Attached files

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EX-99 - EX-99 - PANHANDLE OIL & GAS INCphx-ex99_373.htm
EX-32.2 - EX-32.2 - PANHANDLE OIL & GAS INCphx-ex322_8.htm
EX-32.1 - EX-32.1 - PANHANDLE OIL & GAS INCphx-ex321_327.htm
EX-31.2 - EX-31.2 - PANHANDLE OIL & GAS INCphx-ex312_7.htm
EX-31.1 - EX-31.1 - PANHANDLE OIL & GAS INCphx-ex311_6.htm
EX-23.2 - EX-23.2 - PANHANDLE OIL & GAS INCphx-ex232_331.htm
EX-23.1 - EX-23.1 - PANHANDLE OIL & GAS INCphx-ex231_330.htm
EX-12.1 - EX-12.1 - PANHANDLE OIL & GAS INCphx-ex121_329.htm
EX-10.5 - EX-10.5 - PANHANDLE OIL & GAS INCphx-ex105_332.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

 

 

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

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2017

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

 


 

(Facing Sheet Continued)

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

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.      X   

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       

Emerging growth company       

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.         Yes          No

 

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 $19.20 per share closing price of registrant's Common Stock, as reported by the New York Stock Exchange at March 31, 2017, was $297,276,077. As of December 1, 2017, 16,678,016 shares of Class A Common Stock were outstanding. As of December 1, 2017, there were no shares of Class B Common Stock outstanding.

Documents Incorporated By Reference

The information required by Part III of this Report, to the extent not set forth herein, is incorporated by reference from the registrant’s Definitive Proxy Statement relating to the annual meeting of stockholders to be held on March 7, 2018. The 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

 

1

Item 1A

 

Risk Factors

 

5

Item 1B

 

Unresolved Staff Comments

 

17

Item 2

 

Properties

 

17

Item 3

 

Legal Proceedings

 

29

Item 4

 

Mine Safety Disclosures

 

29

 

 

 

 

 

PART II

 

 

 

 

Item 5

 

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

 

30

Item 6

 

Selected Financial Data

 

33

Item 7

 

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

 

34

Item 7A

 

Quantitative and Qualitative Disclosures about Market Risk

 

49

Item 8

 

Financial Statements and Supplementary Data

 

51

Item 9

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

91

Item 9A

 

Controls and Procedures

 

91

Item 9B

 

Other Information

 

91

 

 

 

 

 

PART III

 

 

 

 

Item 10-14

 

Incorporated by Reference to Proxy Statement

 

92

 

 

 

 

 

PART IV

 

 

 

 

Item 15

 

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

 

93

 

 

 


 

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.

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 a majority of 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 differ 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.

production or produced – volumes of oil, NGL and natural gas that have been both produced and sold.

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 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 hydrocarbon water 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 – 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 2017 mean the fiscal year ended September 30, 2017.

 

References to oil and natural gas properties

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

 

 

 

 


 

PART I

ITEM 1

BUSINESS

GENERAL

Panhandle Oil and Gas Inc. was founded in Range, Texas County, Oklahoma, in 1926, as Panhandle Cooperative Royalty Company. The Company operated as a cooperative until 1979, when it 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 and leasehold acreage and small companies were made from 1980 to the present time.

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. 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 primarily 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. Oil, NGL and natural gas sales are principally handled by the well operator. Payment for oil, NGL and natural gas sold is received by the Company from the well operator or the contracted 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 subject to weather conditions, 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. Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the derivative contracts.

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

(2)


 

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, state and local 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.

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 in both 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 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 with limited capital and staffing.

SOURCES AND AVAILABILITY OF RAW MATERIALS

The existence of economically recoverable oil, NGL and natural gas reserves in commercial quantities is crucial 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. When it is evaluated to be beneficial to share value, the Company 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, to produce and sell 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. During 2017, sales through two separate well operators accounted for approximately 18% and 13% of the Company’s total oil, NGL and natural gas sales. During 2016, sales through two separate well operators accounted for approximately 23% and 12% of the Company’s total oil, NGL and natural gas sales. During 2015, sales through two separate well operators accounted for approximately 23% and 14% 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.

