PHX MINERALS INC. - Annual Report: 2011 (Form 10-K)

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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, 2011

COMMISSION FILE NUMBER: 001-31759

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

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:

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

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):

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, 2011, was $223,251,282. As of December 1, 2011, 8,256,171 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 8, 2012, 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.

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T A B L E    O F    C O N T E N T S

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DEFINITIONS

The following defined terms are used in this report:

“Bbl” means barrel;

“Bcf” means billion cubic feet;

“Board” means board of directors;

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

“CEO” means Chief Executive Officer;

“CFO” means Chief Financial Officer;

“CO2” means carbon dioxide;

“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(s)” refers to DeGolyer and MacNaughton of Dallas, Texas, for proved reserves calculated as of September 30, 2010 and 2011, or to Pinnacle Energy Services, L.L.C. of Oklahoma City, Oklahoma, for proved reserves calculated as of September 30, 2009;

“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;

“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;

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“net wells” or “net acres” are determined by multiplying gross wells or acres by the Company’s net revenue interest in such wells or acres;

“NGL” means natural gas liquids;

“NYMEX” refers to the New York Mercantile Exchange;

“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 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” means the United States Securities and Exchange Commission;

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

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 2011 mean the fiscal year ended September 30, 2011.

References to natural gas

Excluding 2011 reserves, all references to natural gas reserves, production, sales and prices include associated natural gas liquids.

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

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PART I

GENERAL

Panhandle Oil and Gas Inc. (“Company” or “Panhandle”) 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 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 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 its 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, more than 85% of Panhandle’s revenues are derived from the production and sale of oil and natural gas (see Item 8 – “Financial Statements”). The Company’s oil and natural gas properties,

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including its mineral acreage, leasehold acreage and working and royalty interests in producing wells are mainly in Oklahoma with other significant holdings in Arkansas, New Mexico, North Dakota and Texas (see Item 2 – “Description of 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 have been on properties in which the Company owns mineral acreage and, in many cases, already owns an interest in a producing well in the 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 natural gas liquids. 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 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 sold is received by the Company either from the contracted purchasers or the well operator. 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 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 is contained in Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

COMPETITIVE BUSINESS CONDITIONS

The oil and natural gas industry is highly competitive, particularly in the search for new oil 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, changes in prices received for its oil and natural gas production, business and consumer demand for refined oil products and natural gas, and the effects of federal and state regulation of the exploration for, production of and sales of oil 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 and natural gas production.

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

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in the drilling and production phases. The Company uses its strong financial base and its mineral and leasehold acreage ownership, coupled with its own geologic and economic evaluations, to participate in drilling operations with these larger companies. This methodology allows the Company to compete effectively in drilling operations it could not undertake on its own due to financial and personnel limits and allows it to maintain low overhead costs.

SOURCES AND AVAILABILITY OF RAW MATERIALS

The existence of recoverable oil 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 the raw materials to our business. The production and sale of oil and natural gas from the Company’s properties is 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 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 and natural gas production is sold, in most cases, through its well operators to many different purchasers on a well-by-well basis. During 2011, sales through two separate well operators accounted for approximately 15% and 14% of the Company’s total oil 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 and natural gas sales. During 2009, sales through three separate well operators accounted for approximately 20%, 17% and 14% of the Company’s total oil 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 producing oil and natural gas wells 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 and/or 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 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 reports concerning operations and impose other regulations relating to the exploration for and production of oil 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.

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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 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

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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, 2011, Panhandle employed 19 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. 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.

Continuing effects of current domestic and international economic conditions, or the occurrence of a “double dip” recession, could lead to: (1) a decline in demand for oil and natural gas resulting in decreased oil and natural gas reserves due to curtailed drilling activity; (2) a decline in oil and natural gas prices; (3) risk of insolvency of well operators and oil and natural gas purchasers; (4) limited availability of certain insurance coverages; 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 and natural gas prices, would have a negative impact on the Company’s cash flow, profitability and value.

Oil 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.

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

In recent years, oil 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 us. 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 and natural gas prices and production performance.

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

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

A substantial decline in oil 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 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:

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

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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, 2011, was a net asset of $215,940.

Lower oil and natural gas prices or negative adjustments to oil 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 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 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 and natural gas sales prices or unfavorable adjustments to oil 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.

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 or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil 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

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assumptions relating to the level of oil 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 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 is calculated using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil and natural gas price for each month within the 12-month period prior to September 30, 2011, 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 ten percent 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 we make 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 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 ten percent discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board’s (“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 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 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 or natural gas is present and may be commercially produced.

