10-K

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, 2018

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 Website, 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 $19.30 per share closing price of registrant's Class A Common Stock, as reported by the New York Stock Exchange at March 31, 2018, was $303,874,080. As of December 1, 2018, 16,751,414 shares of Class A Common Stock were outstanding. As of December 1, 2018, 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 5, 2019. 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	19
Item 2	Properties	19
Item 3	Legal Proceedings	32
Item 4	Mine Safety Disclosures	32
PART II
Item 5	Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	33
Item 6	Selected Financial Data	36
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	52
Item 8	Financial Statements and Supplementary Data	54
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	95
Item 9A	Controls and Procedures	95
Item 9B	Other Information	95
PART III
Item 10-14	Incorporated by Reference to Proxy Statement	96
PART IV
Item 15	Exhibits, Financial Statement Schedules and Reports on Form 8-K	97

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.

CFTC – the United States Commodity Futures Trading Commission.

Company – Panhandle Oil and Gas Inc.

Common Stock – the Company’s Class A Common Stock.

completion – the post-drilling processes of preparing a well 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 an 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 interests owned in gross acres or gross wells.

NGL – natural gas liquids.

NYMEX – the New York Mercantile Exchange.

NYSE – the New York Stock 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 hydrocarbonwater boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands, and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.

undeveloped acreage – 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 2018 mean the fiscal year ended September 30, 2018.

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’s Class A Common Stock trades on the NYSE under the symbol PHX.

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 a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding the Company that have been filed electronically with the SEC, 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 operating 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 and leasehold acres. 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 Company’s control, 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 and protect the return on investments. 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 beyond its control affect Panhandle’s competitive position and the market for its products. Some of these factors include: the quantity

(2)

and price of foreign oil imports; domestic supply and deliverability 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 of 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 and determined 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 numerous different purchasers. During 2018, sales through three separate well operators accounted for approximately 24%, 16% and 11% of the Company’s total oil, NGL and natural gas sales. 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. Generally, if one purchaser declines to continue purchasing the Company’s production, several other purchasers can be located. Pricing is generally consistent from one purchaser to another.

(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. The 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 and central 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

(4)

coverage at levels which are customary in the industry, but is not fully insured against all environmental risks.

EMPLOYEES

At September 30, 2018, Panhandle employed 20 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 beyond our control, including:

• domestic and worldwide economic conditions

• economic, political, regulatory and tax developments

• market uncertainty

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

(5)

• availability and capacity of necessary transportation and processing facilities

• commodity futures trading

• regional price differentials

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

• differing quality and NGL content of natural gas produced

• weather conditions

• conservation and environmental protection efforts

• 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, product prices affect the credit available under its credit facility.

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

The volatility of the energy markets makes it extremely difficult to predict future oil, NGL and natural gas price movements with any certainty. Oil, NGL and natural gas prices continued to fluctuate in fiscal year 2018 and have fluctuated significantly over the last two months. 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 were low for an extended period of time. The ways in which low prices could have a material negative effect include:

(6)

• significantly decrease the number of wells operators drill 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

• 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.

(7)

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 currently, and may in the future, 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. In addition, this type of derivative contract can limit the benefit we would receive from increases in the prices for oil and natural gas. The fair value of our oil and natural gas derivative instruments outstanding as of September 30, 2018, was a net liability of $3,414,016.

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 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 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.

(8)

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 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, stockholders’ 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 mustmake 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

(9)

• 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. Production and income tax expenses are deducted from this calculation of future estimated development, 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 records. 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.”

Since 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.

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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 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 the eventual 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

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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

• 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 might have a material adverse effect on the Company’s business condition and financial results.

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We may incur losses as a result of title defects in the properties we own.

Consistent with industry practice, we do not have current abstracts or title opinions on all of our mineral acreage and, therefore, cannot be certain that we have unencumbered title to all of these properties. Our failure to cure any title defects that may exist may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we may suffer a financial loss.

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, 2018, the Company had a balance of $51,000,000 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

• 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

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our credit facility could result in a default, which might 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 shareholders to sell shares of our common stock at prices they deem acceptable.

We are currently authorized to issue an aggregate of 24,000,000 shares of common stock of which 16,751,414 shares were issued and outstanding on December 1, 2018. 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.

Federal Income Taxation

We are subject to U.S. federal income tax, as well as income or capital-based taxes in various states, and our operating cash flow is sensitive to the amount of income taxes we must pay. Income taxes are assessed on our revenue after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow.

Congress passed legislation in December 2017, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Reform Legislation”), that significantly affects U.S. tax law. The Tax Reform Legislation contains a number of changes to the manner in which the

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U.S. imposes income tax on multinational corporations. Although some changes should be positive, such as a permanent reduction to the corporate income tax rate, the repeal of the corporate alternative minimum tax, a temporary increase in the amount of bonus depreciation available for qualified property placed into service between September 27, 2017, and December 31, 2022, and other changes may negatively affect the Company. These provisions include, for example, significant additional limitations on the deductibility of interest expense and net operating losses and the repeal of the domestic production activity deduction. In addition, compliance with the Tax Reform Legislation and ensuing regulations will require complex computations and accumulation of information not previously required or regularly produced.

Further revisions to U.S. tax law, such as a reversal of the corporate income tax rate reduction, the repeal of the percentage depletion allowance, the repeal of expensing for intangible drilling costs or the repeal of enhanced bonus depreciation, could have a materially adverse effect on our business. Moreover, the U.S. Department of Treasury has broad authority to issue regulations and interpretative guidance that may significantly impact how we apply U.S. tax law, with a corresponding impact on the results of our operations for the periods affected.

Oklahoma Taxation

Oklahoma imposes a gross production tax, or severance tax, on the value of oil, NGL and natural gas produced within the state. Under recent changes to Oklahoma law, the gross production tax rate on the first three years of a horizontal well’s production has been increased from 2.2% to 5.2%, effective July 1, 2018. This increase in tax will likely decrease the profitability of newer horizontal wells producing oil, NGL and natural gas in Oklahoma, including wells in which the Company owns an interest.

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.

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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 extentof 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 statewide hydraulic fracturing moratoriums and temporary or permanent bans in certain environmentally sensitive areas. Public sentiment against 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 byproduct 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.

Legislation to regulate greenhouse gas emissions has periodically been introduced in the U.S. Congress and such legislation may be proposed in the future. In addition, 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 greenhousegas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. However, on June 1, 2017, the President of the United States announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations to either reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is

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uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

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

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.

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

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number of properties and prospects than our financial or human resources permit, potentially reducing our ability to participate in drilling on certain of our acreage as a working interest owner. Our ability to develop and exploit our oil and natural gas properties and to acquire additional quality properties in the future will depend upon our ability to successfully evaluate, select and acquire suitable properties and join in drilling with reputable operators in this highly competitive environment.

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

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

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

• amount of proved reserves

• volume of oil, NGL and natural gas produced

• received prices for oil, NGL and natural gas sold

• ability to acquire and produce new reserves

• ability to obtain financing

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

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We may reduce or suspend our dividend in the future.

We have paid a quarterly dividend for many years. Our most recent quarterly dividend was $0.04 per share and we have paid the same quarterly dividend for the past two years. In the future, our Board may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position the Company for long‑term success. The declaration and amount of future dividends is at the discretion of our Board and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness. In addition, our ability to pay dividends may be limited by agreements governing our indebtedness now or in the future. Although we do not currently have plans to reduce or suspend our dividend, there can be no assurance that we will not reduce our dividend or that we will continue to pay a dividend in the future.

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

The oil and natural gas industry in general has become increasingly dependent upon digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We use digital technology to estimate quantities of oil, NGL and natural gas reserves, process and record financial data and communicate with our employees and third parties. 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. For instance, unauthorized access to our reserves information or other proprietary or commercially sensitive information could lead to data corruption, communication interruption or other disruptions in our operations or planned business transactions, any of which could have a material adverse impact on our results of operations. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

ITEM 1B UNRESOLVED STAFF COMMENTS

None

ITEM 2 PROPERTIES

At September 30, 2018, Panhandle’s principal properties consisted of (1) perpetual ownership of 258,555 net mineral acres, held principally in Arkansas, New Mexico, North Dakota, Oklahoma, Texas and several other states; (2) leases on 17,203 net acres primarily in Oklahoma; and (3) working interests, royalty interests, or both, in 6,079 producing oil and natural gas wells and 69 wells in the process of being drilled or completed.

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Consistent with industry practice, the Company does not have current abstracts or title opinions on all of its mineral 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 ten states.

ACREAGE

Mineral Interests Owned

The following table of mineral acreage owned reflects, in each respective state, the number of net and gross acres, net and gross producing acres, net and gross acres leased, and net and gross acres open (unleased) as of September 30, 2018.

State	NetAcres		Gross Acres		Net Acres Producing (1)		Gross Acres Producing (1)		Net Acres Leased to Others (2)		Gross Acres Leasedto Others (2)		Net Acres Open (3)		Gross Acres Open (3)
Arkansas		11,963		51,641		7,166		27,026		-		-		4,797		24,615
Colorado		8,217		39,080		-		-		8		80		8,209		39,000
Florida		3,832		8,212		-		-		-		-		3,832		8,212
Kansas		3,102		11,856		164		1,240		-		-		2,938		10,616
Montana		1,008		17,947		-		-		-		-		1,008		17,947
New Mexico		57,374		174,300		1,461		7,449		215		442		55,698		166,409
North Dakota		13,909		76,044		2,379		12,431		-		-		11,530		63,613
Oklahoma		114,089		958,345		43,020		342,568		7,723		50,965		63,346		564,812
South Dakota		1,825		9,300		-		-		-		-		1,825		9,300
Texas		43,045		362,291		5,841		59,041		5,575		42,225		31,629		261,025
Other		192		3,262		165		3,000		-		-		27		262
Total:		258,556		1,712,278		60,196		452,755		13,521		93,712		184,839		1,165,811

(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.

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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, 2018.

			Net Acres Expiring
State	Net Acres		2019		2020		2021		2022		2023		Net Acres Held by Production
Arkansas		2,159		-		-		-		-		-		2,159
Oklahoma		11,609		-		-		-		-		-		11,609
Texas		2,352		-		-		-		-		-		2,352
Other		1,083		-		-		-		-		-		1,083
TOTAL		17,203		-		-		-		-		-		17,203

PROVED RESERVES

The following table summarizes estimates of proved reserves of oil, NGL and natural gas held by Panhandle as of September 30, 2018, 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 6,079 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 ofOil		Barrels of NGL		Mcf of Natural Gas		Mcfe
Net Proved Developed Reserves
September 30, 2018		2,334,587		2,085,706		83,151,954		109,673,712
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
Net Proved Undeveloped Reserves
September 30, 2018		3,649,835		848,484		36,910,082		63,899,996
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
Net Total Proved Reserves
September 30, 2018		5,984,422		2,934,190		120,062,036		173,573,708
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

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The 5.0 Bcfe increase in total proved reserves from 2017 to 2018 is a combination of the following factors:

• Negative pricing revisions of 2.4 Bcfe, primarily resulting from gas wells currently projected to reach their projected economic limits earlier than projected in 2017 due to lower natural gas prices in 2018 relative to 2017; proved developed revisions of 1.7 Bcfe and PUD revisions of 0.7 Bcfe.

• Negative performance revisions of 4.2 Bcfe. Proved developed revisions were positive 7.6 Bcfe, principally due to better well performance from high-interest wells drilled in 2017 in the Anadarko Basin Woodford and southeastern Oklahoma Woodford. Proved undeveloped negative revisions of 11.8 Bcfe are a result of a delayed Eagle Ford drilling program in 2018 which resulted in removal of wells that are no longer projected to be developed within 5 years from the date they were added due to unanticipated drilling delays. However, the Eagle Ford drilling program is now underway.

• Proved developed reserve extensions, discoveries and other additions of 3.7 Bcfe principally resulting from:

a) The Company’s working and royalty interest ownership in ongoing development of unconventional oil, NGL and natural gas utilizing extended horizontal drilling in the Woodford Shale in the Anadarko Basin and southeastern Oklahoma.

b) The Company’s working and royalty interest ownership in ongoing development of unconventional oil, NGL and natural gas utilizing horizontal drilling in the STACK Meramec play in the Anadarko Basin in western Oklahoma.

c) The Company’s royalty interest ownership in ongoing development of conventional and unconventional oil, NGL and natural gas utilizing horizontal drilling in the Permian Basin of New Mexico and Texas.

• The addition of 20.4 Bcfe of PUD reserves primarily within the Company’s active drilling program areas of 1) the Anadarko Basin Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma and 3) the current drilling program of the Eagle Ford Shale in Texas.

• The acquisition of 2.6 Bcfe, predominately in the active drilling program of the Bakken in North Dakota; 1.4 Bcfe proved developed and 1.2 Bcfe proved undeveloped.

• The sale of 2.8 Bcfe in marginal properties located in northwestern Oklahoma and Kearny County, Kansas.

• Production of 12.3 Bcfe.

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The following details the changes in proved undeveloped reserves for 2018 (Mcfe):

Beginning proved undeveloped reserves	56,880,555
Proved undeveloped reserves transferred to proved developed	(2,158,716	)
Revisions	(12,456,931	)
Extensions and discoveries	20,413,545
Purchases	1,221,543
Ending proved undeveloped reserves	63,899,996

Beginning PUD reserves were 56.9 Bcfe. A total of 2.2 Bcfe (4% of the beginning balance) was transferred to proved developed during 2018. In the last two years, 41% of the beginning PUD reserves were transferred to proved developed. The 12.5 Bcfe (22% of the beginning balance) of negative revisions to PUD reserves were pricing revisions of 0.7 Bcfe and performance revision of 11.8 Bcfe, predominately resulting from the removal of oil, NGL and natural gas reserves associated with Eagle Ford wells that are no longer projected to be developed within 5 years from the date they were added due to a delayed drilling program in 2018. We anticipate that all the Company’s current 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 20.4 Bcfe of PUD reserves in 2018 primarily within the Company’s active drilling program areas of 1) the Anadarko Basin Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma and 3) the current drilling program of the Eagle Ford Shale in Texas. These additions result from continuing development and additional well performance data in each of the referenced plays. Of the 2018 PUD adds, 1.2 Bcfe was drilling or completing at year-end.

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.

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

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

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

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acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2018, 2017 and 2016 (see Exhibits 23.2 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, 2018, 2017 and 2016. Since the determination and valuation of proved reserves is a function of testing and estimation, the reserves presented should be expected to change as future information becomes available.

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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, 2018, 2017 and 2016, were as follows: $62.86/Bbl, $26.13/Bbl, $2.56/Mcf; $46.31/Bbl, $17.55/Bbl, $2.81/Mcf; $36.77/Bbl, $12.22/Bbl, $1.97/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
	9/30/2018			9/30/2017			9/30/2016
Proved Developed	$	236,887,976		$	206,878,778		$	98,380,962
Proved Undeveloped		174,078,883			81,303,463			26,502,846
Income Tax Expense		(95,872,182	)		(102,193,819	)		(38,674,100	)
Total Proved	$	315,094,677		$	185,988,422		$	86,209,708
10% Discounted Present Value of Estimated Future Net Cash Flows
	9/30/2018			9/30/2017			9/30/2016
Proved Developed	$	125,915,804		$	112,276,166		$	55,586,606
Proved Undeveloped		78,657,354			13,746,585			(7,696,741	)
Income Tax Expense		(48,247,304	)		(45,190,176	)		(18,119,746	)
Total Proved	$	156,325,854		$	80,832,575		$	29,770,119

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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
	9/30/2018		9/30/2017		9/30/2016
Bbls - Oil		336,565		310,677		364,252
Bbls - NGL		255,176		173,858		171,060
Mcf - Natural Gas		8,721,262		8,194,529		8,284,377
Mcfe		12,271,708		11,101,739		11,496,249

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	9/30/2018		9/30/2017		9/30/2016
Per Bbl, Oil	$	61.75	$	46.27	$	36.70
Per Bbl, NGL	$	23.14	$	19.87	$	12.60
Per Mcf, Natural Gas	$	2.49	$	2.70	$	1.92
Per Mcfe	$	3.94	$	3.60	$	2.73

	Year Ended		Year Ended		Year Ended
Average Production (lifting) Costs	9/30/2018		9/30/2017		9/30/2016
(Per Mcfe)
Well Operating Costs (1)	$	1.10	$	1.14	$	1.18
Production Taxes (2)		0.17		0.14		0.09
	$	1.27	$	1.28	$	1.27

(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 2018, approximately 28% 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 field operating costs on those producing wells, but they do bear a share of the handling fees (primarily gathering and transportation).

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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, 2018. Panhandle owns either working interests, royalty interests or both in these wells. The Company does not operate any wells.

	Gross Working InterestWells		Net Working Interest Wells		Gross Royalty Only Wells		Total Gross Wells
Oil		280		22.45		1,338		1,618
Natural Gas		1,484		56.72		2,977		4,461
Total		1,764		79.17		4,315		6,079

Panhandle’s average interest in royalty interest only wells is 0.81%. Panhandle’s average interest in working interest wells is 4.49% working interest and 4.37% 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, 2018, Panhandle owned 452,755 gross developed mineral acres and 60,196 net developed mineral acres. Panhandle has also leased from others 186,115 gross developed acres containing 17,203 net developed acres.

UNDEVELOPED ACREAGE

As of September 30, 2018, Panhandle owned 1,259,523 gross and 198,360 net undeveloped mineral acres, and no leases on undeveloped acres (all leases are held by production).

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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.

	NetProductive		Net Productive		Net Dry
	Working Interest Wells		Royalty Interest Wells		Working Interest Wells
Development Wells
Fiscal years ended:
September 30, 2018		0.482972		0.994656		-
September 30, 2017		3.893043		0.456612		-
September 30, 2016		0.541405		0.475375		-
Exploratory Wells
Fiscal years ended:
September 30, 2018		-		-		-
September 30, 2017		0.001563		-		-
September 30, 2016		0.002732		0.003186		-
Purchased Wells
Fiscal years ended:
September 30, 2018		-		1.566828		-
September 30, 2017		-		-		-
September 30, 2016		-		-		-

PRESENT ACTIVITIES

The following table sets forth the gross and net oil and natural gas wells drilling or testing as of September 30, 2018, in which Panhandle owns either a working interest, a royalty interest or both. These wells were not producing at September 30, 2018.

	GrossWorking Interest Wells		Net Working Interest Wells		Gross Royalty Only Wells		Total Gross Wells
Oil		15		0.74		41		56
Natural Gas		-		-		13		13

OTHER FACILITIES

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

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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 2019 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.

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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.

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ITEM 3 LEGAL PROCEEDINGS

There were no material legal proceedings involving Panhandle on September 30, 2018, or at the date of this report.

ITEM 4 MINE SAFETY DISCLOSURES

Not applicable.

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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 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 Class A Common Stock and in each of the indexes on September 30, 2013, and its relative performance is tracked through September 30, 2018.

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Since July 2008, the Company’s Class A Common Stockhas 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 Class A Common Stock during the periods indicated:

Quarter Ended	High		Low
December 31, 2016	$	27.70	$	17.10
March 31, 2017	$	24.05	$	17.55
June 30, 2017	$	24.06	$	18.15
September 30, 2017	$	25.30	$	19.20
December 31, 2017	$	25.15	$	19.95
March 31, 2018	$	23.10	$	17.65
June 30, 2018	$	22.25	$	17.75
September 30, 2018	$	21.33	$	17.85

At December 1, 2018, there were 1,270 holders of record of Panhandle’s Class A Common Stock and approximately 5,000 beneficial owners.

During the past two years, the Company has paid quarterly dividends of $0.04 per share on its Class A Common Stock. Approval by the Company’s Board is required before the declaration and payment of any dividends.

While the Company anticipates it will continue to pay dividends on its Class A Common Stock, the payment and amount of future cash dividends will depend upon, among other things, financial condition, funds from operations, the level of capital and development expenditures, future business prospects, contractual restrictions and any other factors considered relevant by the Board. The loan agreement sets limits on dividend payments and stock repurchases if those payments would cause the leverage ratio to go above 2.75 to 1.0.

Purchases of Equity Securities by the Company

The following table presents information about repurchases of our common stock during the quarter ended September 30, 2018:

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program
7/1 - 7/31/18		-	$	-		-	$	128,256
8/1 - 8/31/18		26,324	$	18.99		26,324	$	1,128,420
9/1 - 9/30/18		23,676	$	18.89		23,676	$	681,128
Total		50,000	$	18.94		50,000

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Following approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in May 2018, the Board approved the Company’s repurchase program which, as amended, authorizes management to repurchase up to $1.5 million of the Company’s Class A Common Stock at their discretion. The repurchase program has an evergreen provision which authorizes the repurchase of an additional $1.5 million of the Company’s Class A Common Stock when the previous amount is utilized. As part of the amendment, the number of shares allowed to be purchased by the Company under the repurchase program is no longer capped at an amount equal to the aggregate number of shares of Class A Common Stock (i) awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

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ITEM 6 SELECTED FINANCIAL DATA

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

	As of and for the year ended September 30,
	2018			2017			2016			2015			2014
Revenues
Oil, NGL and natural gas sales	$	48,385,335		$	39,935,912		$	31,411,353		$	54,533,914		$	82,846,528
Lease bonuses and rentals		1,580,997			5,149,297			7,735,785			2,010,395			423,328
Gains (losses) on derivative contracts		(4,932,068	)		1,249,840			(86,355	)		13,822,506			247,414
		45,034,264			46,335,049			39,060,783			70,366,815			83,517,270
Costs and expenses
Lease operating expense		13,460,278			12,682,969			13,590,089			17,472,408			13,912,792
Production taxes		2,089,050			1,548,399			1,071,632			1,702,302			2,694,118
Depreciation, depletion and amortization		18,395,040			18,397,548			24,487,565			23,821,139			21,896,902
Provision for impairment		-			662,990			12,001,271			5,009,191			1,096,076
Loss (gain) on asset sales & other		102,685			105,830			(2,576,237	)		(685,369	)		(799,559	)
Interest expense		1,748,101			1,275,138			1,344,619			1,550,483			462,296
General and administrative		7,342,441			7,441,242			7,139,728			7,339,320			7,433,183
		43,137,595			42,114,116			57,058,667			56,209,474			46,695,808
Income (loss) before provision (benefit) for    income taxes		1,896,669			4,220,933			(17,997,884	)		14,157,341			36,821,462
Provision (benefit) for income taxes		(12,739,000	)		689,000			(7,711,000	)		4,836,000			11,820,000
Net income (loss)	$	14,635,669		$	3,531,933		$	(10,286,884	)	$	9,321,341		$	25,001,462
Basic and diluted earnings (loss) per share	$	0.86		$	0.21		$	(0.61	)	$	0.56		$	1.49
Dividends declared per share	$	0.16		$	0.16		$	0.16		$	0.16		$	0.16
Weighted average shares outstanding
Basic and diluted		16,952,664			16,900,185			16,840,856			16,768,904			16,727,183
Net cash provided by (used in):
Operating activities	$	26,943,894		$	20,758,192		$	22,639,151		$	47,624,914		$	53,099,746
Investing activities	$	(21,829,015	)	$	(25,107,760	)	$	565,617		$	(31,642,385	)	$	(122,428,139	)
Financing activities	$	(5,140,168	)	$	4,436,146		$	(23,337,470	)	$	(15,888,369	)	$	66,970,977
Total assets	$	206,749,686		$	206,744,219		$	197,824,326		$	238,825,273		$	246,640,604
Long-term debt	$	51,000,000		$	52,222,000		$	44,500,000		$	65,000,000		$	78,000,000
Stockholders' equity	$	128,765,205		$	116,707,539		$	115,191,819		$	127,004,675		$	119,188,653

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

BUSINESS OVERVIEW

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

Fiscal 2018 oil, NGL and natural gas production increased 8%, 47% and 6%, respectively, from that of 2017. The 2018 higher oil and NGL prices (see below) and the overall production changes noted above, partially offset by lower natural gas prices (see below), resulted in a 21% increase in revenues from the sale of oil, NGL and natural gas. Based on recent forward strip pricing, the Company currently anticipates 2019 average oil, NGL and natural gas prices could be slightly higher than their corresponding average prices in 2018.

The Company’s proved oil, NGL and natural gas reserves increased in 2018, compared to 2017, by 5.0 Bcfe, or 3%. The increase was primarily due to purchases, additions and extensions partially offset by revisions and sales.

As of September 30, 2018, the Company owned an average 1.2% net revenue interest in 69 wells that were drilling or testing.

Other than the lease of office space, the Company had no off balance sheet arrangements during 2018 or prior years.

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

	For the Year Ended September 30,
		Percent		Percent
	2018	Incr.or(Decr.)	2017	Incr.or(Decr.)	2016
Production:
Oil (Bbls)	336,565	8%	310,677	(15%)	364,252
NGL (Bbls)	255,176	47%	173,858	2%	171,060
Natural Gas (Mcf)	8,721,262	6%	8,194,529	(1%)	8,284,377
Mcfe	12,271,708	11%	11,101,739	(3%)	11,496,249
Average Sales Price:
Oil (per Bbl)	$61.75	33%	$46.27	26%	$36.70
NGL (per Bbl)	$23.14	16%	$19.87	58%	$12.60
Natural Gas (per Mcf)	$2.49	(8%)	$2.70	41%	$1.92
Mcfe	$3.94	9%	$3.60	32%	$2.73

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RESULTS OF OPERATIONS

Fiscal Year 2018 Compared to Fiscal Year 2017

Overview

The Company recorded net income of $14,635,669, or $0.86 per share, in 2018, compared to net income of $3,531,933, or $0.21 per share, in 2017. Revenues decreased in 2018 primarily due to decreased lease bonuses received and losses on derivative contracts, largely offset by higher oil, NGL and natural gas sales.

Expenses increased in 2018 mainly from increases in LOE, production taxes and interest expenses partially offset by a lower provision for impairment.

Oil, NGL and Natural Gas Sales

Oil, NGL and natural gas sales increased $8,449,423, or 21%, for 2018, as compared to 2017. The increase was due to increased oil and NGL prices of 33% and 16%, respectively, combined with higher oil, NGL and natural gas volumes of 8%, 47% and 6%, respectively, partially offset with decreased natural gas prices of 8% in 2018.

In the first quarter of 2018, we continued to see the results of the 2017 drilling program after four Eagle Ford wells were completed with first sales in November 2017. In the second quarter we experienced the relatively steep early decline rates from new high working interest wells placed on production in the second half of 2017 and early 2018, as wells stopped flowing efficiently due to loading. Volumes then leveled off with the installation of lift equipment on the new wells as they transitioned from flowing efficiently up the production casing to requiring downhole equipment modifications to resume efficient flow. Continued normal declines were then offset by first sales from drilling activity in the Anadarko Basin (STACK/Cana/SCOOP), southeastern Oklahoma and the Permian Basin.

The increase in oil production was primarily the result of new well drilling in the Eagle Ford Shale, Anadarko Basin (STACK/Cana/SCOOP), and Permian Basin which was partially offset by declining production from the Bakken and various fields in western and northern Oklahoma and marginal/uneconomic property sales in northwestern Oklahoma.

