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EX-99 - EX-99 - PANHANDLE OIL & GAS INCphx-20140930xex99.htm
EX-32.2 - EX-32.2 - PANHANDLE OIL & GAS INCphx-20140930ex322d20aaa.htm
EX-32.1 - EX-32.1 - PANHANDLE OIL & GAS INCphx-20140930ex3215efa4b.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-K

 

Picture 1

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2014

 

Commission  File  Number:001-31759

 

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

 

 

 

OKLAHOMA

73-1055775

(State or other jurisdiction of incorporation

(I.R.S. Employer Identification No.)

or organization)

 

 

 

Grand Centre, Suite 300, 5400 N. Grand Blvd., Oklahoma City, OK   73112

(Address of principal executive offices)

(Zip code)

 

 

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

 

 

 

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

 

 

 

CLASS A COMMON STOCK (VOTING)

NEW YORK STOCK EXCHANGE

(Title of Class)

(Name of each exchange on which registered)

 

 

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

 

(Title of Class)

 

 

 

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

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Exchange Act of 1934.      Yes    X  No

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.     Yes    X  No

 

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

 


 

(Facing Sheet Continued)

 

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

 

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

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Securities Exchange Act of 1934. (Check one):

 

Large accelerated filer___    Accelerated filer   X        Non-accelerated filer___    Smaller reporting company ___

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).      Yes    X  No

 

The aggregate market value of the voting stock held by non-affiliates of the registrant, computed by using the $21.81 per share closing price (adjusted for 2-for-1 stock split effective October 8, 2014) of registrant's Common Stock, as reported by the New York Stock Exchange at March 31, 2014, was $312,393,606. As of December 1, 2014,  16,491,301 shares of Class A Common Stock were outstanding.

 

Documents Incorporated By Reference

 

The information required by Part III of this Report, to the extent not set forth herein, is incorporated by reference from the registrant’s Definitive Proxy Statement relating to the annual meeting of stockholders to be held on  March 4, 2015, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Report relates.

 


 

 

T A B L E   O F   C O N T E N T S

 

 

 

 

 

 

 

 

PART I

 

Page

Item 1

Business

Item 1A

Risk Factors

Item 1B

Unresolved Staff Comments

13 

Item 2

Properties

13 

Item 3

Legal Proceedings

22 

Item 4

Mine Safety Disclosures

22 

 

 

 

PART II

 

 

Item 5

Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

23 

Item 6

Selected Financial Data

25 

Item 7

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

26 

Item 7A

Quantitative and Qualitative Disclosures about Market Risk

38 

Item 8

Financial Statements and Supplementary Data

39 

Item 9

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

77 

Item 9A

Controls and Procedures

77 

Item 9B

Other Information

77 

 

 

 

PART III

 

 

Item 10-14

Incorporated by Reference to Proxy Statement

77 

 

 

 

PART IV

 

 

Item 15

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

78 

 

 

 

 

 


 

DEFINITIONS

 

The following defined terms are used in this report:

Bbl” barrel.

Bcf” billion cubic feet.

“Bcfe” natural gas stated on a Bcf basis and crude oil and natural gas liquids converted to a billion cubic feet of natural gas equivalent by using the ratio of one million Bbl of crude oil or natural gas liquids to six Bcf of natural gas. 

“Board” board of directors.

BTU”  British Thermal Units.

“CEO” Chief Executive Officer.

“CFO” Chief Financial Officer.

“Company” Panhandle Oil and Gas Inc.

“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.

“conventional” An area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.

“COO” Chief Operating Officer.

“DD&A” depreciation, depletion and amortization.

“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.

“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry gas” natural gas that remains in a gaseous state in the reservoir and does not produce large quantities of liquid hydrocarbons when brought to the surface. Also may refer to gas that has been processed or treated to remove all natural gas liquids.

“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.

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

“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir.

“FASB” the Financial Accounting Standards Board.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“formation” A layer of rock which has distinct characteristics that differs from nearby rock.

“G&A” general and administrative expenses.

“gross acres” or  “gross wells” the total acres or wells in which a working interest is owned.

“held by production” or “HBP” Refers to an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.

“horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.

“hydraulic fracturing” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production.

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

“LOE” lease operating expense.

Mcf” thousand cubic feet.

Mcfd” thousand cubic feet per day.


 

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

Mmbtu”  million BTU.

“Mmcf” million cubic feet.

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

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

“net acres” or “net wells” the sum of the fractional working interests owned in gross acres or gross wells.

“NGL” natural gas liquids.

“NYMEX” New York Mercantile Exchange.

“OPEC” Organization of Petroleum Exporting Countries.

“Panhandle” Panhandle Oil and Gas Inc.

“PDP” proved developed producing.

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

“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.

“proved developed reserves” Reserves expected to be recovered through existing wells with existing equipment and operating methods.

“proved undeveloped reserves” or “PUD” Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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

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

SEC” the United States Securities and Exchange Commission.

“unconventional” An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbonwater boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.

“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

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

 

Fiscal year references

All references to years in this report, unless otherwise noted, refer to the Company’s fiscal year end of September 30. For example, references to 2014 mean the fiscal year ended September 30, 2014.

 

References to oil and natural gas properties

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

 


 

 

PART I

 

ITEM 1BUSINESS

 

GENERAL

 

Panhandle Oil and Gas Inc. was founded in Range, Texas County, Oklahoma, in 1926, as Panhandle Cooperative Royalty Company and operated as a cooperative until 1979, when the Company merged into Panhandle Royalty Company, and its shares became publicly traded. On April 2, 2007, the Company’s name was changed to Panhandle Oil and Gas Inc.

 

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

 

On June 17, 2014, the Company closed on its largest purchase to date which consisted of a 16% non-operated working interest in 11,100 gross leasehold acres (1,775 net) located in the Eagle Ford Shale play in LaSalle and Frio Counties, Texas, at an adjusted purchase price of $81.7 million.

 

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

 

In March 2007, the Company increased its authorized Class A Common Stock from 12 million shares to 24 million shares.  On  October 8, 2014, the Company split its Class A Common Stock on a 2-for-1 basis.

 

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

 

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

 

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

 

(1)


 

BUSINESS STRATEGY

 

Most of Panhandle’s revenues are derived from the production and sale of oil, NGL and natural gas (see Item 8 - “Financial Statements and Supplementary Data”). The Company’s oil and natural gas properties, including its mineral acreage, leasehold acreage and working and royalty interests in producing wells are located mainly in Arkansas, New Mexico, North Dakota, Oklahoma and Texas (see Item 2 – “Properties”). Exploration and development of the Company’s oil and natural gas properties are conducted in association with oil and natural gas exploration and production companies, primarily larger independent companies. The Company does not operate any of its oil and natural gas properties, but has been an active working interest participant for many years in wells drilled on the Company’s mineral acres and leasehold. The majority of the Company’s drilling participations are on properties located in unconventional plays in Arkansas, Oklahoma and Texas.

