10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended SEPTEMBER 30, 2020

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM                      TO                     

Commission File Number 001-31759

PHX MINERALS INC.

(Exact name of Registrant as specified in its Charter)

oklahoma	73-1055775
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Valliance Bank Tower, Suite 1100, 1601 NW Expressway Oklahoma City, OK	73118
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (405) 948-1560

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, $0.01666 par value	PHX	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

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

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

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).  Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☒
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.  ☐

Indicate by check mark whether the Registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☒

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  yes ☐ no ☒

The aggregate market value of the voting stock held by non-affiliates of the registrant, computed by using the $3.69 per share closing price of registrant's Class A Common Stock, as reported by the New York Stock Exchange at March 31, 2020, was $56,675,049.

The number of shares of Registrant’s Class A Common Stock outstanding as of December 3, 2020, was 22,389,194.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of PHX Minerals Inc. (to be filed no later than 120 days after September 30, 2020) relating to the Annual Meeting of Stockholders to be held on March 2, 2021, are incorporated into Part III of this Form 10-K.

T A B L E   O F   C O N T E N T S

		Page
	Special Note Regarding Forward-Looking Statements
	Glossary of Certain Terms
PART I
Item 1	Business	1
Item 1A	Risk Factors	6
Item 1B	Staff Comments	19
Item 2	Properties	19
Item 3	Legal Proceedings	26
Item 4	Mine Safety Disclosures	26
PART II
Item 5	Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6	Selected Financial Data	29
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	40
Item 8	Financial Statements and Supplementary Data	42
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	78
Item 9A	Controls and Procedures	78
Item 9B	Other Information	78
PART III
Item 10-14	Incorporated by Reference to Proxy Statement	79
PART IV
Item 15	Exhibits, Financial Statement Schedules and Reports on Form 8-K	80

Special Note Regarding Forward Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements. Forward-looking statements may include, but are not limited to statements relating to: our ability to execute our business strategies; the volatility of realized natural gas and oil prices; the level of production on our properties; estimates of quantities of natural gas, oil and NGL reserves and their values; general economic or industry conditions; legislation or regulatory requirements; conditions of the securities markets; our ability to raise capital; changes in accounting principles, policies or guidelines; financial or political instability; acts of war or terrorism; title defects in the properties in which we invest; and other economic, competitive, governmental, regulatory or technical factors affecting our properties, operations or prices.

We caution you that the forward-looking statements contained in this Form 10-K are subject to risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas and oil. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended September 30, 2020 (the “2020 Annual Report on Form 10-K” or this “Annual Report”), and all quarterly reports on Form 10-Q filed subsequently thereto.

Should one or more of the risks or uncertainties described above or elsewhere in our 2020 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date of which such statement is made, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Glossary of Certain Terms

The following is a glossary of certain accounting, natural gas and oil industry and other defined terms used in this Annual Report:

ASU	Accounting Standards Update.
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.
Bbl	barrel.
Board	board of directors of the Company.
BTU	British Thermal Units.
Common Stock	the Company’s Class A Common Stock.
completion	the process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas and/or crude oil.
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 natural gas or crude oil reservoir to the depth of a stratigraphic horizon known to be productive.
dry hole	exploratory or development well that does not produce natural gas and/or crude oil in economically producible quantities.
EBITDA	earnings before interest, taxes, depreciation and amortization (including impairment). This is a Non-GAAP measure.
ESOP	the PHX Minerals 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 natural gas or crude oil 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 costs.
GAAP	generally accepted accounting principles.
gross acres or gross wells	the total acres or wells in which an interest is owned.
held by production or HBP	an oil and gas lease continued in effect into its secondary term for so long as a producing gas and/or oil 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 natural gas and crude oil production.
Independent Consulting Petroleum Engineer(s)	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.
Mcfed	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 per day.
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.
NRI	net revenue interest.
NYMEX	New York Mercantile Exchange.
OPEC	Organization of Petroleum Exporting Countries.
overriding royalty interest	an interest in the natural gas and oil produced under a lease, or the proceeds from the sale thereof, apportioned out of the working interest, to be received free and clear of all costs of development, operation or maintenance.
PDP	proved developed producing.
play	term applied to identified areas with potential natural gas and/or oil reserves.
production or produced	volumes of natural gas, oil and NGL that have been both produced and sold.
proved reserves	the quantities of natural gas and crude oil, 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 natural gas and crude oil occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with gas and oil 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 natural gas and/or crude oil.
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.
WTI	West Texas Intermediate.

As used herein, the “Company,” “PHX,” “we,” “us” and “our” refer to PHX Minerals Inc., formerly known as Panhandle Oil and Gas Inc., and its predecessors and subsidiaries unless the context requires otherwise.

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 2020 mean the fiscal year ended September 30, 2020.

References to natural gas and oil properties

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

PART I

ITEM 1. Business

Overview

PHX Minerals 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., and on October 8, 2020, the Company’s name was changed to PHX Minerals Inc.

PHX Minerals Inc. is an Oklahoma City-based company focused on perpetual natural gas and oil mineral ownership in resource plays in the United States. Prior to a strategy change in 2019, the Company participated with a working interest on some of its mineral and leasehold acreage and as a result, the Company still has legacy interests in leasehold acreage and non-operated interests in natural gas and oil properties.

Strategic Focus on Mineral Ownership

During fiscal 2019, the Company made the strategic decision to focus on perpetual natural gas and oil mineral ownership and growth through the acquisitions of producing minerals in its core areas of focus and the development of its significant mineral acreage inventory. In accordance with this new strategy, the Company ceased taking any working interest positions on its mineral and leasehold acreage going forward. During fiscal 2020, the Company did not participate with a working interest in the drilling of any new wells. The Company believes that its strategy to focus on mineral ownership is the best path to giving its stockholders the greatest risk-weighted returns on their investments going forward.

A “mineral fee” is an interest in real property in which the owner owns all of the rights to the minerals under the surface forever, as compared to a mineral lease in which the lessee’s rights end at the expiration of the lease term or after there is no longer production on the lease. Generally, the mineral interest owner of a mineral fee interest reserves a non-cost bearing royalty interest upon the lease of such gas, oil, and other minerals to a gas and oil exploration and development company. Such companies will lease such mineral interest from the fee mineral owner for a term with the expectation of producing natural gas and oil, thereby generating free cash flow from bonuses and royalties to the mineral interest owner.

As referenced above, the Company’s leasehold interests are non-operated working interests on the lease of the minerals from the mineral fee owner. These non-operated working interests require the Company to contribute its proportionate share of the costs incurred by the operator in the development of such minerals. As discussed above and further below, the Company no longer expects to participate with such working interests going forward. The Company’s mineral and leasehold properties are located primarily in Oklahoma, Texas, North Dakota, Arkansas and New Mexico. The majority of the Company’s natural gas, oil and NGL production is from wells located in Oklahoma, Texas, North Dakota and Arkansas.

Although a significant amount of the Company’s revenues is currently derived from the production and sale of natural gas, oil and NGL on its working interests, a growing portion of its revenues is derived from royalties granted from the production and sale of natural gas, oil and NGL. 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 natural gas, oil or NGL is produced and sold from wells located on the Company’s mineral acreage.

As of September 30, 2020, the Company owned approximately 252,443 perpetual mineral acres, as detailed in the table below:

Play	Net Acres		% Producing	% Leased But Not Producing	% Unleased
Arkoma Stack		11,576	65%	2%	33%
Bakken/Three Forks		3,094	90%	0%	10%
Fayetteville		9,851	72%	0%	28%
Permian		38,788	8%	15%	77%
SCOOP		4,997	50%	15%	35%
STACK		5,767	89%	5%	6%
Other		178,370	19%	3%	78%
Total:		252,443	24%	5%	71%

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Approximately 71% of the Company’s net mineral position is currently unleased, providing the opportunity to generate additional cash flow from bonus payments and royalties without spending additional capital. The Company also owns leases on 17,091 net acres primarily in Oklahoma and working interests, royalty interests or both, in 6,510 producing natural gas and oil wells and 125 wells in the process of being drilled or completed.

