PHX MINERALS INC. - Annual Report: 2008 (Form 10-K)

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Annual Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

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

Grand Centre, Suite 300, 5400 North Grand Blvd., Oklahoma City, OK		73112
(Address of principal executive offices)		(Zip code)

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

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

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

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes þ 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. o Yes þ 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. þ Yes o 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. o

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

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer   o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes þ 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, 2008, was $202,089,805. As of December 1, 2008, 8,300,128 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 5, 2009, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Report relates.

 

 

T A B L E   O F   C O N T E N T S

				Page
PART I
Item 1		Business			1-9
Item 1B		Unresolved Staff Comments			9
Item 2		Properties			9-16
Item 3		Legal Proceedings			16
Item 4		Submission of Matters to a Vote of Security Holders			16
PART II
Item 5		Market for Registrants Common Equity and Related Stockholder Matters			17-18
Item 6		Selected Financial Data			19-20
Item 7		Management's Discussion and Analysis of Financial Condition and Results of Operations			20-29
Item 7A		Quantitative and Qualitative Disclosures about Market Risk			29-30
Item 8		Financial Statements and Supplementary Data			31-55
Item 9		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			56
Item 9A		Controls and Procedures			56
PART III
Item 10-14		Incorporated by Reference to Proxy Statement
PART IV
Item 15		Exhibits, Financial Statement Schedules and Reports on Form 8- K			57
Signature Page					58
Exhibit 21					59
Exhibit 31.1-31.2					60-61
Exhibit 32.1-32.2					62-63
EX-21
EX-31.1
EX-31.2
EX-32.1
EX-32.2

Certain defined terms as used in this report: “SEC” means the United States Securities and Exchange Commission; “Bbl” means barrel; “Bcf” means billion cubic feet; “Mcf” means thousand cubic feet; “Mcfd” means thousand cubic feet per day; “Mcfe” means natural gas stated on an Mcf basis and crude oil converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil to six Mcf of natural gas; “CO2” means carbon dioxide; “PV-10” means estimated pretax present value of future net revenues discounted at 10% using SEC rules; “gross” wells or acres are the wells or acres in which the Company has a working interest; and “net” wells or acres are determined by multiplying gross wells or acres by the Company’s net revenue interest in such wells or acres. References to years 2004-2008 refer to the Company’s fiscal years ended September 30 each year. “Minerals”, “mineral acres” or “mineral interests” refers to fee mineral acreage owned in perpetuity by the Company. “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. “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.

PART I

ITEM 1 BUSINESS

GENERAL

     Panhandle Oil and Gas Inc. (“Panhandle” or the “Company”) is an Oklahoma corporation organized in 1926 as Panhandle Cooperative Royalty Company. In 1979, Panhandle Cooperative Royalty Company was merged into Panhandle Royalty Company. In April, 2007, Panhandle Royalty Company changed its name to Panhandle Oil and Gas Inc. Panhandle’s original authorized and registered stock consisted of 100,000 shares of $1.00 par value Class A Common Stock. In 1982, the Company split the stock on a 10-for-1 basis resulting in 1,000,000 shares of authorized Class A Common Stock. In May 1999, the Company’s shareholders voted to increase the authorized Class A Common Stock to 6,000,000 shares and to split the shares on a three-for-one basis. In addition, voting rights for the shares were changed from one vote per shareholder to one vote per share. In February 2004, the Company’s shareholders voted to increase the authorized Class A Common Stock to 12,000,000 shares and to split the shares on a two-for-one basis. In January 2006, the Class A Common Stock was again split on a two-for-one basis. In March 2007, the Company’s shareholders voted to increase the authorized Class A Common Stock to the current 24,000,000 shares.

     Since its formation, the Company has been involved in the acquisition, management and development of oil and gas properties, including wells located on the Company’s mineral acreage. Panhandle’s mineral properties and other oil and gas interests are located primarily in Arkansas, Kansas, Oklahoma, New Mexico and Texas. Properties are also located in seven other states. The majority of the Company’s oil and gas production is from wells located in Oklahoma.

     In October, 2001, Panhandle acquired Wood Oil Company (“Wood”) of Tulsa, Oklahoma. Wood was a privately held company engaged in oil and gas exploration and production and fee mineral ownership. Wood and its shareholders were unrelated parties to Panhandle. Wood is currently operating as a wholly-owned subsidiary of Panhandle.

     The Company’s office is located at Grand Centre, Suite 300, 5400 North Grand Blvd., Oklahoma City, OK 73112 (405)948-1560, fax (405)948-2038. Its website is located at www.panhandleoilandgas.com.

     The Company files periodic SEC reports 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 electronically with the SEC. In addition, posted on the website are copies of the Company’s various corporate governance documents. From time to time, other important disclosures to investors are provided by posting them 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 450 Fifth Street, N.W., 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 have been filed electronically with the SEC.

BUSINESS STRATEGY

     The majority 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 gas holdings, including its mineral

acreage, leasehold acreage and working and royalty interests in producing wells are mainly in Oklahoma with other significant holdings in Arkansas, Kansas, New Mexico and Texas. See Item 2 - “Description of Properties”. Exploration and development of the Company’s oil and gas properties are conducted in association with operating oil and gas companies, primarily larger independent companies. The Company does not operate any of its oil and 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 has mineral acreage and, in many cases, already owns an interest in a producing well in the unit.

PRINCIPAL PRODUCTS AND MARKETS

     The Company’s principal products are natural gas and to a lesser extent crude oil. 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 properties in which it owns an interest, it relies on the operating expertise of numerous companies that operate in the areas where the Company owns interests. This expertise includes the drilling and completion of new wells, producing well operations and, in most cases, the marketing or purchasing of the well’s production. Natural gas sales are principally handled by the well operator and are normally contracted on a monthly basis with third party gas marketers and pipeline companies. Payment for 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.

     In general, prices of oil and gas are dependent on numerous factors beyond the control of the Company, such as 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 are subject to seasonal variations.

     Beginning in calendar 2007, the Company entered into hedging arrangements to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. The hedging arrangements apply to only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These hedging arrangements may expose the Company to risk of financial loss and limit the benefit of future increases in natural gas prices. A more thorough discussion of the hedging arrangements is contained in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operation”.

COMPETITIVE BUSINESS CONDITIONS

     The oil and gas industry is highly competitive, particularly in the search for new oil and gas reserves. There are many factors affecting 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 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, weather patterns and actions taken by OPEC and other oil-producing countries have dramatic influence on the price Panhandle receives for its oil and 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 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 method allows the Company to effectively compete 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 commercial quantities of oil and gas reserves is essential to the ultimate realization of value from the Company’s mineral and leasehold acreage. These mineral properties and leasehold acreage may be considered a raw material to its 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 gas leasehold acreage and, to a lesser extent, additional mineral 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 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 purchases are made from many owners, and the Company does not rely on any particular companies or individuals for these acquisitions.

MAJOR CUSTOMERS

     The Company’s oil and gas production is sold, in most cases, by the well operators to many different purchasers on a well-by-well basis. During fiscal 2008, sales through three separate operators accounted for approximately 17%, 16% and 12%, respectively, of the Company’s total oil and gas sales. Generally, if one purchaser declines to continue purchasing the Company’s oil and natural gas, 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 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 gas is produced 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 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 and production of oil and gas. These states also have regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties and the regulation of spacing, plugging and abandonment of wells. As previously discussed, the well operators are relied upon by the Company to comply with governmental regulations.