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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 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, 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.

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. The facility, which was undrawn at September 30, 2011, has a 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:

The borrowing base of our corporate revolving bank credit facility is subject to periodic redetermination and is based in part on oil and natural gas prices. A lowering of our borrowing base because of lower oil 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.

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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, and future wells expected to be drilled, in which the Company owns an interest were, or 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 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 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 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 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.

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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.

Many of our competitors have financial and other resources substantially 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.

None

At September 30, 2011, Panhandle’s principal properties consisted of perpetual ownership of 255,857 net mineral acres, held principally in Arkansas, New Mexico, North Dakota, Oklahoma, Texas and six other states. The Company also held leases on 17,480 net acres primarily in Oklahoma. At September 30, 2011, Panhandle held working interests, royalty interest or both in 5,107 producing oil and natural gas wells and 48 wells in the process of being drilled or completed.

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, 2011.

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Leases

The following table reflects net mineral acres leased from others, lease expiration dates, and net leased acres held by production.

PROVED RESERVES

The following table summarizes estimates of proved reserves of oil and natural gas held by Panhandle. All proved reserves are located onshore within the United States and are principally made up of small interests in 5,107 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.

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The 7.9 Bcfe increase in reserves is a combination of the following factors:

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The following details the changes in proved undeveloped reserves for 2011 (Mcfe):

The beginning 2011 PUD reserves were 41,208,879 Mcfe. A total of 5,190,555 Mcfe (12.6% of the beginning balance) were transferred to proved developed during 2011. An additional 5,553,576 Mcfe (13.5% of the beginning balance) were removed during 2011 as the result of becoming uneconomic at 2011 product prices. A total of 10,744,131 Mcfe (26.1% of the beginning balance) of PUD reserves were moved out of the category during 2011 as the result of either being transferred to proved developed or removed as uneconomic. Only one PUD location from 2007 and one PUD location from 2008 remain in the PUD category. We anticipate that all the Company’s remaining PUD locations will be drilled and converted to PDP within 5 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.

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 includes 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 10 to the financial statements in Item 8 for disclosures regarding our oil and natural gas reserves.

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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.

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 and natural gas reserves as of September 30, 2011 and 2010 (see Exhibits 23 and 99). Reserves as of September 30, 2009, were calculated by Pinnacle Energy Services, L.L.C. of Oklahoma City, Oklahoma.

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The Company’s net proved oil and natural gas reserves (including certain undeveloped reserves described above), all of which are located onshore in the United States, as of September 30, 2011, 2010 and 2009, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firms. 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, 2011, 2010 and 2009. 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. Estimated future net cash flows as of September 30, 2009, have been computed by applying prices of oil and natural gas on September 30, 2009, to future production of proved reserves less estimated future expenditures to be incurred with respect to the development and production of these reserves. 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 as of September 30, 2010 and 2011, were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil and natural gas price for each month within the 12-month period prior to September 30, 2010 and 2011, 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 pricing used for each of the three years presented complies with SEC regulations in effect for each year. 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 12-18 months in several western Oklahoma plays which produce significant NGL, have 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, natural gas liquids and natural gas as of September 30, 2011, were as follows: $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 and 2009, were as follows: 2010 – $69.23/Bbl, $4.33/Mcf ; 2009 – $66.96/Bbl, $2.86/Mcf, respectively, (these natural gas prices are representative of local pipelines in Oklahoma). 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 and natural gas price and production cost increases or decreases, which could affect the economic life of the properties.

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OIL AND NATURAL GAS PRODUCTION

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

Natural gas production includes NGL volumes.

AVERAGE SALES PRICES AND PRODUCTION COSTS

The following table sets forth unit price and cost data for the fiscal periods indicated.

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Approximately 34% of the Company’s oil 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, 2011. Panhandle owns either working interests, royalty interests or both in these wells. The Company does not operate any wells.

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

As of September 30, 2011, Panhandle owned 410,497 gross developed mineral acres and 53,465 net developed mineral acres. Panhandle has also leased from others 137,284 gross developed acres containing 16,000 net developed acres.

UNDEVELOPED ACREAGE

As of September 30, 2011, Panhandle owned 1,255,523 gross and 198,570 net undeveloped mineral acres, and leases on 20,644 gross and 1,480 net 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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PRESENT ACTIVITIES

The following table sets forth the gross and net oil and natural gas wells drilling or testing as of September 30, 2011, in which Panhandle owns either a working interest, a royalty interest or both. These wells were not producing at September 30, 2011.