(3)


 

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. The Company’s oil and natural gas properties are subject to various taxes, such as gross production taxes and, in some cases, 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 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 made regarding future events, changes in laws, or the interpretation of laws governing our industry. For example, current discussions regarding future governance of hydraulic fracturing could have a material impact on the Company. Several states and local municipalities have adopted or are considering adopting regulations that could impose more stringent requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. The Oklahoma Corporation Commission has ordered the shut-in of some saltwater disposal wells and reductions of injected volumes in others in northern Oklahoma where these wells are proximal to seismic activity. The Company is currently experiencing insignificant impact and anticipates insignificant future impact from these shut-ins and injection volume reductions due to our minimal working interest ownership in this area. 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, the Company has no knowledge 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. The Company maintains insurance coverage at levels which are customary in the industry, but is not fully insured against all environmental risks.

(4)


 

EMPLOYEES

At September 30, 2017, Panhandle employed 21 people with four of the employees serving as executive officers. The President and CEO is also a director of the Company.

ITEM 1A

RISK FACTORS

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

(5)


 

 

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 or other major oil, NGL and natural gas producing or consuming countries

 

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 which negatively affect the Company’s results of operations. In addition, the credit available under its credit facility is affected by product prices.

Low 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 are low for an extended period of time. The ways in which low prices could have a material negative effect include:

 

significantly decrease the number of wells drilled by operators on the Company’s acreage, thereby reducing our production and cash flows

 

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 recognition of impairment expense

(6)


 

 

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 and debt markets, could be severely limited or unavailable

 

the Company may incur a reduction in the borrowing base on its credit facility

The Company cannot control activities on its properties.

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, all changes in fair value of derivative contracts are reflected in earnings. 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, 2017, was a net asset of $516,159.

(7)


 

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.

Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding derivative contracts.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on us and our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market including swap clearing and trade execution requirements. New or modified rules, regulations or requirements may increase the cost and availability to the counterparties of our hedging and swap positions which they can make available to us, as applicable, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to separate entities which may not be as creditworthy as the current counterparties. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.

While many rules and regulations have been promulgated and are already in effect, other rules and regulations remain to be finalized or effectuated, and therefore, the impact of those rules and regulations on us is uncertain at this time. The Dodd-Frank Act, and the rules promulgated thereunder, could (i) significantly increase the cost, or decrease the liquidity, of energy-related derivatives that we use to hedge against commodity price fluctuations (including through requirements to post collateral), (ii) materially alter the terms of derivative contracts, (iii) reduce the availability of derivatives to protect against risks we encounter, and (iv) increase our exposure to less creditworthy counterparties.

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

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

(8)


 

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. See Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplemental Data” for further discussion on impairment under the heading “Depreciation, Depletion, Amortization and Impairment.

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 of future estimated development, production and

(9)


 

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.

Because PUD reserves, 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 reserves 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. Please read Item 2 – “Properties – Proved Reserves” and Note 11 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data.”

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, completion, operating and other costs. In addition, wells that are profitable may not achieve a targeted rate of return. The Company relies on third-party

(10)


 

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

 

lack of water disposal facilities

 

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

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, earthquakes and other natural disasters

 

civil disturbances and terrorist activities

(11)


 

 

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 a group of banks headed by Bank of Oklahoma (BOK), which consists of a revolving loan of $200,000,000. As of September 30, 2017, the Company had a balance of $52,222,000 drawn on the facility. The facility has a current borrowing base of $80,000,000, which 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

(12)


 

 

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 interest payments, 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 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, results of operations and cash flows.

The issuance of additional shares of our common stock could cause the market price of our common stock to decline and may result in dilution to our existing shareholders.

The Company has filed a shelf registration statement, which was declared effective on November 15, 2017, that allows us to issue up to $75 million in securities including common stock, preferred stock, debt, warrants and units. The shelf registration statement is intended to provide the Company with increased financial flexibility and more efficient access to the capital markets.