 

PRINCIPAL PRODUCTS AND MARKETS

 

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

 

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

 

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

 

COMPETITIVE BUSINESS CONDITIONS

 

The oil and natural gas industry is highly competitive, particularly in the search for new oil, NGL and natural gas reserves. Many factors affect Panhandle’s competitive position and the market for its products, which are beyond its control. Some of these factors include: the quantity and price of foreign oil imports; domestic supply of oil, NGL and natural gas; changes in prices received for oil, NGL and natural gas production; business and consumer demand for refined oil products, NGL and natural gas; and the effects of federal and state regulation of the exploration for, production of and sales of oil, NGL and natural gas (see Item 1A – “Risk Factors”). Changes in any of these factors can have a dramatic influence on the price Panhandle receives for its oil, NGL and natural gas production.

 

(2)


 

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

 

SOURCES AND AVAILABILITY OF RAW MATERIALS

 

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

 

MAJOR CUSTOMERS

 

The Company’s oil, NGL and natural gas production is sold, in most cases, through its well operators to many different purchasers on a well-by-well basis. During 2014, sales through two separate well operators accounted for approximately 17% and 11% of the Company’s total oil, NGL and natural gas sales. During 2013, sales through two separate well operators accounted for approximately 20% and 10% of the Company’s total oil, NGL and natural gas sales. During 2012, sales through three separate well operators accounted for approximately 15%,  13% and 10% of the Company’s total oil, NGL and natural gas sales. Generally, if one purchaser declines to continue purchasing the Company’s production, several other purchasers can be located. Pricing is generally consistent from purchaser to purchaser.

 

PATENTS, TRADEMARKS, LICENSES, FRANCHISES AND ROYALTY AGREEMENTS

 

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

 

REGULATION

 

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

 

States require permits for drilling operations, drilling bonds and reports concerning operations and impose other regulations relating to the exploration for and production of oil, NGL and natural gas. These states also have regulations addressing conservation matters, including provisions for the unitization or

(3)


 

pooling of oil and natural gas properties and the regulation of spacing, plugging and abandonment of wells. These regulations vary from state to state. As previously discussed, the Company must rely on its well operators to comply with governmental regulations.

 

ENVIRONMENTAL MATTERS

 

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

 

EMPLOYEES

 

At September 30, 2014, Panhandle employed 22 people with 5 of the employees serving as executive officers. The President and CEO is also a director of the Company.

 

ITEM 1ARISK FACTORS

 

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating the Company’s business and future prospects. If any of the following risk factors should occur, the Company’s financial condition could be materially impacted and the holders of our securities could lose part or all of their investment in Panhandle. The risk factors described below are not 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.

 

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

 

Effects of change in domestic and international economic conditions could include: (1) a decline in demand for oil, NGL and natural gas resulting in decreased oil, NGL and natural gas reserves due to curtailed drilling activity; (2) a decline in oil, NGL and natural gas prices; (3) risk of insolvency of well operators and oil, NGL and natural gas purchasers; (4) limited availability of certain insurance coverage; (5) limited access to derivative instruments; and (6) limited credit availability. A decline in reserves would lead to a decline in production, and either a production decline, or a decrease in oil, NGL and natural gas prices, would have a negative impact on the Company’s cash flow, profitability and value.

 

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

 

The supply of and demand for oil, NGL and natural gas impact the prices we realize on the sale of these commodities and, in turn, materially affect the Company’s financial results. Oil, NGL and natural

(4)


 

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

 

·

worldwide economic conditions

·

economic, political, regulatory and tax developments

·

market uncertainty

·

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

·

availability and capacity of necessary transportation and processing facilities

·

commodity futures trading

·

regional price differentials

·

differing quality of oil produced (i.e., sweet crude versus heavy or sour crude)

·

differing quality and NGL content of natural gas produced

·

weather conditions

·

the level of imports and exports of oil, NGL and natural gas

·

political instability or armed conflicts in major oil and natural gas producing regions

·

actions taken by OPEC

·

competition from alternative sources of energy

·

technological advancements affecting energy consumption and energy supply

 

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

 

Lower oil, NGL and natural gas prices may also trigger significant impairment write-downs on a portion of the Company’s properties and negatively affect the Company’s results of operations and its ability to borrow under its credit facility.

 

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

 

The Company’s financial position, results of operations, access to capital and the quantities of oil, NGL and natural gas that may be economically produced would be negatively impacted if oil, NGL and natural gas prices decrease significantly for an extended period of time. The ways in which such price decreases could have a material negative effect include:

 

·

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

·

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

·

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

·

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

 

 

The Company cannot control activities on its properties.

 

(5)


 

The Company does not operate any of the properties in which it has an interest and has very limited ability to exercise influence over the third-party operators of these properties. Our dependence on the third-party operators of our properties, and on the cooperation of other working interest owners in these properties, could negatively affect the following:

 

·

the Company’s return on capital used in drilling or property acquisition

·

the Company’s production and reserve growth rates

·

capital required to drill and complete wells

·

success and timing of drilling, development and exploitation activities on the Company’s properties

·

compliance with environmental, safety and other regulations

·

lease operating expenses

·

plugging and abandonment costs, including well-site restorations

 

Dependency on each operator’s judgment, expertise and financial resources could result in unexpected future costs, lost revenues and/or capital restrictions to the extent they would cumulatively have a material adverse effect on the Company’s financial position and results of operations.

 

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

 

In order to manage exposure to price volatility on our oil and natural gas production, we enter into oil and natural gas derivative contracts for a portion of our expected production. Oil and natural gas price derivatives may limit the cash flow we actually realize and therefore reduce the Company’s ability to fund future projects. None of our oil and natural gas price derivative contracts are designated as hedges for accounting purposes; therefore, we record all derivative contracts at fair value on our balance sheet. Accordingly, these fair values may vary significantly from period to period, materially affecting reported earnings. The fair value of our oil and natural gas derivative instruments outstanding as of September 30, 2014, was a net asset of $1,901,842.

 

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

 

There are also risks of financial loss associated with derivative instruments if there is an increase in the differential between the underlying price of the derivative contract and the actual received price.

 

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

 

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

 

The Company has elected to utilize the successful efforts method of accounting for its oil and natural gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and development dry holes are capitalized and amortized by property using the unit-of-production method (the ratio of oil, NGL and natural gas

(6)


 

volumes produced to total proved or proved developed reserves) as oil, NGL and natural gas are produced.

 

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

 

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

 

 It is not possible to measure underground accumulations of oil, NGL and natural gas with precision. Oil, NGL and natural gas reserve engineering requires subjective estimates of underground accumulations of oil, NGL and natural gas using assumptions concerning future prices of these commodities, future production levels, and operating and development costs. In estimating our reserves, we and our Independent Consulting Petroleum Engineering Firm must make various assumptions with respect to many matters that may prove to be incorrect, including:

 

·

future oil, NGL and natural gas prices

·

production rates

·

reservoir pressures, decline rates, drainage areas and reservoir limits

·

interpretation of subsurface conditions including geological and geophysical data

·

potential for water encroachment or mechanical failures

·

levels and timing of capital expenditures, lease operating expenses, production taxes and income taxes, and availability of funds for such expenditures

·

effects of government regulation

 

If any of these assumptions prove to be incorrect, our estimates of reserves, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

 

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

 

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

(7)


 

 

Because PUD’s, under SEC reporting rules, may only be recorded if the wells they relate to are scheduled to be drilled within five years of the date of recording, the removal of PUD’s that are not developed within this five-year period may be required. Removals of this nature may significantly reduce the quantity and present value of the Company’s oil, NGL and natural gas reserves.

 

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

 

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

 

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

 

The rate of production from oil and natural gas properties generally declines as reserves are depleted. The Company’s proved reserves will decline materially as reserves are produced except to the extent that the Company acquires additional properties containing proved reserves, conducts additional successful exploration and development drilling, successfully applies new technologies or identifies additional behind-pipe zones (different productive zones within existing producing well bores) or secondary recovery reserves.

 

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

 

Cost factors can adversely affect the economics of any project, and ultimately the cost of drilling, completing and operating a well is controlled by well operators and existing market conditions. Further, drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

 

·

unexpected drilling conditions

·

title problems

·

pressure or irregularities in formations

·

equipment failures or accidents

·

fires, explosions, blowouts and surface cratering

·

lack of availability to market production via pipelines or other transportation

·

adverse weather conditions

·

environmental hazards or liabilities

·

governmental regulations

·

cost and availability of drilling rigs, equipment and services

·

expected sales price to be received for oil, NGL or natural gas produced from the wells

(8)


 

 

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

 

The Company is subject to all the risks normally incident to the operation and development of oil and natural gas properties, including:

 

·

well blowouts, cratering, explosions and human related accidents

·

mechanical, equipment and pipe failures

·

adverse weather conditions and natural disasters

·

civil disturbances and terrorist activities

·

oil, NGL and natural gas price reductions

·

environmental risks stemming from the use, production, handling and disposal of water, waste materials, hydrocarbons and other substances into the air, soil or water

·

title problems

·

limited availability of financing

·

marketing related infrastructure, transportation and processing limitations

·

regulatory compliance issues

 

As a non-operator, we are dependent on third-party operators and the contractors they hire for operational safety, environmental safety and compliance with regulations of governmental authorities.

 

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 the Company against all risks. For example, the Company does not maintain insurance for business interruption, acts of war or terrorism. Additionally, pollution and environmental risks generally are not fully insurable. These risks could give rise to significant uninsured costs that could have a material adverse effect on the Company’s business condition and financial results.

 

Debt level and interest rates may adversely affect our business.

 

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan of $200,000,000. As of September 30, 2014, the Company had a balance of $78,000,000 drawn on the facility. The facility has a current borrowing base of $130,000,000, is secured by certain of the Company’s properties and contains certain restrictive covenants.

 

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

 

·

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

·

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

·

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

·

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

·

changes in prevailing interest rates may affect the Company’s capability to meet its debt service requirements, as its credit facility bears interest at floating rates

 

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

(9)


 

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

 

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

 

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

 

Federal Income Taxation

 

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

 

Hydraulic Fracturing and Water Disposal

 

The vast majority of oil and natural gas wells drilled in recent years have been, and future wells are expected to be, hydraulically fractured as a part of the process of completing the wells and putting them on production. This is true of the wells drilled in which the Company owns an interest. Hydraulic fracturing is a process that involves pumping water, sand and additives at high pressure into rock formations to stimulate oil and natural gas production. In developing plays where hydraulic fracturing, which requires large volumes of water, is necessary for successful development, the demand for water may exceed the supply. A lack of readily available water or a significant increase in the cost of water could cause delays or increased completion costs.

 

In addition to water, hydraulic fracturing fluid contains chemical additives designed to optimize production. Well operators are being required in certain states to disclose the components of these additives. Additional states and the federal government may follow with similar requirements or may restrict the use of certain additives. This could result in more costly or less effective development of wells.

 

Once a well has been hydraulically fractured, the fluid produced from the fractured wells must be either treated for reuse or disposed of by injecting the fluid into disposal wells. Both the fracturing and injection well disposal processes are being studied to determine if there is a correlation between fracturing and/or injection well disposal and the occurrence of earthquakes.

 

Efforts to regulate hydraulic fracturing and fluid disposal are increasing at the local, state and federal level. Several new regulations are being considered, including limiting water withdrawals and usage, limiting water disposition, restricting which additives may be used, implementing state-wide hydraulic fracturing moratoriums and temporary or permanent bans in certain environmentally sensitive areas. Public sentiment against hydraulic fracturing and fluid disposal and shale production has become more vocal, which could result in more stringent permitting and compliance requirements. Consequences of these actions could potentially

(10)


 

increase capital, compliance and operating costs significantly, as well as delay or halt the further development of oil and gas reserves on the Company’s properties.

 

Any of the above factors could have a material adverse effect on our financial position, results of operations or cash flows.

 

Climate Change

 

Certain studies have suggested that emission of certain gases, commonly referred to as "greenhouse gases," may be impacting the earth's climate. Methane, a primary component of natural gas, and carbon dioxide, a by-product of burning oil and natural gas, are examples of greenhouse gases. Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as oil and gas production equipment and operations. At the federal level, the EPA has already made findings and issued regulations that require operators to establish and report an inventory of greenhouse gas emissions.

 

Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the sale of oil and natural gas. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain equipment and facilities, install new emission controls on equipment and facilities, acquire allowances to authorize greenhouse gas emissions and pay taxes related to greenhouse gas emissions. Even without federal legislation or regulation of greenhouse gas emissions, states may pursue the issue either directly or indirectly.

 

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and gas industry. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for oil and natural gas.

 

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

 

The demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, NGL and natural gas prices, resulting in periodic shortages. When demand for rigs and equipment increases due to an increase in the number of wells being drilled, there have been shortages of drilling rigs, hydraulic fracturing equipment and personnel and other oilfield equipment. Higher oil, NGL and natural gas prices generally stimulate increased demand for, and result in increased prices of, drilling rigs, crews and associated supplies, equipment and services. These shortages or price increases could negatively affect the ability to drill wells and conduct ordinary operations by the operators of the Company’s wells, resulting in an adverse effect on the Company’s financial condition, cash flow and operating results.

 

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

 

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

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

 

Significant capital expenditures are required to replace our reserves and conduct our business.

 

The Company funds exploration, development and production activities primarily through cash flows from operations and acquisitions through borrowings under its credit facility. The timing and amount of capital necessary to carry out these activities can vary significantly as a result of product price fluctuations, property acquisitions, drilling results and the availability of drilling rigs, equipment, well services and transportation capacity.

 

Cash flows from operations and access to capital are subject to a number of variables, including the Company’s:

 

·

amount of proved reserves

·

volume of oil, NGL and natural gas produced

·

received prices for oil, NGL and natural gas sold

·

ability to acquire and produce new reserves

·

ability to obtain financing

 

We may have limited ability to obtain the capital required to sustain our operations at current levels if our borrowing base under our credit facility is lowered as a result of decreased revenues, lower product prices, declines in reserves or for other reasons. Failure to sustain operations at current levels could have a material adverse effect on our financial condition, cash flow and results of operations.

 

We may be subject to information technology system failures, network disruptions, cyber-attacks or other breaches in data security.

 

Power, telecommunication or other system failures due to hardware or software malfunctions, computer viruses, vandalism, terrorism, natural disasters, fire, human error or by other means could significantly affect the Company’s ability to conduct its business. Though we have implemented complex network security measures, stringent internal controls and maintain offsite backup of all crucial electronic data, there cannot be absolute assurance that a form of system failure or data security breach will not have a material adverse effect on our financial condition and operations results.

 

ITEM 1BUNRESOLVED STAFF COMMENTS

 

None

 

ITEM 2PROPERTIES

 

At September 30, 2014, Panhandle’s principal properties consisted of (1) perpetual ownership of 255,190 net mineral acres, held principally in Arkansas, New Mexico, North Dakota, Oklahoma, Texas and six other states; (2) leases on 19,645 net acres primarily in Oklahoma: and (3) working interests,

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royalty interests or both in 6,019 producing oil and natural gas wells and 95 wells in the process of being drilled or completed.

 

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

 

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

 

ACREAGE

 

Mineral Interests Owned

 

The following table of mineral acreage owned reflects, in each respective state, the number of net and gross acres, net and gross producing acres, net and gross acres leased, and net and gross acres open (unleased) as of September 30, 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

State

Net Acres

Gross Acres

Net Acres Producing (1)

Gross Acres Producing (1)

Net Acres Leased to Others (2)

Gross Acres Leased to Others (2)

Net Acres Open (3)

Gross Acres Open (3)

Arkansas

11,990 
51,775 
7,088 
26,730 
1,712 
5,428 
3,190 
19,617 

Colorado

8,217 
39,080 

 -

 -

 -

 -

8,217 
39,080 

Florida

3,832 
8,212 

 -

 -

 -

 -

3,832 
8,212 

Kansas

3,082 
11,816 
144 
1,200 

 -

 -

2,938 
10,616 

Montana

1,008 
17,947 

 -

 -

 -

 -

1,008 
17,947 

New Mexico

57,374 
174,300 
1,366 
6,965 
160 
320 
55,848 
167,015 

North Dakota

11,179 
64,286 
190 
2,196 

 -

 -

10,989 
62,090 

Oklahoma

113,459 
952,780 
41,928 
338,850 
6,247 
42,945 
65,284 
570,985 

South Dakota

1,825 
9,300 

 -

 -

 -

 -

1,825 
9,300 

Texas

43,197 
360,348 
8,425 
74,342 
1,129 
4,372 
33,643 
281,634 

Other

27 
262 

 -

 -

 -

 -

27 
262 

Total:

255,190 
1,690,106 
59,141 
450,283 
9,248 
53,065 
186,801 
1,186,758 

 

(1)

“Producing” represents the mineral acres in which Panhandle owns a royalty or working interest in a producing well.

(2)

“Leased” represents the mineral acres owned by Panhandle that are leased to third parties but not producing.

(3)

“Open” represents mineral acres owned by Panhandle that are not leased or in production.

 

 

 

 

Leases

 

The following table reflects net mineral acres leased from others, lease expiration dates, and net leased acres held by production as of September 30, 2014.

 

(13)


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

State

Net  Acres

Net Acres Expiring

Net Acres Held by Production

 

 

2015 
2016 
2017 
2018 
2019 

 

Arkansas

2,256 
71 

 -

27 
88 

 -

2,070 

Kansas

2,117 

 -

 -

 -

 -

 -

2,117 

Oklahoma

11,896 
56 

 -

 -

 -

 -

11,840 

Texas

2,293 

 -

 -

 -

 -

 -

2,293 

Other

1,083 

 -

 -

 -

 -

 -

1,083 

TOTAL

19,645 
127 

 -

27 
88 

 -

19,403 

 

PROVED RESERVES

 

The following table summarizes estimates of proved reserves of oil, NGL and natural gas held by Panhandle as of September 30, 2014. All proved reserves are located onshore within the contiguous United States and are principally made up of small interests in 6,019 wells, which are predominately located in the Mid-Continent region. Other than this report, the Company’s reserve estimates are not filed with any other federal agency.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barrels of Oil

 

Barrels of NGL

 

Mcf of Natural Gas

 

Mcfe

Net Proved Developed Reserves

 

 

 

 

 

 

 

 

September 30, 2014

 

2,890,678 

 

1,564,859 

 

88,512,767 

 

115,245,989 

September 30, 2013

 

1,037,721 

 

764,321 

 

82,298,833 

 

93,111,085 

September 30, 2012

 

849,548 

 

494,160 

 

65,733,119 

 

73,795,367 

 

 

 

 

 

 

 

 

 

Net Proved Undeveloped Reserves

 

 

 

 

 

 

 

 

September 30, 2014

 

4,678,901 

 

1,475,322 

 

53,979,593 

 

90,904,931 

September 30, 2013

 

605,582 

 

851,805 

 

49,990,334 

 

58,734,656 

September 30, 2012

 

222,771 

 

294,582 

 

47,780,937 

 

50,885,055 

 

 

 

 

 

 

 

 

 

Net Total Proved Reserves

 

 

 

 

 

 

 

 

September 30, 2014

 

7,569,579 

 

3,040,181 

 

142,492,360 

 

206,150,920 

September 30, 2013

 

1,643,303 

 

1,616,126 

 

132,289,167 

 

151,845,741 

September 30, 2012

 

1,072,319 

 

788,742 

 

113,514,056 

 

124,680,422 

 

The 54.3 Bcfe increase in total proved reserves from 2013 to 2014 is primarily a combination of the following factors:

 

·

Negative performance revisions of 4.7 Bcfe, which consisted of 1.7 Bcfe of negative proved developed revisions principally due to poorer than projected well performance attributable to properties in western Oklahoma and the Texas Panhandle and 3.0 Bcfe of negative proved undeveloped revisions principally attributable to the removal of dry gas reserves which are no longer projected to be developed within 5 years from the date they were added to the proved undeveloped reserves.

 

·

Added reserves of 3.3 Bcfe due to positive pricing revisions which lengthened the economic limits of certain proved developed wells (2.6 Bcfe) and proved undeveloped locations (0.7 Bcfe). 

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·

Property purchases of 49.0 Bcfe primarily in the Eagle Ford Shale in South Texas and to a much lesser extent the Fayetteville Shale in Arkansas.

 

·

Proved developed reserve additions of 3.2 Bcfe principally resulting from:

 

a)The Company’s participation in ongoing development of unconventional natural gas utilizing horizontal drilling in the Arkansas Fayetteville Shale. 

 

b)The Company’s participation in ongoing development of conventional oil, NGL and natural gas plays including the Granite Wash and Marmaton plays in western Oklahoma, and the Springer play in southern Oklahoma as well as minor activity in other areas.

 

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

 

·

The addition of 17.8 Bcfe of PUD reserves principally in the Fayetteville Shale play in Arkansas, the Anadarko Basin Woodford Shale in western and southern Oklahoma and the Marmaton and Granite Wash plays in western Oklahoma, as well as the Bakken play in North Dakota. These additions are the result of reservoir delineation proved by continuing drilling and well performance data in each of the referenced plays.

 

·

Production of 14.1 Bcfe.

 

The following details the changes in proved undeveloped reserves for 2014 (Mcfe):

 

 

 

 

 

 

Beginning proved undeveloped reserves

58,734,656 

Proved undeveloped reserves transferred to proved developed

(17,488,307)

Revisions

(2,251,443)

Extensions and discoveries

17,776,338 

Purchases

34,133,687 

Ending proved undeveloped reserves

90,904,931 

 

The beginning PUD reserves were 58.7 Bcfe. A total of 17.5 Bcfe (30% of the beginning balance) were transferred to proved developed producing during 2014. The 2.3 Bcfe of negative revisions to PUD reserves consist of a positive pricing revision of 0.7 Bcfe offset by a 3.0 Bcfe (5% of the beginning balance) negative performance revision in 2014 as the result of removal of dry gas reserves which are no longer projected to be developed within 5 years from the date they were added. A total of 20.5 Bcfe (35% of the beginning balance) of PUD reserves were moved out of the category during 2014 as either the result of being transferred to proved developed or removed because they were no longer projected to be developed within 5 years from the date they were added to the proved undeveloped reserves. PUD locations from 2010 representing 9% of total 2014 PUD reserves remain in the PUD category. We anticipate that all the Company’s PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves which are no longer projected to be drilled within 5 years from the date they were added to the proved undeveloped reserves will be removed as revisions at the time that determination is made, and in the event that there are undrilled PUD locations at the end of the five-year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions.

 

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

 

The Company follows the SEC’s modernized oil and natural gas reporting rules, which were effective for annual reports on Form 10−K for fiscal years ending on or after December 31, 2009. See Note 11 to the financial statements in Item 8 – “Financial Statements and Supplementary Data” for disclosures regarding our oil and natural gas reserves.

 

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

 

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

 

Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major

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

 

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2014,  2013 and 2012 (see Exhibits 23 and 99).

 

The Company’s net proved oil, NGL and natural gas reserves (including certain undeveloped reserves described above) are located onshore in the contiguous United States. All studies have been prepared in accordance with regulations prescribed by the SEC. The reserve estimates were based on economic and operating conditions existing at September 30, 2014,  2013 and 2012. Since the determination and valuation of proved reserves is a function of testing and estimation, the reserves presented should be expected to change as future information becomes available.

 

ESTIMATED FUTURE NET CASH FLOWS

 

Set forth below are estimated future net cash flows with respect to Panhandle’s net proved reserves (based on the estimated units set forth above in Proved Reserves) for the year indicated, and the present value of such estimated future net cash flows, computed by applying a 10% discount factor as required by SEC rules and regulations. The Company follows the SEC Rule, Modernization of Oil and Gas Reporting Requirements. In accordance with the SEC rule, the estimated future net cash flows were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-month period prior to September 30 held flat over the life of the properties and applied to future production of proved reserves less estimated future development and production expenditures for these reserves. The amounts presented are net of operating costs and production taxes levied by the respective states. Prices used for determining future cash flows from oil, NGL and natural gas as of September 30, 2014,  2013 and 2012 were as follows: $96.94/Bbl,  $31.45/Bbl,  $4.04/Mcf;  $89.06/Bbl,  $27.28/Bbl,  $3.33/Mcf; $89.41/Bbl,  $35.70/Bbl,  $2.51/Mcf, respectively. These future net cash flows based on SEC pricing rules should not be construed as the fair market value of the Company’s reserves. A market value determination would need to include many additional factors, including anticipated oil, NGL and natural gas price and production cost increases or decreases, which could affect the economic life of the properties.

 

 

(17)


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Estimated Future Net Cash Flows

 

 

 

 

 

 

 

 

 

9/30/2014

 

9/30/2013

 

9/30/2012

Proved Developed

$

451,452,075 

 

$

239,353,059 

 

$

165,036,044 

Proved Undeveloped

 

383,970,247 

 

 

123,822,641 

 

 

72,851,862 

Income Tax Expense

 

(308,149,182)

 

 

(131,397,192)

 

 

(83,543,516)

Total Proved

$

527,273,140 

 

$

231,778,508 

 

$

154,344,390 

 

 

 

 

 

 

 

 

 

10% Discounted Present Value of Estimated Future Net Cash Flows

 

9/30/2014

 

9/30/2013

 

9/30/2012

Proved Developed

$

234,799,797 

 

$

125,186,445 

 

$

87,587,058 

Proved Undeveloped

 

135,228,020 

 

 

51,276,694 

 

 

27,151,132 

Income Tax Expense

 

(165,245,313)

 

 

(74,788,243)

 

 

(47,323,902)

Total Proved

$

204,782,504 

 

$

101,674,896 

 

$

67,414,288 

 

OIL, NGL AND NATURAL GAS PRODUCTION

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

Year Ended

 

Year Ended

 

9/30/2014

 

9/30/2013

 

9/30/2012

Bbls - Oil

346,387 

 

234,084 

 

153,143 

Bbls - NGL

207,688 

 

111,897 

 

98,714 

Mcf - Natural Gas

10,773,559 

 

10,886,329 

 

9,072,298 

Mcfe

14,098,009 

 

12,962,215 

 

10,583,440 

 

AVERAGE SALES PRICES AND PRODUCTION COSTS

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

Year Ended

 

Year Ended

Average Sales Price

9/30/2014

 

9/30/2013

 

9/30/2012

Per Bbl, Oil

$

93.68 

 

$

91.56 

 

$

90.13 

Per Bbl, NGL

$

32.31 

 

$

27.67 

 

$

33.23 

Per Mcf, Natural Gas

$

4.05 

 

$

3.31 

 

$

2.62 

Per Mcfe

$

5.88 

 

$

4.68 

 

$

3.86 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

Year Ended

 

Year Ended

Average Production (lifting) Costs

9/30/2014

 

9/30/2013

 

9/30/2012

 (Per Mcfe)

 

 

 

 

 

 

 

 

          Well Operating Costs (1)

$

0.99 

 

$

0.92 

 

$

0.86 

          Production Taxes (2)

 

0.19 

 

 

0.14 

 

 

0.14 

 

$

1.18 

 

$

1.06 

 

$

1.00 

 

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

(18)


 

(2)Includes production taxes only.

 

In fiscal 2014, approximately 27% of the Company’s oil, NGL and natural gas revenue was generated from royalty payments received on its mineral acreage. Royalty interests bear no share of the operating costs on those producing wells.

 

GROSS AND NET PRODUCTIVE WELLS AND DEVELOPED ACRES

 

The following table sets forth Panhandle’s gross and net productive oil and natural gas wells as of September 30, 2014. Panhandle owns either working interests, royalty interests or both in these wells. The Company does not operate any wells.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Working Interest Wells

 

Net Working Interest Wells

 

Gross Royalty Only Wells

 

Total Gross Wells

Oil

 

334 

 

26.45 

 

936 

 

1,270 

Natural Gas

 

1,839 

 

84.88 

 

2,910 

 

4,749 

Total

 

2,173 

 

111.33 

 

3,846 

 

6,019 

 

Panhandle’s average interest in royalty interest only wells is 0.82%. Panhandle’s average interest in working interest wells is 5.12% working interest and 4.85% net revenue interest.

 

Information on multiple completions is not available from Panhandle’s records, but the number is not believed to be significant. With regard to Gross Royalty Only Wells, some of these wells are in multi-well unitized fields. In such cases, the Company’s ownership in each unitized field is counted as one gross well as the Company does not have access to the actual well count in all of these unitized fields.

 

As of September 30, 2014, Panhandle owned 450,283 gross developed mineral acres and 59,141 net developed mineral acres. Panhandle has also leased from others 145,923 gross developed acres containing 19,403 net developed acres.

 

UNDEVELOPED ACREAGE

 

As of September 30, 2014, Panhandle owned 1,239,823 gross and 196,049 net undeveloped mineral acres, and leases on 7,039 gross and 242 net undeveloped acres.

 

DRILLING ACTIVITY

 

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

 

 

(19)


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Productive

 

Net Productive

 

Net Dry

 

 

Working Interest Wells

 

Royalty Interest Wells

 

Working Interest Wells

Development Wells

 

 

 

 

 

 

Fiscal years ended:

 

 

 

 

 

 

 September 30, 2014

 

6.375382

 

1.215322

 

0.026849

 September 30, 2013

 

7.405905

 

1.532470

 

0.003906

 September 30, 2012

 

5.376408

 

1.225832

 

0.093438

 

 

 

 

 

 

 

Exploratory Wells

 

 

 

 

 

 

Fiscal years ended:

 

 

 

 

 

 

 September 30, 2014

 

0.141038

 

0.026367

 

           -

 September 30, 2013

 

           -

 

0.079589

 

0.048446

 September 30, 2012

 

0.298974

 

0.090654

 

0.531250

 

 

 

 

 

 

 

Purchased Wells

 

 

 

 

 

 

Fiscal years ended:

 

 

 

 

 

 

 September 30, 2014

 

11.644719

 

           -

 

           -

 September 30, 2013

 

           -

 

0.218122

 

           -

 September 30, 2012

 

4.300626

 

0.231430

 

           -

 

PRESENT ACTIVITIES

 

The following table sets forth the gross and net oil and natural gas wells drilling or testing as of September 30, 2014, in which Panhandle owns either a working interest, a royalty interest or both. These wells were not producing at September 30, 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Working Interest Wells

 

Net Working Interest Wells

 

Gross Royalty Only Wells

 

Total Gross Wells

Oil

 

16

 

1.24

 

25

 

41

Natural Gas

 

51

 

1.49

 

3

 

54

 

OTHER FACILITIES

 

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

 

SAFE HARBOR STATEMENT

 

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

 

These forward-looking statements include, among others, such things as: the amount and nature of our future capital expenditures; wells to be drilled or reworked; prices for oil, NGL and natural gas; demand for oil, NGL and natural gas; estimates of proved oil, NGL and natural gas reserves;

(20)


 

development and infill drilling potential; drilling prospects; business strategy; production of oil, NGL and natural gas reserves; and expansion and growth of our business and operations. 

 

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

 

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

 

In order to provide a more thorough understanding of the possible effects of some of these influences on any forward-looking statements made, the following discussion outlines certain factors that in the future could cause results for 2015 and beyond to differ materially from those that may be presented in any such forward-looking statement made by or on behalf of the Company.

 

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

 

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

 

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

 

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

 

(21)


 

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

 

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

 

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

 

ITEM 3LEGAL PROCEEDINGS

 

There were no material legal proceedings involving Panhandle on September 30, 2014, or at the date of this report.

 

ITEM 4MINE SAFETY DISCLOSURES

 

Not applicable.

(22)


 

PART II

 

ITEM 5MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Picture 2

 

The above graph compares the 5-year cumulative total return provided shareholders on our Class A Common Stock (“Common Stock”) relative to the cumulative total returns of the S&P Smallcap 600 Index and the S&P Oil & Gas Exploration & Production Index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our Common Stock and in each of the indexes on September 30, 2009, and its relative performance is tracked through September 30, 2014.

 

Since July 2008, the Company’s Common Stock has been listed and traded on the New York Stock Exchange (symbol PHX). The following table sets forth the high and low trade prices of the Common Stock during the periods indicated (all share and per share amounts have been adjusted for a  2-for-1 stock split, effective on October 8, 2014):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Quarter Ended

 

High

 

Low

December 31, 2012

 

$

15.85 

 

$

12.35 

March 31, 2013

 

$

15.32 

 

$

13.42 

June 30, 2013

 

$

15.56 

 

$

13.50 

September 30, 2013

 

$

16.43 

 

$

13.64 

December 31, 2013

 

$

17.00 

 

$

13.79 

March 31, 2014

 

$

24.10 

 

$

16.17 

June 30, 2014

 

$

30.66 

 

$

21.01 

September 30, 2014

 

$

34.45 

 

$

26.00 

 

(23)


 

At December 1, 2014, there were 1,405 holders of record of Panhandle’s Class A Common Stock and approximately 7,200 beneficial owners.

 

During the past two years, the Company has paid quarterly dividends of $.035 to $.04 per share (adjusted for stock split) on its Common Stock. Approval by the Company’s Board is required before the declaration and payment of any dividends.

 

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

 

The Company’s credit facility also contains a provision limiting the paying or declaring of a cash dividend during any fiscal year to 20% of net cash flow provided by operating activities from the Statement of Cash Flows of the preceding 12-month period. See Note 4 to the financial statements in Item 8 – “Financial Statements and Supplementary Data” for a further discussion of the credit facility.

 

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in  March 2010, the Board directed the purchase of the Company’s Common Stock, from time to time, equal to the aggregate number of shares of Common Stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. Effective May 2014, the board of directors approved for management to make these purchases of the Company’s Common Stock at their discretion. The Boards approval included an initial authorization to purchase up to $1.5 million of Common Stock, with a provision for subsequent authorizations without specific action by the Board. As the amount of Common Stock purchased under any authorization reaches $1.5 million, another $1.5 million is automatically authorized for Common Stock purchases unless the Board determines otherwise. 

 

(24)


 

ITEM 6SELECTED FINANCIAL DATA

 

The following table summarizes financial data of the Company for its last five fiscal years and should be read in conjunction with Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8 – “Financial Statements and Supplementary Data”, including the Notes thereto, included elsewhere in this report.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of and for the year ended September 30,

 

2014

 

2013

 

2012

 

2011

 

2010

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, NGL and natural gas sales

$

82,846,528 

 

$

60,605,878 

 

$

40,818,434 

 

$

43,469,130 

 

$

44,068,947 

Lease bonuses and rentals

 

423,328 

 

 

938,846 

 

 

7,152,991 

 

 

352,757 

 

 

1,120,674 

Gains (losses) on derivative contracts

 

247,414 

 

 

611,024 

 

 

73,822 

 

 

734,299 

 

 

6,343,661 

Income from partnerships

 

893,954 

 

 

733,372 

 

 

487,070 

 

 

420,465 

 

 

405,134 

 

 

84,411,224 

 

 

62,889,120 

 

 

48,532,317 

 

 

44,976,651 

 

 

51,938,416 

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

13,912,792 

 

 

11,861,403 

 

 

9,141,970 

 

 

8,441,754 

 

 

8,193,319 

Production taxes

 

2,694,118 

 

 

1,834,840 

 

 

1,449,537 

 

 

1,456,755 

 

 

1,446,545 

Exploration costs

 

86,017 

 

 

9,795 

 

 

979,718 

 

 

1,025,542 

 

 

1,583,773 

Depreciation, depletion and amortization

 

21,896,902 

 

 

21,945,768 

 

 

19,061,239 

 

 

14,712,188 

 

 

19,222,123 

Provision for impairment

 

1,096,076 

 

 

530,670 

 

 

826,508 

 

 

1,728,162 

 

 

605,615 

Loss (gain) on asset sales & other

 

8,378 

 

 

(942,959)

 

 

(88,477)

 

 

(68,325)

 

 

(1,089,060)

Interest expense

 

462,296 

 

 

157,558 

 

 

127,970 

 

 

 -

 

 

60,912 

General and administrative

 

7,433,183 

 

 

6,801,996 

 

 

6,388,856 

 

 

5,994,663 

 

 

5,594,499 

 

 

47,589,762 

 

 

42,199,071 

 

 

37,887,321 

 

 

33,290,739 

 

 

35,617,726 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before provision

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(benefit) for income taxes

 

36,821,462 

 

 

20,690,049 

 

 

10,644,996 

 

 

11,685,912 

 

 

16,320,690 

Provision (benefit) for income taxes

 

11,820,000 

 

 

6,730,000 

 

 

3,274,000 

 

 

3,192,000 

 

 

4,901,000 

Net income (loss)

$

25,001,462 

 

$

13,960,049 

 

$

7,370,996 

 

$

8,493,912 

 

$

11,419,690 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted earnings (loss) per share

$

1.49 

 

$

0.84 

 

$

0.44 

 

$

0.51 

 

$

0.68 

Dividends declared per share

$

0.16 

 

$

0.14 

 

$

0.14 

 

$

0.14 

 

$

0.14 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted

 

16,727,183 

 

 

16,713,808 

 

 

16,721,862 

 

 

16,787,780 

 

 

16,844,774 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

$

52,622,602 

 

$

37,402,109 

 

$

25,371,195 

 

$

29,283,929 

 

$

27,806,475 

Investing activities

$

(121,950,995)

 

$

(26,379,675)

 

$

(38,372,702)

 

$

(27,200,816)

 

$

(9,845,516)

Financing activities

$

66,970,977 

 

$

(10,139,362)

 

$

11,478,606 

 

$

(4,173,372)

 

$

(13,003,609)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

$

246,640,604 

 

$

147,838,430 

 

$

135,186,730 

 

$

111,424,193 

 

$

105,124,839 

Long-term debt

$

78,000,000 

 

$

8,262,256 

 

$

14,874,985 

 

$

 -

 

$

 -

Shareholders' equity

$

119,188,653 

 

$

95,655,486 

 

$

83,852,146 

 

$

78,802,317 

 

$

73,581,996 

 

All share and per share amounts were adjusted for the 2-for-1 stock split, effective on October 8, 2014.

 

 

 

 

(25)


 

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

 

BUSINESS OVERVIEW

 

The Company’s principal line of business is to explore for, develop, acquire, produce and sell oil, NGL and natural gas. Results of operations are dependent primarily upon the Company’s: existing reserve quantities; costs associated with acquiring, exploring for and developing new reserves; production quantities and related production costs; and oil, NGL and natural gas sales prices.

 

On June 17, 2014, the Company closed on the purchase of a 16% non-operated working interest in 11,100 gross leasehold acres (1,775 net) located in the Eagle Ford Shale play in LaSalle and Frio Counties, Texas, at an adjusted purchase price at closing of $81.7 million. All of the acquired acreage was held by production and, at the time of closing, included 63 producing wells, 1 drilling well, 3 wells in the completion phase and 109 undeveloped locations.

 

Fiscal 2014 oil and NGL production increased 48% and 86%, respectively, over that of 2013. These production increases are primarily the result of the following: the acquisition of producing properties in the Eagle Ford Shale and associated horizontal drilling on that leasehold; horizontal drilling in the Marmaton, Hogshooter and Granite Wash in western Oklahoma; and horizontal Woodford Shale drilling in the Anadarko Basin in western and southern Oklahoma. To a lesser extent, horizontal drilling in the Mississippian in northern Oklahoma and horizontal Cleveland drilling in the Texas Panhandle contributed to the oil and NGL production increase.

 

As of September 30, 2014, the Company owned an average 3.0% net revenue interest in 95 wells that were drilling or testing. As these wells begin producing and other scheduled wells are drilled and completed in the abovementioned plays, the Company anticipates 2015 Mcfe production volumes will increase over those of 2014; however, a reduction in oil prices could curtail 2015 drilling and limit Mcfe production in 2015.

 

The increased production of oil and NGL in 2014, combined with higher 2014 oil, NGL and natural gas prices resulted in a 37% increase in revenues from the sale of oil, NGL and natural gas. Based on recent forward strip pricing, the Company believes 2015 average oil, NGL and natural gas prices will be lower than their corresponding average prices in 2014.

 

The Company’s proved developed oil, NGL and natural gas reserves increased in 2014, compared to 2013, by 22.1 Bcfe, or 24%. The increase was due primarily to the acquisition of producing properties in the Eagle Ford Shale and the associated horizontal Eagle Ford drilling on that leasehold in addition to the Company’s other successful drilling activities.

 

The Company had no off balance sheet arrangements during 2014 or prior years.

 

(26)


 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended September 30,

 

 

 

 

Percent

 

 

 

 

Percent

 

 

 

 

2014

 

Incr. or (Decr.)

 

2013

 

Incr. or (Decr.)

 

2012

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

346,387 

 

48%

 

 

234,084 

 

53%

 

 

153,143 

NGL (Bbls)

 

207,688 

 

86%

 

 

111,897 

 

13%

 

 

98,714 

Natural Gas (Mcf)

 

10,773,559 

 

(1%)

 

 

10,886,329 

 

20%

 

 

9,072,298 

Mcfe

 

14,098,009 

 

9%

 

 

12,962,215 

 

22%

 

 

10,583,440 

Average Sales Price:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

$

93.68 

 

2%

 

$

91.56 

 

2%

 

$

90.13 

NGL (per Bbl)

$

32.31 

 

17%

 

$

27.67 

 

(17%)

 

$

33.23 

Natural Gas (Mcf)

$

4.05 

 

22%

 

$

3.31 

 

26%

 

$

2.62 

Mcfe

$

5.88 

 

26%

 

$

4.68 

 

21%

 

$

3.86 

 

RESULTS OF OPERATIONS

 

Fiscal Year 2014 Compared to Fiscal Year 2013

 

Overview

 

The Company recorded net income of $25,001,462, or $1.49 per share, in 2014, compared to net income of $13,960,049, or $0.84 per share, in 2013. Revenues increased in 2014 primarily due to higher oil and NGL sales volumes and higher natural gas sales prices, partially offset by decreased gains on derivative contracts and decreased lease bonuses received.

 

Expenses increased in 2014 due to higher LOE, production taxes and G&A coupled with an increase in the provision for impairment and a decrease in other miscellaneous income.

 

Oil, NGL and Natural Gas Sales

 

Oil, NGL and natural gas sales increased $22,240,650 or 37% for 2014, as compared to 2013. The increase was due to increased oil and NGL volumes of 48% and 86%, respectively, and increased oil, NGL and natural gas prices of 2%,  17% and 22%, respectively, in 2014.  

 

The oil and NGL production increase is primarily the result of the Company’s acquisition of producing properties in the Eagle Ford Shale in South Texas and the associated horizontal drilling on that leasehold, horizontal drilling in the Marmaton, Hogshooter and Granite Wash in western Oklahoma and horizontal Woodford Shale drilling in the Anadarko Basin in western and southern Oklahoma. To a lesser extent, horizontal drilling in the Mississippian in northern Oklahoma and horizontal Cleveland drilling in the Texas Panhandle contributed to the oil and NGL production increase.

 

(27)


 

Production by quarter for 2014 and 2013 was as follows (Mcfe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

First quarter

 

3,509,270

 

3,008,365

Second quarter

 

3,496,222

 

3,245,411

Third quarter

 

3,309,394

 

3,229,800

Fourth quarter

 

3,783,123

 

3,478,639

Total

 

14,098,009

 

12,962,215

 

Lease Bonus and Rentals

 

Lease bonuses and rentals decreased $515,518 in 2014 due to decreased mineral leasing activity. There were no significant leases of the Company’s mineral acreage in 2013 or 2014.

 

Gains (Losses) on Derivative Contracts

 

Gains on derivative contracts decreased $363,610 or 60% in 2014. The decrease in gains was mainly due to the natural gas collars and natural gas fixed price swaps being more beneficial in 2013, as NYMEX gas futures had fallen further below the floor of the collars and the fixed gas prices of the swaps. As of September 30, 2014, the Company’s natural gas fixed price swaps have expiration dates of October and December 2014; the natural gas costless collar contracts have an expiration date of December 2014; the oil costless collar contracts have an expiration date of December 2014 and the oil fixed price swaps have expiration dates of December 2014, March 2015, June 2015 and December 2015.

 

Lease Operating Expenses (LOE)

 

LOE increased $2,051,389 or 17% in 2014. LOE costs per Mcfe of production increased from $0.92 in 2013 to $0.99 in 2014. The total LOE increase is primarily due to increased field operating costs of $1,900,168 in 2014 compared to 2013. Field operating costs increased due to the acquisition of the Eagle Ford Shale properties and additional wells drilled in 2014. Field operating costs were $.50 per Mcfe in 2014 compared to $.40 per Mcfe in 2013, a 25% increase. This increase in rate is principally the result of the significant number of oil and NGL rich wells drilled in recent years. These wells have higher lifting costs than our overall well population.

 

The increase in LOE related to field operating costs was also coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) on natural gas of $151,221 in 2014, as compared to 2013. On a per Mcfe basis, these fees were down $.03 due to significant increases in oil and NGL production, while natural gas production was essentially flat. Natural gas sales bear the large majority of the handling fees. Handling fees are charged either as a percent of sales or based on production volumes.

 

Depreciation, Depletion and Amortization (DD&A)

 

DD&A decreased $48,866 in 2014. DD&A per Mcfe was $1.55 in 2014, compared to $1.69 in 2013. DD&A increased $1,922,964 due to oil, NGL and natural gas production volumes increasing 9% collectively in the 2014 period, compared to the 2013 period. An offsetting decrease of $1,971,830 was the result of a $.14 decrease in the DD&A rate. This rate decrease was principally due to higher oil, NGL and natural gas prices utilized in the reserve calculations during 2014 as compared to 2013 increasing projected remaining reserves on a significant number of wells.

 

(28)


 

Provision for Impairment

 

The provision for impairment increased $565,406 in 2014, as compared to 2013. During 2014, impairment of $1,096,076 was primarily recorded on ten small fields in Oklahoma and Texas. These fields have one to a few wells and are more susceptible to impairment when a well in the field experiences downward reserve revisions, or when a newly completed well with low reserves is added to one of these fields. During 2013, impairment of $530,670 was recorded on five small fields in Oklahoma and Texas.

 

Loss (Gain) on Asset Sales and Other

 

Loss (gain) on asset sales and other was a net loss of $8,378 in 2014, as compared to a net gain of $942,959 in 2013. The gain in 2013 was mainly the result of a class action lawsuit settlement of approximately $604,000 related to the underpayment of royalty revenues and gains on asset sales of $208,749.

 

Interest Expense

 

Interest expense increased $304,738 in 2014, as compared to 2013. The increase was primarily due to a larger outstanding debt balance that was used to purchase the Eagle Ford Shale properties in the third quarter of 2014.

 

General and Administrative Costs (G&A)

 

G&A increased $631,187 or 9% in 2014. The increase is primarily related to increases in the following expense categories: legal $275,286, personnel $123,586 and audit and tax $112,745. The increase in legal expenses was primarily the result of additional fees for legal services associated with the Eagle Ford Shale acquisition and a property rights dispute in 2014. The increase in 2014 personnel related expenses was largely the result of compensation increases of $100,406. The increase in audit and tax fees in 2014 was principally due to increased fees for services associated with the Eagle Ford Shale acquisition.

 

Provision (Benefit) for Income Taxes

 

The 2014 provision for income taxes of $11,820,000 was based on a pre-tax income of $36,821,462, as compared to a provision for income taxes of $6,730,000 in 2013, based on a pre-tax income of $20,690,049.  The effective tax rate for 2014 was 32%, compared to an effective tax rate for 2013 of 33%. The Company’s utilization of excess percentage depletion, which is a permanent tax benefit, decreased the provision for income taxes and reduced the effective tax rate below the statutory rate for both years. 

 

Fiscal Year 2013 Compared to Fiscal Year 2012

 

Overview

 

The Company recorded net income of $13,960,049, or $0.84 per share, in 2013, compared to net income of $7,370,996, or $0.44 per share, in 2012. Revenues increased in 2013 primarily due to higher oil and natural gas sales volumes and prices, partially offset by decreased lease bonuses received.

 

Expenses increased due to higher DD&A, LOE and G&A in 2013, partially offset by decreases in the provision for impairment and exploration costs and increases i