Exploration and development of the Company’s natural gas and oil properties are conducted by natural gas and oil exploration and production companies, primarily larger independent operating companies. The Company does not operate any natural gas and oil properties. While the Company previously has been an active working interest participant for many years in wells drilled on its mineral and leasehold acreage, the Company’s current focus is on growth through mineral acquisitions and through development of its significant mineral acreage inventory in its core areas of focus.

We intend to maximize value to our stockholders through the acquisition of mineral acreage in the core areas of resource plays with substantial undeveloped opportunities; divestiture of non-core minerals with limited optionality when the amount negotiated exceeds our projected total value; and aggressive leasing of our mineral holdings.

Our Business Strategy

Our principal business objective is to maximize value to our stockholders. At the end of 2019, we made the strategic decision to cease taking any working interest positions on our mineral and leasehold acreage going forward. Our focus is on growth through mineral acquisitions and through development of our significant mineral acreage inventory in our core areas. We believe this is the best path to giving our stockholders the greatest risk-weighted returns on their investment. We intend to accomplish this objective by executing the following corporate strategies:

• Actively Manage Mineral and Leasehold Assets as a Portfolio to Maximize Value. We plan to manage our mineral and leasehold assets through the following:

o Growing our mineral fee holdings by acquiring mineral acreage in the core areas of natural gas and oil resource plays with substantial undeveloped opportunities that meet or exceed our minimum return threshold;

o Utilizing in-house technology and engineering expertise as a competitive advantage;

o Aggressively leasing our open mineral holdings;

o High-grading our asset base by selectively divesting non-core minerals with limited optionality when the amount negotiated exceeds our projected total value, then redeploying proceeds into our core areas of focus; and

o Optimizing our leasehold and working interest positions through strategic sales and farmouts for overriding royalty interests or cash payments.

• Deleveraging Our Balance Sheet. We plan to reduce debt in order to improve our financial position through the following:

o Continue to repay debt using free cash flow to ensure our ability to successfully operate in all business and commodity environments; and

o Hedging to manage commodity price risk and to protect our balance sheet and cash flow.

Our Business Strengths

We believe the following attributes position the Company to achieve our objectives:

• Focused on Perpetual Mineral Fee Ownership. Our strategic decision to focus on mineral ownership provides us with the perpetual option to benefit from future development and technology. We are focused on generating meaningful revenues through lease bonuses and royalty interests, and these revenues have been a growing proportion of our total revenues when compared to our working interests. We owned approximately 252,443 net mineral acres as of September 30, 2020, held principally in Oklahoma, Texas, North Dakota, Arkansas and New Mexico. We also held leases on 17,091 net acres primarily in Oklahoma; and working interests, royalty interests, or both, in 6,510 producing natural gas and oil wells and 125 wells in the process of being drilled or completed.

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• Mineral and Leasehold Ownership in Multiple Top-Tier Resource Plays. We own mineral and leasehold interests in multiple top-tier resource plays in the United States, including positions in the SCOOP, STACK, Haynesville, Bakken/Three Forks, Arkoma Woodford, Eagle Ford, Permian Basin and Fayetteville plays. A significant portion of our revenues is derived from the production and sale of natural gas, oil and NGL from these positions. During the fiscal year ended September 30, 2020, production on our acreage averaged 23,479 Mcfed with approximately 69%, 19% and 12% derived from natural gas, oil and NGL, respectively.

• Material Undeveloped Mineral Position in Gas and Oil Producing Basins. Over 70% of our mineral fee position is currently not leased or producing, providing us with significant potential value and the opportunity to generate additional cash flows from bonus payments and royalties without deploying additional capital. We have an active program in place focused on leasing open acreage to generate additional lease bonus revenue and future royalty revenue.

• Stable and Flexible Financial Position. We maintain a stable and flexible financial position through the management of our debt, cash and working capital. We hedge to manage commodity price risk and to protect our balance sheet and cash flow.

• Experienced Management and Technical Team. We have a management and technical team with extensive experience in the oil and gas industry. Our management and technical team average over 20 years of industry experience in each applicable area of the Company, including accounting, land, geology, engineering and mergers and acquisitions.

Principal Products and Markets

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

Prices of natural gas, oil and NGL are dependent on numerous factors beyond the Company’s control, including supply and demand, competition, weather, international events and geo-political 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 may be 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 natural gas and oil and protect its return on investments. The derivative contracts apply only to a portion of the Company’s natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in natural gas and oil prices. Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 12 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the derivative contracts entered into by the Company.

Competitive Business Conditions

The oil and natural gas industry is highly competitive, particularly in the search for new fee mineral interests and natural gas, oil and NGL reserves. Many factors beyond its control affect the Company’s competitive position. Some of these factors include: the quantity and price of foreign oil imports; domestic supply and deliverability of natural gas, oil and NGL; changes in prices received for natural gas, oil and NGL production; business and consumer demand for refined natural gas, oil products and NGL; and the effects of federal, state and local regulation of the exploration for, production of and sales of natural gas, oil and NGL (see Item 1A – “Risk Factors”). Many companies have substantially greater resources than we have, and such companies may have more resources to evaluate, bid for and purchase more mineral fee, royalty and similar interests than our financial or human resources permit.

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 stable and flexible financial position, coupled with its own geologic and economic evaluations, to acquire new mineral acreage and to lease or farmout its mineral and leasehold acreage ownership. We believe this strategy allows the Company to compete effectively in a competitive mineral market; however, our ability to acquire additional mineral fee, royalty and

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similar interests in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Major Customers

The Company’s natural gas, oil and NGL production is sold, in most cases, through our lessees or well operators to numerous different purchasers.

Regulation of the Oil and Natural Gas Industry

General

As the owner of mineral fee interests and non-operating working interests, we do not have any employees or contractors in the field, and we are not directly subject to many of the regulations of the oil and gas industry. The following disclosure describes regulations and environmental matters more directly associated with operators of natural gas and oil properties, including our current operators. Since the Company does not operate any wells in which it owns an interest, actual compliance with many laws and regulations is controlled by the well operators, with the Company being responsible only for its proportionate share of the costs, if any, involved on wells in which it owns a working interest.

Natural gas and oil operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision. Some of these requirements carry substantial penalties for failure to comply.

Although we are generally not directly subject to many of the rules, regulations and limitations impacting the natural gas and oil exploration and production industry as whole, the operators who operate on our properties may be impacted by such rules and regulations and we may be responsible for our proportionate share of costs for wells on which we own a working interest. While this may provide the Company with some insulation from compliance costs applicable to our operator-lessees, we may still be indirectly impacted by operator regulations because our revenue stream depends on operators and the production of natural gas, oil and NGL.

Regulation of Drilling and Production

The production of natural gas and oil is subject to regulation under federal, state and local statutes, rules, orders and regulations. These statutes and regulations require that operators obtain permits for drilling operations and drilling bonds, as well as require reports concerning operations. Additionally, states where we own mineral and leasehold interests have enacted regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, the regulation of well spacing and plugging and abandonment of wells. The effect of these regulations is to limit the amount of natural gas and oil that can be produced from wells and to limit the number of wells or the locations which can be drilled. Additionally, some states where we hold mineral or leasehold interests may impose a production or severance tax with respect to the production and sale of natural gas, oil and NGL within its jurisdiction.

