterly dividends totaling $2,321,164, treasury stock purchases of $1,158,957, net borrowings under the Company’s revolving credit facility of $14,874,985 and other miscellaneous investing activities, cash was reduced during 2012 by $1,522,900. During 2012, the Company utilized excess cash and the bank credit facility to finance approximately $20 million in asset purchases. Net outstanding borrowings on the credit facility at September 30, 2012, were $14,874,985.

Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and equipping of wells, treasury stock purchases and dividend payments primarily from cash flow and cash on hand. As management evaluates opportunities to acquire additional assets, additional borrowings utilizing our bank credit facility could be necessary. Also, during times of oil, NGL and natural gas price decreases, or increased expenditures for drilling, it may be necessary to utilize the credit facility further in order to fund these expenditures. The Company has availability ($20,125,015 at September 30, 2012) under its revolving credit facility and is in compliance with 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 2013, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund additional acquisitions.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan with a limit in the amount of $80,000,000 which is subject to a semi-annual borrowing base determination. The current borrowing base is $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $41,343,303 at September 30, 2012. The revolving loan matures on November 30, 2014. Borrowings under the revolving loan are due at maturity. The revolving loan bears interest at the national prime rate plus a range of .50% to 1.25%, or 30 day LIBOR plus a range of 2.00% to 2.75% annually. The election of national prime or LIBOR is at the Company’s discretion. 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.

Determinations of the borrowing base are made semi-annually or whenever BOK believes there has been a material change in the value of the Company’s 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 September 30, 2012, the Company was in compliance with these covenants.

The table below summarizes the Company’s contractual obligations and commitments as of September 30, 2012:

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	Payments due by period
Contractual Obligations and Commitments	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Long-term debt obligations	$	14,874,985	$	—	$	14,874,985	$	—	$	—
Building lease	$	527,229	$	204,089	$	323,140	$	—	$	—

At September 30, 2012, the Company’s derivative contracts were in a liability position of $172,271. The ultimate settlement amounts of the derivative contracts are unknown because they are subject to continuing market risk. Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the derivative contracts.

As of September 30, 2012, the Company’s asset retirement obligations were $2,122,950. Asset retirement obligations represent the Company’s share of the future expenditures to plug and abandon the wells in which the Company owns a working interest when the oil, NGL and natural gas reserves are depleted. These amounts were not included in the schedule above due to the uncertainty of timing of the obligations. Please read Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the Company’s asset retirement obligations.

CRITICAL ACCOUNTING POLICIES

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change the Company’s reported cash flows or liquidity. Existing rules must be interpreted and judgments made on how the specifics of a given rule apply to the Company.

The more significant reporting areas impacted by management’s judgments and estimates are crude oil, NGL and natural gas reserve estimation, derivative contracts, impairment of assets, oil, NGL and natural gas sales revenue accruals, refundable production taxes and provision for income tax. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists, consultants and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. The oil, NGL and natural gas sales revenue accrual is particularly subject to estimate inaccuracies due to the Company’s status as a non-operator on all of its properties. As such, production and price information obtained from well operators is substantially delayed. This causes the estimation of recent production and prices used in the oil, NGL and natural gas revenue accrual to be subject to future change.

Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. These estimates affect the unaudited standardized measure disclosures included in Note 11 to the financial statements in Item 8 – “Financial Statements and Supplementary Data,” as well as DD&A and impairment calculations. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, asset retirement obligations 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, NGL and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance

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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 which are updated through the current period. In accordance with the SEC rules, 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. Based on the Company’s 2012 DD&A, a 10% change in the DD&A rate per Mcfe would result in a corresponding $1,906,124 annual change in DD&A expense. Crude oil, NGL 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, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.

Successful Efforts Method of Accounting

The Company has elected to utilize the successful efforts method of accounting for its oil and natural gas exploration and development activities. This means exploration expenses, including geological and geophysical costs, non producing lease impairment, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by property using the unit-of-production method (the ratio of oil, NGL and natural gas volumes produced to total proved or proved developed reserves is used to amortize the remaining asset basis on each producing property) as oil, NGL and natural gas is produced. The Company’s exploratory wells are all on-shore and primarily located in the Mid-Continent area. Generally, expenditures on exploratory wells comprise less than 10% of the Company’s total expenditures for oil and natural gas properties. This accounting method may yield significantly different operating results than the full cost method.

Derivative Contracts

The Company entered into oil costless collar contracts, natural gas costless collar contracts, natural gas fixed swap contracts and natural gas basis protection swaps. 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 for 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 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. 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 unsecured.

The Company is required to recognize all derivative instruments as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. At September 30, 2012, the Company had no derivative contracts designated as cash flow hedges, and therefore, changes in the fair value of derivatives are reflected in earnings.

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Impairment of Assets

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, NGL and natural gas; future production costs; estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof: the economic and regulatory climates and other factors. The Company estimates future net cash flows on its oil and natural gas properties utilizing differentially adjusted forward pricing curves for oil, NGL and natural gas and a discount rate in line with the discount rate we believe is most commonly used by the market participants (10% for all periods presented). The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. A significant reduction in oil, NGL and natural gas prices (which are reviewed quarterly) or a decline in reserve volumes (which are re-evaluated semi-annually) would likely lead to additional impairment that may be material to the Company. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.

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, 2012, the remaining carrying cost of non-producing oil and natural gas leases was $694,968.

Oil, NGL and Natural Gas Sales Revenue Accrual

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.

Income Taxes

The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at

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the end of each fiscal year. During interim periods, an estimate is made taking into account historical data and current pricing. The Company has certain state net operating loss carry forwards (NOLs) that are recognized as tax assets when assessed as more likely than not to be utilized before their expiration dates. Criteria such as expiration dates, future excess state depletion and reversing taxable temporary differences are evaluated to determine whether the NOLs are more likely than not to be utilized before they expire. If any NOLs are determined to no longer be more likely than not to be utilized, then a valuation allowance is recognized to reduce the tax benefit of such NOLs. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.

Refundable Production Taxes Accrual

The State of Oklahoma allows for refunds of production taxes on wells that are horizontally drilled. In order to qualify as a horizontally drilled well, the well must have been completed in a manner which encounters and subsequently produces from a geological formation at an angle in excess of seventy degrees from the vertical and which laterally penetrates a minimum of one hundred and fifty feet into the pay zone of the formation. An operator has 18 months after a given tax year to file the appropriate forms with the Oklahoma Tax Commission requesting the refund of production taxes. The refund is limited to 48 months from first sales or well payout, whichever comes first. Horizontal drilling in Oklahoma over the past four years has resulted in the addition of numerous wells that qualify for the Oklahoma horizontal exemption, thus increasing the Company’s oil, NGL and natural gas sales subject to the accrual.

The Company does not operate any of its oil and natural gas properties and thus must rely on oil, NGL and natural gas sales and drilling information from the operators. The Company utilizes payment remittances from operators to estimate its refundable production tax accrual at the end of each quarterly period. The refundable production tax accrual can be impacted by many variables, including subsequent revenue adjustments received from operators and an operator’s failure to file timely with the Oklahoma Tax Commission requesting refunds. These variables could lead to an over or under accrual of production taxes at the end of any particular period. Based on historical experience, the estimated accrual has been materially accurate.

During the 2010 legislative session, the Oklahoma State Legislature passed House Bill 2432, which provided for the deferral of the payment of certain gross production tax rebates by the Oklahoma Tax Commission for the production periods ending June 30, 2010, (tax year 2010) and June 30, 2011, (tax year 2011) for horizontally drilled wells. These deferred payments are being paid out over a period of three years beginning July 1, 2012. As a concession to producers for accepting the three-year deferral period, the State of Oklahoma, beginning with July 1, 2012, production, reduced the production tax rate rather than pay rebates in future periods. As such, the latest production date in the refundable production tax accrual is June 30, 2011. Given that the Company has received essentially all revenues for Oklahoma horizontal wells for the production periods through June 30, 2011, the refundable production tax accrual should not increase in amount in future periods and should decrease consistently over the next three fiscal years until completely refunded.

The above description of the Company’s critical accounting policies is not intended to be an all-inclusive discussion of the uncertainties considered and estimates made by management in applying generally accepted accounting principles and policies. Results may vary significantly if different policies were used or required and if new or different information becomes known to management.

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ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of oil, NGL and natural gas price trends, and there remains a wide divergence in the opinions held 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 NGL 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 oil, NGL and natural gas in 2013 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 2013 natural gas derivative contracts (see below), based on the Company’s estimated natural gas volumes for 2013, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,050,000 for operating revenue. Based on the Company’s estimated oil volumes for 2013, the price sensitivity in 2013 for each $1.00 per barrel change in wellhead oil is approximately $155,000 for operating revenue.

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 September 30, 2012, the Company has natural gas basis protection swaps and oil and natural gas 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 natural gas 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 $57,000. For the Company’s natural gas collars, a change of $.10 in the forward strip prices would result in a change to pre-tax operating income of approximately $58,000. 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 $10,000.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facility. 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 September 30, 2012, the Company had $14,874,985 outstanding under this facility. 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.

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ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Annual Report on Internal Control Over Financial Reporting	42
Report of Registered Public Accounting Firm on Internal Control Over Financial Reporting	43
Report of Independent Registered Public Accounting Firm	44
Balance Sheets As of September 30, 2012 and 2011	45
Statements of Operations for the Years Ended September 30, 2012, 2011 and 2010	47
Statements of Stockholders’ Equity for the Years Ended September 30, 2012, 2011 and 2010	48
Statements of Cash Flows for the Years Ended September 30, 2012, 2011 and 2010	49
Notes to Financial Statements	51

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Management’s Annual Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934 (the “Exchange Act”) as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2012. In making this assessment, the Company’s management used the criteria set forth in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, management has concluded that, as of September 30, 2012, the Company’s internal control over financial reporting was effective based on those criteria.

Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. This report appears on the following page.

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Report of Independent Registered Public Accounting Firm

on Internal Control Over Financial Reporting

The Board of Directors and Stockholders of

Panhandle Oil and Gas Inc.

We have audited Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Panhandle Oil and Gas Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Panhandle Oil and Gas Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of Panhandle Oil and Gas Inc. as of September 30, 2012 and 2011, and the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2012 and our report dated December 11, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

December 11, 2012

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Panhandle Oil and Gas Inc.

We have audited the accompanying balance sheets of Panhandle Oil and Gas Inc. (the Company) as of September 30, 2012 and 2011, and the related statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended September 30, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Panhandle Oil and Gas Inc. at September 30, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2012, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the financial statements, in 2010 Panhandle Oil and Gas Inc. changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 11, 2012, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

December 11, 2012

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Panhandle Oil and Gas Inc.

Balance Sheets

	September 30,
	2012		2011
Assets
Current Assets:
Cash and cash equivalents	$	1,984,099	$	3,506,999
Oil, NGL and natural gas sales receivables		8,349,865		8,811,404
Refundable income taxes		325,715		354,246
Refundable production taxes		585,454		223,672
Deferred income taxes		121,900		—
Derivative contracts		—		269,329
Other		255,812		95,408
Total current assets		11,622,845		13,261,058
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		275,997,569		230,554,198
Non-producing oil and natural gas properties		10,150,561		11,100,350
Furniture and fixtures		668,004		628,929
		286,816,134		242,283,477
Less accumulated depreciation, depletion and amortization		165,199,079		146,147,514
Net properties and equipment		121,617,055		96,135,963
Investments		1,034,870		667,504
Refundable production taxes		911,960		1,359,668
Total assets	$	135,186,730	$	111,424,193

(Continued on next page)

See accompanying notes.

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Panhandle Oil and Gas Inc.

Balance Sheets

	September 30,
	2012			2011
Liabilities and Stockholders’ Equity
Current Liabilities:
Accounts payable	$	6,447,692		$	4,899,593
Derivative contracts		172,271			—
Deferred income taxes		—			7,100
Accrued liabilities and other		1,007,779			1,040,269
Total current liabilities		7,627,742			5,946,962
Long term debt		14,874,985			—
Deferred income taxes		26,708,907			24,777,650
Asset retirement obligations		2,122,950			1,843,875
Derivative contracts		—			53,389
Stockholders’ equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at September 30, 2012 and 2011		140,524			140,524
Capital in excess of par value		2,020,229			1,924,507
Deferred directors’ compensation		2,676,160			2,665,583
Retained earnings		84,821,395			79,771,563
		89,658,308			84,502,177
Treasury stock, at cost; 181,310 shares at September 30, 2012, and 175,331 shares at September 30, 2011		(5,806,162	)		(5,699,860	)
Total stockholders’ equity		83,852,146			78,802,317
Total liabilities and stockholders’ equity	$	135,186,730		$	111,424,193

See accompanying notes.

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Panhandle Oil and Gas Inc.

Statements of Operations

	Year ended September 30,
	2012		2011			2010
Revenues:
Oil, NGL and natural gas sales	$	40,818,434	$	43,469,130		$	44,068,947
Lease bonuses and rentals		7,152,991		352,757			1,120,674
Gains (losses) on derivative contracts		73,822		734,299			6,343,661
Income from partnerships		487,070		420,465			405,134
		48,532,317		44,976,651			51,938,416
Costs and expenses:
Lease operating expenses		9,141,970		8,441,754			8,193,319
Production taxes		1,449,537		1,456,755			1,446,545
Exploration costs		979,718		1,025,542			1,583,773
Depreciation, depletion and amortization		19,061,239		14,712,188			19,222,123
Provision for impairment		826,508		1,728,162			605,615
Loss (gain) on asset sales, interest and other		39,493		(68,325	)		(1,028,148	)
General and administrative		6,388,856		5,994,663			5,594,499
		37,887,321		33,290,739			35,617,726
Income (loss) before provision (benefit) for income taxes		10,644,996		11,685,912			16,320,690
Provision (benefit) for income taxes		3,274,000		3,192,000			4,901,000
Net income (loss)	$	7,370,996	$	8,493,912		$	11,419,690
Basic and diluted earnings per common share:
Net income (loss)	$	0.88	$	1.01		$	1.36

See accompanying notes.

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Panhandle Oil and Gas Inc.

Statements of Stockholders’ Equity

	Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total
Balances at September 30, 2009		8,431,502	$	140,524	$	1,922,053		$	1,862,499		$	64,507,547			(119,866	)	$	(4,310,280	)	$	64,122,343
Purchase of treasury stock		—		—		—			—			—			(12,326	)		(291,383	)		(291,383	)
Issuance of treasury shares to ESOP		—		—		(117,716	)		—			—			11,632			404,910			287,194
Restricted stock awards		—		—		12,028			—			—			—			—			12,028
Common shares to be issued to directors for services		—		—		—			359,628			—			—			—			359,628
Dividends declared ($.28 per share)		—		—		—			—			(2,327,504	)		—			—			(2,327,504	)
Net income		—		—		—			—			11,419,690			—			—			11,419,690
Balances at September 30, 2010		8,431,502	$	140,524	$	1,816,365		$	2,222,127		$	73,599,733			(120,560	)	$	(4,196,753	)	$	73,581,996
Purchase of treasury stock		—		—		—			—			—			(65,481	)		(1,851,290	)		(1,851,290	)
Issuance of treasury shares to ESOP		—		—		(44,340	)		—			—			10,710			348,183			303,843
Restricted stock awards		—		—		152,482			—			—			—			—			152,482
Common shares to be issued to directors for services		—		—		—			443,456			—			—			—			443,456
Dividends declared ($.28 per share)		—		—		—			—			(2,322,082	)		—			—			(2,322,082	)
Net income		—		—		—			—			8,493,912			—			—			8,493,912
Balances at September 30, 2011		8,431,502	$	140,524	$	1,924,507		$	2,665,583		$	79,771,563			(175,331	)	$	(5,699,860	)	$	78,802,317
Purchase of treasury stock		—		—		—			—			—			(38,771	)		(1,158,957	)		(1,158,957	)
Issuance of treasury shares to ESOP		—		—		(14,391	)		—			—			10,660			341,333			326,942
Restricted stock awards		—		—		330,923			—			—			—			—			330,923
Distribution of deferred directors’ compensation		—		—		(220,810	)		(406,770	)		—			22,132			711,322			83,742
Common shares to be issued to directors for services		—		—		—			417,347			—			—			—			417,347
Dividends declared ($.28 per share)		—		—		—			—			(2,321,164	)		—			—			(2,321,164	)
Net income		—		—		—			—			7,370,996			—			—			7,370,996
Balances at September 30, 2012		8,431,502	$	140,524	$	2,020,229		$	2,676,160		$	84,821,395			(181,310	)	$	(5,806,162	)	$	83,852,146

See accompanying notes.

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Panhandle Oil and Gas Inc.

Statements of Cash Flows

	Year ended September 30,
	2012			2011			2010
Operating Activities
Net income (loss)	$	7,370,996		$	8,493,912		$	11,419,690
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		19,061,239			14,712,188			19,222,123
Impairment		826,508			1,728,162			605,615
Provision for deferred income taxes		1,802,257			1,878,000			777,000
Exploration costs		979,718			1,025,542			1,208,653
Gain from leasing of fee mineral acreage		(7,146,299	)		(352,642	)		(1,189,648	)
Net (gain) loss on sales of assets		(122,504	)		2,112			43
Income from partnerships		(487,070	)		(420,465	)		(405,134	)
Distributions received from partnerships		601,300			553,382			523,317
Other		—			—			64,555
Common stock contributed to ESOP		326,942			303,843			287,194
Common stock (unissued) to Directors’ Deferred Compensation Plan		417,347			443,456			359,628
Restricted stock awards		330,923			152,482			12,028
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		461,539			251,598			(1,315,445	)
Fair value of dervative contracts		388,211			1,404,386			(4,133,761	)
Refundable income taxes		28,531			(354,246	)		—
Refundable production taxes		85,926			(124,621	)		(69,874	)
Other current assets		(108,098	)		317,370			(343,961	)
Accounts payable		585,912			72,119			(24,896	)
Other non-current assets		308			—			—
Income taxes payable		—			(922,136	)		583,625
Accrued liabilities		(32,490	)		119,487			225,723
Total adjustments		18,000,200			20,790,017			16,386,785
Net cash provided by operating activities		25,371,196			29,283,929			27,806,475

(Continued on next page)

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Panhandle Oil and Gas Inc.