An overall increase in NGL production was the result of six new wells in the Anadarko Woodford Shale and new well drilling in Anadarko Basin STACK, which was partially offset by the natural production decline of existing wells in various fields in western Oklahoma.

Natural gas production volume increases were primarily the result of 2017 and 2018 drilling in western Oklahoma (STACK/Cana/SCOOP) and southeastern Oklahoma. The increase was partially offset by naturally declining production in the Fayetteville Shale and to a much lesser extent, declining production from the Anadarko Basin Granite Wash and the marginal/uneconomic property sales in northwestern Oklahoma and Kearny County, Kansas.

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Production by quarter for 2018 and 2017 was as follows (Mcfe):

	2018		2017
First quarter		3,421,812		2,517,414
Second quarter		2,942,274		2,351,207
Third quarter		2,967,340		2,953,915
Fourth quarter		2,940,282		3,279,203
Total		12,271,708		11,101,739

Lease Bonus and Rentals

Lease bonuses and rentals decreased $3,568,300 in 2018. The decrease was mainly due to the Company leasing less valuable acreage in 2018 versus 2017. In 2018, the Company leased 1,754 net mineral acres in Oklahoma (mainly in Major, Ellis, and Roger Mills Counties), 415 net mineral acres in Texas (mainly in Dawson County) and 135 net mineral acres in New Mexico (mainly in Lea and Eddy Counties). In 2017, the Company leased 2,067 net mineral acres in Oklahoma (mainly in Dewey, Canadian, McClain and Grady Counties), 272 net mineral acres in Texas (mainly in Andrews and Dawson Counties) and 125 net mineral acres in New Mexico (mainly in Lea and Eddy Counties).

Gains (Losses) on Derivative Contracts

The fair value of derivative contracts was a net liability of $3,414,016 as of September 30, 2018, and a net asset of $516,159 as of September 30, 2017. We had a net loss on derivative contracts of $4,932,068 in 2018 as compared to a net gain of $1,249,840 in 2017. The change is principally due to the oil collars and fixed price swaps being less beneficial in 2018, as NYMEX oil futures experienced increases in price in relation to the collars and the fixed prices of the swaps. Net cash paid related to derivative contracts settled during 2018 was $1,001,893 compared to net cash received of $305,410 in 2017. As of September 30, 2018, the Company’s natural gas and oil costless collar contracts and fixed price swaps have expiration dates of December 2018 through June 2020. The Company utilizes derivative contracts for the purpose of protecting its return on investments.

Lease Operating Expenses (LOE)

LOE increased $777,309 or 6% in 2018. LOE costs per Mcfe of production decreased from $1.14 in 2017 to $1.10 in 2018. LOE related to field operating costs increased $225,954 or 3% in 2018, compared to 2017. Field operating costs were $0.55 per Mcfe in 2018, compared to $0.58 per Mcfe in 2017. This decrease in rate was principally the result of significant new low-cost production coming on line in late 2017 and the Company selling some high operating cost wells in late 2017 and early 2018.

The increase in LOE related to field operating costs was coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) of $551,355 in 2018, primarily due to increased production in 2018. On a per Mcfe basis, these handling fees were $0.55 in 2018 as compared to $0.56 in 2017. Natural gas sales bear the large majority of the

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handling fees. Handling fees are charged either as a percent of sales or based on production volumes.

Production Taxes

Production taxes increased $540,651 or 35% in 2018, as compared to 2017. The increase in amount was primarily the result of increased oil, NGL and natural gas sales of $8,449,423 during 2018. Production taxes as a percentage of oil, NGL and natural gas sales increased from 3.9% in 2017 to 4.3% in 2018. The increase in tax rate was mainly due to a change in the Oklahoma production tax laws that took effect July 1, 2018. The discounted tax rate was increased from 2.2% to 5.2% for the first three years of production on horizontally drilled wells. There was no change in the ultimate rate of 7.2% after the discounted period expires. The low overall production tax rate in both years was due to a large proportion of the Company’s oil and natural gas revenues coming from horizontally drilled wells, which are eligible for reduced Oklahoma and Arkansas production tax rates in the first few years of production.

Depreciation, Depletion and Amortization (DD&A)

DD&A decreased $2,508 in 2018. DD&A per Mcfe was $1.50 in 2018, compared to $1.66 in 2017. DD&A decreased $1,941,354 as the result of a $0.16 decrease in the DD&A rate per Mcfe. This was mostly offset by an increase of $1,938,846 due to oil, NGL and natural gas production volumes increasing 11% collectively in 2018, compared to 2017. The rate decrease was principally due to higher oil and NGL prices utilized in the reserve calculations during 2018, as compared to 2017, lengthening the economic life of wells thus resulting in higher projected remaining reserves on a significant number of wells. The Company had new high-volume wells with low finding costs begin producing in the later part 2017 and early 2018, which also contributed to the rate decrease.

Provision for Impairment

Provision for impairment decreased $662,990 in 2018, as compared to 2017. No impairment was recorded during 2018. During 2017, impairment of $46,279 was recorded on five fields, primarily in Oklahoma and Texas. Another $616,711 of impairment was recorded on a group of wells that were held for sale at September 30, 2017.

Interest Expense

Interest expense increased $472,963 in 2018, as compared to 2017. The increase was due to higher interest rates and a higher outstanding debt balance during 2018.

Provision (Benefit) for Income Taxes

Income taxes changed $13,428,000, from a $689,000 provision in 2017 to a $12,739,000 benefit in 2018. This was mainly the result of the new Tax Cuts and Jobs Act enacted in December 2017 that reduced the U.S. federal corporate tax rate from 35% to 21%. The tax effects of this law change on our existing deferred tax liabilities of $12,464,000 was made in 2018 and is directly affecting the effective tax rate noted for 2018. Additionally, due to the Company having a September 30 year end versus a calendar year end, we have calculated the

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current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The effective tax rate changed from a 16% provision in 2017 to a 672% benefit in 2018.

When a provision for income taxes is expected for the year, federal and Oklahoma excess percentage depletion decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded.

Fiscal Year 2017 Compared to Fiscal Year 2016

Overview

The Company recorded net income of $3,531,933, or $0.21 per share, in 2017, compared to net loss of $10,286,884, or $0.61 per share, in 2016. Revenues increased in 2017 primarily due to higher oil, NGL and natural gas sales and increased gains on derivative contracts partially offset by decreased lease bonuses received.

Expenses decreased in 2017 mainly from a lower provision for impairment, lower DD&A and lower LOE partially offset by increases in G&A and production taxes and a decrease in gain on sale of assets.

Oil, NGL and Natural Gas Sales

Oil, NGL and natural gas sales increased $8,524,559, or 27%, for 2017, as compared to 2016. The increase was due to increased oil, NGL and natural gas prices of 26%, 58% and 41%, respectively, partially offset with lower oil and natural gas volumes of 15% and 1%, respectively, in 2017.

In the first half of 2017, we continued to see the results of expected production decline in oil, NGL and natural gas volumes. The results of our 2017 drilling program are reflected in the third and fourth quarters as first sales of the new wells began to occur.

The decrease in oil production was primarily the result of natural production decline in the Eagle Ford Shale, which was partially offset by 2017 drilling with first sales from two wells in late April and four wells in mid-August. To a lesser extent, declining production from various fields in western Oklahoma, the Texas Panhandle, and Bakken contributed to the decrease.

An overall increase in NGL production is the result of six new wells in the Anadarko Woodford Shale and six wells in the Eagle Ford Shale, which offset the natural production decline of existing wells in the Anadarko Woodford Shale in western and central Oklahoma and the Anadarko Basin Granite Wash in western Oklahoma and the Texas Panhandle.

Natural gas production volume decreases were primarily the result of naturally declining production in the Fayetteville Shale. To a much lesser extent, declining production from the Anadarko Woodford Shale in western and central Oklahoma, the Anadarko Basin Granite Wash and the southeastern Oklahoma Woodford Shale also contributed to the decrease. The decline was offset as a result of new well drilling in southeastern Oklahoma Woodford Shale, with first

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sales from four new wells in early March and four more wells in mid-May. Additional contribution to gas production was established in the Anadarko Woodford Shale from six new wells with first sales in mid-July.

Production by quarter for 2017 and 2016 was as follows (Mcfe):

	2017		2016
First quarter		2,517,414		3,143,400
Second quarter		2,351,207		2,786,303
Third quarter		2,953,915		2,887,821
Fourth quarter		3,279,203		2,678,725
Total		11,101,739		11,496,249

Lease Bonus and Rentals

Lease bonuses and rentals decreased $2,586,488 in 2017. The decrease was mainly due to the Company leasing fewer acres in 2017 versus 2016. In 2017, the Company leased 2,067 net mineral acres in Oklahoma (mainly in Dewey, Canadian, McClain and Grady Counties), 272 net mineral acres in Texas (mainly in Andrews and Dawson Counties) and 125 net mineral acres in New Mexico (mainly in Lea and Eddy Counties). In 2016, the Company leased 4,057 net mineral acres in Cochran County, Texas, 663 net mineral acres in Blaine, Canadian, Custer and Dewey Counties, Oklahoma, and 706 net mineral acres in Grady and McClain Counties, Oklahoma.

Gains (Losses) on Derivative Contracts

The fair value of derivative contracts was a net asset of $516,159 as of September 30, 2017, and a net liability of $428,271 as of September 30, 2016. We had a net gain on derivative contracts of $1,249,840 in 2017 as compared to a net loss of $86,355 in 2016. The change is principally due to the oil and natural gas collars and fixed price swaps being more beneficial in 2017, as NYMEX oil and natural gas futures experienced decreases in price in relation to the collars and the fixed prices of the swaps. As of September 30, 2017, the Company’s natural gas and oil costless collar contracts and fixed price swaps had expiration dates of December 2017 through December 2018.

Lease Operating Expenses (LOE)

LOE decreased $907,120 or 7% in 2017. LOE costs per Mcfe of production decreased from $1.18 in 2016 to $1.14 in 2017. The total LOE decrease was largely due to decreased field operating costs of $1,561,965 in 2017, compared to 2016. Field operating costs were $0.58 per Mcfe in 2017, compared to $0.70 per Mcfe in 2016, a 17% decrease. This decrease in rate was principally the result of significant new low-cost production coming on, decreased operating costs in several fields and the company selling some high operating cost wells in 2017.

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The decrease in LOE related to field operating costs was partially offset with an increase in handling fees (primarily gathering, transportation and marketing costs) of $654,845 in 2017, as compared to 2016. On a per Mcfe basis, these fees increased $0.08 due mainly to a 15% decrease in oil production, versus a 1% decrease in natural gas production. Natural gas sales bear the large majority of the handling fees. Handling fees are charged either as a percent of sales or based on production volumes.

Production Taxes

Production taxes increased $476,767 or 44% in 2017, as compared to 2016. The increase in amount was primarily the result of increased oil, NGL and natural gas sales of $8,524,559 during 2017. Production taxes as a percentage of oil, NGL and natural gas sales increased from 3.4% in 2016 to 3.9% in 2017. The increase in tax rate was the result of the expiration of production tax discounts on some of the Company’s horizontally drilled wells in Oklahoma and Arkansas. The low overall production tax rate in both years was due to a large proportion of the Company’s oil and natural gas revenues coming from horizontally drilled wells, which are eligible for reduced Oklahoma and Arkansas production tax rates in the first few years of production.

Depreciation, Depletion and Amortization (DD&A)

DD&A decreased $6,090,017 in 2017. DD&A per Mcfe was $1.66 in 2017, compared to $2.13 in 2016. DD&A decreased $5,249,692 as the result of a $0.47 decrease in the DD&A rate per Mcfe. This was coupled by a decrease of $840,325 due to oil, NGL and natural gas production volumes decreasing 3% collectively in 2017, compared to 2016. The rate decrease was principally due to higher oil, NGL and natural gas prices utilized in the reserve calculations during 2017, as compared to 2016, lengthening the economic life of wells thus resulting in higher projected remaining reserves on a significant number of wells. The Company had new high-volume wells with low finding costs begin producing in the 2017, which also contributed to the rate decrease.

Provision for Impairment

Provision for impairment decreased $11,338,281 in 2017, as compared to 2016. During 2017, impairment of $46,279 was recorded on five fields, primarily in Oklahoma and Texas. Another $616,711 of impairment was recorded on a group of wells that were held for sale at September 30, 2017. During 2016, impairment of $12,001,271 was recorded on 44 fields, primarily in Oklahoma, Kansas and Texas. Two fields in western Oklahoma and the Texas Panhandle accounted for $7,548,533 or 63% of the impairment due mainly to declining oil, NGL and natural gas prices.

Loss (Gain) on Asset Sales and Other

Loss (gain) on asset sales and other was a net loss of $105,830 in 2017, as compared to a net gain of $2,576,237 in 2016. The net loss in 2017 was mainly due to the Company selling some high operating cost wells at a loss during the year. The net gain in 2016 was largely due to the gain on sale of assets from two of the Company’s partnerships.

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Interest Expense

Interest expense decreased $69,481 in 2017, as compared to 2016. The decrease was due to a lower outstanding debt balance during 2017.

General and Administrative Costs (G&A)

G&A increased $301,514 in 2017, as compared to 2016. This increase was primarily the result of higher legal and technical consulting fees in 2017. The legal fee increase was mainly due to additional work done around the Company filing its first shelf registration. The technical consulting fee increase was due to additional work performed to analyze possible acquisitions.

Provision (Benefit) for Income Taxes

The 2017 provision for income taxes of $689,000 was based on a pre-tax income of $4,220,933, as compared to a benefit for income taxes of $7,711,000 in 2016, based on a pre-tax loss of $17,997,884. The effective tax rate for 2017 and 2016 was a 16% provision and a 43% benefit, respectively. When a provision for income taxes is recorded, federal and Oklahoma excess percentage depletion decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded, as was the case in 2016. The effective tax rate for 2017 was also impacted by excess tax benefits from stock-based compensation recorded to income tax expense (benefit) during 2017.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2018, the Company had positive working capital of $2,509,050, as compared to positive working capital of $6,451,356 at September 30, 2017.

Liquidity

Cash and cash equivalents were $532,502 as of September 30, 2018, compared to $557,791 at September 30, 2017, a decrease of $25,289. Cash flows for the 12 months ended September 30 are summarized as follows:

Net cash provided (used) by:
	2018			2017			Change
Operating activities	$	26,943,894		$	20,758,192		$	6,185,702
Investing activities		(21,829,015	)		(25,107,760	)		3,278,745
Financing activities		(5,140,168	)		4,436,146			(9,576,314	)
Increase (decrease) in cash and cash equivalents	$	(25,289	)	$	86,578		$	(111,867	)

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Operating activities:

Net cash provided by operating activities increased $6,185,702 during 2018, as compared to 2017, mainly the result of the following:

• Receipts of oil, NGL and natural gas sales (net of production taxes and gathering, transportation and marketing costs) and other increased $10,734,247.

• Decreased lease bonus receipts of $3,630,065.

• Decreased income tax payments of $952,854.

• Decreased net receipts on derivative contracts of $1,307,303.

• Increased payments for interest expense of $517,583.

Investing activities:

Net cash used in investing activities decreased $3,278,745 during 2018, as compared to 2017, due to:

• Lower drilling and completion activity during 2018 decreased capital expenditures by $14,217,762.

• Higher acquisition activity increased expenditures by $11,327,371.

• Higher proceeds from sale of assets of $361,437.

Financing activities:

Net cash used by financing activities increased $9,576,314 during 2018, as compared to 2017, the result of the following:

•  Net borrowings decreased $1,222,000 during 2018.  Net borrowings increased $7,722,000 during 2017.

Capital Resources

Capital expenditures to drill and complete wells decreased $14,217,762 (55%) in 2018, as compared to 2017. The Company received 98 well proposals in fiscal 2018, and working interest participation decisions were as follows: 34 wells met the Company’s participation criteria and elections were made to participate, while 64 wells did not meet participation criteria with no participation elected.

Capital expenditures to acquire assets increased $11,327,371 in 2018, as compared to 2017. On August 21, 2018, the Company closed on an acquisition of mineral acreage and producing oil and gas properties primarily located in the Bakken/Three Forks play in North

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Dakota. The effective date of the purchase was June 1, 2018. Activity on the acreage is ongoing with eight of the 20 previously drilled uncompleted Bakken/Three Forks wells (DUCs) now producing. The purchase price (before closing adjustments) was $9 million and was funded utilizing Panhandle’s bank credit facility. The Company also closed on two other mineral acquisitions in the STACK/SCOOP area for approximately $2.3 million.

On November 2, 2018, the Company entered into a Purchase and Sale Agreement to sell certain mineral acreage and producing oil and gas properties, primarily located in the Lea and Eddy Counties in New Mexico, to a private seller for total consideration of $9.3 million cash (pending any closing adjustments). The transaction is expected to close by late November and will have an effective date of November 1, 2018. The cash from the sale will initially be used to reduce the Company’s outstanding bank debt. Like the vast majority of Panhandle’s mineral acreage, these minerals were purchased by Panhandle several years ago for a minimal cost. In this case, the assets have been completely amortized. Therefore, these mineral rights have no current book value, and the total value received will be a gain on the sale of assets in the Company’s first quarter of 2019. The Company is utilizing a like-kind exchange under IRS Code 1031 to defer income tax on almost all of the sale price by offsetting it with the Bakken mineral acreage that was purchased on August 21, 2018, using a qualified exchange accommodation agreement.

Oil, NGL and natural gas production volumes increased 11% on an Mcfe basis during 2018, as compared to 2017. Significant drilling activity during the latter part of 2017, and to a lesser extent during 2018, resulted in new production coming on line that more than offset the natural decline of existing wells.

Oil production increased 8%, primarily the result of new production in the Eagle Ford Shale, Anadarko Basin (STACK/Cana/SCOOP) and Permian Basin which was partially offset by declining production from the Bakken and various fields in western and northern Oklahoma and marginal/uneconomic property sales in northwestern Oklahoma.

NGL production increased 47%, largely the result of new production in the Anadarko Woodford Shale and new production in Anadarko Basin STACK, which was partially offset by the natural production decline of existing wells in various fields in western Oklahoma.

Natural gas production increased 6%, principally the result of 2017 and 2018 drilling in western Oklahoma (STACK/Cana/SCOOP) and southeastern Oklahoma.  The increase was partially offset by naturally declining production in the Fayetteville Shale, and to a much lesser extent, declining production from the Anadarko Basin Granite Wash and the marginal/uneconomic property sales in northwestern Oklahoma and Kearny County, Kansas.

Since the Company is not the operator of any of its oil and natural gas properties, it can be difficult for us to predict levels of future participation in the drilling and completion of new wells and their associated capital expenditures. This makes total 2019 capital expenditures for drilling and completion projects difficult to forecast; however, the operator of our Eagle Ford properties has initiated a one-rig continuous drilling program with anticipated 2019 capital expenditures of approximately $15 million for the Company.

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Net cash provided by our operating activities allowed the Company to fund all of the capital expenditures, asset acquisitions, overhead costs, treasury stock purchases and dividend payments, while decreasing the Company’s outstanding borrowings on the credit facility by $1.2 million during 2018. The Company received lease bonus payments during 2018 totaling approximately $1.6 million. Looking forward, the cash flow from bonus payments associated with the leasing of drilling rights on the Company’s mineral acreage is very difficult to project as the Company’s mineral acreage position is so diverse and spread across several states. However, management will continue to actively pursue leasing and/or selling certain of the Company’s mineral acres.

With continued oil and natural gas price volatility, management continues to evaluate opportunities for product price protection through additional hedging of the Company’s future oil and natural gas production. See Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for a complete list of the Company’s outstanding derivative contracts.

The use of the Company’s cash provided by operating activities and resultant change to cash is summarized in the table below:

	Twelve months ended
	9/30/2018
Cash provided by operating activities	$	26,943,894
Cash used for (provided by):
Capital expenditures - acquisitions		11,327,371
Capital expenditures - drilling and completion of wells		11,590,135
Quarterly dividends of $0.04 per share		2,698,940
Treasury stock purchases		1,219,228
Net payments (borrowings) on credit facility		1,222,000
Proceeds from sales of assets		(1,085,137	)
Other investing activities		(3,354	)
Net cash used		26,969,183
Net increase (decrease) in cash	$	(25,289	)

Outstanding borrowings on the credit facility at September 30, 2018, were $51,000,000.

Looking forward, the Company intends to fund overhead costs, capital additions related to the drilling and completion of wells, treasury stock purchases, if any, and dividend payments primarily from cash provided by operating activities, cash on hand and borrowings utilizing our bank credit facility. Any excess cash is intended to be used to reduce existing bank debt. The Company had availability of $29,000,000 under its revolving credit facility and was in compliance with its debt covenants at September 30, 2018.

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The borrowing base under the credit facility was redetermined in July 2018and left unchangedat $80 million, which is a level that is expected to provide ample liquidity for the Company to continue to employ its normal operating strategies.

On November 6, 2017, the Company filed a shelf registration statement with the SEC on Form S-3. This move gives us the ability to sell up to $75 million in securities, including common stock, preferred stock, debt securities, warrants and units in amounts to be determined at the time of an offering. Any such offering, if it does occur, may happen in one or more transactions. The specific terms of any securities to be sold will be described in supplemental filings with the SEC. The registration statement will expire on November 6, 2020. The Company has no current plans to issue securities under the shelf registration statement.

Based on expected capital expenditure levels, anticipated cash provided by operating activities for 2019, combined with availability under its credit facility, the Company has sufficient liquidity to fund its ongoing operations.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Company has a credit facility with a group of banks headed by Bank of Oklahoma (BOK) consisting of a revolving loan of $200,000,000, which is subject to a semi-annual borrowing base determination. The current borrowing base is $80,000,000 and is secured by certain of the Company’s properties with a carrying value of $135,994,289 at September 30, 2018. The revolving loan matures on November 30, 2022. Borrowings under the revolving loan are due at maturity. The revolving loan bears interest at the BOK prime rate plus a range of 0.50% to 1.25%, or 30 day LIBOR plus a range of 2.00% to 2.75% annually. At September 30, 2018, the effective rate was 4.34%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from LIBOR or the prime rate increases as the ratio of the loan balance to the borrowing base increases.

Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the banks, in their sole discretion, believe there has been a material change in the value of the Company’s oil and natural gas properties. The borrowing base under the credit facility was redetermined in July 2018 by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of treasury stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by the bank agreement – current assets includes availability under outstanding credit facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing 12 months as defined by bank agreement – traditional EBITDA with the unrealized gain or loss on derivative contracts also removed from earnings) of no more than 4.0 to 1.0. At September 30, 2018, the Company was in compliance with the covenants of the loan agreement and had $29,000,000 of availability under its outstanding credit facility.

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The table below summarizes the Company’s contractual obligations and commitments as ofSeptember 30, 2018:

	Payments due by period
Contractual Obligations			Less than						More than
and Commitments	Total		1 Year		1-3 Years		3-5 Years		5 Years
Long-term debt obligations	$	51,000,000	$	-	$	-	$	51,000,000	$	-
Building lease	$	332,932	$	210,273	$	122,659	$	-	$	-

The Company’s building lease is accounted for as an operating lease and therefore the leased asset and associated liabilities of future rent payments are not included on the Company’s balance sheets.

At September 30, 2018, the Company’s derivative contracts were in a net liability position of $3,414,016. The ultimate settlement amounts of the derivative contracts are unknown because they are subject to continuing market risk. Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the derivative contracts.

As of September 30, 2018, the Company’s estimate for asset retirement obligations was $2,809,378. Asset retirement obligations represent the Company’s share of the future expenditures to plug and abandon the wells in which the Company owns a working interest at the end of their economic lives. These amounts were not included in the schedule above due to the uncertainty of timing of the obligations. Please read Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the Company’s asset retirement obligations.

CRITICAL ACCOUNTING POLICIES

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

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

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substantially delayed. This causes the estimation of recent production and prices used in the oil, NGL and natural gas revenue accrual to be subject to future change.

Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. These estimates affect the unaudited standardized measure disclosures included in Note 11 to the financial statements in Item 8 – “Financial Statements and Supplementary Data,” as well as DD&A and impairment calculations. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, asset retirement obligations and assessment of the need for asset impairments. The Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves on an annual basis, with a semi-annual update. These estimates are based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing prices which are updated through the current period. In accordance with the SEC rules, the reserve estimates were based on average individual product prices during the 12-month period prior to September 30 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. Based on the Company’s 2018 DD&A, a 10% change in the DD&A rate per Mcfe would result in a corresponding $1,839,504 annual change in DD&A expense. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.

Successful Efforts Method of Accounting

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

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Derivative Contracts

The Company has entered into oil and natural gas costless collar contracts and oil and natural gas fixed swap contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide for payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma.

The Company is required to recognize all derivative instruments as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. At September 30, 2018, the Company had no derivative contracts designated as cash flow hedges, and therefore, changes in the fair value of derivatives are reflected in earnings.

Impairment of Assets

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment, since the results are based on estimated future events, such as: inflation rates; future sales prices for oil, NGL and natural gas; future production costs; estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof; economic and regulatory climates and other factors. The Company estimates future net cash flows on its oil and natural gas properties utilizing differentially adjusted forward pricing curves for oil, NGL and natural gas and a discount rate in line with the discount rate we believe is most commonly used by market participants (10% for all periods presented). The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. A further reduction in oil, NGL and natural gas prices (which are reviewed quarterly) or a decline in reserve volumes (which are re-evaluated semi-annually) would likely lead to additional impairment that may be material to the Company. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell (as was the case at September 30, 2017). Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.

Oil, NGL and Natural Gas Sales Revenue Accrual

The Company does not operate its oil and natural gas properties and, therefore, receives actual oil, NGL and natural gas sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the

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case, on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, and oil, NGL and natural gas index prices local to each well are used to estimate the accrual of revenue on these wells. Obtaining timely production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The oil, NGL and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, NGL and natural gas. These variables could lead to an over or under accrual of oil, NGL and natural gas sales at the end of any particular quarter.Based on past history, the Company’s estimated accruals have been materially accurate.

Income Taxes

The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at the end of each fiscal year. During interim periods, an estimate is made taking into account historical data and current pricing. The Company has certain state net operating loss carry forwards (NOLs) that are recognized as tax assets when assessed as more likely than not to be utilized before their expiration dates. Criteria such as expiration dates, future excess state depletion and reversing taxable temporary differences are evaluated to determine whether the NOLs are more likely than not to be utilized before they expire. If any NOLs are determined to no longer be more likely than not to be utilized, then a valuation allowance is recognized to reduce the tax benefit of such NOLs. As of September 30, 2018, the Company had no valuation allowances on NOLs. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.

