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PHX MINERALS INC. - Annual Report: 2012 (Form 10-K)

Form 10-K
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

LOGO

 

 

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

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2012

Commission File Number: 001-31759

 

 

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

 

 

 

OKLAHOMA     73-1055775

(State or other jurisdiction of

incorporation or organization)

   

(I.R.S. Employer

Identification No.)

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

Oklahoma City, OK 73112

(Address of principal executive offices) (Zip code)

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

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

 

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

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

(Title of Class)

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

 

 

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    x  Yes    ¨   No

(Facing Sheet Continued)


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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.    x  Yes    ¨  No

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

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

 

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

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

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

Documents Incorporated By Reference

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

 

 

 


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T A B L E   O F   C O N T E N T S

 

         Page  

PART I

    

Item 1

  Business      1   

Item 1B

  Unresolved Staff Comments      11   

Item 2

  Properties      11   

Item 3

  Legal Proceedings      21   

Item 4

  Submission of Matters to a Vote of Security Holders      21   

PART II

    

Item 5

  Market for Common Equity, Related Stockholder Matters and Unregistered Sales of Equity Securities      22   

Item 6

  Selected Financial Data      24   

Item 7

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      24   

Item 7A

  Quantitative and Qualitative Disclosures about Market Risk      40   

Item 8

  Financial Statements and Supplementary Data      41   

Item 9

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      79   

Item 9A

  Controls and Procedures      79   

Item 9B

  Other Information      79   

PART III

    

Item 10-14

  Incorporated by Reference to Proxy Statement      80   

PART IV

    

Item 15

  Exhibits, Financial Statement Schedules and Reports on Form 8- K      80   


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DEFINITIONS

The following defined terms are used in this report:

Bbl” means barrel;

Bcf” means billion cubic feet;

“Board” means board of directors;

“BTU” means British Thermal Units;

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

“CEO” means Chief Executive Officer;

“CFO” means Chief Financial Officer;

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

“COO” means Chief Operating Officer;

“DD&A” means depreciation, depletion and amortization;

“ESOP” refers to the Panhandle Oil and Gas Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan;

“FASB” means the Financial Accounting Standards Board;

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

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

“LOE” means lease operating expense;

Mcf” means thousand cubic feet;

Mcfd” means thousand cubic feet per day;

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

“Mmbtu” means million BTU;

“Mmcf” means million cubic feet;

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


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

“NGL” means natural gas liquids;

“NYMEX” refers to the New York Mercantile Exchange;

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

“PDP” means proved developed producing;

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

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

“PUD” means proved undeveloped;

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

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

SEC” refers to the United States Securities and Exchange Commission;

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

Fiscal year references

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

References to natural gas

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

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


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PART I

 

ITEM 1 BUSINESS

GENERAL

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

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

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

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

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

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

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

BUSINESS STRATEGY

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

 

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

PRINCIPAL PRODUCTS AND MARKETS

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

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

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

COMPETITIVE BUSINESS CONDITIONS

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

 

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

SOURCES AND AVAILABILITY OF RAW MATERIALS

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

MAJOR CUSTOMERS

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

PATENTS, TRADEMARKS, LICENSES, FRANCHISES AND ROYALTY AGREEMENTS

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

REGULATION

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

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

 

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

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

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

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

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

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

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

 

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

ENVIRONMENTAL MATTERS

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

EMPLOYEES

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

RISK FACTORS

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

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

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

 

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

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

 

   

worldwide economic conditions;

 

   

economic, political and regulatory developments;

 

   

market uncertainty;

 

   

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

 

   

availability and capacity of necessary transportation and processing facilities;

 

   

commodity futures trading;

 

   

weather conditions;

 

   

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

 

   

actions taken by OPEC;

 

   

competition from alternative sources of energy; and

 

   

technological advancements affecting energy consumption and energy supply.

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

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

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

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

 

   

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

 

   

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

 

   

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

 

   

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

 

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We cannot control activities on properties we do not operate.

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

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

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

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

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

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

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

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

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

 

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

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

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

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

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

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

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

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

 

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

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

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

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

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

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

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

Debt level and interest rates may adversely affect our business.

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

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

 

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

 

   

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

 

   

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

 

   

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

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

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

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

Federal Income Taxation

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

Hydraulic Fracturing

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

Climate Change

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

 

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

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

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

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

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

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

 

ITEM 1B UNRESOLVED STAFF COMMENTS

None

 

ITEM 2 PROPERTIES

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

 

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

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

ACREAGE

Mineral Interests Owned

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

 

State

   Net
Acres
     Gross Acres      Net
Acres
Producing
(1)
     Gross
Acres
Producing
(1)
     Net
Acres
Leased
to Others
(2)
     Gross
Acres
Leased
to Others
(2)
     Net
Acres
Open
(3)
     Gross  Acres
Open

(3)
 

Arkansas

     11,872         50,935         6,719         24,603         1,907         6,130         3,246         20,201   

Colorado

     8,217         39,080               224         447         7,993         38,633   

Florida

     3,832         8,212                     3,832         8,212   

Kansas

     3,082         11,816         144         1,200               2,938         10,616   

Montana

     1,008         17,947                     1,008         17,947   

New Mexico

     57,375         174,300         1,352         7,125         205         440         55,818         166,735   

North Dakota

     11,179         64,286         148         1,276         33         680         10,998         62,330   

Oklahoma

     113,399         950,832         39,751         322,635         4,645         32,320         69,003         595,796   

South Dakota

     1,825         9,300                     1,825         9,300   

Texas

     43,196         360,025         7,933         70,781         244         5,285         35,019         283,959   

Other

     27         262                     27         262   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total:

     255,012         1,686,995         56,047         427,620         7,258         45,302         191,707         1,213,991   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) “Producing” represents the mineral acres in which Panhandle owns a royalty or working interest in a producing well.
(2) “Leased” represents the mineral acres owned by Panhandle that are leased to third parties but not producing.
(3) “Open” represents mineral acres owned by Panhandle that are not leased or in production.

Leases

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

 

State

   Net Acres      Net Acres Expiring      Net Acres
Held by
Production
 
            2013      2014      2015      2016      2017         

Arkansas

     1,931         235         108         91            28         1,469   

Kansas

     2,117                        2,117   

Oklahoma

     14,526         1,064         727         20               12,715   

Other

     1,603                        1,603   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

TOTAL

     20,177         1,299         835         111         0         28         17,904   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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PROVED RESERVES

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

 

      Barrels of
Oil
     Barrels of
NGL (1)
     Mcf of
Natural Gas
     Mcfe  

Net Proved Developed Reserves

           

September 30, 2012

     849,548         494,160         65,733,119         73,795,367   

September 30, 2011

     759,989         386,774         60,193,878         67,074,456   

September 30, 2010

     861,240         —           57,344,190         62,511,630   

Net Proved Undeveloped Reserves

           

September 30, 2012

     222,771         294,582         47,780,937         50,885,055   

September 30, 2011

     83,749         404,874         41,644,106         44,575,844   

September 30, 2010

     63,769         —           40,826,265         41,208,879   

Net Total Proved Reserves

           

September 30, 2012

     1,072,319         788,742         113,514,056         124,680,422   

September 30, 2011

     843,738         791,648         101,837,984         111,650,300   

September 30, 2010

     925,009         —           98,170,455         103,720,509   

 

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

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

(6) Production of 10.6 Bcfe.