Statements of Cash Flows (continued)

	Year ended September 30,
	2012			2011			2010
Investing Activities
Capital expenditures, including dry hole costs	$	(25,147,306	)	$	(22,739,908	)	$	(11,308,506	)
Acquistion of working interest properties		(17,399,052	)		(185,125	)		—
Acquistion of minerals and overrides		(2,745,069	)		(4,620,315	)		—
Proceeds from leasing of fee mineral acreage		7,265,808			389,807			1,316,377
Investments in partnerships		(481,904	)		(46,213	)		(254,555	)
Proceeds from sales of assets		134,821			938			401,168
Excess tax benefit on stock-based compensation		83,742			—			—
Net cash used in investing activities		(38,288,960	)		(27,200,816	)		(9,845,516	)
Financing Activities
Borrowings under debt agreement		43,475,443			—			10,799,814
Payments of loan principal		(28,600,458	)		—			(21,184,536	)
Purchases of treasury stock		(1,158,957	)		(1,851,290	)		(291,383	)
Payments of dividends		(2,321,164	)		(2,322,082	)		(2,327,504	)
Net cash provided by (used in) financing activities		11,394,864			(4,173,372	)		(13,003,609	)
Increase (decrease) in cash and cash equivalents		(1,522,900	)		(2,090,259	)		4,957,350
Cash and cash equivalents at beginning of year		3,506,999			5,597,258			639,908
Cash and cash equivalents at end of year	$	1,984,099		$	3,506,999		$	5,597,258
Supplemental Disclosures of Cash Flow Information
Interest paid (net of capitalized interest)	$	127,970		$	—		$	60,912
Income taxes paid, net of refunds received	$	1,356,706		$	2,584,172		$	3,530,718
Supplemental schedule of noncash investing and financing activities:
Additions and revisions, net, to asset retirement obligations	$	279,075		$	113,506		$	110,144
Gross additions to properties and equipment	$	46,201,308		$	27,310,016		$	11,585,521
Net (increase) decrease in accounts payable for properties and equipment additions		(909,881	)		235,332			(277,015	)
Capital expenditures, including dry hole costs	$	45,291,427		$	27,545,348		$	11,308,506

See accompanying notes.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements

September 30, 2012, 2011 and 2010

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 5,666 wells located principally in Oklahoma and Arkansas. Approximately 58% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2012. Approximately 86% of the Company’s total sales volumes in 2012 were derived from the sale of 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.

Basis of Presentation

Certain amounts (lease operating expenses and production taxes in the Statements of Operations; capital expenditures and net (gain) loss on sales of assets in the Statements of Cash Flows) in the prior years have been reclassified to conform to the current year presentation.

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.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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, 2012 and 2011, 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 2012 and 2011, we did not recognize a reserve for bad debt expense.

Derivative contracts entered into by the Company are also unsecured.

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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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, 2012, the remaining carrying cost of non-producing oil and natural gas leases was $694,968.

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, 2012, the Company had no outstanding letters of credit.

Lease Bonus

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 times receives an up-front, non-refundable, cash payment (lease bonus payment) 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 agreement with the exploration company transferring the rights to explore for and produce any oil or natural gas it 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 entered into oil costless collar contracts, natural gas costless collar contracts, natural gas fixed swap contracts and natural gas basis protection swaps. These instruments were 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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 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. 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 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.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Derivative contracts in place as of September 30, 2011

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

Contract period	Production volume covered per month	Indexed (1) Pipeline	Fixed price
Natural gas fixed price swaps
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.65
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.65
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.70
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.75
May - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.50
May - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.60
June - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.63
Natural gas basis protection swaps
January - December 2011	50,000 Mmbtu	CEGT	NYMEX -$.27
January - December 2011	50,000 Mmbtu	CEGT	NYMEX -$.27
January - December 2011	50,000 Mmbtu	PEPL	NYMEX -$.26
January - December 2011	50,000 Mmbtu	PEPL	NYMEX -$.27
January - December 2011	70,000 Mmbtu	PEPL	NYMEX -$.36
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
Oil costless collars
April - December 2011	5,000 Bbls	NYMEX WTI	$100 floor/$112 ceiling

(1) CEGT - Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL - Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Derivative contracts in place as of September 30, 2012

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

Contract period	Production volume covered per month	Indexed  (1) 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

(1) CEGT - Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL - Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

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 a liability of $172,271 as of September 30, 2012, and a net asset of $215,940 as of September 30, 2011. Realized and unrealized gains and (losses) are scheduled below:

(56)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Gains (losses) on natural gas derivative contracts	Fiscal year ended
	9/30/2012			9/30/2011			9/30/2010
Realized	$	462,033		$	2,138,685		$	2,209,900
Increase (decrease) in fair value		(388,211	)		(1,404,386	)		4,133,761
Total	$	73,822		$	734,299		$	6,343,661

To the extent that a legal right of 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 September 30, 2012, and September 30, 2011:

	Balance Sheet Location	9/30/2012 Fair Value		9/30/2011 Fair Value
Asset Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	—	$	269,329
Commodity contracts	Long-term derivative contracts		—		—
Total Asset Derivatives (a)		$	—	$	269,329
Liability Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	172,271	$	—
Commodity contracts	Long-term derivative contracts		—		53,389
Total Liability Derivatives (a)		$	172,271	$	53,389

(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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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. Counterparty quotes are generally assessed as a Level 3 input.

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

	Fair Value Measurement at September 30, 2011
	Quoted Prices  in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	—	$	(77,907	)	$	—	$	(77,907	)
Derivative Contracts - Collars	$	—	$	—		$	293,847	$	293,847

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 and natural gas 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.

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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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.

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

	Derivatives
Balance of Level 3 as of October 1, 2011	$	293,847
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		549,773
Unrealized		(940,557	)
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, 2012	$	(96,937	)

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,
	2012				2011
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	1,301,951	$	826,508	$	1,811,709	$	1,728,162	(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.

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 as the interest rates on the Company’s revolving line of credit are approximately equivalent to market rates for similar type debt based on the Company’s credit worthiness, which represents level 3 of the fair value hierarchy.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 $5,374,868 and $5,215,239 at September 30, 2012 and 2011, 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 86-year life of the Company. There are approximately 198,965 net acres of non-producing minerals in more than 6,931 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $45. 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, 2012, 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 $826,508, $1,728,162 and $605,615, respectively, for 2012, 2011 and 2010. 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 2012, 2011 and 2010, interest of $129,172, $0 and $104,100, respectively, was included in the Company’s capital expenditures. Interest of $127,970, $0 and $60,912, 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.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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, 2012 and 2011, relating to the Company’s asset retirement obligations:

	2012			2011
Asset Retirement Obligations as of beginning of the year	$	1,843,875		$	1,730,369
Accretion of Discount		121,112			109,198
New Wells Placed on Production		184,027			28,624
Wells Sold or Plugged		(26,064	)		(24,316	)
Asset Retirement Obligations as of end of the year	$	2,122,950		$	1,843,875

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.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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, 2012 and 2011, 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, including unissued, vested directors’ shares during the period. The Company’s restricted stock awards are not included in the diluted earnings per share calculation because the effect would be non-dilutive.

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 2007.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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, 2012, 2011 and 2010, the Company recorded interest and penalties of $0, $21,000 and $0, 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 plans to adopt this new standard effective January 1, 2013, and will provide any additional disclosures necessary to comply with the new standard.

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.

2. COMMITMENTS

The Company leases office space in Oklahoma City, Oklahoma, under the terms of an operating lease expiring in April 2015. Future minimum rental payments under the terms of the lease are $204,089 in 2013, $204,089 in 2014 and $119,051 in 2015. Total rent expense incurred by the Company was $204,011 in 2012, $204,089 in 2011 and $203,939 in 2010.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

3. INCOME TAXES

The Company’s provision (benefit) for income taxes is detailed as follows:

	2012		2011			2010
Current:
Federal	$	1,452,000	$	1,266,000		$	3,950,000
State		20,000		48,000			174,000
		1,472,000		1,314,000			4,124,000
Deferred:
Federal		1,126,000		1,982,000			708,000
State		676,000		(104,000	)		69,000
		1,802,000		1,878,000			777,000
	$	3,274,000	$	3,192,000		$	4,901,000

The difference between the provision (benefit) for income taxes and the amount which would result from the application of the federal statutory rate to income before provision (benefit) for income taxes is analyzed below for the years ended September 30:

	2012			2011			2010
Provision (benefit) for income taxes at statutory rate	$	3,725,749		$	4,090,069		$	5,712,242
Percentage depletion		(846,040	)		(733,516	)		(684,053	)
State income taxes, net of federal provision (benefit)		464,677			(92,989	)		325,000
State net operating loss valuation allowance (release)		(31,000	)		31,000			(278,000	)
Other		(39,386	)		(102,564	)		(174,189	)
	$	3,274,000		$	3,192,000		$	4,901,000

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

3. INCOME TAXES (CONTINUED)

Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax basis of assets and liabilities, consist of the following at September 30:

	2012		2011
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$	30,320,765	$	26,939,720
Derivative contracts		—		84,001
		30,320,765		27,023,721
Deferred tax assets:
State net operating loss carry forwards, net of valuation allowance of $0 in 2012 and $31,000 in 2011		1,008,271		1,130,732
AMT credit carry forwards		1,189,053		—
Deferred directors’compensation		990,455		986,340
Statutory depletion carry forwards		415,958		—
Other		130,021		121,899
		3,733,758		2,238,971
Net deferred tax liabilities	$	26,587,007	$	24,784,750

At September 30, 2012, the Company had an income tax benefit of $1,008,271 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring from 2025 to 2031. The valuation allowance of $31,000 that was recorded in fiscal 2011 for the Oklahoma NOL’s was reversed in 2012 as management believes that they will be utilized before they expire. The AMT carry forwards do not have an expiration date.

4. LONG-TERM DEBT

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan with a limit in the amount of $80,000,000 which is subject to a semi-annual borrowing base determination, wherein BOK applies their own pricing forecast and an 8% 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 $41,343,303 at September 30, 2012. 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 balance outstanding under the revolving loan was $14,874,985 and $0 as of September 30, 2012 and 2011, respectively. At September 30, 2012, the effective interest rate was 2.36%.

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.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

4. LONG-TERM DEBT (CONTINUED)

The credit facility 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 September 30, 2012, the Company was in compliance with the covenants of the credit facility.

5. SHAREHOLDERS’ EQUITY

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board approved purchase 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. The Board’s approval included an initial authorization to purchase up to $1.5 million of Common Stock, with a provision for subsequent authorizations without specific action by the Board. As the amount of Common Stock purchased under any authorization reaches $1.5 million, another $1.5 million is automatically authorized for Common Stock purchases unless the Board determines otherwise. Pursuant to these resolutions adopted by the Board, the purchase of additional $1.5 million increments of the Company’s Common Stock became authorized and approved effective March 29, 2011, and March 14, 2012. As of September 30, 2012, $3,301,629 had been spent under the current program to purchase 116,578 shares. The shares are held in treasury and are accounted for using the cost method. On September 30 each year, treasury shares contributed to the Company’s ESOP on behalf of the ESOP participants were 10,660 in 2012, 10,710 in 2011 and 11,632 in 2010.

6. EARNINGS PER SHARE

The following table sets forth the computation of earnings per share.

	Year ended September 30,
	2012		2011		2010
Numerator for basic and diluted earnings per share:
Net income (loss)	$	7,370,996	$	8,493,912	$	11,419,690
Denominator for basic and diluted earnings per share - weighted average shares (including for 2012, 2011 and 2010, unissued, vested directors’ shares of 114,596, 122,728 and 111,491, respectively)		8,360,931		8,393,890		8,422,387

7. EMPLOYEE STOCK OWNERSHIP PLAN

The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan that serves as the Company’s sole retirement plan for all its employees. Company contributions are made at the discretion of the Board and, to date, all contributions have been made in shares of Company Common Stock. The Company contributions are allocated to all ESOP participants in proportion to their compensation for the plan year, and 100% vesting occurs after three years of service. Any shares that do not vest are treated as forfeitures and are distributed amongst other vested employees. For contributions

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

7. EMPLOYEE STOCK OWNERSHIP PLAN (CONTINUED)

of Common Stock, the Company records as expense the fair market value of the stock at the time of contribution. The 267,723 shares of the Company’s Common Stock held by the plan, as of September 30, 2012, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings per share computations and receive dividends.

Contributions to the plan consisted of:

Year	Shares		Amount
2012		10,660	$	326,942
2011		10,710	$	303,843
2010		11,632	$	287,194

8. DEFERRED COMPENSATION PLAN FOR DIRECTORS

The Panhandle Oil and Gas Inc. Deferred Compensation Plan for Non-Employee Directors (the “Plan”) provides that each eligible director can individually elect to receive shares of Company Common Stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These shares are unissued and vest as earned. The shares are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. As of September 30, 2012, there were 121,348 shares (129,776 shares at September 30, 2011) included in the Plan. The deferred balance outstanding at September 30, 2012, under the Plan was $2,676,160 ($2,665,583 at September 30, 2011). Expenses totaling $417,347, $443,456 and $359,628 were charged to the Company’s results of operations for the years ended September 30, 2012, 2011 and 2010, respectively, and are included in general and administrative expense in the accompanying Statement of Operations.

9. 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 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 began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to certain officers. The restricted stock vests at the end of the vesting period (three or five years) and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares was based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.

On December 21, 2010, the Company began awarding shares of the Company’s Common Stock, subject to certain share price performance standards (performance based), as restricted stock to certain officers. Vesting of these shares is based on the performance of the market price of the Common Stock

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

9. RESTRICTED STOCK PLAN (CONTINUED)

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. Upon vesting, shares are expected to be issued out of shares held in treasury.

Compensation expense for the restricted stock awards is recognized in G&A.

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2012, 2011 and 2010, related to the Company’s performance based and non-performance based restricted stock.

	Year Ended September 30,
	2012		2011		2010
Performance based, restricted stock	$	150,480	$	42,909	$	—
Non-performance based, restricted stock		180,443		109,573		12,028
Total compensation expense	$	330,923	$	152,482	$	12,028

A summary of the Company’s unrecognized compensation cost for its unvested performance based and non-performance based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

	As of September 30, 2012
	Unrecognized Compensation		Weighted Average Period
Performance based, restricted stock	$	322,977		1.89
Non-performance based, restricted stock		370,587		2.05
Total	$	693,564

Upon vesting, shares are expected to be issued out of shares held in treasury.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

9. RESTRICTED STOCK PLAN (CONTINUED)

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

	Performance based Unvested Restricted Shares		Weighted Average Grant- Date Fair Value		Non- Performance based  Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
Unvested shares as of September 30, 2010		—	$	—		8,500	$	28.30
Granted		8,782	$	19.54		8,780	$	28.00
Vested		—	$	—		—	$	—
Forfeited		—	$	—		—	$	—
Unvested shares as of September 30, 2011		8,782	$	19.54		17,280	$	28.15
Granted		17,709	$	19.47		5,903	$	31.55
Vested		—	$	—		—	$	—
Forfeited		—	$	—		—	$	—
Unvested shares as of September 30, 2012		26,491	$	19.49		23,183	$	29.01

10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

All oil and natural gas producing activities of the Company are conducted within the United States (principally in Oklahoma and Arkansas) and represent substantially all of the business activities of the Company.

The following table shows sales through various operators/purchasers during 2012, 2011 and 2010.

	2012			2011			2010
Southwestern Energy Company		15	%		9	%		8	%
Chesapeake Operating, Inc.		13	%		15	%		14	%
Devon Energy Corp.		10	%		9	%		6	%
Newfield Exploration		7	%		14	%		15	%
JMA Energy Company		5	%		7	%		11	%

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil and natural gas properties and related accumulated depreciation, depletion and amortization as of September 30 is as follows:

	2012			2011
Producing properties	$	275,997,569		$	230,554,198
Non-producing minerals		9,018,731			8,792,980
Non-producing leasehold		1,123,812			1,102,988
Exploratory wells in progress		8,018			1,204,382
		286,148,130			241,654,548
Accumulated depreciation, depletion and amortization		(164,652,199	)		(145,664,726	)
Net capitalized costs	$	121,495,931		$	95,989,822

Costs Incurred

For the years ended September 30, the Company incurred the following costs in oil and natural gas producing activities:

	2012		2011		2010
Property acquisition costs	$	20,404,465	$	5,140,862	$	742,005
Exploration costs		1,210,417		4,837,451		530,931
Development costs		24,578,943		17,310,808		10,685,088
	$	46,193,825	$	27,289,121	$	11,958,024

In 2012, $17.4 million of the property acquisition costs related to the acquisition of certain assets in the Arkansas Fayetteville Shale which closed on October 25, 2011. Approximately $3.9 million of 2011 property acquisition costs relates to the acquisition of mineral acreage with proved reserves.

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

The following unaudited information regarding the Company’s oil, NGL and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2012, 2011 and 2010 (see Exhibits 23 and 99).