Regulation of Transportation of Oil

The sale and transportation of our crude oil is generally undertaken by the operators (or by third parties at the direction of the operators) of our properties. Sales of crude oil, condensate and NGL are not currently regulated and are made at negotiated prices; however, Congress could reenact price controls in the future.

Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (the “FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs.

Regulation of Transportation and Sale of Natural Gas

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The sale and transportation of our natural gas is generally undertaken by the operators (or by third parties at the direction of the operators) of our properties. Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

The FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state.

Environmental Compliance and Risks

Our operators and properties are impacted by extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment and relating to safety and health.

Natural gas and oil exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Historically, most of the environmental regulation of gas and oil production has been left to state regulatory boards or agencies in those jurisdictions where there is significant natural gas and oil production, with limited direct regulation by such federal agencies as the Environmental Protection Agency. However, there are various regulations issued by the Environmental Protection Agency (“EPA”) and other governmental agencies that would govern significant spills, blow-outs or uncontrolled emissions.

Many states, including states where we own properties, have enacted natural gas and oil regulations that apply to the drilling, completion and operations of wells and the disposal of waste oil and salt water. The operators of our properties are subject to such regulations. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

At the federal level, among the more significant laws and regulations that may affect our business and the oil and natural gas industry are: The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund; the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act, also known as “RCRA”; the Clean Air Act; Federal Water Pollution Control Act of 1972, or the Clean Water Act; and the Safe Drinking Water Act of 1974.

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 the Company being responsible for its proportionate share of the costs involved on wells in which we own a working interest. As such, the Company has no knowledge of any instances of non-compliance with existing laws and regulations. The Company maintains insurance coverage at levels which are customary in the industry, but is not fully insured against all environmental risks.

Taxes

The Company’s natural gas and oil properties are subject to various taxes, such as gross production taxes and, in some cases, ad valorem taxes. The Company pays ad valorem taxes on minerals owned in ten states.

Employees

At September 30, 2020, the Company employed 17 people, including executive officers.

Executive Officers

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Chad L. Stephens has served as President, Chief Executive Officer and Director since January 2020.  Mr. Stephens served as Interim CEO from October 2019 to December 2019, and he has served as a Director since September 2017.  Prior to joining the Company, Mr. Stephens held several positions at Range Resources Corporation starting in 1990, and from 2002 through his retirement in 2018, he served as Senior Vice President – Corporate Development.

Ralph D’Amico has served as Chief Financial Officer and Corporate Secretary since March 2020 and as Vice President – Business Development since January 2019.  Prior to joining the Company, Mr. D’Amico served as Managing Director at Seaport Global and held various positions at Stifel Nicolaus, Jefferies, Friedman Billings Ramsey and Salomon Smith Barney.

Freda R. Webb has served as Vice President, Mineral Operations since January 2017.  Ms. Webb served the Company as a reservoir engineering consultant from 2011 to 2015. In 2015 she was appointed to the Reservoir Engineering Manager position.  Prior to joining the Company, Ms. Webb held various reservoir engineering, acquisitions, corporate planning and management positions for Cities Services, Occidental Petroleum and Southwestern Energy.  

Corporate Office

The Company’s office is located at Valliance Bank Tower, Suite 1100, 1601 NW Expressway, Oklahoma City, OK 73118. Our telephone number is (405) 948-1560 and facsimile number is (405) 948-1063. The Company’s website is www.phxmin.com.

Available Information

We make available free of charge on our website (www.phxmin.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC.

We also make available within the “Corporate Governance” section under the “Investors” section of our website our Code of Ethics & Business Practices, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines, Lead Independent Director Charter and Audit Committee, Corporate Governance and Nominating Committee and Compensation Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Ethics & Business Practices and Code of Ethics for Senior Financial Officers for our principal executive and senior financial officers. Copies of our Code of Ethics & Business Practices and Code of Ethics for Senior Financial Officers are available free of charge by writing us at: PHX Minerals Inc., Attn: Chad True, 1601 NW Expressway, Suite 1100, Oklahoma City, OK 73118.

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 the Company. As the owner of mineral fee interests and non-operating working interests, we do not operate any natural gas and oil properties, and we do not have any employees or contractors in the field. As such, the risks associated with natural gas and oil operations only affect us indirectly and typically through our non-operating working interests as we proportionately share in the costs of operating such wells. 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.

Risks Related to our Business

The volatility of natural gas and oil prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

The supply of and demand for natural gas, oil and NGL impact the prices we realize on the sale of these commodities and, in turn, materially affect the Company’s financial results. Natural gas, oil and NGL prices have historically been, and will likely continue to be, volatile. The prices for natural gas, oil and NGL 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;

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• market uncertainty;

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

• the impacts and effects of public health crises, pandemics and epidemics, such as the ongoing COVID-19 pandemic;

• 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 natural gas, oil and NGL;

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

• actions taken by OPEC or other major natural gas, oil and NGL producing or consuming countries;

• competition from alternative sources of energy; and

• technological advancements affecting energy consumption and energy supply.

Our revenues, operating results, cash available for distribution and the carrying value of our natural gas and oil properties depend significantly upon the prevailing prices for natural gas and oil. Historically, natural gas and oil prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

• the domestic and foreign supply of natural gas and oil;

• the level of prices and expectations about future prices of natural gas and oil;

• the level of global natural gas and oil exploration and production;

• the cost of exploring for, developing, producing and delivering natural gas and oil;

• the price and quantity of foreign imports;

• political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

• the impacts and effects of public health crises, pandemics and epidemics, such as the ongoing COVID-19 pandemic;

• the ability of members of OPEC to agree to and maintain oil price and production controls;

• speculative trading in natural gas and crude oil derivative contracts;

• the level of consumer product demand;

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• weather conditions and other natural disasters;

• risks associated with operating drilling rigs;

• technological advances affecting energy consumption;

• the price and availability of alternative fuels;

• domestic and foreign governmental regulations and taxes;

• the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

• the proximity, cost, availability and capacity of natural gas and oil pipelines and other transportation facilities; and

• overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas and oil price movements with any certainty. If the prices of natural gas and oil remain at current levels or decline further, our operations, financial condition and level of expenditures for the development of our natural gas and oil reserves may be materially and adversely affected. Lower natural gas and oil prices may also result in a reduction in the borrowing base under our credit agreement, which may be determined at the discretion of our lenders.

Low natural gas, oil and NGL 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 natural gas, oil and NGL price movements with any certainty. Natural gas, oil and NGL prices continued to fluctuate in fiscal year 2020 and have fluctuated significantly over the past several months as a result of the ongoing COVID-19 pandemic. The Company’s financial position, results of operations, access to capital and the quantities of natural gas, oil and NGL that may be economically produced would be negatively impacted if natural gas, oil and NGL prices were low for an extended period of time. The ways in which low prices could have a material negative effect include:

• significantly decrease the number of wells 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; and

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

The ongoing COVID-19 pandemic may adversely affect our business, financial condition and results of operations.

The global spread of the ongoing COVID-19 pandemic (“COVID-19”) has created significant uncertainty and economic disruption, as well as heightened volatility in the prices of oil and natural gas. The negative impact on worldwide demand for oil and natural gas resulting from COVID-19 led to a precipitous decline in oil prices, further exacerbated by the early March 2020 failure by OPEC+ to reach an agreement over proposed oil production cuts and global storage considerations. Although OPEC+ subsequently agreed to cut oil production and has extended such production cuts through December 2020, crude oil prices remain depressed as a result of an increasingly utilized global storage network and the decrease in crude oil demand due to COVID-19. Oil and natural gas prices are expected to continue to be volatile as a result of these events and COVID-19 outbreak, and as changes in oil and natural gas inventories, oil demand and economic performance are reported. The response to the COVID-19 outbreak is rapidly evolving, and the

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ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of COVID-19 on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, actions to contain the disease or mitigate its impact and the development and availability of effective treatments and vaccines, all of which are highly uncertain and cannot be predicted with certainty at this time. Sustained low oil prices due to COVID-19 could result in the events discussed in the immediately preceding risk factor, which could have a material adverse effect on our business and financial results. We are unable to predict the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments, including the pandemic’s ongoing effect on the demand for oil and natural gas and the response of the overall economy and the financial markets after governmental restrictions are eased or after an effective treatment becomes available.