     Various aspects of the Company’s oil and 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 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 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 gas transporters. As a result of the various omnibus rulemaking proceedings in the late 1980’s and the individual pipeline restructuring proceedings of the early to mid-1990’s, 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 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 available transportation information 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. What new or different regulations FERC and other regulatory agencies may adopt or what effect subsequent regulations may have on production and marketing of natural gas from the Company’s properties 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 conditions and limitations. These regulations may tend to increase the cost of transporting oil by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved 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 provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays; however, to date the Company’s cost of compliance has been insignificant. The Company does not believe the existence of these environmental laws will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future events. 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 believes the well operators to be in compliance with existing regulations and that absent an extraordinary event any noncompliance will not have a material adverse effect on the Company. Although the Company is not fully insured against all environmental risks, insurance is maintained which is customary in the industry.

EMPLOYEES

     At September 30, 2008, Panhandle employed 18 persons on a full-time basis. Three of the employees are executive officers and the President and CEO is also a director of the Company.

RISK FACTORS

     Economic conditions worldwide and in the United States have declined in recent months having a negative effect on demand for and the price of oil and natural gas, drilling activity to explore for new reserves and availability of capital through either debt or equity markets.

     Further negative effects of the current economic downturn could be decline of reserves due to curtailed drilling activity, the risk of insolvency of well operators and oil and natural gas purchasers, limited availability of certain insurance contracts and limited access to hedging instruments.

     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.

Oil and natural gas prices are volatile. Volatility in oil and natural gas prices can adversely affect results and the price of the Company’s common stock. This volatility also makes valuation of oil and natural gas producing properties difficult and can disrupt markets.

     Oil 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:

	•		worldwide economic conditions;
	•		economic, political and regulatory developments;
	•		market uncertainty;
	•		relatively minor changes in the supply of and demand for oil and natural gas; weather conditions;
	•		import prices;
	•		political conditions in major oil producing regions, especially the Middle East and West Africa;

	•		actions taken by OPEC; and
	•		competition from alternative sources of energy.

     In recent years and months, oil and natural gas price volatility has become increasingly severe. Price volatility makes it difficult to budget and project the return on exploration and development projects and to estimate with precision the value of producing properties that are owned or acquired. In addition, unusually 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. Quarterly results of operations may fluctuate significantly as a result of, among other things, variations in oil and natural gas prices and production performance.

A substantial or extended decline in oil and natural gas prices would have a material adverse effect on the Company.

     A substantial or extended decline in oil and natural gas prices 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 negative effect in several ways, including:

	•		cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production;
	•		certain reserves may no longer be economic to produce, leading to both lower proved reserves and cash flow; and
	•		access to sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable.

The Company’s hedging activities may reduce the realized prices received for oil and natural gas sales.

     In order to manage exposure to price volatility in our natural gas, we enter into natural gas price risk management arrangements (costless collars) for a portion of our expected production. Commodity price hedging may limit the prices we actually realize and therefore reduce oil and natural gas revenues in the future. The fair value of our natural gas derivative instruments outstanding as of September 30, 2008 was an asset of $646,193.

Lower oil and natural gas prices may cause impairment charges.

     The Company has elected to utilize the successful efforts method of accounting for its oil and 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 as oil and gas is produced.

     All long-lived assets, principally the Company’s oil and gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its future net cash flows. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil and gas reserves. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. 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 oil and natural gas prices, future production levels, and operating and development costs. In estimating our level of oil and natural gas reserves, we and our consulting petroleum engineering firm make certain assumptions that may prove to be incorrect, including 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 prices and costs in effect as of the date of estimation, less future development, production and income tax expenses, and 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.

   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. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate.

   The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas 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 of Financial Accounting Standards (“SFAS”) No. 69, “Disclosures about Oil and Gas Producing Activities”, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us 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 successful exploration and development drilling, successfully applies new technologies or identifies additional behind-pipe zones or secondary recovery reserves. Future oil and natural gas production is therefore highly dependent upon the level of success in acquiring or finding additional reserves. The above activities are conducted with well operators, as the Company does not operate any of its wells.

     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 net 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 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 or may be produced economically.

     The ultimate cost of drilling, completing and operating a well is controlled by well operators and cost factors can adversely affect the economics of any project. 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 potentially the expected sales price to be received for oil or 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 and the drilling of oil and natural gas wells, including well blowouts, cratering and explosions, pipe failures, fires, abnormal pressures, uncontrollable flows of oil, 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 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 upon the Company’s financial results.

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 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 success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond the Company’s control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of technology.

Shortages of oil field 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 and other 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.

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 other independent oil and natural gas companies in each of the following areas:

	•		seeking to acquire desirable producing properties or new properties for future exploration; and
	•		seeking to acquire the equipment and expertise necessary to develop and operate properties.

     Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies are able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully join in drilling with operators, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

ITEM 1B UNRESOLVED STAFF COMMENTS

     None

ITEM 2 PROPERTIES

     At September 30, 2008, Panhandle’s principal properties consisted of perpetual ownership of 254,661 net mineral acres, held principally in tracts in Oklahoma, New Mexico, Texas and nine other states. The Company also held leases on 21,458 net acres of minerals primarily in Oklahoma. At September 30, 2008, Panhandle held royalty and/or working interests in 4,593 producing oil or gas wells, and 74 wells in the process of being drilled or completed.

     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, few challenges have been made against the Company’s fee title to its properties.

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

ACREAGE

     Mineral Interests Owned

     The following table of mineral interests owned reflects, at September 30, 2008, 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).

																		Net				Gross
										Net				Gross				Acres				Acres				Net				Gross
										Acres				Acres				Leased				Leased				Acres				Acres
		Net				Gross				Producing				Producing				to Others				to Others				Open				Open
State		Acres				Acres				(1)				(1)				(2)				(2)				(3)				(3)
Arkansas			10,030				45,034				2,216				7,498				7,649				37,063				165				473
Colorado			8,326				39,299				109				219												8,217				39,080
Florida			5,589				12,239																				5,589				12,239
Kansas			3,082				11,816				152				1,280												2,930				10,536
Montana			1,007				17,947												11				1,599				996				16,348
North Dakota			11,179				64,286																				11,179				64,286
New Mexico			57,396				174,460				1,352				7,125				380				480				55,664				166,855
Oklahoma			113,004				939,456				34,870				280,333				1,850				18,832				76,284				640,291
South Dakota			1,825				9,300																				1,825				9,300
Texas			43,179				361,445				7,268				68,795				358				4,717				35,553				287,933
OTHER			44				279																				44				279
Total:			254,661				1,675,561				45,967				365,250				10,248				62,691				198,446				1,247,620

     Leases

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

																						Net Acres
		Net																				Held by
State		Acres				Net Lease Acres Expiring																Production
						2009				2010				2011				2012
Kansas			2,117																				2,117
Oklahoma			17,457				314				1,836				1,884				25				13,397
Texas			483				12				32												439
Other			1,401				29																1,373
TOTAL			21,458				355				1,868				1,884				25				17,326

PROVED RESERVES

     The following table summarizes estimates of proved reserves of oil and gas held by Panhandle. All reserves are located within the United States and are principally made up of small interests in approximately 4,600 individual wells. Because the Company’s non-producing mineral and leasehold interests consist of various small interests in numerous tracts located primarily in Oklahoma, New Mexico and Texas and because the Company is a non-operator and must rely on third parties to propose and drill and operate producing wells, it is not feasible or possible to provide estimates of all proved undeveloped reserves and associated future net revenues. The Company is currently providing proved undeveloped reserve estimates for wells that it has a substantial reason to believe will be drilled in the very near term. In most cases, this means the Company has received some type of notice from the operator that a well will be drilled. All of the Company’s reserve quantity estimates for 2008, 2007 and 2006 were prepared by the Company’s consulting petroleum engineering firm. Other than this report, the Company’s reserve estimates are not filed with any other federal agency.