The Company’s net proved oil, NGL and natural gas reserves, all of which are located in the United States, as of September 30, 2012, 2011 and 2010, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Vice President and COO, who reports directly to our President and CEO. Mr. Blanchard, our COO, holds a Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma. Before joining the Company, he was sole proprietor of a consulting petroleum engineering firm, spent 10 years as Vice President of the Mid-Continent business unit of Range Resources Corporation and spent several years as an engineer with Enron Oil and Gas. He is an active member of the Society of Petroleum Engineers (SPE) with over 26 years of oil and gas industry experience, including engineering assignments in several field locations.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

Our COO and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information to our Independent Consulting Petroleum Engineers for all properties such as ownership interest, oil and gas production, well test data, commodity prices, operating costs and handling fees, and development costs. Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data was available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

Net quantities of proved, developed and undeveloped oil, NGL and natural gas reserves are summarized as follows:

	Proved Reserves
	Oil			NGL (1)			Natural Gas
	(Barrels)			(Barrels)			(Mcf)
September 30, 2009		920,873			—			54,027,810
Revisions of previous estimates		47,999			—			15,762,883
Divestitures		(487	)		—			(7,778	)
Extensions, discoveries and other additions		59,003			—			36,689,882
Production		(102,379	)		—			(8,302,342	)
September 30, 2010		925,009			—			98,170,455
Revisions of previous estimates		(59,360	)		791,648			769,676
Acquisitions		—			—			3,189,520
Extensions, discoveries and other additions		82,230			—			8,005,990
Production		(104,141	)		—			(8,297,657	)
September 30, 2011		843,738			791,648			101,837,984
Revisions of previous estimates		8,627			(76,794	)		(27,389,752	)
Acquisitions		—			—			19,075,529
Extensions, discoveries and other additions		373,097			172,602			29,062,593
Production		(153,143	)		(98,714	)		(9,072,298	)
September 30, 2012		1,072,319			788,742			113,514,056

(1) 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure. These NGL are associated with the rapid increase in drilling activity in western Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and the Anadarko Basin Woodford Shale) producing significant volumes of NGL.

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2012 - $89.41/Bbl, $35.70/Bbl, $2.51/Mcf ; September 30, 2011 - $90.28/Bbl, $38.91/Bbl, $3.81/Mcf. The prices used to calculate reserves and future cash flows from reserves for oil and natural gas, respectively, were as follows: September 30, 2010 - $69.23/Bbl, $4.33/Mcf.

The revisions of previous estimates from 2011 to 2012 were primarily the result of:

(1) Positive performance revisions of 3,613,707 Mcfe, of which 1,644,157 Mcfe were proved developed revisions principally attributable to properties in western Oklahoma. The

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

remaining 1,969,550 Mcfe were proved undeveloped revisions principally attributable to higher proved reserves per well in the Company’s shale resource plays including the Fayetteville Shale, Southeastern Oklahoma Woodford Shale and the Anadarko Basin Woodford Shale.

(2) Negative gas pricing revisions of 31,412,464 Mcfe, which included 7,073,763 Mcfe of negative revisions due to proved developed wells reaching their economic limits earlier than previously projected due to current product prices. Negative revisions of 24,338,701 Mcfe were due to certain proved undeveloped locations, primarily in the Fayetteville Shale, Southeastern Oklahoma Woodford Shale and the Anadarko Basin Woodford Shale, becoming uneconomic at current product prices.

Extensions, discoveries and other additions from 2011 to 2012 are principally attributable to:

(1) The Company’s ongoing development of conventional oil, NGL and natural gas plays utilizing horizontal drilling, including the Granite Wash and Cleveland plays in western Oklahoma and the Texas Panhandle, as well as the Marmaton and Tonkawa plays in western Oklahoma.

(2) The Company’s ongoing development of unconventional natural gas plays utilizing horizontal drilling, including the Arkansas Fayetteville Shale and to a much lesser extent, the Southeastern Oklahoma Woodford Shale.

(3) The Company’s ongoing development of unconventional oil, NGL and natural gas plays utilizing horizontal drilling, in the Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale in western and southern Oklahoma.

(4) The Company’s ongoing development of conventional oil plays utilizing vertical drilling, in the Mississippian play in northern Oklahoma, the Spraberry play in West Texas and the Yeso play in southeastern New Mexico.

(5) PUD additions principally in the Fayetteville Shale play in Arkansas and the Anadarko Basin Woodford Shale play in western Oklahoma.

	Proved Developed Reserves						Proved Undeveloped Reserves
	Oil		NGL		Natural Gas		Oil		NGL		Natural Gas
	(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)		(Mcf)
September 30, 2010		861,240		—		57,344,190		63,769		—		40,826,265
September 30, 2011		759,989		386,774		60,193,878		83,749		404,874		41,644,106
September 30, 2012		849,548		494,160		65,733,119		222,771		294,582		47,780,937

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

The following details the changes in proved undeveloped reserves for 2012 (Mcfe):

Beginning proved undeveloped reserves	44,575,844
Proved undeveloped reserves transferred to proved developed	(5,393,421	)
Revisions	(22,369,152	)
Extensions and discoveries	24,458,980
Purchases	9,612,804
Ending proved undeveloped reserves	50,885,055

The beginning PUD reserves were 44.6 Bcfe. A total of 5.4 Bcfe (12% of the beginning balance) were transferred to proved developed producing during 2012. An additional 24.3 Bcfe (55% of the beginning balance) were removed during 2012 as the result of becoming uneconomic at 2012 prices(revisions due to pricing). A total of 29.7 Bcfe (67% of the beginning balance) of PUD reserves were moved out of the category during 2012 as either the result of being transferred to proved developed or removed as uneconomic. Only one PUD location from 2008, representing 1% of total 2012 PUD reserves remains in the PUD category while 45 PUD locations from 2009, representing 11% of total 2012 PUD reserves remain in the PUD category. The 46 PUD locations from 2008 and 2009 represent 8% of the Company’s current total of 589 PUD locations. We anticipate that all the Company’s PUD locations will be drilled and converted to PDP within five years of the date they were added. However, in the event that there are undrilled PUD locations at the end of the five year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions.

Standardized Measure of Discounted Future Net Cash Flows

Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.

Estimated future income taxes are computed using current statutory income tax rates including consideration for the current tax basis of the properties and related carry forwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

	2012			2011			2010
Future cash inflows	$	408,694,869		$	494,523,456		$	489,691,155
Future production costs		(135,516,703	)		(146,168,829	)		(148,727,914	)
Future development costs		(33,167,310	)		(43,425,811	)		(52,975,820	)
Asset retirement obligation		(2,122,950	)		(1,843,875	)		(1,730,369	)
Future income tax expense		(83,543,516	)		(107,111,317	)		(99,118,090	)
Future net cash flows		154,344,390			195,973,624			187,138,962
10% annual discount		(86,930,102	)		(117,591,190	)		(114,638,553	)
Standardized measure of discounted future net cash flows	$	67,414,288		$	78,382,434		$	72,500,409

Changes in the standardized measure of discounted future net cash flow are as follows:

	2012			2011			2010
Beginning of year	$	78,382,434		$	72,500,409		$	53,746,508
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(30,226,927	)		(33,570,621	)		(34,429,083	)
Net change in sales prices and production costs		(45,178,377	)		(2,697,833	)		30,806,970
Net change in future development costs		4,618,147			4,177,910			(26,093,254	)
Net change in asset retirement obligation		(134,604	)		(51,098	)		(48,185	)
Extensions and discoveries		34,216,533			11,938,029			53,274,047
Revisions of quantity estimates		(27,419,576	)		7,046,873			28,946,810
Acquisitions (divestitures) of reserves-in-place		20,160,327			4,480,858			(15,706	)
Accretion of discount		13,644,203			12,523,091			8,066,959
Net change in income taxes		10,735,694			(5,329,092	)		(25,807,417	)
Change in timing and other, net		8,616,434			7,363,908			(15,947,240	)
Net change		(10,968,146	)		5,882,025			18,753,901
End of year	$	67,414,288		$	78,382,434		$	72,500,409

12. ACQUISITIONS

On October 25, 2011, the Company closed an acquisition of certain Fayetteville Shale assets located in Van Buren, Conway and Cleburne Counties, Arkansas, in the core of the Fayetteville Shale. The Company acquired an average working interest of 2.3% in 193 producing non-operated natural gas wells and 1,531 acres of leasehold from a private seller. There were approximately 240 future infill drilling locations identified on the leasehold at the time of purchase. The purchase price was $17.4 million and was funded by utilizing cash on hand and $13.3 million from the Company’s bank credit facility. The purchase price was allocated to the producing wells based on fair value determined by estimated reserves.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

12. ACQUISITIONS (CONTINUED)

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenue attributable to this acquisition included in the Company’s Statement of Operations for the year ended September 30, 2012, was $3,434,850. Net income attributable to the acquisition included in the Statement of Operations for the year ended September 30, 2012, was $200,158.

Presented below is the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2010. The unaudited pro forma financial information is for informational purposes only and does not purport to present what our results would actually have been had this transaction actually occurred on the date presented or to project our results of operations or financial position for any future period. The pro forma financial information was not provided for the comparative period ending September 30, 2010, as the information could not be obtained from the seller.

	For the Year Ended
	September 30
	2012		2011
Revenue:
As reported	$	48,532,317	$	44,976,651
Pro forma revenue		409,988		4,433,282
Pro forma	$	48,942,305	$	49,409,933
Net Income:
As reported	$	7,370,996	$	8,493,912
Pro forma income		136,315		644,859
Pro forma	$	7,507,311	$	9,138,771

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

13. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

The following is a summary of the Company’s unaudited quarterly results of operations.

	Fiscal 2012
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	13,404,333	$	10,436,910	$	13,649,692	$	11,041,382
Income (loss) before provision for income taxes	$	4,261,110	$	1,205,966	$	4,681,299	$	496,621
Net income (loss)	$	3,412,110	$	675,966	$	3,100,299	$	182,621
Earnings (loss) per share	$	0.41	$	0.08	$	0.37	$	0.02
	Fiscal 2011
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	9,901,548	$	10,977,459	$	11,688,417	$	12,409,227
Income (loss) before provision for income taxes	$	2,002,849	$	2,271,253	$	3,691,429	$	3,720,381
Net income (loss)	$	1,426,849	$	1,772,253	$	2,650,429	$	2,644,381
Earnings (loss) per share	$	0.17	$	0.21	$	0.32	$	0.31

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ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

NONE

ITEM 9A CONTROLS AND PROCEDURES

(a)     EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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.

(b)     MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Company’s management is responsible for establishing and maintaining adequate “internal control over financial reporting,” as such term is defined in Exchange Act Rule 13a-15(f). The Company’s management, including the President/CEO and Vice President/CFO, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the Company’s management concluded that its internal control over financial reporting was effective as of September 30, 2012.

(c)     CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

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 ended September 30, 2012, or subsequent to the date the assessment was completed.

ITEM 9B OTHER INFORMATION

None

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PART III

The information called for by Part III of Form 10-K (Item 10 – Directors and Executive Officers of the Registrant, Item 11 – Executive Compensation, Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 13 – Certain Relationships and Related Transactions, and Item 14 – Principal Accountant Fees and Services), is incorporated by reference from the Company’s definitive proxy statement, which will be filed with the SEC within 120 days after the end of the fiscal year to which this report relates.

PART IV

ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

FINANCIAL STATEMENT SCHEDULES

The Company has omitted all schedules because the conditions requiring their filing do not exist or because the required information appears in the Company’s Financial Statements, including the notes to those statements.

EXHIBITS

(3) Amended Certificate of Incorporation (incorporated by reference to Exhibit attached to Form 10 filed January 27, 1980, and to Forms 8-K dated June 1, 1982, December 3, 1982, to Form 10-QSB dated March 31, 1999, and to Form 10-Q dated March 31, 2007)

By-Laws as amended (incorporated by reference to Form 8-K dated October 31, 1994)

By-Laws as amended (incorporated by reference to Form 8-K dated February 24, 2006)

By-Laws as amended (incorporated by reference to Form 8-K dated October 29, 2008)

By-Laws as amended (incorporated by reference to Form 8-K dated August 2, 2011)

(4) Instruments defining the rights of security holders (incorporated by reference to Certificate of Incorporation and By-Laws listed above)

*(10.1) Agreement indemnifying directors and officers (incorporated by reference to Form 10-K dated September 30, 1989, and Form 8-K dated June 15, 2007)

*(10.2) Agreements to provide certain severance payments and benefits to executive officers should a Change-in-Control occur as defined by the agreements (incorporated by reference to Form 8-K dated September 4, 2007)

(23) Consent of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants

(31.1) Certification of Chief Executive Officer

(31.2) Certification of Chief Financial Officer

(32.1) Certification of Chief Executive Officer

(32.2) Certification of Chief Financial Officer

(99) Report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants

(101.INS) XBRL Instance Document

(101.SCH) XBRL Taxonomy Extension Schema Document

(101.CAL) XBRL Taxonomy Extension Calculation Linkbase Document

(101.LAB) XBRL Taxonomy Extension Labels Linkbase Document

(101.PRE) XBRL Taxonomy Extension Presentation Linkbase Document

(101.DEF) XBRL Taxonomy Extension Definition Linkbase Document

* Indicates management contract or compensatory plan or arrangement

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REPORTS ON FORM 8-K

No Form 8-K’s were filed in the fourth quarter of 2012.

SIGNATURES

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

PANHANDLE OIL AND GAS INC.
By:	/s/ Michael C. Coffman	By:	/s/ Lonnie J. Lowry
Michael C. Coffman President; Chief Executive Officer		Lonnie J. Lowry Vice President; Chief Financial Officer
Date: December 11, 2012		Date: December 11, 2012
By:	/s/ Robb P. Winfield
Robb P. Winfield Controller; Chief Accounting Officer
Date: December 11, 2012

In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ Bruce M. Bell	/s/ Duke R. Ligon
Bruce M. Bell, Director	Duke R. Ligon, Director
Date December 11, 2012	Date December 11, 2012
/s/ Robert O. Lorenz	/s/ Robert A. Reece
Robert O. Lorenz, Lead Independent Director	Robert A. Reece, Director
Date December 11, 2012	Date December 11, 2012
/s/ Robert E. Robotti	/s/ Darryl G. Smette
Robert E. Robotti, Director	Darryl G. Smette, Director
Date December 11, 2012	Date December 11, 2012
/s/ H. Grant Swartzwelder
H. Grant Swartzwelder, Director
Date December 11, 2012

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EX-23

EXHIBIT 23

DEGOLYER AND MACNAUGHTON

500 | SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

November 12, 2012

Panhandle Oil and Gas Inc.

Grand Centre, Suite 300

5400 North Grand Blvd

Oklahoma City, OK 73112

Ladies and Gentlemen:

We hereby consent to the use of the name DeGolyer and MacNaughton, to the inclusion of our Letter Report, dated October 1, 2012, as attached as Exhibit 99 to the Annual Report on Form 10-K of Panhandle Oil and Gas Inc., and to the inclusion of information form “Appraisal Report as of September 30, 2012 on Certain Properties owned by Panhandle Oil and Gas Inc.” in the sections “Proved Reserves,” and “Supplementary Information on Oil and Natural Gas Reserves (Unaudited)” in the Annual Report on Form 10-K of Panhandle Oil and Gas Inc.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

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EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Michael C. Coffman, certify that:

1. I have reviewed this annual report on Form 10-K of Panhandle Oil and Gas Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a). designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b). designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c). evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d). disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a). all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b). any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Michael C. Coffman

Michael C. Coffman

Chief Executive Officer

Date: December 11, 2012

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EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Lonnie J. Lowry, certify that:

1. I have reviewed this annual report on Form 10-K of Panhandle Oil and Gas Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a). designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b). designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c). evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d). disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a). all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b). any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Lonnie J. Lowry

Lonnie J. Lowry

Chief Financial Officer

Date: December 11, 2012

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EX-32.1

EXHIBIT 32.1

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK 73112

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Michael C. Coffman, President and Chief Executive Officer of Panhandle Oil and Gas Inc. (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify in connection with the Company’s Annual Report on Form 10-K for the period that ended September 30, 2012, as filed with the Securities and Exchange Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Michael C. Coffman

Michael C. Coffman

President &

Chief Executive Officer

December 11, 2012

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EX-32.2

EXHIBIT 32.2

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK 73112

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Lonnie J. Lowry, Vice President and Chief Financial Officer of Panhandle Oil and Gas Inc. (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify in connection with the Company’s Annual Report on Form 10-K for the period that ended September 30, 2012, as filed with the Securities and Exchange Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Lonnie J. Lowry

Lonnie J. Lowry

Vice President &

Chief Financial Officer

December 11, 2012

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EX-99

EXHIBIT 99

DEGOLYER AND MACNAUGHTON

500 | SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

This is a digital representation of a DeGolyer and MacNaughton report.

Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

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DEGOLYER AND MACNAUGHTON

500 | SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

October 1, 2012

Panhandle Oil and Gas Inc.

5400 North Grand Boulevard

Suite 300

Oklahoma City, Oklahoma 73112

Gentlemen:

Pursuant to your request, we have prepared estimates of the extent and value of the net proved oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of September 30, 2012, of certain properties owned by Panhandle Oil and Gas Inc. (Panhandle). This evaluation was completed October 1, 2012. The properties appraised consist of working and royalty interests located in the states of Arkansas, Kansas, New Mexico, North Dakota, Oklahoma, and Texas. Panhandle has represented that these properties account for 100 percent of Panhandle’s net proved reserves as of September 30, 2012. The net proved reserves estimates included in this report have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Panhandle.

Reserves included herein are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after September 30, 2012. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Panhandle after deducting all royalties and interests owned by others.