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

 

Beginning proved undeveloped reserves

     44,575,844   

Proved undeveloped reserves transferred to proved developed

     (5,393,421

Revisions

     (22,369,152

Extensions and discoveries

     24,458,980   

Purchases

     9,612,804   
  

 

 

 

Ending proved undeveloped reserves

     50,885,055   

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

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

 

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

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

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

 

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

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

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

ESTIMATED FUTURE NET CASH FLOWS

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

 

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Estimated Future Net Cash Flows

        
     9-30-12      9-30-11      9-30-10  

Proved Developed

   $ 165,036,044       $ 211,851,992       $ 202,056,455   

Proved Undeveloped

     72,851,862         91,232,949         84,200,597   

Income Tax Expense

     83,543,516         107,111,317         99,118,090   
  

 

 

    

 

 

    

 

 

 

Total Proved

   $ 154,344,390       $ 195,973,624       $ 187,138,962   
  

 

 

    

 

 

    

 

 

 

10% Discounted Present Value of Estimated Future Net Cash Flows

  

     9-30-12      9-30-11      9-30-10  

Proved Developed

   $ 87,587,058       $ 106,464,138       $ 103,270,565   

Proved Undeveloped

     27,151,132         29,977,891         21,960,347   

Income Tax Expense

     47,323,902         58,059,595         52,730,503   
  

 

 

    

 

 

    

 

 

 

Total Proved

   $ 67,414,288       $ 78,382,434       $ 72,500,409   
  

 

 

    

 

 

    

 

 

 

OIL, NGL AND NATURAL GAS PRODUCTION

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

 

     Year Ended      Year Ended      Year Ended  
     9-30-12      9-30-11 (1)      9-30-10 (1)  

Bbls - Oil

     153,143         104,141         102,379   

Bbls - NGL

     98,714         *         *   

Mcf - Natural Gas

     9,072,298         8,297,657         8,302,342   

Mcfe

     10,583,440         8,922,503         8,916,616   

 

  (1) Natural gas production includes NGL volumes.

AVERAGE SALES PRICES AND PRODUCTION COSTS

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

 

Average Sales Price

   Year  Ended
9-30-12
     Year Ended
9-30-11 (1)
     Year Ended
9-30-10 (1)
 

Per Bbl, Oil

   $ 90.13       $ 88.00       $ 72.83   

Per Bbl, NGL

   $ 33.23         *         *   

Per Mcf, Natural Gas

   $ 2.62       $ 4.13       $ 4.41   

Per Mcfe

   $ 3.86       $ 4.87       $ 4.94   

 

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

 

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

 

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Average Production (lifting costs)

   Year Ended
9-30-12
     Year Ended
9-30-11
     Year Ended
9-30-10
 

(Per Mcfe)

        

Well Operating Costs (1)

   $ 0.86       $ 0.95       $ 0.92   

Production Taxes (2)

     0.14         0.16         0.16   
  

 

 

    

 

 

    

 

 

 
   $ 1.00       $ 1.11       $ 1.08   
  

 

 

    

 

 

    

 

 

 

 

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

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

GROSS AND NET PRODUCTIVE WELLS AND DEVELOPED ACRES

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

 

     Gross Working
Interest Wells
     Net Working
Interest Wells
     Gross Royalty
Only Wells
     Total Gross
Wells
 

Oil

     206         14.89         937         1,143   

Natural Gas

     1,648         80.42         2,875         4,523   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     1,854         95.31         3,812         5,666   
  

 

 

    

 

 

    

 

 

    

 

 

 

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

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

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

UNDEVELOPED ACREAGE

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

DRILLING ACTIVITY

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

 

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      Net Productive  Working
Interest Wells
     Net Productive Royalty
Interest Wells
     Net Dry Wells  

Development Wells

        

Fiscal years ended:

        

September 30, 2012

     5.376408         1.225832         0.093438   

September 30, 2011

     2.573391         0.907650         0.062188   

September 30, 2010

     2.953777         0.868179         0.057282   

Exploratory Wells

        

Fiscal years ended:

        

September 30, 2012

     0.298974         0.090654         0.531250   

September 30, 2011

     0.510643         0.372957         0.007813   

September 30, 2010

     0.029688         0.338320         0.000000   

Purchased Wells

        

Fiscal years ended:

        

September 30, 2012

     4.300626         0.231430         0.000000   

September 30, 2011

     0.000000         0.235058         0.000000   

September 30, 2010

     0.000000         0.000000         0.000000   

PRESENT ACTIVITIES

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

 

     Gross Wells      Net Wells  

Oil

     6         0.18   

Natural Gas

     56         2.00   

OTHER FACILITIES

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

SAFE HARBOR STATEMENT

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

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

 

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

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

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

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

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

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

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

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

 

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

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

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

 

ITEM 3 LEGAL PROCEEDINGS

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

 

ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

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

 

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PART II

 

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

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

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

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

 

LOGO

 

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

Fiscal year ending September 30.

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

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

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

 

Quarter Ended

   High      Low  

December 31, 2010

   $ 28.70       $ 23.75   

March 31, 2011

   $ 31.88       $ 25.60   

June 30, 2011

   $ 32.50       $ 27.30   

September 30, 2011

   $ 36.25       $ 26.36   

December 31, 2011

   $ 36.00       $ 26.18   

March 31, 2012

   $ 33.74       $ 28.05   

June 30, 2012

   $ 30.57       $ 24.16   

September 30, 2012

   $ 33.49       $ 27.85   

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

 

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

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

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

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

 

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ITEM 6 SELECTED FINANCIAL DATA

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

 

     As of and for the year ended September 30,  
     2012      2011     2010     2009     2008  

Revenues

           

Oil, NGL and natural gas sales

   $ 40,818,434       $ 43,469,130      $ 44,068,947      $ 37,421,688      $ 69,026,785   

Lease bonuses and rentals

     7,152,991         352,757        1,120,674        188,906        167,559   

Gains (losses) on derivative contracts

     73,822         734,299        6,343,661        (661,828     (940,823

Income from partnerships

     487,070         420,465        405,134        323,848        631,891   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 
     48,532,317         44,976,651        51,938,416        37,272,614        68,885,412   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses

           

Lease operating expense

     9,141,970         8,441,754        8,193,319        7,696,026        6,629,170   

Production taxes

     1,449,537         1,456,755        1,446,545        1,201,209        3,426,592   

Exploration costs

     979,718         1,025,542        1,583,773        711,582        455,943   

Depreciation, depletion and amortization

     19,061,239         14,712,188        19,222,123        28,168,933        19,784,660   

Provision for impairment

     826,508         1,728,162        605,615        2,464,520        526,380   

Loss (gain) on asset sales, int. & other

     39,493         (68,325     (1,028,148     (2,677,407     14,826   

Gen. and administrative

     6,388,856         5,994,663        5,594,499        4,866,044        5,006,512   

Bad debt expense (recovery)

     —           —          —          (185,272     591,258   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 
     37,887,321         33,290,739        35,617,726        42,245,635        36,435,341   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before provision (benefit) for income taxes

     10,644,996         11,685,912        16,320,690        (4,973,021     32,450,071   

Provision (benefit) for income taxes

     3,274,000         3,192,000        4,901,000        (2,568,000     10,894,302   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 7,370,996       $ 8,493,912      $ 11,419,690      $ (2,405,021   $ 21,555,769   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Basic and diluted earnings (loss) per share

   $ 0.88       $ 1.01      $ 1.36      $ (0.29   $ 2.54   

Dividends declared per share

   $ 0.28       $ 0.28      $ 0.28      $ 0.28      $ 0.28   

Weighted average shares outstanding

           

Basic and diluted

     8,360,931         8,393,890        8,422,387        8,397,337        8,492,378   

Net cash provided by (used in):

           

Operating activities

   $ 25,371,195       $ 29,283,929      $ 27,806,475      $ 37,710,606      $ 40,063,896   

Investing activities

   $ 38,288,959       $ (27,200,816   $ (9,845,516   $ (36,322,992   $ (37,846,172

Financing activities

   $ 11,394,864       $ (4,173,372   $ (13,003,609   $ (1,643,414   $ (2,311,376

Total assets

   $ 135,186,730       $ 111,424,193      $ 105,124,839      $ 108,549,632      $ 122,007,183   

Long-term debt

   $ 14,874,985       $ —        $ —        $ 10,384,722      $ 9,704,100   

Shareholders’ equity

   $ 83,852,146       $ 78,802,317      $ 73,581,996      $ 64,122,343      $ 68,348,901   

 

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

BUSINESS OVERVIEW

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

 

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

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

 

   

Horizontal Granite Wash in western Oklahoma and the Texas Panhandle

 

   

Horizontal Cleveland in western Oklahoma and the Texas Panhandle

 

   

Horizontal Marmaton in western Oklahoma

 

   

Horizontal Tonkawa in western Oklahoma

 

   

Vertical Mississippian in northern Oklahoma

 

   

Vertical Spraberry in West Texas

 

   

Vertical Yeso in southeastern New Mexico

 

   

Horizontal Anadarko Basin Woodford Shale in western Oklahoma

 

   

Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

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

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

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

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

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

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

 