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

The Company has elected to utilize the successful efforts method of accounting for its natural gas and oil 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 natural gas, oil and NGL volumes produced to total proved or proved developed reserves) as natural gas, oil and NGL are produced.

All long-lived assets, principally the Company’s natural gas and oil 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 natural gas, oil and NGL sales prices or unfavorable adjustments to natural gas, oil and NGL reserves. The decision to not participate in future development on our leasehold acreage can trigger a test for impairment. 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 11 to the financial statements included in Item 8 – “Financial Statements and Supplemental Data” for further discussion on impairment under the heading “Impairment.”

Our future success depends on finding, developing or acquiring additional reserves, and failure to find or acquire additional reserves will cause reserves and production to decline materially from their current levels.

The rate of production from natural gas and oil 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 natural gas and oil 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 natural gas, oil or NGL 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;

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• 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; and

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

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold properties, which could result in unforeseen operating difficulties. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and cash available for distribution. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for distribution.

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Any acquisition involves potential risks, including, among other things:

• the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses and costs;

• a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;

• a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

• mistaken assumptions about the overall cost of equity or debt;

• our ability to obtain satisfactory title to the assets we acquire;

• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

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• the occurrence of other significant changes, such as impairment of natural gas and oil properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

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 natural gas, oil and NGL with precision. Natural gas, oil and NGL reserve engineering requires subjective estimates of underground accumulations of natural gas, oil and NGL 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 (DeGolyer and MacNaughton of Dallas, Texas) must make various assumptions with respect to many matters that may prove to be incorrect, including:

• future natural gas, oil and NGL prices;

• unexpected complications from offset well development;

• production rates;

• reservoir pressures, decline rates, drainage areas and reservoir limits;

• interpretation of subsurface conditions including geological and geophysical data;

• potential for water encroachment or mechanical failures;

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

• 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.

The Company’s 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 natural gas, oil and NGL reserves. Please read Item 2 – “Properties – Proved Reserves” and Note 16 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 natural gas, oil and NGL reserves.

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The timing of the development and production on 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.

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, 2020, the Company had a balance of $28,750,000 drawn on the facility. On December 4, 2020, the facility’s borrowing base after Quarterly Commitment Reductions was reaffirmed at $30,000,000, which is secured by all of the Company’s producing gas and oil 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; and

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

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.

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 natural gas and oil 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 or grow production.

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

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of natural gas, oil and NGL 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.

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

In order to manage exposure to price volatility on our natural gas and oil production, we currently, and may in the future, enter into natural gas and oil derivative contracts for a portion of our expected production. Natural gas and oil price derivatives may limit the cash flow we actually realize and therefore reduce the Company’s ability to fund future projects. None of our natural gas and oil 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 natural gas and oil. The fair value of our natural gas and oil derivative instruments outstanding as of September 30, 2020, was a net liability of $707,647.

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 natural gas and oil production to commodity price changes and could have a negative effect on our ability to fund future acquisitions.

Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 and 12 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding derivative contracts.

Future legislative or regulatory changes, including those resulting from the United States election in 2020, may result in increased costs and decreased revenues, cash flows and liquidity.

Companies that operate wells in which the Company owns a working interest are subject to extensive federal, state and local regulation. The Company, 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. In particular, changes in law or regulation related to hydraulic fracturing or greenhouse gases could potentially increase capital, compliance and operating costs significantly, as well as halt or delay the further development of oil and gas reserves on the Company’s properties.

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 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.

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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 natural gas, oil and NGL 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 was 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 natural gas, oil and NGL in Oklahoma, including wells in which the Company owns an interest.

Hydraulic Fracturing and Water Disposal

The vast majority of natural gas and oil 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 natural gas and oil production. In developing plays where hydraulic fracturing, which requires large volumes of water, is necessary for successful development, the demand for water may exceed the supply. A lack of readily available water or a significant increase in the cost of water could cause delays or increased completion costs.

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

Once a well has been hydraulically fractured, the fluid produced from the fractured wells must be either treated for reuse or disposed of by injecting the fluid into disposal wells. Injection well disposal processes have been, and continue to be, studied to determine the extent of correlation between injection well disposal and the occurrence of earthquakes. Certain studies have concluded there is a correlation, and this has resulted in the cessation of or the reduction of injection rates in certain water disposal wells, especially in northern Oklahoma.

Efforts to regulate hydraulic fracturing and fluid disposal continue at the local, state and federal level. New regulations are being considered, including limiting water withdrawals and usage, limiting water disposition, restricting which additives may be used, implementing 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. In addition, critical declarations made by one or more candidates seeking the office of the President of the United States in 2020 include proposals to ban hydraulic fracturing of oil and gas wells and to ban new leases for production of minerals on federal properties. Consequences of these actions could potentially increase capital, compliance and operating costs significantly, as well as delay or halt the further development of gas and oil 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 natural gas and oil, 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 gas and oil 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

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community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, in preparing an agreement which set greenhouse gas emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. To help achieve these reductions, federal agencies addressed climate change through a variety of administrative actions. The U.S. Environmental Protection Agency (the “EPA”) issued greenhouse gas monitoring and reporting regulations that cover natural gas and oil 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 resulted in an exit in November 2020. The United States’ adherence to the exit process is 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. Critical declarations made by one or more candidates seeking the office of the President of the United States in 2020 include a proposal to reverse the United States’ withdrawal from the Paris Agreement.

The direction of future U.S. climate change regulation is difficult to predict given the current uncertainties surrounding the policies of the Trump Administration and the outcome of the United Stated election in 2020. 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.

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 (the United States Commodity Futures Trading Commission) 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.

Risks Related to our Third-Party Operators

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;

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• capital required to workover or recomplete 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; and

• plugging and abandonment costs, including well-site restorations.

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

The natural gas and oil drilling and producing operations of our third-party operators involve various risks.

Because we do not operate our properties, our business relies heavily upon our third-party operators and their operational effectiveness. Through our third-party operators, we are subject to all the risks normally incident to the operation and development of natural gas and oil 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;

• natural gas, oil and NGL 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; and

• regulatory compliance issues.

As a non-operator, we are also 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.

We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.

A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease

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on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell natural gas or oil at the same price as the operator it replaced.

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 natural gas, oil and NGL 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 natural gas, oil and NGL 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.

The marketability of natural gas and oil production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators’ control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.

The marketability of our or our operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, the shipment of our or our operators’ natural gas and oil on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations and cash distributions to stockholders. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil production, transportation and pipeline safety—as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

Risks Related to the Oil and Gas Industry

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, financial condition and cash available for distribution.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit in the European, Asian and the U.S. markets contribute to economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of natural gas, oil and NGL, volatility in consumer confidence and job markets, may result in an economic slowdown or recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which natural gas, oil and NGL from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.

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Conservation measures and technological advances could reduce demand for natural gas and oil.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas and oil. The impact of the changing demand for natural gas and oil services and products may have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Risks Related to an Investment in our Common Stock

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 stockholders.

The Company filed a shelf registration statement on October 19, 2020, that will allow 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 expect the SEC to declare the shelf registration to be effective after we file an amended shelf registration and issue the September 30, 2020, financials.

We cannot predict the effect, if any, that market sales of these securities or the availability of the securities will have on the prevailing market price of our common stock 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 stockholders to sell shares of our common stock at prices they deem acceptable.