Data used in this report were obtained from Panhandle, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Panhandle with respect to property interests appraised, production from such properties, current costs of operation and

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DEGOLYER AND MACNAUGHTON

development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. It was not considered necessary to make a field examination of the physical condition and operation of the properties.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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DEGOLYER AND MACNAUGHTON

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

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DEGOLYER AND MACNAUGHTON

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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DEGOLYER AND MACNAUGHTON

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

The development status shown herein represents the status applicable on September 30, 2012. In the preparation of this study, data available from wells drilled on the appraised properties through September 30, 2012, were used in estimating gross ultimate recovery. When applicable, gross production estimated to September 30, 2012, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves as of September 30, 2012. Production data through June 2012 were available for most properties.

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DEGOLYER AND MACNAUGHTON

Our estimates of Panhandle’s net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC and are as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of September 30, 2012
	Oil and Condensate (Mbbl)		NGL (Mbbl)		Natural Gas (MMcf)
Proved Producing		820		494		64,044
Proved Non-Producing		29		0		1,689
Proved Undeveloped		223		295		47,781
Total Proved		1,072		789		113,514

Primary Economic Assumptions

Revenue values in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth of future net revenue. Future gross revenue is defined as that revenue to be realized from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating, gathering, processing expenses, and capital costs from the future gross revenue. Present worth of future net revenue is calculated by discounting the future net revenue at the arbitrary rate of 10 percent per year compounded monthly over the expected period of realization.

Revenue values in this report were estimated using the initial prices and costs specified by Panhandle. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The prices used in this report are based on SEC guidelines. The assumptions used for estimating future prices and expenses are as follows:

Oil and Condensate Prices

Oil and condensate prices were calculated using specified differentials for each lease to a price of $95.14 per barrel. No escalation was applied to the prices. The price of $95.14 per

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DEGOLYER AND MACNAUGHTON

barrel is the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The weighted average price for the proved reserves over the lives of the properties was $89.41 per barrel.

NGL Prices

NGL prices were calculated using specified differentials for each lease to a price of $95.14 per barrel. No escalation was applied to the prices. The price of $95.14 per barrel is the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The weighted average price for the proved reserves over the lives of the properties was $35.70 per barrel.

Natural Gas Prices

Gas price differentials for each property were provided by Panhandle. The prices were calculated using these differentials to a Henry Hub price of $2.82 per thousand cubic feet (Mcf) and were held constant for the lives of the properties. The Henry Hub gas price of $2.82 per Mcf is the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to September 30, 2012. The weighted average price over the lives of the properties was $2.508 per Mcf of gas.

Operating Expenses and Capital Costs

Estimates of operating expenses and capital costs based on current costs were used for the lives of the properties with no increases in the future based on inflation. In certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating conditions. Future capital expenditures were estimated using 2012 values and were not adjusted for inflation.

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DEGOLYER AND MACNAUGHTON

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of September 30, 2012, of the properties appraised, expressed in thousands of dollars (M$), is summarized as follows:

	Proved
	Developed Producing		Developed Nonproducing		Undeveloped		Total Proved
Future Gross Revenue, M$		255,959		7,501		145,235		408,695
Production & Ad Valorem Taxes, M$		15,988		535		6,640		23,163
Operating Expenses, M$		76,313		2,213		33,828		112,354
Capital Costs, M$		0		1,252		31,915		33,167
Future Net Revenue, M$		163,658		3,501		72,852		240,011
Present Worth at 10 Percent, M$		86,753		1,858		27,151		115,762

Note:   Future income taxes have not been taken into account in the preparation of these estimates.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the September 30, 2012, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

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DEGOLYER AND MACNAUGHTON

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Panhandle. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Panhandle. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

Paul J. Szatkowski, P.E. Paul J. Szatkowski, P.E. Senior Vice President DeGolyer and MacNaughton

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CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Panhandle Oil and Gas Inc. dated October 1, 2012, and that I, as Senior Vice President, was responsible for the preparation of this letter.

2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 38 years of experience in oil and gas reservoir studies and reserves evaluations.

SIGNED: October 1, 2012

Paul J. Szatkowski, P.E. Paul J. Szatkowski, P.E. Senior Vice President DeGolyer and MacNaughton

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XML

Commitments (Details) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Commitments (Textual) [Abstract]
Future minimum rental payments under the terms of the lease	$ 204,089
Future minimum rental payments under the terms of the lease due in 2014	204,089
Future minimum rental payments under the terms of the lease due in 2015	119,051
Rental Expenses	$ 204,011	$ 204,089	$ 203,939

XML

Restricted Stock Plan (Details Textual)	12 Months Ended
	Sep. 30, 2012
Restricted Stock Plan (Textual) [Abstract]
Common Stock Shares	100,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period	3 years
Restricted Stock [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period	5 years
Restricted Stock [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period	3 years

XML

Employee Stock Ownership Plan (Details) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Employee Stock Ownership Plan/Deferred Compensation Plan For Directors [Abstract]
Shares Contributed to the ESOP	10,660	10,710	11,632
Amount Contributed to the ESOP	$ 326,942	$ 303,843	$ 287,194

XML

Information on Oil and Natural Gas Producing Activities (Details)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Southwestern Energy Company [Member]
Summary of sales through various operators/purchasers
Percentage of revenue	15.00%	9.00%	8.00%
Chesapeake Operating Inc [Member]
Summary of sales through various operators/purchasers
Percentage of revenue	13.00%	15.00%	14.00%
Devon Energy Corp [Member]
Summary of sales through various operators/purchasers
Percentage of revenue	10.00%	9.00%	6.00%
Newfield Exploration [Member]
Summary of sales through various operators/purchasers
Percentage of revenue	7.00%	14.00%	15.00%
JMA Energy Company [Member]
Summary of sales through various operators/purchasers
Percentage of revenue	5.00%	7.00%	11.00%

XML

Earnings Per Share (Details) (USD $)	3 Months Ended								12 Months Ended
	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Numerator for basic and diluted earnings per share:
Net income (loss)	$ 182,621	$ 3,100,299	$ 675,966	$ 3,412,110	$ 2,644,381	$ 2,650,429	$ 1,772,253	$ 1,426,849	$ 7,370,996	$ 8,493,912	$ 11,419,690
Denominator for basic and diluted earnings per share
weighted average shares (including for 2012, 2011 and 2010, unissued, vested directors' shares of 114,596, 122,728 and 111,491, respectively)									8,360,931	8,393,890	8,422,387

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Summary of Significant Accounting Policies (Details 2) (Not Designated as Hedging Instrument [Member], USD $)	Sep. 30, 2012	Sep. 30, 2011
Summary of derivative contracts
Asset Derivatives		$ 269,329
Liability Derivatives	172,271	53,389
Commodity contracts [Member] | Short-term derivative contracts [Member]
Summary of derivative contracts
Asset Derivatives		269,329
Liability Derivatives	172,271
Commodity contracts [Member] | Long-term derivative contracts [Member]
Summary of derivative contracts
Asset Derivatives
Liability Derivatives		$ 53,389

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Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Costs Incurred
Property acquisition costs	$ 20,404,465	$ 5,140,862	$ 742,005
Exploration costs	1,210,417	4,837,451	530,931
Development costs	24,578,943	17,310,808	10,685,088
Total cost incurred	$ 46,193,825	$ 27,289,121	$ 11,958,024

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Employee Stock Ownership Plan (Tables)

12 Months Ended

Sep. 30, 2012

Employee Stock Ownership Plan/Deferred Compensation Plan For Directors [Abstract]

Summary of contributions to the plan

Year	Shares		Amount
2012		10,660	$	326,942
2011		10,710	$	303,843
2010		11,632	$	287,194

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Deferred Compensation Plan for Directors (Details Textual) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Deferred Compensation Plan For Directors (Textual) [Abstract]
Number of shares credited to directors deferred fee account	121,348	129,776
Outstanding deferred balance	$ 2,676,160	$ 2,665,583
Total expenses charged to the company's results of operations	$ 417,347	$ 443,456	$ 359,628

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Income Taxes (Details 2) (USD $)	Sep. 30, 2012	Sep. 30, 2011
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$ 30,320,765	$ 26,939,720
Derivative contracts		84,001
Total deferred tax liabilities	30,320,765	27,023,721
Deferred tax assets:
State net operating loss carry forwards, net of valuation allowance of $0 in 2012 and $31,000 in 2011	1,008,271	1,130,732
AMT credit carry forwards	1,189,053
Deferred directors' compensation	990,455	986,340
Statutory depletion carry forwards	415,958
Other	130,021	121,899
Total Deferred tax assets	3,733,758	2,238,971
Net deferred tax liabilities	$ 26,587,007	$ 24,784,750

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Summary of Significant Accounting Policies (Details 6) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Summary of asset retirement obligation
Asset Retirement Obligations as of beginning of the year	$ 1,843,875	$ 1,730,369
Accretion of Discount	121,112	109,198
New Wells Placed on Production	184,027	28,624
Wells Sold or Plugged	(26,064)	(24,316)
Asset Retirement Obligations as of end of the year	$ 2,122,950	$ 1,843,875

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Restricted Stock Plan (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2012
Summary of unrecognized compensation cost
Unrecognized compensation cost	$ 693,564
Performance Based Restricted Stock [Member]
Summary of unrecognized compensation cost
Unrecognized compensation cost	322,977
Weighted Average Period (in years)	1 year 10 months 21 days
Non Performance Based Restricted Stock [Member]
Summary of unrecognized compensation cost
Unrecognized compensation cost	$ 370,587
Weighted Average Period (in years)	2 years 18 days

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Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) (Details 5) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Standardized measure computations since these estimates reflect the valuation process
Future cash inflows	$ 408,694,869	$ 494,523,456	$ 489,691,155
Future production costs	(135,516,703)	(146,168,829)	(148,727,914)
Future development costs	(33,167,310)	(43,425,811)	(52,975,820)
Asset retirement obligation	(2,122,950)	(1,843,875)	(1,730,369)
Future income tax expense	(83,543,516)	(107,111,317)	(99,118,090)
Future net cash flows	154,344,390	195,973,624	187,138,962
10% annual discount	(86,930,102)	(117,591,190)	(114,638,553)
Standardized measure of discounted future net cash flows	$ 67,414,288	$ 78,382,434	$ 72,500,409

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Earnings Per Share (Details Textual)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Earnings Per Share (Textual) [Abstract]
Weighted Average Number Of Shares Unissued And Vested	114,596	122,728	111,491

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Commitments

12 Months Ended

Sep. 30, 2012

Commitments [Abstract]

COMMITMENTS

2. COMMITMENTS

The Company leases office space in Oklahoma City, Oklahoma, under the terms of an operating lease expiring in April 2015. Future minimum rental payments under the terms of the lease are $204,089 in 2013, $204,089 in 2014 and $119,051 in 2015. Total rent expense incurred by the Company was $204,011 in 2012, $204,089 in 2011 and $203,939 in 2010.

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Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) (Details 6) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Changes in the standardized measure of discounted future net cash flow
Beginning Balance	$ 78,382,434	$ 72,500,409	$ 53,746,508
Changes resulting from:
Sales of oil and natural gas, net of production costs	(30,226,927)	(33,570,621)	(34,429,083)
Net change in sales prices and production costs	(45,178,377)	(2,697,833)	30,806,970
Net change in future development costs	4,618,147	4,177,910	(26,093,254)
Net change in asset retirement obligation	(134,604)	(51,098)	(48,185)
Extensions and discoveries	34,216,533	11,938,029	53,274,047
Revisions of quantity estimates	(27,419,576)	7,046,873	28,946,810
Acquisitions (divestitures) of reserves-in-place	20,160,327	4,480,858	(15,706)
Accretion of discount	13,644,203	12,523,091	8,066,959
Net change in income taxes	10,735,694	(5,329,092)	(25,807,417)
Change in timing and other, net	8,616,434	7,363,908	(15,947,240)
Net change	(10,968,146)	5,882,025	18,753,901
Ending Balance	$ 67,414,288	$ 78,382,434	$ 72,500,409

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Income Taxes (Details Textual) (USD $)	Sep. 30, 2012	Sep. 30, 2011
Income Taxes (Textual) [Abstract]
Operating loss carry forwards, net of valuation allowance	$ 0	$ 31,000
OKLAHOMA [Member]
Valuation Allowance [Line Items]
Valuation Allowance		31,000
Income tax benefit related to Oklahoma state income tax net operating loss carryforwards expiring from 2025 to 2031	$ 1,008,271

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Acquisitions (Tables)

12 Months Ended

Sep. 30, 2012

Acquisitions [Abstract]

Summary of pro forma financial information

	For the Year Ended
	September 30
	2012		2011
Revenue:
As reported	$	48,532,317	$	44,976,651
Pro forma revenue		409,988		4,433,282
Pro forma	$	48,942,305	$	49,409,933
Net Income:
As reported	$	7,370,996	$	8,493,912
Pro forma income		136,315		644,859
Pro forma	$	7,507,311	$	9,138,771

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Supplementary Information On Oil, Ngl and Natural Gas Reserves (Unaudited) (Tables)

12 Months Ended

Sep. 30, 2012

Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) [Abstract]

Summary of capitalized costs of oil and natural gas properties and related depreciation, depletion and amortization

	2012			2011
Producing properties	$	275,997,569		$	230,554,198
Non-producing minerals		9,018,731			8,792,980
Non-producing leasehold		1,123,812			1,102,988
Exploratory wells in progress		8,018			1,204,382
		286,148,130			241,654,548
Accumulated depreciation, depletion and amortization		(164,652,199	)		(145,664,726	)
Net capitalized costs	$	121,495,931		$	95,989,822

Summary of costs incurred in oil and natural gas producing activities

	2012		2011		2010
Property acquisition costs	$	20,404,465	$	5,140,862	$	742,005
Exploration costs		1,210,417		4,837,451		530,931
Development costs		24,578,943		17,310,808		10,685,088
	$	46,193,825	$	27,289,121	$	11,958,024

Summary of net quantities of proved, developed and undeveloped oil and natural gas reserves

	Proved Reserves
	Oil			NGL (1)			Natural Gas
	(Barrels)			(Barrels)			(Mcf)
September 30, 2009		920,873			—			54,027,810
Revisions of previous estimates		47,999			—			15,762,883
Divestitures		(487	)		—			(7,778	)
Extensions, discoveries and other additions		59,003			—			36,689,882
Production		(102,379	)		—			(8,302,342	)
September 30, 2010		925,009			—			98,170,455
Revisions of previous estimates		(59,360	)		791,648			769,676
Acquisitions		—			—			3,189,520
Extensions, discoveries and other additions		82,230			—			8,005,990
Production		(104,141	)		—			(8,297,657	)
September 30, 2011		843,738			791,648			101,837,984
Revisions of previous estimates		8,627			(76,794	)		(27,389,752	)
Acquisitions		—			—			19,075,529
Extensions, discoveries and other additions		373,097			172,602			29,062,593
Production		(153,143	)		(98,714	)		(9,072,298	)
September 30, 2012		1,072,319			788,742			113,514,056

Summary of proved developed and undeveloped reserves

	Proved Developed Reserves						Proved Undeveloped Reserves
	Oil		NGL		Natural Gas		Oil		NGL		Natural Gas
	(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)		(Mcf)
September 30, 2010		861,240		—		57,344,190		63,769		—		40,826,265
September 30, 2011		759,989		386,774		60,193,878		83,749		404,874		41,644,106
September 30, 2012		849,548		494,160		65,733,119		222,771		294,582		47,780,937

Summary of proved undeveloped reserves

Beginning proved undeveloped reserves	44,575,844
Proved undeveloped reserves transferred to proved developed	(5,393,421	)
Revisions	(22,369,152	)
Extensions and discoveries	24,458,980
Purchases	9,612,804
Ending proved undeveloped reserves	50,885,055

Summary Of Standardized measure computations since these estimates reflect the valuation process

	2012			2011			2010
Future cash inflows	$	408,694,869		$	494,523,456		$	489,691,155
Future production costs		(135,516,703	)		(146,168,829	)		(148,727,914	)
Future development costs		(33,167,310	)		(43,425,811	)		(52,975,820	)
Asset retirement obligation		(2,122,950	)		(1,843,875	)		(1,730,369	)
Future income tax expense		(83,543,516	)		(107,111,317	)		(99,118,090	)
Future net cash flows		154,344,390			195,973,624			187,138,962
10% annual discount		(86,930,102	)		(117,591,190	)		(114,638,553	)
Standardized measure of discounted future net cash flows	$	67,414,288		$	78,382,434		$	72,500,409

Summary of changes in standardized measure of discounted future net cash flow

	2012			2011			2010
Beginning of year	$	78,382,434		$	72,500,409		$	53,746,508
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(30,226,927	)		(33,570,621	)		(34,429,083	)
Net change in sales prices and production costs		(45,178,377	)		(2,697,833	)		30,806,970
Net change in future development costs		4,618,147			4,177,910			(26,093,254	)
Net change in asset retirement obligation		(134,604	)		(51,098	)		(48,185	)
Extensions and discoveries		34,216,533			11,938,029			53,274,047
Revisions of quantity estimates		(27,419,576	)		7,046,873			28,946,810
Acquisitions (divestitures) of reserves-in-place		20,160,327			4,480,858			(15,706	)
Accretion of discount		13,644,203			12,523,091			8,066,959
Net change in income taxes		10,735,694			(5,329,092	)		(25,807,417	)
Change in timing and other, net		8,616,434			7,363,908			(15,947,240	)
Net change		(10,968,146	)		5,882,025			18,753,901
End of year	$	67,414,288		$	78,382,434		$	72,500,409

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Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) (Details) (USD $)	Sep. 30, 2012	Sep. 30, 2011
Aggregate Capitalized Costs
Producing properties	$ 275,997,569	$ 230,554,198
Non-producing minerals	9,018,731	8,792,980
Non-producing leasehold	1,123,812	1,102,988
Exploratory wells in progress	8,018	1,204,382
Gross capitalized costs	286,148,130	241,654,548
Accumulated depreciation, depletion and amortization	(164,652,199)	(145,664,726)
Net capitalized costs	$ 121,495,931	$ 95,989,822