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     For the Year Ended September 30,  
            Percent            Percent        
     2012      Incr. or (Decr.)     2011      Incr. or (Decr.)     2010  

Production:

            

Oil (Bbls)

     153,143         47     104,141         2     102,379   

NGL (Bbls)

     98,714         —          *         —          *   

Natural Gas (Mcf)

     9,072,298         9     8,297,657         0     8,302,342   

Mcfe

     10,583,440         19     8,922,503         0     8,916,616   

Average Sales Price:

            

Oil (per Bbl)

   $ 90.13         2   $ 88.00         21   $ 72.83   

NGL (per Bbl)

   $ 33.23         —          *         —          *   

Natural Gas (Mcf) (1)

   $ 2.62         -37   $ 4.13         -6   $ 4.41   

Mcfe

   $ 3.86         -21   $ 4.87         -1   $ 4.94   

 

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

 

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

RESULTS OF OPERATIONS

Fiscal Year 2012 Compared to Fiscal Year 2011

Overview

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

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

Oil, NGL and Natural Gas Sales

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

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

 

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Production by quarter for 2012 and 2011 was as follows:

 

     2012            2011      

First quarter

     2,559,524      Mcfe        2,208,218      Mcfe

Second quarter

     2,654,485      Mcfe        2,152,011      Mcfe

Third quarter

     2,649,351      Mcfe        2,129,160      Mcfe

Fourth quarter

     2,720,080      Mcfe        2,433,114      Mcfe
  

 

 

        

 

 

   

Total

     10,583,440      Mcfe        8,922,503      Mcfe
  

 

 

        

 

 

   

Lease Bonus and Rentals

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

Gains (Losses) on Derivative Contracts

Realized and unrealized gains and losses are scheduled below:

 

Gains (Losses) on       

Derivative Contracts

   2012     2011  

Realized

   $ 462,033      $ 2,138,685   

Unrealized

     (388,211     (1,404,386
  

 

 

   

 

 

 

Total

   $ 73,822      $ 734,299   
  

 

 

   

 

 

 

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

Lease Operating Expenses (LOE) and Production Taxes

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

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

 

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Exploration Costs

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

Depreciation, Depletion and Amortization (DD&A)

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

Provision for Impairment

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

General and Administrative Costs (G&A)

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

Provision (Benefit) for Income Taxes

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

 

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Fiscal Year 2011 Compared to Fiscal Year 2010

Overview

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

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

Oil and Natural Gas Sales

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

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

Production by quarter for 2011 and 2010 was as follows:

 

     2011              2010        

First quarter

     2,208,218        Mcfe           2,278,133        Mcfe   

Second quarter

     2,152,011        Mcfe           2,090,154        Mcfe   

Third quarter

     2,129,160        Mcfe           2,236,236        Mcfe   

Fourth quarter

     2,433,114        Mcfe           2,312,093        Mcfe   
  

 

 

        

 

 

   

Total

     8,922,503        Mcfe           8,916,616        Mcfe   
  

 

 

        

 

 

   

Lease Bonus and Rentals

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

 

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Gains (Losses) on Derivative Contracts

Realized and unrealized gains and losses are scheduled below:

 

Gains (Losses) on       

Derivative Contracts

   2011     2010  

Realized

   $ 2,138,685      $ 2,209,900   

Unrealized

     (1,404,386     4,133,761   
  

 

 

   

 

 

 

Total

   $ 734,299      $ 6,343,661   
  

 

 

   

 

 

 

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

Lease Operating Expenses (LOE) and Production Taxes

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

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

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

Exploration Costs

Exploration costs were $1,025,542 in 2011 compared to $1,583,773 in 2010, a $558,231 decrease. During 2011, leasehold impairment and expired leasehold totaled $482,491 compared to $1,191,598 during 2010, a $709,107 decrease. The decline was driven by lower provisions for expected lease expirations in 2011, as compared to 2010. Charges on two exploratory dry holes totaled $543,051 during 2011; whereas, in 2010 the Company incurred minor exploratory dry hole costs totaling $4,541. During 2010, $387,634 was charged to exploration costs related to geological and geophysical costs paid upon the execution of a joint exploration agreement with a privately held independent operator to explore for oil in eastern Oklahoma.

Depreciation, Depletion and Amortization (DD&A)

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

 

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Provision for Impairment

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

Included in the 2011 total above, was an impairment charge of $716,448 on the Joiner City prospect, a horizontal Woodford Shale prospect in the oil and natural gas liquids-rich Marietta Basin in southern Oklahoma. The first well was drilled and completed during the first quarter of 2011 and is currently producing commercial quantities of oil and natural gas. As of September 30, 2011, this well had a net book value of $503,960 after impairment. Costs on this well were extraordinarily high due to this well being the first and only horizontal well drilled in the field.

Loss (Gain) on Asset Sales, Interest and Other

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

General and Administrative Costs (G&A)

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

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

Provision (Benefit) for Income Taxes

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

 

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LIQUIDITY AND CAPITAL RESOURCES

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

Liquidity

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

Net cash provided (used) by:

 

     2012     2011     Change  

Operating activities

   $ 25,371,195      $ 29,283,929      $ (3,912,734

Investing activities

   $ (38,288,959   $ (27,200,816   $ (11,088,143

Financing activities

   $ 11,394,864      $ (4,173,372   $ 15,568,236   
  

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

   $ (1,522,900   $ (2,090,259   $ 567,359   
  

 

 

   

 

 

   

 

 

 

Operating activities:

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

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

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

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

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

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

Investing activities:

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

 

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

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

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

Financing activities:

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

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

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

Capital Resources

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

 

   

Horizontal Granite Wash in western Oklahoma and the Texas Panhandle

 

   

Horizontal Cleveland in western Oklahoma and the Texas Panhandle

 

   

Horizontal Marmaton in western Oklahoma

 

   

Horizontal Tonkawa in western Oklahoma

 

   

Vertical Mississippian in northern Oklahoma

 

   

Vertical Spraberry in West Texas

 

   

Vertical Yeso in southeastern New Mexico

 

   

Horizontal Anadarko Basin Woodford Shale in western Oklahoma

 

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Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

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

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

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

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

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

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

 

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

Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and equipping of wells, treasury stock purchases and dividend payments primarily from cash flow and cash on hand. As management evaluates opportunities to acquire additional assets, additional borrowings utilizing our bank credit facility could be necessary. Also, during times of oil, NGL and natural gas price decreases, or increased expenditures for drilling, it may be necessary to utilize the credit facility further in order to fund these expenditures. The Company has availability ($20,125,015 at September 30, 2012) under its revolving credit facility and is in compliance with its debt covenants (current ratio, debt to EBITDA, tangible net worth and dividends as a percent of operating cash flow). While the Company believes the availability could be increased (if needed) by placing more of the Company’s properties as security under the revolving credit facility, increases are at the discretion of the bank.

Based on expected capital expenditure levels and anticipated cash flows for 2013, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund additional acquisitions.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

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

Determinations of the borrowing base are made semi-annually or whenever BOK believes there has been a material change in the value of the Company’s oil and natural gas properties. The loan agreement contains customary covenants, which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock and require the Company to maintain certain financial ratios. At September 30, 2012, the Company was in compliance with these covenants.

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

 

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     Payments due by period  

Contractual Obligations

and Commitments

   Total      Less than
1 Year
     1-3 Years      3-5 Years      More than
5 Years
 

Long-term debt obligations

   $ 14,874,985       $ —         $ 14,874,985       $ —         $ —     

Building lease

   $ 527,229       $ 204,089       $ 323,140       $ —         $ —     

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

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

CRITICAL ACCOUNTING POLICIES

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

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

Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. These estimates affect the unaudited standardized measure disclosures included in Note 11 to the financial statements in Item 8 – “Financial Statements and Supplementary Data,” as well as DD&A and impairment calculations. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, asset retirement obligations and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance

 

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history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing prices which are updated through the current period. In accordance with the SEC rules, the reserve estimates were based on average individual product prices during the 12-month period prior to September 30 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. Based on the Company’s 2012 DD&A, a 10% change in the DD&A rate per Mcfe would result in a corresponding $1,906,124 annual change in DD&A expense. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.

Successful Efforts Method of Accounting

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

Derivative Contracts

The Company entered into oil costless collar contracts, natural gas costless collar contracts, natural gas fixed swap contracts and natural gas basis protection swaps. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide for payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL currently). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are unsecured.