We are currently authorized to issue an aggregate of 24,000,500 shares of common stock of which 22,389,194 shares were issued and outstanding on December 3, 2020. Future issuances of our common stock, or other securities convertible into our common stock, may result in significant dilution to our existing stockholders. Significant dilution would reduce the proportionate ownership and voting power held by our existing stockholders.

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 $0.01 per share, and we have paid a quarterly dividend of $0.01 per share or $0.04 per share 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.

If we cannot meet the NYSE continued listing requirements, the NYSE may delist our common stock.

Our common stock is currently listed on the NYSE. In the future, if we are unable to meet the continued listing requirements of the NYSE, including, among other things, (i) the requirement of maintaining a minimum average closing price of $1.00 per share over a consecutive 30 trading-day period and (ii) the requirement of maintaining an average market capitalization of not less than $50 million over a 30 trading-day period with, at the same time, stockholders’ equity not less than $50 million, we would fall below compliance standards and risk having our common stock delisted. In addition, in the event of an abnormally low share price of our common stock and/or we fail to maintain an average market capitalization of at least $15 million over a 30-trading day period, we would be subject to immediate delisting under the NYSE’s rules without any opportunity to cure. A delisting of our common stock could negatively impact us by, among other things, the following:

• causing the Company’s shares to be transferred to a more limited market than the NYSE, which could affect the market price, trading volume, liquidity and resale price of such shares;

• reducing the number of investors, including institutional investors, willing to hold or acquire our common stock, which could negatively impact our ability to raise equity;

• decreasing the amount of news and analyst coverage relating to us;

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• limiting our ability to issue additional securities, obtain additional financing or pursue strategic restructuring, refinancing or other transactions; and

• impacting our reputation and, as a consequence, our business.

ITEM 1B. Staff Comments

None

ITEM 2. Properties

General Background

The Company is focused on perpetual natural gas and oil mineral ownership in resource plays in the United States. As part of our evolution as a company, we also own interests in leasehold acreage and non-operated working interests in natural gas and oil properties.

At September 30, 2020, the Company’s principal properties consisted of (i) perpetual ownership of 252,443 net mineral acres, held principally in Oklahoma, Texas, North Dakota, Arkansas and New Mexico; (ii) leases on 17,091 net acres primarily in Oklahoma; and (iii) working interests, royalty interests or both in 6,510 producing natural gas and oil wells and 125 wells in the process of being drilled or completed.

Management’s Business Strategy Related to Properties

During fiscal 2019, the Company made the strategic decision to focus on perpetual natural gas and oil mineral ownership and growth through mineral acquisitions and the development of its significant mineral acreage inventory in its core areas of focus. In accordance with this strategy, the Company will no longer participate in new development on its mineral or leasehold acreage with a cost-bearing working interest. The Company believes that its strategy to focus on mineral ownership is the best path to giving the Company’s stockholders the greatest risk-weighted returns on their investments.

Our goal is to increase stockholder value through the management of our fee mineral and leasehold assets as a portfolio. We plan to grow our mineral fee holdings by acquiring mineral acreage, in the core areas of resource plays with substantial undeveloped opportunities, that meets or exceeds our corporate return threshold. We also plan to aggressively lease our mineral holdings. We have an active program in place focused on leasing open acreage to generate additional lease bonus revenue and future royalty revenue.

Title to Properties

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 its properties. In recent years, a few insignificant challenges have been made against the Company’s fee title to its acreage.

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Acreage

Mineral Interests Owned

The following table of mineral interests owned reflects, in each respective state, the number of (i) net and gross acres owned by the Company, (ii) net and gross producing acres owned by the Company, (iii) net and gross acres leased to others by the Company and (iv) net and gross acres open (unleased) as of September 30, 2020.

State	Net Acres		Gross Acres		Net Acres Producing (1)		Gross Acres Producing (1)		Net Acres Leased to Others (2)		Gross Acres Leased to Others (2)		Net Acres Open (3)		Gross Acres Open (3)
Arkansas		11,914		51,169		7,183		27,145		-		-		4,731		24,024
New Mexico		56,649		171,868		821		5,310		260		535		55,568		166,023
North Dakota		14,302		78,096		2,772		14,483		-		-		11,530		63,613
Oklahoma		109,131		916,270		45,146		359,870		6,089		40,176		57,896		516,224
Texas		42,436		356,212		5,200		52,864		5,807		43,979		31,429		259,369
Other		18,011		88,365		331		3,280		8		80		17,672		85,005
Total:		252,443		1,661,980		61,453		462,952		12,164		84,770		178,826		1,114,258

(1) “Producing” represents the mineral acres in which PHX owns a royalty or working interest in a producing well.

(2) “Leased” represents the mineral acres owned by PHX that are leased to third parties but not producing.

(3) “Open” represents mineral acres owned by PHX that are not leased or in production.

Leases

The following table reflects the Company’s net mineral acres leased from others, lease expiration dates, and net leased acres held by production as of September 30, 2020.

			Net Acres Expiring
State	Net Acres		2021		2022		2023		2024		2025		Net Acres Held by Production
Arkansas		2,159		-		-		-		-		-		2,159
Oklahoma		11,567		-		-		-		-		-		11,567
Texas		2,282		-		-		-		-		-		2,282
Other		1,083		-		-		-		-		-		1,083
TOTAL		17,091		-		-		-		-		-		17,091

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Proved Reserves

Summary of Proved Reserves

The following table summarizes estimates of proved reserves of natural gas, oil and NGL held by the Company as of September 30, 2020, compared to the two preceding year ends, using prices and costs under existing economic conditions. Proved reserves are located onshore within the contiguous United States and are principally made up of small interests in 6,510 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.

Summary of Proved Natural Gas and Oil Reserves

	Oil		NGL		Natural Gas		Total Proved
	(Bbl)		(Bbl)		(Mcf)		(Mcfe)
Net Proved Developed Reserves
September 30, 2020		1,148,989		1,135,864		40,924,083		54,633,201
September 30, 2019		1,863,096		1,747,242		67,713,193		89,375,221
September 30, 2018		2,334,587		2,085,706		83,151,954		109,673,712
Net Proved Undeveloped Reserves
September 30, 2020		184,668		83,993		1,448,690		3,060,656
September 30, 2019		516,994		226,038		12,560,713		17,018,905
September 30, 2018		3,649,835		848,484		36,910,082		63,899,996
Net Total Proved Reserves
September 30, 2020		1,333,657		1,219,857		42,372,773		57,693,857
September 30, 2019		2,380,090		1,973,280		80,273,906		106,394,126
September 30, 2018		5,984,422		2,934,190		120,062,036		173,573,708

Exploration and development of our natural gas and oil properties is conducted by natural gas and oil exploration and production companies, primarily larger independent operating companies. We do not operate any of our natural gas and oil properties.

For the year ended September 30, 2020, our net total proved reserves decreased by 48.7 Bcfe, as compared to September 30, 2019. The decrease in total proved reserves from 2019 to 2020 is attributable to a combination of the following factors:

• Negative pricing revisions of 35.8 Bcfe comprised of (i) proved developed revisions of 20.4 Bcfe due to natural gas and oil wells reaching their economic limits earlier than was projected in 2019 due to lower gas and oil prices and (ii) proved undeveloped revisions of 15.4 Bcfe resulting from the impact of COVID-19 and reduced pricing leading to an unprecedented decrease in operator activity in 2020, and a decision to remove PUD locations not permitted, in progress, or drilled and uncompleted (DUC).