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Long-term Debt (Details) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Line Of Credit Facility (Textual) [Abstract]
Effective Interest rate	2.36%
Revolving Credit Facility [Member]
Line Of Credit Facility (Textual) [Abstract]
Revolving loan credit facility	$ 80,000,000
Current pricing forecast and a discount rate	8.00%
Borrowing base of credit facility	35,000,000
Secured by carrying value	41,343,303
Credit facility matures	Nov. 30, 2014
Interest rate description	National prime plus from 0.50% to 1.25% or 30 day Libor Plus from 2.00% to 2.75%
Outstanding debt	$ 14,874,985	$ 0
Option Two [Member] | Minimum [Member]
Line Of Credit Facility (Textual) [Abstract]
Interest rate basis	2.00%
Option Two [Member] | Maximum [Member]
Line Of Credit Facility (Textual) [Abstract]
Interest rate basis	2.75%
Option One [Member] | Minimum [Member]
Line Of Credit Facility (Textual) [Abstract]
Interest rate basis	0.50%
Option One [Member] | Maximum [Member]
Line Of Credit Facility (Textual) [Abstract]
Interest rate basis	1.25%

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Quarterly Results of Operations (Unaudited) (Tables)

12 Months Ended

Sep. 30, 2012

Quarterly Results of Operations (Unaudited) [Abstract]

Summary of the Company's unaudited quarterly results of operations

	Fiscal 2012
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	13,404,333	$	10,436,910	$	13,649,692	$	11,041,382
Income (loss) before provision for income taxes	$	4,261,110	$	1,205,966	$	4,681,299	$	496,621
Net income (loss)	$	3,412,110	$	675,966	$	3,100,299	$	182,621
Earnings (loss) per share	$	0.41	$	0.08	$	0.37	$	0.02
	Fiscal 2011
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	9,901,548	$	10,977,459	$	11,688,417	$	12,409,227
Income (loss) before provision for income taxes	$	2,002,849	$	2,271,253	$	3,691,429	$	3,720,381
Net income (loss)	$	1,426,849	$	1,772,253	$	2,650,429	$	2,644,381
Earnings (loss) per share	$	0.17	$	0.21	$	0.32	$	0.31

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Summary of Significant Accounting Policies (Details)	Sep. 30, 2012 MMBTU	Sep. 30, 2011 MMBTU
Natural gas basis protection swaps [Member] | Fixed price One [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Natural gas costless collars [Member] | Fixed price One [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	2.50
Natural gas costless collars [Member] | Fixed price One [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.25
Natural gas costless collars [Member] | Fixed price Two [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	2.50
Natural gas costless collars [Member] | Fixed price Two [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.10
Natural gas costless collars [Member] | Fixed price Three [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	2.50
Natural gas costless collars [Member] | Fixed price Three [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.20
Natural gas costless collars [Member] | Fixed price Four [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	2.50
Natural gas costless collars [Member] | Fixed price Four [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.20
Natural gas costless collars [Member] | Fixed price Five [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	2.50
Natural gas costless collars [Member] | Fixed price Five [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.45
Natural gas costless collars [Member] | Fixed price Six [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	2.50
Natural gas costless collars [Member] | Fixed price Six [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.30
Natural gas costless collars [Member] | Fixed price Seven [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	2.50
Natural gas costless collars [Member] | Fixed price Seven [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.30
Natural gas costless collars [Member] | Fixed price Eight [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	3.00
Natural gas costless collars [Member] | Fixed price Eight [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.70
Natural gas costless collars [Member] | Fixed price Nine [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	3.00
Natural gas costless collars [Member] | Fixed price Nine [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.70
Natural gas costless collars [Member] | Fixed price Ten [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	3.00
Natural gas costless collars [Member] | Fixed price Ten [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	3.65
CEGT [Member] | Natural gas basis protection swaps [Member] | Fixed price One [Member]
Summary of derivative instruments contracts
Fixed price		0.27
CEGT [Member] | Natural gas basis protection swaps [Member] | Fixed price Two [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		0.27
CEGT [Member] | Natural gas basis protection swaps [Member] | Fixed price Three [Member]
Summary of derivative instruments contracts
Production volume covered per month	50,000	50,000
Fixed price	0.29	0.29
CEGT [Member] | Natural gas basis protection swaps [Member] | Fixed price Four [Member]
Summary of derivative instruments contracts
Production volume covered per month	40,000	40,000
Fixed price	0.30	0.30
PEPL [Member] | Natural gas basis protection swaps [Member] | Fixed price One [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		0.26
PEPL [Member] | Natural gas basis protection swaps [Member] | Fixed price Two [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		0.27
PEPL [Member] | Natural gas basis protection swaps [Member] | Fixed price Three [Member]
Summary of derivative instruments contracts
Production volume covered per month		70,000
Fixed price		0.36
PEPL [Member] | Natural gas basis protection swaps [Member] | Fixed price Four [Member]
Summary of derivative instruments contracts
Production volume covered per month	50,000	50,000
Fixed price	0.29	0.29
PEPL [Member] | Natural gas basis protection swaps [Member] | Fixed price Five [Member]
Summary of derivative instruments contracts
Production volume covered per month	50,000	50,000
Fixed price	0.30	0.30
NYMEX Henry Hub [Member] | Natural gas fixed price swaps [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		4.63
NYMEX Henry Hub [Member] | Natural gas fixed price swaps [Member] | Fixed price One [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		4.65
NYMEX Henry Hub [Member] | Natural gas fixed price swaps [Member] | Fixed price Two [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		4.65
NYMEX Henry Hub [Member] | Natural gas fixed price swaps [Member] | Fixed price Three [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		4.70
NYMEX Henry Hub [Member] | Natural gas fixed price swaps [Member] | Fixed price Four [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		4.75
NYMEX Henry Hub [Member] | Natural gas fixed price swaps [Member] | Fixed price Five [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		4.50
NYMEX Henry Hub [Member] | Natural gas fixed price swaps [Member] | Fixed price Six [Member]
Summary of derivative instruments contracts
Production volume covered per month		50,000
Fixed price		4.60
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price One [Member]
Summary of derivative instruments contracts
Production volume covered per month	50,000
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price Two [Member]
Summary of derivative instruments contracts
Production volume covered per month	120,000
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price Three [Member]
Summary of derivative instruments contracts
Production volume covered per month	60,000
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price Four [Member]
Summary of derivative instruments contracts
Production volume covered per month	50,000
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price Five [Member]
Summary of derivative instruments contracts
Production volume covered per month	50,000
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price Six [Member]
Summary of derivative instruments contracts
Production volume covered per month	50,000
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price Seven [Member]
Summary of derivative instruments contracts
Production volume covered per month	50,000
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price Eight [Member]
Summary of derivative instruments contracts
Production volume covered per month	150,000
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price Nine [Member]
Summary of derivative instruments contracts
Production volume covered per month	150,000
NYMEX Henry Hub [Member] | Natural gas costless collars [Member] | Fixed price Ten [Member]
Summary of derivative instruments contracts
Production volume covered per month	50,000
NYMEX WTI [Member] | Oil costless collars [Member]
Summary of derivative instruments contracts
Production volume covered per month	2,000	5,000
NYMEX WTI [Member] | Oil costless collars [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	90	100
NYMEX WTI [Member] | Oil costless collars [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	105	112
NYMEX WTI [Member] | Oil costless collars [Member] | Fixed price One [Member]
Summary of derivative instruments contracts
Production volume covered per month	3,000
NYMEX WTI [Member] | Oil costless collars [Member] | Fixed price One [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	90
NYMEX WTI [Member] | Oil costless collars [Member] | Fixed price One [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	110
NYMEX WTI [Member] | Oil costless collars [Member] | Fixed price Two [Member]
Summary of derivative instruments contracts
Production volume covered per month	2,000
NYMEX WTI [Member] | Oil costless collars [Member] | Fixed price Two [Member] | Floor [Member]
Summary of derivative instruments contracts
Fixed price	90
NYMEX WTI [Member] | Oil costless collars [Member] | Fixed price Two [Member] | Ceiling [Member]
Summary of derivative instruments contracts
Fixed price	114

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Summary of Significant Accounting Policies

12 Months Ended

Sep. 30, 2012

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 5,666 wells located principally in Oklahoma and Arkansas. Approximately 58% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2012. Approximately 86% of the Company’s total sales volumes in 2012 were derived from the sale of 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.

Basis of Presentation

Certain amounts (lease operating expenses and production taxes in the Statements of Operations; capital expenditures and net (gain) loss on sales of assets in the Statements of Cash Flows) in the prior years have been reclassified to conform to the current year presentation.

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, 2012 and 2011, 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 2012 and 2011, we did not recognize a reserve for bad debt expense.

Derivative contracts entered into by the Company are also unsecured.

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, 2012, the remaining carrying cost of non-producing oil and natural gas leases was $694,968.

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, 2012, the Company had no outstanding letters of credit.

Lease Bonus

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 times receives an up-front, non-refundable, cash payment (lease bonus payment) 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 agreement with the exploration company transferring the rights to explore for and produce any oil or natural gas it 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 entered into oil costless collar contracts, natural gas costless collar contracts, natural gas fixed swap contracts and natural gas basis protection swaps. These instruments were 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 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. 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 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 September 30, 2011

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

Contract period	Production volume covered per month	Indexed (1) Pipeline	Fixed price
Natural gas fixed price swaps
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.65
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.65
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.70
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.75
May - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.50
May - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.60
June - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.63
Natural gas basis protection swaps
January - December 2011	50,000 Mmbtu	CEGT	NYMEX -$.27
January - December 2011	50,000 Mmbtu	CEGT	NYMEX -$.27
January - December 2011	50,000 Mmbtu	PEPL	NYMEX -$.26
January - December 2011	50,000 Mmbtu	PEPL	NYMEX -$.27
January - December 2011	70,000 Mmbtu	PEPL	NYMEX -$.36
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
Oil costless collars
April - December 2011	5,000 Bbls	NYMEX WTI	$100 floor/$112 ceiling

(1) CEGT - Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL - Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

Derivative contracts in place as of September 30, 2012

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

Contract period	Production volume covered per month	Indexed  (1) 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

(1) CEGT - Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL - Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

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 a liability of $172,271 as of September 30, 2012, and a net asset of $215,940 as of September 30, 2011. Realized and unrealized gains and (losses) are scheduled below:

Gains (losses) on natural gas derivative contracts	Fiscal year ended
	9/30/2012			9/30/2011			9/30/2010
Realized	$	462,033		$	2,138,685		$	2,209,900
Increase (decrease) in fair value		(388,211	)		(1,404,386	)		4,133,761
Total	$	73,822		$	734,299		$	6,343,661

To the extent that a legal right of 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 September 30, 2012, and September 30, 2011:

	Balance Sheet Location	9/30/2012 Fair Value		9/30/2011 Fair Value
Asset Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	—	$	269,329
Commodity contracts	Long-term derivative contracts		—		—
Total Asset Derivatives (a)		$	—	$	269,329
Liability Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	172,271	$	—
Commodity contracts	Long-term derivative contracts		—		53,389
Total Liability Derivatives (a)		$	172,271	$	53,389

(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. Counterparty quotes are generally assessed as a Level 3 input.

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

	Fair Value Measurement at September 30, 2011
	Quoted Prices  in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	—	$	(77,907	)	$	—	$	(77,907	)
Derivative Contracts - Collars	$	—	$	—		$	293,847	$	293,847

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 and natural gas 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.

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.

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

	Derivatives
Balance of Level 3 as of October 1, 2011	$	293,847
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		549,773
Unrealized		(940,557	)
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, 2012	$	(96,937	)

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,
	2012				2011
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	1,301,951	$	826,508	$	1,811,709	$	1,728,162	(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.

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 as the interest rates on the Company’s revolving line of credit are approximately equivalent to market rates for similar type debt based on the Company’s credit worthiness, which represents level 3 of the fair value hierarchy.

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 $5,374,868 and $5,215,239 at September 30, 2012 and 2011, 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 86-year life of the Company. There are approximately 198,965 net acres of non-producing minerals in more than 6,931 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $45. 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, 2012, 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 $826,508, $1,728,162 and $605,615, respectively, for 2012, 2011 and 2010. 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 2012, 2011 and 2010, interest of $129,172, $0 and $104,100, respectively, was included in the Company’s capital expenditures. Interest of $127,970, $0 and $60,912, 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, 2012 and 2011, relating to the Company’s asset retirement obligations:

	2012			2011
Asset Retirement Obligations as of beginning of the year	$	1,843,875		$	1,730,369
Accretion of Discount		121,112			109,198
New Wells Placed on Production		184,027			28,624
Wells Sold or Plugged		(26,064	)		(24,316	)
Asset Retirement Obligations as of end of the year	$	2,122,950		$	1,843,875

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, 2012 and 2011, 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, including unissued, vested directors’ shares during the period. The Company’s restricted stock awards are not included in the diluted earnings per share calculation because the effect would be non-dilutive.

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 2007.

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, 2012, 2011 and 2010, the Company recorded interest and penalties of $0, $21,000 and $0, 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 plans to adopt this new standard effective January 1, 2013, and will provide any additional disclosures necessary to comply with the new standard.

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.

XML

Summary of Significant Accounting Policies (Details 1) (Gains (losses) on derivative contracts [Member], USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Gains (losses) on derivative contracts [Member]
Summary of realized and unrealized gains and (losses)
Realized	$ 462,033	$ 2,138,685	$ 2,209,900
Increase (decrease) in fair value	(388,211)	(1,404,386)	4,133,761
Total	$ 73,822	$ 734,299	$ 6,343,661

XML

Income Taxes (Details) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Current:
Federal	$ 1,452,000	$ 1,266,000	$ 3,950,000
State	20,000	48,000	174,000
Current Total	1,472,000	1,314,000	4,124,000
Deferred:
Federal	1,126,000	1,982,000	708,000
State	676,000	(104,000)	69,000
Deferred Total	1,802,257	1,878,000	777,000
provision (benefit) for income taxes	$ 3,274,000	$ 3,192,000	$ 4,901,000

XML

Restricted Stock Plan (Details 2) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Performance Based Restricted Stock [Member]
summary of the status of unvested shares of restricted stock awards and changes
Unvested shares, Beginning balance	8,782
Weighted Average Grant Date Fair Value, Beginning balance	$ 19.54
Unvested Restricted Shares, Granted	17,709	8,782
Weighted Average Grant Date Fair Value, Granted	$ 19.47	$ 19.54
Unvested Restricted Shares, Vested
Weighted Average Grant Date Fair Value, Vested
Unvested Restricted Shares, Forfeited
Weighted Average Grant Date Fair Value, Forfeited
Unvested shares, Ending balance	26,491	8,782
Weighted Average Grant Date Fair Value, Ending balance	$ 19.49	$ 19.54
Non Performance Based Restricted Stock [Member]
summary of the status of unvested shares of restricted stock awards and changes
Unvested shares, Beginning balance	17,280	8,500
Weighted Average Grant Date Fair Value, Beginning balance	$ 28.15	$ 28.30
Unvested Restricted Shares, Granted	5,903	8,780
Weighted Average Grant Date Fair Value, Granted	$ 31.55	$ 28.00
Unvested Restricted Shares, Vested
Weighted Average Grant Date Fair Value, Vested
Unvested Restricted Shares, Forfeited
Weighted Average Grant Date Fair Value, Forfeited
Unvested shares, Ending balance	23,183	17,280
Weighted Average Grant Date Fair Value, Ending balance	$ 29.01	$ 28.15

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Balance Sheets (USD $)	Sep. 30, 2012	Sep. 30, 2011
Current Assets:
Cash and cash equivalents	$ 1,984,099	$ 3,506,999
Oil, NGL and natural gas sales receivables	8,349,865	8,811,404
Refundable income taxes	325,715	354,246
Refundable production taxes	585,454	223,672
Deferred income taxes	121,900
Derivative contracts		269,329
Other	255,812	95,408
Total current assets	11,622,845	13,261,058
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties	275,997,569	230,554,198
Non-producing oil and natural gas properties	10,150,561	11,100,350
Furniture and fixtures	668,004	628,929
Total properties and equipment, at cost, based on successful efforts accounting	286,816,134	242,283,477
Less accumulated depreciation, depletion and amortization	165,199,079	146,147,514
Net properties and equipment	121,617,055	96,135,963
Investments	1,034,870	667,504
Refundable production taxes	911,960	1,359,668
Total assets	135,186,730	111,424,193
Current Liabilities:
Accounts payable	6,447,692	4,899,593
Derivative contracts	172,271
Deferred income taxes		7,100
Accrued liabilities and other	1,007,779	1,040,269
Total current liabilities	7,627,742	5,946,962
Long term debt	14,874,985
Deferred income taxes	26,708,907	24,777,650
Asset retirement obligations	2,122,950	1,843,875
Derivative contracts		53,389
Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at September 30, 2012 and 2011	140,524	140,524
Capital in excess of par value	2,020,229	1,924,507
Deferred directors' compensation	2,676,160	2,665,583
Retained earnings	84,821,395	79,771,563
Total stockholders' equity	89,658,308	84,502,177
Treasury stock, at cost; 181,310 shares at September 30, 2012, and 175,331 shares at September 30, 2011	(5,806,162)	(5,699,860)
Total stockholders' equity	83,852,146	78,802,317
Total liabilities and stockholders' equity	$ 135,186,730	$ 111,424,193