		Barrels of Oil				Mcf of Gas
Proved Developed Reserves
September 30, 2008			895,430				35,970,450
September 30, 2007			754,866				31,016,304
September 30, 2006			566,110				25,322,756
Proved Undeveloped Reserves
September 30, 2008			94,530				12,180,220
September 30, 2007			67,958				5,989,487
September 30, 2006			9,081				5,547,083
Total Proved Reserves
September 30, 2008			989,960				48,150,670
September 30, 2007			822,824				37,005,791
September 30, 2006			575,191				30,869,839

     These reserves exclude approximately 1.6 to 2.8 Bcf of CO2 gas reserves for the years presented.

     Because the determination of reserves is a function of testing, evaluating, developing oil and gas reservoirs and establishing a production decline history, along with product price fluctuations, estimates will change as future information concerning individual reservoirs is developed and as market conditions change. Estimated reserve quantities and future net revenues are affected by changes in product prices, and these prices have varied substantially in recent years and are expected to vary substantially from current pricing in the future. Proved developed reserves are those expected to be recovered through existing well bores under existing economic and operating conditions. Proved undeveloped reserves are reserves that may be recovered from undrilled acreage or units, but are limited to those sites directly offsetting established production units, have sufficient geological data to indicate a reasonable expectation of commercial success and the Company has reason to believe will be drilled in the very near term.

ESTIMATED FUTURE NET CASH FLOWS

     Set forth below are estimated future net cash flows with respect to Panhandle’s proved reserves (based on the estimated units set forth in the immediately preceding table) for the fiscal year indicated, and the present value of such estimated future net cash flows, computed by applying a 10% discount factor as required by the rules and regulations of the SEC. Estimated future net cash flows have been computed by applying current prices at September 30 of each year to future production of proved reserves less estimated future expenditures to be incurred with respect to the development and production of such reserves. This pricing is based on SEC regulations. No federal or state income taxes are included in estimated costs. However, the amounts are net of operating costs and production taxes levied by the respective states. Prices used for determining future cash flows from oil and natural gas as of September 30, 2008, 2007, 2006 were as follows: 2008 - $97.74/Bbl, $4.51/Mcf; 2007 — $78.93/Bbl, $5.50/Mcf; 2006 — $60.50/Bbl, $3.49/Mcf. These future net cash flows 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 gas price and production cost increases or decreases.

Estimated Future Net Cash Flows

		9-30-08				9-30-07				9-30-06
Proved Developed		$	182,996,389			$	173,797,222			$	93,565,124
Proved Undeveloped			31,863,340				23,046,080				10,734,504
Income Tax Expense			67,278,008				60,887,878				24,394,272
Total Proved		$	147,581,721			$	135,955,424			$	79,905,356

10% Discounted Present Value of Estimated Future Net Cash Flows

		9-30-08				9-30-07				9-30-06
Proved Developed		$	104,840,854			$	102,583,540			$	62,007,929
Proved Undeveloped			15,068,040				13,178,660				5,716,092
Income Tax Expense			41,896,610				39,068,713				16,532,454
Total Proved		$	78,012,284			$	76,693,487			$	51,191,567

     The future net cash flows are net of immaterial amounts of future cash flow to be received from CO2 reserves.

OIL AND GAS PRODUCTION

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

		Year Ended				Year Ended				Year Ended
		9-30-08				9-30-07				9-30-06
Bbls — Oil			132,402				107,344				97,139
Mcf — Gas			6,928,038				5,147,343				4,299,142
Mcfe			7,722,450				5,791,407				4,881,976

     Gas production includes 193,408, 175,175 and 192,957 Mcf of CO2 sold at average prices of $.86, $.61 and $.65 per Mcf for the years ended September 30, 2008, 2007 and 2006, respectively.

AVERAGE SALES PRICES AND PRODUCTION COSTS

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

		Year Ended				Year Ended				Year Ended
		9-30-08				9-30-07				9-30-06
Average Sales Price
Per Bbl, Oil		$	103.91			$	62.81			$	63.44
Per Mcf, Gas		$	7.98			$	5.97			$	6.94
Per Mcfe		$	8.94			$	6.47			$	7.38
Average Production (lifting costs)
(Per Mcfe of Gas)
(1)		$	0.86			$	0.63			$	0.63
(2)			0.44				0.42				0.45
		$	1.30			$	1.05			$	1.08

     Approximately 25% of the Company’s oil and gas revenue is generated from royalty interests in approximately 4,200 wells. 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 gas wells as of September 30, 2008. Panhandle owns fractional royalty interests or fractional working interests in these wells. The Company does not operate any wells.

		Gross Wells				Net Wells
Oil			958				19.79
Gas			3,635				85.50
Total			4,593				105.29

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

     As of September 30, 2008, Panhandle owned 365,250 gross developed mineral acres and 45,967 net developed mineral acres. Panhandle has also leased from others 154,982 gross developed acres, which contain 17,326 net developed acres.

UNDEVELOPED ACREAGE

     As of September 30, 2008, Panhandle owned 1,310,311 gross and 208,694 net undeveloped mineral acres, and leases on 31,316 gross and 4,132 net acres.

DRILLING ACTIVITY

     The following net productive development and exploratory wells and net dry development and exploratory wells in which the Company had a fractional royalty or working interest were drilled and completed during the fiscal years indicated. Also shown are the net wells purchased during these periods.

		Net Productive Wells				Net Dry Wells
Development Wells
Fiscal year ended September 30, 2006			5.477069				0.139168
Fiscal year ended September 30, 2007			6.215883				0.025393
Fiscal year ended September 30, 2008			8.120236				0.067177
Exploratory Wells
Fiscal year ended September 30, 2006			0.747225				0.159593
Fiscal year ended September 30, 2007			1.539561				0.137873
Fiscal year ended September 30, 2008			0.985659				0.083333
Purchased Wells
Fiscal year ended September 30, 2006			— 0 —				— 0 —
Fiscal year ended September 30, 2007			— 0 —				— 0 —
Fiscal year ended September 30, 2008			— 0 —				— 0 —

PRESENT ACTIVITIES

     The following table sets forth the gross and net oil and gas wells drilling or testing as of September 30, 2008, in which Panhandle owns a royalty or working interest. These wells were not yet producing at September 30, 2008.

		Gross Wells				Net Wells
Oil			3				0.02719
Gas			71				5.15100

OTHER FACILITIES

     The Company leases 12,369 square feet of office space in Oklahoma City, OK. The lease obligation ends in fiscal 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, contain, 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 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 after the date of this report which reflect the occurrence of unanticipated events.

     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 consolidated results for 2009 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 heavily 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 extremely 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, at times, has 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.

     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 estimated discounted future net cash flows from proved oil and natural gas reserves are determined based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Actual future net cash flows are also affected, in part, by the amount and timing of oil and natural gas production, supply and demand for oil and natural gas and increases or decreases in consumption.

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

ITEM 3 LEGAL PROCEEDINGS

     There were no material legal proceedings involving Panhandle or Wood Oil as of the date of this report.

ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     No matters were submitted to a vote of Panhandle’s security holders during the fourth quarter of the fiscal year ended September 30, 2008.

PART II

ITEM 5 MARKET FOR REGISTRANTS’ COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     The above graph compares the cumulative 5-year total return provided shareholders on Panhandle Oil and Gas Inc.’s 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, 2003 and its relative performance is tracked through September 30, 2008.

     On July 22, 2008, the Company’s Class A Common Stock (“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:

Quarter Ended		High				Low
December 31, 2006		$	19.75			$	17.25
March 31, 2007		$	20.68			$	17.80
June 30, 2007		$	28.80			$	19.70
September 30, 2007		$	28.60			$	20.18
December 31, 2007		$	28.41			$	23.75
March 31, 2008		$	31.69			$	24.75
June 30, 2008		$	39.90			$	27.25
September 30, 2008		$	39.98			$	23.91

     As of December 1, 2008, there were 1,798 holders of record of Panhandle’s Class A Common Stock and approximately 3,000 beneficial owners.