We cannot predict the effect, if any, that market sales of these securities or the availability of the securities will have on the market price of our common stock prevailing from time to time. Substantial sales of shares of our common stock or other securities in the public market, or the perception that those sales could occur, may cause the market price of our common stock to decline. Such a decrease in our share price could in turn impair our ability to raise capital through the sale of additional equity securities. In addition, any such decline may make it more difficult for you to sell shares of our common stock at prices you deem acceptable.

We are currently authorized to issue an aggregate of 24,000,000 shares of common stock of which 16,678,016 shares were issued and outstanding on December 1, 2017. Future issuances of our common stock, or other securities convertible into our common stock, may result in significant dilution to our existing shareholders. Significant dilution would reduce the proportionate ownership and voting power held by our existing shareholders.

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.

(13)


 

Federal Income Taxation

The United States House of Representatives and the Senate have each passed their own version of tax reform (the “Tax Bill”) which is a proposed overhaul of the Internal Revenue Code of 1986 and could alter tax rates for individuals and businesses and could eliminate several tax deductions, including several deductions utilized by the Company. The house and the senate bills still have to be reconciled and we do not know if the Tax Bill will be adopted in whole, in part or not at all. As a result, the impact of the Tax Bill on us is uncertain at this time.

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. Injection well disposal processes have been, and continue to be, studied to determine the extent of correlation between injection well disposal and the occurrence of earthquakes. Certain studies have concluded there is a correlation, and this has resulted in the cessation of or the reduction of injection rates in certain water disposal wells, especially in northern Oklahoma.

Efforts to regulate hydraulic fracturing and fluid disposal continue at the local, state and federal level. 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

(14)


 

hydraulic fracturing and fluid disposal and shale production could result in more stringent permitting and compliance requirements. Consequences of these actions could potentially 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, the 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.

In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, in preparing an agreement which set greenhouse gas emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. To help achieve these reductions, federal agencies addressed climate change through a variety of administrative actions. The U.S. Environmental Protection Agency (the “EPA”) issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. However, on June 1, 2017, President Trump announced that the United States will withdraw and attempt to negotiate a different agreement.

The direction of future U.S. climate change regulation is difficult to predict given the current uncertainties surrounding the policies of the Trump Administration. The EPA may or may not continue developing regulations to reduce greenhouse gas emissions from the oil and natural gas industry. Even if federal efforts in this area slow, states may continue pursuing climate regulations. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require our operators to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes, and reduce demand.

Seismic Activity

Recent earthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation that could lead to operational delays, increase operating and compliance costs or otherwise adversely affect operations.

(15)


 

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.

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.

(16)


 

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 1B

UNRESOLVED STAFF COMMENTS

None

ITEM 2

PROPERTIES

At September 30, 2017, Panhandle’s principal properties consisted of (1) perpetual ownership of 255,039 net mineral acres, held principally in Arkansas, New Mexico, North Dakota, Oklahoma, Texas and six other states; (2) leases on 19,351 net acres primarily in Oklahoma: and (3) working interests, royalty interests, or both, in 6,095 producing oil and natural gas wells and 63 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 nine states.

(17)


 

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, 2017.

 

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

 

 

11,963

 

 

 

51,641

 

 

 

7,166

 

 

 

27,026

 

 

 

-

 

 

 

-

 

 

 

4,796

 

 

 

24,615

 

Colorado

 

 

8,217

 

 

 

39,080

 

 

 

-

 

 

 

-

 

 

 

8

 

 

 

80

 

 

 

8,209

 

 

 

39,000

 

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

 

 

 

175

 

 

 

360

 

 

 

55,833

 

 

 

166,975

 

North Dakota

 

 

11,179

 

 

 

64,286

 

 

 

190

 

 

 

2,196

 

 

 

-

 

 

 

-

 

 

 

10,989

 

 

 

62,090

 

Oklahoma

 

 

113,490

 

 

 

953,314

 

 

 

42,495

 

 

 

338,387

 

 

 

7,213

 

 

 

47,595

 

 

 

63,782

 

 

 

567,332

 

South Dakota

 

 

1,825

 

 

 

9,300

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

1,825

 

 

 

9,300

 

Texas

 

 

43,043

 

 

 

362,274

 

 

 

5,502

 

 

 

55,621

 

 

 

7,684

 

 

 

58,203

 

 

 

29,856

 

 

 

248,450

 

Other

 

 

27

 

 

 

262

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

27

 

 

 

262

 

Total:

 

 

255,039

 

 

 

1,692,433

 

 

 

56,864

 

 

 

431,395

 

 

 

15,080

 

 

 

106,238

 

 

 

183,096

 

 

 

1,154,800

 

 

(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, 2017.