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Shareholders' Equity (Details) (USD $)	0 Months Ended	1 Months Ended		12 Months Ended
	Mar. 11, 2011	Mar. 31, 2012	Mar. 31, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Shareholders Equity (Textual) [Abstract]
Purchase of treasury stock				$ 1,158,957	1,851,290	291,383
Restricted Stock Option Plan [Member]
Shareholders Equity (Textual) [Abstract]
Purchase of Common Stock	1,500,000
Purchase of Common Stock Authorized		1,500,000	1,500,000
Purchase of treasury stock				$ 3,301,629
Purchase of treasury stock, shares				116,578
Number Of Treasury Stock contributed to the Companies ESOP				10,660	10,710	11,632

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Statements of Stockholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Dividends per share	$ 0.28	$ 0.28	$ 0.28
Retained Earnings
Dividends per share	$ 0.28	$ 0.28	$ 0.28

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Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) (Details 3)	Sep. 30, 2012 bbl	Sep. 30, 2011 bbl	Sep. 30, 2010 bbl
Reserve Quantities [Line Items]
Proved Undeveloped Reserves	50,885,055	44,575,844
Oil (Barrels) [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	849,548	759,989	861,240
Proved Undeveloped Reserves (Volume)	222,771	83,749	63,769
Natural Gas (Mcf) [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	65,733,119	60,193,878	57,344,190
Proved Undeveloped Reserves (Volume)	47,780,937	41,644,106	40,826,265
NGL (Barrels) [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	494,160	386,774
Proved Undeveloped Reserves (Volume)	294,582	404,874

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Summary of Significant Accounting Policies (Details 4) (USD $)	12 Months Ended
	Sep. 30, 2012
Summary of reconciliation of assets classified as Level 3 measurements
Balance of Level 3 as of October 1, 2011	$ 293,847
Total gains or (losses) - realized and unrealized: Included in earnings
Realized	549,773
Unrealized	(940,557)
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, 2012	$ (96,937)

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Acquisitions (Details Textual) (USD $)	12 Months Ended
	Sep. 30, 2012 acre	Oct. 25, 2011 acre Well
Acquisitions (Textual) [Abstract]
Acquired average working interest		2.30%
Producing non-operated natural gas wells		193
Leasehold from a private seller		1,531
Number of future infill drilling	240
Purchase price business acquisition		$ 17,400,000
Credit facility by bank		13,300,000
Revenues attributable	3,434,850
Net income attributable	$ 200,158
Date of business acquisition	Oct. 25, 2011

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Sep. 30, 2012

Summary of Significant Accounting Policies [Abstract]

Summary of derivative instruments contracts

Contract period	Production volume covered per month	Indexed (1) Pipeline	Fixed price
Natural gas fixed price swaps
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.65
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.65
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.70
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.75
May - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.50
May - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.60
June - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.63
Natural gas basis protection swaps
January - December 2011	50,000 Mmbtu	CEGT	NYMEX -$.27
January - December 2011	50,000 Mmbtu	CEGT	NYMEX -$.27
January - December 2011	50,000 Mmbtu	PEPL	NYMEX -$.26
January - December 2011	50,000 Mmbtu	PEPL	NYMEX -$.27
January - December 2011	70,000 Mmbtu	PEPL	NYMEX -$.36
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
Oil costless collars
April - December 2011	5,000 Bbls	NYMEX WTI	$100 floor/$112 ceiling

(1) CEGT - Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL - Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

Derivative contracts in place as of September 30, 2012

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

Contract period	Production volume covered per month	Indexed  (1) 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

Summary of realized and unrealized gains and (losses)

Gains (losses) on natural gas derivative contracts	Fiscal year ended
	9/30/2012			9/30/2011			9/30/2010
Realized	$	462,033		$	2,138,685		$	2,209,900
Increase (decrease) in fair value		(388,211	)		(1,404,386	)		4,133,761
Total	$	73,822		$	734,299		$	6,343,661

Summary of derivative contracts

	Balance Sheet Location	9/30/2012 Fair Value		9/30/2011 Fair Value
Asset Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	—	$	269,329
Commodity contracts	Long-term derivative contracts		—		—
Total Asset Derivatives (a)		$	—	$	269,329
Liability Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	172,271	$	—
Commodity contracts	Long-term derivative contracts		—		53,389
Total Liability Derivatives (a)		$	172,271	$	53,389

Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis

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

	Fair Value Measurement at September 30, 2011
	Quoted Prices  in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	—	$	(77,907	)	$	—	$	(77,907	)
Derivative Contracts - Collars	$	—	$	—		$	293,847	$	293,847

Summary of reconciliation of assets classified as Level 3 measurements

	Derivatives
Balance of Level 3 as of October 1, 2011	$	293,847
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		549,773
Unrealized		(940,557	)
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, 2012	$	(96,937	)

Summary of impairments associated with certain assets measured at fair value on a nonrecurring basis within Level 3

	Year Ended September 30,
	2012				2011
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	1,301,951	$	826,508	$	1,811,709	$	1,728,162	(a)

Summary of asset retirement obligation

	2012			2011
Asset Retirement Obligations as of beginning of the year	$	1,843,875		$	1,730,369
Accretion of Discount		121,112			109,198
New Wells Placed on Production		184,027			28,624
Wells Sold or Plugged		(26,064	)		(24,316	)
Asset Retirement Obligations as of end of the year	$	2,122,950		$	1,843,875

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Summary of Significant Accounting Policies (Details 5) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Summary of impairments associated with certain assets measured at fair value on a nonrecurring basis within Level 3
Producing Properties, Fair Value	$ 1,301,951	$ 1,811,709
Producing Properties, Impairment	$ 826,508	$ 1,728,162	$ 605,615

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Earnings Per Share (Tables)

12 Months Ended

Sep. 30, 2012

Earnings Per Share [Abstract]

Summary of computation of earnings per share

	Year ended September 30,
	2012		2011		2010
Numerator for basic and diluted earnings per share:
Net income (loss)	$	7,370,996	$	8,493,912	$	11,419,690
Denominator for basic and diluted earnings per share - weighted average shares (including for 2012, 2011 and 2010, unissued, vested directors’ shares of 114,596, 122,728 and 111,491, respectively)		8,360,931		8,393,890		8,422,387

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Statements of Cash Flows (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Operating Activities
Net income (loss)	$ 7,370,996	$ 8,493,912	$ 11,419,690
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	19,061,239	14,712,188	19,222,123
Impairment	826,508	1,728,162	605,615
Provision for deferred income taxes	1,802,257	1,878,000	777,000
Exploration costs	979,718	1,025,542	1,208,653
Gain from leasing of fee mineral acreage	(7,146,299)	(352,642)	(1,189,648)
Net (gain) loss on sales of assets	(122,504)	2,112	43
Income from partnerships	(487,070)	(420,465)	(405,134)
Distributions received from partnerships	601,300	553,382	523,317
Other			64,555
Common stock contributed to ESOP	326,942	303,843	287,194
Common stock (unissued) to Directors' Deferred Compensation Plan	417,347	443,456	359,628
Restricted stock awards	330,923	152,482	12,028
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	461,539	251,598	(1,315,445)
Fair value of derivative contracts	388,211	1,404,386	(4,133,761)
Refundable income taxes	28,531	(354,246)
Refundable production taxes	85,926	(124,621)	(69,874)
Other current assets	(108,098)	317,370	(343,961)
Accounts payable	585,912	72,119	(24,896)
Other non-current asset	308
Income taxes payable		(922,136)	583,625
Accrued liabilities	(32,490)	119,487	225,723
Total adjustments	18,000,200	20,790,017	16,386,785
Net cash provided by operating activities	25,371,196	29,283,929	27,806,475
Investing Activities
Capital expenditures, including dry hole costs	(25,147,306)	(22,739,908)	(11,308,506)
Acquisition of working interest properties	(17,399,052)	(185,125)
Acquisition of minerals and overrides	(2,745,069)	(4,620,315)
Proceeds from leasing of fee mineral acreage	7,265,808	389,807	1,316,377
Investments in partnerships	(481,904)	(46,213)	(254,555)
Proceeds from sales of assets	134,821	938	401,168
Excess tax benefit on stock-based compensation	83,742
Net cash used in investing activities	(38,288,960)	(27,200,816)	(9,845,516)
Financing Activities
Borrowings under debt agreement	43,475,443		10,799,814
Payments of loan principal	(28,600,458)		(21,184,536)
Purchases of treasury stock	(1,158,957)	(1,851,290)	(291,383)
Payments of dividends	(2,321,164)	(2,322,082)	(2,327,504)
Net cash provided by (used in) financing activities	11,394,864	(4,173,372)	(13,003,609)
Increase (decrease) in cash and cash equivalents	(1,522,900)	(2,090,259)	4,957,350
Cash and cash equivalents at beginning of year	3,506,999	5,597,258	639,908
Cash and cash equivalents at end of year	1,984,099	3,506,999	5,597,258
Supplemental Disclosures of Cash Flow Information
Interest paid (net of capitalized interest)	127,970		60,912
Income taxes paid, net of refunds received	1,356,706	2,584,172	3,530,718
Supplemental schedule of noncash investing and financing activities:
Additions and revisions, net, to asset retirement obligations	279,075	113,506	110,144
Gross additions to properties and equipment	46,201,308	27,310,016	11,585,521
Net (increase) decrease in accounts payable for properties and equipment additions	(909,881)	235,332	(277,015)
Capital expenditures, including dry hole costs	$ 45,291,427	$ 27,545,348	$ 11,308,506

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Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2012	Sep. 30, 2011
Balance Sheets [Abstract]
Common stock, par value	$ 0.0166	$ 0.0166
Common stock, shares authorized	24,000,000	24,000,000
Common stock, shares issued	8,431,502	8,431,502
Treasury stock, shares	181,310	175,331

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Information on Oil and Natural Gas Producing Activities

12 Months Ended

Sep. 30, 2012

Information on Oil and Natural Gas Producing Activities [Abstract]

INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

All oil and natural gas producing activities of the Company are conducted within the United States (principally in Oklahoma and Arkansas) and represent substantially all of the business activities of the Company.

The following table shows sales through various operators/purchasers during 2012, 2011 and 2010.

	2012			2011			2010
Southwestern Energy Company		15	%		9	%		8	%
Chesapeake Operating, Inc.		13	%		15	%		14	%
Devon Energy Corp.		10	%		9	%		6	%
Newfield Exploration		7	%		14	%		15	%
JMA Energy Company		5	%		7	%		11	%

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Document and Entity Information (USD $)	12 Months Ended
	Sep. 30, 2012	Dec. 01, 2012	Mar. 31, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	PANHANDLE OIL & GAS INC
Entity Central Index Key	0000315131
Document Type	10-K
Document Period End Date	Sep. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 206,798,928
Entity Common Stock, Shares Outstanding		8,250,192

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Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited)

12 Months Ended

Sep. 30, 2012

Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) [Abstract]

SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil and natural gas properties and related accumulated depreciation, depletion and amortization as of September 30 is as follows:

	2012			2011
Producing properties	$	275,997,569		$	230,554,198
Non-producing minerals		9,018,731			8,792,980
Non-producing leasehold		1,123,812			1,102,988
Exploratory wells in progress		8,018			1,204,382
		286,148,130			241,654,548
Accumulated depreciation, depletion and amortization		(164,652,199	)		(145,664,726	)
Net capitalized costs	$	121,495,931		$	95,989,822

Costs Incurred

For the years ended September 30, the Company incurred the following costs in oil and natural gas producing activities:

	2012		2011		2010
Property acquisition costs	$	20,404,465	$	5,140,862	$	742,005
Exploration costs		1,210,417		4,837,451		530,931
Development costs		24,578,943		17,310,808		10,685,088
	$	46,193,825	$	27,289,121	$	11,958,024

In 2012, $17.4 million of the property acquisition costs related to the acquisition of certain assets in the Arkansas Fayetteville Shale which closed on October 25, 2011. Approximately $3.9 million of 2011 property acquisition costs relates to the acquisition of mineral acreage with proved reserves.

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

The following unaudited information regarding the Company’s oil, NGL and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be

the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2012, 2011 and 2010 (see Exhibits 23 and 99).

The Company’s net proved oil, NGL and natural gas reserves, all of which are located in the United States, as of September 30, 2012, 2011 and 2010, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Vice President and COO, who reports directly to our President and CEO. Mr. Blanchard, our COO, holds a Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma. Before joining the Company, he was sole proprietor of a consulting petroleum engineering firm, spent 10 years as Vice President of the Mid-Continent business unit of Range Resources Corporation and spent several years as an engineer with Enron Oil and Gas. He is an active member of the Society of Petroleum Engineers (SPE) with over 26 years of oil and gas industry experience, including engineering assignments in several field locations.

Our COO and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information to our Independent Consulting Petroleum Engineers for all properties such as ownership interest, oil and gas production, well test data, commodity prices, operating costs and handling fees, and development costs. Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data was available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available.

Net quantities of proved, developed and undeveloped oil, NGL and natural gas reserves are summarized as follows:

	Proved Reserves
	Oil			NGL (1)			Natural Gas
	(Barrels)			(Barrels)			(Mcf)
September 30, 2009		920,873			—			54,027,810
Revisions of previous estimates		47,999			—			15,762,883
Divestitures		(487	)		—			(7,778	)
Extensions, discoveries and other additions		59,003			—			36,689,882
Production		(102,379	)		—			(8,302,342	)
September 30, 2010		925,009			—			98,170,455
Revisions of previous estimates		(59,360	)		791,648			769,676
Acquisitions		—			—			3,189,520
Extensions, discoveries and other additions		82,230			—			8,005,990
Production		(104,141	)		—			(8,297,657	)
September 30, 2011		843,738			791,648			101,837,984
Revisions of previous estimates		8,627			(76,794	)		(27,389,752	)
Acquisitions		—			—			19,075,529
Extensions, discoveries and other additions		373,097			172,602			29,062,593
Production		(153,143	)		(98,714	)		(9,072,298	)
September 30, 2012		1,072,319			788,742			113,514,056

(1) 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure. These NGL are associated with the rapid increase in drilling activity in western Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and the Anadarko Basin Woodford Shale) producing significant volumes of NGL.

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2012 - $89.41/Bbl, $35.70/Bbl, $2.51/Mcf ; September 30, 2011 - $90.28/Bbl, $38.91/Bbl, $3.81/Mcf. The prices used to calculate reserves and future cash flows from reserves for oil and natural gas, respectively, were as follows: September 30, 2010 - $69.23/Bbl, $4.33/Mcf.

The revisions of previous estimates from 2011 to 2012 were primarily the result of:

(1) Positive performance revisions of 3,613,707 Mcfe, of which 1,644,157 Mcfe were proved developed revisions principally attributable to properties in western Oklahoma. The

remaining 1,969,550 Mcfe were proved undeveloped revisions principally attributable to higher proved reserves per well in the Company’s shale resource plays including the Fayetteville Shale, Southeastern Oklahoma Woodford Shale and the Anadarko Basin Woodford Shale.

(2) Negative gas pricing revisions of 31,412,464 Mcfe, which included 7,073,763 Mcfe of negative revisions due to proved developed wells reaching their economic limits earlier than previously projected due to current product prices. Negative revisions of 24,338,701 Mcfe were due to certain proved undeveloped locations, primarily in the Fayetteville Shale, Southeastern Oklahoma Woodford Shale and the Anadarko Basin Woodford Shale, becoming uneconomic at current product prices.

Extensions, discoveries and other additions from 2011 to 2012 are principally attributable to:

(1) The Company’s ongoing development of conventional oil, NGL and natural gas plays utilizing horizontal drilling, including the Granite Wash and Cleveland plays in western Oklahoma and the Texas Panhandle, as well as the Marmaton and Tonkawa plays in western Oklahoma.

(2) The Company’s ongoing development of unconventional natural gas plays utilizing horizontal drilling, including the Arkansas Fayetteville Shale and to a much lesser extent, the Southeastern Oklahoma Woodford Shale.

(3) The Company’s ongoing development of unconventional oil, NGL and natural gas plays utilizing horizontal drilling, in the Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale in western and southern Oklahoma.

(4) The Company’s ongoing development of conventional oil plays utilizing vertical drilling, in the Mississippian play in northern Oklahoma, the Spraberry play in West Texas and the Yeso play in southeastern New Mexico.

(5) PUD additions principally in the Fayetteville Shale play in Arkansas and the Anadarko Basin Woodford Shale play in western Oklahoma.

	Proved Developed Reserves						Proved Undeveloped Reserves
	Oil		NGL		Natural Gas		Oil		NGL		Natural Gas
	(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)		(Mcf)
September 30, 2010		861,240		—		57,344,190		63,769		—		40,826,265
September 30, 2011		759,989		386,774		60,193,878		83,749		404,874		41,644,106
September 30, 2012		849,548		494,160		65,733,119		222,771		294,582		47,780,937

The following details the changes in proved undeveloped reserves for 2012 (Mcfe):

Beginning proved undeveloped reserves	44,575,844
Proved undeveloped reserves transferred to proved developed	(5,393,421	)
Revisions	(22,369,152	)
Extensions and discoveries	24,458,980
Purchases	9,612,804
Ending proved undeveloped reserves	50,885,055

The beginning PUD reserves were 44.6 Bcfe. A total of 5.4 Bcfe (12% of the beginning balance) were transferred to proved developed producing during 2012. An additional 24.3 Bcfe (55% of the beginning balance) were removed during 2012 as the result of becoming uneconomic at 2012 prices(revisions due to pricing). A total of 29.7 Bcfe (67% of the beginning balance) of PUD reserves were moved out of the category during 2012 as either the result of being transferred to proved developed or removed as uneconomic. Only one PUD location from 2008, representing 1% of total 2012 PUD reserves remains in the PUD category while 45 PUD locations from 2009, representing 11% of total 2012 PUD reserves remain in the PUD category. The 46 PUD locations from 2008 and 2009 represent 8% of the Company’s current total of 589 PUD locations. We anticipate that all the Company’s PUD locations will be drilled and converted to PDP within five years of the date they were added. However, in the event that there are undrilled PUD locations at the end of the five year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions.