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

 

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Impairment of Assets

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

Non-producing oil and natural gas leases are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when recognized. As of September 30, 2012, the remaining carrying cost of non-producing oil and natural gas leases was $694,968.

Oil, NGL and Natural Gas Sales Revenue Accrual

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

Income Taxes

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

 

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

Refundable Production Taxes Accrual

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

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

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

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

 

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ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of oil, NGL and natural gas price trends, and there remains a wide divergence in the opinions held in the industry. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in oil or NGL prices. Longer term natural gas prices will be determined by the supply of and demand for natural gas as well as the prices of competing fuels, such as crude oil and coal. The market price of oil, NGL and natural gas in 2013 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2013 natural gas derivative contracts (see below), based on the Company’s estimated natural gas volumes for 2013, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,050,000 for operating revenue. Based on the Company’s estimated oil volumes for 2013, the price sensitivity in 2013 for each $1.00 per barrel change in wellhead oil is approximately $155,000 for operating revenue.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. As of September 30, 2012, the Company has natural gas basis protection swaps and oil and natural gas collars in place. All of our outstanding derivative contracts are with one counterparty and are unsecured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas and oil prices. These derivative contracts may expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s natural gas basis protection swaps, a change of $.10 in the basis differential from NYMEX and the indexed pipelines would result in a change to pre-tax operating income of approximately $57,000. For the Company’s natural gas collars, a change of $.10 in the forward strip prices would result in a change to pre-tax operating income of approximately $58,000. For the Company’s oil collars, a change of $1.00 in the forward strip prices would result in a change to pre-tax operating income of approximately $10,000.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facility. The revolving loan bears interest at the national prime rate plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. At September 30, 2012, the Company had $14,874,985 outstanding under this facility. At this point, the Company does not believe that its liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that its liquidity will be impacted in the near future.

 

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ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Management’s Annual Report on Internal Control Over Financial Reporting

     42   

Report of Registered Public Accounting Firm on Internal Control Over Financial Reporting

     43   

Report of Independent Registered Public Accounting Firm

     44   

Balance Sheets As of September 30, 2012 and 2011

     45   

Statements of Operations for the Years Ended September 30, 2012, 2011 and 2010

     47   

Statements of Stockholders’ Equity for the Years Ended September 30, 2012, 2011 and 2010

     48   

Statements of Cash Flows for the Years Ended September 30, 2012, 2011 and 2010

     49   

Notes to Financial Statements

     51   

 

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Management’s Annual Report on Internal Control Over Financial Reporting

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

 

   

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

 

   

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

 

   

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

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

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

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

 

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Report of Independent Registered Public Accounting Firm

on Internal Control Over Financial Reporting

The Board of Directors and Stockholders of

Panhandle Oil and Gas Inc.

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

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

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

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

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

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

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

December 11, 2012

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Panhandle Oil and Gas Inc.

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

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

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

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

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

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

December 11, 2012

 

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Panhandle Oil and Gas Inc.

Balance Sheets

 

     September 30,  
     2012      2011  

Assets

     

Current Assets:

     

Cash and cash equivalents

   $ 1,984,099       $ 3,506,999   

Oil, NGL and natural gas sales receivables

     8,349,865         8,811,404   

Refundable income taxes

     325,715         354,246   

Refundable production taxes

     585,454         223,672   

Deferred income taxes

     121,900         —     

Derivative contracts

     —           269,329   

Other

     255,812         95,408   
  

 

 

    

 

 

 

Total current assets

     11,622,845         13,261,058   

Properties and equipment at cost, based on successful efforts accounting:

     

Producing oil and natural gas properties

     275,997,569         230,554,198   

Non-producing oil and natural gas properties

     10,150,561         11,100,350   

Furniture and fixtures

     668,004         628,929   
  

 

 

    

 

 

 
     286,816,134         242,283,477   

Less accumulated depreciation, depletion and amortization

     165,199,079         146,147,514   
  

 

 

    

 

 

 

Net properties and equipment

     121,617,055         96,135,963   

Investments

     1,034,870         667,504   

Refundable production taxes

     911,960         1,359,668   
  

 

 

    

 

 

 

Total assets

   $ 135,186,730       $ 111,424,193   
  

 

 

    

 

 

 

(Continued on next page)

See accompanying notes.

 

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Panhandle Oil and Gas Inc.

Balance Sheets

 

     September 30,  
     2012     2011  

Liabilities and Stockholders’ Equity

    

Current Liabilities:

    

Accounts payable

   $ 6,447,692      $ 4,899,593   

Derivative contracts

     172,271        —     

Deferred income taxes

     —          7,100   

Accrued liabilities and other

     1,007,779        1,040,269   
  

 

 

   

 

 

 

Total current liabilities

     7,627,742        5,946,962   

Long term debt

     14,874,985        —     

Deferred income taxes

     26,708,907        24,777,650   

Asset retirement obligations

     2,122,950        1,843,875   

Derivative contracts

     —          53,389   

Stockholders’ equity:

    

Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at September 30, 2012 and 2011

     140,524        140,524   

Capital in excess of par value

     2,020,229        1,924,507   

Deferred directors’ compensation

     2,676,160        2,665,583   

Retained earnings

     84,821,395        79,771,563   
  

 

 

   

 

 

 
     89,658,308        84,502,177   

Treasury stock, at cost; 181,310 shares at September 30, 2012, and 175,331 shares at September 30, 2011

     (5,806,162     (5,699,860
  

 

 

   

 

 

 

Total stockholders’ equity

     83,852,146        78,802,317   
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 135,186,730      $ 111,424,193   
  

 

 

   

 

 

 

See accompanying notes.

 

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Table of Contents

Panhandle Oil and Gas Inc.

Statements of Operations

 

     Year ended September 30,  
     2012      2011     2010  

Revenues:

       

Oil, NGL and natural gas sales

   $ 40,818,434       $ 43,469,130      $ 44,068,947   

Lease bonuses and rentals

     7,152,991         352,757        1,120,674   

Gains (losses) on derivative contracts

     73,822         734,299        6,343,661   

Income from partnerships

     487,070         420,465        405,134   
  

 

 

    

 

 

   

 

 

 
     48,532,317         44,976,651        51,938,416   

Costs and expenses:

       

Lease operating expenses

     9,141,970         8,441,754        8,193,319   

Production taxes

     1,449,537         1,456,755        1,446,545   

Exploration costs

     979,718         1,025,542        1,583,773   

Depreciation, depletion and amortization

     19,061,239         14,712,188        19,222,123   

Provision for impairment

     826,508         1,728,162        605,615   

Loss (gain) on asset sales, interest and other

     39,493         (68,325     (1,028,148

General and administrative

     6,388,856         5,994,663        5,594,499   
  

 

 

    

 

 

   

 

 

 
     37,887,321         33,290,739        35,617,726   
  

 

 

    

 

 

   

 

 

 

Income (loss) before provision (benefit) for income taxes

     10,644,996         11,685,912        16,320,690   

Provision (benefit) for income taxes

     3,274,000         3,192,000        4,901,000   
  

 

 

    

 

 

   

 

 

 

Net income (loss)

   $ 7,370,996       $ 8,493,912      $ 11,419,690   
  

 

 

    

 

 

   

 

 

 

Basic and diluted earnings per common share:

       

Net income (loss)

   $ 0.88       $ 1.01      $ 1.36   
  

 

 

    

 

 

   

 

 

 

See accompanying notes.

 

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Panhandle Oil and Gas Inc.