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

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of oil, NGL and natural gas price trends, and there remains a wide divergence in the opinions held in the industry. The Company can be significantly impacted by changes in oil and natural gas prices. The market price of oil, NGL and natural gas in 2019 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures

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and production. Excluding the impact of the Company’s 2019 derivative contracts (see below), the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $872,126 for operating revenue based on the Company’s prior year natural gas volumes. The price sensitivity in 2019 for each $1.00 per barrel change in wellhead oil is approximately $336,565 for operating revenue based on the Company’s prior year oil volumes.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. All of our outstanding derivative contracts at September 30, 2018, are with Bank of Oklahoma and are secured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas and oil prices. These derivative contracts expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s natural gas fixed price swaps, a change of $0.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $200,100. For the Company’s natural gas collars, a change of $0.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $11,800. For the Company’s oil fixed price swaps, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $143,500. For the Company’s oil collars, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $97,200. See Note 1 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding our derivative contracts.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facility. The revolving loan bears interest at the BOK prime rate plus from 0.50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. At September 30, 2018, the Company had $51,000,000 outstanding under this facility and the effective interest rate was 4.34%. At this point, the Company does not believe that its liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that its liquidity will be impacted in the near future.

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ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Annual Report on Internal Control Over Financial Reporting	55
Report of Registered Public Accounting Firm on Internal Control Over Financial Reporting	56
Report of Independent Registered Public Accounting Firm	58
Balance Sheets As of September 30, 2018 and 2017	59
Statements of Operations for the Years Ended September 30, 2018, 2017 and 2016	61
Statements of Stockholders’ Equity for the Years Ended September 30, 2018, 2017 and 2016	62
Statements of Cash Flows for the Years Ended September 30, 2018, 2017 and 2016	63
Notes to Financial Statements	65

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Management’s Annual Report on Internal Control Over Financial Reporting

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

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

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

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

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

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018. In making this assessment, the Company’s management used the criteria set forth in Internal Control – Integrated Framework (as updated in 2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, management has concluded that, as of September 30, 2018, the Company’s internal control over financial reporting was effective based on those criteria.

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

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Panhandle Oil and Gas Inc.

Opinion on Internal Control over Financial Reporting

We have audited Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2018, based on criteria established in Internal Control— Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework)(the COSO criteria). In our opinion, Panhandle Oil and Gas Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of September 30, 2018, based onthe COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the accompanying balance sheets of the Company as of September 30, 2018 and 2017, and the related statements of operations, stockholders' equity and cash flows for each of the three years in the period ended September 30, 2018, and the related notes and our report dated December 11, 2018, expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

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

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detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

	/s/ Ernst & Young LLP
Oklahoma City, Oklahoma
December 11, 2018

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Panhandle Oil and Gas Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Panhandle Oil and Gas Inc. (the Company) as of September 30, 2018 and 2017, and the related statements of operations, stockholders' equity and cash flows for each of the three years in the period ended September 30, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2018, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of September 30, 2018, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated December 11, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

	/s/ Ernst & Young LLP
We have served as the Company’s auditor since 1989.
Oklahoma City, Oklahoma
December 11, 2018

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Panhandle Oil and Gas Inc.

Balance Sheets

	September 30,
	2018			2017
Assets
Current Assets:
Cash and cash equivalents	$	532,502		$	557,791
Oil, NGL and natural gas sales receivables (net of allowance    for uncollectable accounts)		7,101,629			7,585,485
Refundable income taxes		33,165			489,945
Derivative contracts, net		-			544,924
Assets held for sale		-			557,750
Other		578,880			253,480
Total current assets		8,246,176			9,989,375
Properties and equipment at cost, based on successful efforts    accounting:
Producing oil and natural gas properties		427,448,584			434,571,516
Non-producing oil and natural gas properties		12,563,519			7,428,927
Other		1,529,770			1,067,894
		441,541,873			443,068,337
Less accumulated depreciation, depletion and    amortization		(243,257,472	)		(246,483,979	)
Net properties and equipment		198,284,401			196,584,358
Investments		219,109			170,486
Total assets	$	206,749,686		$	206,744,219

(Continued on next page)

See accompanying notes.

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Panhandle Oil and Gas Inc.

Balance Sheets

	September 30,
	2018			2017
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable	$	881,130		$	1,847,230
Derivative contracts, net		3,064,046			-
Accrued liabilities and other		1,791,950			1,690,789
Total current liabilities		5,737,126			3,538,019
Long-term debt		51,000,000			52,222,000
Deferred income taxes		18,088,007			31,051,007
Asset retirement obligations		2,809,378			3,196,889
Derivative contracts, net		349,970			28,765
Stockholders' equity:
Class A voting common stock, $0.0166 par value; 24,000,000    shares authorized; 16,896,881 issued at September 30,    2018; 16,863,004 issued at September 30, 2017		281,502			280,938
Capital in excess of par value		2,824,691			2,726,444
Deferred directors' compensation		2,950,405			3,459,909
Retained earnings		125,266,945			113,330,216
		131,323,543			119,797,507
Treasury stock, at cost; 145,467 shares at September 30,    2018; 184,988 shares at September 30, 2017		(2,558,338	)		(3,089,968	)
Total stockholders' equity		128,765,205			116,707,539
Total liabilities and stockholders' equity	$	206,749,686		$	206,744,219

See accompanying notes.

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Panhandle Oil and Gas Inc.

Statements of Operations

	Year ended September 30,
	2018			2017		2016
Revenues:
Oil, NGL and natural gas sales	$	48,385,335		$	39,935,912	$	31,411,353
Lease bonuses and rentals		1,580,997			5,149,297		7,735,785
Gains (losses) on derivative contracts		(4,932,068	)		1,249,840		(86,355	)
		45,034,264			46,335,049		39,060,783
Costs and expenses:
Lease operating expenses		13,460,278			12,682,969		13,590,089
Production taxes		2,089,050			1,548,399		1,071,632
Depreciation, depletion and amortization		18,395,040			18,397,548		24,487,565
Provision for impairment		-			662,990		12,001,271
Loss (gain) on asset sales and other		102,685			105,830		(2,576,237	)
Interest expense		1,748,101			1,275,138		1,344,619
General and administrative		7,342,441			7,441,242		7,139,728
		43,137,595			42,114,116		57,058,667
Income (loss) before provision (benefit) for income    taxes		1,896,669			4,220,933		(17,997,884	)
Provision (benefit) for income taxes		(12,739,000	)		689,000		(7,711,000	)
Net income (loss)	$	14,635,669		$	3,531,933	$	(10,286,884	)
Basic and diluted earnings (loss) per common share	$	0.86		$	0.21	$	(0.61	)

See accompanying notes.

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Panhandle Oil and Gas Inc.

Statements of Stockholders’ Equity

	Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total
Balances at September 30, 2015		16,863,004	$	280,938	$	2,993,119		$	3,084,289		$	125,446,473			(302,623	)	$	(4,800,144	)	$	127,004,675
Purchase of treasury stock		-		-		-			-			-			(7,477	)		(117,165	)		(117,165	)
Issuance of treasury shares to ESOP		-		-		19,068			-			-			11,418			181,090			200,158
Restricted stock awards		-		-		781,479			-			-			-			-			781,479
Distribution of restricted stock to    officers and directors		-		-		(601,779	)		-			-			35,257			559,175			(42,604	)
Distribution of deferred directors'    compensation		-		-		(831	)		(10,541	)		-			717			11,372			-
Common shares to be issued to    directors for services		-		-		-			329,465			-			-			-			329,465
Dividends declared ($0.16 per share)		-		-		-			-			(2,677,305	)		-			-			(2,677,305	)
Net income (loss)		-		-		-			-			(10,286,884	)		-			-			(10,286,884	)
Balances at September 30, 2016		16,863,004	$	280,938	$	3,191,056		$	3,403,213		$	112,482,284			(262,708	)	$	(4,165,672	)	$	115,191,819
Purchase of treasury stock		-		-		-			-			-			(25,742	)		(601,853	)		(601,853	)
Issuance of treasury shares to ESOP		-		-		93,192			-			-			13,125			219,188			312,380
Restricted stock awards		-		-		597,940			-			-			-			-			597,940
Distribution of restricted stock to    officers and directors		-		-		(1,010,275	)		-			-			63,121			1,010,938			663
Distribution of deferred directors'    compensation		-		-		(145,469	)		(301,962	)		-			27,216			447,431			-
Common shares to be issued to    directors for services		-		-		-			358,658			-			-			-			358,658
Dividends declared ($0.16 per share)		-		-		-			-			(2,684,001	)		-			-			(2,684,001	)
Net income (loss)		-		-		-			-			3,531,933			-			-			3,531,933
Balances at September 30, 2017		16,863,004	$	280,938	$	2,726,444		$	3,459,909		$	113,330,216			(184,988	)	$	(3,089,968	)	$	116,707,539
Purchase of treasury stock		-		-		-			-			-			(63,404	)		(1,219,228	)		(1,219,228	)
Issuance of treasury shares to ESOP		-		-		19,509			-			-			20,632			362,665			382,174
Restricted stock awards		-		-		655,414			-			-			-			-			655,414
Distribution of restricted stock to    officers and directors		1,278		21		(845,788	)		-			-			50,455			846,629			862
Distribution of deferred directors'    compensation		32,599		543		269,112			(811,219	)		-			31,838			541,564			-
Common shares to be issued to    directors for services		-		-		-			301,715			-			-			-			301,715
Dividends declared ($0.16 per share)		-		-		-			-			(2,698,940	)		-			-			(2,698,940	)
Net income (loss)		-		-		-			-			14,635,669			-			-			14,635,669
Balances at September 30, 2018		16,896,881	$	281,502	$	2,824,691		$	2,950,405		$	125,266,945			(145,467	)	$	(2,558,338	)	$	128,765,205

See accompanying notes.

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Panhandle Oil and Gas Inc.

Statements of Cash Flows

	Year ended September 30,
	2018			2017			2016
Operating Activities
Net income (loss)	$	14,635,669		$	3,531,933		$	(10,286,884	)
Adjustments to reconcile net income (loss) to net    cash provided by operating activities:
Depreciation, depletion and amortization		18,395,040			18,397,548			24,487,565
Impairment		-			662,990			12,001,271
Provision for deferred income taxes		(12,963,000	)		375,000			(9,960,000	)
Gain from leasing fee mineral acreage		(1,520,262	)		(5,147,957	)		(7,732,023	)
Proceeds from leasing fee mineral acreage		1,564,225			5,194,290			8,049,434
Net (gain) loss on sales of assets		660,597			94,889			(2,688,408	)
Common stock contributed to ESOP		382,174			312,380			200,158
Common stock (unissued) to Directors' Deferred    Compensation Plan		301,715			358,658			329,465
Fair value of derivative contracts		3,930,175			(944,430	)		4,639,035
Restricted stock awards		655,414			597,940			781,479
Other		6,326			(5,783	)		81,606
Cash provided (used) by changes in assets and    liabilities:
Oil, NGL and natural gas sales receivables		483,856			(2,298,256	)		2,589,146
Refundable income taxes		456,780			(406,071	)		262,023
Other current assets		57,752			165,557			308,980
Accounts payable		(140,600	)		(103,389	)		(811,749	)
Other non-current assets		(62,295	)		-			-
Accrued liabilities		100,328			(27,107	)		388,053
Total adjustments		12,308,225			17,226,259			32,926,035
Net cash provided by operating activities		26,943,894			20,758,192			22,639,151

(Continued on next page)

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Panhandle Oil and Gas Inc.

Statements of Cash Flows (continued)

	Year ended September 30,
	2018			2017			2016
Investing Activities
Capital expenditures, including dry hole costs	$	(11,590,135	)	$	(25,807,897	)	$	(3,986,235	)
Acquisition of minerals and overrides		(11,327,371	)		-			-
Investments in partnerships		3,354			(23,563	)		50,126
Proceeds from sales of assets		1,085,137			723,700			4,501,726
Net cash used in investing activities		(21,829,015	)		(25,107,760	)		565,617
Financing Activities
Borrowings under debt agreement		29,017,800			27,809,185			12,339,101
Payments of loan principal		(30,239,800	)		(20,087,185	)		(32,839,101	)
Purchases of treasury stock		(1,219,228	)		(601,853	)		(117,165	)
Payments of dividends		(2,698,940	)		(2,684,001	)		(2,677,305	)
Excess tax benefit on stock-based compensation		-			-			(43,000	)
Net cash provided by (used in) financing activities		(5,140,168	)		4,436,146			(23,337,470	)
Increase (decrease) in cash and cash equivalents		(25,289	)		86,578			(132,702	)
Cash and cash equivalents at beginning of year		557,791			471,213			603,915
Cash and cash equivalents at end of year	$	532,502		$	557,791		$	471,213
Supplemental Disclosures of Cash Flow    Information
Interest paid (net of capitalized interest)	$	1,730,461		$	1,212,878		$	1,365,474
Income taxes paid (net of refunds received)	$	(232,782	)	$	720,072		$	2,029,977
Supplemental schedule of noncash investing and    financing activities:
Additions and revisions, net, to asset retirement    obligations	$	17,216		$	624,893		$	14,095
Gross additions to properties and equipment	$	21,711,279		$	25,406,894		$	5,118,733
Net (increase) decrease in accounts payable for    properties and equipment additions		1,206,227			401,003			(1,132,498	)
Capital expenditures, including dry hole costs	$	22,917,506		$	25,807,897		$	3,986,235

See accompanying notes.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements

September 30, 2018, 2017 and 2016

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Through management of its fee mineral and leasehold acreage, the Company’s principal line of business is to explore for, develop, acquire, produce and sell oil, NGL and natural gas. Panhandle’s mineral and leasehold properties and other oil and natural gas interests are all located in the contiguous United States, primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas, with properties located in several other states. The Company’s oil, NGL and natural gas production is from interests in 6,079 wells located principally in Arkansas, Oklahoma and Texas. The Company does not operate any wells. Approximately 45% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2018. Approximately 71% of the Company’s total sales volumes in 2018 were derived from natural gas. Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells. From time to time, the Company sells certain non-material, non-core or small-interest oil and natural gas properties in the normal course of business.

Use of Estimates

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

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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

projected future crude oil, NGL and natural gas pricing assumptions to prepare estimates of crude oil, NGL and natural gas reserves used in formulating management’s overall operating decisions.

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

Cash and Cash Equivalents

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

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

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

The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves. At September 30, 2018 and 2017, the Company had no material natural gas imbalances.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers of oil, NGL and natural gas or operators of the oil and natural gas properties. Oil, NGL and natural gas sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our oil, NGL and natural gas and the operators of the properties in which we have an interest may be similarly affected by changes in economic, industry or other conditions. During 2018, 2017 and 2016 the Company did not have any bad debt expense. The Company’s allowance for uncollectible accounts as of the Balance Sheet dates was not material.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Oil and Natural Gas Producing Activities

The Company follows the successful efforts method of accounting for oil and natural gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income, if and when the well does not reach commercial production levels. Oil and natural gas mineral and leasehold costs are capitalized when incurred.

It is common business practice in the petroleum industry to prepay drilling costs before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2018, the Company had no outstanding letters of credit.

Leasing of Mineral Rights

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

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

Derivatives

The Company has entered into fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts at September 30, 2018 and 2017, were with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Derivative contracts in place as of September 30, 2018

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
April - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.15 ceiling
Natural gas fixed price swaps
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
April - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.910
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.835
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.925
July - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.988
July 2018 - March 2019	50,000 Mmbtu	NYMEX Henry Hub	$3.065
January - July 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.867
Oil costless collars
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$50.00 floor / $55.75 ceiling
July - December 2018	3,000 Bbls	NYMEX WTI	$50.00 floor / $58.00 ceiling
January - June 2019	2,000 Bbls	NYMEX WTI	$55.00 floor / $63.45 ceiling
January - December 2019	1,000 Bbls	NYMEX WTI	$50.00 floor / $60.00 ceiling
January - December 2019	2,000 Bbls	NYMEX WTI	$60.00 floor / $69.25 ceiling
July - December 2019	3,000 Bbls	NYMEX WTI	$60.00 floor / $70.75 ceiling
January - June 2020	2,000 Bbls	NYMEX WTI	$60.00 floor / $67.00 ceiling
Oil fixed price swaps
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02
April - December 2018	4,000 Bbls	NYMEX WTI	$54.14
July - December 2018	2,000 Bbls	NYMEX WTI	$58.20
January - June 2019	2,000 Bbls	NYMEX WTI	$59.69
January - June 2019	2,000 Bbls	NYMEX WTI	$57.15
January - June 2019	3,000 Bbls	NYMEX WTI	$58.02
January - December 2019	1,000 Bbls	NYMEX WTI	$56.15
January - December 2019	2,000 Bbls	NYMEX WTI	$56.71
January - December 2019	1,000 Bbls	NYMEX WTI	$58.56
July - December 2019	2,000 Bbls	NYMEX WTI	$56.85

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Derivative contracts in place as of September 30, 2017

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.65 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $3.65 ceiling
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
January - March 2018	150,000 Mmbtu	NYMEX Henry Hub	$3.40 floor / $3.95 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
Natural gas fixed price swaps
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.210
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.300
July - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.510
August - December 2017	100,000 Mmbtu	NYMEX Henry Hub	$3.095
January - March 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.700
January - March 2018	75,000 Mmbtu	NYMEX Henry Hub	$3.575
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.520
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
Oil costless collars
January - December 2017	3,000 Bbls	NYMEX WTI	$50.00 floor / $55.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$52.00 floor / $58.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$53.00 floor / $57.75 ceiling
April - December 2017	2,000 Bbls	NYMEX WTI	$50.00 floor / $57.50 ceiling
July - December 2017	5,000 Bbls	NYMEX WTI	$45.00 floor / $56.25 ceiling
January - June 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.75 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
Oil fixed price swaps
January - December 2017	3,000 Bbls	NYMEX WTI	$53.89
April - December 2017	2,000 Bbls	NYMEX WTI	$54.20
January - March 2018	4,000 Bbls	NYMEX WTI	$54.00
January - June 2018	4,000 Bbls	NYMEX WTI	$51.25
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $3,414,016 as of September 30, 2018, and a net asset of $516,159 as of September 30, 2017. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations. The portion of the gain (loss) on derivatives settled in cash for 2018, 2017 and 2016 was $1,001,893 (net paid), $305,410 (net received) and $4,552,680 (net received), respectively.

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on, or termination of, any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Balance Sheets. The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Balance Sheets at September 30, 2018, and September 30, 2017. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2018, and September 30, 2017.

	9/30/2018								9/30/2017
	Fair Value								Fair Value
	Commodity Contracts								Commodity Contracts
	CurrentAssets			Current Liabilities			Non-Current Liabilities		CurrentAssets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	42,150		$	3,106,196		$	349,970	$	735,702		$	190,778		$	9,439		$	38,204
Offsetting adjustments		(42,150	)		(42,150	)		-		(190,778	)		(190,778	)		(9,439	)		(9,439	)
Net presentation on Balance Sheets	$	-		$	3,064,046		$	349,970	$	544,924		$	-		$	-		$	28,765

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

Fair Value Measurements

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels.

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur with

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and, as of the fourth quarter of 2018, commodity options (i.e. price collars).

The Company uses an option pricing valuation model for option derivative contracts that considers various inputs including: future prices, time value, volatility factors, counterparty credit risk and current market and contractual prices for the underlying instruments. The values calculated are then compared to the values given by counterparties for reasonableness.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and unobservable (or less observable) from objective sources (supported by little or no market activity).

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

	Fair Value Measurement at September 30, 2018
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs		TotalFair
	(Level 1)		(Level 2)			(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(2,317,069	)	$	-	$	(2,317,069	)
Derivative Contracts - Collars	$	-	$	(1,096,947	)	$	-	$	(1,096,947	)

	Fair Value Measurement at September 30, 2017
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	364,606	$	-	$	364,606
Derivative Contracts - Collars	$	-	$	-	$	151,553	$	151,553

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

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

	Derivatives
Net Asset (Liability) Balance of Level 3 as of October 1, 2017	$	151,553
Total gains or (losses):
Included in earnings		(877,307	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(371,193	)
Transfers in and out of Level 3 (i)		1,096,947
Net Asset (Liability) Balance of Level 3 as of September 30, 2018	$	-

(i) During the fourth quarter of 2018, we transferred $1,096,947 of derivative collars out of Level 3 hierarchy, into Level 2 hierarchy as a result of our ability to obtain volatility inputs from direct observable sources.

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

	Year Ended September 30,
	2018				2017				2016
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	567,077	$	662,990	$	9,877,905	$	12,001,271

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

At September 30, 2018, and September 30, 2017, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short term maturities of those instruments. Financial instruments include long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Properties and Equipment

Depreciation, Depletion and Amortization

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

Non-producing oil and natural gas properties include non-producing minerals, which had a net book value of $8,025,015 and $3,079,008 at September 30, 2018 and 2017, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 92-year life of the Company. There are approximately 198,360 net acres of non-producing minerals in more than 6,749 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $62. Since inception, the Company has continually generated an interest in several thousand oil and natural gas wells using its ownership of the fee mineral acres as an ownership basis. There continues to be significant drilling and leasing activity on these mineral interests each year. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (as do oil and natural gas leases). Given the above, management concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.

Impairment

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing thefair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company or fair value (sales price) less cost to sell if the property is held for sale. The Company's estimate of fair value of its oil and natural gas properties at September 30, 2018, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $0, $662,990 and $12,001,271 for 2018, 2017 and 2016, respectively. A further reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company. 

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Divestitures

During the 2018 fiscal year, the Company sold 324 non-core marginal wells for $1,085,137 and recorded a loss on the sales of $660,597. The total net book value that was removed from the Balance Sheets due to these sales was approximately $1.7 million. The loss on sales was included in the Loss (gain) on asset sales and other line of the Statements of Operations. All of the wells included in the Assets held for sale line item on the Balance Sheets at September 30, 2017, were sold during the first quarter of 2018.

Acquisitions

During the 2018 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 4,306 net mineral acres for $11.3 million or an average of approximately $2,600 per net mineral acre. These mineral purchases were accounted for as asset acquisitions.

Capitalized Interest

During 2018, 2017 and 2016, interest of $89,023, $168,351 and $24,929, respectively, was included in the Company’s capital expenditures. Interest of $1,748,101, $1,275,138 and $1,344,619, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the unit-of-production method.

Asset Retirement Obligations

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

The following table shows the activity for the years ended September 30, 2018 and 2017, relating to the Company’s asset retirement obligations:

	2018			2017
Asset retirement obligations as of beginning of the year	$	3,196,889		$	2,958,048
Wells acquired or drilled		17,215			114,766
Wells sold or plugged		(542,892	)		(548,634	)
Revisions in estimated cash flows		-			536,536
Accretion of discount		138,166			136,173
Asset retirement obligations as of end of the year	$	2,809,378		$	3,196,889

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

The revisions in estimated cash flows in fiscal 2017 were due to increased plugging charges noted recently that were higher than previously estimated. As a non-operator, we do not control the plugging of wells in which we have a working interest and are not involved in the negotiation of the terms of the plugging contracts. Our estimate relies on information that we can gather from outside sources as well as relevant information that we receive directly from operators.

Environmental Costs

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

Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2018 and 2017, there were no such costs accrued.

Earnings (Loss) Per Share of Common Stock

Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period.

Share-based Compensation

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

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

Restricted stock awards to officers provide for cliff vesting at the end of three years from the date of the awards. These restricted stock awards can be granted based on service time only (non-performance based) or subject to certain share price performance standards (performance

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Notes to Financial Statements (continued)

based). Restricted stock awards to the non-employee directors provide for quarterly vesting during the calendar year of the award. The fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance.

Income Taxes

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

The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduces the U.S. federal corporate tax rate from 35% to 21%, requires companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously tax deferred and creates new taxes on certain foreign sourced earnings. As of September 30, 2018, we have completed our estimates accounting for the tax effects of enactment of the Act. Based on these estimates, we recognized an amount which is included as a component of income tax expense (benefit) from continuing operations.

We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The amount recorded related to the remeasurement of our deferred tax balance was $12,464,000 income tax benefit.

The Company has a year end of September 30. Because this differs from a calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The impact of using a blended rate versus the old rate in the current year resulted in a federal tax benefit of $198,581.

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended September 30, 2018, was a 672% benefit as compared to a 16% provision for the year ended September 30, 2017.

The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2015.

The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Operations. For fiscal September 30, 2018, 2017 and 2016, the Company’s interest and penalties was not material. The Company does not believe it has any significant uncertain tax positions.

Adoption of New Accounting Pronouncements

In January 2017, the FASB issued ASU 2017-01, which changed the definition of a business. The new guidance requires an entity to first evaluate whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets. If that threshold is met, the set of assets and activities is not a business. If it’s not met, the entity evaluates whether the set meets the definition of a business. The new definition requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue recognition guidance. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. The ASU was applied prospectively to transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods for which the financial statements have not been issued or made available for issuance. The Company early adopted ASU 2017-01 during the third quarter ended June 30, 2018.

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. The guidance is effective for us beginning October 1, 2019, including interim periods within the fiscal year. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this update will have on our financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for us beginning October 1, 2018, including interim periods within the fiscal year. This update is not expected to have a material impact on our financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services.

Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis.

The standard is effective for us beginning October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements and utilizes a cumulative effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Panhandle intends to use the modified retrospective method upon adoption.

The Company has completed its evaluation of the impact of the new standard and related interpretive guidance on its financial statements, accounting policies, internal controls, and disclosures. Based on our assessments, the standard is not expected to have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures and internal controls over financial reporting.

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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

2. COMMITMENTS

The Company leases office space in Oklahoma City, Oklahoma, under the terms of an operating lease expiring in April 2020. Future minimum rental payments under the terms of the lease are $210,273, $122,659 and $0 in 2019, 2020 and 2021, respectively. Total rent expense incurred by the Company was $215,803 in 2018, $206,366 in 2017 and $202,083 in 2016.

3. INCOME TAXES

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

	2018			2017			2016
Current:
Federal	$	204,000		$	314,000		$	2,166,000
State		20,000			-			83,000
		224,000			314,000			2,249,000
Deferred:
Federal		(13,240,000	)		390,000			(8,597,000	)
State		277,000			(15,000	)		(1,363,000	)
		(12,963,000	)		375,000			(9,960,000	)
	$	(12,739,000	)	$	689,000		$	(7,711,000	)

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

	2018			2017			2016
Provision (benefit) for income taxes at statutory rate	$	465,253		$	1,477,327		$	(6,299,259	)
Percentage depletion		(577,780	)		(570,801	)		(395,649	)
State income taxes, net of federal provision (benefit)		36,980			3,900			(683,800	)
Effect of graduated rates		-			85,644			(86,745	)
Restricted stock tax benefit		(69,000	)		(238,000	)		-
Deferred directors compensation benefit		(134,000	)		(79,000	)		-
Law change (a)		(12,464,000	)		-			-
Other		3,547			9,930			(245,547	)
	$	(12,739,000	)	$	689,000		$	(7,711,000	)

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

(a) This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21%.