     During the past two years, cash dividends have been declared and paid as follows on the Class A Common Stock:

Date		Rate Per Share
December 2006		$	0.04
March 2007		$	0.07
June 2007		$	0.07
September 2007		$	0.07
December 2007		$	0.07
March 2008		$	0.07
June 2008		$	0.07
September 2008		$	0.07

     While the Company expects to continue to pay dividends on its common stock, the payment 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 current line of credit loan agreement also contains a provision limiting the paying or declaring of a cash dividend to twenty percent of net cash flow provided by operating activities from the Consolidated Statement of Cash Flows of the preceding twelve-month period. See Note 4. to the consolidated financial statements contained herein at Item 8 — “Financial Statements”, for a further discussion of the loan agreement.

ISSUER PURCHASES OF EQUITY SECURITIES

										Total Number of				Approximate Dollar
		Total Number				Average				Shares Purchased				Value of Shares that
		of Shares				Price Paid				as Part of Publicly				May Yet Be Purchased
Period		Purchased				per Share				Announced Program				Under the Program
6/1 - 6/30/08			54,514			$	35.88				54,514			$	44,239
7/1 - 7/31/08			1,300			$	33.44				1,300			$	3,000,772
8/1 - 8/31/08			61,000			$	37.51				61,000			$	712,722
9/1 - 9/30/08			22,200			$	32.06				22,200			$	0

     On May 28, 2008 and July 29, 2008 the Company announced that its Board of Directors had approved stock repurchase programs to purchase up to $2,000,000 and $3,000,000 (respectively) of the Company’s common stock. The shares are held in treasury and are accounted for using the cost method. As of September 30, 2008, 7,640 treasury shares were contributed to the Company’s ESOP on behalf of the ESOP participants.

ITEM 6 SELECTED FINANCIAL DATA

     The following table summarizes consolidated financial data of the Company and should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements of the Company, including the Notes thereto, included elsewhere in this report.

		Year Ended September 30,
		2008				2007				2006				2005				2004
Revenues
Oil and gas sales		$	69,026,785			$	37,449,174			$	36,008,527			$	30,242,210			$	23,578,615
Lease bonuses and rentals			167,559				208,625				410,984				2,214,992				115,938
Interest and other			(75,223	)			1,471,112				1,066,169				1,140,973				912,056
			69,119,121				39,128,911				37,485,680				33,598,175				24,606,609
Costs and Expenses
Lease oper. exp and prod. taxes			10,055,762				6,057,456				5,262,834				4,802,595				4,098,124
Exploration costs (A)			455,943				1,050,069				222,892				784,741				236,939
Depr. depl. and amortization			19,784,660				15,291,625				10,142,367				7,506,571				6,115,500
Provision for impairment			526,380				3,761,832				3,009,953				232,295				841,687
Loss on sales of assets			204,189				254,395				119,282				291,452				—
Gen. and administrative			5,006,512				3,877,492				3,335,899				4,545,208				3,033,437
Bad debt expense			591,258				—				—				—				—
Interest expense			44,346				133,578				232,234				359,527				488,097
			36,669,050				30,426,447				22,325,461				18,522,389				14,813,784
Income before provision for income taxes			32,450,071				8,702,464				15,160,219				15,075,786				9,792,825
Provision for income taxes			10,894,302				2,359,000				4,586,000				4,591,000				3,063,000
Net income		$	21,555,769			$	6,343,464			$	10,574,219			$	10,484,786			$	6,729,825
Basic Earnings per share		$	2.54			$	0.75			$	1.25			$	1.25			$	0.80
Diluted Earnings per share		$	2.54			$	0.75			$	1.25			$	1.24			$	0.80
Dividends Declared per share		$	0.28			$	0.25			$	0.185			$	0.125			$	0.09
Weighted Average Shares Outstanding (B)
Basic			8,492,378				8,499,233				8,479,406				8,390,280				8,357,566
Diluted			8,492,378				8,499,233				8,479,406				8,450,238				8,457,602
Net cash provided by (used in):
Operating activities		$	39,924,719			$	28,106,500			$	23,470,145			$	17,909,249			$	15,583,362
Investing activities		$	(37,706,995	)		$	(26,940,679	)		$	(21,118,606	)		$	(10,514,096	)		$	(10,631,869	)
Financing activities		$	(2,311,376	)		$	(610,814	)		$	(3,556,019	)		$	(6,398,663	)		$	(4,902,156	)
Total assets		$	122,007,183			$	78,539,797			$	70,949,242			$	61,241,692			$	54,186,362
Long-term debt		$	9,704,100			$	4,661,471			$	1,166,649			$	3,166,653			$	8,516,657
Shareholders’ equity		$	68,348,901			$	53,681,371			$	49,065,697			$	38,635,350			$	28,700,515

All share and per share amounts are adjusted for the effects of 2-for-1 stock splits, effective in January 2006 and in April 2004.

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

RESULTS OF OPERATIONS

     General

     The Company’s principal line of business is the production and sale of oil and natural gas. Results of operations are dependent upon the quantity of production and the price obtained for such production. Prices received by the Company for the sale of its oil and natural gas have fluctuated significantly from period to period. These fluctuations affect the Company’s ability to maintain or increase its production from existing oil and gas properties and to explore, develop or acquire new properties. As the Company is a non-operator it relies on operating companies to drill, complete and place on production new wells. The Company anticipates increased production for fiscal year 2009 as 63 working interest wells were drilling or testing as of September 30, 2008 with production from these wells expected to begin in fiscal 2009. The Company owned an average 8% working interest in these wells with working interests ranging from less than 1% to 42.8%. Although capital expenditures increased significantly in fiscal years 2008 and 2007, the announcement of capital expenditure cutbacks by many operating companies may reduce the Company’s capital expenditures in fiscal year 2009. Therefore, the Company currently anticipates a modest decrease in capital expenditures for fiscal year 2009 as compared to fiscal year 2008. This potentially could reduce production in future years as the number of new wells coming on line would not continue to increase.

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

		For the Year Ended September 30,
						Percent								Percent
		2008				Incr. or (Decr.)				2007				Incr. or (Decr.)				2006
Production:
Oil (Bbls)			132,402				23	%			107,344				11	%			97,139
Gas (Mcf)			6,928,038				35	%			5,147,343				20	%			4,299,142
Mcfe			7,722,450				33	%			5,791,407				19	%			4,881,976
Average Sales Price:
Oil (per Bbl)		$	103.91				65	%		$	62.81				(1	%)		$	63.44
Gas (per Mcf)		$	7.98				34	%		$	5.97				(14	%)		$	6.94
Mcfe		$	8.94				38	%		$	6.47				(12	%)		$	7.38

     Fiscal Year 2008 Compared to Fiscal Year 2007

     Overview

     The Company recorded net income of $21,555,769 in 2008, compared to net income of $6,343,464 in 2007. Total revenues were significantly higher in 2008 as a result of increases in both oil and natural gas production and prices in 2008 as compared to 2007. The increase in revenue was partially offset by increases in 2008 as compared to 2007 in the following expense categories: lease operating expense; production taxes; depreciation, depletion and amortization; general and administrative

expense; and provision for income taxes. Provision for impairment experienced a significant decrease in 2008 as compared to 2007.

     Revenues

     Total revenues increased $29,990,210 or 77% for 2008 as compared to 2007. The increase was the result of a $31,577,611 increase in oil and natural gas sales, partially offset by losses related to natural gas collar contracts of $1,706,139, which is the result of high natural gas prices from March, 2008 through July, 2008 which exceeded the ceilings of the natural gas collar contracts. Oil and natural gas sales increases were due to an overall 33% increase in mcfe production, a 65% increase in oil prices and a 34% increase in natural gas prices. Fiscal 2008 capital expenditures, net wells drilled and completed and, accordingly, oil and natural gas production increased, as compared to fiscal 2007. The major areas in which new wells significant to the Company have been drilled and completed are the Woodford Shale in southeast Oklahoma, the Fayetteville Shale in Arkansas and the Dill City and Yellowstone Southeast prospects in western Oklahoma. The Company plans to continue to maximize its working interest participation on most wells to be drilled during fiscal 2009; although, the Company’s total number of wells to be drilled in fiscal 2009 in which it has a working interest is expected to decline. The result expected is a flat to modest increase in oil and natural gas production for fiscal 2009 as compared to fiscal 2008.