• Negative revisions of 10.1 Bcfe, which included (i) proved developed negative revisions of 8.7 Bcfe, principally due to lower performance of high-interest Woodford natural gas wells in the STACK and Arkoma Stack in Oklahoma and, to a lesser extent, lower performance of the Eagle Ford Shale oil properties in southern Texas; and (ii) proved undeveloped negative revisions of 1.4 Bcfe due to changes to scheduled first production date, expected performance, costs, and other reserve parameters.

• Production of 8.6 Bcfe from the Company’s natural gas and oil properties.

• The sale of 0.7 Bcfe, predominately in the Permian Basin in New Mexico, of which 0.2 Bcfe were proved developed and 0.5 Bcfe were proved undeveloped.

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• Reserve extensions, discoveries and other additions of 4.1 Bcfe (comprised of 1.7 Bcfe proved developed and 2.4 Bcfe proved undeveloped reserves) principally resulting from: (i) the Company’s royalty interest ownership in the ongoing development of unconventional natural gas, oil and NGL utilizing extended horizontal drilling in the Woodford Shale in the STACK and SCOOP in Oklahoma; (ii) the Company’s royalty interest ownership in the ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the STACK Meramec play in the Anadarko Basin in western Oklahoma; and (iii) the Company’s royalty interest ownership in ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the Bakken Shale in North Dakota.

• The acquisition of 2.4 Bcfe, predominately in the active drilling program of the Woodford and Mississippian in the SCOOP and STACK plays in Oklahoma and the Bakken in North Dakota, of which 1.1 Bcfe were proved developed and 1.3 Bcfe were proved undeveloped.

Proved Undeveloped Reserves

The following details the changes in proved undeveloped reserves for 2020 (Mcfe):

Beginning proved undeveloped reserves	17,018,905
Proved undeveloped reserves transferred to proved developed	(399,894	)
Revisions	(16,767,540	)
Extensions and discoveries	2,405,590
Sales	(479,415	)
Purchases	1,283,010
Ending proved undeveloped reserves	3,060,656

For the fiscal year ending September 30, 2020, total net PUD reserves decreased by 14.0 Bcfe, as compared to September 20, 2019. In 2020, a total of 0.4 Bcfe (2% of the beginning balance) was transferred to proved developed. The remaining approximately 13.6 Bcfe (80% of the beginning balance) of negative revisions to PUD reserves consist of  (i) pricing revisions of -15.4 Bcfe resulting from the impact of COVID-19 and reduced pricing leading to an unprecedented decrease in operator activity in 2020, and a decision to remove PUD locations not permitted, in progress, or drilled and uncompleted (DUC), (ii) sales and performance revisions of -1.8 Bcfe, and (ii) purchases and extensions of 3.6 Bcfe.

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 2.4 Bcfe of PUD reserves in 2020 within the active drilling program areas of (i) STACK Meramec and Woodford in western Oklahoma, (ii) the SCOOP Woodford Shale in western Oklahoma, (iii) the Arkoma Stack in eastern Oklahoma, (iv) the Bakken in North Dakota. These additions result from continuing development and additional well performance data in each of the referenced plays. Additionally, the Company purchased 1.3 Bcfe in the STACK Meramec and Woodford in Oklahoma and sold 0.5 Bcfe, predominately in the Permian Basin in New Mexico.

Estimated Future Net Cash Flows

Set forth below are estimated future net cash flows with respect to the Company’s net proved reserves (based on the estimated units set forth above in Proved Reserves) for each of the years 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 natural gas, oil and NGL as of September 30, 2020, 2019 and 2018, were as follows: in 2020, $1.62/Mcf for natural gas,  $40.18/Bbl for oil and $9.95/Bbl for NGL; in 2019, $2.48/Mcf for natural gas, $54.40/Bbl for oil and $19.30/Bbl for NGL; and in 2018, $2.56/Mcf for natural gas, $62.86/Bbl for oil and $26.13/Bbl for NGL. 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 natural gas, oil and NGL price and production cost increases or decreases, which could affect the economic life of the properties.

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Estimated Future Net Cash Flows
	9/30/2020			9/30/2019			9/30/2018
Proved Developed	$	57,306,480		$	161,943,514		$	236,887,976
Proved Undeveloped		8,779,289			48,900,497			174,078,883
Income Tax Expense		(13,224,535	)		(47,788,416	)		(95,872,182	)
Total Proved	$	52,861,234		$	163,055,595		$	315,094,677
10% Discounted Present Value of Estimated Future Net Cash Flows
	9/30/2020			9/30/2019			9/30/2018
Proved Developed	$	33,270,804		$	86,814,212		$	125,915,804
Proved Undeveloped		5,659,479			23,581,427			78,657,354
Income Tax Expense		(7,796,130	)		(24,834,110	)		(48,247,304	)
Total Proved	$	31,134,153		$	85,561,529		$	156,325,854

Evaluation and Review of Reserves

The determination of reserve estimates is a function of testing and evaluating the production and development of natural gas and oil reservoirs in order to establish a production decline curve. The established production decline curves, in conjunction with natural gas and oil prices, development costs, production taxes and operating expenses, are used to estimate natural gas and oil 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 16 to the financial statements in Item 8 – “Financial Statements and Supplementary Data” for disclosures regarding our natural gas and oil reserves.

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

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

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

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, prepared the Company’s natural gas, oil and NGL reserves estimates as of September 30, 2020, 2019 and 2018 (see Exhibits 23.2 and 99). Within DeGolyer and MacNaughton, the technical person primarily responsible for preparing the estimates set forth in the Report of DeGolyer and MacNaughton dated October 6, 2020, filed as Exhibit 99 to this Annual Report on Form 10-K, was Gregory K. Graves. Mr. Graves has a Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin and is a Registered Professional Engineer in the state of Texas. He is a member or the Society of Petroleum Evaluation Engineers and has over 36 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Graves meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

All of the reserve estimates are reviewed and approved by our Vice President, Minerals Operations, Freda Webb. 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 40 years of experience in the oil and gas industry. She is an active member of the Society of Petroleum Engineers (SPE).

Our Vice President, Minerals 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, gas and oil production, well test data, commodity prices, operating costs, 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. The Company’s net proved natural gas, oil and NGL 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, 2020, 2019 and 2018. Since the determination and valuation of proved reserves is a function of testing and estimation, the reserves presented are expected to change as future information becomes available.

Natural Gas, Oil and NGL Production

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

	Year Ended		Year Ended		Year Ended
	9/30/2020		9/30/2019		9/30/2018
Mcf - Natural Gas		5,962,705		7,086,761		8,721,262
Bbls - Oil		269,785		329,199		336,565
Bbls - NGL		168,623		216,259		255,176
Mcfe		8,593,153		10,359,509		12,271,708

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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	9/30/2020		9/30/2019		9/30/2018
Per Mcf, Natural Gas	$	1.72	$	2.48	$	2.49
Per Bbl, Oil	$	41.47	$	55.07	$	61.75
Per Bbl, NGL	$	11.42	$	17.10	$	23.14
Per Mcfe	$	2.72	$	3.80	$	3.94

	Year Ended		Year Ended		Year Ended
Average Production (lifting) Costs	9/30/2020		9/30/2019		9/30/2018
(Per Mcfe)
Well Operating Costs (1)	$	1.12	$	1.21	$	1.10
Production Taxes (2)		0.12		0.18		0.17
	$	1.24	$	1.39	$	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 2020, approximately 45% of the Company’s natural gas, oil and NGL 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).

Gross and Net Productive Wells and Developed Acres

The following table sets forth the Company’s gross and net productive natural gas and oil wells as of September 30, 2020. The Company owns either working interests, royalty interests or both in these wells. The Company does not operate any wells.