OTHER FACILITIES

The Company leases 12,369 square feet of office space in Oklahoma City, OK ending in 2012.

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 of our future capital expenditures; wells to be drilled or reworked; prices for oil and natural gas; demand

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for oil and natural gas; estimates of proved oil and natural gas reserves; development and infill drilling potential; drilling prospects; business strategy; production of oil 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 2012 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 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 natural gas and crude oil are dependent on a number of factors beyond the Company’s control, including: the demand for oil 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 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 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 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 and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil 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 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 and natural gas and estimates of the future net cash flows from oil and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, oil and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual production, revenues and expenditures with respect to oil 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 and natural gas reserves attributable to the Company’s properties. As required by the SEC, the 2010 and 2011 estimated discounted future net cash flows from proved oil and natural gas reserves are determined based on the fiscal year’s 12-month average of the first-day-of-the-month oil and natural gas prices (oil and natural gas prices used for 2009 were based on the September 30 spot price of that year) 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 and natural gas production, supply and demand for oil 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.

There were no material legal proceedings involving Panhandle on September 30, 2011, or at the date of this report.

No matters were submitted to a vote of Panhandle’s security holders during the fourth quarter of the fiscal year ended September 30, 2011.

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PART II

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, 2006, and its relative performance is tracked through September 30, 2011.

On July 22, 2008, the Company’s Common Stock was listed on the New York Stock Exchange (symbol PHX) and, prior to that, it was listed on the American Stock Exchange under the same symbol. The following table sets forth the high and low trade prices of the Common Stock during the periods indicated:

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At November 22, 2011, there were 1,592 holders of record of Panhandle’s Class A Common Stock and approximately 4,200 beneficial owners.

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 of directors 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 of directors.

The Company’s credit facility also contains a provision limiting the paying or declaring of a cash dividend to fifteen percent 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,” 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 of directors 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 of directors’ 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 of directors. 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 of directors determine otherwise. Pursuant to these resolutions adopted by the board of directors, the purchase of an additional $1.5 million of the Company’s Common Stock became authorized and approved effective March 29, 2011. The shares are held in treasury and are accounted for using the cost method. There were no Common Stock purchases in the fourth quarter of fiscal year 2011. At September 30, 2011, and September 30, 2010, 10,710 and 11,632 (respectively) treasury shares were contributed to the Company’s ESOP on behalf of the ESOP participants.

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The following table summarizes financial data of the Company for its last five fiscal years and should be read in conjunction with the “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.

BUSINESS OVERVIEW

The Company’s principal line of business is to explore for, develop, produce and sell oil 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 and natural gas sales prices. 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 relatively flat to those of 2010, thus reversing the decrease in production that occurred in 2010, as

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compared to 2009. The increased drilling activity is primarily on the Company’s mineral acreage in the Arkansas Fayetteville Shale play and in the oil and natural gas liquids-rich plays such as the Anadarko (Cana) 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. As these wells begin producing and other scheduled wells are drilled and completed in the abovementioned plays, we expect fiscal 2012 production to increase over that of 2011.

Further enhancing production in 2012 will be production from newly acquired producing properties during the last half of 2011 and the first quarter of 2012, primarily in the Arkansas Fayetteville Shale play. The producing properties included with these acquisitions will provide an immediate boost to our production, while the drilling and completion of a substantial number of wells on this newly acquired acreage is expected to provide additional production which will come on line later in 2012.

Although oil and natural gas production remained flat in 2011, oil and natural gas sales revenues decreased slightly as a result of lower natural gas prices, partially offset by increased oil prices. It is difficult to predict what oil and natural gas prices will be in 2012.

Oil, natural gas and natural gas liquids reserves increased in 2011 compared to 2010, the result of successful drilling of exploratory and developmental wells in excess of PUD reserves previously presented. The positive performance revisions recognized in the reserves reported at September 30, 2010, has resulted in lower 2011 DD&A.

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 2012. Also, during the first quarter of 2012, we closed the purchase of 1,531 net leasehold acres (82% of which is held by production) in the Fayetteville Shale at a cost of $17.5 million. The Company used existing cash and $13.3 million in borrowings from its bank credit facility to finance the acquisition. The acquisition included non-operating working interests in 193 producing gas wells and approximately 240 infill drilling locations. The Company will 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 2011 or prior years.

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

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RESULTS OF OPERATIONS

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, has resulted in lower 2011 DD&A.

