ITEM 1 BUSINESS
GENERAL
Panhandle Oil and Gas Inc. (“Panhandle” or the “Company”) is an Oklahoma corporation organized in 1926 as Panhandle Cooperative Royalty Company. In 1979, Panhandle Cooperative Royalty Company was merged into Panhandle Royalty Company. In April, 2007, Panhandle Royalty Company changed its name to Panhandle Oil and Gas Inc. Panhandle’s original authorized and registered stock consisted of 100,000 shares of $1.00 par value Class A Common Stock. In 1982, the Company split the stock on a 10-for-1 basis resulting in 1,000,000 shares of authorized Class A Common Stock. In May 1999, the Company’s shareholders voted to increase the authorized Class A Common Stock to 6,000,000 shares and to split the shares on a three-for-one basis. In addition, voting rights for the shares were changed from one vote per shareholder to one vote per share. In February 2004, the Company’s shareholders voted to increase the authorized Class A Common Stock to 12,000,000 shares and to split the shares on a two-for-one basis. In January 2006, the Class A Common Stock was again split on a two-for-one basis. In March 2007, the Company’s shareholders voted to increase the authorized Class A Common Stock to the current 24,000,000 shares.
Since its formation, the Company has been involved in the acquisition, management and development of oil and gas properties, including wells located on the Company’s mineral acreage. Panhandle’s mineral properties and other oil and gas interests are located primarily in Arkansas, Kansas, Oklahoma, New Mexico and Texas. Properties are also located in seven other states. The majority of the Company’s oil and gas production is from wells located in Oklahoma.
In October, 2001, Panhandle acquired Wood Oil Company (“Wood”) of Tulsa, Oklahoma. Wood was a privately held company engaged in oil and gas exploration and production and fee mineral ownership. Wood and its shareholders were unrelated parties to Panhandle. Wood is currently operating as a wholly-owned subsidiary of Panhandle.
The Company’s office is located at Grand Centre, Suite 300, 5400 North Grand Blvd., Oklahoma City, OK 73112 (405)948-1560, fax (405)948-2038. Its website is located at www.panhandleoilandgas.com.
The Company files periodic SEC reports on Forms 10-Q and 10-K. These Forms, the Company’s annual report to shareholders and current press releases are available free of charge through its website as soon as reasonably practicable after they are filed electronically with the SEC. In addition, posted on the website are copies of the Company’s various corporate governance documents. From time to time, other important disclosures to investors are provided by posting them in the “Press Release” or “Upcoming Events” section of the website, as allowed by SEC rules.
Materials filed with the SEC may be read and copied at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet website at www.sec.gov that contains reports, proxy and information statements, and other information regarding the Company that have been filed electronically with the SEC.
BUSINESS STRATEGY
The majority of Panhandle’s revenues are derived from the production and sale of oil and natural gas. See Item 8 - “Financial Statements”. The Company’s oil and gas holdings, including its mineral
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acreage, leasehold acreage and working and royalty interests in producing wells are mainly in Oklahoma with other significant holdings in Arkansas, Kansas, New Mexico and Texas. See Item 2 - “Description of Properties”. Exploration and development of the Company’s oil and gas properties are conducted in association with operating oil and gas companies, primarily larger independent companies. The Company does not operate any of its oil and gas properties, but has been an active working interest participant for many years in wells drilled on the Company’s mineral properties and on third party drilling prospects. A significant percentage of the Company’s recent drilling participations have been on properties in which the Company has mineral acreage and, in many cases, already owns an interest in a producing well in the unit.
PRINCIPAL PRODUCTS AND MARKETS
The Company’s principal products are natural gas and to a lesser extent crude oil. These products are sold to various purchasers, including pipeline and marketing companies, which service the areas where the Company’s producing wells are located. Since the Company does not operate any of the properties in which it owns an interest, it relies on the operating expertise of numerous companies that operate in the areas where the Company owns interests. This expertise includes the drilling and completion of new wells, producing well operations and, in most cases, the marketing or purchasing of the well’s production. Natural gas sales are principally handled by the well operator and are normally contracted on a monthly basis with third party gas marketers and pipeline companies. Payment for gas sold is received by the Company either from the contracted purchasers or the well operator. Crude oil sales are generally handled by the well operator and payment for oil sold is received by the Company from the well operator or from the crude oil purchaser.
In general, prices of oil and gas are dependent on numerous factors beyond the control of the Company, such as competition, weather, international events and circumstances, supply and demand, actions taken by the Organization of Petroleum Exporting Countries (“OPEC”), and economic, political and regulatory developments. Since demand for natural gas is generally highest during winter months, prices received for the Company’s natural gas are subject to seasonal variations.
Beginning in calendar 2007, the Company entered into hedging arrangements to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. The hedging arrangements apply to only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These hedging arrangements may expose the Company to risk of financial loss and limit the benefit of future increases in natural gas prices. A more thorough discussion of the hedging arrangements is contained in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operation”.
COMPETITIVE BUSINESS CONDITIONS
The oil and gas industry is highly competitive, particularly in the search for new oil and gas reserves. There are many factors affecting Panhandle’s competitive position and the market for its products which are beyond its control. Some of these factors include the quantity and price of foreign oil imports, changes in prices received for its oil and gas production, business and consumer demand for refined oil products and natural gas, and the effects of federal and state regulation of the exploration for, production of and sales of oil and natural gas. Changes in existing economic conditions, weather patterns and actions taken by OPEC and other oil-producing countries have dramatic influence on the price Panhandle receives for its oil and gas production.
The Company does not operate any of the wells in which it has an interest; rather it relies on companies with greater resources, staff, equipment, research, and experience for operation of wells both in the drilling and production phases. The Company uses its strong financial base and its mineral and
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leasehold acreage ownership, coupled with its own geologic and economic evaluations, to participate in drilling operations with these larger companies. This method allows the Company to effectively compete in drilling operations it could not undertake on its own due to financial and personnel limits and allows it to maintain low overhead costs.
SOURCES AND AVAILABILITY OF RAW MATERIALS
The existence of commercial quantities of oil and gas reserves is essential to the ultimate realization of value from the Company’s mineral and leasehold acreage. These mineral properties and leasehold acreage may be considered a raw material to its business. The production and sale of oil and natural gas from the Company’s properties is essential to provide the cash flow necessary to sustain the ongoing viability of the Company. The Company reinvests a portion of its cash flow to purchase oil and gas leasehold acreage and, to a lesser extent, additional mineral acreage, to assure the continued availability of acreage with which to participate in exploration, drilling, and development operations and subsequently the production and sale of oil and gas. This participation in exploration and production activities and purchase of additional acreage is necessary to continue to supply the Company with the raw materials with which to generate additional cash flow. Mineral and leasehold purchases are made from many owners, and the Company does not rely on any particular companies or individuals for these acquisitions.
MAJOR CUSTOMERS
The Company’s oil and gas production is sold, in most cases, by the well operators to many different purchasers on a well-by-well basis. During fiscal 2008, sales through three separate operators accounted for approximately 17%, 16% and 12%, respectively, of the Company’s total oil and gas sales. Generally, if one purchaser declines to continue purchasing the Company’s oil and natural gas, several other purchasers can be located. Pricing is generally consistent from purchaser to purchaser.
PATENTS, TRADEMARKS, LICENSES, FRANCHISES AND ROYALTY AGREEMENTS
The Company does not own any patents, trademarks, licenses or franchises. Royalty agreements on producing oil and gas wells stemming from the Company’s ownership of mineral acreage generate a portion of the Company’s revenues. These royalties are tied to ownership of mineral acreage and this ownership is perpetual, unless sold by the Company. Royalties are due and payable to the Company whenever oil and/or gas is produced from wells located on the Company’s mineral acreage.
REGULATION
All of the Company’s well interests and non-producing properties are located onshore in the United States. Oil and gas production is subject to various taxes, such as gross production taxes and, in some cases, ad valorem taxes.
The State of Oklahoma and other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other regulations relating to the exploration and production of oil and gas. These states also have regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties and the regulation of spacing, plugging and abandonment of wells. As previously discussed, the well operators are relied upon by the Company to comply with governmental regulations.
Various aspects of the Company’s oil and gas operations are regulated by agencies of the federal government. Transportation of natural gas in interstate commerce is generally regulated by the Federal Energy Regulatory Commission (“FERC”) pursuant to the Natural Gas Act of 1938 and the Natural Gas
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Policy Act of 1978 (“NGPA”). The intrastate transportation and gathering of natural gas (and operational and safety matters related thereto) may be subject to regulation by state and local governments.
FERC’s jurisdiction over interstate natural gas sales was substantially modified by the NGPA under which FERC continued to regulate the maximum selling prices of certain categories of gas sold in “first sales” in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas. Because “first sales” include typical wellhead sales by producers, all natural gas produced from the Company’s natural gas properties is sold at market prices, subject to the terms of any private contracts in effect. FERC’s jurisdiction over natural gas transportation was not affected by the Decontrol Act.