	Gross Working Interest Only Wells		Net Working Interest Only Wells		Gross Working Interest and Royalty Interest Wells		Net Working Interest and Royalty Interest Wells		Gross Royalty Only Wells		Net Royalty Only Wells		Total Gross Wells
Natural Gas		426		11.48		1,067		44.85		3,087		20.83		4,580
Oil		117		14.27		98		4.40		1,715		11.66		1,930
Total		543		25.75		1,165		49.25		4,802		32.49		6,510

The Company’s average interest in royalty interest only wells is 0.68%. The Company’s average interest in working interest wells is 4.39% working interest and 4.28% net revenue interest.

Information on multiple completions is not available from the Company’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, 2020, the Company owned 462,952 gross (61,453 net) developed mineral acres. The Company has also leased from others 184,840 gross (17,091 net) developed acres.

Undeveloped Acreage

As of September 30, 2020, the Company owned 1,199,028 gross and 190,990 net undeveloped mineral acres. All of the Company’s leases are held by production (“HBP”), and the Company does not have any leases on undeveloped acres.

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Drilling Activity

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

	Net Productive		Net Productive		Net Dry
	Working Interest Wells		Royalty Interest Wells		Working Interest Wells
Development Wells
Fiscal years ended:
September 30, 2020		-		0.597278		-
September 30, 2019		0.939636		0.395755		-
September 30, 2018		0.482972		0.994656		-
Exploratory Wells
Fiscal years ended:
September 30, 2020		-		-		-
September 30, 2019		-		-		-
September 30, 2018		-		-		-
Purchased Wells
Fiscal years ended:
September 30, 2020		-		0.364206		-
September 30, 2019		-		0.516293		-
September 30, 2018		-		1.566828		-

Present Activities

The following table sets forth the Company’s gross and net natural gas and oil wells being drilled or waiting on completion as of September 30, 2020, in which the Company owns either a working interest, a royalty interest or both. These wells were not producing at September 30, 2020.

	Gross Working Interest Wells		Net Working Interest Wells		Gross Royalty Only Wells		Total Gross Wells
Natural Gas		-		-		46		46
Oil		-		-		79		79
Total		-		-		125		125

Other Facilities

The Company has an office lease on 8,776 square feet of office space in Oklahoma City, Oklahoma, which is scheduled to expire on August 31, 2027.

ITEM 3. Legal Proceedings

In the ordinary course of business, we may be, from time to time, a claimant or a defendant in various legal proceedings. There were no material pending legal proceedings involving the Company on September 30, 2020, 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

Market for our Common Stock

Our Common Stock is listed on the New York Stock Exchange (NYSE) under the trading symbol “PHX.”

In March 2007, the Company increased its authorized Common Stock from 12 million shares to 24 million shares. On October 8, 2014, the Company split its Common Stock on a 2-for-1 basis in the form of a stock dividend. We currently have 24 million shares of Common Stock authorized.

Performance Graph

The following graph compares the 5-year cumulative total return provided stockholders on our Common Stock relative to the cumulative total returns of the S&P Smallcap 600 Index and the S&P Oil & Gas Exploration & Production Index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our Common Stock and in each of the indexes on September 30, 2015, and the relative performance of such investment is tracked through and including September 30, 2020. This table is not intended to forecast future performance of our Common Stock.

Record Holders

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At December 3, 2020, there were 1,292 holders of record of our Common Stock and approximately 5,000 beneficial owners.

Dividends

During the past two years, the Company has paid quarterly dividends of either $0.04 per share or $0.01 per share on its Common Stock. Approval by the Company’s Board is required before the declaration and payment of any dividends.

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

During the quarter ended September 30, 2020, the Company did not repurchase any shares of the Company’s common stock.

Following approval by the stockholders 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 Common Stock at its discretion. The repurchase program has an evergreen provision which authorizes the repurchase of an additional $1.5 million of the Company’s 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 Common Stock (i) awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, (ii) contributed by the Company to the PHX Minerals Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan (the “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,
	2020			2019			2018			2017			2016
Revenues
Natural gas, oil and NGL sales	$	23,370,003		$	39,410,036		$	48,385,335		$	39,935,912		$	31,411,353
Lease bonuses and rentals		690,961			1,547,078			1,580,997			5,149,297			7,735,785
Gains (losses) on derivative contracts		907,419			6,105,145			(4,932,068	)		1,249,840			(86,355	)
Gain on asset sales		3,997,436			18,973,426			-			26,105			2,688,408
		28,965,819			66,035,685			45,034,264			46,361,154			41,749,191
Costs and expenses
Lease operating expense		4,841,541			6,398,522			6,714,448			6,488,494			8,050,460
Transportation, gathering and marketing		4,812,869			6,089,903			6,745,830			6,194,475			5,539,629
Production taxes		1,022,912			1,902,636			2,089,050			1,548,399			1,071,632
Depreciation, depletion and amortization		11,313,783			18,196,583			18,395,040			18,397,548			24,487,565
Provision for impairment		29,904,528			76,824,337			-			662,990			12,001,271
Interest expense		1,286,788			1,995,789			1,748,101			1,275,138			1,344,619
General and administrative		8,024,901			8,565,243			7,342,441			7,441,242			7,139,728
Other expense (income)		(466	)		288,610			102,685			131,935			112,171
		61,206,856			120,261,623			43,137,595			42,140,221			59,747,075
Income (loss) before provision (benefit) for    income taxes		(32,241,037	)		(54,225,938	)		1,896,669			4,220,933			(17,997,884	)
Provision (benefit) for income taxes		(8,289,000	)		(13,481,000	)		(12,739,000	)		689,000			(7,711,000	)
Net income (loss)	$	(23,952,037	)	$	(40,744,938	)	$	14,635,669		$	3,531,933		$	(10,286,884	)
Basic and diluted earnings (loss) per share	$	(1.41	)	$	(2.43	)	$	0.86		$	0.21		$	(0.61	)
Dividends declared per share	$	0.10		$	0.16		$	0.16		$	0.16		$	0.16
Weighted average shares outstanding
Basic and diluted		17,010,934			16,743,746			16,952,664			16,900,185			16,840,856
Net cash provided by (used in):
Operating activities	$	11,106,295		$	21,005,684		$	26,943,894		$	20,758,192		$	22,639,151
Investing activities	$	(6,462,518	)	$	10,325,211		$	(21,829,015	)	$	(25,107,760	)	$	565,617
Financing activities	$	(114,073	)	$	(25,702,706	)	$	(5,140,168	)	$	4,436,146		$	(23,337,470	)
Total assets	$	100,021,835		$	126,644,947		$	206,749,686		$	206,744,219		$	197,824,326
Total debt	$	28,750,000		$	35,425,000		$	51,000,000		$	52,222,000		$	44,500,000
Stockholders' equity	$	62,993,926		$	79,309,533		$	128,765,205		$	116,707,539		$	115,191,819

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this Annual Report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report. The following discussion and analysis generally discuss fiscal year 2020 and 2019 items and fiscal year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2019.

Business Overview

We are focused on perpetual natural gas and oil mineral ownership in resource plays in the United States. Prior to a strategy change in 2019, we participated with a working interest on some of our mineral and leasehold acreage and as a result, we still have legacy interests in leasehold acreage and non-operated interests in natural gas and oil properties. Effective October 8, 2020, our corporate name was changed to PHX Minerals Inc. to more accurately reflect our business strategy.

Our 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 natural gas, oil and NGL sales prices. Although a significant amount of our revenues is currently derived from the production and sale of natural gas, oil and NGL on our working interests, a growing portion of our revenues is derived from royalties granted from the production and sale of natural gas, oil and NGL.

Strategic Focus on Mineral Ownership

During fiscal 2019, we made the strategic decision to focus on perpetual natural gas and oil mineral ownership and growth through mineral acquisitions and the development of our significant mineral acreage inventory in our core areas of focus. In accordance with this decision, we ceased taking any working interest positions on our mineral and leasehold acreage going forward. In fiscal 2020, we did not participate with a working interest in the drilling of any new wells. We believe that our strategy to focus on mineral ownership is the best path to giving the Company’s stockholders the greatest risk-weighted returns on their investments.