Standardized Measure of Discounted Future Net Cash Flows

Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.

Estimated future income taxes are computed using current statutory income tax rates including consideration for the current tax basis of the properties and related carry forwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

	2012			2011			2010
Future cash inflows	$	408,694,869		$	494,523,456		$	489,691,155
Future production costs		(135,516,703	)		(146,168,829	)		(148,727,914	)
Future development costs		(33,167,310	)		(43,425,811	)		(52,975,820	)
Asset retirement obligation		(2,122,950	)		(1,843,875	)		(1,730,369	)
Future income tax expense		(83,543,516	)		(107,111,317	)		(99,118,090	)
Future net cash flows		154,344,390			195,973,624			187,138,962
10% annual discount		(86,930,102	)		(117,591,190	)		(114,638,553	)
Standardized measure of discounted future net cash flows	$	67,414,288		$	78,382,434		$	72,500,409

Changes in the standardized measure of discounted future net cash flow are as follows:

	2012			2011			2010
Beginning of year	$	78,382,434		$	72,500,409		$	53,746,508
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(30,226,927	)		(33,570,621	)		(34,429,083	)
Net change in sales prices and production costs		(45,178,377	)		(2,697,833	)		30,806,970
Net change in future development costs		4,618,147			4,177,910			(26,093,254	)
Net change in asset retirement obligation		(134,604	)		(51,098	)		(48,185	)
Extensions and discoveries		34,216,533			11,938,029			53,274,047
Revisions of quantity estimates		(27,419,576	)		7,046,873			28,946,810
Acquisitions (divestitures) of reserves-in-place		20,160,327			4,480,858			(15,706	)
Accretion of discount		13,644,203			12,523,091			8,066,959
Net change in income taxes		10,735,694			(5,329,092	)		(25,807,417	)
Change in timing and other, net		8,616,434			7,363,908			(15,947,240	)
Net change		(10,968,146	)		5,882,025			18,753,901
End of year	$	67,414,288		$	78,382,434		$	72,500,409

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Statements of Operations (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Revenues:
Oil, NGL and natural gas sales	$ 40,818,434	$ 43,469,130	$ 44,068,947
Lease bonuses and rentals	7,152,991	352,757	1,120,674
Gains (losses) on derivative contracts	73,822	734,299	6,343,661
Income from partnerships	487,070	420,465	405,134
Total revenues	48,532,317	44,976,651	51,938,416
Costs and expenses:
Lease operating expenses	9,141,970	8,441,754	8,193,319
Production taxes	1,449,537	1,456,755	1,446,545
Exploration costs	979,718	1,025,542	1,583,773
Depreciation, depletion and amortization	19,061,239	14,712,188	19,222,123
Provision for impairment	826,508	1,728,162	605,615
Loss (gain) on asset sales, interest and other	39,493	(68,325)	(1,028,148)
General and administrative	6,388,856	5,994,663	5,594,499
Total costs and expenses	37,887,321	33,290,739	35,617,726
Income (loss) before provision (benefit) for income taxes	10,644,996	11,685,912	16,320,690
Provision (benefit) for income taxes	3,274,000	3,192,000	4,901,000
Net income (loss)	$ 7,370,996	$ 8,493,912	$ 11,419,690
Basic and diluted earnings per common share:
Net income (loss)	$ 0.88	$ 1.01	$ 1.36

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Shareholders' Equity

12 Months Ended

Sep. 30, 2012

Shareholders' Equity [Abstract]

SHAREHOLDERS' EQUITY

5. SHAREHOLDERS’ EQUITY

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board approved purchase 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. The Board’s approval included an initial authorization to purchase up to $1.5 million of Common Stock, with a provision for subsequent authorizations without specific action by the Board. As the amount of Common Stock purchased under any authorization reaches $1.5 million, another $1.5 million is automatically authorized for Common Stock purchases unless the Board determines otherwise. Pursuant to these resolutions adopted by the Board, the purchase of additional $1.5 million increments of the Company’s Common Stock became authorized and approved effective March 29, 2011, and March 14, 2012. As of September 30, 2012, $3,301,629 had been spent under the current program to purchase 116,578 shares. The shares are held in treasury and are accounted for using the cost method. On September 30 each year, treasury shares contributed to the Company’s ESOP on behalf of the ESOP participants were 10,660 in 2012, 10,710 in 2011 and 11,632 in 2010.

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Long-term Debt

12 Months Ended

Sep. 30, 2012

Long-term Debt [Abstract]

LONG-TERM DEBT

4. LONG-TERM DEBT

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan with a limit in the amount of $80,000,000 which is subject to a semi-annual borrowing base determination, wherein BOK applies their own pricing forecast and an 8% 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 $41,343,303 at September 30, 2012. 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 balance outstanding under the revolving loan was $14,874,985 and $0 as of September 30, 2012 and 2011, respectively. At September 30, 2012, the effective interest rate was 2.36%.

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 credit facility 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 September 30, 2012, the Company was in compliance with the covenants of the credit facility.

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Income Taxes (Tables)

12 Months Ended

Sep. 30, 2012

Income Taxes [Abstract]

Summary of provision for income taxes

	2012		2011			2010
Current:
Federal	$	1,452,000	$	1,266,000		$	3,950,000
State		20,000		48,000			174,000
		1,472,000		1,314,000			4,124,000
Deferred:
Federal		1,126,000		1,982,000			708,000
State		676,000		(104,000	)		69,000
		1,802,000		1,878,000			777,000
	$	3,274,000	$	3,192,000		$	4,901,000

Summary of difference between the provision (benefit) for income taxes and the amount from the application of the federal statutory rate to income before provision (benefit) for income taxes

	2012			2011			2010
Provision (benefit) for income taxes at statutory rate	$	3,725,749		$	4,090,069		$	5,712,242
Percentage depletion		(846,040	)		(733,516	)		(684,053	)
State income taxes, net of federal provision (benefit)		464,677			(92,989	)		325,000
State net operating loss valuation allowance (release)		(31,000	)		31,000			(278,000	)
Other		(39,386	)		(102,564	)		(174,189	)
	$	3,274,000		$	3,192,000		$	4,901,000

Deferred tax assets and liabilities resulting from differences between the financial statement carrying amounts and the tax basis of assets and liabilities

	2012		2011
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$	30,320,765	$	26,939,720
Derivative contracts		—		84,001
		30,320,765		27,023,721
Deferred tax assets:
State net operating loss carry forwards, net of valuation allowance of $0 in 2012 and $31,000 in 2011		1,008,271		1,130,732
AMT credit carry forwards		1,189,053		—
Deferred directors’compensation		990,455		986,340
Statutory depletion carry forwards		415,958		—
Other		130,021		121,899
		3,733,758		2,238,971
Net deferred tax liabilities	$	26,587,007	$	24,784,750

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Acquisitions

12 Months Ended

Sep. 30, 2012

Acquisitions [Abstract]

ACQUISITIONS

12. ACQUISITIONS

On October 25, 2011, the Company closed an acquisition of certain Fayetteville Shale assets located in Van Buren, Conway and Cleburne Counties, Arkansas, in the core of the Fayetteville Shale. The Company acquired an average working interest of 2.3% in 193 producing non-operated natural gas wells and 1,531 acres of leasehold from a private seller. There were approximately 240 future infill drilling locations identified on the leasehold at the time of purchase. The purchase price was $17.4 million and was funded by utilizing cash on hand and $13.3 million from the Company’s bank credit facility. The purchase price was allocated to the producing wells based on fair value determined by estimated reserves.

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenue attributable to this acquisition included in the Company’s Statement of Operations for the year ended September 30, 2012, was $3,434,850. Net income attributable to the acquisition included in the Statement of Operations for the year ended September 30, 2012, was $200,158.

Presented below is the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2010. The unaudited pro forma financial information is for informational purposes only and does not purport to present what our results would actually have been had this transaction actually occurred on the date presented or to project our results of operations or financial position for any future period. The pro forma financial information was not provided for the comparative period ending September 30, 2010, as the information could not be obtained from the seller.

	For the Year Ended
	September 30
	2012		2011
Revenue:
As reported	$	48,532,317	$	44,976,651
Pro forma revenue		409,988		4,433,282
Pro forma	$	48,942,305	$	49,409,933
Net Income:
As reported	$	7,370,996	$	8,493,912
Pro forma income		136,315		644,859
Pro forma	$	7,507,311	$	9,138,771

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Deferred Compensation Plan for Directors

12 Months Ended

Sep. 30, 2012

Employee Stock Ownership Plan/Deferred Compensation Plan For Directors [Abstract]

DEFERRED COMPENSATION PLAN FOR DIRECTORS

8. DEFERRED COMPENSATION PLAN FOR DIRECTORS

The Panhandle Oil and Gas Inc. Deferred Compensation Plan for Non-Employee Directors (the “Plan”) provides that each eligible director can individually elect to receive shares of Company Common Stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These shares are unissued and vest as earned. The shares are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. As of September 30, 2012, there were 121,348 shares (129,776 shares at September 30, 2011) included in the Plan. The deferred balance outstanding at September 30, 2012, under the Plan was $2,676,160 ($2,665,583 at September 30, 2011). Expenses totaling $417,347, $443,456 and $359,628 were charged to the Company’s results of operations for the years ended September 30, 2012, 2011 and 2010, respectively, and are included in general and administrative expense in the accompanying Statement of Operations.

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Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) (Details 4)	12 Months Ended
	Sep. 30, 2012 Mcfe
Changes in proved undeveloped reserves
Beginning proved undeveloped reserves	44,575,844
Proved undeveloped reserves transferred to proved developed	(5,393,421)
Revisions	(22,369,152)
Extensions and discoveries	24,458,980
Purchases	9,612,804
Ending proved undeveloped reserves	50,885,055

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Earnings Per Share

12 Months Ended

Sep. 30, 2012

Earnings Per Share [Abstract]

EARNINGS PER SHARE

6. EARNINGS PER SHARE

The following table sets forth the computation of earnings per share.

	Year ended September 30,
	2012		2011		2010
Numerator for basic and diluted earnings per share:
Net income (loss)	$	7,370,996	$	8,493,912	$	11,419,690
Denominator for basic and diluted earnings per share - weighted average shares (including for 2012, 2011 and 2010, unissued, vested directors’ shares of 114,596, 122,728 and 111,491, respectively)		8,360,931		8,393,890		8,422,387

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Employee Stock Ownership Plan

12 Months Ended

Sep. 30, 2012

Employee Stock Ownership Plan/Deferred Compensation Plan For Directors [Abstract]

EMPLOYEE STOCK OWNERSHIP PLAN

7. EMPLOYEE STOCK OWNERSHIP PLAN

The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan that serves as the Company’s sole retirement plan for all its employees. Company contributions are made at the discretion of the Board and, to date, all contributions have been made in shares of Company Common Stock. The Company contributions are allocated to all ESOP participants in proportion to their compensation for the plan year, and 100% vesting occurs after three years of service. Any shares that do not vest are treated as forfeitures and are distributed amongst other vested employees. For contributions

of Common Stock, the Company records as expense the fair market value of the stock at the time of contribution. The 267,723 shares of the Company’s Common Stock held by the plan, as of September 30, 2012, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings per share computations and receive dividends.

Contributions to the plan consisted of:

Year	Shares		Amount
2012		10,660	$	326,942
2011		10,710	$	303,843
2010		11,632	$	287,194

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Restricted Stock Plan

12 Months Ended

Sep. 30, 2012

Restricted Stock Plan [Abstract]

RESTRICTED STOCK PLAN

9. 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 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 began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to certain officers. The restricted stock vests at the end of the vesting period (three or five years) and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares was based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.

On December 21, 2010, the Company began awarding shares of the Company’s Common Stock, subject to certain share price performance standards (performance based), 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. Upon vesting, shares are expected to be issued out of shares held in treasury.

Compensation expense for the restricted stock awards is recognized in G&A.

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2012, 2011 and 2010, related to the Company’s performance based and non-performance based restricted stock.

	Year Ended September 30,
	2012		2011		2010
Performance based, restricted stock	$	150,480	$	42,909	$	—
Non-performance based, restricted stock		180,443		109,573		12,028
Total compensation expense	$	330,923	$	152,482	$	12,028

A summary of the Company’s unrecognized compensation cost for its unvested performance based and non-performance based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

	As of September 30, 2012
	Unrecognized Compensation		Weighted Average Period
Performance based, restricted stock	$	322,977		1.89
Non-performance based, restricted stock		370,587		2.05
Total	$	693,564

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 is presented below:

	Performance based Unvested Restricted Shares		Weighted Average Grant- Date Fair Value		Non- Performance based  Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
Unvested shares as of September 30, 2010		—	$	—		8,500	$	28.30
Granted		8,782	$	19.54		8,780	$	28.00
Vested		—	$	—		—	$	—
Forfeited		—	$	—		—	$	—
Unvested shares as of September 30, 2011		8,782	$	19.54		17,280	$	28.15
Granted		17,709	$	19.47		5,903	$	31.55
Vested		—	$	—		—	$	—
Forfeited		—	$	—		—	$	—
Unvested shares as of September 30, 2012		26,491	$	19.49		23,183	$	29.01

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Acquisitions (Details) (USD $)	3 Months Ended								12 Months Ended
	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Revenue:
Revenue as reported	$ 11,041,382	$ 13,649,692	$ 10,436,910	$ 13,404,333	$ 12,409,227	$ 11,688,417	$ 10,977,459	$ 9,901,548	$ 48,532,317	$ 44,976,651	$ 51,938,416
Pro forma revenue									409,988	4,433,282
Pro forma									48,942,305	49,409,933
Net Income:
Net income	182,621	3,100,299	675,966	3,412,110	2,644,381	2,650,429	1,772,253	1,426,849	7,370,996	8,493,912	11,419,690
Pro forma income									136,315	644,859
Pro forma									$ 7,507,311	$ 9,138,771

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Quarterly Results of Operations (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Summary of the Company's unaudited quarterly results of operations
Revenues	$ 11,041,382	$ 13,649,692	$ 10,436,910	$ 13,404,333	$ 12,409,227	$ 11,688,417	$ 10,977,459	$ 9,901,548	$ 48,532,317	$ 44,976,651	$ 51,938,416
Income (loss) before provision for income taxes	496,621	4,681,299	1,205,966	4,261,110	3,720,381	3,691,429	2,271,253	2,002,849	10,644,996	11,685,912	16,320,690
Net income (loss)	$ 182,621	$ 3,100,299	$ 675,966	$ 3,412,110	$ 2,644,381	$ 2,650,429	$ 1,772,253	$ 1,426,849	$ 7,370,996	$ 8,493,912	$ 11,419,690
Earnings (loss) per share	$ 0.02	$ 0.37	$ 0.08	$ 0.41	$ 0.31	$ 0.32	$ 0.21	$ 0.17	$ 0.88	$ 1.01	$ 1.36

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Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) (Details Textual) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Reserve Quantities [Line Items]
Proved Undeveloped Reserves	50,885,055	44,575,844
Percentage of PUD reserves total	8.00%
Number of PUD location	589
Supplementary information on oil and natural gas reserves (Textual) [Abstract]
Positive performance revisions	3,613,707
Proved Developed Reserves (Energy)	1,644,157
Proved undeveloped revisions	1,969,550
Negative proved developed revisions	7,073,763
Negative gas pricing revisions	31,412,464
Negative proved undeveloped revisions	24,338,701
Acquisition of mineral acreage with proved reserves	$ 17.4	$ 3.9
Percentage of annual discount factor	10.00%
Oil [Member]
Reserve Quantities [Line Items]
Prices used to calculate reserves and future cash flows from reserves from NGL	89.41	90.28	69.23
Natural Gas [Member]
Reserve Quantities [Line Items]
Prices used to calculate reserves and future cash flows from reserves for natural gas	2.51	3.81	4.33
Proved undeveloped reserves transferred to proved developed	5,400,000
Percentage transferred to proved developed	12.00%
Additional undeveloped reserves removed	24,300,000
Percentage of additional undeveloped reserves removed	55.00%
Total proved undeveloped reserves moved out	29,700,000
Percentage of proved undeveloped reserves moved out	67.00%
Period for converting PUD to PDP	5 years
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Prices used to calculate reserves and future cash flows from reserves from NGL	35.70	38.91
2008 [Member]
Reserve Quantities [Line Items]
Percentage of PUD reserves	1.00%
Number of PUD location	1
2009 [Member]
Reserve Quantities [Line Items]
Percentage of PUD reserves	11.00%
Number of PUD location	45
2008 and 2009 [Member]
Reserve Quantities [Line Items]
Number of PUD location	46

XML

Summary of Significant Accounting Policies (Details 3) (USD $)	Sep. 30, 2012	Sep. 30, 2011
Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis
Total Fair Value	$ 172,271
Derivative Contracts - Swaps [Member]
Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis
Total Fair Value	(75,334)	(77,907)
Derivative Contracts - Collars [Member]
Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis
Total Fair Value	(96,937)	293,847
Quoted Prices in Active Markets (Level 1) [Member] | Derivative Contracts - Swaps [Member]
Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis
Total Fair Value
Quoted Prices in Active Markets (Level 1) [Member] | Derivative Contracts - Collars [Member]
Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis
Total Fair Value
Significant Other Observable Inputs (Level 2) [Member] | Derivative Contracts - Swaps [Member]
Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis
Total Fair Value	(75,334)	(77,907)
Significant Other Observable Inputs (Level 2) [Member] | Derivative Contracts - Collars [Member]
Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis
Total Fair Value
Significant Unobservable Inputs (Level 3) [Member] | Derivative Contracts - Swaps [Member]
Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis
Total Fair Value
Significant Unobservable Inputs (Level 3) [Member] | Derivative Contracts - Collars [Member]
Summary of fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis
Total Fair Value	$ (96,937)	$ 293,847

XML

Restricted Stock Plan (Details) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Summary of pre-tax compensation expense
Restricted stock awards	$ 330,923	$ 152,482	$ 12,028
Performance Based Restricted Stock [Member]
Summary of pre-tax compensation expense
Restricted stock awards	150,480	42,909
Non Performance Based Restricted Stock [Member]
Summary of pre-tax compensation expense
Restricted stock awards	$ 180,443	$ 109,573	$ 12,028

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Sep. 30, 2012

Summary of Significant Accounting Policies [Abstract]

Nature of Business

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 5,666 wells located principally in Oklahoma and Arkansas. Approximately 58% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2012. Approximately 86% of the Company’s total sales volumes in 2012 were derived from the sale of 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.