Sales of natural gas are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by FERC to foster competition by transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the primary role of gas transporters. As a result of the various omnibus rulemaking proceedings in the late 1980’s and the individual pipeline restructuring proceedings of the early to mid-1990’s, interstate pipelines must provide open and nondiscriminatory transportation and transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end users and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, FERC expanded the impact of open access regulations to intrastate commerce.
More recently, FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are: (1) permitting the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline’s demonstration of lack of market control in the relevant service market.
As a result of these changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are able to conduct business with a larger number of counter parties. These changes generally have improved the access to markets for natural gas while substantially increasing competition in the natural gas marketplace. What new or different regulations FERC and other regulatory agencies may adopt or what effect subsequent regulations may have on production and marketing of natural gas from the Company’s properties cannot be predicted.
Sales of oil are not regulated and are made at market prices. The price received from the sale of oil is affected by the cost of transporting it to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, FERC will examine the relationship between the annual change in the applicable index and the actual cost changes experienced by the oil pipeline industry.
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ENVIRONMENTAL MATTERS
As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays; however, to date the Company’s cost of compliance has been insignificant. The Company does not believe the existence of these environmental laws will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future events. Since the Company does not operate any wells in which it owns an interest, actual compliance with environmental laws is controlled by the well operators, with Panhandle being responsible for its proportionate share of the costs involved. As such, to its knowledge, the Company believes the well operators to be in compliance with existing regulations and that absent an extraordinary event any noncompliance will not have a material adverse effect on the Company. Although the Company is not fully insured against all environmental risks, insurance is maintained which is customary in the industry.
EMPLOYEES
At September 30, 2008, Panhandle employed 18 persons on a full-time basis. Three of the employees are executive officers and the President and CEO is also a director of the Company.
RISK FACTORS
Economic conditions worldwide and in the United States have declined in recent months having a negative effect on demand for and the price of oil and natural gas, drilling activity to explore for new reserves and availability of capital through either debt or equity markets.
Further negative effects of the current economic downturn could be decline of reserves due to curtailed drilling activity, the risk of insolvency of well operators and oil and natural gas purchasers, limited availability of certain insurance contracts and limited access to hedging instruments.
In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating the Company’s business and future prospects. The risk factors described below are not necessarily exhaustive and investors are encouraged to perform their own investigation with respect to the Company and its business. Investors should also read the other information in this Form 10-K, including the financial statements and related notes.
Oil and natural gas prices are volatile. Volatility in oil and natural gas prices can adversely affect results and the price of the Company’s common stock. This volatility also makes valuation of oil and natural gas producing properties difficult and can disrupt markets.
Oil and natural gas prices have historically been, and will likely continue to be, volatile. The prices for oil and natural gas are subject to wide fluctuation in response to a number of factors, including:
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worldwide economic conditions;
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economic, political and regulatory developments;
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market uncertainty;
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relatively minor changes in the supply of and demand for oil and natural gas; weather conditions;
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import prices;
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political conditions in major oil producing regions, especially the Middle East and West Africa;
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•
actions taken by OPEC; and
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competition from alternative sources of energy.
In recent years and months, oil and natural gas price volatility has become increasingly severe. Price volatility makes it difficult to budget and project the return on exploration and development projects and to estimate with precision the value of producing properties that are owned or acquired. In addition, unusually volatile prices often disrupt the market for oil and natural gas properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties. Quarterly results of operations may fluctuate significantly as a result of, among other things, variations in oil and natural gas prices and production performance.
A substantial or extended decline in oil and natural gas prices would have a material adverse effect on the Company.
A substantial or extended decline in oil and natural gas prices would have a material adverse effect on the Company’s financial position, results of operations, access to capital and the quantities of oil and natural gas that may be economically produced. A significant decrease in price levels for an extended period would have a negative effect in several ways, including:
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cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production;
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certain reserves may no longer be economic to produce, leading to both lower proved reserves and cash flow; and
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access to sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable.
The Company’s hedging activities may reduce the realized prices received for oil and natural gas sales.
In order to manage exposure to price volatility in our natural gas, we enter into natural gas price risk management arrangements (costless collars) for a portion of our expected production. Commodity price hedging may limit the prices we actually realize and therefore reduce oil and natural gas revenues in the future. The fair value of our natural gas derivative instruments outstanding as of September 30, 2008 was an asset of $646,193.
Lower oil and natural gas prices may cause impairment charges.
The Company has elected to utilize the successful efforts method of accounting for its oil and gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and development dry holes are capitalized and amortized by property using the unit-of-production method as oil and gas is produced.
All long-lived assets, principally the Company’s oil and gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its future net cash flows. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil and gas reserves. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded. If an impairment charge is recognized, cash flow from operating activities is not impacted but net income and, consequently, shareholders’ equity, are reduced.
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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 or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels, and operating and development costs. In estimating our level of oil and natural gas reserves, we and our consulting petroleum engineering firm make certain assumptions that may prove to be incorrect, including assumptions relating to the level of oil and natural gas prices, future production levels, capital expenditures, operating and development costs, the effects of regulation and availability of funds. If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.
Our standardized measure is calculated using prices and costs in effect as of the date of estimation, less future development, production and income tax expenses, and discounted at ten percent per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.
The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.
The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the ten percent discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 69, “Disclosures about Oil and Gas Producing Activities”, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Failure to find or acquire additional reserves will cause reserves and production to decline materially from their current levels.
The rate of production from oil and natural gas properties generally declines as reserves are depleted. The Company’s proved reserves will decline materially as reserves are produced except to the extent that the Company acquires additional properties containing proved reserves, conducts successful exploration and development drilling, successfully applies new technologies or identifies additional behind-pipe zones or secondary recovery reserves. Future oil and natural gas production is therefore highly dependent upon the level of success in acquiring or finding additional reserves. The above activities are conducted with well operators, as the Company does not operate any of its wells.
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Drilling for oil and natural gas invariably involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs. In addition, wells that are profitable may not achieve a targeted rate of return. The Company relies on the operators’ seismic data and other advanced technologies in identifying prospects and in conducting exploration activities. The seismic data and other technologies used do not allow operators to know conclusively prior to drilling a well whether oil or natural gas is present or may be produced economically.
The ultimate cost of drilling, completing and operating a well is controlled by well operators and cost factors can adversely affect the economics of any project. Further drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, environmental and other governmental requirements, the cost and availability of drilling rigs, equipment and services and potentially the expected sales price to be received for oil or gas produced from the wells.
Oil and natural gas drilling and producing operations involve various risks.
The Company is subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including well blowouts, cratering and explosions, pipe failures, fires, abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks.
The Company maintains insurance against many potential losses or liabilities arising from well operations in accordance with customary industry practices and in amounts believed by management to be prudent. However, this insurance does not protect it against all operational risks. For example, the Company does not maintain business interruption insurance. Additionally, pollution and environmental risks generally are not fully insurable. These risks could give rise to significant uninsured costs that could have a material adverse effect upon the Company’s financial results.
We cannot control activities on properties we do not operate.
The Company does not operate any of the properties in which it has an interest and has very limited ability to exercise influence over operations for these properties or their associated costs. Dependence on the operator and other working interest owners for these projects and the limited ability to influence operations and associated costs could materially and adversely affect the realization of targeted returns on capital in drilling or acquisition activities and targeted production growth rates. The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond the Company’s control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of technology.
Shortages of oil field equipment, services, qualified personnel and resulting cost increases could adversely affect results of operations.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. These shortages or price increases could adversely affect the Company’s profit
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margin, cash flow and operating results, or restrict its ability to drill wells and conduct ordinary operations.
Competition in the oil and natural gas industry is intense, and most of our competitors have greater financial and other resources than we do.
We compete in the highly competitive areas of oil and natural gas acquisition, development, exploration and production. We face intense competition from both major and other independent oil and natural gas companies in each of the following areas:
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seeking to acquire desirable producing properties or new properties for future exploration; and
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seeking to acquire the equipment and expertise necessary to develop and operate properties.
Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies are able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully join in drilling with operators, evaluate and select suitable properties and consummate transactions in this highly competitive environment.
ITEM 1B
ITEM 1B UNRESOLVED STAFF COMMENTS
None
ITEM 2
ITEM 2 PROPERTIES
At September 30, 2008, Panhandle’s principal properties consisted of perpetual ownership of 254,661 net mineral acres, held principally in tracts in Oklahoma, New Mexico, Texas and nine other states. The Company also held leases on 21,458 net acres of minerals primarily in Oklahoma. At September 30, 2008, Panhandle held royalty and/or working interests in 4,593 producing oil or gas wells, and 74 wells in the process of being drilled or completed.
The Company does not have current abstracts or title opinions on all of its mineral properties and, therefore, cannot be certain that it has unencumbered title to all of these properties. In recent years, few challenges have been made against the Company’s fee title to its properties.
The Company pays ad valorem taxes on minerals owned in certain states.
ACREAGE
Mineral Interests Owned
The following table of mineral interests owned reflects, at September 30, 2008, in each respective state, the number of net and gross acres, net and gross producing acres, net and gross acres leased, and net and gross acres open (unleased).
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“Producing” represents the mineral acres in which Panhandle owns a royalty or working interest in a producing well.
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“Leased” represents the mineral acres owned by Panhandle that are leased to third parties but not producing.
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“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.
PROVED RESERVES
The following table summarizes estimates of proved reserves of oil and gas held by Panhandle. All reserves are located within the United States and are principally made up of small interests in approximately 4,600 individual wells. Because the Company’s non-producing mineral and leasehold interests consist of various small interests in numerous tracts located primarily in Oklahoma, New Mexico and Texas and because the Company is a non-operator and must rely on third parties to propose and drill and operate producing wells, it is not feasible or possible to provide estimates of all proved undeveloped reserves and associated future net revenues. The Company is currently providing proved undeveloped reserve estimates for wells that it has a substantial reason to believe will be drilled in the very near term. In most cases, this means the Company has received some type of notice from the operator that a well will be drilled. All of the Company’s reserve quantity estimates for 2008, 2007 and 2006 were prepared by the Company’s consulting petroleum engineering firm. Other than this report, the Company’s reserve estimates are not filed with any other federal agency.
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These reserves exclude approximately 1.6 to 2.8 Bcf of CO2 gas reserves for the years presented.
Because the determination of reserves is a function of testing, evaluating, developing oil and gas reservoirs and establishing a production decline history, along with product price fluctuations, estimates will change as future information concerning individual reservoirs is developed and as market conditions change. Estimated reserve quantities and future net revenues are affected by changes in product prices, and these prices have varied substantially in recent years and are expected to vary substantially from current pricing in the future. Proved developed reserves are those expected to be recovered through existing well bores under existing economic and operating conditions. Proved undeveloped reserves are reserves that may be recovered from undrilled acreage or units, but are limited to those sites directly offsetting established production units, have sufficient geological data to indicate a reasonable expectation of commercial success and the Company has reason to believe will be drilled in the very near term.
ESTIMATED FUTURE NET CASH FLOWS
Set forth below are estimated future net cash flows with respect to Panhandle’s proved reserves (based on the estimated units set forth in the immediately preceding table) for the fiscal year indicated, and the present value of such estimated future net cash flows, computed by applying a 10% discount factor as required by the rules and regulations of the SEC. Estimated future net cash flows have been computed by applying current prices at September 30 of each year to future production of proved reserves less estimated future expenditures to be incurred with respect to the development and production of such reserves. This pricing is based on SEC regulations. No federal or state income taxes are included in estimated costs. However, the amounts are net of operating costs and production taxes levied by the respective states. Prices used for determining future cash flows from oil and natural gas as of September 30, 2008, 2007, 2006 were as follows: 2008 - $97.74/Bbl, $4.51/Mcf; 2007 - $78.93/Bbl, $5.50/Mcf; 2006 - $60.50/Bbl, $3.49/Mcf. These future net cash flows should not be construed as the fair market value of the Company’s reserves. A market value determination would need to include many additional factors, including anticipated oil and gas price and production cost increases or decreases.
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Estimated Future Net Cash Flows
10% Discounted Present Value of Estimated Future Net Cash Flows
The future net cash flows are net of immaterial amounts of future cash flow to be received from CO2 reserves.
OIL AND GAS PRODUCTION
The following table sets forth the Company’s net production of oil and gas for the fiscal periods indicated.
Gas production includes 193,408, 175,175 and 192,957 Mcf of CO2 sold at average prices of $.86, $.61 and $.65 per Mcf for the years ended September 30, 2008, 2007 and 2006, respectively.
AVERAGE SALES PRICES AND PRODUCTION COSTS
The following table sets forth unit price and cost data for the fiscal periods indicated.
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(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 25% of the Company’s oil and gas revenue is generated from royalty interests in approximately 4,200 wells. Royalty interests bear no share of the operating costs on those producing wells.
GROSS AND NET PRODUCTIVE WELLS AND DEVELOPED ACRES
The following table sets forth Panhandle’s gross and net productive oil and gas wells as of September 30, 2008. Panhandle owns fractional royalty interests or fractional working interests in these wells. The Company does not operate any wells.
Information on multiple completions is not available from Panhandle’s records, but the number of such is not believed to be significant.
As of September 30, 2008, Panhandle owned 365,250 gross developed mineral acres and 45,967 net developed mineral acres. Panhandle has also leased from others 154,982 gross developed acres, which contain 17,326 net developed acres.
UNDEVELOPED ACREAGE
As of September 30, 2008, Panhandle owned 1,310,311 gross and 208,694 net undeveloped mineral acres, and leases on 31,316 gross and 4,132 net acres.
DRILLING ACTIVITY
The following net productive development and exploratory wells and net dry development and exploratory wells in which the Company had a fractional royalty or working interest were drilled and completed during the fiscal years indicated. Also shown are the net wells purchased during these periods.
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PRESENT ACTIVITIES
The following table sets forth the gross and net oil and gas wells drilling or testing as of September 30, 2008, in which Panhandle owns a royalty or working interest. These wells were not yet producing at September 30, 2008.
OTHER FACILITIES
The Company leases 12,369 square feet of office space in Oklahoma City, OK. The lease obligation ends in fiscal 2012.
SAFE HARBOR STATEMENT
This report, including information included in, or incorporated by reference from, future filings by the Company with the SEC, as well as information contained in written material, press releases and oral statements, contain, or may contain, certain statements that are “forward-looking statements” within
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the meaning of the federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address activities, events or developments which are expected to, or anticipated will, or may, occur in the future are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts” and similar expressions are used to identify forward-looking statements.
These forward-looking statements include, among others, such things as: the amount and nature of our future capital expenditures; wells to be drilled or reworked; prices for oil and natural gas; demand for oil and natural gas; estimates of proved oil and natural gas reserves; development and infill drilling potential; drilling prospects; business strategy; production of oil and natural gas reserves; and expansion and growth of our business and operations.
These statements are based on certain assumptions and analyses made by the Company in light of experience and perception of historical trends, current conditions and expected future developments as well as other factors believed appropriate in the circumstances. However, whether actual results and development will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations.
One should not place undue reliance on any of these forward-looking statements. The Company does not currently intend to update forward-looking information and to release publicly the results of any future revisions made to forward-looking statements to reflect events or circumstances after the date of this report which reflect the occurrence of unanticipated events.
In order to provide a more thorough understanding of the possible effects of some of these influences on any forward-looking statements made, the following discussion outlines certain factors that in the future could cause consolidated results for 2009 and beyond to differ materially from those that may be presented in any such forward-looking statement made by or on behalf of the Company.
Commodity Prices. The prices received for oil and natural gas production have a direct impact on the Company’s revenues, profitability and cash flows as well as the ability to meet its projected financial and operational goals. The prices for natural gas and crude oil are heavily dependent on a number of factors beyond the Company’s control, including: the demand for oil and natural gas; weather conditions in the continental United States (which can greatly influence the demand for natural gas at any given time as well as the price we receive for such natural gas); and the ability of current distribution systems in the United States to effectively meet the demand for oil and natural gas at any given time, particularly in times of peak demand which may result because of adverse weather conditions.
Oil prices are extremely sensitive to foreign influences based on political, social or economic factors, any one of which could have an immediate and significant effect on the price and supply of oil. In addition, prices of both natural gas and oil are becoming more and more influenced by trading on the commodities markets which, at times, has increased the volatility associated with these prices.
Uncertainty of Oil and Natural Gas Reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and their values, including many factors beyond the Company’s control. The oil and natural gas reserve data included in this report represents only an estimate of these reserves. Oil and natural gas reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves depend on a number of variable factors, including historical production from the area compared with production from other producing areas, and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs, and workover and remedial costs.
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Some or all of these assumptions may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas, and estimates of the future net cash flows from oil and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, oil and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual production, revenues and expenditures with respect to oil and natural gas reserves will vary from estimates, and those variances can be material.
The information regarding discounted future net cash flows included in this report is not necessarily the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties. As required by the SEC, the estimated discounted future net cash flows from proved oil and natural gas reserves are determined based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Actual future net cash flows are also affected, in part, by the amount and timing of oil and natural gas production, supply and demand for oil and natural gas and increases or decreases in consumption.
In addition, the 10% discount factor used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and the risks associated with operations of the oil and natural gas industry in general.
ITEM 3
ITEM 3 LEGAL PROCEEDINGS
There were no material legal proceedings involving Panhandle or Wood Oil as of the date of this report.
ITEM 4
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of Panhandle’s security holders during the fourth quarter of the fiscal year ended September 30, 2008.
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PART II
ITEM 5
ITEM 5 MARKET FOR REGISTRANTS’ COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The above graph compares the cumulative 5-year total return provided shareholders on Panhandle Oil and Gas Inc.’s common stock relative to the cumulative total returns of the S&P Smallcap 600 index and the S&P Oil & Gas Exploration & Production index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common stock and in each of the indexes on September 30, 2003 and its relative performance is tracked through September 30, 2008.
On July 22, 2008, the Company’s Class A Common Stock (“Common Stock”) was listed on the New York Stock Exchange (symbol PHX) and, prior to that, it was listed on the American Stock Exchange under the same symbol. The following table sets forth the high and low trade prices of the Common Stock during the periods indicated:
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As of December 1, 2008, there were 1,798 holders of record of Panhandle’s Class A Common Stock and approximately 3,000 beneficial owners.
During the past two years, cash dividends have been declared and paid as follows on the Class A Common Stock:
While the Company expects to continue to pay dividends on its common stock, the payment of future cash dividends will depend upon, among other things, financial condition, funds from operations, the level of capital and development expenditures, future business prospects, contractual restrictions and any other factors considered relevant by the board of directors.
The Company’s current line of credit loan agreement also contains a provision limiting the paying or declaring of a cash dividend to twenty percent of net cash flow provided by operating activities from the Consolidated Statement of Cash Flows of the preceding twelve-month period. See Note 4. to the consolidated financial statements contained herein at Item 8 - “Financial Statements”, for a further discussion of the loan agreement.
ISSUER PURCHASES OF EQUITY SECURITIES
On May 28, 2008 and July 29, 2008 the Company announced that its Board of Directors had approved stock repurchase programs to purchase up to $2,000,000 and $3,000,000 (respectively) of the Company’s common stock. The shares are held in treasury and are accounted for using the cost method. As of September 30, 2008, 7,640 treasury shares were contributed to the Company’s ESOP on behalf of the ESOP participants.
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ITEM 6
ITEM 6 SELECTED FINANCIAL DATA
The following table summarizes consolidated financial data of the Company and should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements of the Company, including the Notes thereto, included elsewhere in this report.
All share and per share amounts are adjusted for the effects of 2-for-1 stock splits, effective in January 2006 and in April 2004.
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The Company uses the successful efforts method of accounting for its oil and gas activities.
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ITEM 7
ITEM 7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
General
The Company’s principal line of business is the production and sale of oil and natural gas. Results of operations are dependent upon the quantity of production and the price obtained for such production. Prices received by the Company for the sale of its oil and natural gas have fluctuated significantly from period to period. These fluctuations affect the Company’s ability to maintain or increase its production from existing oil and gas properties and to explore, develop or acquire new properties. As the Company is a non-operator it relies on operating companies to drill, complete and place on production new wells. The Company anticipates increased production for fiscal year 2009 as 63 working interest wells were drilling or testing as of September 30, 2008 with production from these wells expected to begin in fiscal 2009. The Company owned an average 8% working interest in these wells with working interests ranging from less than 1% to 42.8%. Although capital expenditures increased significantly in fiscal years 2008 and 2007, the announcement of capital expenditure cutbacks by many operating companies may reduce the Company’s capital expenditures in fiscal year 2009. Therefore, the Company currently anticipates a modest decrease in capital expenditures for fiscal year 2009 as compared to fiscal year 2008. This potentially could reduce production in future years as the number of new wells coming on line would not continue to increase.
The following table reflects certain operating data for the periods presented:
Fiscal Year 2008 Compared to Fiscal Year 2007
Overview
The Company recorded net income of $21,555,769 in 2008, compared to net income of $6,343,464 in 2007. Total revenues were significantly higher in 2008 as a result of increases in both oil and natural gas production and prices in 2008 as compared to 2007. The increase in revenue was partially offset by increases in 2008 as compared to 2007 in the following expense categories: lease operating expense; production taxes; depreciation, depletion and amortization; general and administrative
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expense; and provision for income taxes. Provision for impairment experienced a significant decrease in 2008 as compared to 2007.
Revenues
Total revenues increased $29,990,210 or 77% for 2008 as compared to 2007. The increase was the result of a $31,577,611 increase in oil and natural gas sales, partially offset by losses related to natural gas collar contracts of $1,706,139, which is the result of high natural gas prices from March, 2008 through July, 2008 which exceeded the ceilings of the natural gas collar contracts. Oil and natural gas sales increases were due to an overall 33% increase in mcfe production, a 65% increase in oil prices and a 34% increase in natural gas prices. Fiscal 2008 capital expenditures, net wells drilled and completed and, accordingly, oil and natural gas production increased, as compared to fiscal 2007. The major areas in which new wells significant to the Company have been drilled and completed are the Woodford Shale in southeast Oklahoma, the Fayetteville Shale in Arkansas and the Dill City and Yellowstone Southeast prospects in western Oklahoma. The Company plans to continue to maximize its working interest participation on most wells to be drilled during fiscal 2009; although, the Company’s total number of wells to be drilled in fiscal 2009 in which it has a working interest is expected to decline. The result expected is a flat to modest increase in oil and natural gas production for fiscal 2009 as compared to fiscal 2008.
Production by quarter for 2008 was as follows:
(Losses) Gains on Natural Gas Collar Contracts
Realized and unrealized gains and losses are scheduled below:
The Company made payments of $1,480,100 under the contracts in 2008 as compared to receiving cash payments of $658,400 in 2007. The Company’s fair value of derivative contracts was an asset of $646,193 as of September 30, 2008 as compared to an asset of $106,916 as of September 30, 2007.
Lease Operating Expenses and Production Taxes (LOE)
LOE increased $2,961,627 or 81% in 2008. LOE costs per mcfe of production increased from $.63 in 2007 to $.86 in 2008. This $.23 per mcfe increase is the result of significant increases in costs related to the transporting, compressing and marketing of natural gas. These increases account for approximately $1.9 million of the overall LOE increase and have been experienced primarily in the Woodford Shale area in southeast Oklahoma and the Dill City prospect in western Oklahoma. The remaining LOE increase of approximately $1.1 million is the result of the increased number of net wells
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owned that began producing in 2008 (new wells generally experience higher operating costs during the first year of production) combined with continued increases in costs of field personnel, fuel and materials on wells existing prior to 2008.
Production taxes increased $1,036,679 or 43% in 2008. The increase is primarily the result of significantly higher oil and natural gas sales in 2008, as production taxes are paid as a percentage of sales. The increase is not proportional to the sales increase due to new wells coming on line in Arkansas which has a low production tax rate and production tax credits that the Company is entitled to on production from horizontally drilled wells in Oklahoma (primarily from the Woodford Shale area in southeast Oklahoma). These production tax credits totaled approximately $467,000 in 2008.
Exploration Costs
Exploration costs decreased $594,126 in 2008 as compared to 2007. This decrease is the result of a $467,868 exploratory dry hole drilled in 2007 in Louisiana. No exploratory dry holes were drilled in 2008. Since the Company utilizes the successful efforts method of accounting for oil and natural gas operations, only exploratory dry holes result in their costs being charged to exploration costs. Charges to exploration costs for expired or abandoned leasehold costs also decreased approximately $101,000 in 2008 as compared to 2007.
Depreciation, Depletion and Amortization (DD&A)
DD&A increased $4,493,035 or 29% in 2008 to $2.56 per mcfe as compared to $2.64 per mcfe in 2007. The overall increase is the result of increased production volumes in 2008 as compared to 2007. The decrease in the DD&A rate per mcfe is the result of higher than normal DD&A per mcfe in 2007 resulting from downward reserve revisions on approximately fifty of the Company’s working interest wells. Additional DD&A charges on those wells totaled approximately $2 million.
Provision for Impairment
The provision for impairment decreased $3,235,452 in 2008 as compared to 2007. Seven fields were impaired $514,180 in 2008 as compared to eight fields which were impaired $3,397,087 in 2007. In 2008 approximately $309,000 of impairment was on one field in western Oklahoma. In 2007 approximately $2 million of the impairment was on one field in western Oklahoma (unexpected declining production resulted in lower reserve estimates), approximately $476,000 was on one field in west Texas and approximately $390,000 was on one field in New Mexico.
Loss on Sale of Assets
Loss on sale of assets decreased $50,206 in 2008 as compared to 2007. Two low performing wells in western Oklahoma were sold in 2008 at a loss of $203,107. In 2007 several low performing wells in southeast Oklahoma were sold at a loss of $221,998.
General and Administrative Costs (G&A)
G&A costs increased $1,129,020 or 29% in 2008. The increase is principally the result of increased personnel costs of $749,110, increased professional fees of $149,303 and increased directors’ expenses of $89,985.
Bad Debt Expense
Bad debt expense increased $591,258 in 2008 as compared to 2007. On July 22, 2008
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SemGroup, L.P. and certain subsidiaries (SemGroup) filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy code. All of the 2008 bad debt expense of $591,258 represents the total amount owed the Company directly and indirectly, through the operators of the affected wells where SemGroup was the purchaser of oil. No bad debt expense was recorded in 2007.
Provision for Income Taxes
Provision for income taxes increased $8,535,302 in 2008 as compared to 2007 as a result of income before provision for income taxes increasing by $23,747,607. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate. The effective tax rate was 33.6% for 2008 and 27.1% for 2007.
Liquidity and Capital Resources
At September 30, 2008, the Company had positive working capital of $4,599,004 as compared to $7,191,111 at September 30, 2007. Items with positive effects on working capital include an increase in oil and gas sales receivables, net of allowance for uncollectible accounts of $9,079,878, an increase in the fair value of derivative contracts of $539,277 and an increase in refundable income taxes and other of $2,267,114. Items that had a negative effect include an increase in accounts payable of $14,124,310 and an increase in accrued liabilities of $260,414. Oil and gas sales receivable increased as a result of increased revenue. The fair value of derivative contracts increased as a result of an increase in the variance between natural gas prices and contract floors. The increase in refundable income taxes and other is the result of federal income tax estimated payments made in fiscal 2008 in excess of the actual current income tax liability for 2008. The accounts payable increase is the result of continued increases in the Company’s working interest participation in new wells drilled and an increase in the number of wells drilled. As of September 30, 2008, the Company had working interests in 63 wells that were drilling or testing. The Company’s average working interest in these wells was approximately 8% and the accounts payable for these wells as of September 30, 2008 was approximately $11.2 million. Capital expenditures increased significantly in 2008, but are currently anticipated to slightly decrease for fiscal 2009. The Company will continue its strategy of increased working interest participation in new wells drilled but capital expenditure reductions by operating companies may substantially reduce our expenditure level resulting in fewer new net wells drilled.
Cash flows from operating activities increased 42% over last year primarily due to higher oil and gas sales, net of lease operating expenses and production taxes. Additions to properties and equipment for oil and gas activities for 2008 were $52,812,138 compared to $28,112,522 for 2007. Management currently expects additions to properties and equipment for oil and gas activities in fiscal year 2009 to decrease as compared to fiscal 2008. These expenditures will continue to be concentrated in the southeast Oklahoma Woodford Shale area, the Fayetteville Shale area in Arkansas and the Dill City prospect and other areas in western Oklahoma. Any acquisition of oil and gas properties would further increase additions to properties and equipment. As the Company does not operate any of the wells in which it participates, it is difficult to predict which or how many wells will actually be drilled in fiscal 2009 and a significant reduction in drilling by operating companies may substantially reduce the Company’s planned expenditure level.
The Company has historically funded capital expenditures, overhead costs and dividend payments from operating cash flow and has utilized, at times, its bank revolving line-of-credit facility to help fund these expenditures. The $50,000,000 facility currently has a $15,000,000 borrowing base which, if needed, the Company believes could be expanded up to the $50,000,000 maximum. The borrowing base is set by the Company to minimize the fee on the unused portion of the borrowing base. The Company has outstanding borrowings of $9,704,100 and availability of $5,295,900 as of September 30, 2008. Based on expected natural gas production volumes and prices for fiscal 2009, the expected capital
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expenditure level discussed above, and no meaningful acquisitions of oil and gas properties, additional borrowings of $5-15 million in fiscal 2009 are possible. Changes in production volumes or pricing or an acceleration or slowing down of the development in the gas resource projects would materially affect anticipated borrowings.
Contractual Obligations
The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan in the amount of $50,000,000 which is subject to a semi-annual borrowing base determination. The current borrowing base under the BOK Agreement is $15,000,000. The revolving loan matures on October 31, 2010. Borrowings under the revolving loan are due at maturity. The revolving loan bears interest at the BOK national prime rate minus from 1.375% to .75%, or 30 day LIBOR plus from 1.375% to 2.0%. The interest rate charged will be based on the percent of the value advanced of the calculated loan value of the Company’s oil and gas reserves. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and gas properties is advanced.
Determinations of the borrowing base are made semi-annually or whenever BOK believes there has been a material change in the value of the Company’s oil and gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2008, the Company was in compliance with these covenants.
The table below summarizes the Company’s contractual obligations under the BOK facility, as of September 30, 2008:
Fiscal Year 2007 Compared to Fiscal Year 2006
Overview
The Company recorded net income of $6,343,464 in 2007, compared to net income of $10,574,219 in 2006. Total revenues were slightly higher in 2007 as a result of increased oil and gas sales generated by increased sales volumes of oil and natural gas in 2007 as compared to 2006. However, the revenue increases were more than offset by substantial increases in exploration costs, depreciation, depletion and amortization and provision for impairment expense in 2007 as compared to 2006.
Revenues
Total revenues increased $1,643,231 or 4% for 2007 as compared to 2006. The increase was the result of a $1,440,647 increase in oil and natural gas sales, a $765,316 increase in combined realized and unrealized gains on natural gas collar contracts and a $202,359 decrease in lease bonuses and rentals. Oil and natural gas sales increases were due to an overall 19% increase in mcfe production, a 1% decrease in oil prices and a 14% decrease in natural gas prices. The production increases are the result of the Company’s continued strategy of participating with higher interests in new wells, especially in the Dill City and Woodford Shale areas where significant production is now being received from several recently completed wells. Realized and unrealized gains from natural gas collar contracts in 2007 were a part of
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the revenue increase. No hedging of natural gas prices had been implemented by the Company in previous years. The decrease in lease bonuses and rentals is attributed to the Company’s strategy of increasing its average working interest in wells by participating with larger portions of its mineral acreage as well proposals are received, thus leasing to third parties less.
Production by quarter for 2007 was as follows:
Realized and Unrealized Gains on Natural Gas Collar Contracts
As of September 30, 2007, the Company’s fair value of derivative contracts (unrealized gain) was $106,916. The Company had no derivative contracts during 2006. The Company received cash payments (realized gains) in 2007 of $658,400 under the contracts.
Lease Operating Expenses and Production Taxes (LOE)
LOE increased $614,072 or 20% in 2007. The increase is a result of the increased number of larger ownership wells going on line in 2007, (new wells normally have higher operating costs the first several months of production) and the continuing increase in the overall number of wells in which the Company has an interest. LOE costs per mcfe of production were $.63 in both 2007 and 2006.
Production taxes increased $180,550 or 8% in 2007. The increase is the result of the higher oil and gas revenues in 2007, as production taxes are paid as a percentage of these revenues.
Exploration Costs
Exploration costs increased $827,177 in 2007 as compared to 2006. This increase is principally the result of a $467,868 exploratory dry hole drilled in 2007 as compared to a $143,264 exploratory dry hole drilled in 2006. Since the Company utilizes the successful efforts method of accounting for oil and gas operations, only exploratory dry holes result in their costs being charged to exploration costs. Also, the Company charges to exploration costs leasehold deemed worthless or leasehold for which the lease term has expired. Leasehold charged to exploration costs was higher in 2007 as compared to 2006 by $479,420.
Depreciation, Depletion and Amortization (DD&A)
DD&A increased $5,149,258 or 51% in 2007 to $2.64 per mcfe as compared to $2.08 per mcfe in 2006. Reductions in the estimate of remaining reserves on several properties, large increases in drilling expenditures during 2006 and 2007 due to the Company’s participation with higher ownership interests in new wells and high initial production on these newly drilled wells resulted in this increase. On 34 of the Company’s over 1,250 working interest wells, reserve evaluations were reduced by the Company’s consulting engineer resulting in approximately $2 million of additional DD&A charges in 2007 as compared to 2006. DD&A on 16 significant new wells that began producing in 2007 accounted for another $1.3 million of the DD&A increase. The continued increase in drilling expenditures which has added significantly to the depreciable base of the Company’s properties combined with the higher initial production received from these same properties (thus accelerating the depreciation taken) accounts for the remainder of the increase.
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Provision for Impairment
The provision for impairment increased $751,879 in 2007 as compared to 2006. One large western Oklahoma field which was impaired by approximately $1.9 million in 2006 was again impaired in 2007 by approximately $2.0 million as production, and thus ultimate reserves, from the wells in this field continued to decline at a faster rate than anticipated. The impairment of a Chaves County, New Mexico field for approximately $402,000, a Winkler County, Texas field for approximately $478,000 and a Beckham County, Oklahoma field for approximately $214,000 comprised most of the remaining 2007 impairment provision.
Loss on Sale of Assets
Loss on sale of assets increased $135,113 in 2007 as compared to 2006. Several low performing properties in southeast Oklahoma were sold in 2007 at a loss of $221,998. In 2006, one property was sold at a loss of $94,275. Other insignificant sales accounted for the remainder of the charges in both 2007 and 2006.
General and Administrative Costs (G&A)
G&A costs increased $541,593 or 16% in 2007. Increases of approximately $290,000 of directors’ expense, $147,000 of salary and benefit related costs, $76,000 of consulting costs and $20,000 of legal costs account for the majority of the overall increase in G&A costs. Of the directors’ expense increase, approximately $288,000 relates to an amendment to the Directors’ Deferred Compensation Plan (the Plan) that was effective October 19, 2005. The Plan was amended so that on retirement, termination or death of the director or on a change in control of the Company, the shares accrued under the Plan will be issued to the director. No shares are issued to a director until the occurrence of one of these events. This amendment removed the “conversion to cash” option previously available under the Plan, thus eliminating the requirement (after October 19, 2005) that the deferred compensation accounts be adjusted for changes in the market value of the Company’s common stock. The adjustment of the deferred compensation liability to market value of the shares at the closing price on October 19, 2005 resulted in a credit to G&A of approximately $288,000. After the October 19, 2005 adjustment, the deferred compensation liability was reclassified to stockholders’ equity.
Provision for Income Taxes
Provision for income taxes decreased $2,227,000 in 2007 as compared to 2006 as a result of income before provision for income tax decreasing by $6,457,755. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate. The effective tax rate was 27.1% for 2007 and 30.3% for 2006.
CRITICAL ACCOUNTING POLICIES
Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change the Company’s reported cash flows or liquidity. Generally, accounting rules do not involve a selection among alternatives, but involve a selection of the appropriate policies for applying the basic principles. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to the Company.
The more significant reporting areas impacted by management’s judgments and estimates are
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crude oil and natural gas reserve estimation, impairment of assets, oil and gas sales revenue accruals and tax accruals. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. The oil and gas sales revenue accrual is particularly subject to estimates due to the Company’s status as a non-operator of its oil and gas properties. Production information obtained from well operators by the Company is delayed. This causes the estimation of recent production, used in the oil and gas revenue accrual, to be subject to some variations.
Oil and Gas Reserves
Of these judgments and estimates, management considers the estimation of crude oil and nature gas reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. Changes in crude oil and natural gas reserve estimates affect the Company’s calculation of depreciation, depletion and amortization, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a limited scope semi-annual update, the Company’s consulting engineer (the Company employed a new consulting engineer beginning with the March 31, 2007 semi-annual update), with assistance from Company geologists, prepares estimates of crude oil and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. As required by the guidelines and definitions established by the SEC, these estimates are based on current crude oil and natural gas pricing. Crude oil and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future crude oil and natural gas pricing assumptions are used by management to prepare estimates of crude oil and natural gas reserves used in formulating management’s overall operating decisions in the exploration and production segment.
Hedging
The Company periodically utilizes commodity price instruments, costless collars, to reduce its exposure to unfavorable changes in natural gas prices. Volumes under such contracts are a portion of expected production. The Company’s collars contain a fixed floor price and a fixed ceiling price. If market prices exceed the ceiling price or fall below the floor, then the Company will receive the difference between the floor and market price or pay the difference between the ceiling and market price. If market prices are between the ceiling and the floor, then no payments or receipts related to the collars are required.
The Company accounts for its derivative contracts under Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (SFAS No. 133). Under the provision of SFAS No. 133, the Company is required to recognize all derivative instruments as either assets or liabilities in the consolidated balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is required to be measured at least quarterly based on relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. For derivative instruments not designated as hedging instruments, the change in fair value is recognized in earnings during the period of change as a change in derivative fair value. Amounts recorded in unrealized gains (losses) on derivative activities do not represent cash gains or losses. Rather, these amounts are temporary valuation swings in contracts that are not entitled to receive
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hedge accounting treatment.
Successful Efforts Method of Accounting
The Company has elected to utilize the successful efforts method of accounting for its oil and gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by property using the unit-of-production method as oil and gas is produced. This accounting method may yield significantly different operating results than the full cost method.
Impairment of Assets
All long-lived assets, principally oil and gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil and gas, future production costs, estimates of future oil and gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil and gas reserves. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.
Oil and Gas Sales Revenue Accrual
The Company does not operate any of its oil and gas properties, and it primarily holds small interests in approximately 4,600 wells. Thus, obtaining timely production data from the well operators is extremely difficult. This requires the Company to utilize past production receipts and estimated sales price information to estimate its oil and gas sales revenue accrual at the end of each quarterly period. The oil and gas accrual can be impacted by many variables, including initial high production rates of new wells and subsequent rapid decline rates of those wells and rapidly changing market prices for natural gas. This could lead to an over or under accrual of oil and gas sales at the end of any particular quarter. Based on past history, the estimated accrual has been materially accurate.
Income Taxes
The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax laws, regulations and interpretations.
On October 1, 2007, the Company adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company and its subsidiary file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2004.
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The Company has performed its evaluation of tax positions and has determined that the adoption of FIN 48 did not have a material impact on the Company’s financial condition, results of operations, or cash flows. This evaluation included a review of the appropriate recognition threshold for each tax position recognized in the Company’s financial statements. Based on this evaluation, the Company did not identify any tax positions that did not meet the “highly certain positions” threshold. As a result, no additional tax expense, interest, or penalties have been accrued as a result of the review.
The Company includes interest assessed by the taxing authorities in “Interest expense” and penalties related to income taxes in “General and administrative expense” on its Consolidated Statements of Income. For the years ended September 30, 2008 and 2007, the Company recorded no interest or penalties on uncertain tax positions.
The above description of the Company’s critical accounting policies is not intended to be an all-inclusive discussion of the uncertainties considered and estimates made by management in applying accounting principles and policies. Results may vary significantly if different policies were used or required and if new or different information becomes known to management.
ITEM 7A
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company’s results of operations and operating cash flows can be significantly impacted by changes in market prices for oil and gas. Based on the Company’s 2008 production, a $.10 per Mcf change in the price received for natural gas production would result in a corresponding $693,000 annual change in pre-tax operating cash flow. A $1.00 per barrel change in the price received for oil production would result in a corresponding $132,000 annual change in pre-tax operating cash flow. Cash flows could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities. The revolving loan bears interest at the national prime rate minus from 1.375% to .75%, or 30 day LIBOR plus from 1.375% to 2.0%. At September 30, 2008, the Company had $9,704,100 outstanding under these facilities. A change of .5% in the prime rate or on LIBOR would result in a change to interest expense of $48,521.
The Company periodically utilizes certain commodity price instruments, costless collars, to reduce its exposure to unfavorable changes in natural gas prices. Volumes under such contracts are a portion of expected production. The Company’s collars contain a fixed floor price and a fixed ceiling price. If market prices exceed the ceiling price or fall below the floor, then the Company will receive the difference between the floor and market price or pay the difference between the ceiling and market price. If market prices are between the ceiling and the floor, then no payments or receipts related to the collars are required.
Beginning in fiscal year 2007, the Company has entered in costless collar arrangements intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These economic hedging arrangements may expose the Company to risk of financial loss and limit the benefit of future increases in prices. The derivative instruments will settle based on the prices below which are basis adjusted and tied to certain pipelines in Oklahoma.
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Derivative contracts in place during fiscal 2007 and 2008
(prices below reflect the Company’s net price from Oklahoma pipelines)
While the Company believes that its derivative contracts are effective in achieving the risk management objective for which they were intended, the Company has elected not to complete all of the documentation requirements necessary under SFAS No. 133 to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was $646,193 and $106,916 as of September 30, 2008 and 2007, respectively. Realized and unrealized gains and losses are scheduled below:
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ITEM 8
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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Management’s Annual Report on Internal Control Over Financial Reporting
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934 (the “Exchange Act”) as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:
•
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2008. In making this assessment, the Company’s management used the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, management has concluded that, as of September 30, 2008, the Company’s internal control over financial reporting was effective based on those criteria.
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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, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Panhandle Oil and Gas Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Panhandle Oil and Gas Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Panhandle Oil and Gas Inc. as of September 30, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2008 and our report dated December 5, 2008 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Oklahoma City, Oklahoma
December 5, 2008
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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 consolidated balance sheets of Panhandle Oil and Gas Inc. (the Company) as of September 30, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Panhandle Oil and Gas Inc. at September 30, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2008, in conformity with U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 5, 2008, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Oklahoma City, Oklahoma
December 5, 2008
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Panhandle Oil and Gas Inc.
Consolidated Balance Sheets
(Continued on next page)
See accompanying notes.
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Panhandle Oil and Gas Inc.
Consolidated Balance Sheets
See accompanying notes.
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Panhandle Oil and Gas Inc.
Consolidated Statements of Income
See accompanying notes.
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Panhandle Oil and Gas Inc.
Consolidated Statements of Stockholders’ Equity
See accompanying notes.
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Panhandle Oil and Gas Inc.
Consolidated Statements of Cash Flows
(Continued on next page)
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Panhandle Oil and Gas Inc.
Consolidated Statements of Cash Flows (continued)
See accompanying notes.
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements
September 30, 2008, 2007 and 2006
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 gas properties, principally involving drilling wells located on the Company’s mineral acreage. Panhandle’s mineral properties and other oil and gas interests are all located in the United States, primarily in Arkansas, Kansas, Oklahoma, New Mexico and Texas. The Company is not the operator of any wells. The majority of the Company’s oil and gas production is from small interests in several thousand wells located principally in Oklahoma. Approximately 80% of oil and gas revenues are derived from the sale of natural gas. Substantially all the Company’s oil and 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 gas properties as a normal course of business.
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of Panhandle Oil and Gas Inc. and its wholly-owned subsidiaries after elimination of all material intercompany transactions.
Use of Estimates
Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Of these judgments and estimates, management considers the estimation of crude oil and nature gas reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. On an annual basis, with a limited scope semi-annual update, the Company’s consulting petroleum engineer, with assistance from Company geologists, prepares estimates of crude oil and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. As required by the guidelines and definitions established by the SEC, these estimates are based on year-end crude oil and natural gas pricing for DD&A purposes. For impairment purposes, projected future crude oil and natural gas prices as estimated by management are used. Crude oil and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future crude oil and natural gas pricing assumptions are used by management to prepare estimates of crude oil and natural gas reserves used in formulating management’s overall operating decisions in the exploration and production segment.
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
The Company does not operate any of its oil and gas properties, and primarily holds small interests in several thousand wells, however in the last three years it has begun to take larger interests in several new wells drilled each year. Obtaining timely production data from the well operators is extremely difficult and in most cases delayed one to three months. This causes the Company to utilize past production receipts and estimated sales price information to estimate its oil and gas sales revenue accrual at the end of each quarterly period. The oil and gas accrual can be impacted by many variables, including the initial high production rates and possible rapid decline rates of certain new wells and rapidly changing market prices for natural gas. The Company records an accrual to actual adjustment in each succeeding quarter.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.
Oil and Gas Sales and Gas Imbalances
The Company sells oil and natural gas to various customers, recognizing revenues as oil and gas is produced and sold. The Company uses the sales method of accounting for gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a reservoir cannot be recouped through the production of remaining reserves. At September 30, 2008 and 2007, the Company had no material gas imbalances.
Charges for compression, marketing, gathering and transportation of natural gas are included in lease operating expenses and production taxes.
Concentration of Credit Risk
Substantially all of the Company’s accounts receivable are due from purchasers of oil and natural gas or operators of the oil and gas properties. Oil and natural gas sales are generally unsecured. On July 22, 2008, SemGroup, L.P. and certain subsidiaries (SemGroup) filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. As a result of the filing, the Company has reserved $591,258 of receivables as uncollectible for substantially all of the sales of crude oil through various well operators to SemGroup during the period June 1, 2008 through July 22, 2008. The amount reserved was charged to bad debt expense in fiscal 2008.
Derivative contracts entered into by the Company are also unsecured.
Oil and Gas Producing Activities
The Company follows the successful efforts method of accounting for oil and gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income if and when the well is determined to be nonproductive. Oil and gas mineral and leasehold costs are capitalized when incurred.
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
Derivatives
Beginning in fiscal year 2007, the Company entered in costless collar arrangements intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These economic hedging arrangements may expose the Company to risk of financial loss and limit the benefit of future increases in prices. The derivative instruments have settled or will settle based on the prices below which are basis adjusted and tied to certain pipelines in Oklahoma.
Derivative contracts in place during fiscal 2007 and 2008
(prices below reflect the Company’s net price from Oklahoma pipelines)
While the Company believes that its derivative contracts are effective in achieving the risk management objective for which they were intended, the Company has elected not to complete all of the documentation requirements necessary under SFAS No. 133 to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was $646,193 and $106,916 as of September 30, 2008 and 2007, respectively. Realized and unrealized gains and (losses) are scheduled below:
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Panhandle Oil and Gas Inc.
Notes to Consolidated 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 gas properties are generally computed using the units of production method primarily on a separate property basis using proved reserves as estimated annually by a consulting petroleum engineer. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.
Non-producing oil and gas properties include non-producing minerals, which have a net book value of $5,024,581 at September 30, 2008, consisting of perpetual ownership of mineral interests in several states, with 84% of the acreage in Oklahoma, Texas and New Mexico. As mentioned these mineral rights are perpetual and have been accumulated over the 82 year life of the Company. There are approximately 209,000 net acres of non-producing minerals in over 7,000 tracts owned by the Company. An average tract contains approximately 29 acres and the average cost per acre is $39. Since inception, the Company has continually generated an interest in several thousand oil and 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 thirty-three year period. These assets are considered a long-term investment by the Company, they do not expire (as do oil and gas leases), in many cases the same mineral acreage has seen several wells drilled over the span of several years and development of this acreage has been steady since the 1960’s. Given the above, it was concluded that a longer term amortization was appropriate and that 33 years, based on past history and experience was a conservative range. Also, based on the fact that the minerals consist of a large number of properties whose costs are not individually significant, and virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.
In accordance with the provisions of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, 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 techniques considering expected future prices and costs and oil and gas quantities as estimated by management with the assistance of the Company’s consulting petroleum engineer. The Company’s oil and gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $526,380, $3,761,832 and $3,009,953 respectively, for 2008, 2007 and 2006. The impairment in 2006 is mostly due to two adjacent western Oklahoma fields on which earlier drilled wells performed better than more recently drilled wells. These same fields experienced higher than expected overall production and reserve volume declines in 2007, resulting in further impairment on both fields in 2007. The impairments taken on these fields in 2006 and 2007 comprise approximately 66% of all impairment costs.
In accordance with SFAS 144, the Company’s estimate of fair value of its oil and gas properties at September 30, 2008 is based on the best information available as of that date, including estimates of forward oil and natural gas prices. Subsequent to September 30, 2008, both crude oil and natural gas prices have declined, with crude oil prices in particular declining substantially. Continued lower crude oil and natural gas prices would likely result in lower estimates of the fair value of oil and gas properties, and potentially result in additional impairment charges.
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Panhandle Oil and Gas Inc.
Notes to Consolidated 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 five percent or greater, but does not have control of the partnership or LLC, are accounted for using the equity method of accounting.
Asset Retirement Obligations
The Company owns interests in oil and natural gas properties which may require expenditures to plug and abandon the wells when the oil and natural gas reserves in the wells are depleted. These expenditures are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). The obligations represent the Company’s share of the total costs of all wells. The Company does not have any assets restricted for the purpose of settling the plugging liabilities.
The following table shows the activity for the year ended September 30, 2008 relating to the Company’s retirement obligation for plugging liability:
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 these environmental laws will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future events. Since the Company does not operate any wells 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 to the extent available at reasonable cost, pollution control coverage. However, all risks are not insured due to the availability and cost of insurance.
Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2008 and 2007, there were no such costs accrued.
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
Earnings Per Share of Common Stock
Earnings per share is calculated using net income divided by the weighted average of common shares outstanding including unissued, vested directors’ shares during the period.
Share-based Compensation
The Company recognizes current compensation costs for its Outside Directors Deferred Compensation Plan (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. Effective October 19, 2005, the Plan was amended such 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. This amendment removed the conversion to cash option available under the Plan, resulting in reclassification to equity of the liability under the Plan. Effective October 1, 2005, the Company adopted Financial Accounting Standards Board (FASB) No. 123(R) “Share Based Payments.” Due to the nature of the Company’s equity based compensation, the adoption of the standard did not have a material effect on the Company’s financial statements.
The Company applies SOP 93-6 in accounting for its non-leveraged Employee Stock Ownership Plan. Under SOP 93-6 the Company records as expense, the fair market value of the stock at the time of contribution.
Fair Values of Financial Instruments
The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, derivative contracts, income tax and other, 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 due to the interest rates on the Company’s revolving line of credit being rates which are approximately equivalent to market rates for similar type debt based on the Company’s credit worthiness.
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 matters.
On October 1, 2007, the Company adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company and its subsidiary file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2004.
The Company has performed its evaluation of tax positions and has determined that the adoption of FIN 48 did not have a material impact on the Company’s financial condition, results of operations, or cash flows. This evaluation included a review of the appropriate recognition threshold for each tax position recognized in the Company’s financial statements. Based on this evaluation, the Company did not identify any tax positions that did not meet the “highly certain positions” threshold. As a result, no additional tax expense, interest, or penalties have been accrued as a result of the review.
The Company includes interest assessed by the taxing authorities in “Interest expense” and penalties related to income taxes in “General and administrative expense” on its Consolidated Statements of Income. For the years ended September 30, 2008 and 2007, the Company recorded no interest or penalties on uncertain tax positions.
New Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. Adoption of this statement is not expected to have a material effect on the Company’s financial position, results of operations or cash flows.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. Adoption of this statement is not expected to have a material effect on the Company’s financial position, results of operations or cash flows.
Other accounting standards that have been issued or proposed by the FASB or other standards-setting bodies that do not require adoption until a future date are not expected to have a material impact on the consolidated financial statements upon adoption.
2. Commitments
The Company leases office space in Oklahoma City, Oklahoma under the terms of an operating lease expiring in April 2012. Future minimum rental payments under the terms of the lease are $196,699 in 2009, $204,089 in 2010, $204,089 in 2011 and $119,052 in 2012. Total rent expense incurred by the Company was $175,335 in 2008, $147,849 in 2007 and $153,164 in 2006.
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
3. Income Taxes
The Company’s provision for income taxes is detailed as follows:
The difference between the provision for income taxes and the amount which would result from the application of the federal statutory rate to income before provision for income taxes is analyzed below:
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:
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
4. Long-term Debt
The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan in the amount of $50,000,000 which is subject to a semi-annual borrowing base determination. The current borrowing base under the BOK Agreement is $15,000,000. The revolving loan matures on October 31, 2010. Borrowings outstanding under the revolving loan amounted to $9,704,100 and $4,661,471 as of September 30, 2008 and 2007, respectively. The revolving loan bears interest at the BOK national prime rate minus from 1.375% to .75%, or 30 day LIBOR plus from 1.375% to 2.0% (effective rate of 5.3% as of September 30, 2008). The interest rate charged will be based on the percent of the value advanced of the calculated loan value of the Company’s oil and gas reserves. The interest rate spread from LIBOR or prime increases or decreases as a larger percent of the loan value of the Company’s oil and gas properties is advanced.
Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2008, the Company was in compliance with the covenants of the BOK agreement.
5. Shareholders’ Equity
On December 12, 2006, the Company’s Board of Directors approved a proposal to amend the Company’s Articles of Incorporation to increase the number of authorized shares of Class A Common Stock from 12,000,000 shares to 24,000,000 shares with no change to the par value of $.01666 per share. On March 8, 2007, this proposal was put forth to a vote of the shareholders, for which a majority of the shareholders voted in favor of the proposal, causing this proposal to become effective on such date.
All agreements concerning Common Stock of the Company, including the Company’s Employee Stock Ownership Plan and the Company’s commitment under the Deferred Compensation Plan for Non-Employee Directors, provide for the issuance or commitment, respectively, of additional shares of the Company’s stock due to the declaration of a stock split. All references to number of shares, per share, and authorized share information in the accompanying consolidated financial statements have been adjusted to reflect the stock split distributed to stockholders on January 9, 2006 and to reflect the increase in authorized shares approved on March 8, 2007, at the Annual Meeting of the Stockholders of the Company.
ISSUER PURCHASES OF EQUITY SECURITIES
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
5. Shareholders’ Equity (continued)
On May 28, 2008 and July 29, 2008 the Company announced that its Board of Directors had approved stock repurchase programs to purchase up to $2,000,000 and $3,000,000 (respectively) of the Company’s common stock. The shares are held in treasury and are accounted for using the cost method. As of September 30, 2008, 7,640 treasury shares were contributed to the Company’s ESOP on behalf of the ESOP participants.
6. Earnings Per Share
The following table sets forth the computation of earnings per share.
7. Employee Stock Ownership Plan
The Company has an employee stock ownership plan that covers all employees and is established to provide such employees with a retirement benefit. These benefits become fully vested after three years of employment. Contributions to the plan are at the discretion of the Board of Directors and can be made in cash (none in 2008, 2007 or 2006) or the Company’s common stock. For contributions of common stock, the Company records as expense, the fair market value of the stock at the time of contribution. The 228,623 shares of the Company’s common stock held by the plan as of September 30, 2008, 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:
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
8. Deferred Compensation Plan for Directors
Effective November 1, 1994, the Company formed the Panhandle Deferred Compensation Plan for Non-Employee Directors (the Plan). The Plan provides that each eligible director can individually elect to receive shares of Company stock rather than cash for board and committee chair retainers, board meeting fees and board committee meeting fees. These shares are unissued and vest as earned. The shares are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. Because the original Plan contained an option allowing the directors to convert the shares to cash upon separation from the Company, the liability was adjusted for subsequent changes in market value of the shares. Upon retirement, termination or death of the director or upon change in control of the Company, the shares accrued under the Plan would have been either issued to the director or converted to cash, at the director’s discretion, for the fair market value of the shares on the conversion date, as defined by the Plan. As of September 30, 2008, 86,853 shares (78,398 shares at September 30, 2007) are included in the Plan. Effective October 19, 2005 the Plan was amended such 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. This amendment removed the conversion to cash option available under the Plan, which resulted in reclassification to stockholders’ equity of the deferred shares outstanding under the Plan. The deferred balance outstanding at September 30, 2008 under the Plan was $1,605,811 ($1,358,778 at September 30, 2007). $247,033, $156,209 and ($132,736) were charged (credited) to the Company’s results of operations for the years ended September 30, 2008, 2007 and 2006, respectively, and is included in general and administrative expense in the accompanying income statement.
9. Information on Oil and Gas Producing Activities
All oil and gas producing activities of the Company are conducted within the United States (principally in Oklahoma and Arkansas) and represent substantially all of the business activities of the Company.
During 2008, 2007 and 2006 approximately 16%, 20% and 14%, respectively, of the Company’s total revenues were derived from sales through Chesapeake Operating, Inc. During 2008, 2007 and 2006 approximately 17%, 13% and 11%, respectively, of the Company’s total revenues were derived from sales through JMA Energy Company. During 2008 approximately 12% of the Company’s total revenues were derived from sales through Newfield Exploration.
Aggregate Capitalized Costs
The aggregate amount of capitalized costs of oil and gas properties and related accumulated depreciation, depletion, and amortization as of September 30 is as follows:
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
9. Information on Oil and Gas Producing Activities (continued)
Costs Incurred
During the reporting period, the Company incurred the following costs in oil and gas producing activities:
10. Supplementary Information on Oil and Gas Reserves (Unaudited)
The following unaudited information regarding the Company’s oil and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission (SEC) and SFAS No. 69, Disclosures About Oil and Gas Producing Activities.
Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Because the Company’s non-producing mineral and leasehold interests consist of various small interests in numerous tracts located primarily in Oklahoma, New Mexico and Texas and because the Company is a non-operator and must rely on third parties to propose and drill and operate producing wells, it is not feasible or possible to provide estimates of all proved undeveloped reserves and associated future net revenues. The Company is currently providing proved undeveloped reserve estimates for wells that it has a substantial reason to believe will be drilled in the very near term. In most cases, this means the Company has received some type of notice from the operator that a well will be drilled.
The Company’s net proved (including certain undeveloped reserves described above) oil and gas reserves, all of which are located in the United States, as of September 30, 2008, 2007 and 2006, have been estimated by the Company’s consulting petroleum engineering firm. 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, 2008, 2007 and 2006. 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.
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
10. Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)
Estimated Quantities of Proved Oil and Gas Reserves
Net quantities of proved, developed, and undeveloped oil and gas reserves are summarized as follows:
The prices used to calculate reserves and future cash flows from reserves for oil and natural gas, respectively, were as follows: September 30, 2008 - $97.74/Bbl, $4.51/Mcf; September 30, 2007 - $78.93/Bbl, $5.50/Mcf; September 30, 2006 - $60.50/Bbl, $3.49/Mcf.
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
10. Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)
The above reserve numbers exclude approximately 2.9, 2.3, 1.6 and 1.5 Bcf of CO2 gas reserves for the years ended September 30, 2008, 2007, 2006 and 2005, respectively.
(1) Wells had commenced drilling on approximately 65% of Proved Undeveloped Reserves at September 30, 2008.
Standardized Measure of Discounted Future Net Cash Flows
Estimates of future cash flows from proved oil and gas reserves, based on current prices and costs, as of September 30 are shown in the following table. Estimated income taxes are calculated by applying the appropriate year-end tax rates to the estimated future pretax net cash flows less depreciation of the tax basis of properties and statutory depletion allowances. Prices used for determining future cash flows from oil and natural gas as of September 30, 2008, 2007, 2006 were as follows: 2008 - $97.74/Bbl, $4.51/Mcf; 2007 - $78.93/Bbl, $5.50/Mcf; 2006 - $60.50/Bbl, $3.49/Mcf.
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Panhandle Oil and Gas Inc.
Notes to Consolidated Financial Statements (continued)
10. Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)
Changes in the standardized measure of discounted future net cash flow are as follows:
11. Quarterly Results of Operations (Unaudited)
The following is a summary of the Company’s unaudited quarterly results of operations.
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ITEM 9
ITEM 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
NONE
ITEM 9A
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 Securities Exchange Act of 1934, 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/CEO and Vice President/CFO, 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 President/CEO and Vice President/CFO have concluded that, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure that material information relating to the Company, including its consolidated subsidiary, is made known to them.
(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, 2008.
(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, 2008 or subsequent to the date the assessment was completed.
PART III
The information called for by Part III of Form 10-K (Item 10
ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statement Schedules
The Company has omitted all other schedules because the conditions requiring their filing do not exist or because the required information appears in the Company’s Consolidated Financial Statements, including the notes to those statements.
Exhibits
REPORTS ON FORM 8-K
No Form 8-K’s were filed in the fourth quarter of fiscal 2008.
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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.
In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ Bruce M. Bell
/s/ E. Chris Kauffman
Bruce M. Bell, Director
E. Chris Kauffman, Director
Date December 10, 2008
Date December 10, 2008
/s/ Duke R. Ligon
Duke R. Ligon, Director
/s/ Robert O. Lorenz
Robert O. Lorenz, Lead Independent Director
Date December 10, 2008
Date December 10, 2008
/s/ Robert A. Reece
/s/ Robert E. Robotti
Robert A. Reece, Director
Robert E. Robotti, Director
Date December 10, 2008
Date December 10, 2008
/s/ H. Grant Swartzwelder
H. Grant Swartzwelder, Director
Date December 10, 2008
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