Statements of Stockholders’ Equity

 

     Class A voting      Capital in     Deferred                    
     Common Stock      Excess of     Directors     Retained     Treasury     Treasury        
     Shares      Amount      Par Value     Compensation     Earnings     Shares     Stock     Total  

Balances at September 30, 2009

     8,431,502       $ 140,524       $ 1,922,053      $ 1,862,499      $ 64,507,547        (119,866   $ (4,310,280   $ 64,122,343   

Purchase of treasury stock

     —           —           —          —          —          (12,326     (291,383     (291,383

Issuance of treasury shares to ESOP

     —           —           (117,716     —          —          11,632        404,910        287,194   

Restricted stock awards

     —           —           12,028        —          —          —          —          12,028   

Common shares to be issued to directors for services

     —           —           —          359,628        —          —          —          359,628   

Dividends declared ($.28 per share)

     —           —           —          —          (2,327,504     —          —          (2,327,504

Net income

     —           —           —          —          11,419,690        —          —          11,419,690   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balances at September 30, 2010

     8,431,502       $ 140,524       $ 1,816,365      $ 2,222,127      $ 73,599,733        (120,560   $ (4,196,753   $ 73,581,996   

Purchase of treasury stock

     —           —           —          —          —          (65,481     (1,851,290     (1,851,290

Issuance of treasury shares to ESOP

     —           —           (44,340     —          —          10,710        348,183        303,843   

Restricted stock awards

     —           —           152,482        —          —          —          —          152,482   

Common shares to be issued to directors for services

     —           —           —          443,456        —          —          —          443,456   

Dividends declared ($.28 per share)

     —           —           —          —          (2,322,082     —          —          (2,322,082

Net income

     —           —           —          —          8,493,912        —          —          8,493,912   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balances at September 30, 2011

     8,431,502       $ 140,524       $ 1,924,507      $ 2,665,583      $ 79,771,563        (175,331   $ (5,699,860   $ 78,802,317   

Purchase of treasury stock

     —           —           —          —          —          (38,771     (1,158,957     (1,158,957

Issuance of treasury shares to ESOP

     —           —           (14,391     —          —          10,660        341,333        326,942   

Restricted stock awards

     —           —           330,923        —          —          —          —          330,923   

Distribution of deferred directors’ compensation

     —           —           (220,810     (406,770     —          22,132        711,322        83,742   

Common shares to be issued to directors for services

     —           —           —          417,347        —          —          —          417,347   

Dividends declared ($.28 per share)

     —           —           —          —          (2,321,164     —          —          (2,321,164

Net income

     —           —           —          —          7,370,996        —          —          7,370,996   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balances at September 30, 2012

     8,431,502       $ 140,524       $ 2,020,229      $ 2,676,160      $ 84,821,395        (181,310   $ (5,806,162   $ 83,852,146   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes.

 

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Table of Contents

Panhandle Oil and Gas Inc.

Statements of Cash Flows

 

     Year ended September 30,  
     2012     2011     2010  

Operating Activities

      

Net income (loss)

   $ 7,370,996      $ 8,493,912      $ 11,419,690   

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

      

Depreciation, depletion and amortization

     19,061,239        14,712,188        19,222,123   

Impairment

     826,508        1,728,162        605,615   

Provision for deferred income taxes

     1,802,257        1,878,000        777,000   

Exploration costs

     979,718        1,025,542        1,208,653   

Gain from leasing of fee mineral acreage

     (7,146,299     (352,642     (1,189,648

Net (gain) loss on sales of assets

     (122,504     2,112        43   

Income from partnerships

     (487,070     (420,465     (405,134

Distributions received from partnerships

     601,300        553,382        523,317   

Other

     —          —          64,555   

Common stock contributed to ESOP

     326,942        303,843        287,194   

Common stock (unissued) to Directors’ Deferred Compensation Plan

     417,347        443,456        359,628   

Restricted stock awards

     330,923        152,482        12,028   

Cash provided (used) by changes in assets and liabilities:

      

Oil, NGL and natural gas sales receivables

     461,539        251,598        (1,315,445

Fair value of dervative contracts

     388,211        1,404,386        (4,133,761

Refundable income taxes

     28,531        (354,246     —     

Refundable production taxes

     85,926        (124,621     (69,874

Other current assets

     (108,098     317,370        (343,961

Accounts payable

     585,912        72,119        (24,896

Other non-current assets

     308        —          —     

Income taxes payable

     —          (922,136     583,625   

Accrued liabilities

     (32,490     119,487        225,723   
  

 

 

   

 

 

   

 

 

 

Total adjustments

     18,000,200        20,790,017        16,386,785   
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     25,371,196        29,283,929        27,806,475   

(Continued on next page)

 

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Table of Contents

Panhandle Oil and Gas Inc.

Statements of Cash Flows (continued)

 

     Year ended September 30,  
     2012     2011     2010  

Investing Activities

      

Capital expenditures, including dry hole costs

   $ (25,147,306   $ (22,739,908   $ (11,308,506

Acquistion of working interest properties

     (17,399,052     (185,125     —     

Acquistion of minerals and overrides

     (2,745,069     (4,620,315     —     

Proceeds from leasing of fee mineral acreage

     7,265,808        389,807        1,316,377   

Investments in partnerships

     (481,904     (46,213     (254,555

Proceeds from sales of assets

     134,821        938        401,168   

Excess tax benefit on stock-based compensation

     83,742        —          —     
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (38,288,960     (27,200,816     (9,845,516

Financing Activities

      

Borrowings under debt agreement

     43,475,443        —          10,799,814   

Payments of loan principal

     (28,600,458     —          (21,184,536

Purchases of treasury stock

     (1,158,957     (1,851,290     (291,383

Payments of dividends

     (2,321,164     (2,322,082     (2,327,504
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     11,394,864        (4,173,372     (13,003,609
  

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

     (1,522,900     (2,090,259     4,957,350   

Cash and cash equivalents at beginning of year

     3,506,999        5,597,258        639,908   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of year

   $ 1,984,099      $ 3,506,999      $ 5,597,258   
  

 

 

   

 

 

   

 

 

 

Supplemental Disclosures of Cash Flow Information

      

Interest paid (net of capitalized interest)

   $ 127,970      $ —        $ 60,912   

Income taxes paid, net of refunds received

   $ 1,356,706      $ 2,584,172      $ 3,530,718   

Supplemental schedule of noncash investing and financing activities:

      

Additions and revisions, net, to asset retirement obligations

   $ 279,075      $ 113,506      $ 110,144   

Gross additions to properties and equipment

   $ 46,201,308      $ 27,310,016      $ 11,585,521   

Net (increase) decrease in accounts payable for properties and equipment additions

     (909,881     235,332        (277,015
  

 

 

   

 

 

   

 

 

 

Capital expenditures, including dry hole costs

   $ 45,291,427      $ 27,545,348      $ 11,308,506   

See accompanying notes.

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements

September 30, 2012, 2011 and 2010

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Since its formation, the Company has been involved in the acquisition and management of fee mineral acreage and the exploration for, and development of, oil and natural gas properties, principally involving drilling wells located on the Company’s mineral acreage. Panhandle’s mineral properties and other oil and natural gas interests are all located in the United States, primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. The Company is not the operator of any wells. The Company’s oil, NGL and natural gas production is from interests in 5,666 wells located principally in Oklahoma and Arkansas. Approximately 58% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2012. Approximately 86% of the Company’s total sales volumes in 2012 were derived from the sale of natural gas. Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells. The Company from time to time disposes of certain non-material, non-core or small-interest oil and natural gas properties in the normal course of business.

Basis of Presentation

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

Use of Estimates

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

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

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

Cash and Cash Equivalents

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

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

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

The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves. At September 30, 2012 and 2011, the Company had no material natural gas imbalances.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers of oil, NGL and natural gas or operators of the oil and natural gas properties. Oil, NGL and natural gas sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our oil, NGL and natural gas and the operators of the properties we have an interest in may be similarly affected by changes in economic, industry or other conditions. During 2012 and 2011, we did not recognize a reserve for bad debt expense.

Derivative contracts entered into by the Company are also unsecured.

Oil and Natural Gas Producing Activities

The Company follows the successful efforts method of accounting for oil and natural gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income if and when the well is determined to be nonproductive. Oil and natural gas mineral and leasehold costs are capitalized when incurred.

Non-producing oil and natural gas leases are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when recognized. As of September 30, 2012, the remaining carrying cost of non-producing oil and natural gas leases was $694,968.

It is common business practice in the petroleum industry for drilling costs to be prepaid before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2012, the Company had no outstanding letters of credit.

Lease Bonus

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

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

Derivatives

The Company entered into oil costless collar contracts, natural gas costless collar contracts, natural gas fixed swap contracts and natural gas basis protection swaps. These instruments were intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

Derivative contracts in place as of September 30, 2011

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

 

Contract period

   Production volume
covered per month
   Indexed (1)
Pipeline
   Fixed price

Natural gas fixed price swaps

        

April - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.65

April - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.65

April - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.70

April - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.75

May - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.50

May - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.60

June - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.63

Natural gas basis protection swaps

        

January - December 2011

   50,000 Mmbtu    CEGT    NYMEX -$.27

January - December 2011

   50,000 Mmbtu    CEGT    NYMEX -$.27

January - December 2011

   50,000 Mmbtu    PEPL    NYMEX -$.26

January - December 2011

   50,000 Mmbtu    PEPL    NYMEX -$.27

January - December 2011

   70,000 Mmbtu    PEPL    NYMEX -$.36

January - December 2012

   50,000 Mmbtu    CEGT    NYMEX -$.29

January - December 2012

   40,000 Mmbtu    CEGT    NYMEX -$.30

January - December 2012

   50,000 Mmbtu    PEPL    NYMEX -$.29

January - December 2012

   50,000 Mmbtu    PEPL    NYMEX -$.30

Oil costless collars

        

April - December 2011

   5,000 Bbls    NYMEX WTI    $100 floor/$112 ceiling

 

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

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

Derivative contracts in place as of September 30, 2012

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

 

Contract period

   Production volume
covered per month
   Indexed  (1)
pipeline
   Fixed price

Natural gas basis protection swaps

        

January - December 2012

   50,000 Mmbtu    CEGT    NYMEX -$.29

January - December 2012

   40,000 Mmbtu    CEGT    NYMEX -$.30

January - December 2012

   50,000 Mmbtu    PEPL    NYMEX -$.29

January - December 2012

   50,000 Mmbtu    PEPL    NYMEX -$.30

Natural gas costless collars

        

March - October 2012

   50,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.25 ceiling

April - October 2012

   120,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.10 ceiling

April - October 2012

   60,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.20 ceiling

April - October 2012

   50,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.20 ceiling

April - October 2012

   50,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.45 ceiling

April - October 2012

   50,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.30 ceiling

August - October 2012

   50,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.30 ceiling

November 2012 - January 2013

   150,000 Mmbtu    NYMEX Henry Hub    $3.00 floor/$3.70 ceiling

November 2012 - January 2013

   150,000 Mmbtu    NYMEX Henry Hub    $3.00 floor/$3.70 ceiling

November 2012 - January 2013

   50,000 Mmbtu    NYMEX Henry Hub    $3.00 floor/$3.65 ceiling

Oil costless collars

        

January - December 2012

   2,000 Bbls    NYMEX WTI    $90 floor/$105 ceiling

February - December 2012

   3,000 Bbls    NYMEX WTI    $90 floor/$110 ceiling

May - December 2012

   2,000 Bbls    NYMEX WTI    $90 floor/$114 ceiling

 

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

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

While the Company believes that its derivative contracts are effective in achieving the risk management objective for which they were intended, the Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a liability of $172,271 as of September 30, 2012, and a net asset of $215,940 as of September 30, 2011. Realized and unrealized gains and (losses) are scheduled below:

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

 

Gains (losses) on natural gas

derivative contracts

   Fiscal year ended  
   9/30/2012     9/30/2011     9/30/2010  

Realized

   $ 462,033      $ 2,138,685      $ 2,209,900   

Increase (decrease) in fair value

     (388,211     (1,404,386     4,133,761   
  

 

 

   

 

 

   

 

 

 

Total

   $ 73,822      $ 734,299      $ 6,343,661   
  

 

 

   

 

 

   

 

 

 

To the extent that a legal right of offset exists, the Company nets the fair value of its derivative contracts with the same counterparty in the accompanying balance sheets. The following table summarizes the Company’s derivative contracts as of September 30, 2012, and September 30, 2011:

 

    

Balance Sheet

Location

   9/30/2012
Fair Value
     9/30/2011
Fair Value
 

Asset Derivatives:

        

Derivatives not designated as Hedging Instruments:

     

Commodity contracts

   Short-term derivative contracts    $ —         $ 269,329   

Commodity contracts

   Long-term derivative contracts      —           —     
     

 

 

    

 

 

 

Total Asset Derivatives (a)

   $ —         $ 269,329   
     

 

 

    

 

 

 

Liability Derivatives:

        

Derivatives not designated as Hedging Instruments:

     

Commodity contracts

   Short-term derivative contracts    $ 172,271       $ —     

Commodity contracts

   Long-term derivative contracts      —           53,389   
     

 

 

    

 

 

 

Total Liability Derivatives (a)

   $ 172,271       $ 53,389   
     

 

 

    

 

 

 

 

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

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

Fair Value Measurements

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

for the asset or liability; or (iv) inputs that are derived principally from, or corroborated by, observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability. Counterparty quotes are generally assessed as a Level 3 input.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis.

 

     Fair Value Measurement at September 30, 2012  
     Quoted
Prices  in
Active
Markets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs
(Level 3)
    Total Fair
Value
 

Financial Assets (Liabilities):

         

Derivative Contracts - Swaps

   $ —         $ (75,334   $ —        $ (75,334

Derivative Contracts - Collars

   $ —         $ —        $ (96,937   $ (96,937

 

     Fair Value Measurement at September 30, 2011  
     Quoted
Prices  in
Active
Markets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs
(Level 3)
     Total Fair
Value
 

Financial Assets (Liabilities):

          

Derivative Contracts - Swaps

   $ —         $ (77,907   $ —         $ (77,907

Derivative Contracts - Collars

   $ —         $ —        $ 293,847       $ 293,847   

Level 2 – Market Approach - The fair values of the Company’s natural gas swaps are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas curves, or can be corroborated from active markets. These values are based upon, among other things, future prices and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

Level 3 – The fair values of the Company’s oil and natural gas collar contracts are based on a pricing model which utilizes inputs that are unobservable or not readily available in the public market. These values are based upon, among other things, future prices, volatility and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

prices and volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives, and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.

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

 

     Derivatives  

Balance of Level 3 as of October 1, 2011

   $ 293,847   

Total gains or (losses) - realized and unrealized:

  

Included in earnings

  

Realized

     549,773   

Unrealized

     (940,557

Included in other comprehensive income (loss)

     —     

Purchases, issuances and settlements

     —     

Transfers in and out of Level 3

     —     
  

 

 

 

Balance of Level 3 as of September 30, 2012

   $ (96,937
  

 

 

 

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

 

     Year Ended September 30,  
     2012      2011  
     Fair Value      Impairment      Fair Value      Impairment  

Producing Properties

   $ 1,301,951       $ 826,508       $ 1,811,709       $ 1,728,162 (a) 

 

  (a) At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.

The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, refundable income taxes, accounts payable and accrued liabilities approximate their fair values due to the short maturity of these instruments. The fair value of Company’s debt approximates its carrying amount as the interest rates on the Company’s revolving line of credit are approximately equivalent to market rates for similar type debt based on the Company’s credit worthiness, which represents level 3 of the fair value hierarchy.

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

Depreciation, Depletion, Amortization and Impairment

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

Non-producing oil and natural gas properties include non-producing minerals, which had a net book value of $5,374,868 and $5,215,239 at September 30, 2012 and 2011, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 86-year life of the Company. There are approximately 198,965 net acres of non-producing minerals in more than 6,931 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $45. Since inception, the Company has continually generated an interest in several thousand oil and natural gas wells using its ownership of the fee mineral acres as an ownership basis. There continues to be significant drilling activity each year on these mineral interests. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (as do oil and natural gas leases). Given the above, it was concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company's estimate of fair value of its oil and natural gas properties at September 30, 2012, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $826,508, $1,728,162 and $605,615, respectively, for 2012, 2011 and 2010. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes would likely lead to additional impairment in future periods that may be material to the Company.

Capitalized Interest

During 2012, 2011 and 2010, interest of $129,172, $0 and $104,100, respectively, was included in the Company’s capital expenditures. Interest of $127,970, $0 and $60,912, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using unit-of-production method.

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

Investments

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

Asset Retirement Obligations

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

The following table shows the activity for the years ended September 30, 2012 and 2011, relating to the Company’s asset retirement obligations:

 

     2012     2011  

Asset Retirement Obligations as of beginning of the year

   $ 1,843,875      $ 1,730,369   

Accretion of Discount

     121,112        109,198   

New Wells Placed on Production

     184,027        28,624   

Wells Sold or Plugged

     (26,064     (24,316
  

 

 

   

 

 

 

Asset Retirement Obligations as of end of the year

   $ 2,122,950      $ 1,843,875   
  

 

 

   

 

 

 

Environmental Costs

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2012 and 2011, there were no such costs accrued.

Earnings (Loss) Per Share of Common Stock

Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, including unissued, vested directors’ shares during the period. The Company’s restricted stock awards are not included in the diluted earnings per share calculation because the effect would be non-dilutive.

Share-based Compensation

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

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

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

Income Taxes

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

The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2007.

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

 

The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Operations. For fiscal September 30, 2012, 2011 and 2010, the Company recorded interest and penalties of $0, $21,000 and $0, respectively. The Company does not believe it has any significant uncertain tax positions.

New Accounting Standards

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

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

2. COMMITMENTS

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

3. INCOME TAXES

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

 

     2012      2011     2010  

Current:

       

Federal

   $ 1,452,000       $ 1,266,000      $ 3,950,000   

State

     20,000         48,000        174,000   
  

 

 

    

 

 

   

 

 

 
     1,472,000         1,314,000        4,124,000   

Deferred:

       

Federal

     1,126,000         1,982,000        708,000   

State

     676,000         (104,000     69,000   
  

 

 

    

 

 

   

 

 

 
     1,802,000         1,878,000        777,000   
  

 

 

    

 

 

   

 

 

 
   $ 3,274,000       $ 3,192,000      $ 4,901,000   
  

 

 

    

 

 

   

 

 

 

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

 

     2012     2011     2010  

Provision (benefit) for income taxes at statutory rate

   $ 3,725,749      $ 4,090,069      $ 5,712,242   

Percentage depletion

     (846,040     (733,516     (684,053

State income taxes, net of federal provision (benefit)

     464,677        (92,989     325,000   

State net operating loss valuation allowance (release)

     (31,000     31,000        (278,000

Other

     (39,386     (102,564     (174,189
  

 

 

   

 

 

   

 

 

 
   $ 3,274,000      $ 3,192,000      $ 4,901,000   
  

 

 

   

 

 

   

 

 

 

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

3. INCOME TAXES (CONTINUED)

 

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

 

     2012      2011  

Deferred tax liabilities:

     

Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes

   $ 30,320,765       $ 26,939,720   

Derivative contracts

     —           84,001   
  

 

 

    

 

 

 
     30,320,765         27,023,721   

Deferred tax assets:

     

State net operating loss carry forwards, net of valuation allowance of $0 in 2012 and $31,000 in 2011

     1,008,271         1,130,732   

AMT credit carry forwards

     1,189,053         —     

Deferred directors’compensation

     990,455         986,340   

Statutory depletion carry forwards

     415,958         —     

Other

     130,021         121,899   
  

 

 

    

 

 

 
     3,733,758         2,238,971   
  

 

 

    

 

 

 

Net deferred tax liabilities

   $ 26,587,007       $ 24,784,750   
  

 

 

    

 

 

 

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

4. LONG-TERM DEBT

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan with a limit in the amount of $80,000,000 which is subject to a semi-annual borrowing base determination, wherein BOK applies their own pricing forecast and an 8% discount rate to the Company’s proved reserves as calculated by the Company’s Independent Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to risk all proved non-producing and proved undeveloped reserves. The facility has a borrowing base of $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $41,343,303 at September 30, 2012. The facility matures on November 30, 2014. The interest rate is based on national prime plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced. The balance outstanding under the revolving loan was $14,874,985 and $0 as of September 30, 2012 and 2011, respectively. At September 30, 2012, the effective interest rate was 2.36%.

Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties.

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

4. LONG-TERM DEBT (CONTINUED)

 

The credit facility contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2012, the Company was in compliance with the covenants of the credit facility.

5. SHAREHOLDERS’ EQUITY

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

6. EARNINGS PER SHARE

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

 

     Year ended September 30,  
     2012      2011      2010  

Numerator for basic and diluted earnings per share:

        

Net income (loss)

   $ 7,370,996       $ 8,493,912       $ 11,419,690   
  

 

 

    

 

 

    

 

 

 

Denominator for basic and diluted earnings per share - weighted average shares (including for 2012, 2011 and 2010, unissued, vested directors’ shares of 114,596, 122,728 and 111,491, respectively)

     8,360,931         8,393,890         8,422,387   
  

 

 

    

 

 

    

 

 

 

7. EMPLOYEE STOCK OWNERSHIP PLAN

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

7. EMPLOYEE STOCK OWNERSHIP PLAN (CONTINUED)

 

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

Contributions to the plan consisted of:

 

Year

   Shares      Amount  

2012

     10,660       $ 326,942   

2011

     10,710       $ 303,843   

2010

     11,632       $ 287,194   

8. DEFERRED COMPENSATION PLAN FOR DIRECTORS

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

9. RESTRICTED STOCK PLAN

On March 11, 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 100,000 shares of Common Stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. The 2010 Stock Plan is designed to provide as much flexibility as possible for future grants of restricted stock so the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

In June 2010, the Company began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to certain officers. The restricted stock vests at the end of the vesting period (three or five years) and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares was based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

9. RESTRICTED STOCK PLAN (CONTINUED)

 

over the vesting period (three years). The fair value of the performance shares was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period (three years) regardless of whether performance shares are awarded at the end of the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.

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

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

 

     Year Ended September 30,  
     2012      2011      2010  

Performance based, restricted stock

   $ 150,480       $ 42,909       $ —     

Non-performance based, restricted stock

     180,443         109,573         12,028   
  

 

 

    

 

 

    

 

 

 

Total compensation expense

   $ 330,923       $ 152,482       $ 12,028   

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

 

     As of September 30, 2012  
     Unrecognized
Compensation
     Weighted
Average Period
 

Performance based, restricted stock

   $ 322,977         1.89   

Non-performance based, restricted stock

     370,587         2.05   
  

 

 

    

Total

   $ 693,564      

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

9. RESTRICTED STOCK PLAN (CONTINUED)

 

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

 

     Performance
based
Unvested
Restricted
Shares
     Weighted
Average
Grant-
Date Fair
Value
     Non-
Performance
based  Unvested
Restricted
Shares
     Weighted
Average
Grant-Date
Fair Value
 

Unvested shares as of September 30, 2010

     —         $ —           8,500       $ 28.30   

Granted

     8,782       $ 19.54         8,780       $ 28.00   

Vested

     —         $ —           —         $ —     

Forfeited

     —         $ —           —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Unvested shares as of September 30, 2011

     8,782       $ 19.54         17,280       $ 28.15   

Granted

     17,709       $ 19.47         5,903       $ 31.55   

Vested

     —         $ —           —         $ —     

Forfeited

     —         $ —           —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Unvested shares as of September 30, 2012

     26,491       $ 19.49         23,183       $ 29.01   

10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

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

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

 

     2012     2011     2010  

Southwestern Energy Company

     15     9     8

Chesapeake Operating, Inc.

     13     15     14

Devon Energy Corp.

     10     9     6

Newfield Exploration

     7     14     15

JMA Energy Company

     5     7     11

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

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

Aggregate Capitalized Costs

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

 

     2012     2011  

Producing properties

   $ 275,997,569      $ 230,554,198   

Non-producing minerals

     9,018,731        8,792,980   

Non-producing leasehold

     1,123,812        1,102,988   

Exploratory wells in progress

     8,018        1,204,382   
  

 

 

   

 

 

 
     286,148,130        241,654,548   

Accumulated depreciation, depletion and amortization

     (164,652,199     (145,664,726
  

 

 

   

 

 

 

Net capitalized costs

   $ 121,495,931      $ 95,989,822   
  

 

 

   

 

 

 

Costs Incurred

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

 

     2012      2011      2010  

Property acquisition costs

   $ 20,404,465       $ 5,140,862       $ 742,005   

Exploration costs

     1,210,417         4,837,451         530,931   

Development costs

     24,578,943         17,310,808         10,685,088   
  

 

 

    

 

 

    

 

 

 
   $ 46,193,825       $ 27,289,121       $ 11,958,024   
  

 

 

    

 

 

    

 

 

 

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

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

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

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

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

 

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

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

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

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

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

 

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

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

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

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

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

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

 

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

 

     Proved Reserves  
     Oil     NGL (1)     Natural Gas  
     (Barrels)     (Barrels)     (Mcf)  