Oil and Natural Gas (And Associated Natural Gas Liquids) 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, thus reversing the decrease in production volumes that occurred in 2010, as compared to 2009. 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 (Cana) 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:

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:

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 are 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 are principally the result of well workovers performed in 2011.

Value based 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 is 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 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. 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 has 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, which was impaired in total by $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, is 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. Production volumes and future development potential are being evaluated. 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 is primarily related to increases in the following expense categories: personnel $346,331; board of directors 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 by $20,220. The increase in board of directors 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

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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.

Fiscal Year 2010 Compared to Fiscal Year 2009

Overview

The Company recorded net income of $11,419,690, or $1.36 per share, in 2010 compared to net loss of $2,405,021, or $.29 per share, in 2009. Increased revenues in 2010 were mainly from increases in oil and natural gas sales, gains on derivative contracts and lease bonuses. Higher oil and natural gas prices more than offset a 10% decrease in production resulting in increased oil and natural gas sales; actual and forward looking prices lower than the Company’s fixed price swap contracts resulted in gains on derivative contracts in 2010 compared to a loss in 2009; and the renewal of leases on certain of the Company’s Arkansas undeveloped mineral acreage increased 2010 revenue from lease bonuses.

The decrease in expenses was primarily related to lower DD&A and impairment costs, resulting from the increase in oil and natural gas reserves (as of September 30, 2010) which lowered the DD&A rate per Mcfe of production. In 2010, an income tax expense of $4,901,000 was incurred compared to a tax benefit of $2,568,000 recognized in 2009.

Oil and Natural Gas (And Associated Natural Gas Liquids) Sales

Oil and natural gas sales increased $6,647,259 or 18% for 2010, as compared to 2009. Driven by higher oil and natural gas prices of 41% and 30%, respectively, 2010 oil and natural gas sales went up, despite a 10% decrease in combined oil and natural gas production on an Mcfe basis. The production decrease occurred as fewer new wells were drilled and put on line in 2010, thus the production decline of existing wells exceeded the production which came on line from new wells.

Production by quarter for 2010 and 2009 was as follows:

Lease Bonus and Rentals

Lease bonus and rentals increased $931,768 for 2010, as compared to 2009. This increase was principally due to the renewal of leases on certain of the Company’s Arkansas undeveloped mineral acreage which increased 2010 revenue from lease bonuses approximately $723,000.

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Gains (Losses) on Natural Gas Derivative Contracts

Realized and unrealized gains and losses are scheduled below:

Lease Operating Expenses (LOE) and Production Taxes

LOE increased $497,293 or 7% in 2010. LOE costs per Mcfe of production increased from $.78 in 2009 to $.92 in 2010. Increased natural gas prices, which increased value based fees (primarily gathering, transportation and marketing costs) caused total LOE and LOE per Mcfe to increase. Natural gas production from the southeast Oklahoma Woodford Shale, Anadarko (Cana) Woodford Shale and Fayetteville Shale areas continued to increase as a proportion of total production. Value based fees are charged as a percent of natural gas revenues and are significantly higher in these shale areas than like fees charged in other of the Company’s production areas. The total amount of value based fees in these three shale areas typically are 12% to 22% of total natural gas revenues. Value based fees increased $1,201,209, or 36%, in 2010 compared to 2009. Value based fees per Mcfe increased $.17, or 51%, in 2010 compared to 2009.

The increase in value based fees was partially offset by a decrease of $703,916 in LOE related to field operating costs in 2010 compared to 2009, a 16% decrease. In 2010, field operating costs were $.38 per Mcfe compared to $.42 per Mcfe in 2009, a 9% decrease. These decreases were due to fewer wells coming on line in 2010 with high initial LOE, fewer well repairs made in 2010 compared to 2009 and the fiscal 2009 sale of wells in the Southeast Leedey field and the McElmo Dome Unit, thus reducing fiscal 2010 LOE.

Production taxes increased $245,336, or 20%, in 2010. The increase was the result of increased sales of oil and natural gas. Oil and natural gas sales in 2010 increased 18%, and production taxes increased 20% compared to 2009. Production taxes were 3.3% of oil and natural gas sales in 2010, compared to 3.2% in 2009. The low overall production tax rate was due to a large proportion of the Company’s natural gas revenues coming from horizontally drilled wells, which were eligible for either Oklahoma production tax credits or reduced Arkansas production tax rates.