     Production by quarter for 2008 was as follows:

First quarter			1,831,206			mcfe
Second quarter			1,727,757			mcfe
Third quarter			1,979,904			mcfe
Fourth quarter			2,183,583			mcfe
Total			7,722,450			mcfe

     (Losses) Gains on Natural Gas Collar Contracts

     Realized and unrealized gains and losses are scheduled below:

(Losses) gains on		Fiscal year
derivative contracts		2008				2007
Realized		$	(1,480,100	)		$	658,400
Unrealized			539,277				106,916
Total		$	(940,823	)		$	765,316

     The Company made payments of $1,480,100 under the contracts in 2008 as compared to receiving cash payments of $658,400 in 2007. The Company’s fair value of derivative contracts was an asset of $646,193 as of September 30, 2008 as compared to an asset of $106,916 as of September 30, 2007.

     Lease Operating Expenses and Production Taxes (LOE)

     LOE increased $2,961,627 or 81% in 2008. LOE costs per mcfe of production increased from $.63 in 2007 to $.86 in 2008. This $.23 per mcfe increase is the result of significant increases in costs related to the transporting, compressing and marketing of natural gas. These increases account for approximately $1.9 million of the overall LOE increase and have been experienced primarily in the Woodford Shale area in southeast Oklahoma and the Dill City prospect in western Oklahoma. The remaining LOE increase of approximately $1.1 million is the result of the increased number of net wells

owned that began producing in 2008 (new wells generally experience higher operating costs during the first year of production) combined with continued increases in costs of field personnel, fuel and materials on wells existing prior to 2008.

     Production taxes increased $1,036,679 or 43% in 2008. The increase is primarily the result of significantly higher oil and natural gas sales in 2008, as production taxes are paid as a percentage of sales. The increase is not proportional to the sales increase due to new wells coming on line in Arkansas which has a low production tax rate and production tax credits that the Company is entitled to on production from horizontally drilled wells in Oklahoma (primarily from the Woodford Shale area in southeast Oklahoma). These production tax credits totaled approximately $467,000 in 2008.

     Exploration Costs

     Exploration costs decreased $594,126 in 2008 as compared to 2007. This decrease is the result of a $467,868 exploratory dry hole drilled in 2007 in Louisiana. No exploratory dry holes were drilled in 2008. Since the Company utilizes the successful efforts method of accounting for oil and natural gas operations, only exploratory dry holes result in their costs being charged to exploration costs. Charges to exploration costs for expired or abandoned leasehold costs also decreased approximately $101,000 in 2008 as compared to 2007.

     Depreciation, Depletion and Amortization (DD&A)

     DD&A increased $4,493,035 or 29% in 2008 to $2.56 per mcfe as compared to $2.64 per mcfe in 2007. The overall increase is the result of increased production volumes in 2008 as compared to 2007. The decrease in the DD&A rate per mcfe is the result of higher than normal DD&A per mcfe in 2007 resulting from downward reserve revisions on approximately fifty of the Company’s working interest wells. Additional DD&A charges on those wells totaled approximately $2 million.

     Provision for Impairment

     The provision for impairment decreased $3,235,452 in 2008 as compared to 2007. Seven fields were impaired $514,180 in 2008 as compared to eight fields which were impaired $3,397,087 in 2007. In 2008 approximately $309,000 of impairment was on one field in western Oklahoma. In 2007 approximately $2 million of the impairment was on one field in western Oklahoma (unexpected declining production resulted in lower reserve estimates), approximately $476,000 was on one field in west Texas and approximately $390,000 was on one field in New Mexico.

     Loss on Sale of Assets

     Loss on sale of assets decreased $50,206 in 2008 as compared to 2007. Two low performing wells in western Oklahoma were sold in 2008 at a loss of $203,107. In 2007 several low performing wells in southeast Oklahoma were sold at a loss of $221,998.

     General and Administrative Costs (G&A)

     G&A costs increased $1,129,020 or 29% in 2008. The increase is principally the result of increased personnel costs of $749,110, increased professional fees of $149,303 and increased directors’ expenses of $89,985.

     Bad Debt Expense

     Bad debt expense increased $591,258 in 2008 as compared to 2007. 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. All of the 2008 bad debt expense of $591,258 represents the total amount owed the Company directly and indirectly, through the operators of the affected wells where SemGroup was the purchaser of oil. No bad debt expense was recorded in 2007.

     Provision for Income Taxes

     Provision for income taxes increased $8,535,302 in 2008 as compared to 2007 as a result of income before provision for income taxes increasing by $23,747,607. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate. The effective tax rate was 33.6% for 2008 and 27.1% for 2007.

     Liquidity and Capital Resources

     At September 30, 2008, the Company had positive working capital of $4,599,004 as compared to $7,191,111 at September 30, 2007. Items with positive effects on working capital include an increase in oil and gas sales receivables, net of allowance for uncollectible accounts of $9,079,878, an increase in the fair value of derivative contracts of $539,277 and an increase in refundable income taxes and other of $2,267,114. Items that had a negative effect include an increase in accounts payable of $14,124,310 and an increase in accrued liabilities of $260,414. Oil and gas sales receivable increased as a result of increased revenue. The fair value of derivative contracts increased as a result of an increase in the variance between natural gas prices and contract floors. The increase in refundable income taxes and other is the result of federal income tax estimated payments made in fiscal 2008 in excess of the actual current income tax liability for 2008. The accounts payable increase is the result of continued increases in the Company’s working interest participation in new wells drilled and an increase in the number of wells drilled. As of September 30, 2008, the Company had working interests in 63 wells that were drilling or testing. The Company’s average working interest in these wells was approximately 8% and the accounts payable for these wells as of September 30, 2008 was approximately $11.2 million. Capital expenditures increased significantly in 2008, but are currently anticipated to slightly decrease for fiscal 2009. The Company will continue its strategy of increased working interest participation in new wells drilled but capital expenditure reductions by operating companies may substantially reduce our expenditure level resulting in fewer new net wells drilled.

     Cash flows from operating activities increased 42% over last year primarily due to higher oil and gas sales, net of lease operating expenses and production taxes. Additions to properties and equipment for oil and gas activities for 2008 were $52,812,138 compared to $28,112,522 for 2007. Management currently expects additions to properties and equipment for oil and gas activities in fiscal year 2009 to decrease as compared to fiscal 2008. These expenditures will continue to be concentrated in the southeast Oklahoma Woodford Shale area, the Fayetteville Shale area in Arkansas and the Dill City prospect and other areas in western Oklahoma. Any acquisition of oil and gas properties would further increase additions to properties and equipment. As the Company does not operate any of the wells in which it participates, it is difficult to predict which or how many wells will actually be drilled in fiscal 2009 and a significant reduction in drilling by operating companies may substantially reduce the Company’s planned expenditure level.

     The Company has historically funded capital expenditures, overhead costs and dividend payments from operating cash flow and has utilized, at times, its bank revolving line-of-credit facility to help fund these expenditures. The $50,000,000 facility currently has a $15,000,000 borrowing base which, if needed, the Company believes could be expanded up to the $50,000,000 maximum. The borrowing base is set by the Company to minimize the fee on the unused portion of the borrowing base. The Company has outstanding borrowings of $9,704,100 and availability of $5,295,900 as of September 30, 2008. Based on expected natural gas production volumes and prices for fiscal 2009, the expected capital

expenditure level discussed above, and no meaningful acquisitions of oil and gas properties, additional borrowings of $5-15 million in fiscal 2009 are possible. Changes in production volumes or pricing or an acceleration or slowing down of the development in the gas resource projects would materially affect anticipated borrowings.

     Contractual Obligations

     The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan in the amount of $50,000,000 which is subject to a semi-annual borrowing base determination. The current borrowing base under the BOK Agreement is $15,000,000. The revolving loan matures on October 31, 2010. Borrowings under the revolving loan are due at maturity. The revolving loan bears interest at the BOK national prime rate minus from 1.375% to .75%, or 30 day LIBOR plus from 1.375% to 2.0%. The interest rate charged will be based on the percent of the value advanced of the calculated loan value of the Company’s oil and gas reserves. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and gas properties is advanced.

     Determinations of the borrowing base are made semi-annually or whenever BOK believes there has been a material change in the value of the Company’s oil and gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2008, the Company was in compliance with these covenants.

     The table below summarizes the Company’s contractual obligations under the BOK facility, as of September 30, 2008:

		Payments Due By Period
						Less than												More than
Contractual Obligations		Total				1 Year				1-3 Years				3-5 Years				5 Years
Long-term debt obligations		$	9,704,100			$	—			$	9,704,100			$	—			$	—

     Fiscal Year 2007 Compared to Fiscal Year 2006

     Overview

     The Company recorded net income of $6,343,464 in 2007, compared to net income of $10,574,219 in 2006. Total revenues were slightly higher in 2007 as a result of increased oil and gas sales generated by increased sales volumes of oil and natural gas in 2007 as compared to 2006. However, the revenue increases were more than offset by substantial increases in exploration costs, depreciation, depletion and amortization and provision for impairment expense in 2007 as compared to 2006.

     Revenues

     Total revenues increased $1,643,231 or 4% for 2007 as compared to 2006. The increase was the result of a $1,440,647 increase in oil and natural gas sales, a $765,316 increase in combined realized and unrealized gains on natural gas collar contracts and a $202,359 decrease in lease bonuses and rentals. Oil and natural gas sales increases were due to an overall 19% increase in mcfe production, a 1% decrease in oil prices and a 14% decrease in natural gas prices. The production increases are the result of the Company’s continued strategy of participating with higher interests in new wells, especially in the Dill City and Woodford Shale areas where significant production is now being received from several recently completed wells. Realized and unrealized gains from natural gas collar contracts in 2007 were a part of

the revenue increase. No hedging of natural gas prices had been implemented by the Company in previous years. The decrease in lease bonuses and rentals is attributed to the Company’s strategy of increasing its average working interest in wells by participating with larger portions of its mineral acreage as well proposals are received, thus leasing to third parties less.

     Production by quarter for 2007 was as follows:

First quarter			1,334,357			mcfe
Second quarter			1,305,041			mcfe
Third quarter			1,432,023			mcfe
Fourth quarter			1,719,986			mcfe
Total			5,791,407			mcfe

     Realized and Unrealized Gains on Natural Gas Collar Contracts

     As of September 30, 2007, the Company’s fair value of derivative contracts (unrealized gain) was $106,916. The Company had no derivative contracts during 2006. The Company received cash payments (realized gains) in 2007 of $658,400 under the contracts.

     Lease Operating Expenses and Production Taxes (LOE)

     LOE increased $614,072 or 20% in 2007. The increase is a result of the increased number of larger ownership wells going on line in 2007, (new wells normally have higher operating costs the first several months of production) and the continuing increase in the overall number of wells in which the Company has an interest. LOE costs per mcfe of production were $.63 in both 2007 and 2006.

     Production taxes increased $180,550 or 8% in 2007. The increase is the result of the higher oil and gas revenues in 2007, as production taxes are paid as a percentage of these revenues.

     Exploration Costs

     Exploration costs increased $827,177 in 2007 as compared to 2006. This increase is principally the result of a $467,868 exploratory dry hole drilled in 2007 as compared to a $143,264 exploratory dry hole drilled in 2006. Since the Company utilizes the successful efforts method of accounting for oil and gas operations, only exploratory dry holes result in their costs being charged to exploration costs. Also, the Company charges to exploration costs leasehold deemed worthless or leasehold for which the lease term has expired. Leasehold charged to exploration costs was higher in 2007 as compared to 2006 by $479,420.

     Depreciation, Depletion and Amortization (DD&A)

     DD&A increased $5,149,258 or 51% in 2007 to $2.64 per mcfe as compared to $2.08 per mcfe in 2006. Reductions in the estimate of remaining reserves on several properties, large increases in drilling expenditures during 2006 and 2007 due to the Company’s participation with higher ownership interests in new wells and high initial production on these newly drilled wells resulted in this increase. On 34 of the Company’s over 1,250 working interest wells, reserve evaluations were reduced by the Company’s consulting engineer resulting in approximately $2 million of additional DD&A charges in 2007 as compared to 2006. DD&A on 16 significant new wells that began producing in 2007 accounted for another $1.3 million of the DD&A increase. The continued increase in drilling expenditures which has added significantly to the depreciable base of the Company’s properties combined with the higher initial production received from these same properties (thus accelerating the depreciation taken) accounts for the remainder of the increase.

     Provision for Impairment

     The provision for impairment increased $751,879 in 2007 as compared to 2006. One large western Oklahoma field which was impaired by approximately $1.9 million in 2006 was again impaired in 2007 by approximately $2.0 million as production, and thus ultimate reserves, from the wells in this field continued to decline at a faster rate than anticipated. The impairment of a Chaves County, New Mexico field for approximately $402,000, a Winkler County, Texas field for approximately $478,000 and a Beckham County, Oklahoma field for approximately $214,000 comprised most of the remaining 2007 impairment provision.

     Loss on Sale of Assets

     Loss on sale of assets increased $135,113 in 2007 as compared to 2006. Several low performing properties in southeast Oklahoma were sold in 2007 at a loss of $221,998. In 2006, one property was sold at a loss of $94,275. Other insignificant sales accounted for the remainder of the charges in both 2007 and 2006.

     General and Administrative Costs (G&A)

     G&A costs increased $541,593 or 16% in 2007. Increases of approximately $290,000 of directors’ expense, $147,000 of salary and benefit related costs, $76,000 of consulting costs and $20,000 of legal costs account for the majority of the overall increase in G&A costs. Of the directors’ expense increase, approximately $288,000 relates to an amendment to the Directors’ Deferred Compensation Plan (the Plan) that was effective October 19, 2005. The Plan was amended so that on retirement, termination or death of the director or on a change in control of the Company, the shares accrued under the Plan will be issued to the director. No shares are issued to a director until the occurrence of one of these events. This amendment removed the “conversion to cash” option previously available under the Plan, thus eliminating the requirement (after October 19, 2005) that the deferred compensation accounts be adjusted for changes in the market value of the Company’s common stock. The adjustment of the deferred compensation liability to market value of the shares at the closing price on October 19, 2005 resulted in a credit to G&A of approximately $288,000. After the October 19, 2005 adjustment, the deferred compensation liability was reclassified to stockholders’ equity.

     Provision for Income Taxes

     Provision for income taxes decreased $2,227,000 in 2007 as compared to 2006 as a result of income before provision for income tax decreasing by $6,457,755. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate. The effective tax rate was 27.1% for 2007 and 30.3% for 2006.

CRITICAL ACCOUNTING POLICIES

     Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change the Company’s reported cash flows or liquidity. Generally, accounting rules do not involve a selection among alternatives, but involve a selection of the appropriate policies for applying the basic principles. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to the Company.

     The more significant reporting areas impacted by management’s judgments and estimates are

crude oil and natural gas reserve estimation, impairment of assets, oil and gas sales revenue accruals and tax accruals. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. The oil and gas sales revenue accrual is particularly subject to estimates due to the Company’s status as a non-operator of its oil and gas properties. Production information obtained from well operators by the Company is delayed. This causes the estimation of recent production, used in the oil and gas revenue accrual, to be subject to some variations.

     Oil and Gas Reserves

     Of these judgments and estimates, management considers the estimation of crude oil and nature gas reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. Changes in crude oil and natural gas reserve estimates affect the Company’s calculation of depreciation, depletion and amortization, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a limited scope semi-annual update, the Company’s consulting engineer (the Company employed a new consulting engineer beginning with the March 31, 2007 semi-annual update), with assistance from Company geologists, prepares estimates of crude oil and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. As required by the guidelines and definitions established by the SEC, these estimates are based on current crude oil and natural gas pricing. Crude oil and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future crude oil and natural gas pricing assumptions are used by management to prepare estimates of crude oil and natural gas reserves used in formulating management’s overall operating decisions in the exploration and production segment.

     Hedging

     The Company periodically utilizes commodity price instruments, costless collars, to reduce its exposure to unfavorable changes in natural gas prices. Volumes under such contracts are a portion of expected production. The Company’s collars contain a fixed floor price and a fixed ceiling price. If market prices exceed the ceiling price or fall below the floor, then the Company will receive the difference between the floor and market price or pay the difference between the ceiling and market price. If market prices are between the ceiling and the floor, then no payments or receipts related to the collars are required.

     The Company accounts for its derivative contracts under Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (SFAS No. 133). Under the provision of SFAS No. 133, the Company is required to recognize all derivative instruments as either assets or liabilities in the consolidated balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is required to be measured at least quarterly based on relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. For derivative instruments not designated as hedging instruments, the change in fair value is recognized in earnings during the period of change as a change in derivative fair value. Amounts recorded in unrealized gains (losses) on derivative activities do not represent cash gains or losses. Rather, these amounts are temporary valuation swings in contracts that are not entitled to receive

hedge accounting treatment.

     Successful Efforts Method of Accounting

     The Company has elected to utilize the successful efforts method of accounting for its oil and 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 developmental dry holes are capitalized and amortized by property using the unit-of-production method as oil and gas is produced. This accounting method may yield significantly different operating results than the full cost method.

     Impairment of Assets

     All long-lived assets, principally oil and gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil and gas, future production costs, estimates of future oil and gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil and gas reserves. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.

     Oil and Gas Sales Revenue Accrual

     The Company does not operate any of its oil and gas properties, and it primarily holds small interests in approximately 4,600 wells. Thus, obtaining timely production data from the well operators is extremely difficult. This requires the Company to utilize past production receipts and estimated sales price information to estimate its oil and gas sales revenue accrual at the end of each quarterly period. The oil and gas accrual can be impacted by many variables, including initial high production rates of new wells and subsequent rapid decline rates of those wells and rapidly changing market prices for natural gas. This could lead to an over or under accrual of oil and gas sales at the end of any particular quarter. Based on past history, the estimated accrual has been materially accurate.

     Income Taxes

     The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax laws, regulations and interpretations.

     On October 1, 2007, the Company adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company and its subsidiary file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2004.

     The Company has performed its evaluation of tax positions and has determined that the adoption of FIN 48 did not have a material impact on the Company’s financial condition, results of operations, or cash flows. This evaluation included a review of the appropriate recognition threshold for each tax position recognized in the Company’s financial statements. Based on this evaluation, the Company did not identify any tax positions that did not meet the “highly certain positions” threshold. As a result, no additional tax expense, interest, or penalties have been accrued as a result of the review.

     The Company includes interest assessed by the taxing authorities in “Interest expense” and penalties related to income taxes in “General and administrative expense” on its Consolidated Statements of Income. For the years ended September 30, 2008 and 2007, the Company recorded no interest or penalties on uncertain tax positions.

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

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The Company’s results of operations and operating cash flows can be significantly impacted by changes in market prices for oil and gas. Based on the Company’s 2008 production, a $.10 per Mcf change in the price received for natural gas production would result in a corresponding $693,000 annual change in pre-tax operating cash flow. A $1.00 per barrel change in the price received for oil production would result in a corresponding $132,000 annual change in pre-tax operating cash flow. Cash flows could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities. The revolving loan bears interest at the national prime rate minus from 1.375% to .75%, or 30 day LIBOR plus from 1.375% to 2.0%. At September 30, 2008, the Company had $9,704,100 outstanding under these facilities. A change of .5% in the prime rate or on LIBOR would result in a change to interest expense of $48,521.

     The Company periodically utilizes certain commodity price instruments, costless collars, to reduce its exposure to unfavorable changes in natural gas prices. Volumes under such contracts are a portion of expected production. The Company’s collars contain a fixed floor price and a fixed ceiling price. If market prices exceed the ceiling price or fall below the floor, then the Company will receive the difference between the floor and market price or pay the difference between the ceiling and market price. If market prices are between the ceiling and the floor, then no payments or receipts related to the collars are required.

     Beginning in fiscal year 2007, the Company has entered in costless collar arrangements intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These economic hedging arrangements may expose the Company to risk of financial loss and limit the benefit of future increases in prices. The derivative instruments will settle based on the prices below which are basis adjusted and tied to certain pipelines in Oklahoma.

Derivative contracts in place during fiscal 2007 and 2008

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

Production volume

Floor price range

Ceiling price range

Contract period

covered per month

(per mmbtu)

(per mmbtu)

January — December, 2007 (1)

100,000 mmbtu

$

6.00

$

9.20 to $10.20

January — March, 2008 (2)

120,000 mmbtu

$

6.55 to $6.60

$

8.80 to $9.10

April — September, 2008 (2)

120,000 mmbtu

$

6.15 to $6.40

$

8.05 to $8.60

April — September, 2008 (2)

90,000 mmbtu

$

6.60 to $6.85

$

7.50 to $7.80

April — September, 2008 (2)

30,000 mmbtu

$

7.20 to $7.45

$

8.15 to $8.45

October — December, 2008 (2)

120,000 mmbtu

$

6.50 to $6.90

$

8.75 to $9.15

          While the Company believes that its derivative contracts are effective in achieving the risk management objective for which they were intended, the Company has elected not to complete all of the documentation requirements necessary under SFAS No. 133 to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was $646,193 and $106,916 as of September 30, 2008 and 2007, respectively. Realized and unrealized gains and losses are scheduled below:

(Losses) gains on		Fiscal year
derivative contracts		2008				2007
Realized		$	(1,480,100	)		$	658,400
Unrealized			539,277				106,916
Total		$	(940,823	)		$	765,316

ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting			32
Report of Registered Public Accounting Firm on Internal Control Over Financial Reporting			33
Report of Independent Registered Public Accounting Firm			34
Consolidated Balance Sheets As of September 30, 2008 and 2007			35-36
Consolidated Statements of Income for the Years Ended September 30, 2008, 2007 and 2006			37
Consolidated Statements of Stockholders’ Equity for the Years Ended September 30, 2008, 2007 and 2006			38
Consolidated Statements of Cash Flows for the Years Ended September 30, 2008, 2007 and 2006			39-40
Notes to Consolidated Financial Statements			41-55

Management’s Annual Report on Internal Control Over Financial Reporting

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

	•		Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;
	•		Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
	•		Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

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

     The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2008. In making this assessment, the Company’s management used the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, management has concluded that, as of September 30, 2008, the Company’s internal control over financial reporting was effective based on those criteria.

Report of Independent Registered Public Accounting Firm

on Internal Control Over Financial Reporting

The Board of Directors and Stockholders of
Panhandle Oil and Gas Inc.

We have audited Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Panhandle Oil and Gas Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, Panhandle Oil and Gas Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2008, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Panhandle Oil and Gas Inc. as of September 30, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2008 and our report dated December 5, 2008 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma
December 5, 2008

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of
Panhandle Oil and Gas Inc.

We have audited the accompanying consolidated balance sheets of Panhandle Oil and Gas Inc. (the Company) as of September 30, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Panhandle Oil and Gas Inc. at September 30, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2008, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 5, 2008, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma
December 5, 2008

Panhandle Oil and Gas Inc.

Consolidated Balance Sheets

		September 30,
		2008				2007
Assets
Current Assets:
Cash and cash equivalents		$	895,708			$	989,360
Oil and gas sales receivables, net of allowance for uncollectible accounts			17,183,128				8,103,250
Fair value of derivative contracts			646,193				106,916
Refundable income taxes and other			2,379,996				112,882
Total current assets			21,105,025				9,312,408
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and gas properties			175,727,196				125,634,251
Non-producing oil and gas properties			11,216,103				10,697,854
Furniture and fixtures			491,321				625,455
			187,434,620				136,957,560
Less accumulated depreciation, depletion, and amortization			87,661,433				68,424,645
Net properties and equipment			99,773,187				68,532,915
Investments			736,314				690,011
Other			392,657				4,463
Total assets		$	122,007,183			$	78,539,797

(Continued on next page)

See accompanying notes.

Panhandle Oil and Gas Inc.
Consolidated Balance Sheets

		September 30,
		2008				2007
Liabilities and Stockholders’ Equity
Current Liabilities:
Accounts payable		$	15,897,565			$	1,773,255
Accrued liabilities			608,456				348,042
Total current liabilities			16,506,021				2,121,297
Long-term debt			9,704,100				4,661,471
Deferred income taxes			25,943,750				16,827,750
Asset retirement obligations			1,504,411				1,247,908
Stockholders’ equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at September 30, 2008 and at September 30, 2007			140,524				140,524
Capital in excess of par value			2,090,070				2,146,071
Deferred directors’ compensation			1,605,811				1,358,778
Retained earnings			69,236,604				50,035,998
			73,073,009				53,681,371
Treasury stock, at cost; 131,374 shares at September 30, 2008 and no shares at September 30, 2007			(4,724,108	)			—
Total stockholders’ equity			68,348,901				53,681,371
Total liabilities and stockholders’ equity		$	122,007,183			$	78,539,797

See accompanying notes.

Panhandle Oil and Gas Inc.

Consolidated Statements of Income

		Year ended September 30,
		2008				2007				2006
Revenues:
Oil and gas sales		$	69,026,785			$	37,449,174			$	36,008,527
Lease bonuses and rentals			167,559				208,625				410,984
(Losses) gains on gas collar contracts			(940,823	)			765,316				—
Gain on sales of assets and interest			233,709				322,405				529,804
Income from partnerships			631,891				383,391				536,365
			69,119,121				39,128,911				37,485,680
Costs and expenses:
Lease operating expenses and production taxes			10,055,762				6,057,456				5,262,834
Exploration costs			455,943				1,050,069				222,892
Depreciation, depletion, and amortization			19,784,660				15,291,625				10,142,367
Provision for impairment			526,380				3,761,832				3,009,953
Loss on sales of assets			204,189				254,395				119,282
General and administrative			5,006,512				3,877,492				3,335,899
Bad debt expense			591,258				—				—
Interest expense			44,346				133,578				232,234
			36,669,050				30,426,447				22,325,461
Income before provision for income taxes			32,450,071				8,702,464				15,160,219
Provision for income taxes			10,894,302				2,359,000				4,586,000
Net income		$	21,555,769			$	6,343,464			$	10,574,219
Basic earnings per common share:
Net income		$	2.54			$	0.75			$	1.25

See accompanying notes.

Panhandle Oil and Gas Inc.

Consolidated Statements of Stockholders’ Equity

		Class A voting								Capital in				Deferred
		Common Stock								Excess of				Directors				Retained				Treasury				Treasury
		Shares				Amount				Par Value				Compensation				Earnings				Shares				Stock				Total
Balances at September 30, 2005			8,410,886			$	140,182			$	1,715,206			$	—			$	36,779,962				—			$	—			$	38,635,350
Issuance of common shares to ESOP			11,643				193				209,381				—				—				—				—				209,574
Increase in deferred directors compensation:
Reclassification of liability			—				—				—				1,053,408				—				—				—				1,053,408
Charged to expense			—				—				—				149,161								—				—				149,161
Dividends declared ($.185 per share)			—				—				—				—				(1,556,015	)			—				—				(1,556,015	)
Net income			—				—				—				—				10,574,219				—				—				10,574,219
Balances at September 30, 2006			8,422,529			$	140,375			$	1,924,587			$	1,202,569			$	45,798,166				—			$	—			$	49,065,697
Issuance of common shares to ESOP			8,973				149				221,484				—				—				—				—				221,633
Issuance of common shares to directors for services			—				—				—				156,209				—				—				—				156,209
Dividends declared ($.25 per share)			—				—				—				—				(2,105,632	)			—				—				(2,105,632	)
Net income			—				—				—				—				6,343,464				—				—				6,343,464
Balances at September 30, 2007			8,431,502			$	140,524			$	2,146,071			$	1,358,778			$	50,035,998				—			$	—			$	53,681,371
Purchase of treasury stock			—				—				—				—				—				(139,014	)			(4,998,842	)			(4,998,842	)
Issuance of treasury shares to ESOP			—				—				(56,001	)			—				—				7,640				274,734				218,733
Issuance of common shares to directors for services			—				—				—				247,033				—				—				—				247,033
Dividends declared ($.28 per share)			—				—				—				—				(2,355,163	)			—				—				(2,355,163	)
Net income			—				—				—				—				21,555,769				—				—				21,555,769
Balances at September 30, 2008			8,431,502			$	140,524			$	2,090,070			$	1,605,811			$	69,236,604				(131,374	)		$	(4,724,108	)		$	68,348,901

See accompanying notes.

Panhandle Oil and Gas Inc.

Consolidated Statements of Cash Flows

		Year ended September 30,
		2008				2007				2006
Operating Activities
Net income		$	21,555,769			$	6,343,464			$	10,574,219
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization, and impairment			20,311,040				19,053,457				13,152,320
Deferred income taxes			9,116,000				1,329,000				2,177,000
Lease bonus income			—				(45,954	)			(95,892	)
Exploration costs			455,943				1,050,069				222,892
Net loss (gain) on sales of assets			20,632				22,856				(415,951	)
Income from partnerships			(631,891	)			(383,391	)			(536,365	)
Distributions received from partnerships			585,588				465,535				618,509
Common stock issued to ESOP			218,733				221,633				209,574
Common stock (unissued) to Directors’ Deferred Compensation Plan			247,033				156,209				149,161
Bad debt expense			591,258				—				—
Cash provided (used) by changes in assets and liabilities:
Oil and gas sales receivables			(9,671,136	)			(1,631,627	)			169,824
Fair value of derivative contracts			(539,277	)			(106,916	)			—
Refundable income taxes and other			(2,267,114	)			1,635,853				(1,889,363	)
Other non-current assets			(388,194	)			—				—
Accounts payable			59,921				(118,012	)			(21,361	)
Accrued directors’ deferred compensation			—				—				(281,897	)
Accrued liabilities			260,414				114,324				(562,525	)
Total adjustments			18,368,950				21,763,036				12,895,926
Net cash provided by operating activities			39,924,719				28,106,500				23,470,145
Investing Activities
Capital expenditures, including dry hole costs			(38,747,749	)			(27,785,431	)			(21,738,745	)
Proceeds from leasing of fee mineral acreage			200,356				188,417				493,652
Sale (purchase) of investments			—				11,280				(282,000	)
Proceeds from sales of assets			840,398				645,055				408,487
Net cash used in investing activities			(37,706,995	)			(26,940,679	)			(21,118,606	)