September 30, 2009

     920,873        —          54,027,810   

Revisions of previous estimates

     47,999        —          15,762,883   

Divestitures

     (487     —          (7,778

Extensions, discoveries and other additions

     59,003        —          36,689,882   

Production

     (102,379     —          (8,302,342
  

 

 

   

 

 

   

 

 

 

September 30, 2010

     925,009        —          98,170,455   

Revisions of previous estimates

     (59,360     791,648        769,676   

Acquisitions

     —          —          3,189,520   

Extensions, discoveries and other additions

     82,230        —          8,005,990   

Production

     (104,141     —          (8,297,657
  

 

 

   

 

 

   

 

 

 

September 30, 2011

     843,738        791,648        101,837,984   

Revisions of previous estimates

     8,627        (76,794     (27,389,752

Acquisitions

     —          —          19,075,529   

Extensions, discoveries and other additions

     373,097        172,602        29,062,593   

Production

     (153,143     (98,714     (9,072,298
  

 

 

   

 

 

   

 

 

 

September 30, 2012

     1,072,319        788,742        113,514,056   
  

 

 

   

 

 

   

 

 

 

 

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

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

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

 

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

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

 

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

 

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

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

 

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

 

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

 

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

 

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

 

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

 

     Proved Developed Reserves      Proved Undeveloped Reserves  
     Oil      NGL      Natural Gas      Oil      NGL      Natural Gas  
     (Barrels)      (Barrels)      (Mcf)      (Barrels)      (Barrels)      (Mcf)  

September 30, 2010

     861,240         —           57,344,190         63,769         —           40,826,265   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

September 30, 2011

     759,989         386,774         60,193,878         83,749         404,874         41,644,106   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

September 30, 2012

     849,548         494,160         65,733,119         222,771         294,582         47,780,937   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

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

 

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

 

Beginning proved undeveloped reserves

     44,575,844   

Proved undeveloped reserves transferred to proved developed

     (5,393,421

Revisions

     (22,369,152

Extensions and discoveries

     24,458,980   

Purchases

     9,612,804   
  

 

 

 

Ending proved undeveloped reserves

     50,885,055   

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

Standardized Measure of Discounted Future Net Cash Flows

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

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

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

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

 

 

     2012     2011     2010  

Future cash inflows

   $ 408,694,869      $ 494,523,456      $ 489,691,155   

Future production costs

     (135,516,703     (146,168,829     (148,727,914

Future development costs

     (33,167,310     (43,425,811     (52,975,820

Asset retirement obligation

     (2,122,950     (1,843,875     (1,730,369

Future income tax expense

     (83,543,516     (107,111,317     (99,118,090
  

 

 

   

 

 

   

 

 

 

Future net cash flows

     154,344,390        195,973,624        187,138,962   

10% annual discount

     (86,930,102     (117,591,190     (114,638,553
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 67,414,288      $ 78,382,434      $ 72,500,409   
  

 

 

   

 

 

   

 

 

 

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

 

     2012     2011     2010  

Beginning of year

   $ 78,382,434      $ 72,500,409      $ 53,746,508   

Changes resulting from:

      

Sales of oil, NGL and natural gas, net of production costs

     (30,226,927     (33,570,621     (34,429,083

Net change in sales prices and production costs

     (45,178,377     (2,697,833     30,806,970   

Net change in future development costs

     4,618,147        4,177,910        (26,093,254

Net change in asset retirement obligation

     (134,604     (51,098     (48,185

Extensions and discoveries

     34,216,533        11,938,029        53,274,047   

Revisions of quantity estimates

     (27,419,576     7,046,873        28,946,810   

Acquisitions (divestitures) of reserves-in-place

     20,160,327        4,480,858        (15,706

Accretion of discount

     13,644,203        12,523,091        8,066,959   

Net change in income taxes

     10,735,694        (5,329,092     (25,807,417

Change in timing and other, net

     8,616,434        7,363,908        (15,947,240
  

 

 

   

 

 

   

 

 

 

Net change

     (10,968,146     5,882,025        18,753,901   
  

 

 

   

 

 

   

 

 

 

End of year

   $ 67,414,288      $ 78,382,434      $ 72,500,409   
  

 

 

   

 

 

   

 

 

 

12. ACQUISITIONS

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

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

12. ACQUISITIONS (CONTINUED)

 

Actual and Pro Forma Impact of Acquisitions (Unaudited)

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

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

 

     For the Year Ended  
     September 30  
     2012      2011  

Revenue:

     

As reported

   $ 48,532,317       $ 44,976,651   

Pro forma revenue

     409,988         4,433,282   
  

 

 

    

 

 

 

Pro forma

   $ 48,942,305       $ 49,409,933   

Net Income:

     

As reported

   $ 7,370,996       $ 8,493,912   

Pro forma income

     136,315         644,859   
  

 

 

    

 

 

 

Pro forma

   $ 7,507,311       $ 9,138,771   

 

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Table of Contents

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 

13. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

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

 

     Fiscal 2012  
     Quarter Ended  
     December 31      March 31      June 30      September 30  

Revenues

   $ 13,404,333       $ 10,436,910       $ 13,649,692       $ 11,041,382   

Income (loss) before provision for income taxes

   $ 4,261,110       $ 1,205,966       $ 4,681,299       $ 496,621   

Net income (loss)

   $ 3,412,110       $ 675,966       $ 3,100,299       $ 182,621   

Earnings (loss) per share

   $ 0.41       $ 0.08       $ 0.37       $ 0.02   
     Fiscal 2011  
     Quarter Ended  
     December 31      March 31      June 30      September 30  

Revenues

   $ 9,901,548       $ 10,977,459       $ 11,688,417       $ 12,409,227   

Income (loss) before provision for income taxes

   $ 2,002,849       $ 2,271,253       $ 3,691,429       $ 3,720,381   

Net income (loss)

   $ 1,426,849       $ 1,772,253       $ 2,650,429       $ 2,644,381   

Earnings (loss) per share

   $ 0.17       $ 0.21       $ 0.32       $ 0.31   

 

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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, 2012.

(c)     CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter ended September 30, 2012, or subsequent to the date the assessment was completed.

 

ITEM 9B OTHER INFORMATION

None

 

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

EXHIBITS

 

  (3) Amended Certificate of Incorporation (incorporated by reference to Exhibit attached to Form 10 filed January 27, 1980, and to Forms 8-K dated June 1, 1982, December 3, 1982, to Form 10-QSB dated March 31, 1999, and to Form 10-Q dated March 31, 2007)
       By-Laws as amended (incorporated by reference to Form 8-K dated October 31, 1994)
       By-Laws as amended (incorporated by reference to Form 8-K dated February 24, 2006)
       By-Laws as amended (incorporated by reference to Form 8-K dated October 29, 2008)
       By-Laws as amended (incorporated by reference to Form 8-K dated August 2, 2011)

 

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

 

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

 

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

 

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

 

  (31.1) Certification of Chief Executive Officer

 

  (31.2) Certification of Chief Financial Officer

 

  (32.1) Certification of Chief Executive Officer

 

  (32.2) Certification of Chief Financial Officer

 

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

 

  (101.INS) XBRL Instance Document

 

  (101.SCH) XBRL Taxonomy Extension Schema Document

 

  (101.CAL) XBRL Taxonomy Extension Calculation Linkbase Document

 

  (101.LAB) XBRL Taxonomy Extension Labels Linkbase Document

 

  (101.PRE) XBRL Taxonomy Extension Presentation Linkbase Document

 

  (101.DEF) XBRL Taxonomy Extension Definition Linkbase Document

 

* Indicates management contract or compensatory plan or arrangement

 

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Table of Contents

REPORTS ON FORM 8-K

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

SIGNATURES

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

 

  PANHANDLE OIL AND GAS INC.  
  By:   /s/ Michael C. Coffman     By:   /s/ Lonnie J. Lowry
 

Michael C. Coffman

President;

Chief Executive Officer

 

Lonnie J. Lowry

Vice President;

Chief Financial Officer

  Date: December 11, 2012   Date: December 11, 2012
  By:   /s/ Robb P. Winfield    
 

Robb P. Winfield

Controller;

Chief Accounting Officer

 
  Date: December 11, 2012  

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

 

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

 

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