Exploration Costs

Exploration costs were $1,583,773 in 2010 compared to $711,582 in 2009, an $872,191 increase. During 2010, leasehold impairment and expired leases totaled $1,191,598 compared to $634,918 during 2009, a $556,680 increase. Five exploratory dry holes incurred expenses of approximately $77,000 during 2009; one exploratory dry hole incurred expenses of approximately $5,000 during 2010.

Also, the Company charged approximately $387,000 to exploration costs in 2010 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 $8,946,810, or 32%, in 2010, while DD&A per Mcfe decreased to $2.16 in 2010, as compared to $2.85 in 2009. Approximately $2,744,000 of the DD&A decrease was the result of a 10% decrease in 2010 combined oil and natural gas production on an Mcfe basis. The remaining DD&A decrease of approximately $6,203,000 was attributable to the $.69 decline in the DD&A rate per Mcfe. This rate declined as a result of increased proved developed oil and natural gas reserves as of

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September 30, 2010 (see Financial Statements, Note 10 – Supplementary Information on Oil and Natural Gas Reserves), as compared to September 30, 2009, and a net reduction during fiscal year 2009 of approximately $3.1 million of asset basis subject to DD&A. This asset basis reduction occurred as fiscal 2009 DD&A and impairment, combined with the basis reduction associated with assets sold, exceeded new additions to properties and equipment for oil and natural gas activities.

Provision for Impairment

The provision for impairment decreased $1,858,905 in 2010, as compared to 2009. During 2010, impairment of $605,615 was recorded on six fields. Approximately $380,000 of the impairment was related to the Buffalo Wallow field in Texas, where the first horizontal well in the field was recently drilled and completed with poor economic results. During 2009, impairment of $2,464,520 was recorded on 13 fields driven by depressed oil and natural gas prices, which negatively affected the estimates of future net revenues from oil and natural gas properties.

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. In 2009, the Company sold a portion of its working interest in the Southeast Leedey field and all of its working interest in the McElmo Dome CO2 Unit for a combined gain of approximately $2.5 million.

General and Administrative Costs (G&A)

G&A increased $728,455, or 15%, in 2010 due to increases in the following expense categories: salaries, bonuses and benefits $433,847; legal $161,016; board of directors fees $101,474; and insurance $87,350. Personnel expenses increased mainly because of higher accrued performance bonuses based on improved Company performance metrics in fiscal 2010 compared to 2009. Legal expense increased primarily due to legal costs of approximately $129,000 incurred during 2010 on a lawsuit related to one well in western Oklahoma. The addition of a new director, an increase in the number of Board meetings and increased director fees resulted in the increase in board of directors’ expense in 2010.

Bad Debt Expense (Recovery)

On July 22, 2008, SemGroup, L.P. and certain subsidiaries (SemGroup) filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy code. On October 28, 2009, the U.S. Bankruptcy Court confirmed the Fourth Amended Joint Plan of Affiliated Debtors which set forth various settlement details for producers and interest owners. Based on the details of the plan, discussion with operators impacted and management’s judgment, the Company lowered the reserve for doubtful accounts to $405,129 at September 30, 2009, resulting in $186,129 of bad debt recovery. No adjustments were made in 2010 to the Company’s reserve for doubtful accounts.

Provision (Benefit) for Income Taxes

The 2010 provision for income taxes was $4,901,000 based on a pre-tax income of $16,320,690, as compared to a benefit for income taxes of $2,568,000 in 2009, based on a pre-tax loss of $4,973,021. The provision for income taxes increased in 2010 by $7,469,000, the result of a $21,293,711 increase in income (loss) before provision (benefit) for income taxes in 2010, compared to 2009, partially offset by the removal of the $278,000 valuation allowance on Oklahoma NOLs. The effective tax rate for 2010 was 30%, whereas the effective tax benefit rate for 2009 was 52%. The Company’s utilization of excess percentage depletion (which is a permanent tax benefit) decreased the provision for income taxes in 2010, whereas it increased the tax benefit in 2009. The effect of this permanent tax benefit is that the

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effective tax rate is decreased when recording a provision for income taxes as in 2010, while increasing the effective tax rate when recording a benefit for income taxes as in 2009. 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. The reversal of the $278,000 valuation allowance on Oklahoma NOLs reduced the effective tax rate by 2% for 2010.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2011, the Company had positive working capital of $7,314,096, as compared to positive working capital of $10,098,861 at September 30, 2010.

Liquidity

Cash and cash equivalents were $3,506,999 as of September 30, 2011, compared to $5,597,258 at September 30, 2010, a decrease of $2,090,259. Cash flows for the 12 months ended September 30 are summarized as follows:

Net cash provided (used) by: