Attached files

file filename
EX-23 - EX-23 - PANHANDLE OIL & GAS INCd78254exv23.htm
EX-21 - EX-21 - PANHANDLE OIL & GAS INCd78254exv21.htm
EX-99 - EX-99 - PANHANDLE OIL & GAS INCd78254exv99.htm
EX-32.2 - EX-32.2 - PANHANDLE OIL & GAS INCd78254exv32w2.htm
EX-31.1 - EX-31.1 - PANHANDLE OIL & GAS INCd78254exv31w1.htm
EX-32.1 - EX-32.1 - PANHANDLE OIL & GAS INCd78254exv32w1.htm
EX-31.2 - EX-31.2 - PANHANDLE OIL & GAS INCd78254exv31w2.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(PANHANDLE OIL AND GAS INC. LOGO)
Annual Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended September 30, 2010
Commission File Number: 001-31759
PANHANDLE OIL AND GAS INC.
(Exact name of registrant as specified in its charter)
     
OKLAHOMA   73-1055775
     
(State or other jurisdiction of incorporation
or organization)
  (I.R.S. Employer Identification No.)
     
Grand Centre, Suite 300, 5400 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.
o Yes   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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer 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, 2010, was $168,087,326. As of December 1, 2010, 8,310,942 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 3, 2011, 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.
 
 


 

TABLE OF CONTENTS
             
        Page
 
           
PART I        
 
           
  Business     1  
 
           
  Unresolved Staff Comments     10  
 
           
  Properties     10  
 
           
  Legal Proceedings     19  
 
           
  Submission of Matters to a Vote of Security Holders     19  
 
           
PART II        
 
           
  Market for Registrant’s Common Equity and Related Stockholder Matters     20  
 
           
  Selected Financial Data     21  
 
           
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     22  
 
           
  Quantitative and Qualitative Disclosures about Market Risk     37  
 
           
  Financial Statements and Supplementary Data     38  
 
           
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     72  
 
           
  Controls and Procedures     72  
 
           
  Other Information     72  
 
           
PART III        
 
           
Item 10-14
  Incorporated by Reference to Proxy Statement        
 
           
PART IV        
 
           
  Exhibits, Financial Statement Schedules and Reports on Form 8- K     73  
 
           
Signature Page     74  
 
           
Exhibit 21
        75  
 
           
Exhibit 23
        76  
 
           
Exhibit 31.1-31.2     77  
 
           
Exhibit 32.1-32.2     79  
 
           
Exhibit 99
        81  


Table of Contents

The following defined terms are used in this report:
Bbl” means barrel;
Bcf” means billion cubic feet;
“Board” means board of directors;
“CEGT” means Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma;
“CEO” means Chief Executive Officer;
“CFO” means Chief Financial Officer;
“CO2” means carbon dioxide;
“COO” means Chief Operating Officer;
“DD&A” means depreciation, depletion and amortization;
“ESOP” refers to the Panhandle Oil and Gas Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan;
“FASB” means the Financial Accounting Standards Board;
“gross wells” or “gross acres” are the wells or acres in which the Company has a working interest;
“Independent Consulting Petroleum Engineer(s)” or “Independent Consulting Petroleum Engineering Firm(s)” refers to DeGolyer and MacNaughton of Dallas, Texas, for proved reserves calculated as of September 30, 2010, or to Pinnacle Energy Services, L.L.C. of Oklahoma City, Oklahoma, for proved reserves calculated as of September 30, 2008 and 2009;
“LOE” means lease operating expense;
Mcf” means thousand cubic feet;
Mcfd” means thousand cubic feet per day;
Mcfe” means natural gas stated on an Mcf basis and crude oil 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;
minerals”, “mineral acres” or “mineral interests” refers to fee mineral acreage owned in perpetuity by the Company;
“net wells” or “net acres” are determined by multiplying gross wells or acres by the Company’s net revenue interest in such wells or acres;
“NYMEX” refers to the New York Mercantile Exchange;
“PEPL” means Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline;
“play” is a term applied to identified areas with potential oil and/or natural gas reserves;
PV-10” means estimated pretax present value of future net revenues discounted at 10% using SEC rules;
royalty interest” refers to well interests in which the Company does not pay a share of the costs to drill, complete and operate a well, but receives a much smaller proportionate share (as compared to a working interest) of production;
SEC” means the United States Securities and Exchange Commission;
working interest” refers to well interests in which the Company pays a share of the costs to drill, complete and operate a well and receives a proportionate share of production.
Fiscal year references
All references to years in this report, unless otherwise noted, refer to the Company’s fiscal year end of September 30.
References to natural gas
All references to natural gas reserves, sales and prices include associated natural gas liquids.


Table of Contents

PART I
ITEM 1 BUSINESS
GENERAL
     Panhandle Oil and Gas Inc. (“Company” or “Panhandle”) was founded in Range, Texas County, Oklahoma, in 1926, as Panhandle Cooperative Royalty Company and operated as a cooperative until 1979, when the Company merged into Panhandle Royalty Company and its shares became publicly traded. On April 2, 2007 the Company’s name was changed to Panhandle Oil and Gas Inc. The name change was made to clear up confusion as to the nature of the Company’s business operations. Panhandle has never been a Royalty Trust.
     While operating as a cooperative, the Company returned most of its net income to shareholders as cash dividends. Upon conversion to a public company in 1979, although still paying dividends, the Company began to retain a substantial part of its cash flow to participate with a working interest in the drilling of wells on its mineral acreage and to purchase additional mineral acreage. Several acquisitions of additional mineral acreage and small companies were made in the ‘80s and ‘90s, and the acquisition of Wood Oil Company (now a wholly owned subsidiary) was consummated in October 2001.
     In January 2006 the Company last split its Class A Common Stock on a two-for-one basis. In March 2007, the Company last increased its authorized Class A Common Stock from 12 million shares to the current 24 million shares.
     The Company is involved in the acquisition, management and development of oil and natural gas properties, including wells located on the Company’s mineral and leasehold acreage. Panhandle’s mineral and leasehold properties are located primarily in Arkansas, Kansas, Oklahoma, New Mexico and Texas, with properties also located in seven other states. The majority of the Company’s oil and natural gas production is from wells located in Oklahoma.
     The Company’s office is located at Grand Centre, Suite 300, 5400 North Grand Blvd., Oklahoma City, OK 73112; telephone — (405) 948-1560, facsimile — (405) 948-2038. Its website is www.panhandleoilandgas.com.
     The Company files periodic reports with the SEC on Forms 10-Q and 10- K. These Forms, the Company’s annual report to shareholders and current press releases are available free of charge through its website as soon as reasonably practicable after they are filed with the SEC. Also, the Company posts copies of its various corporate governance documents on the website. From time to time, the Company posts other important disclosures to investors in the “Press Release” or “Upcoming Events” section of the website, as allowed by SEC rules.
     Materials filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet website at www.sec.gov that contains reports, proxy and information statements, and other information regarding the Company that has been filed electronically with the SEC.
BUSINESS STRATEGY
     Typically, more than 80% of Panhandle’s revenues are derived from the production and sale of oil and natural gas (see Item 8 — “Financial Statements”). The Company’s oil and natural gas holdings, including its mineral acreage, leasehold acreage and working and royalty interests in producing wells are

(1)


Table of Contents

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 natural gas properties are conducted in association with operating oil and natural gas companies, primarily larger independent companies. The Company does not operate any of its oil and natural gas properties, but has been an active working interest participant for many years in wells drilled on the Company’s mineral properties and on third-party drilling prospects. A significant percentage of the Company’s recent drilling participations have been on properties in which the Company owns mineral acreage and, in many cases, already owns an interest in a producing well in the unit. Most of these wells are in unconventional plays (shale gas) located in Oklahoma and Arkansas.
PRINCIPAL PRODUCTS AND MARKETS
     The Company’s principal products are natural gas and, to a lesser extent, crude oil. These products are sold to various purchasers, including pipeline and marketing companies, which service the areas where the Company’s producing wells are located. Since the Company does not operate any of the wells in which it owns an interest, it relies on the operating expertise of numerous companies that operate wells in the areas where the Company owns interests. This includes expertise in the drilling and completion of new wells, producing well operations and, in most cases, the marketing or purchasing of production from the wells. Natural gas sales are principally handled by the well operator and are normally contracted on a monthly basis with third party natural gas marketers and pipeline companies. Payment for natural gas sold is received by the Company either from the contracted purchasers or the well operator. Crude oil sales are generally handled by the well operator and payment for oil sold is received by the Company from the well operator or from the crude oil purchaser.
     Prices of oil and natural gas are dependent on numerous factors beyond the control of the Company, including competition, weather, international events and circumstances, supply and demand, actions taken by the Organization of Petroleum Exporting Countries (“OPEC”), and economic, political and regulatory developments. Since demand for natural gas is generally highest during winter months, prices received for the Company’s natural gas production are subject to seasonal variations.
     Beginning in calendar 2007, the Company entered into price risk management instruments (derivatives) to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. The derivative contracts apply to only a portion of the Company’s natural gas production and provide only partial price protection against declines in natural gas prices. These derivative contracts expose the Company to risk of financial loss and may limit the benefit of future increases in natural gas prices. A more thorough discussion of these derivative contracts is contained in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operation”.
COMPETITIVE BUSINESS CONDITIONS
     The oil and natural gas industry is highly competitive, particularly in the search for new oil and natural gas reserves. 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 natural gas production, business and consumer demand for refined oil products and natural gas, and the effects of federal and state regulation of the exploration for, production of and sales of oil and natural gas. Changes in existing economic conditions, weather patterns and actions taken by OPEC and other oil-producing countries have a dramatic influence on the price Panhandle receives for its oil and natural gas production.
     The Company does not operate any of the wells in which it has an interest; rather it relies on companies with greater resources, staff, equipment, research and experience for operation of wells both in the drilling and production phases. The Company uses its strong financial base and its mineral and

(2)


Table of Contents

leasehold acreage ownership, coupled with its own geologic and economic evaluations, to participate in drilling operations with these larger companies. This methodology allows the Company to compete effectively in drilling operations it could not undertake on its own due to financial and personnel limits and allows it to maintain low overhead costs.
SOURCES AND AVAILABILITY OF RAW MATERIALS
     The existence of recoverable oil and natural gas reserves in commercial quantities is essential to the ultimate realization of value from the Company’s mineral and leasehold acreage. These mineral and leasehold properties are the raw materials to 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 natural 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 natural gas. This participation in exploration and production activities and purchase of additional acreage is necessary to continue to supply the Company with the raw materials with which to generate additional cash flow. Mineral and leasehold acreage purchases are made from many owners. The Company does not rely on any particular companies or persons for the purchases of additional mineral and leasehold acreage.
MAJOR CUSTOMERS
     The Company’s oil and natural gas production is sold, in most cases, through its well operators to many different purchasers on a well-by -well basis. During 2010, sales through three separate well operators accounted for approximately 15%, 14% and 11%, respectively, of the Company’s total oil and natural 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 natural gas wells stemming from the Company’s ownership of mineral acreage generate a portion of the Company’s revenues. These royalties are tied to ownership of mineral acreage and this ownership is perpetual, unless sold by the Company. Royalties are due and payable to the Company whenever oil and/or natural gas is produced and sold from wells located on the Company’s mineral acreage.
REGULATION
     All of the Company’s well interests and non-producing properties are located onshore in the United States. Oil and natural gas production is subject to various taxes, such as gross production taxes and, in some cases, ad valorem taxes.
     The State of Oklahoma and other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other regulations relating to the exploration for and production of oil and natural gas. These states also have regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties and the regulation of spacing, plugging and abandonment of wells. As previously discussed, the Company relies on the well operators to comply with governmental regulations.
     Various aspects of the Company’s oil and natural gas operations are regulated by agencies of the

(3)


Table of Contents

federal government. Transportation of natural gas in interstate commerce is generally regulated by the Federal Energy Regulatory Commission (“FERC”) pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 (“NGPA”) . The intrastate transportation and gathering of natural gas (and operational and safety matters related thereto) may be subject to regulation by state and local governments.
     FERC’s jurisdiction over interstate natural gas sales was substantially modified by the NGPA under which FERC continued to regulate the maximum selling prices of certain categories of natural gas sold in “first sales” in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas. Because “first sales” include typical wellhead sales by producers, all natural gas produced from the Company’s natural gas properties is sold at market prices, subject to the terms of any private contracts in effect. FERC’s jurisdiction over natural gas transportation was not affected by the Decontrol Act.
     Sales of natural gas are affected by intrastate and interstate natural gas transportation regulation. Beginning in 1985, FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by FERC to foster competition by transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the primary role of natural gas transporters. As a result of the various omnibus rulemaking proceedings in the late 1980s and the individual pipeline restructuring proceedings of the early to mid-1990s, interstate pipelines must provide open and nondiscriminatory transportation and transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end users and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, FERC expanded the impact of open access regulations to intrastate commerce.
     More recently, FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are: (1) permitting the large-scale divestiture of interstate pipeline-owned natural gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline’s demonstration of lack of market control in the relevant service market.
     As a result of these changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are able to conduct business with a larger number of counter parties. These changes generally have improved the access to markets for natural gas while substantially increasing competition in the natural gas marketplace. The effect of future regulations by FERC and other regulatory agencies cannot be predicted.
     Sales of oil are not regulated and are made at market prices. The price received from the sale of oil is affected by the cost of transporting it to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. Over time, these regulations tend to increase the cost of transporting oil by interstate pipeline, although some annual adjustments may result in decreased rates for a given year. These regulations have generally been upheld on judicial review. Every five years, FERC will examine

(4)


Table of Contents

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 immaterial. The Company does not believe the existence of these environmental laws, as currently written and interpreted, will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future events or changes in laws, or the interpretation of laws, governing our industry. Current discussions involving the governance of hydraulic fracturing in the future could have a material impact on the Company. Since the Company does not operate any wells in which it owns an interest, actual compliance with environmental laws is controlled by the well operators, with Panhandle being responsible for its proportionate share of the costs involved. As such, to its knowledge, the Company is not aware of any instances of non-compliance with existing regulations and that, absent an extraordinary event, any noncompliance will not have a material adverse effect on the financial condition of the Company. Although the Company is not fully insured against all environmental risks, insurance coverage is maintained at levels which are customary in the industry.
EMPLOYEES
     At September 30, 2010, Panhandle employed 18 persons on a full-time basis with five of the employees serving as executive officers. The President and CEO is also a director of the Company.
RISK FACTORS
     In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating the Company’s business and future prospects. The risk factors described below are not necessarily exhaustive, and investors are encouraged to perform their own investigation with respect to the Company and its business. Investors should also read the other information in this Form 10-K, including the financial statements and related notes.
Worldwide and in the United States, economic recession continues to have a negative effect on demand for and the price of oil and natural gas.
     Continuing effects of the economic recession could lead to: (1) a decline of oil and natural gas reserves due to curtailed drilling activity; (2) risk of insolvency of well operators and oil and natural gas purchasers; (3) limited availability of certain insurance contracts; and (4) limited access to derivative instruments. A decline in reserves would lead to a decline in production and would have a negative impact on profitability and Company value.
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 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;

(5)


Table of Contents

    market uncertainty;
 
    relatively minor changes in the supply of and demand for oil and natural gas;
 
    availability and capacity of necessary transportation and processing facilities;
 
    commodity futures trading;
 
    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, 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, 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. 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 decline in oil and natural gas prices for an extended period of time would have a material adverse effect on the Company.
     A substantial decline in oil and natural gas prices for an extended period of time would have a material adverse effect on the Company’s financial position, results of operations, access to capital and the quantities of oil and natural gas that may be economically produced. A significant decrease in price levels for an extended period would have a material negative effect in several ways, including:
    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.
We cannot control activities on properties we do not operate.
     The Company does not operate any of the properties in which it has an interest and has very limited ability to exercise influence over operations of these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and the limited ability to influence operations and associated costs could materially and adversely affect the realization of targeted returns on capital in drilling or acquisition activities and targeted production growth rates. The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond the Company’s control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of appropriate technology.
The Company’s derivative activities may reduce the cash flow received for oil and natural gas sales.
     In order to manage exposure to price volatility in our natural gas, we enter into natural gas derivative contracts for a portion of our expected production. Commodity price derivatives may limit the cash flow we actually realize and therefore reduce revenues in the future. The fair value of our natural gas derivative instruments outstanding as of September 30, 2010 was an asset of $1,620,326.

(6)


Table of Contents

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 natural gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and development dry holes are capitalized and amortized by property using the unit-of-production method as oil and natural gas is produced.
     All long-lived assets, principally the Company’s oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset 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 natural gas reserves. Once assets are classified as held for sale, they are reviewed for impairment. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded. If an impairment charge is recognized, cash flow from operating activities is not impacted but net income and, consequently, shareholders’ equity, are reduced.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
     It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future 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 Independent 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 the 12- month average price calculated as the unweighted arithmetic average of the first-day- of-the-month oil and natural gas price for each month within the 12- month period prior to September 30, 2010, held flat over the life of the properties and costs in effect as of the date of estimation, less future development, production and income tax expenses, and is discounted at ten percent per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.
     The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures. Further, our lack of knowledge of all individual well information known to the well operators such as incomplete well stimulation efforts, restricted production rates for various reasons and up to date well production data, etc. may cause differences in our reserve estimates.
     Because forward-looking prices and costs are not used to estimate discounted future net cash flows from our estimated proved reserves, the standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.

(7)


Table of Contents

     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 on oil and natural gas producing activities disclosures may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company, or the oil and natural gas industry in general.
Failure to find or acquire additional reserves will cause reserves and production to decline materially from their current levels.
     The rate of production from oil and natural gas properties generally declines as reserves are depleted. The Company’s proved reserves will decline materially as reserves are produced except to the extent that the Company acquires additional properties containing proved reserves, conducts additional successful exploration and development drilling, successfully applies new technologies or identifies additional behind-pipe zones 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 and development activities. The seismic data and other technologies used do not allow operators to know conclusively prior to drilling a well whether oil or natural gas is present and may be commercially produced.
     Cost factors can adversely affect the economics of any project, and ultimately the cost of drilling, completing and operating a well is controlled by well operators and existing market conditions. Further drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, environmental and other governmental requirements, the cost and availability of drilling rigs, equipment and services and potentially the expected sales price to be received for oil or natural gas produced from the wells.
Reserve estimates for September 30, 2010, calculated under the new SEC reporting rules, Modernization of Oil and Gas Reporting Requirements, are not directly comparable to reserve estimates made in prior years.
     This report presents reserve estimates prepared using the new SEC reporting rules, Modernization of Oil and Gas Reporting Requirements, which are different in a number of respects from rules used for reserve estimates made in prior years. The changes include: (1) permitting use of new technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; (2) enabling companies to additionally disclose their probable and possible reserves to investors, in addition to their proved reserves; (3) allowing previously excluded resources, such as oil sands, to be classified as oil and natural gas reserves rather than mining reserves; (4) requiring companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria; (5) requiring the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; and (6) requiring companies to report oil and natural gas reserves using an average price based upon the prior 12-month period, rather

(8)


Table of Contents

than year-end prices. The result is reserve estimates beginning with the fiscal year ended September 30, 2010 will not be directly comparable to estimated reserves reported in previous fiscal years.
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.
Future legislative or regulatory changes may result in increased costs and decreased revenues, cash flows and liquidity.
     Companies which operate wells in which Panhandle owns a working interest are subject to extensive federal, state and local regulation. Panhandle, as a working interest owner, is therefore indirectly subject to the same regulations. New or changed laws and regulations such as those described below could have an adverse effect on our business.
     Federal Income Taxation
     Proposals to repeal the expensing of intangible drilling costs, repeal the percentage depletion allowance and increase the amortization period of geological and geophysical expenses, if enacted, would increase and accelerate the Company’s payment of federal income taxes. As a result, these changes would decrease the Company’s cash flows available for developing its oil and natural gas properties.
     Hydraulic Fracturing
     The vast majority of oil and natural gas wells drilled in recent years, and future wells expected to be drilled, in which the Company owns an interest were, or are expected to be, hydraulically fractured as a part of the process of completing the wells and putting them on production. Some members of Congress have proposed legislation to either ban or further regulate the hydraulic fracturing process. We cannot predict whether any such legislation will be enacted or, if enacted, what its provisions would be. If legislation is passed to ban hydraulic fracturing, the number of wells drilled in the future may drop dramatically, and the economic performance of those drilled will be negatively affected. Legislation imposing further regulation of hydraulic fracturing may result in increased costs to drill, complete and operate wells, as well as delays in obtaining permits to drill wells.
     Climate Change
     The EPA has proposed regulations for the purpose of restricting greenhouse gas emissions from stationary sources. Also, the U.S. Congress has considered legislation that would establish a cap-and-trade program in order to reduce emissions of greenhouse gases such as carbon dioxide and methane. Such regulatory and legislative proposals to restrict greenhouse gas emissions, or to generally address climate change, could increase the Company’s operating costs as operators of wells, in which the Company owns a working interest, incur costs to comply with new rules. The increase in costs to the

(9)


Table of Contents

well operators, and ultimately the Company, as a working interest owner, could include new or increased costs to install new emissions control equipment, operate and maintain existing equipment, obtain allowances to authorize greenhouse gas emissions and pay greenhouse gas related taxes. There also could be an adverse effect on demand for oil and natural gas in the market place.
Shortages of 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, hydraulic fracturing equipment and personnel and other oilfield equipment, as demand for rigs and equipment increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. These shortages or price increases could adversely affect the Company’s profit margin, cash flow and operating results, or restrict its ability to drill wells and conduct ordinary operations.
Competition in the oil and natural gas industry is intense, and most of our competitors have greater financial and other resources than we do.
     We compete in the highly competitive areas of oil and natural gas acquisition, development, exploration and production. We face intense competition from both major and independent oil and natural gas companies in seeking to acquire desirable producing properties, seeking new properties for future exploration and seeking the human resource expertise necessary to effectively develop properties. We also face similar competition in obtaining sufficient capital to maintain drilling rights in all drilling units.
     Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil and natural gas companies. These companies are able to pay more for development prospects and productive oil and natural gas properties and are able to define, evaluate, bid for, purchase and subsequently drill a greater number of properties and prospects than our financial or human resources permit, effectively reducing our right to participate in drilling on certain of our acreage as a working interest owner. Our ability to develop and exploit our oil and natural gas properties and to acquire additional quality properties in the future will depend upon our ability to successfully evaluate, select and acquire suitable properties and join in drilling with reputable operators in this highly competitive environment.
ITEM 1B UNRESOLVED STAFF COMMENTS
     None
ITEM 2 PROPERTIES
     At September 30, 2010, Panhandle’s principal properties consisted of perpetual ownership of 254,422 net mineral acres, held principally in Arkansas, New Mexico, North Dakota, Oklahoma, Texas and six other states. The Company also held leases on 19,066 net acres primarily in Oklahoma. At September 30, 2010, Panhandle held working interests, royalty interest or both in 4,989 producing oil and natural gas wells and 40 wells in the process of being drilled or completed.

(10)


Table of Contents

     Consistent with industry practice, the Company does not have current abstracts or title opinions on all of its mineral properties and, therefore, cannot be certain that it has unencumbered title to all of these properties. In recent years, a few insignificant challenges have been made against the Company’s fee title to its properties.
     The Company pays ad valorem taxes on minerals owned in nine states.
ACREAGE
     Mineral Interests Owned
     The following table of mineral interests owned reflects, in each respective state, the number of net and gross acres, net and gross producing acres, net and gross acres leased, and net and gross acres open (unleased) as of September 30, 2010.
                                                                 
                                    Net   Gross        
                    Net   Gross   Acres   Acres   Net    
                    Acres   Acres   Leased   Leased   Acres   Gross Acres
    Net           Producing   Producing   to Others   to Others   Open   Open
State   Acres   Gross Acres   (1)   (1)   (2)   (2)   (3)   (3)
 
Arkansas
    9,951       45,277       4,106       16,174       3,312       13,102       2,533       16,001  
Colorado
    8,217       39,080                       223       447       7,994       38,633  
Florida
    5,589       12,239                                       5,589       12,239  
Kansas
    3,082       11,816       144       1,200                       2,938       10,616  
Montana
    1,007       17,947                                       1,007       17,947  
North Dakota
    11,179       64,286       110       800                       11,069       63,486  
New Mexico
    57,396       174,460       1,352       7,125       525       760       55,519       166,575  
Oklahoma
    112,975       945,038       36,799       296,339       1,099       9,029       75,077       639,670  
South Dakota
    1,825       9,300                                       1,825       9,300  
Texas
    43,174       359,864       7,451       70,500       547       5,578       35,176       283,786  
OTHER
    27       262                                       27       262  
 
 
                                                               
Total:
    254,422       1,679,569       49,962       392,138       5,706       28,916       198,754       1,258,515  
 
(1)   “Producing” represents the mineral acres in which Panhandle owns a royalty or working interest in a producing well.
 
(2)   “Leased” represents the mineral acres owned by Panhandle that are leased to third parties but not producing.
 
(3)   “Open” represents mineral acres owned by Panhandle that are not leased or in production.
     Leases
     The following table reflects net mineral acres leased from others, lease expiration dates, and net leased acres held by production.
                                                                 
                                                            Net Acres
                                                            Held by
State       Net Acres   Net Lease Acres Expiring   Production
                    2011   2012   2013   2014   2015        
Kansas
            2,117                                               2,117  
Oklahoma
            15,077       1,597       167       600       653       32       12,028  
Texas
            504               3                               501  
Other
            1,368                                               1,368  
 
TOTAL
            19,066       1,597       170       600       653       32       16,014  
 

(11)


Table of Contents

PROVED RESERVES
     The following table summarizes estimates of proved reserves of oil and natural gas held by Panhandle. All proved reserves are located within the United States and are principally made up of small interests in 4,989 wells. Other than this report, the Company’s reserve estimates are not filed with any other federal agency.
                         
    Barrels of Oil   Mcf of Natural Gas   Mcfe
Net Proved Developed Reserves
September 30, 2010
    861,240       57,344,190       62,511,630  
September 30, 2009
    882,987       45,036,460       50,334,382  
September 30, 2008
    895,430       35,970,450       41,343,030  
 
Net Proved Undeveloped Reserves
September 30, 2010
    63,769       40,826,265       41,208,879  
September 30, 2009
    37,886       8,991,350       9,218,666  
September 30, 2008
    94,530       12,180,220       12,747,400  
 
Net Total Proved Reserves
September 30, 2010
    925,009       98,170,455       103,720,509  
September 30, 2009
    920,873       54,027,810       59,553,048  
September 30, 2008
    989,960       48,150,670       54,090,430  
     Reserves for 2008 exclude approximately 2.9 Bcf of CO2 gas reserves. These reserves were sold in the fourth quarter of 2009.
     The determination of reserve estimates is a function of testing and evaluating the production and development of oil and natural gas reservoirs in order to establish a production decline curve. The established production decline curves, in conjunction with estimated future oil and natural gas prices, development costs, production taxes and operating expenses, are used to estimate oil and natural gas reserve quantities and associated future net cash flows. As information is processed, over time, regarding the development of individual reservoirs and as market conditions change, estimated reserve quantities and future net cash flows will change as well. Estimated reserve quantities and future net cash flows are affected by changes in product prices, and these prices have varied substantially in recent years and are expected to vary substantially from current pricing in the future.
     In January 2010, the FASB updated its oil and natural gas estimation and disclosure requirements to align its requirements with the SEC’s modernized oil and natural gas reporting rules, which are effective for annual reports on Form 10K for fiscal years ending on or after December 31, 2009. The update includes the following changes: (1) permitting use of new technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; (2) enabling companies to additionally disclose their probable and possible reserves to investors, in addition to their proved reserves; (3) allowing previously excluded resources, such as oil sands, to be classified as oil and natural gas reserves rather than mining reserves; (4) requiring companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria; (5) requiring the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; and (6) requiring companies to report oil and natural gas reserves using an average price based upon the prior 12-month period, rather than year-end prices. The update must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. Effective September 30, 2010, the Company adopted the new requirements. See Note 10 for disclosures regarding our natural gas and oil reserves.

(12)


Table of Contents

     The Company is not able to disclose the effects resulting from the implementation of these changes on the financial statements or on the amount of proved reserves and disclosed quantities. In order to accurately report the quantitative effect of applying oil and gas modernization rules, it would have been necessary for the Company to prepare two sets of reserve reports, one applying the new oil and gas modernization rules and another applying the rules in effect at September 30, 2009. The Company has interests in several thousand developed and undeveloped properties which are evaluated in the reserve estimation process. The Company has a total of eighteen employees including one petroleum engineer and one engineering tech. Staff time was not available for the engineering staff to perform necessary controls to ensure the accuracy of the report, for accounting personnel to recalculate DD&A and re-test for impairment of producing properties and be able to timely prepare and file this Form 10-K with the SEC. Therefore, the Company determined that it was not practicable to perform a second reserve estimation process under the prior rules.
     Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves, which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection), are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12 -month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
     Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
     Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless

(13)


Table of Contents

evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
     The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas calculated the Company’s oil and natural gas reserves as of September 30, 2010 (see Exhibits 23 and 99). Reserves as of September 30, 2008 and 2009 were calculated by Pinnacle Energy Services, L.L.C. of Oklahoma City, Oklahoma.
     The Company’s net proved (including certain undeveloped reserves described above) oil and natural gas reserves, all of which are located in the United States, as of September 30, 2010, 2009 and 2008, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firms. All studies have been prepared in accordance with regulations prescribed by the Securities and Exchange Commission. The reserve estimates were based on economic and operating conditions existing at September 30, 2010, 2009 and 2008. Since the determination and valuation of proved reserves is a function of testing and estimation, the reserves presented should be expected to change as future information becomes available.
ESTIMATED FUTURE NET CASH FLOWS
     Set forth below are estimated future net cash flows with respect to Panhandle’s net proved reserves (based on the estimated units set forth in the immediately preceding table) for the year indicated, and the present value of such estimated future net cash flows, computed by applying a 10% discount factor as required by the rules and regulations of the SEC. Estimated future net cash flows as of September 30, 2008 and 2009 have been computed by applying prices of oil and natural gas on 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 these reserves. As of September 30, 2010, the Company adopted the new SEC Rule, Modernization of Oil and Gas Reporting Requirements. In accordance with the new SEC rule, the estimated future net cash flows as of September 30, 2010 were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil and natural gas price for each month within the 12-month period prior to September 30, 2010, held flat over the life of the properties and applied to future production of proved reserves less estimated future development and production expenditures for these reserves. The pricing used for each of the three years presented is in accordance with SEC regulations in effect for each year. The amounts presented 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, 2010, 2009 and 2008, were as follows: 2010 - $69.23/Bbl, $4.33/Mcf ; 2009 — $66.96/Bbl, $2.86/Mcf; 2008 — $97.74/Bbl, $4.51/Mcf (these natural gas prices are representative of local pipelines in Oklahoma). These future net cash flows based on SEC pricing rules should not be construed as the fair market value of the Company’s reserves. A market value determination would need to include many additional factors, including anticipated oil and natural gas price and production cost increases or decreases, which could affect the economic life of the properties.

(14)


Table of Contents

Estimated Future Net Cash Flows
                         
    9-30-10     9-30-09     9-30-08  
Proved Developed
  $ 202,056,455     $ 131,674,245     $ 182,996,389  
Proved Undeveloped
    84,200,597       15,372,040       31,863,340  
Income Tax Expense
    99,118,090       43,832,666       67,278,008  
 
                 
Total Proved
  $ 187,138,962     $ 103,213,619     $ 147,581,721  
 
                 
10% Discounted Present Value of Estimated Future Net Cash Flows
                         
    9-30-10     9-30-09     9-30-08  
Proved Developed
  $ 103,270,565     $ 73,869,512     $ 104,840,854  
Proved Undeveloped
    21,960,347       6,800,080       15,068,040  
Income Tax Expense
    52,730,503       26,923,084       41,896,610  
 
                 
Total Proved
  $ 72,500,409     $ 53,746,508     $ 78,012,284  
 
                 
     The future net cash flows for 9-30-08 are net of immaterial amounts of future cash flow to be received from CO2 reserves. These reserves were sold in the fourth quarter of 2009.
OIL AND NATURAL GAS PRODUCTION
     The following table sets forth the Company’s net production of oil and natural gas for the fiscal periods indicated.
                         
    Year Ended   Year Ended   Year Ended
    9-30-10   9-30-09   9-30-08
Bbls — Oil
    102,379       128,160       132,402  
Mcf — Natural Gas
    8,302,342       9,109,988       6,928,038  
Mcfe
    8,916,616       9,878,948       7,722,450  
     Natural gas production includes 236,308 and 193,408 Mcf of CO2 sold at average prices of $.85 and $.86 per Mcf for the years ended September 30, 2009 and 2008, 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
Average Sales Price   9-30-10   9-30-09   9-30-08
Per Bbl, Oil
  $ 72.83     $ 51.79     $ 103.91  
Per Mcf, Natural Gas (1)
  $ 4.41     $ 3.38     $ 7.98  
Per Mcfe
  $ 4.94     $ 3.79     $ 8.94  
 
(1)   Proceeds from the sale of natural gas liquids have been included in natural gas sales, and are therefore included in the price per Mcf of natural gas.

(15)


Table of Contents

                         
    Year Ended     Year Ended     Year Ended  
Average Production (lifting costs)   9-30-10     9-30-09     9-30-08  
(Per Mcfe of Natural Gas)
                       
(1)
  $ 0.92     $ 0.78     $ 0.86  
(2)
    0.16       0.12       0.44  
 
                 
 
  $ 1.08     $ 0.90     $ 1.30  
 
                 
 
(1)   Includes actual well operating costs, compression, handling and marketing fees paid on natural gas sales and other minor expenses associated with well operations.
 
(2)   Includes production taxes only. The low production tax rate per Mcfe in 2009 and 2010 is because of a large proportion of the Company’s natural gas revenue coming from horizontally drilled wells which are eligible for either Oklahoma production tax credits or reduced Arkansas production tax rates.
     Approximately 28% of the Company’s oil and natural gas revenue is generated from royalty interests in approximately 3,600 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 natural gas wells as of September 30, 2010. Panhandle owns either working interests, royalty interests or both in these wells. The Company does not operate any wells.
                 
    Gross Wells   Net Wells
Oil
    997       20.47  
Natural Gas
    3,992       92.30  
 
               
Total
    4,989       112.77  
 
               
     Information on multiple completions is not available from Panhandle’s records, but the number is not believed to be significant.
     As of September 30, 2010, Panhandle owned 392,138 gross developed mineral acres and 49,962 net developed mineral acres. Panhandle has also leased from others 138,112 gross developed acres containing 16,014 net developed acres.
UNDEVELOPED ACREAGE
     As of September 30, 2010, Panhandle owned 1,287,431 gross and 204,460 net undeveloped mineral acres, and leases on 28,044 gross and 3,052 net acres.
DRILLING ACTIVITY
     The following net productive development and exploratory wells and net dry development and exploratory wells in which the Company had either a working interest, a royalty interest or both were drilled and completed during the fiscal years indicated. The Company did not purchase any wells during these periods.

(16)


Table of Contents

                 
    Net Productive Wells   Net Dry Wells
Development Wells
               
Fiscal years ended:
               
September 30, 2010
    4.029693       0.057282  
September 30, 2009
    8.893170       0.092978  
September 30, 2008
    8.120236       0.067177  
Exploratory Wells
               
Fiscal years ended:
               
September 30, 2010
    0.160270       0.000000  
September 30, 2009
    0.867702       0.138051  
September 30, 2008
    0.985659       0.083333  
Purchased Wells
               
Fiscal years ended:
               
September 30, 2010
    — 0 —       — 0 —  
September 30, 2009
    — 0 —       — 0 —  
September 30, 2008
    — 0 —       — 0 —  
PRESENT ACTIVITIES
     The following table sets forth the gross and net oil and natural gas wells drilling or testing as of September 30, 2010, in which Panhandle owns either a working interest, a royalty interest or both. These wells were not yet producing at September 30, 2010.
                 
    Gross Wells   Net Wells
Oil
    7       0.15976  
Natural Gas
    33       0.74449  
OTHER FACILITIES
     The Company leases 12,369 square feet of office space in Oklahoma City, OK. The lease obligation ends in 2012.
SAFE HARBOR STATEMENT
     This report, including information included in, or incorporated by reference from, future filings by the Company with the SEC, as well as information contained in written material, press releases and oral statements, contains, or may contain, certain statements that are “forward-looking statements,” within the meaning of the federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address activities, events or developments which are expected to, or anticipated will, or may, occur in the future, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts” and similar expressions are used to identify forward-looking statements.

(17)


Table of Contents

     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, which reflect the occurrence of unanticipated events, after the date of this report.
     In order to provide a more thorough understanding of the possible effects of some of these influences on any forward-looking statements made, the following discussion outlines certain factors that in the future could cause consolidated results for 2011 and beyond to differ materially from those that may be presented in any such forward-looking statement made by or on behalf of the Company.
     Commodity Prices. The prices received for oil and natural gas production have a direct impact on the Company’s revenues, profitability and cash flows as well as the ability to meet its projected financial and operational goals. The prices for natural gas and crude oil are dependent on a number of factors beyond the Company’s control, including: the demand for oil and natural gas, weather conditions in the continental United States (which can greatly influence the demand for natural gas at any given time as well as the price we receive for such natural gas) and the ability of current distribution systems in the United States to effectively meet the demand for oil and natural gas at any given time, particularly in times of peak demand which may result because of adverse weather conditions.
     Oil prices are sensitive to foreign influences based on political, social or economic factors, any one of which could have an immediate and significant effect on the price and supply of oil. In addition, prices of both natural gas and oil are becoming more and more influenced by trading on the commodities markets, which has, at times, increased the volatility associated with these prices.
     Uncertainty of Oil and Natural Gas Reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and their values, including many factors beyond the Company’s control. The oil and natural gas reserve data included in this report represents only an estimate of these reserves. Oil and natural gas reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves depend on a number of variable factors, including historical production from the area compared with production from other producing areas and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs, and workover and remedial costs.
     Some or all of these assumptions may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas and estimates of the future net cash flows from oil and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, oil and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual production, revenues and expenditures with respect to oil and natural gas reserves will vary from estimates, and those variances can be material.

(18)


Table of Contents

     The Company does not operate any of the properties in which it has an interest and has very limited ability to exercise influence over operations for these properties or their associated costs. Dependence on the operator and other working interest owners for these projects and the limited ability to influence operations and associated costs could materially and adversely affect the realization of targeted returns on capital in drilling or acquisition activities and targeted production growth rates.
     The information regarding discounted future net cash flows included in this report is not necessarily the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties. As required by the SEC, the 2010 estimated discounted future net cash flows from proved oil and natural gas reserves are determined based on the fiscal year’s 12-month average of the first-day-of-the-month oil and natural gas prices (oil and natural gas prices used for 2008 and 2009 were based on the September 30 spot price of each respective year) and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Actual future net cash flows are also affected, in part, by the amount and timing of oil and natural gas production, supply and demand for oil and natural gas and increases or decreases in consumption.
     In addition, the 10% discount factor 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 on September 30, 2010, or at the date of this report.
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     No matters were submitted to a vote of Panhandle’s security holders during the fourth quarter of the fiscal year ended September 30, 2010.

(19)


Table of Contents

PART II
ITEM 5 MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(PERFORMANCE GRAPH)
     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, 2005, and its relative performance is tracked through September 30, 2010.
     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, 2008
  $ 28.18     $ 13.75  
March 31, 2009
  $ 23.75     $ 13.15  
June 30, 2009
  $ 24.62     $ 15.79  
September 30, 2009
  $ 28.02     $ 18.17  
December 31, 2009
  $ 26.25     $ 19.06  
March 31, 2010
  $ 29.65     $ 20.34  
June 30, 2010
  $ 29.29     $ 21.97  
September 30, 2010
  $ 30.31     $ 21.00  

(20)


Table of Contents

     As of November 22, 2010, there were 1,716 holders of record of Panhandle’s Class A Common Stock and approximately 4,000 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 2008
  $ 0.07  
March 2009
  $ 0.07  
June 2009
  $ 0.07  
September 2009
  $ 0.07  
December 2009
  $ 0.07  
March 2010
  $ 0.07  
June 2010
  $ 0.07  
September 2010
  $ 0.07  
     Approval by the Company’s board of directors is required before the declaration and payment of any dividends.
     While the Company anticipates it will continue to pay dividends on its common stock, the payment and amount of future cash dividends will depend upon, among other things, financial condition, funds from operations, the level of capital and development expenditures, future business prospects, contractual restrictions and any other factors considered relevant by the board of directors.
     The Company’s credit facility also contains a provision limiting the paying or declaring of a cash dividend to fifteen percent of net cash flow provided by operating activities from the Consolidated Statement of Cash Flows of the preceding 12-month period. See Note 4 to the consolidated financial statements contained herein at Item 8 — “Financial Statements,” for a further discussion of the credit facility.
     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. These programs were completed in 2008. Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the board of directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. The shares are held in treasury and are accounted for using the cost method. At September 30, 2010 and September 30, 2009, 11,632 and 11,508 (respectively) 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.

(21)


Table of Contents

                                         
    As of and for the year ended September 30,  
    2010     2009     2008     2007     2006  
Revenues
                                       
Oil and natural gas sales
  $ 44,068,947     $ 37,421,688     $ 69,026,785     $ 37,449,174     $ 36,008,527  
Lease bonuses and rentals
    1,120,674       188,906       167,559       208,625       410,984  
Gains (losses) on derivative contracts
    6,343,661       (661,828 )     (940,823 )     765,316        
Income from partnerships
    405,134       323,848       631,891       383,391       536,365  
 
                             
 
    51,938,416       37,272,614       68,885,412       38,806,506       36,955,876  
 
                             
Costs and expenses
                                       
Lease operating expense and production taxes
    9,639,864       8,897,235       10,055,762       6,057,456       5,262,834  
Exploration costs
    1,583,773       711,582       455,943       1,050,069       222,892  
Depreciation, depletion and amortization
    19,222,123       28,168,933       19,784,660       15,291,625       10,142,367  
Provision for impairment
    605,615       2,464,520       526,380       3,761,832       3,009,953  
Loss (gain) on asset sales, interest and other
    (1,028,148 )     (2,677,407 )     14,826       65,568       (178,288 )
General and administrative
    5,594,499       4,866,044       5,006,512       3,877,492       3,335,899  
Bad debt expense (recovery)
          (185,272 )     591,258              
 
                             
 
    35,617,726       42,245,635       36,435,341       30,104,042       21,795,657  
 
                             
 
                                       
Income (loss) before provision (benefit) for income taxes
    16,320,690       (4,973,021 )     32,450,071       8,702,464       15,160,219  
Provision (benefit) for income taxes
    4,901,000       (2,568,000 )     10,894,302       2,359,000       4,586,000  
 
                             
Net income (loss)
  $ 11,419,690     $ (2,405,021 )   $ 21,555,769     $ 6,343,464     $ 10,574,219  
 
                             
 
                                       
Basic and diluted earnings (loss) per share
  $ 1.36     $ (0.29 )   $ 2.54     $ 0.75     $ 1.25  
Dividends declared per share
  $ 0.28     $ 0.28     $ 0.28     $ 0.25     $ 0.185  
 
                                       
Weighted average shares outstanding
                                       
Basic and diluted
    8,422,387       8,397,337       8,492,378       8,499,233       8,479,406  
 
                                       
Net cash provided by (used in):
                                       
Operating activities
  $ 27,806,475     $ 37,710,606     $ 40,063,896     $ 28,106,500     $ 23,470,145  
Investing activities
  $ (9,845,516 )   $ (36,322,992 )   $ (37,846,172 )   $ (26,940,679 )   $ (21,118,606 )
Financing activities
  $ (13,003,609 )   $ (1,643,414 )   $ (2,311,376 )   $ (610,814 )   $ (3,556,019 )
 
                                       
Total assets
  $ 105,124,839     $ 108,549,632     $ 122,007,183     $ 78,539,797     $ 70,949,242  
Long-term debt
  $     $ 10,384,722     $ 9,704,100     $ 4,661,471     $ 1,166,649  
Shareholders’ equity
  $ 73,581,996     $ 64,122,343     $ 68,348,901     $ 53,681,371     $ 49,065,697  
All share and per-share amounts are adjusted for the effect of a 2-for-1 stock split effective in January 2006.
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 to explore for, develop, produce and sell oil and natural gas. Results of operations are dependent primarily upon reserve quantities and associated exploration and development costs in finding new reserves, production quantities and related production costs and oil and natural gas sales prices. Oil and natural gas prices have rebounded somewhat since last year resulting in increased revenues. On the other hand, drilling activity on the Company’s acreage remained low through the first nine months of fiscal 2010 and the Company accordingly experienced a decline in production. We have seen an increase in drilling during the last quarter of fiscal 2010 and are experiencing a shift in drilling activity toward oil and natural gas liquids-rich areas where the Company owns mineral acreage such as the Anadarko (Cana) Woodford Shale, Horizontal Granite Wash,

(22)


Table of Contents

Cleveland, Tonkawa and other areas in western Oklahoma. As of September 30, 2010, the Company had 32 working interest wells which were drilling or testing in which the Company owns an average 2.5% net revenue interest. Production from these wells, combined with other wells to be drilled in the oil and natural gas liquids-rich areas, is expected to provide an increase in production for 2011. Also, the first well in our internally generated Joiner City prospect, a horizontal Woodford Shale prospect in the oil and natural gas liquids-rich Marietta Basin in southern Oklahoma, is expected to be completed during the first quarter of 2011.
     Increased oil and natural gas prices, as well as drilling success during 2010, resulted in higher oil and natural gas reserves as of September 30, 2010. The increased reserves in turn resulted in lower DD&A and impairment costs during 2010.
     With the expected increase in drilling activity on our acreage during 2011, we expect additions to properties and equipment for oil and natural gas activities to significantly increase in 2011 compared to 2010. Additions to properties and equipment are distinct from capital expenditures in that these include cash and accrued additions; therefore, additions to properties and equipment represent amounts added to properties and equipment in the period, whereas capital expenditures represent amounts paid in the period. During 2010, we paid off all amounts borrowed under our credit facility and ended 2010 with a cash balance of approximately $5.6 million. The Company’s debt-free position, combined with its cash holdings, provides the resources for the Company to capitalize on the current increase in drilling on its acreage.
     The Company had no off balance sheet arrangements during 2010 or prior years.
     The following table reflects certain operating data for the periods presented:
                                         
    For the Year Ended September 30,
            Percent           Percent    
    2010   Incr. or (Decr.)   2009   Incr. or (Decr.)   2008
     
Production:
                                       
Oil (Bbls)
    102,379       -20 %     128,160       -3 %     132,402  
Natural Gas (Mcf)
    8,302,342       -9 %     9,109,988       31 %     6,928,038  
Mcfe
    8,916,616       -10 %     9,878,948       28 %     7,722,450  
Average Sales Price:
                                       
Oil (per Bbl)
  $ 72.83       41 %   $ 51.79       -50 %   $ 103.91  
Natural Gas (Mcf) (1)
  $ 4.41       30 %   $ 3.38       -58 %   $ 7.98  
Mcfe
  $ 4.94       30 %   $ 3.79       -58 %   $ 8.94  
 
(1)   Proceeds from the sale of natural gas liquids have been included in natural gas sales, and are therefore included in the price per Mcf of natural gas.
     Fiscal Year 2010 Compared to Fiscal Year 2009
     Overview
     The Company recorded net income of $11,419,690, or $1.36 per share, in 2010, compared to net loss of $2,405,021, or $.29 per share, in 2009. Increased revenues in 2010 were mainly from increases in oil and natural gas sales, gains on derivative contracts and lease bonuses. Higher oil and natural gas prices more than offset a 10% decrease in production resulting in increased oil and natural gas sales; actual and forward looking prices lower than the Company’s fixed price swap contracts resulted in gains on derivative contracts in 2010, compared to a loss in 2009; and the renewal of leases on most of the

(23)


Table of Contents

Company’s Arkansas undeveloped mineral acreage increased 2010 revenue from lease bonuses.
     The decrease in expenses is primarily related to lower DD&A and impairment costs, resulting from the increase in oil and natural gas reserves (as of September 30, 2010) which lowered the DD&A rate per Mcfe of production. In 2010, an income tax expense of $4,901,000 was incurred compared to a tax benefit of $2,568,000 recognized in 2009.
     Oil and Natural Gas (and associated natural gas liquids) Sales
     Oil and natural gas sales increased $6,647,259 or 18% for 2010 as compared to 2009. Despite a 10% decrease in oil and natural gas production, 2010 oil and natural gas sales went up approximately $6.6 million (compared to 2009) driven by higher oil and natural gas prices of 41% and 30%, respectively. The production decrease occurred as fewer new wells were drilled and put on line in 2010, thus the production decline of existing wells exceeded the production which came on line from new wells.
     Production by quarter for 2010 was as follows:
             
First quarter
    2,278,133  Mcfe
Second quarter
    2,090,154  Mcfe
Third quarter
    2,236,236  Mcfe
Fourth quarter
    2,312,093  Mcfe
 
         
Total
    8,916,616  Mcfe
 
         
     Drilling activity on our acreage was low through the first three quarters of 2010; however, well proposals and drilling have increased since. The new well proposals reflect a shift to oil and natural gas liquids-rich areas where the Company owns mineral acreage, such as the Anadarko (Cana) Woodford Shale, Horizontal Granite Wash, Cleveland, Tonkawa and other areas in western Oklahoma. Because of both the increase in wells being proposed and drilled on our acreage and the shift to oil and natural gas liquids-rich areas with improved well economics, we expect the Company’s production to increase in 2011.
     Lease Bonus and Rentals
     Lease bonus and rentals increased $931,768 for 2010 as compared to 2009. This increase was mostly due to the renewal of leases on most of the Company’s Arkansas undeveloped mineral acreage which increased 2010 revenue from lease bonuses approximately $723,000.
     Gains (Losses) on Natural Gas Derivative Contracts
     Realized and unrealized gains and losses are scheduled below:
                 
Gains (losses) on   Fiscal year  
derivative contracts   2010     2009  
Realized
  $ 2,209,900     $ 2,497,800  
Unrealized
    4,133,761       (3,159,628 )
 
           
Total
  $ 6,343,661       ($661,828 )
 
           

(24)


Table of Contents

     Lease Operating Expenses (LOE) and Production Taxes
     LOE increased $497,293 or 7% in 2010. LOE costs per Mcfe of production increased from $.78 in 2009 to $.92 in 2010. Increased natural gas prices, which increased value based fees (primarily gathering, transportation and marketing costs) caused total LOE and LOE per Mcfe to increase. Natural gas production from the southeast Oklahoma Woodford Shale, Anadarko (Cana) Woodford Shale and Fayetteville Shale areas continues to increase as a proportion of total production. Value based fees are charged as a percent of natural gas revenues and are significantly higher in these shale areas than like fees charged in other of the Company’s production areas. The total amount of value based fees in these three shale areas typically are 12% to 22% of total natural gas revenues. Value based fees increased $1,201,209, or 36%, in 2010 compared to 2009. Value based fees per Mcfe increased $.17, or 51%, in 2010 compared to 2009.
     The increase in value based fees is partially offset by a decrease of $703,916 in LOE related to field operating costs in 2010 compared to 2009, a 16% decrease. In 2010, field operating costs were $.38 per Mcfe compared to $.42 per Mcfe in 2009, a 9% decrease. These decreases are due to fewer new wells coming on line in 2010 with high initial LOE, fewer well repairs made in 2010 compared to 2009 and the fiscal 2009 sale of wells in the Southeast Leedey field and the McElmo Dome Unit, thus reducing fiscal 2010 LOE.
     Production taxes increased $245,336 or 20% in 2010. The increase is the result of increased sales of oil and natural gas. 2010 oil and natural gas sales increased 18%, and production taxes increased 20%, compared to 2009. Production taxes were 3.3% of oil and natural gas sales in 2010, compared to 3.2% in 2009. The low overall production tax rate is due to a large proportion of the Company’s natural gas revenues coming from horizontally drilled wells, which are eligible for either Oklahoma production tax credits or reduced Arkansas production tax rates.
     Exploration Costs
     Exploration costs were $1,583,773 in 2010 compared to $711,582 in 2009, an $872,191 increase. During 2010, leasehold impairment and expired leases totaled $1,191,598 compared to $634,918 during 2009, a $556,680 increase. Five exploratory dry holes incurred expenses of approximately $77,000 during 2009; one exploratory dry hole incurred expenses of approximately $5,000 during 2010.
     Also, the Company charged approximately $387,000 to exploration costs in 2010 related to geological and geophysical costs paid upon the execution of a joint exploration agreement with a privately held independent operator to explore for oil in eastern Oklahoma.
     Depreciation, Depletion and Amortization (DD&A)
     Total DD&A decreased $8,946,810 or 32% in 2010, while DD&A per Mcfe decreased to $2.16 in 2010 as compared to $2.85 in 2009. Approximately $2,744,000 of the DD&A decrease is the result of a 10% decrease in 2010 oil and natural gas production. The remaining DD&A decrease of approximately $6,203,000 is attributable to the $.69 decline in the DD&A rate per Mcfe. This rate declined as a result of increased proved developed oil and natural gas reserves as of September 30, 2010 (see Note 10 — Supplementary Information on Oil and Natural Gas Reserves), as compared to September 30, 2009, and a net reduction during fiscal year 2009 of approximately $3.1 million of asset basis subject to DD&A. This asset basis reduction occurred as fiscal 2009 DD&A and impairment, combined with the basis reduction associated with assets sold, exceeded new additions to properties and equipment for oil and natural gas activities.
     Provision for Impairment
     The provision for impairment decreased $1,858,905 in 2010 as compared to 2009. During 2010, impairment of $605,615 was recorded on seven fields. Approximately $380,000 of the impairment was

(25)


Table of Contents

related to the Buffalo Wallow field in Texas, where the first horizontal well in the field was recently drilled and completed with poor economic results. During 2009, impairment of $2,464,520 was recorded on 13 fields driven by depressed oil and natural gas prices, which negatively affected the estimates of future net revenues from oil and natural gas properties.
     Loss (Gain) on Asset Sales, Interest and Other
     In 2010, the Company received $1,124,682 from the settlement of a lawsuit related to one well in western Oklahoma. In 2009, the Company sold a portion of its working interest in the Southeast Leedey field and all of its working interest in the McElmo Dome CO2 Unit for a combined gain of approximately $2.5 million.
     General and Administrative Costs (G&A)
     G&A increased $728,455 or 15% in 2010 due to increases in the following expense categories: personnel $433,847; legal $161,016; board of directors $101,474; and insurance $87,350. Personnel expenses increased mainly because of higher accrued performance bonuses based on improved Company performance metrics in fiscal 2010 compared to 2009. Legal expense increased primarily due to legal costs of approximately $129,000 incurred during 2010 on a lawsuit related to one well in western Oklahoma. The addition of a new director, an increase in the number of Board meetings and increased director fees comprise the increase in board of directors’ expense in 2010.
     Bad Debt Expense (Recovery)
     On July 22, 2008, SemGroup, L.P. and certain subsidiaries (SemGroup) filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy code. On October 28, 2009, the U.S. Bankruptcy Court confirmed the Fourth Amended Joint Plan of Affiliated Debtors which set forth various settlement details for producers and interest owners. Based on the details of the plan, discussion with operators impacted and management’s judgment, the Company lowered the reserve for doubtful accounts to $405,129 at September 30, 2009, resulting in $186,129 of bad debt recovery. No adjustments were made in 2010 to the Company’s reserve for doubtful accounts.
     Provision (Benefit) for Income Taxes
     The 2010 provision for income taxes of $4,901,000 was a result of a pre-tax income of $16,320,690, as compared to a benefit for income taxes of $2,568,000 in 2009, resulting from a pre-tax loss of $4,973,021. The provision for income taxes increased in 2010 by $7,469,000, the result of a $21,293,711 increase in income (loss) before provision (benefit) for income taxes in 2010, compared to 2009, partially offset by the removal of the $278,000 valuation allowance on Oklahoma NOLs. The effective tax rate for 2010 was 30%, whereas the effective tax benefit rate for 2009 was 52%. The Company’s utilization of excess percentage depletion (which is a permanent tax benefit) decreased the provision for income taxes in 2010, whereas it increased the tax benefit in 2009. The effect of this permanent tax benefit is that the effective tax rate is decreased when recording a provision for income taxes as in 2010, while increasing the effective tax rate when recording a benefit for income taxes as in 2009. The benefit of excess percentage depletion is not directly related to the amount of recorded income or loss. Accordingly, in cases where the recorded income or loss is relatively small, the proportional effect of the excess percentage depletion on the effective tax rate may become significant. The reversal of the $278,000 valuation allowance on Oklahoma NOLs reduced the effective tax rate by 2% for 2010.

(26)


Table of Contents

     Liquidity and Capital Resources
     At September 30, 2010, the Company had positive working capital of $10,098,861, as compared to positive working capital of $3,436,692 at September 30, 2009.
ANALYSIS OF CHANGE IN WORKING CAPITAL
                         
    As of     As of        
    9/30/2010     9/30/2009     Change  
CURRENT ASSETS:
                       
Cash and cash equivalents (1)
  $ 5,597,258     $ 639,908     $ 4,957,350  
Oil and natural gas sales receivables (net)
    9,063,002       7,747,557       1,315,445  
Refundable production taxes (2)
    804,120       616,668       187,452  
Derivative contracts (3)
    1,481,527             1,481,527  
Deferred income taxes (4)
          1,934,900       (1,934,900 )
Other
    412,778       68,817       343,961  
 
                 
Total current assets
    17,358,685       11,007,850       6,350,835  
 
                 
 
                       
CURRENT LIABILITIES:
                       
Accounts payable
    5,062,806       4,810,687       252,119  
Derivative contracts (3)
          1,726,901       (1,726,901 )
Deferred income taxes
    354,100       53,100       301,000  
Accrued income taxes and other liabilities (5)
    1,842,918       980,470       862,448  
 
                 
Total current liabilities
    7,259,824       7,571,158       (311,334 )
 
                 
 
                       
WORKING CAPITAL
  $ 10,098,861     $ 3,436,692     $ 6,662,169  
 
                 
 
(1)   During 2010, cash provided by operating activities exceeded cash used in investing activities enabling the Company to pay off its line-of-credit during May 2010.
 
(2)   Refundable production taxes of approximately $759,000, previously reported as non-current, have now become current, thus increasing current refundable production taxes. This increase was partially offset by payments received during fiscal 2010 of approximately $518,000.
 
(3)   The Company’s current portion of fair value of derivative contracts has changed from a liability of $1,726,901 as of September 30, 2009, to an asset of $1,481,527 as of September 30, 2010, due to lower forward-looking natural gas prices as of September 30, 2010. The Company has received net payments relative to its derivative contracts of $2,209,900 during 2010.
 
(4)   Approximately $1,039,000 of the decrease in the current assets portion of deferred income taxes relates to expected utilization of the Company’s Alternative Minimum Tax (AMT) credit during fiscal 2010. The change from a liability to an asset in the unrealized value of the Company’s derivative contracts (as mentioned above) decreased the current asset portion of deferred income taxes approximately $896,000.
 
(5)   Income taxes payable increased $583,625 on higher net income before tax. Accrued liabilities for employee bonuses increased a combined $268,682.

(27)


Table of Contents

ANALYSIS OF CHANGE IN CASH PROVIDED BY OPERATING ACTIVITIES
                         
    12 months ended     12 months ended        
    9/30/2010     9/30/2009     Change  
 
                       
Net income (loss)
  $ 11,419,690     $ (2,405,021 )   $ 13,824,711  
 
                       
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
DD&A and impairment (1)
    19,827,738       30,633,453       (10,805,715 )
Provision for deferred income taxes (2)
    777,000       (3,814,000 )     4,591,000  
Exploration costs (3)
    1,208,653       711,582       497,071  
Net (gain) loss on asset sales and other (4)
    (1,189,605 )     (2,654,759 )     1,465,154  
Income from partnerships
    (405,134 )     (323,848 )     (81,286 )
Distributions received from partnerships
    523,317       432,805       90,512  
Other
    64,555       4,708       59,847  
Common stock contributed to ESOP
    287,194       245,811       41,383  
Common stock (unissued) to Directors’ Deferred Compensation Plan
    359,628       256,688       102,940  
Restricted stock awards
    12,028             12,028  
Bad debt expense (recovery)
          (185,272 )     185,272  
Cash provided by changes in assets and liabilities:
                       
Oil and natural gas sales receivables (5)
    (1,315,445 )     9,620,843       (10,936,288 )
Fair value of derivative contracts (6)
    (4,133,761 )     3,159,628       (7,293,389 )
Refundable income taxes (7)
          2,162,305       (2,162,305 )
Refundable production taxes (8)
    (69,874 )     (921,769 )     851,895  
Other current assets
    (343,961 )     74,455       (418,416 )
Accounts payable
    (24,896 )     287,883       (312,779 )
Income taxes payable (7)
    583,625       338,511       245,114  
Accrued liabilities
    225,723       86,603       139,120  
 
                 
Net cash provided by operating activities
  $ 27,806,475     $ 37,710,606     $ (9,904,131 )
 
                 
 
(1)   DD&A declined as a result of a decline in oil and natural gas production, increased oil and natural gas reserves and a net reduction during fiscal year 2009 in asset basis, as DD&A, impairment and basis in assets sold during 2009 exceeded additions to properties and equipment. An impairment of $605,615 was recorded in 2010, compared to $2,464,520 in 2009. For further discussion related to these items, see “Depreciation, Depletion and Amortization” and “Provision for Impairment” in Management’s Discussion and Analysis.
 
(2)   The deferred income tax expense change of $4,591,000 resulted from a provision for deferred income taxes during 2010 of $777,000, compared to a deferred income tax benefit of $3,814,000 during 2009. Deferred income tax provisions or benefits are primarily related to expenditures for intangible drilling costs, which are expensed for tax purposes in the year incurred, but amortized over the life of the oil and natural gas properties for financial purposes, thus creating an income tax timing difference. Levels of expenditures for intangible drilling costs in relation to the before tax income or loss were significantly less in 2010 than in 2009.

(28)


Table of Contents

(3)   Leases expired or impaired during 2010 exceeded those expired or impaired during 2009 by approximately $557,000.
 
(4)   In 2010, we received $1,124,682 from the settlement of a lawsuit related to one well in western Oklahoma. In 2009, the Company sold a portion of its working interest in the Southeast Leedey field and all of its working interest in the McElmo Dome CO2 Unit for a combined gain of approximately $2.5 million.
 
(5)   For the year ending September 30, 2010, oil and natural gas sales receivables increased due to higher average oil and natural gas prices; whereas, through September 30, 2009, oil and natural gas sales receivables had decreased primarily as a result of lower average oil and natural gas prices. The net change to cash provided by operating activities was a decrease of $10,936,288; as receivables collected during 2009 exceeded those collected during 2010.
 
(6)   During 2010, the Company had an unrealized gain related to derivative contracts of $4,133,761. During 2009, we had an unrealized loss related to derivative contracts of $3,159,628.
 
(7)   During 2010, income taxes payable increased $583,625; whereas, during 2009 income taxes payable increased $338,511 resulting in a positive impact to net cash provided by operating activities of $245,114. Refundable income taxes did not change during 2010 and decreased $2,162,305 (primarily due to refund payments of approximately $2.2 million) during 2009. Refundable income taxes and income taxes payable overall had a negative effect change of $1,917,191 in 2010 compared to 2009.
 
(8)   During 2010, we received payment of approximately $552,000 of refundable production taxes, which were reflected as a receivable at September 30, 2009.
     Additions to properties and equipment for oil and natural gas activities during 2010 were $11,585,521 ($28,540,290 in 2009). Average natural gas prices during 2010 were higher than 2009; yet drilling activity on our acreage did not increase until the fourth quarter of 2010. With this increase in drilling, we are experiencing a shift in drilling activity toward oil and natural gas liquids-rich areas where the Company owns significant mineral acreage such as the Anadarko (Cana) Woodford Shale, Horizontal Granite Wash, Cleveland, Tonkawa and other plays in western Oklahoma. As of September 30, 2010, the Company had 32 working interest wells which were drilling or testing in which the Company owns an average 2.5% net revenue interest. Production from these wells combined with other wells to be drilled in the oil and natural gas liquids-rich areas during 2011 is expected to result in a production increase in 2011, compared to 2010.
     Also, the first well in our internally generated Joiner City prospect, a horizontal Woodford Shale prospect in the oil and natural gas liquids-rich Marietta Basin in southern Oklahoma, is expected to be completed during the first quarter of 2011. The Company owns 2,557 acres, or approximately 6.7% of 60 sections (or drilling units), within the prospect. Due to the increase in drilling activity on our acreage, management currently projects 2011 properties and equipment additions to be approximately $27 million, compared to approximately $12 million during 2010.
     However, due to the Company not being the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of participation in drilling and completing new wells, and associated capital expenditures, with certainty.
     For 2010, cash provided by operating activities was $27,806,475, well in excess of capital expenditures of $11,308,506. This excess allowed us to reduce bank debt by $10,384,722, which paid off

(29)


Table of Contents

the Company’s line-of-credit during May 2010. Looking forward, the Company expects to fund capital additions, overhead costs and dividend payments primarily from cash provided by operating activities. However, during times of oil and natural gas price decreases, or increased expenditures for drilling, the Company has utilized its revolving line-of-credit facility in the past to help fund these expenditures. The Company’s continued drilling activity, combined with normal delays in receiving first payments from new production, could result in future borrowings under the Company’s credit facility. The Company has availability ($35 million at September 30, 2010) under its revolving credit facility and also is in compliance on its debt covenants (current ratio, debt to EBITDA, tangible net worth and dividends as a percent of operating cash flow). While the Company believes the availability could be increased (if needed) by placing more of the Company’s properties as security under the revolving credit facility, increases are at the discretion of the bank.
     Contractual Obligations and Commitments
     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 is $35,000,000. The revolving loan matures on October 31, 2012. Borrowings under the revolving loan are due at maturity. The revolving loan bears interest at the national prime rate plus a range of .50% to 1.25%, or 30 day LIBOR plus a range of 2.00% to 2.75% annually. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced.
     Determinations of the borrowing base are made semi-annually or whenever BOK believes there has been a material change in the value of the Company’s oil and natural gas properties. The loan agreement contains customary covenants, which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2010, the Company was in compliance with these covenants.
     The table below summarizes the Company’s contractual obligations and commitments as of September 30, 2010:
                                         
    Payments due by period
Contractual Obligations           Less than                   More than
and Commitments   Total   1 Year   1-3 Years   3-5 Years   5 Years
Long-term debt obligations
  $     $     $     $     $  
 
                                       
Building lease
  $ 323,141     $ 204,089     $ 119,052     $     —     $     —  
     At September 30, 2010, the Company’s derivative contracts were in a net asset position of $1,620,326. The ultimate settlement amounts of the derivative contracts are unknown because they are subject to continuing market risk. Please read Item 7A — “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 of Notes to Consolidated Financial Statements included in Item 8 — “Financial Statements and Supplementary Data” for additional information regarding the derivative contracts.
     As of September 30, 2010, the Company’s asset retirement obligations were $1,730,369. Asset retirement obligations represent the Company’s share of the future expenditures to plug and abandon the wells in which the Company owns a working interest when the oil and natural gas reserves are depleted. Please read Note 1 of Notes to Consolidated Financial Statements included in Item 8 — “Financial Statements and Supplementary Data” for additional information regarding the Company’s asset retirement obligations.

(30)


Table of Contents

     Fiscal Year 2009 Compared to Fiscal Year 2008
     Overview
     The Company recorded a net loss of $2,405,021, or $.29 per share, in 2009, compared to net income of $21,555,769, or $2.54 per share, in 2008. Lower oil and natural gas prices during 2009 resulted in significantly lower total revenues in 2009 as compared to 2008, notwithstanding substantially increased production volumes. Total expenses increased in 2009 over 2008 as there were significant increases in DD&A and provision for impairment, which were partially offset by decreases in lease operating expenses and production taxes, general and administrative expenses and bad debt expense. An income tax benefit of approximately $2.6 million was incurred in 2009, whereas approximately $10.9 million of income tax expense was recognized in 2008.
     Oil and Natural Gas (and associated natural gas liquids) Sales
     Oil and natural gas sales decreased $31,605,096 or 46% for 2009 as compared to 2008. The decrease in oil and natural gas sales was largely due to a 50% decrease in oil prices and a 58% decrease in natural gas prices, partially offset by a 28% increase in production on a Mcfe basis. Production increased even though 2009 additions to properties and equipment for oil and natural gas activities decreased significantly compared to 2008. This occurred because many wells in which the Company owned significant working interests (as high as 42%) came on line in the latter half of 2008 and in the first quarter of 2009 (resulting in nearly a full year’s production being recorded in 2009). The majority of new production which came on line in 2009 was from wells in the Woodford Shale in southeast Oklahoma and the Fayetteville Shale in Arkansas.
     Production by quarter for 2009 was as follows:
         
First quarter
    2,495,299  Mcfe
Second quarter
    2,380,124  Mcfe
Third quarter
    2,647,474  Mcfe
Fourth quarter
    2,356,051  Mcfe
 
     
Total
    9,878,948  Mcfe
 
     
     Gains (Losses) on Natural Gas Derivative Contracts
     Realized and unrealized gains and losses are scheduled below:
                 
Gains (losses) on   Fiscal year  
derivative contracts   2009     2008  
Realized
  $ 2,497,800       ($1,480,100 )
Unrealized
    (3,159,628 )     539,277  
 
           
Total
    ($661,828 )     ($940,823 )
 
           
     Lease Operating Expenses (LOE) and Production Taxes
     LOE increased $1,066,856 or 16% in 2009. LOE costs per Mcfe of production decreased from $.86 in 2008 to $.78 in 2009. As a result of continued drilling and completion of new wells, the Company’s ownership of net wells increased. This increase in well ownership combined with high initial LOE on newly completed wells resulted in increased overall LOE costs. However, certain LOE costs such as transportation, compression and marketing of natural gas decreased dramatically on a per Mcfe basis due to the much lower natural gas sales prices on which these expenses were calculated (on a

(31)


Table of Contents

percentage basis). These lower expenses plus the significant increase in total Mcfe production lowered per Mcfe costs.
     Production taxes decreased $2,225,383 or 65% in 2009. The decrease was primarily the result of significantly lower oil and natural gas sales in 2009, as production taxes are paid as a percentage of sales. However, the decrease was not proportional to the sales decrease due to new horizontal wells which came on line in Arkansas and Oklahoma which qualified for production tax credits or lower production tax rates from these states. These horizontally drilled wells are primarily in the Woodford Shale play in southeast Oklahoma and the Fayetteville Shale play in Arkansas.
     Exploration Costs
     Exploration costs were $711,582 in 2009 compared to $455,943 in 2008, a $255,639 increase. Expired, impaired or abandoned leasehold costs charged to exploration costs in 2009 were $169,564 more than in 2008. Five exploratory dry holes (in which the Company had very small working interests) were drilled in 2009 compared to none during 2008 resulting in an $86,075 increase in exploration costs related to exploratory dry holes.
     Depreciation, Depletion and Amortization (DD&A)
     Total DD&A increased $8,384,273 or 42% in 2009, while DD&A per Mcfe increased to $2.85 in 2009 as compared to $2.56 in 2008. The 28% increase in total Mcfe produced in 2009, as compared to the 2008 period, accounted for approximately $5.5 million of the overall DD&A increase. The remaining increase of approximately $2.9 million was attributable to the increase in DD&A per Mcfe which was related to lower oil and natural gas reserve volumes per well resulting from lower oil and natural gas prices (expected reserves per well decrease when oil and natural gas prices decline as the lower prices result in wells reaching their economic limits earlier in time, thus shortening the wells’ economic lives and increasing the DD&A rate per Mcfe of production), and the substantially higher drilling and completion costs for horizontally drilled wells, primarily in the Woodford and Fayetteville Shale areas. These same wells also accounted for the majority of the 2009 increase in natural gas production.
     Provision for Impairment
     The provision for impairment increased $1,938,140 in 2009 as compared to 2008. In 2009, thirteen fields were impaired $2,433,652, whereas in 2008 seven fields were impaired $514,180. The amount and number of fields impaired increased in 2009 as lower oil and natural gas price projections were used to calculate oil and natural gas reserves and future net cash flows as compared to 2008. These lower price projections resulted in lower future net cash flows and lower estimated fair value, which is used to test each field for impairment.
     Loss (Gains) on Asset Sales, Interest and Other
     During 2009, the Company sold a portion of its interest in the Southeast Leedey Field in Oklahoma and all of its interest in the McElmo Dome Unit in Colorado, the Company’s sole source of CO2 production. The total proceeds from the 2009 sale of these interests were approximately $3.4 million; the combined gain was approximately $2.5 million, whereas approximately $16,000 was recorded as gain on sale of assets in 2008. Loss on sale of assets decreased $204,189 in 2009 as compared to 2008. Two low performing wells in western Oklahoma were sold in 2008 at a loss, while none were sold at a loss in 2009.

(32)


Table of Contents

     General and Administrative Costs (G&A)
     G&A decreased $140,468 or 3% in 2009 due to decreased personnel related costs of approximately $229,000, which included a decrease in employee bonus costs of approximately $500,000 in the 2009 period (the result of beginning to ratably accrue for estimated 2008 annual employee bonuses during the 2008 fiscal period due to specific bonus performance criteria being established plus recording the full 2007 annual discretionary bonuses approved and paid during the 2008 fiscal period), partially offset by increases in legal fees of approximately $106,000.
     Bad Debt Expense (Recovery)
     Bad debt expense decreased $776,530 in 2009 as compared to 2008. 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 represented over 80% of the total amount owed the Company directly and indirectly, through the operators of the affected wells where SemGroup was the purchaser of oil. On October 28, 2009, the U.S. Bankruptcy Court confirmed the Fourth Amended Joint Plan of Affiliated Debtors which set forth various settlement details for producers and interest owners. Based on the details of the plan, discussion with operators impacted and management’s judgment, the Company lowered the reserve for doubtful accounts to $405,129 at September 30, 2009, resulting in $186,129 of bad debt recovery.
     Provision (Benefit) for Income Taxes
     In 2009, the Company recorded a benefit for income taxes of $2,568,000 as a result of a pre-tax loss of $4,973,021 as compared to a provision for income taxes of $10,894,302 in the 2008 period as a result of pre-tax income of $32,450,071. The resulting effective tax benefit rate in 2009 was 52% as compared to an effective tax provision rate of 34% in 2008. The Company’s utilization of excess percentage depletion (which is a permanent tax benefit) increased the tax benefit in the 2009 period, whereas it decreased the provision for income taxes in the 2008 period. The effect of this permanent tax benefit is that the effective tax rate is increased when recording a benefit for income taxes as in the 2009 period, while reducing the effective tax rate when recording a provision for income taxes as in the 2008 period. The benefit of excess percentage depletion is not directly related to the amount of a recorded loss or income. Accordingly, in cases where a recorded loss or income is relatively small, the proportional effect of the excess percentage depletion on the effective tax rate may become significant.
     With the decline in prices and the loss in 2009, the Company established a valuation allowance on certain state tax net operating loss carryforwards (NOLs) for which the Company no longer believed were more likely than not to be realized prior to expiration. This reduced the benefit recognized during 2009 by $278,000.
CRITICAL ACCOUNTING POLICIES
     Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change the Company’s reported cash flows or liquidity. Existing rules must be interpreted and judgments made on how the specifics of a given rule apply to the Company.
     The more significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimation, derivative contracts, impairment of assets, oil and natural gas sales revenue accruals, refundable production taxes and provision for income tax. Management’s

(33)


Table of Contents

judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists, consultants and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. The oil and natural gas sales revenue accrual is particularly subject to estimate inaccuracies due to the Company’s status as a non-operator on all of its properties. As such, production and price information obtained from well operators is substantially delayed. This causes the estimation of recent production and prices used in the oil and natural gas revenue accrual to be subject to future change.
     Oil and Natural Gas Reserves
     Management considers the estimation of the Company’s crude oil and natural gas reserves to be the most significant of its judgments and estimates. 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 DD&A, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing prices current with the period. As of September 30, 2010, the Company adopted the new SEC Rule, Modernization of Oil and Gas Reporting Requirements. In accordance with the new SEC rule, the estimated oil and natural gas reserves at September 30, 2010, were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil and natural gas price for each month within the 12-month period prior to September 30, 2010, held flat over the life of the properties. In accordance with SEC rules effective in fiscal years 2008 and 2009, current pricing of oil and natural gas on September 30, 2008 and 2009, held flat over the life of the properties was used to estimate oil and natural gas reserves as of September 30, 2008 and 2009. Based on the Company’s 2010 DD&A, a 10% change in the DD&A rate per Mcfe would result in a corresponding $1,922,212 annual change in DD&A expense. Crude oil and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. However, projected future crude oil and natural gas pricing assumptions are used by management to prepare estimates of crude oil and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.
     Successful Efforts Method of Accounting
     The Company has elected to utilize the successful efforts method of accounting for its oil and natural gas exploration and development activities. Exploration expenses, including geological and geophysical costs, non producing lease impairment, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by property using the unit-of-production method as oil and natural gas is produced. The Company’s exploratory wells are all on-shore and primarily located in the mid-continent area. Generally, expenditures on exploratory wells comprise significantly less than 10% of the Company’s total expenditures for oil and natural gas properties. This accounting method may yield significantly different operating results than the full cost method.
     Derivative contracts
     The Company entered into costless collar arrangements (all of which expired in first quarter 2009), fixed swap contracts and basis protection swaps. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. Fixed swap contracts set a

(34)


Table of Contents

fixed price and provide for payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s natural gas production and provide only partial price protection against declines in natural gas prices. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL currently). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are unsecured.
     The Company is required to recognize all derivative instruments as either assets or liabilities in the 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, 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 in current 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. At September 30, 2010, the Company had no derivative contracts designated as cash flow hedges.
     Impairment of Assets
     All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil and natural gas, future production costs, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The Company estimates future net cash flows on its oil and natural gas properties utilizing differentially adjusted forward pricing curves for both oil and natural gas and a discount rate in line with the discount rate we believe is most commonly used by the market participants (currently 10%). The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil and natural gas reserves. A significant reduction in oil and natural gas prices (which are reviewed quarterly) or a decline in reserve volumes (which are re-evaluated semi-annually) would likely lead to additional impairment that may be material to the Company. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.
     Non-producing oil and natural gas leases are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when recognized. As of September 30, 2010, the remaining carrying cost of non-producing oil and natural gas leases was $786,976.

(35)


Table of Contents

     Oil and Natural Gas Sales Revenue Accrual
     The Company does not operate any of its oil and natural gas properties and, therefore, receives actual oil and natural gas sales volumes and prices (in the normal course of business) over a month later than the information is available to the operators of the wells. This being the case, on many of these wells, the most current available production data is gathered from the appropriate operators, and oil and natural gas index prices local to each well are used to estimate the accrual of revenue on these wells. Timely obtaining production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The oil and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil and natural gas. These variables could lead to an over or under accrual of oil and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.
     Income Taxes
     The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at the end of each fiscal year. During interim periods, a high-level estimate is made taking into account historical data and current pricing. The Company has certain state net operating loss carryforwards (NOLs) that are recognized as tax assets when assessed as more likely than not to be utilized before their expiration dates. Criteria such as expiration dates, future excess state depletion and reversing taxable temporary differences are evaluated to determine whether the NOLs are more likely than not to be utilized before they expire. If any NOLs are determined to no longer be more likely than not to be utilized, then a valuation allowance is recognized to reduce the tax benefit of such NOLs. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.
     Refundable Production Taxes Accrual
     The state of Oklahoma allows for refunds of production taxes on wells that are horizontally drilled. In order to qualify as a horizontally drilled well, the well “has completed in a manner which encounters and subsequently produces from a geological formation at an angle in excess of seventy (70) degrees from the vertical and which laterally penetrates a minimum of one hundred and fifty (150) feet into the pay zone of the formation.” An operator has 18 months after a given tax year to file the appropriate forms with the Oklahoma Tax Commission (OTC) requesting the refund of production taxes. The refund is limited to 48 months from first sales or well payout, whichever comes first. Horizontal drilling in Oklahoma over the past four years has resulted in the addition of numerous wells that qualify for the Oklahoma horizontal exemption, thus increasing the Company’s oil and natural gas sales subject to the accrual.
     The Company does not operate any of its oil and natural gas properties and thus must rely on oil and natural gas sales and drilling information from the operators. The Company utilizes payment remittances from operators to estimate its refundable production tax accrual at the end of each quarterly period. The refundable production tax accrual can be impacted by many variables, including subsequent revenue adjustments received from operators and an operator’s failure to file timely with the OTC requesting refunds. These variables could lead to an over or under accrual of production taxes at the end

(36)


Table of Contents

of any particular period. Based on historical experience, the estimated accrual has been materially accurate.
     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
     Market Risk
     Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of natural gas and oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in oil or natural gas liquids prices. Longer term natural gas prices will be determined by the supply of and demand for natural gas as well as the prices of competing fuels, such as crude oil and coal. The market price of natural gas, oil and natural gas liquids in 2011 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2011 natural gas derivative contracts (see below), based on the Company’s estimated natural gas volumes for 2011, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $855,000 for pre-tax operating income. Based on the Company’s estimated oil volumes for 2011, the price sensitivity in 2011 for each $1.00 per barrel change in wellhead oil is approximately $123,000 for pre-tax operating income.
     Commodity Price Risk
     The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas prices. The Company does not enter into these derivatives for speculative or trading purposes. As of September 30, 2010, the Company has fixed swap contracts and basis protection swaps (Refer to the “Derivatives” section of Note 1 for more detail) in place. All of our outstanding derivative contracts are with one counterparty and are unsecured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These derivative contracts may expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s fixed price swaps as of September 30, 2010, the sensitivity of a $0.10 per Mcf change in the indexed pipelines (CEGT and PEPL) futures price is approximately $90,000 for pre-tax operating income. For the Company’s basis protection swaps as of September 30, 2010, the sensitivity of a $.10 per MCF change in differential between NYMEX and the indexed pipelines (CEGT and PEPL) futures prices is approximately $453,000 for pre-tax operating income.
     Financial Market Risk
     Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities. The revolving loan bears interest at the national prime rate plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. At September 30, 2010, the Company had $0 outstanding under these facilities. At this point, the company doesn’t believe that it’s liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that it’s liquidity will be impacted in the near future.

(37)


 


Table of Contents

Management’s Annual Report on Internal Control Over Financial Reporting
     Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934 (the “Exchange Act”) as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:
    Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;
 
    Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
 
    Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
     The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2010. 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, 2010, the Company’s internal control over financial reporting was effective based on those criteria.
     Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. This report appears on the following page.

(39)


Table of Contents

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, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Panhandle Oil and Gas Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Panhandle Oil and Gas Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2010, 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, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2010 and our report dated December 9, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Oklahoma City, Oklahoma
December 9, 2010

(40)


Table of Contents

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, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2010. 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, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2010, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, in 2010 Panhandle Oil and Gas Inc. has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
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, 2010, 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 9, 2010, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Oklahoma City, Oklahoma
December 9, 2010

(41)


Table of Contents

Panhandle Oil and Gas Inc.
Consolidated Balance Sheets
                 
    September 30,
    2010   2009
Assets
               
Current Assets:
               
Cash and cash equivalents
  $ 5,597,258     $ 639,908  
Oil and natural gas sales receivables, net of allowance for uncollectible accounts
    9,063,002       7,747,557  
Deferred income taxes
          1,934,900  
Refundable production taxes
    804,120       616,668  
Derivative contracts
    1,481,527        
Other
    412,778       68,817  
     
Total current assets
    17,358,685       11,007,850  
 
               
Properties and equipment at cost, based on successful efforts accounting:
               
Producing oil and natural gas properties
    207,928,578       198,076,244  
Non-producing oil and natural gas properties
    9,616,330       10,332,537  
Furniture and fixtures
    656,889       578,460  
     
 
    218,201,797       208,987,241  
 
               
Less accumulated depreciation, depletion, and amortization
    131,983,249       112,900,027  
     
Net properties and equipment
    86,218,548       96,087,214  
 
               
Investments
    754,208       682,391  
 
               
Derivative contracts
    138,799        
 
               
Refundable production taxes
    654,599       772,177  
     
Total assets
  $ 105,124,839     $ 108,549,632  
     
(Continued on next page)
See accompanying notes.

(42)


Table of Contents

Panhandle Oil and Gas Inc.
Consolidated Balance Sheets
                 
    September 30,
    2010   2009
Liabilities and Stockholders’ Equity
               
Current Liabilities:
               
Accounts payable
  $ 5,062,806     $ 4,810,687  
Derivative contracts
          1,726,901  
Deferred income taxes
    354,100       53,100  
Accrued income taxes and other liabilities
    1,842,918       980,470  
     
Total current liabilities
    7,259,824       7,571,158  
 
               
Long-term debt
          10,384,722  
 
               
Deferred income taxes
    22,552,650       24,064,650  
 
               
Asset retirement obligations
    1,730,369       1,620,225  
 
               
Derivative contracts
          786,534  
 
               
Stockholders’ equity:
               
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at September 30, 2010 and 2009
    140,524       140,524  
Capital in excess of par value
    1,816,365       1,922,053  
Deferred directors’ compensation
    2,222,127       1,862,499  
Retained earnings
    73,599,733       64,507,547  
     
 
    77,778,749       68,432,623  
 
               
Treasury stock, at cost; 120,560 shares at September 30, 2010, and 119,866 shares at September 30, 2009
    (4,196,753 )     (4,310,280 )
     
Total stockholders’ equity
    73,581,996       64,122,343  
     
 
               
Total liabilities and stockholders’ equity
  $ 105,124,839     $ 108,549,632  
     
See accompanying notes.

(43)


Table of Contents

Panhandle Oil and Gas Inc.
Consolidated Statements of Operations
                         
    Year ended September 30,
    2010   2009   2008
     
Revenues:
                       
Oil and natural gas (and associated natural gas liquids) sales
  $ 44,068,947     $ 37,421,688     $ 69,026,785  
Lease bonuses and rentals
    1,120,674       188,906       167,559  
Gains (losses) on derivative contracts
    6,343,661       (661,828 )     (940,823 )
Income from partnerships
    405,134       323,848       631,891  
     
 
    51,938,416       37,272,614       68,885,412  
Costs and expenses:
                       
Lease operating expenses and production taxes
    9,639,864       8,897,235       10,055,762  
Exploration costs
    1,583,773       711,582       455,943  
Depreciation, depletion, and amortization
    19,222,123       28,168,933       19,784,660  
Provision for impairment
    605,615       2,464,520       526,380  
Loss (gain) on asset sales, interest and other
    (1,028,148 )     (2,677,407 )     14,826  
General and administrative
    5,594,499       4,866,044       5,006,512  
Bad debt expense (recovery)
          (185,272 )     591,258  
     
 
    35,617,726       42,245,635       36,435,341  
     
Income (loss) before provision (benefit) for income taxes
    16,320,690       (4,973,021 )     32,450,071  
Provision (benefit) for income taxes
    4,901,000       (2,568,000 )     10,894,302  
     
 
                       
Net income (loss)
  $ 11,419,690     $ (2,405,021 )   $ 21,555,769  
     
 
                       
Basic and diluted earnings per common share:
                       
Net income (loss)
  $ 1.36     $ (0.29 )   $ 2.54  
     
See accompanying notes.

(44)


Table of Contents

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, 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 common shares to ESOP
                (56,001 )                 7,640       274,734       218,733  
Common shares to be issued 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  
 
                                                               
Issuance of treasury shares to ESOP
                (168,017 )                 11,508       413,828       245,811  
Common shares to be issued to directors for services
                      256,688                         256,688  
Dividends declared ($.28 per share)
                            (2,324,036 )                 (2,324,036 )
Net loss
                            (2,405,021 )                 (2,405,021 )
     
 
                                                               
Balances at September 30, 2009
    8,431,502     $ 140,524     $ 1,922,053     $ 1,862,499     $ 64,507,547       (119,866 )   $ (4,310,280 )   $ 64,122,343  
 
                                                               
Purchase of treasury stock
                                  (12,326 )     (291,383 )     (291,383 )
Issuance of treasury shares to ESOP
                (117,716 )                 11,632       404,910       287,194  
Restricted stock awards
                12,028                               12,028  
Common shares to be issued to directors for services
                      359,628                         359,628  
Dividends declared ($.28 per share)
                            (2,327,504 )                 (2,327,504 )
Net income
                            11,419,690                   11,419,690  
     
 
                                                               
Balances at September 30, 2010
    8,431,502     $ 140,524     $ 1,816,365     $ 2,222,127     $ 73,599,733       (120,560 )   $ (4,196,753 )   $ 73,581,996  
     
See accompanying notes.

(45)


Table of Contents

Panhandle Oil and Gas Inc.
Consolidated Statements of Cash Flows
                         
    Year ended September 30,
    2010   2009   2008
     
Operating Activities
                       
 
                       
Net income (loss)
  $ 11,419,690     $ (2,405,021 )   $ 21,555,769  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
Depreciation, depletion, amortization and impairment
    19,827,738       30,633,453       20,311,040  
Provision for deferred income taxes
    777,000       (3,814,000 )     9,116,000  
Exploration costs
    1,208,653       711,582       455,943  
Net (gain) loss on sales of assets
    (1,189,605 )     (2,654,759 )     20,632  
Income from partnerships
    (405,134 )     (323,848 )     (631,891 )
Distributions received from partnerships
    523,317       432,805       724,765  
Other
    64,555       4,708        
Common stock contributed to ESOP
    287,194       245,811       218,733  
Common stock (unissued) to Directors’ Deferred Compensation Plan
    359,628       256,688       247,033  
Restricted stock awards
    12,028              
Bad debt expense (recovery)
          (185,272 )     591,258  
Cash provided (used) by changes in assets and liabilities:
                       
Oil and natural gas sales receivables
    (1,315,445 )     9,620,843       (9,671,136 )
Fair value of dervative contracts
    (4,133,761 )     3,159,628       (539,277 )
Refundable income taxes
          2,162,305       (2,162,305 )
Refundable production taxes
    (69,874 )     (921,769 )     (467,076 )
Other current assets
    (343,961 )     74,455       (25,927 )
Accounts payable
    (24,896 )     287,883       59,921  
Income taxes payable
    583,625       338,511       (211,155 )
Accrued liabilities
    225,723       86,603       471,569  
     
Total adjustments
    16,386,785       40,115,627       18,508,127  
     
Net cash provided by operating activities
    27,806,475       37,710,606       40,063,896  
 
                       
Investing Activities
                       
Capital expenditures, including dry hole costs
    (11,308,506 )     (39,915,051 )     (38,747,749 )
Proceeds from leasing of fee mineral acreage
    1,316,377       209,930       200,356  
Investments in partnerships
    (254,555 )     (59,742 )     (139,177 )
Proceeds from sales of assets
    401,168       3,441,871       840,398  
     
Net cash used in investing activities
    (9,845,516 )     (36,322,992 )     (37,846,172 )
(Continued on next page)

(46)


Table of Contents

Panhandle Oil and Gas Inc.
Consolidated Statements of Cash Flows (continued)
                         
    Year ended September 30,
      2010     2009     2008
     
Financing Activities
                       
 
                       
Borrowings under debt agreement
  $ 10,799,814     $ 49,027,225     $ 47,281,411  
Payments of loan principal
    (21,184,536 )     (48,346,603 )     (42,238,782 )
Purchases of treasury stock
    (291,383 )           (4,998,842 )
Payments of dividends
    (2,327,504 )     (2,324,036 )     (2,355,163 )
     
Net cash used in financing activities
    (13,003,609 )     (1,643,414 )     (2,311,376 )
     
Increase (decrease) in cash and cash equivalents
    4,957,350       (255,800 )     (93,652 )
Cash and cash equivalents at beginning of year
    639,908       895,708       989,360  
     
Cash and cash equivalents at end of year
  $ 5,597,258     $ 639,908     $ 895,708  
     
 
                       
Supplemental Disclosures of Cash Flow Information
                       
 
                       
Interest paid (net of capitalized interest)
  $ 60,912     $     $ 23,212  
Income taxes paid, net of refunds received
  $ 3,530,718     $ (1,261,808 )   $ 4,145,122  
 
                       
Supplemental schedule of noncash investing and financing activities:
                       
Additions and revisions, net, to asset retirement obligations
  $ 110,144     $ 95,076     $ 151,998  
 
                       
Gross additions to properties and equipment
  $ 11,585,521     $ 28,540,290     $ 52,812,138  
Net (increase) decrease in accounts payable for properties and equipment additions
    (277,015 )     11,374,761       (14,064,389 )
 
                 
Capital expenditures, including dry hole costs
  $ 11,308,506     $ 39,915,051     $ 38,747,749  
See accompanying notes.

(47)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements
September 30, 2010, 2009 and 2008
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
     Nature of Business
     Since its formation, the Company has been involved in the acquisition and management of fee mineral acreage and the exploration for, and development of, oil and natural gas properties, principally involving drilling wells located on the Company’s mineral acreage. Panhandle’s mineral properties and other oil and natural gas interests are all located in the United States, primarily in Arkansas, Kansas, New Mexico, North Dakota, Oklahoma and Texas. The Company is not the operator of any wells. The majority of the Company’s oil and natural gas production is from interests in 4,989 wells located principally in Oklahoma. Approximately 83% of oil and natural gas revenues are derived from the sale of natural gas. Substantially all the Company’s oil and natural gas production is sold through the operators of the wells. The Company from time to time disposes of certain non-material, non-core or small-interest oil and natural gas properties as a normal course of business.
     Principles of Consolidation and Basis of Presentation
     The consolidated financial statements include the accounts of Panhandle Oil and Gas Inc. and its wholly-owned subsidiaries after elimination of all material intercompany transactions.
     Certain amounts (refundable production taxes, investment in partnerships, deferred income taxes and gain on asset sales, interest and other) in the prior year have been reclassified to conform to the current year presentation.
     Use of Estimates
     Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
     Of these estimates and assumptions, management considers the estimation of crude oil and natural gas reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (DD&A) and impairment calculations. On an annual basis, with a limited scope semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, 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. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the 2010 estimate was based on the average price during the 12-month period prior to September 30, 2010, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. Oil and natural gas prices used for the 2008 and 2009 estimates were based on the September 30 price of each respective year. For impairment purposes, projected future crude oil and natural gas prices as estimated by management are used. 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

(48)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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.
     The Company does not operate any of its oil and natural gas properties and, therefore, receives actual oil and natural gas sales volumes and prices (in the normal course of business) over a month later than the information is available to the operators of the wells. This being the case, on many of these wells, the most current available production data is gathered from the appropriate operators, and oil and natural gas index prices local to each well are used to estimate the accrual of revenue on these wells. Timely obtaining production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The oil and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil and natural gas. These variables could lead to an over or under accrual of oil and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.
     Cash and Cash Equivalents
     Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.
     Oil and Natural Gas (and associated natural gas liquids) Sales and Natural Gas Imbalances
     The Company sells oil and natural gas to various customers, recognizing revenues as oil and natural gas is produced and sold. Charges for compression, marketing, gathering and transportation of natural gas are included in lease operating expenses and production taxes.
     The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a reservoir cannot be recouped through the production of remaining reserves. At September 30, 2010 and 2009, the Company had no material natural gas imbalances.
     Concentration of Credit Risk
     Substantially all of the Company’s accounts receivable are due from purchasers of oil and natural gas or operators of the oil and natural gas properties. Oil and natural gas sales receivables are generally unsecured.
     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. As a result of the filing, the Company reserved $591,258 of receivables as uncollectible for substantially all of the sales of crude oil through various well operators to SemGroup during the period June 1, 2008 through July 22, 2008. The amount reserved was charged to bad debt expense in 2008. On October 28, 2009, the U.S. Bankruptcy Court confirmed the Fourth Amended Joint Plan of Affiliated Debtors, which set forth various settlement details for producers and interest owners. Based on the details of the plan, discussion with impacted

(49)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
operators and management’s judgment, the Company has lowered the reserve for doubtful accounts to $405,129 at September 30, 2009, resulting in $186,129 of bad debt recovery.
    Derivative contracts entered into by the Company are also unsecured.
     Oil and Natural Gas Producing Activities
     The Company follows the successful efforts method of accounting for oil and natural gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income if and when the well is determined to be nonproductive. Oil and natural gas mineral and leasehold costs are capitalized when incurred.
     Non-producing oil and natural gas leases are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when recognized. As of September 30, 2010, the remaining carrying cost of non-producing oil and natural gas leases was $786,976.
     It is common business practice in the petroleum industry for drilling costs to be prepaid before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2010, the Company had outstanding letters of credit totaling $57,051 that expired in November 2010.
     Derivatives
     The Company entered into costless collar contracts (all of which expired in first quarter 2009), fixed swap contracts and basis protection swaps. These instruments were intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL currently). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. These contracts cover only a portion of the Company’s natural gas production and provide only partial price protection against declines in natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of

(50)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Oklahoma and are unsecured. The derivative instruments have settled or will settle based on the prices below which are adjusted for location differentials and tied to certain pipelines in Oklahoma.
Derivative contracts in place as of September 30, 2009
(prices below reflect the Company’s net price from the listed Oklahoma pipelines)
                         
    Production volume   Indexed (1)    
Contract period   covered per month   Pipeline   Fixed price
 
                       
Fixed price swaps
                       
March — December, 2009
  60,000 Mmbtu   CEGT   $ 4.010  
April — December, 2009
  100,000 Mmbtu   CEGT   $ 3.710  
May — December, 2009
  70,000 Mmbtu   CEGT   $ 3.615  
July — December, 2009
  70,000 Mmbtu   PEPL   $ 3.745  
January — December, 2010
  100,000 Mmbtu   CEGT   $ 5.015  
January — December, 2010
  50,000 Mmbtu   CEGT   $ 5.050  
January — December, 2010
  100,000 Mmbtu   PEPL   $ 5.570  
January — December, 2010
  50,000 Mmbtu   PEPL   $ 5.560  
 
(1)   CEGT — Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma
PEPL — Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

(51)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Derivative contracts in place as of September 30, 2010
(prices below reflect the Company’s net price from the listed Oklahoma pipelines)
                         
    Production volume   Indexed (1)    
Contract period   covered per month   Pipeline   Fixed price
Fixed price swaps
                       
January — December, 2010
  100,000 Mmbtu   CEGT   $ 5.015  
January — December, 2010
  50,000 Mmbtu   CEGT   $ 5.050  
January — December, 2010
  100,000 Mmbtu   PEPL   $ 5.570  
January — December, 2010
  50,000 Mmbtu   PEPL   $ 5.560  
 
                       
Basis protection swaps
                       
January — December, 2011
  50,000 Mmbtu   CEGT   NYMEX -$.27
January — December, 2011
  50,000 Mmbtu   CEGT   NYMEX -$.27
January — December, 2011
  50,000 Mmbtu   PEPL   NYMEX -$.26
January — December, 2011
  50,000 Mmbtu   PEPL   NYMEX -$.27
January — December, 2012
  50,000 Mmbtu   CEGT   NYMEX -$.29
January — December, 2012
  40,000 Mmbtu   CEGT   NYMEX -$.30
January — December, 2012
  50,000 Mmbtu   PEPL   NYMEX -$.29
January — December, 2012
  50,000 Mmbtu   PEPL   NYMEX -$.30
 
(1)   CEGT — Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma
PEPL — Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline
     While the Company believes that its derivative contracts are effective in achieving the risk management objective for which they were intended, the Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was an asset of $1,620,326 as of September 30, 2010, and a liability of $2,513,435 as of September 30, 2009. Realized and unrealized gains and (losses) are scheduled below:
                         
Gains (losses) on natural gas   Fiscal year ended  
derivative contracts   9/30/2010     9/30/2009     9/30/2008  
Realized
  $ 2,209,900     $ 2,497,800     $ (1,480,100 )
Increase (decrease) in fair value
    4,133,761       (3,159,628 )     539,277  
 
                 
Total
  $ 6,343,661     $ (661,828 )   $ (940,823 )
 
                 
     To the extent that a legal offset exists, the Company nets the fair value of its derivative contracts with the same counterparty in the accompanying balance sheets. The following table summarizes the Company’s derivative contracts as of September 30, 2010 and September 30, 2009:

(52)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
                     
    Balance Sheet   9/30/2010     9/30/2009  
    Location   Fair Value     Fair Value  
Asset Derivatives:
                   
Derivatives not designated as Hedging Instruments:                
Commodity contracts
  Short-term derivative contracts   $ 1,481,527     $  
Commodity contracts
  Long-term derivative contracts     138,799        
 
               
Total Asset Derivatives (a)
      $ 1,620,326     $  
 
               
 
                   
Liability Derivatives:                
Derivatives not designated as Hedging Instruments:                
Commodity contracts
  Short-term derivative contracts   $     $ 1,726,901  
Commodity contracts
  Long-term derivative contracts           786,534  
 
               
Total Liability Derivatives (a)
      $     $ 2,513,435  
 
               
 
(a)   See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.
     The fair value of derivative assets and derivative liabilities is adjusted for credit risk, only if the impact is deemed material. The impact of credit risk was immaterial for all periods presented.
     Fair Value Measurements
     Effective October 1, 2008, the Company adopted guidance which established a framework for measuring the fair value of assets and liabilities measured on a recurring basis and expanded disclosures about fair value measurements. In February 2008, the FASB delayed the effective date of this guidance by one year for nonfinancial assets and liabilities. Consequently, the Company only applied the fair value measurement statement to financial assets and liabilities and delayed application for nonfinancial assets and liabilities (including, but not limited to, its asset retirement obligations) until the Company’s fiscal year beginning October 1, 2009, as permitted. Upon adoption as of October 1, 2009, the impact of full application for nonfinancial assets and liabilities on its financial position, results of operations and cash flows was not material.
     This guidance defines fair value as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are

(53)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
unobservable inputs for the financial asset or liability. Counterparty quotes are generally assessed as a Level 3 input.
     The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2010.
                                 
    Quoted   Significant        
    Prices in   Other   Significant    
    Active   Observable   Unobservable    
    Markets   Inputs   Inputs   Total Fair
    (Level 1)   (Level 2)   (Level 3)   Value
Financial Assets (Liabilities):
                               
Derivative Contracts — Swaps
        $ 1,620,326           $ 1,620,326  
Level 2 — Market Approach — The fair values of the Company’s natural gas swaps are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas curves, or can be corroborated from active markets. These values are based upon, among other things, future prices and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.
     The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
         
    Total Losses for the
    Year Ended
    September 30, 2010
Impairments:
       
Producing Properties
  $ 605,615 (a)
 
(a)   At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil and natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. As a result, the Company recorded $605,615 in impairment charges during 2010.
     Fair Values of Financial Instruments
     The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, derivative contracts, refundable income taxes, accounts payable and accrued liabilities approximate their fair values due to the short maturity of these instruments. The fair value of Company’s debt approximates

(54)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
its carrying amount due to the interest rates on the Company’s revolving line of credit being rates, which are approximately equivalent to market rates for similar type debt based on the Company’s credit worthiness.
     Depreciation, Depletion, Amortization and Impairment
     Depreciation, depletion and amortization of the costs of producing oil and natural gas properties are generally computed using the units of production method primarily on a separate property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.
     Non-producing oil and natural gas properties include non-producing minerals, which had a net book value of $4,346,191 and $4,771,926 at September 30, 2010 and 2009, respectively, consisting of perpetual ownership of mineral interests in several states, with 90% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 84 year life of the Company. There are approximately 204,460 net acres of non-producing minerals in over 7,000 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $39. Since inception, the Company has continually generated an interest in several thousand oil and natural gas wells using its ownership of the fee mineral acres as an ownership basis. There continues to be significant drilling activity each year on these mineral interests. Non-producing minerals are being amortized straight-line over a 33 year period. These assets are considered a long-term investment by the Company; as they do not expire (as do oil and natural gas leases). Given the above, it was concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.
     The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s estimate of fair value of its oil and natural gas properties at September 30, 2010 is based on the best information available as of that date, including estimates of forward oil and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $605,615, $2,464,520 and $526,380 respectively, for 2010, 2009 and 2008. A significant reduction in oil and natural gas prices or a decline in reserve volumes would likely lead to additional impairment in future periods that may be material to the Company.
     Capitalized Interest
     During 2010, 2009 and 2008, interest of $104,100, $455,516 and $144,520, respectively, was included in the Company’s capital expenditures. Interest of $60,912, $6,946 and $44,346, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate

(55)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
based on the Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using units of production method.
     Investments
     Insignificant investments in partnerships and limited liability companies (LLC) that maintain specific ownership accounts for each investor and where the Company holds an interest of five percent or greater, but does not have control of the partnership or LLC, are accounted for using the equity method of accounting.
     Asset Retirement Obligations
     The Company owns interests in oil and natural gas properties, which may require expenditures to plug and abandon the wells when the oil and natural gas reserves in the wells are depleted. Fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties and equipment is depreciated over the useful life of the remaining asset. The Company does not have any assets restricted for the purpose of settling the plugging liabilities.
     The following table shows the activity for the year ended September 30, 2010 and 2009 relating to the Company’s retirement obligation for plugging liability:
         
    Plugging  
    Liability  
Plugging Liability as of September 30, 2009
  $ 1,620,225  
Accretion of Discount
    106,093  
New Wells Placed on Production
    20,476  
Wells Sold or Plugged
    (16,425 )
 
     
Plugging Liability as of September 30, 2010
  $ 1,730,369  
 
     
 
       
Plugging Liability as of September 30, 2008
  $ 1,504,411  
Accretion of Discount
    104,991  
New Wells Placed on Production
    118,371  
Wells Sold or Plugged
    (107,548 )
 
     
Plugging Liability as of September 30, 2009
  $ 1,620,225  
 
     
     Environmental Costs
     As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays; however, to date the Company’s cost of compliance has been insignificant. The Company does not believe the existence of current

(56)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
environmental laws or interpretations thereof will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future effects on the Company of new laws or interpretations thereof. Since the Company does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by others, with Panhandle being responsible for its proportionate share of the costs involved. Panhandle carries liability insurance and pollution control coverage. However, all risks are not insured due to the availability and cost of insurance.
     Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2010 and 2009, there were no such costs accrued.
     Earnings (Loss) Per Share of Common Stock
     Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, including unissued, vested directors’ shares during the period.
     In June 2010, the Company awarded 8,500 shares of restricted stock to certain officers. The restricted stock vests at the end of five years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the awards is approximately $240,000 and will be recognized as compensation expense over the vesting period. In accordance with accounting guidance, the outstanding stock awards for the period ended September 30, 2010 are not included in the diluted earnings per share calculation.
     Share-based Compensation
     The Company recognizes current compensation costs for its Deferred Compensation Plan for Non-Employee Directors (the “Plan”). Compensation cost is recognized for the requisite directors’ fees as earned and unissued stock is added to each director’s account based on the fair market value of the stock at the date earned. The Plan’s structure is, that upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director.
     In accordance with guidance on accounting for employee stock ownership plans, the Company records as expense, the fair market value of the stock at the time of contribution into its ESOP.
     Restricted stock awards to certain officers during 2010 provide for vesting at the end of five years from the date of the awards. The fair value of the awards is ratably expensed over the vesting period in accordance with accounting guidance.
     Income Taxes
     The estimation of amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of

(57)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
pending and new tax matters. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities.
     On October 1, 2007, the Company adopted the guidelines on accounting for income tax uncertainties; the impact was not material. The guidelines prescribe 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 2007.
     The Company includes interest assessed by the taxing authorities in “Interest expense” and penalties related to income taxes in “General and administrative expense” on its Consolidated Statements of Operations. For fiscal September 30, 2010, 2009 and 2008, the Company recorded no interest or penalties; as the Company does not believe it has any significant uncertain tax positions.
     New Accounting Standards
     In January 2010, the FASB updated its oil and natural gas estimation and disclosure requirements to align its requirements with the SEC’s modernized oil and natural gas reporting rules, which are effective for annual reports on Form 10K for fiscal years ending on or after December 31, 2009. The update includes the following changes: (1) permitting use of new technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; (2) enabling companies to additionally disclose their probable and possible reserves to investors, in addition to their proved reserves; (3) allowing previously excluded resources, such as oil sands, to be classified as oil and natural gas reserves rather than mining reserves; (4) requiring companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria; (5) requiring the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; and (6) requiring companies to report oil and natural gas reserves using an average price based upon the prior 12-month period, rather than year-end prices. The update must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. This accounting guidance has been adopted on a prospective basis beginning in the fourth quarter of 2010. See Note 10 for disclosures regarding our natural gas and oil reserves.
     The Company is not able to disclose the effects resulting from the implementation of these changes on the financial statements or on the amount of proved reserves and disclosed quantities. In order to accurately report the quantitative effect of applying oil and gas modernization rules, it would have been necessary for the Company to prepare two sets of reserve reports, one applying the new oil and gas modernization rules and another applying the rules in effect at September 30, 2009. The Company has interests in several thousand developed and undeveloped properties which are evaluated in the reserve estimation process. The Company has a total of eighteen employees including one petroleum engineer and one engineering tech. Staff time was not available for the engineering staff to perform necessary controls to ensure the accuracy of the report, for accounting personnel to recalculate DD&A

(58)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
and re-test for impairment of producing properties and be able to timely prepare and file this Form 10-K with the SEC. Therefore, the Company determined that it was not practicable to perform a second reserve estimation process under the prior rules.
     Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the consolidated financial statements upon adoption.
2. COMMITMENTS
     The Company leases office space in Oklahoma City, Oklahoma under the terms of an operating lease expiring in April 2012. Future minimum rental payments under the terms of the lease are $204,089 in 2011 and $119,052 in 2012. Total rent expense incurred by the Company was $203,939 in 2010, $200,627 in 2009 and $175,335 in 2008.
3. INCOME TAXES
    The Company’s provision (benefit) for income taxes is detailed as follows:
                         
    2010   2009   2008
     
Current:
                       
Federal
  $ 3,950,000     $ 1,246,000     $ 1,728,000  
State
    174,000             50,302  
     
 
    4,124,000       1,246,000       1,778,302  
 
                       
Deferred:
                       
Federal
    708,000       (3,254,000 )     8,090,000  
State
    69,000       (560,000 )     1,026,000  
     
 
    777,000       (3,814,000 )     9,116,000  
     
 
  $ 4,901,000     $ (2,568,000 )   $ 10,894,302  
     

(59)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
3. INCOME TAXES (CONTINUED)
     The difference between the provision (benefit) for income taxes and the amount which would result from the application of the federal statutory rate to income before provision (benefit) for income taxes is analyzed below:
                         
    2010   2009   2008
     
 
                       
Provision (benefit) for income taxes at statutory rate
  $ 5,712,242     $ (1,690,827 )   $ 11,336,596  
Percentage depletion
    (684,053 )     (469,962 )     (1,072,282 )
State income taxes, net of federal provision (benefit)
    325,000       (451,440 )     797,550  
State net operating loss carryforward benefit
          (154,000 )     (143,000 )
State net operating loss valuation allowance (release)
    (278,000 )     278,000        
Other
    (174,189 )     (79,771 )     (24,562 )
     
 
  $ 4,901,000     $ (2,568,000 )   $ 10,894,302  
     
     Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax basis of assets and liabilities, consist of the following:
                 
    2010   2009
     
Deferred tax liabilities:
               
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes
  $ 24,141,021     $ 27,139,652  
Derivative contracts
    630,307        
     
 
    24,771,328       27,139,652  
Deferred tax assets:
               
Alternative minimum tax credit carryforwards
          2,207,810  
State net operating loss carry forwards, net of valuation allowance of $278,000 in 2009
    825,048       926,600  
Derivative contracts
          977,726  
Deferred directors compensation, allowance for uncollectible accounts and other
    1,039,530       897,766  
     
 
    1,864,578       5,009,902  
     
Net deferred tax liabilities
  $ 22,906,750     $ 22,129,750  
     
     At September 30, 2010, the Company had an income tax benefit of $825,048 related to Oklahoma state income tax net operating loss (OK NOL) carryforwards expiring from 2023 to 2029. The valuation allowance of $278,000 from 2009 was reversed in the current year as it became evident that the previously reserved Oklahoma NOLs will be utilized before they expire.

(60)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
4. LONG-TERM DEBT
     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, wherein BOK applies their own pricing forecast and a 9% discount rate to the Company’s proved reserves as calculated by the Company’s Independent Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to risk all proved non-producing and proved undeveloped reserves. Effective February 3, 2009, the Company amended its revolving credit facility with BOK to increase the borrowing base from $15,000,000 to $25,000,000 (the revolving loan amount remained $50,000,000), restructure the interest rate, secure the loan by certain of the Company’s properties and change the maturity date to October 31, 2011. Effective May 20, 2009 the Company again increased the borrowing base from $25,000,000 to $35,000,000. On December 8, 2009 and May 25, 2010, Panhandle’s bank reaffirmed the Company’s $35,000,000 borrowing base and extended the maturity date of the credit facility to October 31, 2012. The restructured interest rate is based on national prime plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%, with an established interest rate floor of 4.50% annually. On August 3, 2010, the 4.50% interest rate floor was removed. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced. Borrowings outstanding under the revolving loan amounted to $0 and $10,384,722 as of September 30, 2010 and 2009, respectively.
     Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties. The credit facility contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2010, the Company was in compliance with the covenants of the credit facility.
5. SHAREHOLDERS’ EQUITY
     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. These programs were completed in 2008. Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the board of directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. Approximately 40,000 shares are expected to be repurchased during fiscal year 2011. As of September 30, 2010, approximately $291,000 had been spent under the current program to purchase 12,326 shares. The shares are held in treasury and are accounted for using the cost method. At September 30, 2010 and 2009, 11,632 and 11,508 (respectively) treasury shares were contributed to the Company’s ESOP on behalf of the ESOP participants.

(61)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
6. EARNINGS PER SHARE
     The following table sets forth the computation of earnings per share.
                         
    Year ended September 30,
    2010   2009   2008
     
Numerator for basic and diluted earnings per share:
                       
Net income (loss)
  $ 11,419,690     $ (2,405,021 )   $ 21,555,769  
     
Denominator for basic and diluted earnings per share — weighted average shares (including for 2010, 2009 and 2008, unissued, vested directors’ shares of 111,491, 97,177 and 85,504, respectively)
    8,422,387       8,397,337       8,492,378  
     
7. EMPLOYEE STOCK OWNERSHIP PLAN
     The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan, and serves as the Company’s sole retirement plan for its employees. Company contributions are made at the discretion of the Board of Directors and, to date, all contributions have been made in shares of Company common stock. The Company contributions are allocated to all ESOP participants in proportion to their salaries for the plan year and 100% vesting occurs after three years of service. For contributions of common stock, the Company records as expense, the fair market value of the stock at the time of contribution. The 243,149 shares of the Company’s common stock held by the plan, as of September 30, 2010, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings per share computations and receive dividends. Contributions to the plan consisted of:
                 
Year   Shares   Amount
 
2010
    11,632     $ 287,194  
2009
    11,508     $ 245,811  
2008
    7,640     $ 218,733  
8. DEFERRED COMPENSATION PLAN FOR DIRECTORS
     The Panhandle Oil and Gas Inc. Deferred Compensation Plan for Non-Employee Directors (the Plan) provides that each eligible director can individually elect to receive shares of Company stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These shares are unissued and vest as earned. The shares are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. As of September 30, 2010, there were 114,323 shares (99,560 shares at September 30, 2009) included in the Plan. The deferred balance outstanding at September 30, 2010 under the Plan was $2,222,127 ($1,862,499 at September 30, 2009). Expense totaling $359,628, $256,688 and $247,033 was charged to the Company’s results of operations for the years ended September 30, 2010, 2009 and 2008, respectively, and is included in general and administrative expense in the accompanying Statement of Operations.

(62)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
9. RESTRICTED STOCK PLAN
     On March 11, 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 100,000 shares of Common Stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. The 2010 Stock Plan is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.
     In June 2010, the Company awarded 8,500 shares of the Company’s Common Stock as restricted stock to certain officers. The restricted stock vests at the end of five years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. Dividends expected to be paid are $.07 per share each quarter. The fair value of the shares at the time of their award, based on the closing price of the shares on their award date, was $240,550 and will be recognized as compensation expense ratably over the vesting period. The compensation expense recognized as a part of G&A expense in 2010 was $12,028.
     A summary of the status of unvested shares of restricted stock awards and changes during 2010 is presented below:
                 
            Weighted
    Unvested   Average
    Restricted   Grant-Date
    Shares   Fair Value
 
Unvested shares as of October 1, 2009
        $  
Granted
    8,500     $ 28.30  
Vested
        $  
Forfeited
        $  
 
               
Unvested shares as of September 30, 2010
    8,500     $ 28.30  
     No vesting of restricted stock occurred during 2010. As of September 30, 2010, there was $228,522 of total unrecognized compensation cost related to unvested restricted stock. The cost is to be recognized over a weighted average period of 4.75 years. Upon vesting, shares are expected to be issued out of shares held in treasury.
10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES
     All oil and natural gas producing activities of the Company are conducted within the United States (principally in Oklahoma and Arkansas) and represent substantially all of the business activities of the Company.
     During 2010, 2009 and 2008, approximately 14%, 20% and 16%, respectively, of the Company’s total revenues were derived from sales through Chesapeake Operating, Inc. During 2010, 2009 and 2008, approximately 11%, 14% and 17%, respectively, of the Company’s total revenues were derived from sales through JMA Energy Company. During 2010, 2009 and 2008, approximately 15%, 17% and 12% of the Company’s total revenues were derived from sales through Newfield Exploration.

(63)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (CONTINUED)
     Aggregate Capitalized Costs
     The aggregate amount of capitalized costs of oil and natural gas properties and related accumulated depreciation, depletion, and amortization as of September 30 is as follows:
                 
    2010   2009
     
 
               
Producing properties
  $ 207,928,578     $ 198,076,244  
Non-producing minerals
    7,744,767       8,036,236  
Non-producing leasehold
    1,360,264       2,241,232  
Exploratory wells in progress
    511,299       55,069  
     
 
    217,544,908       208,408,781  
Accumulated depreciation, depletion and amortization
    (131,529,373 )     (112,505,428 )
     
Net capitalized costs
  $ 86,015,535     $ 95,903,353  
     
     Costs Incurred
     During the reporting period, the Company incurred the following costs in oil and natural gas producing activities:
                         
    2010   2009   2008
     
 
                       
Property acquisition costs
  $ 742,005     $ 382,239     $ 2,359,988  
Exploration costs
    530,931       1,647,456       1,887,182  
Development costs
    10,685,088       26,411,704       48,503,130  
     
 
  $ 11,958,024     $ 28,441,399     $ 52,750,300  
     
11. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS RESERVES (UNAUDITED)
     The following unaudited information regarding the Company’s oil and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.
     Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced or the operator

(64)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
11. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)
must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
     The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas calculated the Company’s oil and natural gas reserves as of September 30, 2010 (see Exhibits 23 and 99). Reserves as of September 30, 2008 and 2009 were calculated by Pinnacle Energy Services, L.L.C. of Oklahoma City, Oklahoma.
     The Company’s net proved oil and natural gas reserves, all of which are located in the United States, as of September 30, 2010, 2009 and 2008, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firms (as noted above). All studies have been prepared in accordance with regulations prescribed by the SEC and generally accepted geological and engineering methods by the petroleum industry.
     All of the reserve estimates are reviewed and approved by our Vice President and COO, who reports directly to our President and CEO. Mr. Blanchard, our COO, holds a Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma. Before joining the Company, he was sole proprietor of a consulting petroleum engineering firm, spent 10 years as Vice President of the Mid-Continent business unit of Range Resources Corporation and spent several years as an engineer with Enron Oil and Gas. He is an active member of the Society of Petroleum Engineers (SPE) with over 25 years of oil and gas industry experience, including engineering assignments in several field locations.
     Our COO and internal staff of professionals work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information to our Independent Consulting Petroleum Engineers for all properties such as ownership interest; oil and gas production; well test data; commodity prices; operating costs and deduct rates, and development costs. Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions.

(65)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
11. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)
     When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data was available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.
     Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure and gas-oil ratio behavior, was used in the estimation of reserves.
     For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.
     Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available.
     Estimated Quantities of Proved Oil and Natural Gas Reserves
     Net quantities of proved, developed and undeveloped oil and natural gas reserves are summarized as follows:

(66)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
11. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)
                 
    Proved Reserves
    Oil   Natural Gas
    (Mbarrels)   (MMcf)
September 30, 2007
    823       37,006  
 
               
Revisions of previous estimates
    136       117  
Divestitures
    (1 )     (83 )
Extensions and discoveries
    164       18,039  
Production
    (132 )     (6,928 )
     
September 30, 2008
    990       48,151  
 
               
Revisions of previous estimates
    (30 )     589  
Divestitures
    (4 )     (317 )
Extensions and discoveries
    93       14,715  
Production
    (128 )     (9,110 )
     
September 30, 2009
    921       54,028  
 
               
Revisions of previous estimates
    48       15,763  
Divestitures
    (1 )     (8 )
Extensions and discoveries
    59       36,690  
Production
    (102 )     (8,303 )
     
September 30, 2010
    925       98,170  
     
     The prices used to calculate reserves and future cash flows from reserves for oil and natural gas, respectively, were as follows: September 30, 2010 — $69.23/Bbl, $4.33/Mcf; September 30, 2009 — $66.96/Bbl, $2.86/Mcf; September 30, 2008 — $97.74/Bbl, $4.51/Mcf (these natural gas prices are representative of local pipelines in Oklahoma).
     The revisions of previous estimates were primarily the result of positive performance revisions, which were principally attributable to properties in the southeast Oklahoma Woodford Shale and the Arkansas Fayetteville Shale. The revisions are principally the result of actual well performance on both new and existing wells exceeding the performance projections in the prior estimates. The improved performance in the new wells can be attributed to the drilling of longer horizontal laterals as well as enhanced fracture stimulation techniques. Increased oil and natural gas prices also contributed to the increase in reserves.
     Extensions and discoveries are principally attributable to: (1) the Company’s drilling expenditures in ongoing development of unconventional natural gas plays utilizing horizontal drilling, including the southeast Oklahoma Woodford Shale and Arkansas Fayetteville Shale; (2) the Company’s drilling expenditures in development of an unconventional natural gas and natural gas liquids-rich play utilizing horizontal drilling, the Anadarko Basin (Cana) Woodford Shale: (3) the Company’s drilling expenditures in development of conventional natural gas, natural gas liquids-rich and oil plays utilizing horizontal

(67)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
11. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)
drilling and to a lesser extent vertical drilling, primarily in western Oklahoma and the Texas Panhandle; and (4) a significant addition of proven undeveloped reserves resulting from the implementation of the Securities and Exchange Commission’s “Modernization of Oil and Gas Reporting Rules”. Increased oil and natural gas prices also contributed to the increase in reserves.
                                 
    Proved Developed Reserves   Proved Undeveloped Reserves
    Oil   Natural Gas   Oil   Natural Gas
    (Mbarrels)   (Mmcf)   (Mbarrels)   (Mmcf)
 
                               
September 30, 2008
    895       35,970       95       12,181  
     
 
                               
September 30, 2009
    883       45,036       38       8,991  
     
 
                               
September 30, 2010
    861       57,344       64       40,826  
     
     The above reserve numbers exclude approximately 2.9 Bcf of CO2 gas reserves for the year ended September 30, 2008. These reserves were sold in the fourth quarter of 2009.
    The following details the changes in proved undeveloped reserves for 2010 (Mmcfe):
         
Beginning proved undeveloped reserves
    9,219  
Proved undeveloped reserves transferred to proved developed
    (3,545 )
Revisions
    3,060  
Extensions and discoveries
    32,476  
 
       
Ending proved undeveloped reserves
    41,210  
     During 2010, various exploration and development drilling evaluations were completed. Approximately $10.7 million was spent during 2010 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $12 million in 2011, $14 million in 2012 and $9 million in 2013. All proved undeveloped drilling locations are expected to be drilled prior to the end of 2015.
     Standardized Measure of Discounted Future Net Cash Flows
     Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.
     Future cash inflows and future production and development costs as of September 30, 2010 are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month oil and natural gas prices and year-end costs to the estimated quantities of natural gas and oil to be

(68)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
11. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)
produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month oil and natural gas prices and year-end costs used. Amounts as of September 30, 2008 and 2009 were determined using year-end prices and costs. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year. Estimated future income taxes are computed using current statutory income tax rates including consideration for the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.
                         
    2010   2009   2008
 
                       
Future cash inflows
  $ 489,691,155     $ 216,181,210     $ 318,004,410  
Future production costs
    148,727,914       62,102,230       79,668,500  
Future development costs
    52,975,820       5,412,470       19,364,580  
Asset retirement obligation
    1,730,369       1,620,225       1,504,411  
Future income tax expense
    99,118,090       43,832,666       68,086,237  
     
Future net cash flows
    187,138,962       103,213,619       149,380,682  
 
                       
10% annual discount
    114,638,553       49,467,111       70,585,957  
     
Standardized measure of discounted future net cash flows
  $ 72,500,409     $ 53,746,508     $ 78,794,725  
     
     Changes in the standardized measure of discounted future net cash flow are as follows:

(69)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
11. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)
                         
    2010   2009   2008
Beginning of year
  $ 53,746,508     $ 78,794,725     $ 77,029,122  
Changes resulting from:
                       
Sales of oil and natural gas, net of production costs (1)
    (34,429,083 )     (28,524,453 )     (58,971,023 )
Net change in sales prices and production costs
    30,806,970       (59,790,799 )     9,274,593  
Net change in future development costs
    (26,093,254 )     7,769,930       (5,841,539 )
Net change in asset retirement obligation
    (48,185 )     (63,536 )     (142,847 )
Extensions and discoveries
    53,274,047       21,677,448       46,677,163  
Revisions of quantity estimates
    28,946,810       587,215       2,417,457  
Divestitures of reserves-in-place
    (15,706 )     (480,535 )     (208,419 )
Accretion of discount
    8,066,959       12,110,733       11,626,875  
Net change in income taxes
    (25,807,417 )     15,389,517       (3,072,975 )
Change in timing and other, net
    (15,947,240 )     6,276,263       6,318  
     
Net change
    18,753,901       (25,048,217 )     1,765,603  
     
End of year
  $ 72,500,409     $ 53,746,508     $ 78,794,725  
     
 
(1)   Sales of natural gas includes associated natural gas liquids
12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
    The following is a summary of the Company’s unaudited quarterly results of operations.
                                 
    Fiscal 2010
    Quarter Ended
    December 31   March 31   June 30   September 30
Revenues
  $ 12,321,352     $ 16,856,884     $ 10,461,870     $ 12,298,310  
Income before provision for income taxes
    2,411,378       6,964,566       2,264,300       4,680,446  
Net income
    1,708,378       5,163,566       1,511,300       3,036,446  
Earnings per share
  $ 0.20     $ 0.61     $ 0.18     $ 0.36  
                                 
    Fiscal 2009
    Quarter Ended
    December 31   March 31   June 30   September 30
Revenues
  $ 11,261,642     $ 8,835,617     $ 8,665,216     $ 8,510,139  
Income (loss) before provision for income taxes
    (1,053,629 )     (1,971,256 )     (2,001,512 )     53,376  
Net income (loss)
    (874,629 )     (945,256 )     (928,512 )     343,376  
Earnings (loss) per share
  $ (0.10 )   $ (0.11 )   $ (0.11 )   $ 0.04  

(70)


Table of Contents

Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
13. SUBSEQUENT EVENTS
     Effective December 6, 2010, the Company amended its revolving credit facility with BOK to increase the revolving loan amount to $80,000,000 (the borrowing base remains at $35,000,000) and change the maturity date to November 30, 2014. There was no change to the current interest rates as discussed in Note 4.

(71)


Table of Contents

ITEM 9   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
NONE
ITEM 9A   CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
     The Company maintains “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including the Company’s President/Chief Executive Officer and Vice President/Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The Company’s disclosure controls and procedures have been designed to meet, and management believes that they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this report, the Chief Executive Officer and Chief Financial Officer have concluded that, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective.
(b) MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
     The Company’s management is responsible for establishing and maintaining adequate “internal control over financial reporting”, as such term is defined in Exchange Act Rule 13a-15(f). The Company’s management, including the President/CEO and Vice President/CFO, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the Company’s management concluded that its internal control over financial reporting was effective as of September 30, 2010.
(c) CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
     There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter ended September 30, 2010 or subsequent to the date the assessment was completed.
ITEM 9B   OTHER INFORMATION
     None

(72)


Table of Contents

PART III
     The information called for by Part III of Form 10-K (Item 10 — Directors and Executive Officers of the Registrant, Item 11 — Executive Compensation, Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 13 — Certain Relationships and Related Transactions, and Item 14 — Principal Accountant Fees and Services), is incorporated by reference from the Company’s definitive proxy statement, which will be filed with the SEC within 120 days after the end of the fiscal year to which this report relates.
PART IV
ITEM 15   EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
FINANCIAL STATEMENT SCHEDULES
     The Company has omitted all other schedules because the conditions requiring their filing do not exist or because the required information appears in the Company’s Consolidated Financial Statements, including the notes to those statements.
EXHIBITS
     
(3)
  Amended Certificate of Incorporation (incorporated by reference to Exhibit attached to Form 10 filed January 27, 1980, and to Forms 8-K dated June 1, 1982, December 3, 1982, to Form 10-QSB dated March 31, 1999, and to Form 10-Q dated March 31, 2007)
By-Laws as amended (incorporated by reference to Form 8-K dated October 31, 1994)
By-Laws as amended (incorporated by reference to Form 8-K dated February 24, 2006)
By-Laws as amended (incorporated by reference to Form 8-K dated October 29, 2008)
(4)
  Instruments defining the rights of security holders (incorporated by reference to Certificate of Incorporation and By-Laws listed above)
*(10)
  Agreement indemnifying directors and officers (incorporated by reference to Form 10-K dated September 30, 1989, and Form 8-K dated June 15, 2007)
*(10)
  Agreements to provide certain severance payments and benefits to executive officers should a Change-in-Control occur as defined by the agreements (incorporated by reference to Form 8-K dated September 4, 2007)
(21)
  Subsidiaries of the Registrant
(23)
  Consent of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants
(31.1)
  Certification of Chief Executive Officer
(31.2)
  Certification of Chief Financial Officer
(32.1)
  Certification of Chief Executive Officer
(32.2)
  Certification of Chief Financial Officer
(99)
  Report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants
 
*
  Indicates management contract or compensatory plan or arrangement
REPORTS ON FORM 8-K
     Dated September 14, 2010; item 8.01 — Other Events

(73)


Table of Contents

SIGNATURES
     Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
                     
PANHANDLE OIL AND GAS INC.                
 
                   
By:
  /s/ Michael C. Coffman
 
      By:   /s/ Lonnie J. Lowry
 
   
 
  Michael C. Coffman           Lonnie J. Lowry    
 
  President;           Vice President;    
 
  Chief Executive Officer           Chief Financial Officer    
 
                   
Date: December 9, 2010       Date: December 9, 2010    
 
                   
By:
  /s/ Robb P. Winfield                
 
                   
 
  Robb P. Winfield                
 
  Controller;                
 
  Chief Accounting Officer                
 
                   
Date: December 9, 2010
               
     In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
         
/s/ Bruce M. Bell
 
  /s/ E. Chris Kauffman
 
   
Bruce M. Bell, Director
  E. Chris Kauffman, Director    
 
       
Date December 9, 2010
  Date December 9, 2010    
 
       
/s/ Duke R. Ligon
 
  /s/ Robert O. Lorenz
 
   
Duke R. Ligon, Director
  Robert O. Lorenz, Lead Independent Director    
 
       
Date December 9, 2010
  Date December 9, 2010    
 
       
/s/ Robert A. Reece
 
  /s/ Robert E. Robotti
 
   
Robert A. Reece, Director
  Robert E. Robotti, Director    
 
       
Date December 9, 2010
  Date December 9, 2010    
 
       
/s/ Darryl G. Smette
 
  /s/ H. Grant Swartzwelder
 
   
Darryl G. Smette, Director
  H. Grant Swartzwelder, Director    
 
       
Date December 9, 2010
  Date December 9, 2010    

(74)