 

State

 

Net

Acres

 

 

Net Acres Expiring

 

 

Net Acres

Held by

Production

 

 

 

 

 

 

 

2018

 

 

2019

 

 

2020

 

 

2021

 

 

2022

 

 

 

 

 

Arkansas

 

 

2,159

 

 

 

88

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

2,071

 

Kansas

 

 

2,117

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

2,117

 

Oklahoma

 

 

11,641

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

11,641

 

Texas

 

 

2,352

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

2,352

 

Other

 

 

1,083

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

1,083

 

TOTAL

 

 

19,351

 

 

 

88

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

19,263

 

 

(18)


 

PROVED RESERVES

The following table summarizes estimates of proved reserves of oil, NGL and natural gas held by Panhandle as of September 30, 2017, compared to the two preceding year ends. Proved reserves are located onshore within the contiguous United States and are principally made up of small interests in 6,095 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, 2017

 

 

2,201,528

 

 

 

1,768,425

 

 

 

87,861,043

 

 

 

111,680,761

 

September 30, 2016

 

 

1,980,519

 

 

 

1,095,256

 

 

 

62,929,047

 

 

 

81,383,697

 

September 30, 2015

 

 

2,725,077

 

 

 

1,466,834

 

 

 

82,899,159

 

 

 

108,050,625

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Proved Undeveloped Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2017

 

 

3,308,139

 

 

 

616,274

 

 

 

33,334,077

 

 

 

56,880,555

 

September 30, 2016

 

 

3,445,571

 

 

 

527,447

 

 

 

18,796,551

 

 

 

42,634,659

 

September 30, 2015

 

 

4,313,353

 

 

 

1,453,766

 

 

 

37,314,885

 

 

 

71,917,599

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Total Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2017

 

 

5,509,667

 

 

 

2,384,699

 

 

 

121,195,120

 

 

 

168,561,316

 

September 30, 2016

 

 

5,426,090

 

 

 

1,622,703

 

 

 

81,725,598

 

 

 

124,018,356

 

September 30, 2015

 

 

7,038,430

 

 

 

2,920,600

 

 

 

120,214,044

 

 

 

179,968,224

 

 

The 44.5 Bcfe increase in total proved reserves from 2016 to 2017 is primarily a combination of the following factors:

 

Positive pricing revisions of 17.9 Bcfe, primarily due to wells reaching their projected economic limits much later than projected in 2016: proved developed revisions of 17.3 Bcfe and PUD revisions of 0.6 Bcfe.

 

Negative performance revisions of 0.3 Bcfe.

 

Proved developed reserve extensions, discoveries and other additions of 9.9 Bcfe principally resulting from the Company’s participation in six wells in the liquids-rich portion of the Anadarko Woodford Shale in Canadian County, Oklahoma.

 

The addition of 29.1 Bcfe of PUD reserves, all are within the Company’s active drilling program areas of the Anadarko Woodford Shale (Cana, STACK and SCOOP) and southeastern Oklahoma Woodford.

 

The sale of 1.0 Bcfe in marginal properties located in southwestern Oklahoma.

 

Production of 11.1 Bcfe.