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

	2018		2017
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible    drilling costs capitalized for financial purposes and    expensed for tax purposes	$	24,560,165	$	38,185,387
Derivative contracts		-		200,786
		24,560,165		38,386,173
Deferred tax assets:
State net operating loss carry forwards		551,435		655,741
AMT credit carry forwards		2,936,457		3,499,320
Deferred directors' compensation		725,971		1,295,333
Restricted stock expense		249,610		411,019
Derivative contracts		878,767		-
Statutory depletion carry forwards		-		634,405
Other		1,129,918		839,348
		6,472,158		7,335,166
Net deferred tax liabilities	$	18,088,007	$	31,051,007

At September 30, 2018, the Company had a deferred tax asset of $497,752 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring from 2031 to 2037. There is no valuation allowance for the OK NOL’s, as management believes they will be utilized before they expire.

The AMT carry forwards do not have an expiration date. The corporate alternative minimum tax was repealed by The Tax Cuts and Jobs Act (enacted on December 22, 2017). Taxpayers with AMT credit carryovers can use the credits to offset regular tax liability for any taxable year. In addition, the AMT credit is refundable in any taxable year beginning after 2017 and before 2022 in an amount equal to 50% (100% in the case of taxable years beginning in 2021) of the excess of the minimum tax credit for the taxable year over the amount of the credit allowable for the year against regular tax liability. Thus, the Company’s entire AMT credit carryforward amounts are fully refundable by 2023.

4. LONG-TERM DEBT

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2022. The credit facility is subject to a semi-annual borrowing base determination,

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties with a net book value of $135,994,289 atSeptember 30, 2018. The interest rate is based on BOK prime plus from 0.50% to1.25%, or 30 day LIBOR plus from 2.00% to2.75%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. AtSeptember 30, 2018, the effective interest rate was4.34%.

The Company’s debt is recorded at the carrying amount on its balance sheet. The carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates.

Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the banks, in their sole discretion, believe that there has been a material change in the value of the Company’s oil and natural gas properties. The borrowing base for the credit facility was redetermined in July 2018 by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants, which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of treasury stock. The loan agreement sets limits on dividend payments and stock repurchases if those payments would cause the leverage ratio to go above 2.75 to 1.0. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by the bank agreement – current assets includes availability under outstanding credit facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing 12 months as defined by bank agreement – traditional EBITDA with the unrealized gain or loss on derivative contracts also removed from earnings) of no more than 4.0 to 1.0. At September 30, 2018, the Company was in compliance with the covenants of the loan agreement and had $29,000,000 of availability under its outstanding credit facility.

5. STOCKHOLDERS’ EQUITY

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in May 2018, the board of directors approved to continue to allow management to repurchase up to $1.5 million of the Company’s common stock at their discretion. The repurchase of an additional $1.5 million of the Company’s common stock continues to be authorized and approved effective when the previous amount is utilized. The Board added language to clarify that this is intended to be an evergreen provision. The number of shares allowed to be purchased by the Company under the repurchase program is no longer capped at an amount equal to the aggregate number of shares of common stock (i) awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. As of September 30, 2018, $1,219,228 had been spent to purchase 63,404 shares. The shares are held in treasury and are accounted for using the cost method.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

6. EARNINGS (LOSS) PER SHARE

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

	Year ended September 30,
	2018		2017		2016
Numerator for basic and diluted earnings (loss) per share:
Net income (loss)	$	14,635,669	$	3,531,933	$	(10,286,884	)
Denominator for basic and diluted earnings per share:
Weighted average shares (including for 2018, 2017    and 2016, unissued, vested directors' shares of    205,736, 253,603 and 263,057, respectively)		16,952,664		16,900,185		16,840,856

7. EMPLOYEE STOCK OWNERSHIP PLAN

The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan that serves as the sole retirement plan for all its employees to which the Company makes contributions. Company contributions are made at the discretion of the Board and, to date, all contributions have been made in shares of Company Common Stock. The Company contributions are allocated to all ESOP participants in proportion to their compensation for the plan year, and 100% vesting occurs after three years of service. Any shares that do not vest are treated as forfeitures and are distributed among other vested employees. For contributions of Common Stock, the Company records as expense the fair market value of the stock contributed. Compensation expense is equal to the contributions for each year. The 247,667 shares of the Company’s Common Stock held by the plan as of September 30, 2018, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings-per-share computations and receive dividends.

Contributions to the plan consisted of:

Year	Shares		Amount
2018		20,632	$	382,174
2017		13,125	$	312,380
2016		11,418	$	200,158

8. DEFERRED COMPENSATION PLAN FOR DIRECTORS

Annually, independent directors may elect to be included in the Panhandle Oil and Gas Inc. Deferred Directors’ Compensation Plan for Non-Employee Directors (the “Plan”). The Plan provides that each independent director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees, and may elect to receive shares, when issued, over annual time periods up to ten years. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

upon a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director under the Plan be issued to the director. The promise to issue such shares in the future is an unsecured obligation of the Company.As ofSeptember 30, 2018, there were212,574shares (261,846shares atSeptember 30, 2017) recorded under the Plan.The deferred balance outstanding atSeptember 30, 2018, under the Plan was$2,950,405($3,459,909atSeptember 30, 2017).Expenses totaling $301,715, $358,658 and$329,465were charged to the Company’s results of operations for the years endedSeptember 30, 2018, 2017 and2016, respectively, and are included in general and administrative expense in the accompanying Statement of Operations.

9. RESTRICTED STOCK PLAN

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (“2010 Stock Plan”), which made available 200,000 shares of Common Stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, is designed to provide as much flexibility as possible for future grants of restricted stock so the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

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

In December 2010, the Company also began awarding shares of the Company’s Common Stock, subject to certain share price performance standards (performance based), as restricted stock to certain officers. Vesting of these shares is based on the performance of the market price of the Common Stock over the vesting period. The fair value of the performance shares was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period regardless of whether performance shares are awarded at the end of the vesting period. Should the awards vest, they are expected to be issued out of shares held in treasury.

In May 2014, the Company also began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to its non-employee directors. The restricted stock vests quarterly during the calendar year of the award and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares was based on the closing price of the shares on their award date and will be recognized as

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

compensation expense ratably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.

Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur.

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2018, 2017 and 2016, related to the Company’s performance based and non-performance based restricted stock.

	Year Ended September 30,
	2018		2017		2016
Performance based, restricted stock	$	276,272	$	233,122	$	390,655
Non-performance based, restricted stock		379,142		364,818		390,824
Total compensation expense	$	655,414	$	597,940	$	781,479

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

	Unrecognized Compensation Cost		Weighted AveragePeriod (in years)
Performance based, restricted stock	$	321,389		1.79
Non-performance based, restricted stock		274,666		1.50
Total	$	596,055

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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

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

	Performance Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Non- Performance BasedUnvested Restricted Shares			Weighted Average Grant-Date Fair Value
Unvested shares as of September 30,    2015		112,251		$	9.20		39,966		$	16.56
Granted		40,446			9.32		26,478			16.37
Vested		(10,197	)		7.59		(23,433	)		16.91
Forfeited		(28,083	)		7.59		-			-
Unvested shares as of September 30,    2016		114,417		$	9.78		43,011		$	16.25
Granted		20,531			14.27		16,426			24.41
Vested		(34,672	)		8.07		(28,449	)		18.02
Forfeited		(1,186	)		8.07		(5,991	)		17.04
Unvested shares as of September 30,    2017		99,090		$	11.33		24,997		$	19.41
Granted		29,099			11.34		19,918			20.77
Vested		(35,485	)		12.18		(16,248	)		19.34
Forfeited		-			-		-			-
Unvested shares as of September 30,    2018		92,704		$	11.00		28,667		$	20.40

The intrinsic value of the vested shares in 2018 was $1,047,761.

10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

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

The following table shows sales, by percentage, through various operators/purchasers during 2018, 2017 and 2016.

	2018			2017			2016
Company A		24	%		18	%		23	%
Company B		16	%		3	%		3	%
Company C		11	%		8	%		2	%
Company D		7	%		13	%		12	%

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

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

Aggregate Capitalized Costs

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

	2018			2017
Producing properties	$	427,448,584		$	434,571,516
Non-producing minerals		12,378,395			7,243,802
Non-producing leasehold		185,124			185,125
Exploratory wells in progress		-			-
		440,012,103			442,000,443
Accumulated depreciation, depletion and amortization		(242,169,604	)		(245,640,247	)
Net capitalized costs	$	197,842,499		$	196,360,196

Costs Incurred

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

	2018		2017		2016
Property acquisition costs	$	11,409,673	$	20,190	$	-
Exploration costs		-		-		21,049
Development costs		10,291,476		25,382,377		5,075,710
	$	21,701,149	$	25,402,567	$	5,096,759

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

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

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

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Notes to Financial Statements (continued)

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

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2018, 2017 and 2016.

The Company’s net proved oil, NGL and natural gas reserves, which are located in the contiguous United States, as of September 30, 2018, 2017 and 2016, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Vice President of Operations, Freda Webb, who reports directly to our President and CEO. Ms. Webb holds a Bachelor of Science Degree in Mechanical Engineering from the University of Oklahoma, a Master of Science Degree in Petroleum Engineering from the University of Southern California and a Professional Engineering License in Petroleum Engineering in the State of Oklahoma. Ms. Webb has more than 35 years of experience in the oil and gas industry. Before joining the Company, she was sole proprietor of a consulting petroleum engineering firm and a mineral acquisition company. Ms. Webb held various positions of increasing responsibility at Southwestern Energy Company and Occidental Petroleum Corporation, with reservoir

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Notes to Financial Statements (continued)

engineering assignments in several field locations across the United States. She is an active member of the Society of Petroleum Engineers (SPE).

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

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

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

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

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

(88)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

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

	Proved Reserves
	Oil			NGL			Natural Gas			Total
	(Barrels)			(Barrels)			(Mcf)			Bcfe
September 30, 2015		7,038,430			2,920,600			120,214,044			180.0
Revisions of previous estimates		(1,552,010	)		(1,192,143	)		(47,068,144	)		(63.5	)
Acquisitions (divestitures)		-			-			-			-
Extensions, discoveries and other additions		303,922			65,306			16,864,075			19.1
Production		(364,252	)		(171,060	)		(8,284,377	)		(11.5	)
September 30, 2016		5,426,090			1,622,703			81,725,598			124.0
Revisions of previous estimates		253,481			407,250			13,651,501			17.6
Acquisitions (divestitures)		(37,724	)		(12,953	)		(669,064	)		(1.0	)
Extensions, discoveries and other additions		178,497			541,557			34,681,614			39.0
Production		(310,677	)		(173,858	)		(8,194,529	)		(11.1	)
September 30, 2017		5,509,667			2,384,699			121,195,120			168.6
Revisions of previous estimates		(1,407,995	)		303,728			(29,247	)		(6.7	)
Acquisitions (divestitures)		236,690			24,765			(1,782,949	)		(0.2	)
Extensions, discoveries and other additions		1,982,624			476,174			9,400,374			24.2
Production		(336,564	)		(255,176	)		(8,721,262	)		(12.3	)
September 30, 2018		5,984,422			2,934,190			120,062,036			173.6

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2018 - $62.86/Bbl, $26.13/Bbl, $2.56/Mcf; September 30, 2017 - $46.31/Bbl, $17.55/Bbl, $2.81/Mcf; September 30, 2016 - $36.77/Bbl, $12.22/Bbl, $1.97/Mcf.

The revisions of previous estimates from 2017 to 2018 were primarily the result of:

• Negative pricing revisions of 2.4 Bcfe, primarily resulting from gas wells currently projected to reach their projected economic limits earlier than projected in 2017 due to lower natural gas prices in 2018 relative to 2017; proved developed revisions of 1.7 Bcfe and PUD revisions of 0.7 Bcfe.

(89)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

• Negative performance revisions of 4.2 Bcfe. Proved developed revisions were positive 7.6 Bcfe, principally due to better well performance from high-interest wells drilled in 2017 in the Anadarko Basin Woodford and southeastern Oklahoma Woodford. Proved undeveloped negative revisions of 11.8 Bcfe are a result of a delayed Eagle Ford drilling program in 2018 which resulted in removal of wells that are no longer projected to be developed within 5 years from the date they were added due to unanticipated drilling delays. However, the Eagle Ford drilling program is now underway.

Acquisitions and divestitures were the result of:

• The sale of 2.8 Bcfe in marginal properties located in northwestern Oklahoma and Kearny County, Kansas.

• The acquisition of 2.6 Bcfe, predominately in the active drilling program of the Bakken in North Dakota; 1.4 Bcfe proved developed and 1.2 Bcfe proved undeveloped.

Extensions, discoveries and other additions from 2017 to 2018 are principally attributable to:

• Proved developed reserve extensions, discoveries and other additions of 3.7 Bcfe resulting from:

a) The Company’s working and royalty interest ownership in ongoing development of unconventional oil, NGL and natural gas utilizing extended horizontal drilling in the Woodford Shale in the Anadarko Basin and southeastern Oklahoma.

b) The Company’s working and royalty interest ownership in ongoing development of unconventional oil, NGL and natural gas utilizing horizontal drilling in the STACK Meramec play in the Anadarko Basin in western Oklahoma.

c) The Company’s royalty interest ownership in ongoing development of conventional and unconventional oil, NGL and natural gas utilizing horizontal drilling in the Permian Basin of New Mexico and Texas.

• The addition of 20.4 Bcfe of PUD reserves primarily within the Company’s active drilling program areas of 1) the Anadarko Basin Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma and 3) the current drilling program of the Eagle Ford Shale in Texas.    

(90)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

	Proved Developed Reserves						Proved Undeveloped Reserves
	Oil		NGL		NaturalGas		Oil		NGL		NaturalGas
	(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)		(Mcf)
September 30, 2016		1,980,519		1,095,256		62,929,047		3,445,571		527,447		18,796,551
September 30, 2017		2,201,528		1,768,425		87,861,043		3,308,139		616,274		33,334,077
September 30, 2018		2,334,587		2,085,706		83,151,954		3,649,835		848,484		36,910,082

The following details the changes in proved undeveloped reserves for 2018 (Mcfe):

Beginning proved undeveloped reserves	56,880,555
Proved undeveloped reserves transferred to proved developed	(2,158,716	)
Revisions	(12,456,931	)
Extensions and discoveries	20,413,545
Purchases	1,221,543
Ending proved undeveloped reserves	63,899,996

Beginning PUD reserves were 56.9 Bcfe. A total of 2.2 Bcfe (4% of the beginning balance) was transferred to proved developed during 2018. In the last two years, 41% of the beginning PUD reserves were transferred to proved developed. The 12.5 Bcfe (22% of the beginning balance) of negative revisions to PUD reserves were pricing revisions of 0.7 Bcfe and performance revision of 11.8 Bcfe, predominately resulting from the removal of oil, NGL and natural gas reserves associated with Eagle Ford wells that are no longer projected to be developed within 5 years from the date they were added due to a delayed drilling program in 2018. We anticipate that all the Company’s current 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 20.4 Bcfe of PUD reserves in 2018 primarily within the Company’s active drilling program areas of 1) the Anadarko Basin Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma and 3) the current drilling program of the Eagle Ford Shale in Texas. These additions result from continuing development and additional well performance data in each of the referenced plays. Of the 2018 PUD adds, 1.2 Bcfe was drilling or completing at year-end.

Standardized Measure of Discounted Future Net Cash Flows

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

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month

(91)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

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

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

	2018			2017			2016
Future cash inflows	$	759,899,074		$	637,509,599		$	380,263,695
Future production costs		(259,413,766	)		(256,193,675	)		(182,948,045	)
Future development and asset retirement costs		(89,518,449	)		(93,133,683	)		(72,431,842	)
Future income tax expense		(95,872,182	)		(102,193,819	)		(38,674,100	)
Future net cash flows		315,094,677			185,988,422			86,209,708
10% annual discount		(158,768,823	)		(105,155,847	)		(56,439,589	)
Standardized measure of discounted future net    cash flows	$	156,325,854		$	80,832,575		$	29,770,119

(92)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

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

	2018			2017			2016
Beginning of year	$	80,832,575		$	29,770,119		$	81,591,211
Changes resulting from:
Sales of oil, NGL and natural gas, net of    production costs		(32,836,007	)		(25,783,055	)		(16,749,632	)
Net change in sales prices and production costs		47,533,281			37,186,619			(86,198,778	)
Net change in future development and asset    retirement costs		1,580,942			(7,939,156	)		21,636,258
Extensions and discoveries		34,667,557			38,582,908			11,640,704
Revisions of quantity estimates		(8,391,223	)		15,282,587			(41,716,689	)
Acquisitions (divestitures) of reserves-in-place		(307,472	)		(962,667	)		-
Accretion of discount		12,602,209			4,789,294			14,424,032
Net change in income taxes		(3,057,128	)		(27,070,430	)		44,533,277
Change in timing and other, net		23,701,120			16,976,356			609,736
Net change		75,493,279			51,062,456			(51,821,092	)
End of year	$	156,325,854		$	80,832,575		$	29,770,119

12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

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

	Fiscal 2018
	Quarter Ended
	December31			March 31		June 30			September 30
Revenues	$	12,490,526		$	11,421,258	$	9,557,937		$	11,564,543
Income (loss) before provision for    income taxes	$	1,074,939		$	1,046,176	$	(984,093	)	$	759,647
Net income (loss)	$	13,784,939		$	1,070,176	$	(775,093	)	$	555,647
Earnings (loss) per share	$	0.81		$	0.06	$	(0.05	)	$	0.04
	Fiscal 2017
	Quarter Ended
	December 31			March 31		June 30			September 30
Revenues	$	7,036,643		$	13,964,288	$	12,437,186		$	12,896,932
Income (loss) before provision for    income taxes	$	(3,345,392	)	$	4,273,433	$	1,827,758		$	1,465,134
Net income (loss)	$	(2,238,392	)	$	3,470,433	$	1,260,758		$	1,039,134
Earnings (loss) per share	$	(0.13	)	$	0.21	$	0.07		$	0.06

(93)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

13. SUBSEQUENT EVENTS (AUDITED)

On November 30, 2018, the Company closed on a mineral acreage sale of 206 net mineral acres in Lea and Eddy Counties, New Mexico. The sale price was $9.3 million or approximately $45,000 per acre. The proceeds will initially be used to reduce the Company’s bank debt. This sale represents 0.08% of the Company’s total net mineral acreage position, 0.7% of total production and 0.9% of total revenues for fiscal year 2018. This sale also includes 1.2% of our total proved reserves as of September 30, 2018.

These minerals had no net book value at September 30, 2018,and the total value received less any post-closing adjustments will be a gain on the sale of assets in the Company’s first quarter of 2019.

(94)

ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A CONTROLS AND PROCEDURES

(a)       EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The Company maintains “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including the Company’s President/CEO and Vice President/CFO, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The Company’s disclosure controls and procedures have been designed to meet, and management believes that they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this report, the Chief Executive Officer and Chief Financial Officer have concluded that, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective.

(b)       MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Company’s management is responsible for establishing and maintaining adequate “internal control over financial reporting,” as such term is defined in Exchange Act Rule 13a-15(f). The Company’s management, including the President/CEO and Vice President/CFO, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the Company’s management concluded that its internal control over financial reporting was effective as of September 30, 2018.

(c)       CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter ended September 30, 2018, or subsequent to the date the assessment was completed.

ITEM 9B OTHER INFORMATION

None

(95)

PART III

The information called for by Part III of Form 10-K (Item 10 – Directors and Executive Officers of the Registrant, Item 11 – Executive Compensation, Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 13 – Certain Relationships and Related Transactions, and Item 14 – Principal Accountant Fees and Services), is incorporated by reference from the Company’s definitive proxy statement, which will be filed with the SEC within 120 days after the end of the fiscal year to which this report relates.

(96)

PART IV

ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

FINANCIAL STATEMENT SCHEDULES

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

EXHIBITS

(3)	Amended Certificate of Incorporation (incorporated by reference to Exhibit attached to Form 10 filed January 27, 1980, and to Forms 8-K dated June 1, 1982, December 3, 1982, to Form 10-QSB dated March 31, 1999, and to Form 10-Q dated March 31, 2007)
	By-Laws as amended (incorporated by reference to Forms 8-K dated October 31, 1994, February 24, 2006, October 29, 2008, August 2, 2011, December 11, 2013, January 19, 2017, and April 3, 2018)
(4)	Instruments defining the rights of security holders (incorporated by reference to Certificate of Incorporation and By-Laws listed above)
*(10.1)	Agreement indemnifying directors and officers (incorporated by reference to Form 10-K dated September 30, 1989, and Form 8-K dated June 15, 2007)
*(10.2)	Agreements to provide certain severance payments and benefits to executive officers should a Change-in-Control occur as defined by the agreements (incorporated by reference to Form 8-K dated September 4, 2007)
(10.3)	Amended and Restated Credit Agreement dated November 25, 2013 (incorporated by reference to Form 10-K dated December 11, 2013)
(10.4)	Second Amendment to Amended and Restated Credit Agreement and Joinder dated June 17, 2014 (incorporated by reference to Form 8-K dated June 19, 2014)
(10.5)	Third Amendment to Amended and Restated Credit Agreement and Joinder dated December 8, 2016 (incorporated by reference to Form 10-K dated December 12, 2017)
(10.6)	Fourth Amendment to Amended and Restated Credit Agreement and Joinder dated October 25, 2017 (incorporated by reference to Form 8-K dated October 26, 2017)
(10.7)	Fifth Amendment to Amended and Restated Credit Agreement and Joinder dated July 2, 2018 (incorporated by reference to Form 8-K dated July 2, 2018)
(12.1)	Statement of Computation of Ratio of Earnings to Fixed Charges
(23.1)	Consent of Ernst & Young, LLP
(23.2)	Consent of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants
(31.1)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(31.2)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

(97)

(32.1)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(32.2)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(99)	Report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants
(101.INS)	XBRL Instance Document
(101.SCH)	XBRL Taxonomy Extension Schema Document
(101.CAL)	XBRL Taxonomy Extension Calculation Linkbase Document
(101.LAB)	XBRL Taxonomy Extension Labels Linkbase Document
(101.PRE)	XBRL Taxonomy Extension Presentation Linkbase Document
(101.DEF)	XBRL Taxonomy Extension Definition Linkbase Document
*	Indicates management contract or compensatory plan or arrangement

REPORTS ON FORM 8-K

Form 8-K dated November 6, 2018; item 8.01 – Other Events

SIGNATURES

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

PANHANDLE OIL AND GAS INC.

By: /s/ Paul F. Blanchard Jr.

Paul F. Blanchard Jr.

Chief Executive Officer

Date:  December 11, 2018

(98)

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

Signature	Title	Date
/s/ Paul F. Blanchard Jr. Paul F. Blanchard Jr.	President, Chief Executive Officer, Director	December 11, 2018
/s/Robb P. Winfield Robb P. Winfield	Vice President, Chief Financial Officer and Controller	December 11, 2018
/s/ Mark T. Behrman Mark T. Behrman	Director	December 11, 2018
/s/ Lee M. Canaan Lee M. Canaan	Director	December 11, 2018
/s/ Peter B. Delaney Peter B. Delaney	Director	December 11, 2018
/s/ Robert O. Lorenz Robert O. Lorenz	Director	December 11, 2018
/s/ Robert E. Robotti Robert E. Robotti	Director	December 11, 2018
/s/ Chad L. Stephens III Chad L. Stephens III	Lead Independent Director	December 11, 2018

(99)

EX-12.1

EXHIBIT 12.1

Statement Computation Ratio Earnings to Fixed Charges

PANHANDLE OIL AND GAS INC.

RATIO OF EARNINGS TO FIXED CHARGES

	Fiscal Year Ended September 30,
	2014			2015			2016			2017			2018
Earnings
Income (loss) before income taxes		36,821,462			14,157,341			(17,997,884	)		4,220,933			1,896,669
Fixed charges		670,117			1,820,605			1,491,513			1,565,118			2,039,453
Amortization of capitalized interest		68,245			76,270			71,136			80,857			81,674
Interest capitalized		(172,499	)		(148,493	)		(24,929	)		(168,351	)		(89,023	)
Total Earnings		37,387,325			15,905,723			(16,460,164	)		5,698,557			3,928,773
Fixed Charges
Interest expensed		462,296			1,550,483			1,344,619			1,275,138			1,748,101
Interest capitalized		172,499			148,493			24,929			168,351			89,023
Amortization of capitalized expenses related to debt		35,322			121,629			121,965			121,629			202,329
Total Fixed charges		670,117			1,820,605			1,491,513			1,565,118			2,039,453
Ratio of Earnings to Fixed Charges		55.79			8.74		-       (1)				3.64			1.93

(1) For the fiscal year ended September 30, 2016, our earnings were insufficient to cover our fixed charges by $14,968,651.

EX-23.1

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-3 No. 333-221370) of Panhandle Oil and Gas Inc. and in the related Prospectus of our report dated December 11, 2018, with respect to the financial statements of Panhandle Oil and Gas Inc., and the effectiveness of internal control over financial reporting of Panhandle Oil and Gas Inc. included in this Annual Report (Form 10-K) for the year ended September 30, 2018.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

December 11, 2018

EX-23.2

EXHIBIT 23.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

December 10, 2018

Panhandle Oil and Gas Inc.

Grand Centre, Suite 300

5400 North Grand Blvd.

Oklahoma City, OK 73112

Ladies and Gentlemen:

We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton as independent petroleum engineers, and to the inclusion of information taken from the reports listed below in the Panhandle Oil and Gas Inc. Annual Report on Form 10-K (“the 10-K”):

• Report as of September 30, 2018 on Reserves and Revenue of Certain Properties with interests attributable to Panhandle Oil and Gas Inc.;

• Report as of September 30, 2017 on Certain Properties owned by Panhandle Oil and Gas Inc.; and

• Report as of September 30, 2016 on Certain Properties owned by Panhandle Oil and Gas Inc.

We further consent to the inclusion of our report of third party dated October 5, 2018, as Exhibit 99 in the 10-K.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Paul F. Blanchard Jr., certify that:

1. I have reviewed this annual report on Form 10- K of Panhandle Oil and Gas Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Paul F. Blanchard Jr.

Paul F. Blanchard Jr.

Chief Executive Officer

Date:   December 11, 2018

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Robb P. Winfield, certify that:

1. I have reviewed this annual report on Form 10- K of Panhandle Oil and Gas Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Robb P. Winfield

Robb P. Winfield

Chief Financial Officer

Date:   December 11, 2018

EX-32.1

Exhibit 32.1

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK  73112

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Paul F. Blanchard Jr., President and Chief Executive Officer of Panhandle Oil and Gas Inc. (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify in connection with the Company’s Annual Report on Form 10- K for the period that ended September 30, 2018, as filed with the Securities and Exchange Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Paul F. Blanchard Jr.

Paul F. Blanchard Jr.

President &

Chief Executive Officer

December 11, 2018

EX-32.2

Exhibit 32.2

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK  73112

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Robb P. Winfield, Vice President and Chief Financial Officer of Panhandle Oil and Gas Inc. (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify in connection with the Company’s Annual Report on Form 10- K for the period that ended September 30, 2018, as filed with the Securities and Exchange Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Robb P. Winfield

Robb P. Winfield

Vice President,

Chief Financial Officer and Controller

December 11, 2018

EX-99

EXHIBIT 99

DeGolyer and MacNaughton

5001 Spring Valley Road 

Suite 800 East

Dallas, Texas 75244 

October 5, 2018

Panhandle Oil and Gas Inc.

5400 North Grand Boulevard

Suite 300

Oklahoma City, Oklahoma 73112

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of September 30, 2018, of the extent and value of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which Panhandle Oil and Gas Inc. (Panhandle) has represented it holds an interest. This evaluation was completed on October 5, 2018. The properties evaluated herein are located in Arkansas, New Mexico, North Dakota, Oklahoma, Texas, and Utah. Panhandle has represented that these properties account for 100 percent of Panhandle’s net proved reserves as of September 30, 2018. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Panhandle.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after September 30, 2018. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Panhandle after deducting all interests held by others.

Values of proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated

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production taxes, advalorem taxes, operating expenses, transportation expenses, capital costs, and abandonment costs from the future gross revenue. Operating expenses include field operating expenses,processing expenses, and an allocation of overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and field maintenance costs. Abandonment costs are represented by Panhandle to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. At the request of Panhandle, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary nominal discount rate of 10percent compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Estimates of reserves and revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was obtained from Panhandle and from public sources. Additionally, this information included data supplied by IHS Markit Inc; Copyright 2018 IHS Markit Inc. In the preparation of this report we have relied, without independent verification, upon information furnished by Panhandle with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves estimated in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically

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DeGolyer and MacNaughton

producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) 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 gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be

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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.

(iv) 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:

(A) 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 (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) 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 gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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Undeveloped oil and gas reserves – Undeveloped oil and 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.

(i) Reserves on undrilled acreage shall be 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.

(ii) 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.

(iii) 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, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry, which are presented in the Petroleum Resources Management System and Monograph 3 and Monograph  4 published by the Society of Petroleum Evaluation Engineers.

A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (1) production diagnostics,
(2) decline-curve analysis, and (3) model-based analysis (if necessary, based on the availability of data). Production diagnostics include data quality control,

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DeGolyer and MacNaughton

identification of flow regimes, and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model‑based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history, and appropriate reserves definitions.

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

Based on the current stage of field development, production performance, the development plans provided by Panhandle, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. Proved undeveloped reserves were estimated for locations that have been permitted, are currently drilling, are drilled but not yet completed, or locations where the operator has indicated to Panhandle its intention to drill.

Panhandle has represented that its senior management is committed to the development plan provided by Panhandle and that Panhandle has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

Data provided by Panhandle from wells drilled through September 30, 2018, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through July 2018. Estimated cumulative production, as of September 30, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include C₅₊ and liquefied

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DeGolyer and MacNaughton

petroleum gas (LPG), which consist primarily of propane and butane fractions. NGL reserves are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in barrels (bbl) representing 42 United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel use and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. All gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state in which the reserves are located. Gas reserves included in this report are expressed in thousands of cubic feet (Mcf).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

The estimated net proved reserves, as of September 30, 2018, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of September 30, 2018
	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)
Proved Developed Producing	2,212	2,069	82,398
Proved Developed Non-Producing	122	17	754
Total Proved Developed	2,334	2,086	83,152
Proved Undeveloped	3,650	848	36,910
Total Proved	5,984	2,934	120,062

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Primary Economic Assumptions

Revenue values in this report were estimated using initial prices, expenses, and costs provided by Panhandle. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:

Oil, Condensate, and NGL Prices

Panhandle has represented that the oil, condensate and NGL prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Panhandle supplied differentials to the West Texas Intermediate (WTI) oil reference price of $63.27 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to the estimated reserves over the lives of the properties was $62.86 per barrel of oil and condensate and $26.13 per barrel of NGL.

Gas Prices

Panhandle has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Panhandle supplied differentials to the Henry Hub gas reference price of $2.91 per million Btu (MMBtu). The prices were held constant thereafter. Btu factors provided by Panhandle were used to convert prices from dollars per MMBtu to dollars per thousand cubic feet ($/Mcf). The volume-weighted average gas price attributable to the estimated reserves was $2.558 per thousand cubic feet.

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DeGolyer and MacNaughton

Production and Ad Valorem Taxes

Production taxes were calculated using the tax rates for each state in which the reserves are located, including, where appropriate, abatements for enhanced recovery programs. Ad valorem taxes were estimated using rates provided by Panhandle based on historical payments.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses, provided by Panhandle and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2018 values, provided by Panhandle, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of the wells, and reclamation and restoration associated with the abandonment, were provided by Panhandle for all properties.

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of September 30, 2018, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):

	Proved Developed Producing (M$)	Proved Developed Non-Producing (M$)	Total Proved Developed (M$)	Proved Undeveloped (M$)	Total Proved (M$)
Future Gross Revenue	398,848	10,406	409,254	350,645	759,899
Production and Ad Valorem Taxes	23,365	615	23,980	20,636	44,616
Operating and Transportation Expenses	144,012	2,225	146,237	68,561	214,798
Capital and Abandonment Costs	1,984	165	2,149	87,369	89,518
Future Net Revenue	229,487	7,401	236,888	174,079	410,967
Present Worth at 10 Percent	120,788	5,128	125,916	78,657	204,573
Note: Future income taxes have not been taken into account in the preparation of these estimates.

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In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas of the properties reviewed by us contained in this report has been prepared in accordance with Paragraphs 932‑235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932‑235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X andRules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the September 30, 2018, estimated reserves.

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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Panhandle. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Panhandle. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTONTexas Registered Engineering Firm F-716

/s/ Gregory K. Graves

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Panhandle dated
October 5, 2018, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

2. That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 34 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Gregory K. Graves

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

XML

Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2018	Dec. 01, 2018	Mar. 31, 2018
Document Information [Line Items]
Entity Registrant Name	PANHANDLE OIL & GAS INC
Entity Central Index Key	0000315131
Trading Symbol	PHX
Document Type	10-K
Document Period End Date	Sep. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 303,874,080
Class A Common Stock [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		16,751,414
Class B Common Stock [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		0

XML

Balance Sheets - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Current Assets:
Cash and cash equivalents	$ 532,502	$ 557,791
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)	7,101,629	7,585,485
Refundable income taxes	33,165	489,945
Derivative contracts, net		544,924
Assets held for sale		557,750
Other	578,880	253,480
Total current assets	8,246,176	9,989,375
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties	427,448,584	434,571,516
Non-producing oil and natural gas properties	12,563,519	7,428,927
Other	1,529,770	1,067,894
Gross properties and equipment, at cost, based on successful efforts accounting	441,541,873	443,068,337
Less accumulated depreciation, depletion and amortization	(243,257,472)	(246,483,979)
Net properties and equipment	198,284,401	196,584,358
Investments	219,109	170,486
Total assets	206,749,686	206,744,219
Current Liabilities:
Accounts payable	881,130	1,847,230
Derivative contracts, net	3,064,046
Accrued liabilities and other	1,791,950	1,690,789
Total current liabilities	5,737,126	3,538,019
Long-term debt	51,000,000	52,222,000
Deferred income taxes	18,088,007	31,051,007
Asset retirement obligations	2,809,378	3,196,889
Derivative contracts, net	349,970	28,765
Stockholders' equity:
Class A voting common stock, $0.0166 par value; 24,000,000 shares authorized; 16,896,881 issued at September 30, 2018; 16,863,004 issued at September 30, 2017	281,502	280,938
Capital in excess of par value	2,824,691	2,726,444
Deferred directors' compensation	2,950,405	3,459,909
Retained earnings	125,266,945	113,330,216
Stockholders' Equity	131,323,543	119,797,507
Treasury stock, at cost; 145,467 shares at September 30, 2018; 184,988 shares at September 30, 2017	(2,558,338)	(3,089,968)
Total stockholders' equity	128,765,205	116,707,539
Total liabilities and stockholders' equity	$ 206,749,686	$ 206,744,219

XML

Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2018	Sep. 30, 2017
Statement Of Financial Position [Abstract]
Common stock, par value	$ 0.0166	$ 0.0166
Common stock, shares authorized	24,000,000	24,000,000
Common stock, shares issued	16,896,881	16,863,004
Treasury stock, shares	145,467	184,988

XML

Statements Of Operations - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017		Sep. 30, 2016
Revenues:
Revenues	$ 45,034,264	$ 46,335,049		$ 39,060,783
Lease bonuses and rentals	1,580,997	5,149,297		7,735,785
Gains (losses) on derivative contracts	(4,932,068)	1,249,840		(86,355)
Costs and expenses:
Lease operating expenses	13,460,278	12,682,969		13,590,089
Production taxes	2,089,050	1,548,399		1,071,632
Depreciation, depletion and amortization	18,395,040	18,397,548		24,487,565
Provision for impairment	0	662,990	[1]	12,001,271	[1]
Loss (gain) on asset sales and other	102,685	105,830		(2,576,237)
Interest expense	1,748,101	1,275,138		1,344,619
General and administrative	7,342,441	7,441,242		7,139,728
Total costs and expenses	43,137,595	42,114,116		57,058,667
Income (loss) before provision (benefit) for income taxes	1,896,669	4,220,933		(17,997,884)
Provision (benefit) for income taxes	(12,739,000)	689,000		(7,711,000)
Net income (loss)	$ 14,635,669	$ 3,531,933		$ (10,286,884)
Basic and diluted earnings (loss) per common share	$ 0.86	$ 0.21		$ (0.61)
Oil, NGL and Natural Gas [Member]
Revenues:
Revenues	$ 48,385,335	$ 39,935,912		$ 31,411,353

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

XML

Statements Of Stockholders' Equity - USD ($)	Total	Class A voting Common Stock [Member]	Capital in Excess of Par Value [Member]	Deferred Directors' Compensation [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Balances at Sep. 30, 2015	$ 127,004,675	$ 280,938	$ 2,993,119	$ 3,084,289	$ 125,446,473	$ (4,800,144)
Balances, shares at Sep. 30, 2015		16,863,004
Balances, Treasury shares at Sep. 30, 2015						(302,623)
Purchase of treasury stock	(117,165)					$ (117,165)
Purchase of treasury stock, shares						(7,477)
Issuance of treasury shares to ESOP	200,158		19,068			$ 181,090
Issuance of treasury shares to ESOP, shares						11,418
Restricted stock awards	781,479		781,479
Distribution of restricted stock to officers and directors	(42,604)		(601,779)			$ 559,175
Distribution of restricted stock to officers and directors, shares						35,257
Distribution of deferred directors' compensation			(831)	(10,541)		$ 11,372
Distribution of deferred directors' compensation, shares						717
Common shares to be issued to directors for services	329,465			329,465
Dividends declared ($0.16 per share)	(2,677,305)				(2,677,305)
Net income (loss)	(10,286,884)				(10,286,884)
Balances at Sep. 30, 2016	115,191,819	$ 280,938	3,191,056	3,403,213	112,482,284	$ (4,165,672)
Balances, shares at Sep. 30, 2016		16,863,004
Balances, Treasury shares at Sep. 30, 2016						(262,708)
Purchase of treasury stock	(601,853)					$ (601,853)
Purchase of treasury stock, shares						(25,742)
Issuance of treasury shares to ESOP	312,380		93,192			$ 219,188
Issuance of treasury shares to ESOP, shares						13,125
Restricted stock awards	597,940		597,940
Distribution of restricted stock to officers and directors	663		(1,010,275)			$ 1,010,938
Distribution of restricted stock to officers and directors, shares						63,121
Distribution of deferred directors' compensation			(145,469)	(301,962)		$ 447,431
Distribution of deferred directors' compensation, shares						27,216
Common shares to be issued to directors for services	358,658			358,658
Dividends declared ($0.16 per share)	(2,684,001)				(2,684,001)
Net income (loss)	3,531,933				3,531,933
Balances at Sep. 30, 2017	$ 116,707,539	$ 280,938	2,726,444	3,459,909	113,330,216	$ (3,089,968)
Balances, shares at Sep. 30, 2017		16,863,004
Balances, Treasury shares at Sep. 30, 2017	(184,988)					(184,988)
Purchase of treasury stock	$ (1,219,228)					$ (1,219,228)
Purchase of treasury stock, shares						(63,404)
Issuance of treasury shares to ESOP	382,174		19,509			$ 362,665
Issuance of treasury shares to ESOP, shares						20,632
Restricted stock awards	655,414		655,414
Distribution of restricted stock to officers and directors	862	$ 21	(845,788)			$ 846,629
Distribution of restricted stock to officers and directors, shares		1,278				50,455
Distribution of deferred directors' compensation		$ 543	269,112	(811,219)		$ 541,564
Distribution of deferred directors' compensation, shares		32,599				31,838
Common shares to be issued to directors for services	301,715			301,715
Dividends declared ($0.16 per share)	(2,698,940)				(2,698,940)
Net income (loss)	14,635,669				14,635,669
Balances at Sep. 30, 2018	$ 128,765,205	$ 281,502	$ 2,824,691	$ 2,950,405	$ 125,266,945	$ (2,558,338)
Balances, shares at Sep. 30, 2018		16,896,881
Balances, Treasury shares at Sep. 30, 2018	(145,467)					(145,467)

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Statements Of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Statement Of Stockholders Equity [Abstract]
Dividends per share	$ 0.16	$ 0.16	$ 0.16

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Statements Of Cash Flows - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017		Sep. 30, 2016
Operating Activities
Net income (loss)	$ 14,635,669	$ 3,531,933		$ (10,286,884)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	18,395,040	18,397,548		24,487,565
Impairment	0	662,990	[1]	12,001,271	[1]
Provision for deferred income taxes	(12,963,000)	375,000		(9,960,000)
Gain from leasing fee mineral acreage	(1,520,262)	(5,147,957)		(7,732,023)
Proceeds from leasing fee mineral acreage	1,564,225	5,194,290		8,049,434
Net (gain) loss on sales of assets	660,597	94,889		(2,688,408)
Common stock contributed to ESOP	382,174	312,380		200,158
Common stock (unissued) to Directors' Deferred Compensation Plan	301,715	358,658		329,465
Fair value of derivative contracts	3,930,175	(944,430)		4,639,035
Restricted stock awards	655,414	597,940		781,479
Other	6,326	(5,783)		81,606
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	483,856	(2,298,256)		2,589,146
Refundable income taxes	456,780	(406,071)		262,023
Other current assets	57,752	165,557		308,980
Accounts payable	(140,600)	(103,389)		(811,749)
Other non-current assets	(62,295)
Accrued liabilities	100,328	(27,107)		388,053
Total adjustments	12,308,225	17,226,259		32,926,035
Net cash provided by operating activities	26,943,894	20,758,192		22,639,151
Investing Activities
Capital expenditures, including dry hole costs	(11,590,135)	(25,807,897)		(3,986,235)
Acquisition of minerals and overrides	(11,327,371)
Investments in partnerships	3,354	(23,563)		50,126
Proceeds from sales of assets	1,085,137	723,700		4,501,726
Net cash used in investing activities	(21,829,015)	(25,107,760)		565,617
Financing Activities
Borrowings under debt agreement	29,017,800	27,809,185		12,339,101
Payments of loan principal	(30,239,800)	(20,087,185)		(32,839,101)
Purchases of treasury stock	(1,219,228)	(601,853)		(117,165)
Payments of dividends	(2,698,940)	(2,684,001)		(2,677,305)
Excess tax benefit on stock-based compensation				(43,000)
Net cash provided by (used in) financing activities	(5,140,168)	4,436,146		(23,337,470)
Increase (decrease) in cash and cash equivalents	(25,289)	86,578		(132,702)
Cash and cash equivalents at beginning of year	557,791	471,213		603,915
Cash and cash equivalents at end of year	532,502	557,791		471,213
Supplemental Disclosures of Cash Flow Information
Interest paid (net of capitalized interest)	1,730,461	1,212,878		1,365,474
Income taxes paid (net of refunds received)	(232,782)	720,072		2,029,977
Supplemental schedule of noncash investing and financing activities:
Additions and revisions, net, to asset retirement obligations	17,216	624,893		14,095
Gross additions to properties and equipment	21,711,279	25,406,894		5,118,733
Net (increase) decrease in accounts payable for properties and equipment additions	1,206,227	401,003		(1,132,498)
Capital expenditures, including dry hole costs	$ 22,917,506	$ 25,807,897		$ 3,986,235

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

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Summary Of Significant Accounting Policies

12 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Through management of its fee mineral and leasehold acreage, the Company’s principal line of business is to explore for, develop, acquire, produce and sell oil, NGL and natural gas. Panhandle’s mineral and leasehold properties and other oil and natural gas interests are all located in the contiguous United States, primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas, with properties located in several other states. The Company’s oil, NGL and natural gas production is from interests in 6,079 wells located principally in Arkansas, Oklahoma and Texas. The Company does not operate any wells. Approximately 45% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2018. Approximately 71% of the Company’s total sales volumes in 2018 were derived from natural gas. Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells. From time to time, the Company sells certain non-material, non-core or small-interest oil and natural gas properties in the normal course of business.

Use of Estimates

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

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

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

Cash and Cash Equivalents

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

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

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

The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves. At September 30, 2018 and 2017, the Company had no material natural gas imbalances.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers of oil, NGL and natural gas or operators of the oil and natural gas properties. Oil, NGL and natural gas sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our oil, NGL and natural gas and the operators of the properties in which we have an interest may be similarly affected by changes in economic, industry or other conditions. During 2018, 2017 and 2016 the Company did not have any bad debt expense. The Company’s allowance for uncollectible accounts as of the Balance Sheet dates was not material.

Oil and Natural Gas Producing Activities

The Company follows the successful efforts method of accounting for oil and natural gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income, if and when the well does not reach commercial production levels. Oil and natural gas mineral and leasehold costs are capitalized when incurred.

It is common business practice in the petroleum industry to prepay drilling costs before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2018, the Company had no outstanding letters of credit.

Leasing of Mineral Rights

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

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

Derivatives

The Company has entered into fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts at September 30, 2018 and 2017, were with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of September 30, 2018

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
April - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.15 ceiling
Natural gas fixed price swaps
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
April - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.910
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.835
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.925
July - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.988
July 2018 - March 2019	50,000 Mmbtu	NYMEX Henry Hub	$3.065
January - July 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.867
Oil costless collars
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$50.00 floor / $55.75 ceiling
July - December 2018	3,000 Bbls	NYMEX WTI	$50.00 floor / $58.00 ceiling
January - June 2019	2,000 Bbls	NYMEX WTI	$55.00 floor / $63.45 ceiling
January - December 2019	1,000 Bbls	NYMEX WTI	$50.00 floor / $60.00 ceiling
January - December 2019	2,000 Bbls	NYMEX WTI	$60.00 floor / $69.25 ceiling
July - December 2019	3,000 Bbls	NYMEX WTI	$60.00 floor / $70.75 ceiling
January - June 2020	2,000 Bbls	NYMEX WTI	$60.00 floor / $67.00 ceiling
Oil fixed price swaps
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02
April - December 2018	4,000 Bbls	NYMEX WTI	$54.14
July - December 2018	2,000 Bbls	NYMEX WTI	$58.20
January - June 2019	2,000 Bbls	NYMEX WTI	$59.69
January - June 2019	2,000 Bbls	NYMEX WTI	$57.15
January - June 2019	3,000 Bbls	NYMEX WTI	$58.02
January - December 2019	1,000 Bbls	NYMEX WTI	$56.15
January - December 2019	2,000 Bbls	NYMEX WTI	$56.71
January - December 2019	1,000 Bbls	NYMEX WTI	$58.56
July - December 2019	2,000 Bbls	NYMEX WTI	$56.85

Derivative contracts in place as of September 30, 2017

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.65 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $3.65 ceiling
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
January - March 2018	150,000 Mmbtu	NYMEX Henry Hub	$3.40 floor / $3.95 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
Natural gas fixed price swaps
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.210
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.300
July - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.510
August - December 2017	100,000 Mmbtu	NYMEX Henry Hub	$3.095
January - March 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.700
January - March 2018	75,000 Mmbtu	NYMEX Henry Hub	$3.575
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.520
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
Oil costless collars
January - December 2017	3,000 Bbls	NYMEX WTI	$50.00 floor / $55.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$52.00 floor / $58.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$53.00 floor / $57.75 ceiling
April - December 2017	2,000 Bbls	NYMEX WTI	$50.00 floor / $57.50 ceiling
July - December 2017	5,000 Bbls	NYMEX WTI	$45.00 floor / $56.25 ceiling
January - June 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.75 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
Oil fixed price swaps
January - December 2017	3,000 Bbls	NYMEX WTI	$53.89
April - December 2017	2,000 Bbls	NYMEX WTI	$54.20
January - March 2018	4,000 Bbls	NYMEX WTI	$54.00
January - June 2018	4,000 Bbls	NYMEX WTI	$51.25
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02

The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $3,414,016 as of September 30, 2018, and a net asset of $516,159 as of September 30, 2017. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations. The portion of the gain (loss) on derivatives settled in cash for 2018, 2017 and 2016 was $1,001,893 (net paid), $305,410 (net received) and $4,552,680 (net received), respectively.

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on, or termination of, any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Balance Sheets. The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Balance Sheets at September 30, 2018, and September 30, 2017. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2018, and September 30, 2017.

	9/30/2018								9/30/2017
	Fair Value								Fair Value
	Commodity Contracts								Commodity Contracts
	CurrentAssets			Current Liabilities			Non-Current Liabilities		CurrentAssets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	42,150		$	3,106,196		$	349,970	$	735,702		$	190,778		$	9,439		$	38,204
Offsetting adjustments		(42,150	)		(42,150	)		-		(190,778	)		(190,778	)		(9,439	)		(9,439	)
Net presentation on Balance Sheets	$	-		$	3,064,046		$	349,970	$	544,924		$	-		$	-		$	28,765

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

Fair Value Measurements

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels.

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and, as of the fourth quarter of 2018, commodity options (i.e. price collars).

The Company uses an option pricing valuation model for option derivative contracts that considers various inputs including: future prices, time value, volatility factors, counterparty credit risk and current market and contractual prices for the underlying instruments. The values calculated are then compared to the values given by counterparties for reasonableness.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and unobservable (or less observable) from objective sources (supported by little or no market activity).

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

	Fair Value Measurement at September 30, 2018
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs		TotalFair
	(Level 1)		(Level 2)			(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(2,317,069	)	$	-	$	(2,317,069	)
Derivative Contracts - Collars	$	-	$	(1,096,947	)	$	-	$	(1,096,947	)

	Fair Value Measurement at September 30, 2017
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	364,606	$	-	$	364,606
Derivative Contracts - Collars	$	-	$	-	$	151,553	$	151,553

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

	Derivatives
Net Asset (Liability) Balance of Level 3 as of October 1, 2017	$	151,553
Total gains or (losses):
Included in earnings		(877,307	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(371,193	)
Transfers in and out of Level 3 (i)		1,096,947
Net Asset (Liability) Balance of Level 3 as of September 30, 2018	$	-

(i) During the fourth quarter of 2018, we transferred $1,096,947 of derivative collars out of Level 3 hierarchy, into Level 2 hierarchy as a result of our ability to obtain volatility inputs from direct observable sources.

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

	Year Ended September 30,
	2018				2017				2016
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	567,077	$	662,990	$	9,877,905	$	12,001,271

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

At September 30, 2018, and September 30, 2017, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short term maturities of those instruments. Financial instruments include long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

Properties and Equipment

Depreciation, Depletion and Amortization

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

Non-producing oil and natural gas properties include non-producing minerals, which had a net book value of $8,025,015 and $3,079,008 at September 30, 2018 and 2017, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 92-year life of the Company. There are approximately 198,360 net acres of non-producing minerals in more than 6,749 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $62. Since inception, the Company has continually generated an interest in several thousand oil and natural gas wells using its ownership of the fee mineral acres as an ownership basis. There continues to be significant drilling and leasing activity on these mineral interests each year. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (as do oil and natural gas leases). Given the above, management concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.

Impairment

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing thefair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company or fair value (sales price) less cost to sell if the property is held for sale. The Company's estimate of fair value of its oil and natural gas properties at September 30, 2018, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $0, $662,990 and $12,001,271 for 2018, 2017 and 2016, respectively. A further reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company. 

Divestitures

During the 2018 fiscal year, the Company sold 324 non-core marginal wells for $1,085,137 and recorded a loss on the sales of $660,597. The total net book value that was removed from the Balance Sheets due to these sales was approximately $1.7 million. The loss on sales was included in the Loss (gain) on asset sales and other line of the Statements of Operations. All of the wells included in the Assets held for sale line item on the Balance Sheets at September 30, 2017, were sold during the first quarter of 2018.

Acquisitions

During the 2018 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 4,306 net mineral acres for $11.3 million or an average of approximately $2,600 per net mineral acre. These mineral purchases were accounted for as asset acquisitions.

Capitalized Interest

During 2018, 2017 and 2016, interest of $89,023, $168,351 and $24,929, respectively, was included in the Company’s capital expenditures. Interest of $1,748,101, $1,275,138 and $1,344,619, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the unit-of-production method.

Asset Retirement Obligations

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

The following table shows the activity for the years ended September 30, 2018 and 2017, relating to the Company’s asset retirement obligations:

	2018			2017
Asset retirement obligations as of beginning of the year	$	3,196,889		$	2,958,048
Wells acquired or drilled		17,215			114,766
Wells sold or plugged		(542,892	)		(548,634	)
Revisions in estimated cash flows		-			536,536
Accretion of discount		138,166			136,173
Asset retirement obligations as of end of the year	$	2,809,378		$	3,196,889

The revisions in estimated cash flows in fiscal 2017 were due to increased plugging charges noted recently that were higher than previously estimated. As a non-operator, we do not control the plugging of wells in which we have a working interest and are not involved in the negotiation of the terms of the plugging contracts. Our estimate relies on information that we can gather from outside sources as well as relevant information that we receive directly from operators.

Environmental Costs

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

Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2018 and 2017, there were no such costs accrued.

Earnings (Loss) Per Share of Common Stock

Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period.

Share-based Compensation

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

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

Restricted stock awards to officers provide for cliff vesting at the end of three years from the date of the awards. These restricted stock awards can be granted based on service time only (non-performance based) or subject to certain share price performance standards (performance based). Restricted stock awards to the non-employee directors provide for quarterly vesting during the calendar year of the award. The fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance.

Income Taxes

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

The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduces the U.S. federal corporate tax rate from 35% to 21%, requires companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously tax deferred and creates new taxes on certain foreign sourced earnings. As of September 30, 2018, we have completed our estimates accounting for the tax effects of enactment of the Act. Based on these estimates, we recognized an amount which is included as a component of income tax expense (benefit) from continuing operations.

We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The amount recorded related to the remeasurement of our deferred tax balance was $12,464,000 income tax benefit.

The Company has a year end of September 30. Because this differs from a calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The impact of using a blended rate versus the old rate in the current year resulted in a federal tax benefit of $198,581.

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended September 30, 2018, was a 672% benefit as compared to a 16% provision for the year ended September 30, 2017.

The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2015.

The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Operations. For fiscal September 30, 2018, 2017 and 2016, the Company’s interest and penalties was not material. The Company does not believe it has any significant uncertain tax positions.

Adoption of New Accounting Pronouncements

In January 2017, the FASB issued ASU 2017-01, which changed the definition of a business. The new guidance requires an entity to first evaluate whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets. If that threshold is met, the set of assets and activities is not a business. If it’s not met, the entity evaluates whether the set meets the definition of a business. The new definition requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue recognition guidance. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. The ASU was applied prospectively to transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods for which the financial statements have not been issued or made available for issuance. The Company early adopted ASU 2017-01 during the third quarter ended June 30, 2018.

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. The guidance is effective for us beginning October 1, 2019, including interim periods within the fiscal year. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this update will have on our financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for us beginning October 1, 2018, including interim periods within the fiscal year. This update is not expected to have a material impact on our financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services.

Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis.

The standard is effective for us beginning October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements and utilizes a cumulative effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Panhandle intends to use the modified retrospective method upon adoption.

The Company has completed its evaluation of the impact of the new standard and related interpretive guidance on its financial statements, accounting policies, internal controls, and disclosures. Based on our assessments, the standard is not expected to have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures and internal controls over financial reporting.

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

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Commitments

12 Months Ended

Sep. 30, 2018

Commitments And Contingencies Disclosure [Abstract]

Commitments

2. COMMITMENTS

The Company leases office space in Oklahoma City, Oklahoma, under the terms of an operating lease expiring in April 2020. Future minimum rental payments under the terms of the lease are $210,273, $122,659 and $0 in 2019, 2020 and 2021, respectively. Total rent expense incurred by the Company was $215,803 in 2018, $206,366 in 2017 and $202,083 in 2016.

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Income Taxes

12 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

3. INCOME TAXES

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

	2018			2017			2016
Current:
Federal	$	204,000		$	314,000		$	2,166,000
State		20,000			-			83,000
		224,000			314,000			2,249,000
Deferred:
Federal		(13,240,000	)		390,000			(8,597,000	)
State		277,000			(15,000	)		(1,363,000	)
		(12,963,000	)		375,000			(9,960,000	)
	$	(12,739,000	)	$	689,000		$	(7,711,000	)

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

	2018			2017			2016
Provision (benefit) for income taxes at statutory rate	$	465,253		$	1,477,327		$	(6,299,259	)
Percentage depletion		(577,780	)		(570,801	)		(395,649	)
State income taxes, net of federal provision (benefit)		36,980			3,900			(683,800	)
Effect of graduated rates		-			85,644			(86,745	)
Restricted stock tax benefit		(69,000	)		(238,000	)		-
Deferred directors compensation benefit		(134,000	)		(79,000	)		-
Law change (a)		(12,464,000	)		-			-
Other		3,547			9,930			(245,547	)
	$	(12,739,000	)	$	689,000		$	(7,711,000	)

(a) This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21%.

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

	2018		2017
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible    drilling costs capitalized for financial purposes and    expensed for tax purposes	$	24,560,165	$	38,185,387
Derivative contracts		-		200,786
		24,560,165		38,386,173
Deferred tax assets:
State net operating loss carry forwards		551,435		655,741
AMT credit carry forwards		2,936,457		3,499,320
Deferred directors' compensation		725,971		1,295,333
Restricted stock expense		249,610		411,019
Derivative contracts		878,767		-
Statutory depletion carry forwards		-		634,405
Other		1,129,918		839,348
		6,472,158		7,335,166
Net deferred tax liabilities	$	18,088,007	$	31,051,007

At September 30, 2018, the Company had a deferred tax asset of $497,752 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring from 2031 to 2037. There is no valuation allowance for the OK NOL’s, as management believes they will be utilized before they expire.

The AMT carry forwards do not have an expiration date. The corporate alternative minimum tax was repealed by The Tax Cuts and Jobs Act (enacted on December 22, 2017). Taxpayers with AMT credit carryovers can use the credits to offset regular tax liability for any taxable year. In addition, the AMT credit is refundable in any taxable year beginning after 2017 and before 2022 in an amount equal to 50% (100% in the case of taxable years beginning in 2021) of the excess of the minimum tax credit for the taxable year over the amount of the credit allowable for the year against regular tax liability. Thus, the Company’s entire AMT credit carryforward amounts are fully refundable by 2023.

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Long-Term Debt

12 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Long-Term Debt

4. LONG-TERM DEBT

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2022. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties with a net book value of $135,994,289 at September 30, 2018. The interest rate is based on BOK prime plus from 0.50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At September 30, 2018, the effective interest rate was 4.34%.

The Company’s debt is recorded at the carrying amount on its balance sheet. The carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates.

Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the banks, in their sole discretion, believe that there has been a material change in the value of the Company’s oil and natural gas properties. The borrowing base for the credit facility was redetermined in July 2018 by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants, which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of treasury stock. The loan agreement sets limits on dividend payments and stock repurchases if those payments would cause the leverage ratio to go above 2.75 to 1.0. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by the bank agreement – current assets includes availability under outstanding credit facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing 12 months as defined by bank agreement – traditional EBITDA with the unrealized gain or loss on derivative contracts also removed from earnings) of no more than 4.0 to 1.0. At September 30, 2018, the Company was in compliance with the covenants of the loan agreement and had $29,000,000 of availability under its outstanding credit facility.

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Stockholders' Equity

12 Months Ended

Sep. 30, 2018

Stockholders Equity Note [Abstract]

Stockholders' Equity

5. STOCKHOLDERS’ EQUITY

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in May 2018, the board of directors approved to continue to allow management to repurchase up to $1.5 million of the Company’s common stock at their discretion. The repurchase of an additional $1.5 million of the Company’s common stock continues to be authorized and approved effective when the previous amount is utilized. The Board added language to clarify that this is intended to be an evergreen provision. The number of shares allowed to be purchased by the Company under the repurchase program is no longer capped at an amount equal to the aggregate number of shares of common stock (i) awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. As of September 30, 2018, $1,219,228 had been spent to purchase 63,404 shares. The shares are held in treasury and are accounted for using the cost method.

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Earnings (Loss) Per Share

12 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Earnings (Loss) Per Share

6. EARNINGS (LOSS) PER SHARE

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

	Year ended September 30,
	2018		2017		2016
Numerator for basic and diluted earnings (loss) per share:
Net income (loss)	$	14,635,669	$	3,531,933	$	(10,286,884	)
Denominator for basic and diluted earnings per share:
Weighted average shares (including for 2018, 2017    and 2016, unissued, vested directors' shares of    205,736, 253,603 and 263,057, respectively)		16,952,664		16,900,185		16,840,856

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Employee Stock Ownership Plan

12 Months Ended

Sep. 30, 2018

Share Based Arrangements To Obtain Goods And Services [Abstract]

Employee Stock Ownership Plan

7. EMPLOYEE STOCK OWNERSHIP PLAN

The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan that serves as the sole retirement plan for all its employees to which the Company makes contributions. Company contributions are made at the discretion of the Board and, to date, all contributions have been made in shares of Company Common Stock. The Company contributions are allocated to all ESOP participants in proportion to their compensation for the plan year, and 100% vesting occurs after three years of service. Any shares that do not vest are treated as forfeitures and are distributed among other vested employees. For contributions of Common Stock, the Company records as expense the fair market value of the stock contributed. Compensation expense is equal to the contributions for each year. The 247,667 shares of the Company’s Common Stock held by the plan as of September 30, 2018, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings-per-share computations and receive dividends.

Contributions to the plan consisted of:

Year	Shares		Amount
2018		20,632	$	382,174
2017		13,125	$	312,380
2016		11,418	$	200,158

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Deferred Compensation Plan For Directors

12 Months Ended

Sep. 30, 2018

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Deferred Compensation Plan For Directors

8. DEFERRED COMPENSATION PLAN FOR DIRECTORS

Annually, independent directors may elect to be included in the Panhandle Oil and Gas Inc. Deferred Directors’ Compensation Plan for Non-Employee Directors (the “Plan”). The Plan provides that each independent director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees, and may elect to receive shares, when issued, over annual time periods up to ten years. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director under the Plan be issued to the director. The promise to issue such shares in the future is an unsecured obligation of the Company. As of September 30, 2018, there were 212,574 shares (261,846 shares at September 30, 2017) recorded under the Plan. The deferred balance outstanding at September 30, 2018, under the Plan was $2,950,405 ($3,459,909 at September 30, 2017). Expenses totaling $301,715, $358,658 and $329,465 were charged to the Company’s results of operations for the years ended September 30, 2018, 2017 and 2016, respectively, and are included in general and administrative expense in the accompanying Statement of Operations.

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Restricted Stock Plan

12 Months Ended

Sep. 30, 2018

Restricted Stock Plan [Abstract]

Restricted Stock Plan

9. RESTRICTED STOCK PLAN

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (“2010 Stock Plan”), which made available 200,000 shares of Common Stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, is designed to provide as much flexibility as possible for future grants of restricted stock so the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

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

In December 2010, the Company also began awarding shares of the Company’s Common Stock, subject to certain share price performance standards (performance based), as restricted stock to certain officers. Vesting of these shares is based on the performance of the market price of the Common Stock over the vesting period. The fair value of the performance shares was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period regardless of whether performance shares are awarded at the end of the vesting period. Should the awards vest, they are expected to be issued out of shares held in treasury.

In May 2014, the Company also began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to its non-employee directors. The restricted stock vests quarterly during the calendar year of the award and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares was based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.

Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur.

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2018, 2017 and 2016, related to the Company’s performance based and non-performance based restricted stock.

	Year Ended September 30,
	2018		2017		2016
Performance based, restricted stock	$	276,272	$	233,122	$	390,655
Non-performance based, restricted stock		379,142		364,818		390,824
Total compensation expense	$	655,414	$	597,940	$	781,479

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

	Unrecognized Compensation Cost		Weighted AveragePeriod (in years)
Performance based, restricted stock	$	321,389		1.79
Non-performance based, restricted stock		274,666		1.50
Total	$	596,055

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

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

	Performance Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Non- Performance BasedUnvested Restricted Shares			Weighted Average Grant-Date Fair Value
Unvested shares as of September 30,    2015		112,251		$	9.20		39,966		$	16.56
Granted		40,446			9.32		26,478			16.37
Vested		(10,197	)		7.59		(23,433	)		16.91
Forfeited		(28,083	)		7.59		-			-
Unvested shares as of September 30,    2016		114,417		$	9.78		43,011		$	16.25
Granted		20,531			14.27		16,426			24.41
Vested		(34,672	)		8.07		(28,449	)		18.02
Forfeited		(1,186	)		8.07		(5,991	)		17.04
Unvested shares as of September 30,    2017		99,090		$	11.33		24,997		$	19.41
Granted		29,099			11.34		19,918			20.77
Vested		(35,485	)		12.18		(16,248	)		19.34
Forfeited		-			-		-			-
Unvested shares as of September 30,    2018		92,704		$	11.00		28,667		$	20.40

The intrinsic value of the vested shares in 2018 was $1,047,761.

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Information On Oil And Natural Gas Producing Activities

12 Months Ended

Sep. 30, 2018

Oil And Gas Exploration And Production Industries Disclosures [Abstract]

Information On Oil And Natural Gas Producing Activities

10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

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

The following table shows sales, by percentage, through various operators/purchasers during 2018, 2017 and 2016.

	2018			2017			2016
Company A		24	%		18	%		23	%
Company B		16	%		3	%		3	%
Company C		11	%		8	%		2	%
Company D		7	%		13	%		12	%

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Supplementary Information On Oil, NGL And Natural Gas Reserves

12 Months Ended

Sep. 30, 2018

Extractive Industries [Abstract]

Supplementary Information On Oil, NGL And Natural Gas Reserves

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

Aggregate Capitalized Costs

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

	2018			2017
Producing properties	$	427,448,584		$	434,571,516
Non-producing minerals		12,378,395			7,243,802
Non-producing leasehold		185,124			185,125
Exploratory wells in progress		-			-
		440,012,103			442,000,443
Accumulated depreciation, depletion and amortization		(242,169,604	)		(245,640,247	)
Net capitalized costs	$	197,842,499		$	196,360,196

Costs Incurred

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

	2018		2017		2016
Property acquisition costs	$	11,409,673	$	20,190	$	-
Exploration costs		-		-		21,049
Development costs		10,291,476		25,382,377		5,075,710
	$	21,701,149	$	25,402,567	$	5,096,759

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

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

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

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2018, 2017 and 2016.

The Company’s net proved oil, NGL and natural gas reserves, which are located in the contiguous United States, as of September 30, 2018, 2017 and 2016, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Vice President of Operations, Freda Webb, who reports directly to our President and CEO. Ms. Webb holds a Bachelor of Science Degree in Mechanical Engineering from the University of Oklahoma, a Master of Science Degree in Petroleum Engineering from the University of Southern California and a Professional Engineering License in Petroleum Engineering in the State of Oklahoma. Ms. Webb has more than 35 years of experience in the oil and gas industry. Before joining the Company, she was sole proprietor of a consulting petroleum engineering firm and a mineral acquisition company. Ms. Webb held various positions of increasing responsibility at Southwestern Energy Company and Occidental Petroleum Corporation, with reservoir engineering assignments in several field locations across the United States. She is an active member of the Society of Petroleum Engineers (SPE).

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

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

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

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

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

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

	Proved Reserves
	Oil			NGL			Natural Gas			Total
	(Barrels)			(Barrels)			(Mcf)			Bcfe
September 30, 2015		7,038,430			2,920,600			120,214,044			180.0
Revisions of previous estimates		(1,552,010	)		(1,192,143	)		(47,068,144	)		(63.5	)
Acquisitions (divestitures)		-			-			-			-
Extensions, discoveries and other additions		303,922			65,306			16,864,075			19.1
Production		(364,252	)		(171,060	)		(8,284,377	)		(11.5	)
September 30, 2016		5,426,090			1,622,703			81,725,598			124.0
Revisions of previous estimates		253,481			407,250			13,651,501			17.6
Acquisitions (divestitures)		(37,724	)		(12,953	)		(669,064	)		(1.0	)
Extensions, discoveries and other additions		178,497			541,557			34,681,614			39.0
Production		(310,677	)		(173,858	)		(8,194,529	)		(11.1	)
September 30, 2017		5,509,667			2,384,699			121,195,120			168.6
Revisions of previous estimates		(1,407,995	)		303,728			(29,247	)		(6.7	)
Acquisitions (divestitures)		236,690			24,765			(1,782,949	)		(0.2	)
Extensions, discoveries and other additions		1,982,624			476,174			9,400,374			24.2
Production		(336,564	)		(255,176	)		(8,721,262	)		(12.3	)
September 30, 2018		5,984,422			2,934,190			120,062,036			173.6

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2018 - $62.86/Bbl, $26.13/Bbl, $2.56/Mcf; September 30, 2017 - $46.31/Bbl, $17.55/Bbl, $2.81/Mcf; September 30, 2016 - $36.77/Bbl, $12.22/Bbl, $1.97/Mcf.

The revisions of previous estimates from 2017 to 2018 were primarily the result of:

• Negative pricing revisions of 2.4 Bcfe, primarily resulting from gas wells currently projected to reach their projected economic limits earlier than projected in 2017 due to lower natural gas prices in 2018 relative to 2017; proved developed revisions of 1.7 Bcfe and PUD revisions of 0.7 Bcfe.

• Negative performance revisions of 4.2 Bcfe. Proved developed revisions were positive 7.6 Bcfe, principally due to better well performance from high-interest wells drilled in 2017 in the Anadarko Basin Woodford and southeastern Oklahoma Woodford. Proved undeveloped negative revisions of 11.8 Bcfe are a result of a delayed Eagle Ford drilling program in 2018 which resulted in removal of wells that are no longer projected to be developed within 5 years from the date they were added due to unanticipated drilling delays. However, the Eagle Ford drilling program is now underway.

Acquisitions and divestitures were the result of:

• The sale of 2.8 Bcfe in marginal properties located in northwestern Oklahoma and Kearny County, Kansas.

• The acquisition of 2.6 Bcfe, predominately in the active drilling program of the Bakken in North Dakota; 1.4 Bcfe proved developed and 1.2 Bcfe proved undeveloped.

Extensions, discoveries and other additions from 2017 to 2018 are principally attributable to:

• Proved developed reserve extensions, discoveries and other additions of 3.7 Bcfe resulting from:

a) The Company’s working and royalty interest ownership in ongoing development of unconventional oil, NGL and natural gas utilizing extended horizontal drilling in the Woodford Shale in the Anadarko Basin and southeastern Oklahoma.

b) The Company’s working and royalty interest ownership in ongoing development of unconventional oil, NGL and natural gas utilizing horizontal drilling in the STACK Meramec play in the Anadarko Basin in western Oklahoma.

c) The Company’s royalty interest ownership in ongoing development of conventional and unconventional oil, NGL and natural gas utilizing horizontal drilling in the Permian Basin of New Mexico and Texas.

• The addition of 20.4 Bcfe of PUD reserves primarily within the Company’s active drilling program areas of 1) the Anadarko Basin Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma and 3) the current drilling program of the Eagle Ford Shale in Texas.    

	Proved Developed Reserves						Proved Undeveloped Reserves
	Oil		NGL		NaturalGas		Oil		NGL		NaturalGas
	(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)		(Mcf)
September 30, 2016		1,980,519		1,095,256		62,929,047		3,445,571		527,447		18,796,551
September 30, 2017		2,201,528		1,768,425		87,861,043		3,308,139		616,274		33,334,077
September 30, 2018		2,334,587		2,085,706		83,151,954		3,649,835		848,484		36,910,082

The following details the changes in proved undeveloped reserves for 2018 (Mcfe):

Beginning proved undeveloped reserves	56,880,555
Proved undeveloped reserves transferred to proved developed	(2,158,716	)
Revisions	(12,456,931	)
Extensions and discoveries	20,413,545
Purchases	1,221,543
Ending proved undeveloped reserves	63,899,996

Beginning PUD reserves were 56.9 Bcfe. A total of 2.2 Bcfe (4% of the beginning balance) was transferred to proved developed during 2018. In the last two years, 41% of the beginning PUD reserves were transferred to proved developed. The 12.5 Bcfe (22% of the beginning balance) of negative revisions to PUD reserves were pricing revisions of 0.7 Bcfe and performance revision of 11.8 Bcfe, predominately resulting from the removal of oil, NGL and natural gas reserves associated with Eagle Ford wells that are no longer projected to be developed within 5 years from the date they were added due to a delayed drilling program in 2018. We anticipate that all the Company’s current 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 20.4 Bcfe of PUD reserves in 2018 primarily within the Company’s active drilling program areas of 1) the Anadarko Basin Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma and 3) the current drilling program of the Eagle Ford Shale in Texas. These additions result from continuing development and additional well performance data in each of the referenced plays. Of the 2018 PUD adds, 1.2 Bcfe was drilling or completing at year-end.

Standardized Measure of Discounted Future Net Cash Flows

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

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

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

	2018			2017			2016
Future cash inflows	$	759,899,074		$	637,509,599		$	380,263,695
Future production costs		(259,413,766	)		(256,193,675	)		(182,948,045	)
Future development and asset retirement costs		(89,518,449	)		(93,133,683	)		(72,431,842	)
Future income tax expense		(95,872,182	)		(102,193,819	)		(38,674,100	)
Future net cash flows		315,094,677			185,988,422			86,209,708
10% annual discount		(158,768,823	)		(105,155,847	)		(56,439,589	)
Standardized measure of discounted future net    cash flows	$	156,325,854		$	80,832,575		$	29,770,119

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

	2018			2017			2016
Beginning of year	$	80,832,575		$	29,770,119		$	81,591,211
Changes resulting from:
Sales of oil, NGL and natural gas, net of    production costs		(32,836,007	)		(25,783,055	)		(16,749,632	)
Net change in sales prices and production costs		47,533,281			37,186,619			(86,198,778	)
Net change in future development and asset    retirement costs		1,580,942			(7,939,156	)		21,636,258
Extensions and discoveries		34,667,557			38,582,908			11,640,704
Revisions of quantity estimates		(8,391,223	)		15,282,587			(41,716,689	)
Acquisitions (divestitures) of reserves-in-place		(307,472	)		(962,667	)		-
Accretion of discount		12,602,209			4,789,294			14,424,032
Net change in income taxes		(3,057,128	)		(27,070,430	)		44,533,277
Change in timing and other, net		23,701,120			16,976,356			609,736
Net change		75,493,279			51,062,456			(51,821,092	)
End of year	$	156,325,854		$	80,832,575		$	29,770,119

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Quarterly Results Of Operations (Unaudited)

12 Months Ended

Sep. 30, 2018

Quarterly Financial Information Disclosure [Abstract]

Quarterly Results Of Operations

12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

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

	Fiscal 2018
	Quarter Ended
	December31			March 31		June 30			September 30
Revenues	$	12,490,526		$	11,421,258	$	9,557,937		$	11,564,543
Income (loss) before provision for    income taxes	$	1,074,939		$	1,046,176	$	(984,093	)	$	759,647
Net income (loss)	$	13,784,939		$	1,070,176	$	(775,093	)	$	555,647
Earnings (loss) per share	$	0.81		$	0.06	$	(0.05	)	$	0.04
	Fiscal 2017
	Quarter Ended
	December 31			March 31		June 30			September 30
Revenues	$	7,036,643		$	13,964,288	$	12,437,186		$	12,896,932
Income (loss) before provision for    income taxes	$	(3,345,392	)	$	4,273,433	$	1,827,758		$	1,465,134
Net income (loss)	$	(2,238,392	)	$	3,470,433	$	1,260,758		$	1,039,134
Earnings (loss) per share	$	(0.13	)	$	0.21	$	0.07		$	0.06

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Subsequent Events

12 Months Ended

Sep. 30, 2018

Subsequent Events [Abstract]

Subsequent Events

13. SUBSEQUENT EVENTS (AUDITED)

On November 30, 2018, the Company closed on a mineral acreage sale of 206 net mineral acres in Lea and Eddy Counties, New Mexico. The sale price was $9.3 million or approximately $45,000 per acre. The proceeds will initially be used to reduce the Company’s bank debt. This sale represents 0.08% of the Company’s total net mineral acreage position, 0.7% of total production and 0.9% of total revenues for fiscal year 2018. This sale also includes 1.2% of our total proved reserves as of September 30, 2018.

These minerals had no net book value at September 30, 2018,and the total value received less any post-closing adjustments will be a gain on the sale of assets in the Company’s first quarter of 2019.

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Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Nature Of Business

Nature of Business

Through management of its fee mineral and leasehold acreage, the Company’s principal line of business is to explore for, develop, acquire, produce and sell oil, NGL and natural gas. Panhandle’s mineral and leasehold properties and other oil and natural gas interests are all located in the contiguous United States, primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas, with properties located in several other states. The Company’s oil, NGL and natural gas production is from interests in 6,079 wells located principally in Arkansas, Oklahoma and Texas. The Company does not operate any wells. Approximately 45% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2018. Approximately 71% of the Company’s total sales volumes in 2018 were derived from natural gas. Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells. From time to time, the Company sells certain non-material, non-core or small-interest oil and natural gas properties in the normal course of business.

Use Of Estimates

Use of Estimates

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

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

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

Cash And Cash Equivalents

Cash and Cash Equivalents

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

Oil, NGL And Natural Gas Sales And Natural Gas Imbalances

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

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

The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves. At September 30, 2018 and 2017, the Company had no material natural gas imbalances.

Accounts Receivable And Concentration Of Credit Risk

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers of oil, NGL and natural gas or operators of the oil and natural gas properties. Oil, NGL and natural gas sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our oil, NGL and natural gas and the operators of the properties in which we have an interest may be similarly affected by changes in economic, industry or other conditions. During 2018, 2017 and 2016 the Company did not have any bad debt expense. The Company’s allowance for uncollectible accounts as of the Balance Sheet dates was not material.

Oil And Natural Gas Producing Activities

Oil and Natural Gas Producing Activities

The Company follows the successful efforts method of accounting for oil and natural gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income, if and when the well does not reach commercial production levels. Oil and natural gas mineral and leasehold costs are capitalized when incurred.

It is common business practice in the petroleum industry to prepay drilling costs before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2018, the Company had no outstanding letters of credit.

Leasing Of Mineral Rights

Leasing of Mineral Rights

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

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

Derivatives

Derivatives

The Company has entered into fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts at September 30, 2018 and 2017, were with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of September 30, 2018

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
April - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.15 ceiling
Natural gas fixed price swaps
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
April - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.910
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.835
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.925
July - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.988
July 2018 - March 2019	50,000 Mmbtu	NYMEX Henry Hub	$3.065
January - July 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.867
Oil costless collars
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$50.00 floor / $55.75 ceiling
July - December 2018	3,000 Bbls	NYMEX WTI	$50.00 floor / $58.00 ceiling
January - June 2019	2,000 Bbls	NYMEX WTI	$55.00 floor / $63.45 ceiling
January - December 2019	1,000 Bbls	NYMEX WTI	$50.00 floor / $60.00 ceiling
January - December 2019	2,000 Bbls	NYMEX WTI	$60.00 floor / $69.25 ceiling
July - December 2019	3,000 Bbls	NYMEX WTI	$60.00 floor / $70.75 ceiling
January - June 2020	2,000 Bbls	NYMEX WTI	$60.00 floor / $67.00 ceiling
Oil fixed price swaps
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02
April - December 2018	4,000 Bbls	NYMEX WTI	$54.14
July - December 2018	2,000 Bbls	NYMEX WTI	$58.20
January - June 2019	2,000 Bbls	NYMEX WTI	$59.69
January - June 2019	2,000 Bbls	NYMEX WTI	$57.15
January - June 2019	3,000 Bbls	NYMEX WTI	$58.02
January - December 2019	1,000 Bbls	NYMEX WTI	$56.15
January - December 2019	2,000 Bbls	NYMEX WTI	$56.71
January - December 2019	1,000 Bbls	NYMEX WTI	$58.56
July - December 2019	2,000 Bbls	NYMEX WTI	$56.85

Derivative contracts in place as of September 30, 2017

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.65 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $3.65 ceiling
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
January - March 2018	150,000 Mmbtu	NYMEX Henry Hub	$3.40 floor / $3.95 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
Natural gas fixed price swaps
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.210
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.300
July - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.510
August - December 2017	100,000 Mmbtu	NYMEX Henry Hub	$3.095
January - March 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.700
January - March 2018	75,000 Mmbtu	NYMEX Henry Hub	$3.575
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.520
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
Oil costless collars
January - December 2017	3,000 Bbls	NYMEX WTI	$50.00 floor / $55.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$52.00 floor / $58.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$53.00 floor / $57.75 ceiling
April - December 2017	2,000 Bbls	NYMEX WTI	$50.00 floor / $57.50 ceiling
July - December 2017	5,000 Bbls	NYMEX WTI	$45.00 floor / $56.25 ceiling
January - June 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.75 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
Oil fixed price swaps
January - December 2017	3,000 Bbls	NYMEX WTI	$53.89
April - December 2017	2,000 Bbls	NYMEX WTI	$54.20
January - March 2018	4,000 Bbls	NYMEX WTI	$54.00
January - June 2018	4,000 Bbls	NYMEX WTI	$51.25
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02

The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $3,414,016 as of September 30, 2018, and a net asset of $516,159 as of September 30, 2017. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations. The portion of the gain (loss) on derivatives settled in cash for 2018, 2017 and 2016 was $1,001,893 (net paid), $305,410 (net received) and $4,552,680 (net received), respectively.

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on, or termination of, any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Balance Sheets. The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Balance Sheets at September 30, 2018, and September 30, 2017. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2018, and September 30, 2017.

	9/30/2018								9/30/2017
	Fair Value								Fair Value
	Commodity Contracts								Commodity Contracts
	CurrentAssets			Current Liabilities			Non-Current Liabilities		CurrentAssets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	42,150		$	3,106,196		$	349,970	$	735,702		$	190,778		$	9,439		$	38,204
Offsetting adjustments		(42,150	)		(42,150	)		-		(190,778	)		(190,778	)		(9,439	)		(9,439	)
Net presentation on Balance Sheets	$	-		$	3,064,046		$	349,970	$	544,924		$	-		$	-		$	28,765

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

Fair Value Measurements

Fair Value Measurements

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels.

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and, as of the fourth quarter of 2018, commodity options (i.e. price collars).

The Company uses an option pricing valuation model for option derivative contracts that considers various inputs including: future prices, time value, volatility factors, counterparty credit risk and current market and contractual prices for the underlying instruments. The values calculated are then compared to the values given by counterparties for reasonableness.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and unobservable (or less observable) from objective sources (supported by little or no market activity).

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

	Fair Value Measurement at September 30, 2018
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs		TotalFair
	(Level 1)		(Level 2)			(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(2,317,069	)	$	-	$	(2,317,069	)
Derivative Contracts - Collars	$	-	$	(1,096,947	)	$	-	$	(1,096,947	)

	Fair Value Measurement at September 30, 2017
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	364,606	$	-	$	364,606
Derivative Contracts - Collars	$	-	$	-	$	151,553	$	151,553

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

	Derivatives
Net Asset (Liability) Balance of Level 3 as of October 1, 2017	$	151,553
Total gains or (losses):
Included in earnings		(877,307	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(371,193	)
Transfers in and out of Level 3 (i)		1,096,947
Net Asset (Liability) Balance of Level 3 as of September 30, 2018	$	-

(i) During the fourth quarter of 2018, we transferred $1,096,947 of derivative collars out of Level 3 hierarchy, into Level 2 hierarchy as a result of our ability to obtain volatility inputs from direct observable sources.

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

	Year Ended September 30,
	2018				2017				2016
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	567,077	$	662,990	$	9,877,905	$	12,001,271

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

At September 30, 2018, and September 30, 2017, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short term maturities of those instruments. Financial instruments include long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

Depreciation, Depletion and Amortization

Depreciation, Depletion and Amortization

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

Non-producing oil and natural gas properties include non-producing minerals, which had a net book value of $8,025,015 and $3,079,008 at September 30, 2018 and 2017, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 92-year life of the Company. There are approximately 198,360 net acres of non-producing minerals in more than 6,749 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $62. Since inception, the Company has continually generated an interest in several thousand oil and natural gas wells using its ownership of the fee mineral acres as an ownership basis. There continues to be significant drilling and leasing activity on these mineral interests each year. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (as do oil and natural gas leases). Given the above, management concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.

Impairment

Impairment

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing thefair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company or fair value (sales price) less cost to sell if the property is held for sale. The Company's estimate of fair value of its oil and natural gas properties at September 30, 2018, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $0, $662,990 and $12,001,271 for 2018, 2017 and 2016, respectively. A further reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company. 

Divestitures

Divestitures

During the 2018 fiscal year, the Company sold 324 non-core marginal wells for $1,085,137 and recorded a loss on the sales of $660,597. The total net book value that was removed from the Balance Sheets due to these sales was approximately $1.7 million. The loss on sales was included in the Loss (gain) on asset sales and other line of the Statements of Operations. All of the wells included in the Assets held for sale line item on the Balance Sheets at September 30, 2017, were sold during the first quarter of 2018.

Acquisitions

Acquisitions

During the 2018 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 4,306 net mineral acres for $11.3 million or an average of approximately $2,600 per net mineral acre. These mineral purchases were accounted for as asset acquisitions.

Capitalized Interest

Capitalized Interest

During 2018, 2017 and 2016, interest of $89,023, $168,351 and $24,929, respectively, was included in the Company’s capital expenditures. Interest of $1,748,101, $1,275,138 and $1,344,619, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the unit-of-production method.

Asset Retirement Obligations

Asset Retirement Obligations

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

The following table shows the activity for the years ended September 30, 2018 and 2017, relating to the Company’s asset retirement obligations:

	2018			2017
Asset retirement obligations as of beginning of the year	$	3,196,889		$	2,958,048
Wells acquired or drilled		17,215			114,766
Wells sold or plugged		(542,892	)		(548,634	)
Revisions in estimated cash flows		-			536,536
Accretion of discount		138,166			136,173
Asset retirement obligations as of end of the year	$	2,809,378		$	3,196,889

The revisions in estimated cash flows in fiscal 2017 were due to increased plugging charges noted recently that were higher than previously estimated. As a non-operator, we do not control the plugging of wells in which we have a working interest and are not involved in the negotiation of the terms of the plugging contracts. Our estimate relies on information that we can gather from outside sources as well as relevant information that we receive directly from operators.

Environmental Costs

Environmental Costs

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

Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2018 and 2017, there were no such costs accrued.

Earnings (Loss) Per Share Of Common Stock

Earnings (Loss) Per Share of Common Stock

Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period.

Share-based Compensation

Share-based Compensation

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

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

Restricted stock awards to officers provide for cliff vesting at the end of three years from the date of the awards. These restricted stock awards can be granted based on service time only (non-performance based) or subject to certain share price performance standards (performance based). Restricted stock awards to the non-employee directors provide for quarterly vesting during the calendar year of the award. The fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance.

Income Taxes

Income Taxes

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

The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduces the U.S. federal corporate tax rate from 35% to 21%, requires companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously tax deferred and creates new taxes on certain foreign sourced earnings. As of September 30, 2018, we have completed our estimates accounting for the tax effects of enactment of the Act. Based on these estimates, we recognized an amount which is included as a component of income tax expense (benefit) from continuing operations.

We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The amount recorded related to the remeasurement of our deferred tax balance was $12,464,000 income tax benefit.

The Company has a year end of September 30. Because this differs from a calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The impact of using a blended rate versus the old rate in the current year resulted in a federal tax benefit of $198,581.

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended September 30, 2018, was a 672% benefit as compared to a 16% provision for the year ended September 30, 2017.

The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2015.

The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Operations. For fiscal September 30, 2018, 2017 and 2016, the Company’s interest and penalties was not material. The Company does not believe it has any significant uncertain tax positions.

Adoption Of New Accounting Pronouncements

Adoption of New Accounting Pronouncements

In January 2017, the FASB issued ASU 2017-01, which changed the definition of a business. The new guidance requires an entity to first evaluate whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets. If that threshold is met, the set of assets and activities is not a business. If it’s not met, the entity evaluates whether the set meets the definition of a business. The new definition requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue recognition guidance. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. The ASU was applied prospectively to transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods for which the financial statements have not been issued or made available for issuance. The Company early adopted ASU 2017-01 during the third quarter ended June 30, 2018.

New Accounting Pronouncements Yet To Be Adopted

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. The guidance is effective for us beginning October 1, 2019, including interim periods within the fiscal year. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this update will have on our financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for us beginning October 1, 2018, including interim periods within the fiscal year. This update is not expected to have a material impact on our financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services.

Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis.

The standard is effective for us beginning October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements and utilizes a cumulative effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Panhandle intends to use the modified retrospective method upon adoption.

The Company has completed its evaluation of the impact of the new standard and related interpretive guidance on its financial statements, accounting policies, internal controls, and disclosures. Based on our assessments, the standard is not expected to have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures and internal controls over financial reporting.

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

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of September 30, 2018

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
April - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.15 ceiling
Natural gas fixed price swaps
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
April - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.910
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.835
July - December 2018	100,000 Mmbtu	NYMEX Henry Hub	$2.925
July - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$2.988
July 2018 - March 2019	50,000 Mmbtu	NYMEX Henry Hub	$3.065
January - July 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.867
Oil costless collars
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$50.00 floor / $55.75 ceiling
July - December 2018	3,000 Bbls	NYMEX WTI	$50.00 floor / $58.00 ceiling
January - June 2019	2,000 Bbls	NYMEX WTI	$55.00 floor / $63.45 ceiling
January - December 2019	1,000 Bbls	NYMEX WTI	$50.00 floor / $60.00 ceiling
January - December 2019	2,000 Bbls	NYMEX WTI	$60.00 floor / $69.25 ceiling
July - December 2019	3,000 Bbls	NYMEX WTI	$60.00 floor / $70.75 ceiling
January - June 2020	2,000 Bbls	NYMEX WTI	$60.00 floor / $67.00 ceiling
Oil fixed price swaps
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02
April - December 2018	4,000 Bbls	NYMEX WTI	$54.14
July - December 2018	2,000 Bbls	NYMEX WTI	$58.20
January - June 2019	2,000 Bbls	NYMEX WTI	$59.69
January - June 2019	2,000 Bbls	NYMEX WTI	$57.15
January - June 2019	3,000 Bbls	NYMEX WTI	$58.02
January - December 2019	1,000 Bbls	NYMEX WTI	$56.15
January - December 2019	2,000 Bbls	NYMEX WTI	$56.71
January - December 2019	1,000 Bbls	NYMEX WTI	$58.56
July - December 2019	2,000 Bbls	NYMEX WTI	$56.85

Derivative contracts in place as of September 30, 2017

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.65 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $3.65 ceiling
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
January - March 2018	150,000 Mmbtu	NYMEX Henry Hub	$3.40 floor / $3.95 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
January - December 2018	40,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.30 ceiling
Natural gas fixed price swaps
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.210
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.300
July - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.510
August - December 2017	100,000 Mmbtu	NYMEX Henry Hub	$3.095
January - March 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.700
January - March 2018	75,000 Mmbtu	NYMEX Henry Hub	$3.575
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.520
January - December 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.080
Oil costless collars
January - December 2017	3,000 Bbls	NYMEX WTI	$50.00 floor / $55.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$52.00 floor / $58.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$53.00 floor / $57.75 ceiling
April - December 2017	2,000 Bbls	NYMEX WTI	$50.00 floor / $57.50 ceiling
July - December 2017	5,000 Bbls	NYMEX WTI	$45.00 floor / $56.25 ceiling
January - June 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.75 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$47.50 floor / $52.50 ceiling
January - December 2018	2,000 Bbls	NYMEX WTI	$48.00 floor / $53.25 ceiling
Oil fixed price swaps
January - December 2017	3,000 Bbls	NYMEX WTI	$53.89
April - December 2017	2,000 Bbls	NYMEX WTI	$54.20
January - March 2018	4,000 Bbls	NYMEX WTI	$54.00
January - June 2018	4,000 Bbls	NYMEX WTI	$51.25
January - December 2018	3,000 Bbls	NYMEX WTI	$50.72
January - December 2018	2,000 Bbls	NYMEX WTI	$52.02

Summary Of Derivative Contracts

	9/30/2018								9/30/2017
	Fair Value								Fair Value
	Commodity Contracts								Commodity Contracts
	CurrentAssets			Current Liabilities			Non-Current Liabilities		CurrentAssets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	42,150		$	3,106,196		$	349,970	$	735,702		$	190,778		$	9,439		$	38,204
Offsetting adjustments		(42,150	)		(42,150	)		-		(190,778	)		(190,778	)		(9,439	)		(9,439	)
Net presentation on Balance Sheets	$	-		$	3,064,046		$	349,970	$	544,924		$	-		$	-		$	28,765

Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis

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

	Fair Value Measurement at September 30, 2018
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs		TotalFair
	(Level 1)		(Level 2)			(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(2,317,069	)	$	-	$	(2,317,069	)
Derivative Contracts - Collars	$	-	$	(1,096,947	)	$	-	$	(1,096,947	)

	Fair Value Measurement at September 30, 2017
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	364,606	$	-	$	364,606
Derivative Contracts - Collars	$	-	$	-	$	151,553	$	151,553

Summary Of Reconciliation Of Derivative Contracts Classified As Level 3 Measurements

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

	Derivatives
Net Asset (Liability) Balance of Level 3 as of October 1, 2017	$	151,553
Total gains or (losses):
Included in earnings		(877,307	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(371,193	)
Transfers in and out of Level 3 (i)		1,096,947
Net Asset (Liability) Balance of Level 3 as of September 30, 2018	$	-

(i) During the fourth quarter of 2018, we transferred $1,096,947 of derivative collars out of Level 3 hierarchy, into Level 2 hierarchy as a result of our ability to obtain volatility inputs from direct observable sources.

Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3

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

	Year Ended September 30,
	2018				2017				2016
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	567,077	$	662,990	$	9,877,905	$	12,001,271

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

Summary Of Asset Retirement Obligation

The following table shows the activity for the years ended September 30, 2018 and 2017, relating to the Company’s asset retirement obligations:

	2018			2017
Asset retirement obligations as of beginning of the year	$	3,196,889		$	2,958,048
Wells acquired or drilled		17,215			114,766
Wells sold or plugged		(542,892	)		(548,634	)
Revisions in estimated cash flows		-			536,536
Accretion of discount		138,166			136,173
Asset retirement obligations as of end of the year	$	2,809,378		$	3,196,889

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Income Taxes (Tables)

12 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Summary Of Provision (Benefit) For Income Taxes

	2018			2017			2016
Current:
Federal	$	204,000		$	314,000		$	2,166,000
State		20,000			-			83,000
		224,000			314,000			2,249,000
Deferred:
Federal		(13,240,000	)		390,000			(8,597,000	)
State		277,000			(15,000	)		(1,363,000	)
		(12,963,000	)		375,000			(9,960,000	)
	$	(12,739,000	)	$	689,000		$	(7,711,000	)

Summary Of Difference Between Provision (Benefit) For Income Taxes And Amount Which Would Result From Application Of Federal Statutory Rate

	2018			2017			2016
Provision (benefit) for income taxes at statutory rate	$	465,253		$	1,477,327		$	(6,299,259	)
Percentage depletion		(577,780	)		(570,801	)		(395,649	)
State income taxes, net of federal provision (benefit)		36,980			3,900			(683,800	)
Effect of graduated rates		-			85,644			(86,745	)
Restricted stock tax benefit		(69,000	)		(238,000	)		-
Deferred directors compensation benefit		(134,000	)		(79,000	)		-
Law change (a)		(12,464,000	)		-			-
Other		3,547			9,930			(245,547	)
	$	(12,739,000	)	$	689,000		$	(7,711,000	)

(a) This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21%.

Summary Of Deferred Tax Assets And Liabilities

	2018		2017
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible    drilling costs capitalized for financial purposes and    expensed for tax purposes	$	24,560,165	$	38,185,387
Derivative contracts		-		200,786
		24,560,165		38,386,173
Deferred tax assets:
State net operating loss carry forwards		551,435		655,741
AMT credit carry forwards		2,936,457		3,499,320
Deferred directors' compensation		725,971		1,295,333
Restricted stock expense		249,610		411,019
Derivative contracts		878,767		-
Statutory depletion carry forwards		-		634,405
Other		1,129,918		839,348
		6,472,158		7,335,166
Net deferred tax liabilities	$	18,088,007	$	31,051,007

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Earnings (Loss) Per Share (Tables)

12 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Summary Of Computation Of Earnings (Loss) Per Share

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

	Year ended September 30,
	2018		2017		2016
Numerator for basic and diluted earnings (loss) per share:
Net income (loss)	$	14,635,669	$	3,531,933	$	(10,286,884	)
Denominator for basic and diluted earnings per share:
Weighted average shares (including for 2018, 2017    and 2016, unissued, vested directors' shares of    205,736, 253,603 and 263,057, respectively)		16,952,664		16,900,185		16,840,856

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Employee Stock Ownership Plan (Tables)

12 Months Ended

Sep. 30, 2018

Share Based Arrangements To Obtain Goods And Services [Abstract]

Summary Of Plan Contributions

Year	Shares		Amount
2018		20,632	$	382,174
2017		13,125	$	312,380
2016		11,418	$	200,158

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Restricted Stock Plan (Tables)

12 Months Ended

Sep. 30, 2018

Restricted Stock Plan [Abstract]

Summary Of Pre-Tax Compensation Expense

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2018, 2017 and 2016, related to the Company’s performance based and non-performance based restricted stock.

	Year Ended September 30,
	2018		2017		2016
Performance based, restricted stock	$	276,272	$	233,122	$	390,655
Non-performance based, restricted stock		379,142		364,818		390,824
Total compensation expense	$	655,414	$	597,940	$	781,479

Summary Of Unrecognized Compensation Cost

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

	Unrecognized Compensation Cost		Weighted AveragePeriod (in years)
Performance based, restricted stock	$	321,389		1.79
Non-performance based, restricted stock		274,666		1.50
Total	$	596,055

Summary Of Status Of Unvested Shares Of Restricted Stock Awards

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

	Performance Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Non- Performance BasedUnvested Restricted Shares			Weighted Average Grant-Date Fair Value
Unvested shares as of September 30,    2015		112,251		$	9.20		39,966		$	16.56
Granted		40,446			9.32		26,478			16.37
Vested		(10,197	)		7.59		(23,433	)		16.91
Forfeited		(28,083	)		7.59		-			-
Unvested shares as of September 30,    2016		114,417		$	9.78		43,011		$	16.25
Granted		20,531			14.27		16,426			24.41
Vested		(34,672	)		8.07		(28,449	)		18.02
Forfeited		(1,186	)		8.07		(5,991	)		17.04
Unvested shares as of September 30,    2017		99,090		$	11.33		24,997		$	19.41
Granted		29,099			11.34		19,918			20.77
Vested		(35,485	)		12.18		(16,248	)		19.34
Forfeited		-			-		-			-
Unvested shares as of September 30,    2018		92,704		$	11.00		28,667		$	20.40

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Information On Oil And Natural Gas Producing Activities (Tables)

12 Months Ended

Sep. 30, 2018

Oil And Gas Exploration And Production Industries Disclosures [Abstract]

Summary Of Sales By Percentage Through Various Operators Or Purchasers

The following table shows sales, by percentage, through various operators/purchasers during 2018, 2017 and 2016.

	2018			2017			2016
Company A		24	%		18	%		23	%
Company B		16	%		3	%		3	%
Company C		11	%		8	%		2	%
Company D		7	%		13	%		12	%

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Supplementary Information On Oil, NGL And Natural Gas Reserves (Tables)

12 Months Ended

Sep. 30, 2018

Extractive Industries [Abstract]

Summary Of Capitalized Costs Of Oil And Natural Gas Properties And Related Depreciation, Depletion And Amortization

	2018			2017
Producing properties	$	427,448,584		$	434,571,516
Non-producing minerals		12,378,395			7,243,802
Non-producing leasehold		185,124			185,125
Exploratory wells in progress		-			-
		440,012,103			442,000,443
Accumulated depreciation, depletion and amortization		(242,169,604	)		(245,640,247	)
Net capitalized costs	$	197,842,499		$	196,360,196

Summary Of Costs Incurred In Oil And Natural Gas Producing Activities

	2018		2017		2016
Property acquisition costs	$	11,409,673	$	20,190	$	-
Exploration costs		-		-		21,049
Development costs		10,291,476		25,382,377		5,075,710
	$	21,701,149	$	25,402,567	$	5,096,759

Summary Of Net Quantities Of Proved, Developed And Undeveloped Oil And Natural Gas Reserves

	Proved Reserves
	Oil			NGL			Natural Gas			Total
	(Barrels)			(Barrels)			(Mcf)			Bcfe
September 30, 2015		7,038,430			2,920,600			120,214,044			180.0
Revisions of previous estimates		(1,552,010	)		(1,192,143	)		(47,068,144	)		(63.5	)
Acquisitions (divestitures)		-			-			-			-
Extensions, discoveries and other additions		303,922			65,306			16,864,075			19.1
Production		(364,252	)		(171,060	)		(8,284,377	)		(11.5	)
September 30, 2016		5,426,090			1,622,703			81,725,598			124.0
Revisions of previous estimates		253,481			407,250			13,651,501			17.6
Acquisitions (divestitures)		(37,724	)		(12,953	)		(669,064	)		(1.0	)
Extensions, discoveries and other additions		178,497			541,557			34,681,614			39.0
Production		(310,677	)		(173,858	)		(8,194,529	)		(11.1	)
September 30, 2017		5,509,667			2,384,699			121,195,120			168.6
Revisions of previous estimates		(1,407,995	)		303,728			(29,247	)		(6.7	)
Acquisitions (divestitures)		236,690			24,765			(1,782,949	)		(0.2	)
Extensions, discoveries and other additions		1,982,624			476,174			9,400,374			24.2
Production		(336,564	)		(255,176	)		(8,721,262	)		(12.3	)
September 30, 2018		5,984,422			2,934,190			120,062,036			173.6

Summary Of Proved Developed And Undeveloped Reserves

	Proved Developed Reserves						Proved Undeveloped Reserves
	Oil		NGL		NaturalGas		Oil		NGL		NaturalGas
	(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)		(Mcf)
September 30, 2016		1,980,519		1,095,256		62,929,047		3,445,571		527,447		18,796,551
September 30, 2017		2,201,528		1,768,425		87,861,043		3,308,139		616,274		33,334,077
September 30, 2018		2,334,587		2,085,706		83,151,954		3,649,835		848,484		36,910,082

Summary Of Proved Undeveloped Reserves

Beginning proved undeveloped reserves	56,880,555
Proved undeveloped reserves transferred to proved developed	(2,158,716	)
Revisions	(12,456,931	)
Extensions and discoveries	20,413,545
Purchases	1,221,543
Ending proved undeveloped reserves	63,899,996

Summary Of Standardized Measure Of Discounted Future Net Cash Flows

	2018			2017			2016
Future cash inflows	$	759,899,074		$	637,509,599		$	380,263,695
Future production costs		(259,413,766	)		(256,193,675	)		(182,948,045	)
Future development and asset retirement costs		(89,518,449	)		(93,133,683	)		(72,431,842	)
Future income tax expense		(95,872,182	)		(102,193,819	)		(38,674,100	)
Future net cash flows		315,094,677			185,988,422			86,209,708
10% annual discount		(158,768,823	)		(105,155,847	)		(56,439,589	)
Standardized measure of discounted future net    cash flows	$	156,325,854		$	80,832,575		$	29,770,119

Summary Of Changes In Standardized Measure Of Discounted Future Net Cash Flows

	2018			2017			2016
Beginning of year	$	80,832,575		$	29,770,119		$	81,591,211
Changes resulting from:
Sales of oil, NGL and natural gas, net of    production costs		(32,836,007	)		(25,783,055	)		(16,749,632	)
Net change in sales prices and production costs		47,533,281			37,186,619			(86,198,778	)
Net change in future development and asset    retirement costs		1,580,942			(7,939,156	)		21,636,258
Extensions and discoveries		34,667,557			38,582,908			11,640,704
Revisions of quantity estimates		(8,391,223	)		15,282,587			(41,716,689	)
Acquisitions (divestitures) of reserves-in-place		(307,472	)		(962,667	)		-
Accretion of discount		12,602,209			4,789,294			14,424,032
Net change in income taxes		(3,057,128	)		(27,070,430	)		44,533,277
Change in timing and other, net		23,701,120			16,976,356			609,736
Net change		75,493,279			51,062,456			(51,821,092	)
End of year	$	156,325,854		$	80,832,575		$	29,770,119

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Quarterly Results Of Operations (Unaudited) (Tables)

12 Months Ended

Sep. 30, 2018

Quarterly Financial Information Disclosure [Abstract]

Summary Of The Company's Quarterly Results Of Operations

	Fiscal 2018
	Quarter Ended
	December31			March 31		June 30			September 30
Revenues	$	12,490,526		$	11,421,258	$	9,557,937		$	11,564,543
Income (loss) before provision for    income taxes	$	1,074,939		$	1,046,176	$	(984,093	)	$	759,647
Net income (loss)	$	13,784,939		$	1,070,176	$	(775,093	)	$	555,647
Earnings (loss) per share	$	0.81		$	0.06	$	(0.05	)	$	0.04
	Fiscal 2017
	Quarter Ended
	December 31			March 31		June 30			September 30
Revenues	$	7,036,643		$	13,964,288	$	12,437,186		$	12,896,932
Income (loss) before provision for    income taxes	$	(3,345,392	)	$	4,273,433	$	1,827,758		$	1,465,134
Net income (loss)	$	(2,238,392	)	$	3,470,433	$	1,260,758		$	1,039,134
Earnings (loss) per share	$	(0.13	)	$	0.21	$	0.07		$	0.06

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Summary Of Significant Accounting Policies (Narrative) (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2018 USD ($) a Item $ / a	Sep. 30, 2018 USD ($) a Item $ / a	Sep. 30, 2017 USD ($)		Sep. 30, 2016 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of Oil, NGL and Natural Gas Production Units | Item		6,079	6,079
Oil, NGL and natural gas revenues were derived from the sale of natural gas			45.00%
Amount of Material Natural Gas Imbalances		$ 0	$ 0	$ 0
Bad debt expense			0	0		$ 0
Outstanding letters of credit		0	0
Fair value of derivative contracts, asset				516,159
Fair value of derivative contracts, liability		3,414,016	3,414,016
Net cash paid on derivatives settled			1,001,893
Net cash received on derivatives settled				305,410		4,552,680
Book value of Non-producing oil and natural gas		$ 8,025,015	$ 8,025,015	$ 3,079,008
Percentage of perpetual ownership of mineral interests in Arkansas ,New Mexico, North Dakota, Oklahoma and Texas		91.00%	91.00%
Accumulated period perpetual rights				92 years
Non Producing Minerals Area | a		198,360	198,360
Number of tracts owned | Item		6,749	6,749
Amount of acres average tract contains | a		29	29
Tracts Average Cost Per Acre | $ / a		62	62
Amortized Period of Non-producing Minerals				33 years
Impairment			$ 0	$ 662,990	[1]	12,001,271	[1]
Number of non-core marginal wells sold | Item			324
Proceeds from sales of assets			$ 1,085,137	723,700		4,501,726
Loss on sale of assets			660,597	94,889		(2,688,408)
Decrease in net book value			1,700,000
Amount of Capitalized Interest Included in the Company's Capital Expenditures			89,023	168,351		24,929
Interest Expense			$ 1,748,101	$ 1,275,138		$ 1,344,619
U.S. federal corporate tax rate	35.00%	21.00%	24.53%
Remeasurement of deferred income tax benefit, amount			$ 12,464,000
Federal tax benefit resulting from the use of blend rate versus old rate			$ 198,581
Effective tax rate			(672.00%)	16.00%
Oklahoma [Member]
Summary Of Significant Accounting Policies [Line Items]
Mineral acreage acquired | a			4,306
Purchase price of mineral acreage acquired			$ 11,300,000
Net mineral price per acre | $ / a		2,600	2,600
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Useful life of furniture and fixtures			5 years
Restricted Stock Awards, vesting period			3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Useful life of furniture and fixtures			8 years
Sales Revenue, Net [Member] | Product Concentration Risk [Member]
Summary Of Significant Accounting Policies [Line Items]
Total sale volume from sale of natural gas			71.00%

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

XML

Summary Of Significant Accounting Policies (Summary Of Derivative Instruments Contracts) (Details)	Sep. 30, 2018 MMBTU $ / MMBTU $ / bbl bbl	Sep. 30, 2017 MMBTU $ / MMBTU $ / bbl bbl
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	40,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	2.75	2.80
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	3.35	3.47
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	40,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	2.75	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	3.30	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	2.80	2.80
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU	3.15	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		2.75
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		30,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.65
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.60
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.20
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.65
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		100,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.50
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.95
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		40,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		2.75
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		150,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.40
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.95
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		40,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		2.75
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / MMBTU		3.30
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price | $ / MMBTU	3.080
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Five [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	40,000
Contract price | $ / MMBTU	2.910
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Six [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.835
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Seven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.925
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Eight [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price | $ / MMBTU	2.988
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Ten [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.867
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Nine [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price | $ / MMBTU	3.065
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		50,000
Contract price | $ / MMBTU		3.070
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		25,000
Contract price | $ / MMBTU		3.100
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fourteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		50,000
Contract price | $ / MMBTU		3.210
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		30,000
Contract price | $ / MMBTU		3.300
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		50,000
Contract price | $ / MMBTU		3.510
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Seventeen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		100,000
Contract price | $ / MMBTU		3.095
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Eighteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		50,000
Contract price | $ / MMBTU		3.700
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Nineteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		75,000
Contract price | $ / MMBTU		3.575
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Twenty [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		100,000
Contract price | $ / MMBTU		3.520
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Twenty One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		50,000
Contract price | $ / MMBTU		3.080
Oil Costless Collars [Member] | Derivative Contract Period Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	50.00
Oil Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	55.75
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	47.50
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	52.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Two [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price		50.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price		55.00
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	48.00
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	53.25
Oil Costless Collars [Member] | Derivative Contract Period Twenty Three [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price		52.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price		58.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Four [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price		53.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price		57.75
Oil Costless Collars [Member] | Derivative Contract Period Fourteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Fourteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	50.00
Oil Costless Collars [Member] | Derivative Contract Period Fourteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	58.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Five [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		2,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price		50.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price		57.50
Oil Costless Collars [Member] | Derivative Contract Period Fifteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Fifteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	55.00
Oil Costless Collars [Member] | Derivative Contract Period Fifteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	63.45
Oil Costless Collars [Member] | Derivative Contract Period Sixteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Sixteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	50.00
Oil Costless Collars [Member] | Derivative Contract Period Sixteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	60.00
Oil Costless Collars [Member] | Derivative Contract Period Seventeen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	60.00
Oil Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	69.25
Oil Costless Collars [Member] | Derivative Contract Period Eighteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	60.00
Oil Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	70.75
Oil Costless Collars [Member] | Derivative Contract Period Nineteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	60.00
Oil Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	67.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Six [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		5,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price		45.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price		56.25
Oil Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		2,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price		47.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price		52.75
Oil Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		2,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price		47.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price		52.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		2,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price		48.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price		53.25
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Two [Member]
Derivative [Line Items]
Contract price	54.14
Production volume covered per month - Oil | bbl	4,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Three [Member]
Derivative [Line Items]
Contract price	58.20
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Four [Member]
Derivative [Line Items]
Contract price	59.69
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Five [Member]
Derivative [Line Items]
Contract price	57.15
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty [Member]
Derivative [Line Items]
Contract price	50.72
Production volume covered per month - Oil | bbl	3,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty One [Member]
Derivative [Line Items]
Contract price	52.02
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Six [Member]
Derivative [Line Items]
Contract price	58.02
Production volume covered per month - Oil | bbl	3,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Seven [Member]
Derivative [Line Items]
Contract price	56.15
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Eight [Member]
Derivative [Line Items]
Contract price	56.71
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Nine [Member]
Derivative [Line Items]
Contract price	58.56
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirty [Member]
Derivative [Line Items]
Contract price	56.85	53.89
Production volume covered per month - Oil | bbl	2,000	3,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirty One [Member]
Derivative [Line Items]
Contract price		54.20
Production volume covered per month - Oil | bbl		2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirty Two [Member]
Derivative [Line Items]
Contract price		54.00
Production volume covered per month - Oil | bbl		4,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirty Three [Member]
Derivative [Line Items]
Contract price		51.25
Production volume covered per month - Oil | bbl		4,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirty Four []Member]
Derivative [Line Items]
Contract price		50.72
Production volume covered per month - Oil | bbl		3,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirty Five [Member]
Derivative [Line Items]
Contract price		52.02
Production volume covered per month - Oil | bbl		2,000

XML

Summary Of Significant Accounting Policies (Summary Of Derivative Contracts) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gross amounts recognized - Current Assets	$ 42,150	$ 735,702
Offsetting adjustments - Current Assets	(42,150)	(190,778)
Net presentation on Balance Sheets - Current Assets		544,924
Gross amounts recognized - Current Liabilities	3,106,196	190,778
Offsetting adjustments - Current Liabilities	(42,150)	(190,778)
Net presentation on Balance Sheets - Current Liabilities	3,064,046
Gross amounts recognized - Non-Current Assets		9,439
Offsetting adjustments - Non-Current Assets		(9,439)
Gross amounts recognized - Non-Current Liabilities	349,970	38,204
Offsetting adjustments - Non-Current Liabilities		(9,439)
Net presentation on Balance Sheets - Non-Current Liabilities	$ 349,970	$ 28,765

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Summary Of Significant Accounting Policies (Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ (2,317,069)	$ 364,606
Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	(2,317,069)	364,606
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	(1,096,947)	151,553
Collars [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ (1,096,947)
Collars [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)		$ 151,553

XML

Summary Of Significant Accounting Policies (Summary Of Reconciliation Of Derivative Contracts Classified As Level 3 Measurements) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Net Asset (Liability) Balance of Level 3 as of October 1, 2017		$ 151,553
Total gains or (losses) included in earnings		(877,307)
Purchases, issuances and settlements		(371,193)
Transfers in and out of Level 3	$ 1,096,947	$ 1,096,947	[1]

[1] During the fourth quarter of 2018, we transferred $1,096,947 of derivative collars out of Level 3 hierarchy, into Level 2 hierarchy as a result of our ability to obtain volatility inputs from direct observable sources.

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Summary Of Significant Accounting Policies (Summary Of Reconciliation Of Derivative Contracts Classified As Level 3 Measurements) (Parenthetical) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Derivative collars transferred	$ 1,096,947	$ 1,096,947	[1]

[1] During the fourth quarter of 2018, we transferred $1,096,947 of derivative collars out of Level 3 hierarchy, into Level 2 hierarchy as a result of our ability to obtain volatility inputs from direct observable sources.

XML

Summary Of Significant Accounting Policies (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017		Sep. 30, 2016
Accounting Policies [Abstract]
Producing Properties, Fair Value	[1]		$ 567,077		$ 9,877,905
Provision for impairment		$ 0	$ 662,990	[1]	$ 12,001,271	[1]

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

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Summary Of Significant Accounting Policies (Summary Of Asset Retirement Obligation) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Accounting Policies [Abstract]
Asset retirement obligations as of beginning of the year	$ 3,196,889	$ 2,958,048
Wells acquired or drilled	17,215	114,766
Wells sold or plugged	(542,892)	(548,634)
Revisions in estimated cash flows		536,536
Accretion of discount	138,166	136,173
Asset retirement obligations as of end of the year	$ 2,809,378	$ 3,196,889

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Commitments (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
Future minimum rental payments under the terms of the lease due in 2019	$ 210,273
Future minimum rental payments under the terms of the lease due in 2020	122,659
Future minimum rental payments under the terms of the lease due in 2021	0
Rental Expenses	$ 215,803	$ 206,366	$ 202,083

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Income Taxes (Summary of Provision (Benefit) for Income Taxes) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Federal	$ 204,000	$ 314,000	$ 2,166,000
State	20,000		83,000
Current	224,000	314,000	2,249,000
Federal	(13,240,000)	390,000	(8,597,000)
State	277,000	(15,000)	(1,363,000)
Deferred	(12,963,000)	375,000	(9,960,000)
Provision (benefit) for income taxes	$ (12,739,000)	$ 689,000	$ (7,711,000)

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Income Taxes (Summary of Difference Between Provision (Benefit) for Income Taxes and Amount which Would Result from Application of Federal Statutory Rate) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Provision (benefit) for income taxes at statutory rate		$ 465,253	$ 1,477,327	$ (6,299,259)
Percentage depletion		(577,780)	(570,801)	(395,649)
State income taxes, net of federal provision (benefit)		36,980	3,900	(683,800)
Effect of graduated rates			85,644	(86,745)
Restricted stock tax benefit		(69,000)	(238,000)
Deferred directors compensation benefit		(134,000)	(79,000)
Law change	[1]	(12,464,000)
Other		3,547	9,930	(245,547)
Provision (benefit) for income taxes		$ (12,739,000)	$ 689,000	$ (7,711,000)

[1] This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21%.

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Income Taxes (Summary of Difference Between Provision (Benefit) for Income Taxes and Amount which Would Result from Application of Federal Statutory Rate) (Parenthetical) (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2018	Sep. 30, 2018
Income Tax Disclosure [Abstract]
U.S. federal corporate tax rate	35.00%	21.00%	24.53%

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Income Taxes (Summary of Deferred Tax Assets and Liabilities) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$ 24,560,165	$ 38,185,387
Derivative contracts		200,786
Total deferred tax liabilities	24,560,165	38,386,173
State net operating loss carry forwards	551,435	655,741
AMT credit carry forwards	2,936,457	3,499,320
Deferred directors' compensation	725,971	1,295,333
Restricted stock expense	249,610	411,019
Derivative contracts	878,767
Statutory depletion carry forwards		634,405
Other	1,129,918	839,348
Total Deferred tax assets	6,472,158	7,335,166
Net deferred tax liabilities	$ 18,088,007	$ 31,051,007

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Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Income Tax Contingency [Line Items]
State net operating loss carry forwards	$ 551,435	$ 655,741
Percentage of AMT credit refundable amount equal to excess of minimum tax credit	50.00%
Percentage of AMT credit refundable amount equal to excess of minimum tax credit in case of taxable years beginning in 2021	100.00%
AMT carryforward, description	The AMT carry forwards do not have an expiration date. The corporate alternative minimum tax was repealed by The Tax Cuts and Jobs Act (enacted on December 22, 2017). Taxpayers with AMT credit carryovers can use the credits to offset regular tax liability for any taxable year. In addition, the AMT credit is refundable in any taxable year beginning after 2017 and before 2022 in an amount equal to 50% (100% in the case of taxable years beginning in 2021) of the excess of the minimum tax credit for the taxable year over the amount of the credit allowable for the year against regular tax liability. Thus, the Company’s entire AMT credit carryforward amounts are fully refundable by 2023.
Earliest Tax Year [Member]
Income Tax Contingency [Line Items]
AMT credit refundable taxable year	2017
Latest Tax Year [Member]
Income Tax Contingency [Line Items]
AMT credit refundable taxable year	2022
Oklahoma [Member]
Income Tax Contingency [Line Items]
State net operating loss carry forwards	$ 497,752
Operating loss carry forwards valuation allowance	$ 0
Minimum [Member] | Oklahoma [Member]
Income Tax Contingency [Line Items]
Net operating loss carry forwards expiration period	2031
Maximum [Member] | Oklahoma [Member]
Income Tax Contingency [Line Items]
Net operating loss carry forwards expiration period	2037

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Long-Term Debt (Details) - Revolving Credit Facility [Member] - USD ($)	12 Months Ended
	Sep. 30, 2018	Jul. 31, 2018
Line Of Credit Facility [Line Items]
Revolving loan credit facility	$ 200,000,000
Borrowing base of credit facility	$ 80,000,000	$ 80,000,000
Credit facility maturity	Nov. 30, 2022
Mortgaged properties net book value	$ 135,994,289
Effective Interest rate	4.34%
Funded debt to EBITDA ratio	400.00%
Availability under outstanding credit facility	$ 29,000,000
Minimum [Member]
Line Of Credit Facility [Line Items]
Current ratio	100.00%
Dividend payments and stock repurchases leverage ratio	275.00%
Minimum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	0.50%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	2.00%
Maximum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.25%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	2.75%

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Stockholders' Equity (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016	May 31, 2018
Equity, Class of Treasury Stock [Line Items]
Purchase of additional common stock authorized				$ 1,500,000
Purchase of treasury stock	$ 1,219,228	$ 601,853	$ 117,165
Maximum [Member]
Equity, Class of Treasury Stock [Line Items]
Purchase of common stock, approval level				$ 1,500,000
2010 Restricted Stock Plan [Member]
Equity, Class of Treasury Stock [Line Items]
Purchase of treasury stock	$ 1,219,228
Purchase of treasury stock, shares	63,404

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Earnings (Loss) Per Share (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share [Abstract]
Net income (loss)	$ 555,647	$ (775,093)	$ 1,070,176	$ 13,784,939	$ 1,039,134	$ 1,260,758	$ 3,470,433	$ (2,238,392)	$ 14,635,669	$ 3,531,933	$ (10,286,884)
Denominator for basic and diluted earnings per share - Weighted average shares (including for 2018, 2017 and 2016, unissued, vested directors' shares of 205,736, 253,603 and 263,057, respectively)									16,952,664	16,900,185	16,840,856

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Earnings (Loss) Per Share (Parenthetical) (Details) - shares	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share [Abstract]
Vested directors' shares	205,736	253,603	263,057

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Employee Stock Ownership Plan (Narrative) (Details)	12 Months Ended
	Sep. 30, 2018 shares
Share Based Arrangements To Obtain Goods And Services [Abstract]
Percentage of Company Contributions Are Allocated To Employee Stock Ownership Plan Participants	100.00%
Eligibility of Receiving Full Contribution Of Employee Stock Ownership Plan	3 years
Number of Common Stock Share held for ESOP plan	247,667

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Employee Stock Ownership Plan (Summary Of Plan Contributions) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Share Based Arrangements To Obtain Goods And Services [Abstract]
Shares Contributed to the ESOP	20,632	13,125	11,418
Amount Contributed to the ESOP	$ 382,174	$ 312,380	$ 200,158

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Deferred Compensation Plan For Directors (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Deferred Compensation Plan For Directors [Line Items]
Number of shares credited to directors deferred fee account	212,574	261,846
Outstanding deferred balance	$ 2,950,405	$ 3,459,909
Total expenses charged to the company's results of operations	$ 301,715	$ 358,658	$ 329,465
Maximum [Member]
Deferred Compensation Plan For Directors [Line Items]
Period outside directors may elect to receive shares	10 years

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Restricted Stock Plan (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Mar. 31, 2014	Mar. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of vested shares	$ 1,047,761
2010 Stock Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock authorized		500,000	200,000

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Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 655,414	$ 597,940	$ 781,479
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	276,272	233,122	390,655
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 379,142	$ 364,818	$ 390,824

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Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details)	12 Months Ended
	Sep. 30, 2018 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 596,055
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 321,389
Weighted Average Period (in years)	1 year 9 months 14 days
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 274,666
Weighted Average Period (in years)	1 year 6 months

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Restricted Stock Plan (Summary Of Unvested Shares Of Restricted Stock Awards) (Details) - $ / shares	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Performance Based Restricted Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares, Beginning balance	99,090	114,417	112,251
Unvested Restricted Shares, Granted	29,099	20,531	40,446
Unvested Restricted Shares, Vested	(35,485)	(34,672)	(10,197)
Unvested Restricted Shares, Forfeited		(1,186)	(28,083)
Unvested shares, Ending balance	92,704	99,090	114,417
Weighted Average Grant Date Fair Value, Beginning balance	$ 11.33	$ 9.78	$ 9.20
Weighted Average Grant Date Fair Value, Granted	11.34	14.27	9.32
Weighted Average Grant Date Fair Value, Vested	12.18	8.07	7.59
Weighted Average Grant Date Fair Value, Forfeited		8.07	7.59
Weighted Average Grant Date Fair Value, Ending balance	$ 11.00	$ 11.33	$ 9.78
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares, Beginning balance	24,997	43,011	39,966
Unvested Restricted Shares, Granted	19,918	16,426	26,478
Unvested Restricted Shares, Vested	(16,248)	(28,449)	(23,433)
Unvested Restricted Shares, Forfeited		(5,991)
Unvested shares, Ending balance	28,667	24,997	43,011
Weighted Average Grant Date Fair Value, Beginning balance	$ 19.41	$ 16.25	$ 16.56
Weighted Average Grant Date Fair Value, Granted	20.77	24.41	16.37
Weighted Average Grant Date Fair Value, Vested	19.34	18.02	16.91
Weighted Average Grant Date Fair Value, Forfeited		17.04
Weighted Average Grant Date Fair Value, Ending balance	$ 20.40	$ 19.41	$ 16.25

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Information On Oil And Natural Gas Producing Activities (Details)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Company A [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	24.00%	18.00%	23.00%
Company B [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	16.00%	3.00%	3.00%
Company C [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	11.00%	8.00%	2.00%
Company D [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	7.00%	13.00%	12.00%

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Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Capitalized Costs of Oil and Natural Gas Properties and Related Depreciation, Depletion and Amortization) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Extractive Industries [Abstract]
Producing properties	$ 427,448,584	$ 434,571,516
Non-producing minerals	12,378,395	7,243,802
Non-producing leasehold	185,124	185,125
Gross capitalized costs	440,012,103	442,000,443
Accumulated depreciation, depletion and amortization	(242,169,604)	(245,640,247)
Net capitalized costs	$ 197,842,499	$ 196,360,196

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Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Costs Incurred in Oil and Natural Gas Producing Activities) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Extractive Industries [Abstract]
Property acquisition costs	$ 11,409,673	$ 20,190
Exploration costs			$ 21,049
Development costs	10,291,476	25,382,377	5,075,710
Total cost incurred	$ 21,701,149	$ 25,402,567	$ 5,096,759

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Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Net Quantities of Proved, Developed and Undeveloped Oil and Natural Gas Reserves) (Details)	12 Months Ended
	Sep. 30, 2018 Bcfe bbl Mcf	Sep. 30, 2017 Bcfe bbl Mcf	Sep. 30, 2016 Bcfe bbl Mcf
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance | Bcfe	168.6	124.0	180.0
Revisions of previous estimates | Bcfe	(6.7)	17.6	(63.5)
Acquisitions (divestitures) | Bcfe	(0.2)	(1.0)
Extensions, discoveries and other additions | Bcfe	24.2	39.0	19.1
Production | Bcfe	(12.3)	(11.1)	(11.5)
Proved Oil and Natural Gas Reserves, Ending Balance | Bcfe	173.6	168.6	124.0
Oil [Member]
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance	5,509,667	5,426,090	7,038,430
Revisions of previous estimates	(1,407,995)	253,481	(1,552,010)
Acquisitions (divestitures)	236,690	(37,724)
Extensions, discoveries and other additions	1,982,624	178,497	303,922
Production	(336,564)	(310,677)	(364,252)
Proved Oil and Natural Gas Reserves, Ending Balance	5,984,422	5,509,667	5,426,090
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance	2,384,699	1,622,703	2,920,600
Revisions of previous estimates	303,728	407,250	(1,192,143)
Acquisitions (divestitures)	24,765	(12,953)
Extensions, discoveries and other additions	476,174	541,557	65,306
Production	(255,176)	(173,858)	(171,060)
Proved Oil and Natural Gas Reserves, Ending Balance	2,934,190	2,384,699	1,622,703
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance | Mcf	121,195,120	81,725,598	120,214,044
Revisions of previous estimates | Mcf	(29,247)	13,651,501	(47,068,144)
Acquisitions (divestitures) | Mcf	(1,782,949)	(669,064)
Extensions, discoveries and other additions | Mcf	9,400,374	34,681,614	16,864,075
Production | Mcf	(8,721,262)	(8,194,529)	(8,284,377)
Proved Oil and Natural Gas Reserves, Ending Balance | Mcf	120,062,036	121,195,120	81,725,598

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Supplementary Information On Oil, NGL And Natural Gas Reserves (Narrative) (Details)	12 Months Ended	24 Months Ended
	Sep. 30, 2018 Mcfe $ / bbl $ / Mcf	Sep. 30, 2018 Mcfe $ / bbl $ / Mcf	Sep. 30, 2017 Mcfe $ / bbl $ / Mcf	Sep. 30, 2016 $ / bbl $ / Mcf
Supplementary Oil And Gas Disclosures [Line Items]
Negative pricing revisions	2,400,000
Negative revisions, developed	1,700,000
Negative revisions, undeveloped	700,000
Negative performance revisions	4,200,000
Proved developed reserve extensions, discoveries and other additions	3,700,000
Proved undeveloped reserves, additions	20,400,000
Proved undeveloped Reserves	63,899,996	63,899,996	56,880,555
Proved undeveloped reserves transferred to proved developed	2,158,716
Percentage transferred to proved developed	4.00%	41.00%
Revisions of proved undeveloped reserves	12,456,931
Revisions percentage of proved undeveloped reserves	22.00%
Proved undeveloped reserves drilled or completed	1,200,000
Anadarko Basin Woodford and Southeastern Oklahoma Woodford [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Positive revisions, developed	7,600,000
Eagle Ford [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Negative revisions, undeveloped	11,800,000
Program development projected period	5 years
Northwestern Oklahoma and Kearny County, Kansas [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Divestiture of marginal properties	2,800,000
Oil [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Price used to calculate reserves and future cash flows from reserves | $ / bbl	62.86	62.86	46.31	36.77
Natural Gas Liquids [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Price used to calculate reserves and future cash flows from reserves | $ / bbl	26.13	26.13	17.55	12.22
Natural Gas [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Price used to calculate reserves and future cash flows from reserves | $ / Mcf	2.56	2.56	2.81	1.97
Oil, NGL And Natural Gas [Member] | Bakken, North Dakota [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Acquisition	2,600,000
Proved developed acquisition	1,400,000
Proved undeveloped acquisition	1,200,000

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Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Proved Developed and Undeveloped Reserves) (Details)	Sep. 30, 2018 bbl Mcf	Sep. 30, 2017 bbl Mcf	Sep. 30, 2016 bbl Mcf
Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	2,334,587	2,201,528	1,980,519
Proved Undeveloped Reserves (Volume)	3,649,835	3,308,139	3,445,571
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	2,085,706	1,768,425	1,095,256
Proved Undeveloped Reserves (Volume)	848,484	616,274	527,447
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | Mcf	83,151,954	87,861,043	62,929,047
Proved Undeveloped Reserves (Volume) | Mcf	36,910,082	33,334,077	18,796,551

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Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Proved Undeveloped Reserves) (Details)	12 Months Ended
	Sep. 30, 2018 Mcfe
Extractive Industries [Abstract]
Beginning proved undeveloped reserves	56,880,555
Proved undeveloped reserves transferred to proved developed	(2,158,716)
Revisions	(12,456,931)
Extensions and discoveries	20,413,545
Purchases	1,221,543
Ending proved undeveloped reserves	63,899,996

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Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Extractive Industries [Abstract]
Future cash inflows	$ 759,899,074	$ 637,509,599	$ 380,263,695
Future production costs	(259,413,766)	(256,193,675)	(182,948,045)
Future development and asset retirement costs	(89,518,449)	(93,133,683)	(72,431,842)
Future income tax expense	(95,872,182)	(102,193,819)	(38,674,100)
Future net cash flows	315,094,677	185,988,422	86,209,708
10% annual discount	(158,768,823)	(105,155,847)	(56,439,589)
Standardized measure of discounted future net cash flows	$ 156,325,854	$ 80,832,575	$ 29,770,119	$ 81,591,211

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Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Extractive Industries [Abstract]
Beginning Balance	$ 80,832,575	$ 29,770,119	$ 81,591,211
Sales of oil, NGL and natural gas, net of production costs	(32,836,007)	(25,783,055)	(16,749,632)
Net change in sales prices and production costs	47,533,281	37,186,619	(86,198,778)
Net change in future development and asset retirement costs	1,580,942	(7,939,156)	21,636,258
Extensions and discoveries	34,667,557	38,582,908	11,640,704
Revisions of quantity estimates	(8,391,223)	15,282,587	(41,716,689)
Acquisitions (divestitures) of reserves-in-place	(307,472)	(962,667)
Accretion of discount	12,602,209	4,789,294	14,424,032
Net change in income taxes	(3,057,128)	(27,070,430)	44,533,277
Change in timing and other, net	23,701,120	16,976,356	609,736
Net change	75,493,279	51,062,456	(51,821,092)
Ending Balance	$ 156,325,854	$ 80,832,575	$ 29,770,119

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Quarterly Results Of Operations (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 11,564,543	$ 9,557,937	$ 11,421,258	$ 12,490,526	$ 12,896,932	$ 12,437,186	$ 13,964,288	$ 7,036,643	$ 45,034,264	$ 46,335,049	$ 39,060,783
Income (loss) before provision for income taxes	759,647	(984,093)	1,046,176	1,074,939	1,465,134	1,827,758	4,273,433	(3,345,392)
Net income (loss)	$ 555,647	$ (775,093)	$ 1,070,176	$ 13,784,939	$ 1,039,134	$ 1,260,758	$ 3,470,433	$ (2,238,392)	$ 14,635,669	$ 3,531,933	$ (10,286,884)
Earnings (loss) per share	$ 0.04	$ (0.05)	$ 0.06	$ 0.81	$ 0.06	$ 0.07	$ 0.21	$ (0.13)	$ 0.86	$ 0.21	$ (0.61)

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Subsequent Events (Narrative) (Details)		12 Months Ended
	Nov. 30, 2018 USD ($) a $ / a	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
Subsequent Event [Line Items]
Proceeds from sales of assets		$ 1,085,137	$ 723,700	$ 4,501,726
Net book value of minerals		$ 198,284,401	$ 196,584,358
Lea and Eddy Counties, New Mexico [Member]
Subsequent Event [Line Items]
Percentage of net mineral acreage sold		0.08%
Percentage of net mineral acreage sold on overall production		0.70%
Percentage of net mineral acreage sold on overall revenues		0.90%
Percentage of net mineral acreage sold on proved reserves		1.20%
Net book value of minerals		$ 0
Subsequent Event [Member] | Lea and Eddy Counties, New Mexico [Member]
Subsequent Event [Line Items]
Mineral acreage sold | a	206
Proceeds from sales of assets	$ 9,300,000
Sale price per acre | $ / a	45,000