Basis of Presentation

Basis of Presentation

Certain amounts (lease operating expenses and production taxes in the Statements of Operations; capital expenditures and net (gain) loss on sales of assets in the Statements of Cash Flows) in the prior years have been reclassified to conform to the current year presentation.

Use of Estimates

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

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

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, 2012 and 2011, the Company had no material natural gas imbalances.

Accounts Receivable and Concentration of Credit Risk

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 2012 and 2011, we did not recognize a reserve for bad debt expense.

Derivative contracts entered into by the Company are also unsecured.

Oil and Natural Gas Producing Activities

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, 2012, the remaining carrying cost of non-producing oil and natural gas leases was $694,968.

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, 2012, the Company had no outstanding letters of credit.

Lease Bonus

Lease Bonus

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 times receives an up-front, non-refundable, cash payment (lease bonus payment) 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 agreement with the exploration company transferring the rights to explore for and produce any oil or natural gas it 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

Derivatives

The Company entered into oil costless collar contracts, natural gas costless collar contracts, natural gas fixed swap contracts and natural gas basis protection swaps. These instruments were 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 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. 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 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.

Fair Value Measurements

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. Counterparty quotes are generally assessed as a Level 3 input.

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

	Fair Value Measurement at September 30, 2011
	Quoted Prices  in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	—	$	(77,907	)	$	—	$	(77,907	)
Derivative Contracts - Collars	$	—	$	—		$	293,847	$	293,847

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 and natural gas 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.

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.

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

	Derivatives
Balance of Level 3 as of October 1, 2011	$	293,847
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		549,773
Unrealized		(940,557	)
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, 2012	$	(96,937	)

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,
	2012				2011
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	1,301,951	$	826,508	$	1,811,709	$	1,728,162	(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.

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 as the interest rates on the Company’s revolving line of credit are approximately equivalent to market rates for similar type debt based on the Company’s credit worthiness, which represents level 3 of the fair value hierarchy.

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 $5,374,868 and $5,215,239 at September 30, 2012 and 2011, 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 86-year life of the Company. There are approximately 198,965 net acres of non-producing minerals in more than 6,931 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $45. 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, 2012, 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 $826,508, $1,728,162 and $605,615, respectively, for 2012, 2011 and 2010. 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 2012, 2011 and 2010, interest of $129,172, $0 and $104,100, respectively, was included in the Company’s capital expenditures. Interest of $127,970, $0 and $60,912, 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, 2012 and 2011, relating to the Company’s asset retirement obligations:

	2012			2011
Asset Retirement Obligations as of beginning of the year	$	1,843,875		$	1,730,369
Accretion of Discount		121,112			109,198
New Wells Placed on Production		184,027			28,624
Wells Sold or Plugged		(26,064	)		(24,316	)
Asset Retirement Obligations as of end of the year	$	2,122,950		$	1,843,875

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, 2012 and 2011, 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, including unissued, vested directors’ shares during the period. The Company’s restricted stock awards are not included in the diluted earnings per share calculation because the effect would be non-dilutive.

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 2007.

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, 2012, 2011 and 2010, the Company recorded interest and penalties of $0, $21,000 and $0, 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 plans to adopt this new standard effective January 1, 2013, and will provide any additional disclosures necessary to comply with the new standard.

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.

Depreciation, Depletion, Amortization and Impairment

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 $5,374,868 and $5,215,239 at September 30, 2012 and 2011, 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 86-year life of the Company. There are approximately 198,965 net acres of non-producing minerals in more than 6,931 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $45. 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, 2012, 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 $826,508, $1,728,162 and $605,615, respectively, for 2012, 2011 and 2010. 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

Capitalized Interest

During 2012, 2011 and 2010, interest of $129,172, $0 and $104,100, respectively, was included in the Company’s capital expenditures. Interest of $127,970, $0 and $60,912, 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

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

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, 2012 and 2011, relating to the Company’s asset retirement obligations:

Environmental Costs

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, 2012 and 2011, there were no such costs accrued.

Earnings (Loss) Per Share of Common Stock

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, including unissued, vested directors’ shares during the period. The Company’s restricted stock awards are not included in the diluted earnings per share calculation because the effect would be non-dilutive.

Share-based Compensation

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

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 2007.

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, 2012, 2011 and 2010, the Company recorded interest and penalties of $0, $21,000 and $0, respectively. The Company does not believe it has any significant uncertain tax positions.

New Accounting Standards

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 plans to adopt this new standard effective January 1, 2013, and will provide any additional disclosures necessary to comply with the new standard.

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.

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Restricted Stock Plan (Tables)

12 Months Ended

Sep. 30, 2012

Restricted Stock Plan [Abstract]

Summary of pre-tax compensation expense

	Year Ended September 30,
	2012		2011		2010
Performance based, restricted stock	$	150,480	$	42,909	$	—
Non-performance based, restricted stock		180,443		109,573		12,028
Total compensation expense	$	330,923	$	152,482	$	12,028

Summary of unrecognized compensation cost

	As of September 30, 2012
	Unrecognized Compensation		Weighted Average Period
Performance based, restricted stock	$	322,977		1.89
Non-performance based, restricted stock		370,587		2.05
Total	$	693,564

Summary of the status of unvested shares of restricted stock awards

	Performance based Unvested Restricted Shares		Weighted Average Grant- Date Fair Value		Non- Performance based  Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
Unvested shares as of September 30, 2010		—	$	—		8,500	$	28.30
Granted		8,782	$	19.54		8,780	$	28.00
Vested		—	$	—		—	$	—
Forfeited		—	$	—		—	$	—
Unvested shares as of September 30, 2011		8,782	$	19.54		17,280	$	28.15
Granted		17,709	$	19.47		5,903	$	31.55
Vested		—	$	—		—	$	—
Forfeited		—	$	—		—	$	—
Unvested shares as of September 30, 2012		26,491	$	19.49		23,183	$	29.01

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Employee Stock Ownership Plan (Details Textual)	12 Months Ended
	Sep. 30, 2012
Employee Stock Ownership Plan (Textual) [Abstract]
Percentage of Company Contributions Are Allocated To Employee Stock Ownership Plan Participants	100.00%
Eligibility of Receiving Full Contribution Of Employee Stock Ownership Plan	3 years
Number of Common Stock Share held for ESOP plan	267,723

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Income Taxes (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
The difference between the provision (benefit) for income taxes and the amount result from the application of the federal statutory rate to income before provision (benefit) for income taxes
Provision (benefit) for income taxes at statutory rate	$ 3,725,749	$ 4,090,069	$ 5,712,242
Percentage depletion	(846,040)	(733,516)	(684,053)
State income taxes, net of federal provision (benefit)	464,677	(92,989)	325,000
State net operating loss valuation allowance (release)	(31,000)	31,000	(278,000)
Other	(39,386)	(102,564)	(174,189)
provision (benefit) for income taxes	$ 3,274,000	$ 3,192,000	$ 4,901,000

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Statements of Stockholders' Equity (USD $)	Total	Class A voting Common Stock	Capital in Excess of Par Value	Deferred Directors Compensation	Retained Earnings	Treasury Stock
Balances at Sep. 30, 2009	$ 64,122,343	$ 140,524	$ 1,922,053	$ 1,862,499	$ 64,507,547	$ (4,310,280)
Balances, shares at Sep. 30, 2009		8,431,502				(119,866)
Purchase of treasury stock	(291,383)					(291,383)
Purchase of treasury stock, shares						(12,326)
Issuance of treasury shares to ESOP	287,194		(117,716)			404,910
Issuance of treasury shares to ESOP, shares						11,632
Restricted stock awards	12,028		12,028
Common shares to be issued to directors for services	359,628			359,628
Dividends declared ($.28 per share)	(2,327,504)				(2,327,504)
Net income	11,419,690				11,419,690
Balances at Sep. 30, 2010	73,581,996	140,524	1,816,365	2,222,127	73,599,733	(4,196,753)
Balances, shares at Sep. 30, 2010		8,431,502				(120,560)
Purchase of treasury stock	(1,851,290)					(1,851,290)
Purchase of treasury stock, shares						(65,481)
Issuance of treasury shares to ESOP	303,843		(44,340)			348,183
Issuance of treasury shares to ESOP, shares						10,710
Restricted stock awards	152,482		152,482
Common shares to be issued to directors for services	443,456			443,456
Dividends declared ($.28 per share)	(2,322,082)				(2,322,082)
Net income	8,493,912				8,493,912
Balances at Sep. 30, 2011	78,802,317	140,524	1,924,507	2,665,583	79,771,563	(5,699,860)
Balances, shares at Sep. 30, 2011		8,431,502				(175,331)
Purchase of treasury stock	(1,158,957)					(1,158,957)
Purchase of treasury stock, shares						(38,771)
Issuance of treasury shares to ESOP	326,942		(14,391)			341,333
Issuance of treasury shares to ESOP, shares						10,660
Restricted stock awards	330,923		330,923
Distribution of deferred directors' compensation	83,742		(220,810)	(406,770)		711,322
Distribution of deferred directors' compensation, shares						22,132
Common shares to be issued to directors for services	417,347			417,347
Dividends declared ($.28 per share)	(2,321,164)				(2,321,164)
Net income	7,370,996				7,370,996
Balances at Sep. 30, 2012	$ 83,852,146	$ 140,524	$ 2,020,229	$ 2,676,160	$ 84,821,395	$ (5,806,162)
Balances, shares at Sep. 30, 2012		8,431,502				(181,310)

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Income Taxes

12 Months Ended

Sep. 30, 2012

Income Taxes [Abstract]

INCOME TAXES

3. INCOME TAXES

The Company’s provision (benefit) for income taxes is detailed as follows:

	2012		2011			2010
Current:
Federal	$	1,452,000	$	1,266,000		$	3,950,000
State		20,000		48,000			174,000
		1,472,000		1,314,000			4,124,000
Deferred:
Federal		1,126,000		1,982,000			708,000
State		676,000		(104,000	)		69,000
		1,802,000		1,878,000			777,000
	$	3,274,000	$	3,192,000		$	4,901,000

The difference between the provision (benefit) for income taxes and the amount which would result from the application of the federal statutory rate to income before provision (benefit) for income taxes is analyzed below for the years ended September 30:

	2012			2011			2010
Provision (benefit) for income taxes at statutory rate	$	3,725,749		$	4,090,069		$	5,712,242
Percentage depletion		(846,040	)		(733,516	)		(684,053	)
State income taxes, net of federal provision (benefit)		464,677			(92,989	)		325,000
State net operating loss valuation allowance (release)		(31,000	)		31,000			(278,000	)
Other		(39,386	)		(102,564	)		(174,189	)
	$	3,274,000		$	3,192,000		$	4,901,000

Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax basis of assets and liabilities, consist of the following at September 30:

	2012		2011
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$	30,320,765	$	26,939,720
Derivative contracts		—		84,001
		30,320,765		27,023,721
Deferred tax assets:
State net operating loss carry forwards, net of valuation allowance of $0 in 2012 and $31,000 in 2011		1,008,271		1,130,732
AMT credit carry forwards		1,189,053		—
Deferred directors’compensation		990,455		986,340
Statutory depletion carry forwards		415,958		—
Other		130,021		121,899
		3,733,758		2,238,971
Net deferred tax liabilities	$	26,587,007	$	24,784,750

At September 30, 2012, the Company had an income tax benefit of $1,008,271 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring from 2025 to 2031. The valuation allowance of $31,000 that was recorded in fiscal 2011 for the Oklahoma NOL’s was reversed in 2012 as management believes that they will be utilized before they expire. The AMT carry forwards do not have an expiration date.

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Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) (Details 2)	12 Months Ended
	Sep. 30, 2012 bbl	Sep. 30, 2011 bbl	Sep. 30, 2010 bbl
Oil (Barrels) [Member]
Estimated Quantities of Proved Oil and Natural Gas Reserves
Proved Oil and Natural Gas Reserves, Beginning Balance	843,738	925,009	920,873
Revisions of previous estimates	8,627	(59,360)	47,999
Divestitures			(487)
Acquisitions
Extensions and discoveries and other additions	373,097	82,230	59,003
Production	(153,143)	(104,141)	(102,379)
Proved Oil and Natural Gas Reserves, Ending Balance	1,072,319	843,738	925,009
NGL (Barrels) [Member]
Estimated Quantities of Proved Oil and Natural Gas Reserves
Proved Oil and Natural Gas Reserves, Beginning Balance	791,648
Revisions of previous estimates	(76,794)	791,648
Divestitures
Acquisitions
Extensions and discoveries and other additions	172,602
Production	(98,714)
Proved Oil and Natural Gas Reserves, Ending Balance	788,742	791,648
Natural Gas (Mcf) [Member]
Estimated Quantities of Proved Oil and Natural Gas Reserves
Proved Oil and Natural Gas Reserves, Beginning Balance	101,837,984	98,170,455	54,027,810
Revisions of previous estimates	(27,389,752)	769,676	15,762,883
Divestitures			(7,778)
Acquisitions	19,075,529	3,189,520
Extensions and discoveries and other additions	29,062,593	8,005,990	36,689,882
Production	(9,072,298)	(8,297,657)	(8,302,342)
Proved Oil and Natural Gas Reserves, Ending Balance	113,514,056	101,837,984	98,170,455

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Information On Oil and Natural Gas Producing Activities (Tables)

12 Months Ended

Sep. 30, 2012

Information on Oil and Natural Gas Producing Activities [Abstract]

Summary of sales through various operators or purchasers

	2012			2011			2010
Southwestern Energy Company		15	%		9	%		8	%
Chesapeake Operating, Inc.		13	%		15	%		14	%
Devon Energy Corp.		10	%		9	%		6	%
Newfield Exploration		7	%		14	%		15	%
JMA Energy Company		5	%		7	%		11	%

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Summary of Significant Accounting Policies (Details Textual) (USD $)	12 Months Ended
	Sep. 30, 2012 Tracts Area acre Well	Sep. 30, 2011	Sep. 30, 2010
Property Plant And Equipment [Line Items]
Total sale volume from sale of natural Gas	58.00%
Summary of Significant Accounting Policies (Textual) [Abstract]
Number of Oil and Natural Gas Production Units Located in Oklahoma	5,666
Maturity Period of Cash and Cash Equivalents	three months or less
Reserve for bad debt expense	$ 0	$ 0
Amount of Natural Gas Imbalances
Carrying Cost of Non-Producing Oil and Natural Gas Leases	694,968
Fair value of derivative contracts Asset , Liabilities	172,271
Fair value of derivative contracts Asset		215,940
Impairment	826,508	1,728,162	605,615
Book value of Non-producing oil and natural gas	5,374,868	5,215,239
Percentage of perpetual ownership of mineral interests in Arkansas ,New Mexico, North Dakota, Oklahoma and Texas	91.00%
Accumulated Period perpetual rights	86 years
Non Producing Minerals Area	198,965
Number of tracts owned	6,931
Tracts Average Cost Per Acre	45
Average Tract Contains	29
Amortized Period of Non-producing Minerals	33 years
Amount of Capitalized Interest Included in the Company's Capital Expenditures	129,172	0	104,100
Interest On capitalized Expenses	127,970	0	60,912
Interest Held By Company	5.00%
Environmental liability costs
Restricted Stock Awards	three or five years
Income Taxes interests and penalties	0	21,000	0
Outstanding letters of credit
Natural Gas [Member]
Property Plant And Equipment [Line Items]
Total sale volume from sale of natural Gas	86.00%
Maximum [Member]
Property Plant And Equipment [Line Items]
Useful life of furniture and fixtures	8 years
Minimum [Member]
Property Plant And Equipment [Line Items]
Useful life of furniture and fixtures	5 years

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Quarterly Results of Operations (Unaudited)

12 Months Ended

Sep. 30, 2012

Quarterly Results of Operations (Unaudited) [Abstract]

QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

13. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

The following is a summary of the Company’s unaudited quarterly results of operations.

	Fiscal 2012
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	13,404,333	$	10,436,910	$	13,649,692	$	11,041,382
Income (loss) before provision for income taxes	$	4,261,110	$	1,205,966	$	4,681,299	$	496,621
Net income (loss)	$	3,412,110	$	675,966	$	3,100,299	$	182,621
Earnings (loss) per share	$	0.41	$	0.08	$	0.37	$	0.02
	Fiscal 2011
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	9,901,548	$	10,977,459	$	11,688,417	$	12,409,227
Income (loss) before provision for income taxes	$	2,002,849	$	2,271,253	$	3,691,429	$	3,720,381
Net income (loss)	$	1,426,849	$	1,772,253	$	2,650,429	$	2,644,381
Earnings (loss) per share	$	0.17	$	0.21	$	0.32	$	0.31