(19)


 

The following details the changes in proved undeveloped reserves for 2017 (Mcfe):

 

Beginning proved undeveloped reserves

 

 

42,634,659

 

Proved undeveloped reserves transferred to proved developed

 

 

(15,670,848

)

Revisions

 

 

819,338

 

Extensions and discoveries

 

 

29,097,406

 

Purchases

 

 

-

 

Ending proved undeveloped reserves

 

 

56,880,555

 

 

 

Beginning PUD reserves were 42.6 Bcfe. A total of 15.7 Bcfe (37% of the beginning balance) was transferred to proved developed producing during 2017. The 0.8 Bcfe (2% of the beginning balance) of positive revisions to PUD reserves were pricing revisions of 0.6 Bcfe and performance revision of 0.2 Bcfe. No PUD locations from 2013 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 five years from the date they were added to PUD reserves, will be removed as revisions at the time that determination is made. In the event that there are undrilled PUD locations at the end of the five-year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions. The Company added 29.1 Bcfe of PUD reserves in 2017 within the Company’s active drilling program areas of the Anadarko Woodford Shale (Cana, STACK, SCOOP) and southeastern Oklahoma Woodford Shale.

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, estimated reserve quantities and future net cash flows will change over time 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

(20)


 

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 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.

(21)


 

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, 2017, 2016 and 2015 (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, 2017, 2016 and 2015. 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.

(22)


 

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, 2017, 2016 and 2015, were as follows: $46.31/Bbl, $17.55/Bbl, $2.81/Mcf; $36.77/Bbl, $12.22/Bbl, $1.97/Mcf; $55.27/Bbl, $19.10/Bbl, $2.84/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.

 

Estimated Future Net Cash Flows

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9/30/2017

 

 

9/30/2016

 

 

9/30/2015

 

Proved Developed

 

$

206,878,778

 

 

$

98,380,962

 

 

$

233,189,810

 

Proved Undeveloped

 

 

81,303,463

 

 

 

26,502,846

 

 

 

116,314,237

 

Income Tax Expense

 

 

(102,193,819

)

 

 

(38,674,100

)

 

 

(123,007,909

)

Total Proved

 

$

185,988,422

 

 

$

86,209,708

 

 

$

226,496,138

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10% Discounted Present Value of Estimated Future Net Cash Flows

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9/30/2017

 

 

9/30/2016

 

 

9/30/2015

 

Proved Developed

 

$

112,276,166

 

 

$

55,586,606

 

 

$

126,295,752

 

Proved Undeveloped

 

 

13,746,585

 

 

 

(7,696,741

)

 

 

17,948,482

 

Income Tax Expense

 

 

(45,190,176

)

 

 

(18,119,746

)

 

 

(62,653,023

)

Total Proved

 

$

80,832,575

 

 

$

29,770,119

 

 

$

81,591,211

 

 

(23)


 

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

 

 

 

9/30/2017

 

 

9/30/2016

 

 

9/30/2015

 

Bbls - Oil

 

 

310,677

 

 

 

364,252

 

 

 

453,125

 

Bbls - NGL

 

 

173,858

 

 

 

171,060

 

 

 

210,960

 

Mcf - Natural Gas

 

 

8,194,529

 

 

 

8,284,377

 

 

 

9,745,223

 

Mcfe

 

 

11,101,739

 

 

 

11,496,249

 

 

 

13,729,733

 

 

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

 

9/30/2017

 

 

9/30/2016

 

 

9/30/2015

 

Per Bbl, Oil

 

$

46.27

 

 

$

36.70

 

 

$

53.12

 

Per Bbl, NGL

 

$

19.87

 

 

$

12.60

 

 

$

18.25

 

Per Mcf, Natural Gas

 

$

2.70

 

 

$

1.92

 

 

$

2.73

 

Per Mcfe

 

$

3.60

 

 

$

2.73

 

 

$

3.97

 

 

 

 

Year Ended

 

 

Year Ended

 

 

Year Ended

 

Average Production (lifting) Costs

 

9/30/2017

 

 

9/30/2016

 

 

9/30/2015

 

(Per Mcfe)

 

 

 

 

 

 

 

 

 

 

 

 

Well Operating Costs (1)

 

$

1.14

 

 

$

1.18

 

 

$

1.27

 

Production Taxes (2)

 

 

0.14

 

 

 

0.09

 

 

 

0.12

 

 

 

$

1.28

 

 

$

1.27

 

 

$

1.39

 

 

(1)

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

(2)

Includes production taxes only.

In fiscal 2017, approximately 25% 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.

(24)


 

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, 2017. 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

 

 

337

 

 

 

26.87

 

 

 

1,142

 

 

 

1,479

 

Natural Gas

 

 

1,717

 

 

 

78.62

 

 

 

2,899

 

 

 

4,616

 

Total

 

 

2,054

 

 

 

105.49

 

 

 

4,041

 

 

 

6,095

 

 

Panhandle’s average interest in royalty interest only wells is 0.80%. Panhandle’s average interest in working interest wells is 5.14% working interest and 4.91% 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, 2017, Panhandle owned 431,395 gross developed mineral acres and 56,864 net developed mineral acres. Panhandle has also leased from others 145,828 gross developed acres containing 19,263 net developed acres.

UNDEVELOPED ACREAGE

As of September 30, 2017, Panhandle owned 1,261,038 gross and 198,176 net undeveloped mineral acres, and leases on 640 gross and 88 net undeveloped acres.

(25)


 

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.

 

 

 

Net Productive

 

 

Net Productive

 

 

Net Dry

 

 

 

Working Interest

Wells

 

 

Royalty Interest

Wells

 

 

Working Interest

Wells

 

Development Wells

 

 

 

 

 

 

 

 

 

 

 

 

Fiscal years ended:

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2017

 

 

3.893043

 

 

 

0.456612

 

 

 

-

 

September 30, 2016

 

 

0.541405

 

 

 

0.475375

 

 

 

-

 

September 30, 2015

 

 

5.349843

 

 

 

1.372020

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory Wells

 

 

 

 

 

 

 

 

 

 

 

 

Fiscal years ended:

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2017

 

 

0.001563

 

 

 

-

 

 

 

-

 

September 30, 2016

 

 

0.002732

 

 

 

0.003186

 

 

 

-

 

September 30, 2015

 

 

0.188489

 

 

 

0.060184

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Wells

 

 

 

 

 

 

 

 

 

 

 

 

Fiscal years ended:

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2017

 

 

-

 

 

 

-

 

 

 

-

 

September 30, 2016

 

 

-

 

 

 

-

 

 

 

-

 

September 30, 2015

 

 

-

 

 

 

-

 

 

 

-

 

 

PRESENT ACTIVITIES

The following table sets forth the gross and net oil and natural gas wells drilling or testing as of September 30, 2017, in which Panhandle owns either a working interest, a royalty interest or both. These wells were not producing at September 30, 2017.

 

 

 

Gross Working Interest Wells

 

 

Net Working Interest Wells

 

 

Gross Royalty Only Wells

 

 

Total Gross Wells

 

Oil

 

 

6

 

 

 

0.36

 

 

 

34

 

 

 

40

 

Natural Gas

 

 

10

 

 

 

0.06

 

 

 

13

 

 

 

23

 

 

OTHER FACILITIES

The Company has a lease on 12,369 square feet of office space in Oklahoma City, Oklahoma, which ends April 30, 2020.

(26)


 

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; 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 2018 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 supply and 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.

(27)


 

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.

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.

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.

(28)


 

ITEM 3

LEGAL PROCEEDINGS

There were no material legal proceedings involving Panhandle on September 30, 2017, or at the date of this report.

ITEM 4

MINE SAFETY DISCLOSURES

Not applicable.

 

 

(29)


 

PART II

ITEM 5

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


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, 2012, and its relative performance is tracked through September 30, 2017.

(30)


 

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:

 

Quarter Ended

 

High

 

 

Low

 

December 31, 2015

 

$

20.20

 

 

$

13.18

 

March 31, 2016

 

$

18.89

 

 

$

10.82

 

June 30, 2016

 

$

19.47

 

 

$

15.34

 

September 30, 2016

 

$

19.30

 

 

$

15.45

 

December 31, 2016

 

$

27.70

 

 

$

17.10

 

March 31, 2017

 

$

24.05

 

 

$

17.55

 

June 30, 2017

 

$