Market Conditions and Commodity Prices

Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our production volumes or revenues.

Our working interest and royalty revenues may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our operators.

Production and Operational Update

Our natural gas, oil and NGL production for the fiscal year ended September 30, 2020, decreased 16%, 18% and 22%, respectively, from that of 2019. The 2020 fiscal year’s lower natural gas, oil and NGL prices (as discussed below) and the overall production changes noted above resulted in a 41% decrease in revenues from the sale of natural gas, oil and NGL in 2020.

The Company’s proved natural gas, oil and NGL reserves decreased to 57.7 Bcfe in 2020, compared to 106.4 Bcfe in 2019, a decrease of approximately 48.7 Bcfe, or 46%. The decrease was primarily due to revisions and slightly offset by additions, extensions and purchases. The revisions were primarily related to lower gas and oil prices and consisted of natural gas and oil wells reaching their economic limits earlier than was projected in 2019, and the removal of proved undeveloped reserves not permitted, in progress, or drilled and uncompleted as a result of a change in strategy, and the impact of COVID-19 and reduced pricing leading to decreased operator activity in 2020. This was coupled with negative performance revisions on developed reserves principally due to lower performance of high-interest Woodford natural gas wells in the STACK and Arkoma Stack in Oklahoma and, to a lesser extent, lower performance of the Eagle Ford Shale oil properties in southern Texas.

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As of September 30, 2020, the Company owned an average 0.3% net revenue interest in 125 wells, all royalty interest, that were being drilled or awaiting completion.

Results of Operations

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

	For the Year Ended September 30,
			Percent
	2020	2019	Incr. or (Decr.)
Production:
Natural Gas (Mcf)	5,962,705	7,086,761	(16%)
Oil (Bbls)	269,785	329,199	(18%)
NGL (Bbls)	168,623	216,259	(22%)
Mcfe	8,593,153	10,359,509	(17%)
Average Sales Price:
Natural Gas (per Mcf)	$1.72	$2.48	(31%)
Oil (per Bbl)	$41.47	$55.07	(25%)
NGL (per Bbl)	$11.42	$17.10	(33%)
Mcfe	$2.72	$3.80	(28%)

Production by quarter for 2020 and 2019 was as follows (Mcfe):

	For the Year Ended September 30, 2020
	Royalty Interest		Working Interest		Total
First quarter		785,431		1,493,056		2,278,487
Second quarter		971,589		1,401,546		2,373,135
Third quarter		814,501		1,089,251		1,903,752
Fourth quarter		776,276		1,261,503		2,037,779
Total		3,347,797		5,245,356		8,593,153

	For the Year Ended September 30, 2019
	Royalty Interest		Working Interest		Total
First quarter		929,877		1,834,653		2,764,530
Second quarter		770,455		1,651,070		2,421,525
Third quarter		788,290		1,830,079		2,618,369
Fourth quarter		860,177		1,694,908		2,555,085
Total		3,348,799		7,010,710		10,359,509

Fiscal Year 2020 Compared to Fiscal Year 2019

Overview

Revenues decreased in 2020 primarily due to lower natural gas, oil and NGL sales, lower gains on asset sales and lower gains on derivative contracts. The Company recorded a net loss of $23,952,037, or $1.41 per share, in 2020, compared to net loss of $40,744,938, or $2.43 per share, in 2019. Expenses decreased in 2020, primarily the result of decreases in provision for impairment (non-cash), DD&A, LOE and transportation, gathering and marketing expenses.

31

Natural Gas, Oil and NGL Sales

	For the Year Ended September 30,
					Percent
	2020		2019		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	23,370,003	$	39,410,036	(41%)

The decrease was due to decreased natural gas, oil and NGL prices of 31%, 25% and 33%, respectively, combined with lower natural gas, oil and NGL volumes of 16%, 18% and 22%, respectively.

The decrease in oil production was a result of postponement of workovers due to prevailing economic conditions as well as naturally declining production in high interest wells in the Eagle Ford, and asset sales in 2019 and 2020 in the Permian Basin in Texas and New Mexico.  These decreases were slightly offset by a ten-well drilling program in the Bakken that came online in November 2019 and mineral acquisitions of Bakken and STACK producing properties in late 2019. Decreased natural gas and NGL production was primarily due to naturally declining production in the Arkoma Stack and STACK and, to a lesser extent, the Fayetteville, as well as production downtime in high-interest wells in the Arkoma Stack.

Given the Company’s strategic decision to cease participating with working interests, we plan to offset the natural decline of our existing production base by the development of our current inventory of mineral acreage and through acquisitions of additional mineral interests going forward.

Gains (Losses) on Derivative Contracts

	For the Year Ended September 30,
						Percent
	2020			2019		Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net	$	4,109,210		$	196,985	1,986%
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(3,201,791	)	$	5,908,160	(154%)
Gains (losses) on derivative contracts, net	$	907,419		$	6,105,145	(85%)
	As of September 30,
	2020			2019
Fair value of derivative contracts
Net asset (net liability)	$	(707,647	)	$	2,494,144	(128%)

The change in net gain on derivative contracts was principally due to the natural gas and oil collars and fixed price swaps being more beneficial in 2019 in relation to their respective contracted volumes and prices. During the 2020 period, we received $4,109,210 on settled derivative contracts as compared to $196,985 received in the 2019 period. The change from a net asset position at September 30, 2019 to a net liability position at September 30, 2020 resulted in an unrealized loss on derivative contracts in the 2020 period of $3,201,791.

The Company’s natural gas and oil costless collar contracts and fixed price swaps in place at September 30, 2020, had expiration dates of October 2020 through February 2022. The Company utilizes derivative contracts for the purpose of protecting its cash flow and return on investments.

32

Gains on Asset Sales

In 2020, the Company recorded gain on asset sales of $3,997,436 as compared to $18,973,426 in 2019. During the first quarter of 2020, the Company sold producing mineral acreage in Eddy County, New Mexico, for a gain of $3,272,499. The Company utilized a like-kind exchange under Internal Revenue Code Section 1031 to defer income tax on all of the gain by offsetting it with the STACK/SCOOP mineral acreage acquisition that was purchased during the quarter using qualified exchange accommodation agreements. During the fourth quarter of 2020, the Company sold 5,925 non-producing mineral acres in northwestern Oklahoma for a gain of $717,640. The remaining gain on asset sales in 2020 was due to various asset sales less adjustments.

In 2019, the Company sold mineral acreage in Lea and Eddy Counties, New Mexico, for a gain of $9,096,938; Martin County, Texas, (mineral and leasehold) for a gain of $4,921,656; Loving, Reeves and Ward Counties, Texas, for a gain of $2,704,323; and Reagan and Upton Counties, Texas, for a gain of $2,250,509.

Lease Operating Expenses (LOE)

	For the Year Ended September 30,
					Percent
	2020		2019		Incr. or (Decr.)
Lease operating expenses	$	4,841,541	$	6,398,522	(24%)
Lease operating expenses per MCFE	$	0.56	$	0.62	(10%)

LOE related to field operating costs decreased $1,556,981 or 24% in 2020, compared to 2019. The decrease in LOE rate was principally the result of the Company’s strategic decision to not participate with a working interest in new wells, selling some non-core marginal properties which had higher operating costs and operators negotiating lower well service pricing resulting in lower LOE charges.

Transportation, Gathering and Marketing

	For the Year Ended September 30,
					Percent
	2020		2019		Incr. or (Decr.)
Transportation, gathering and marketing	$	4,812,869	$	6,089,903	(21%)
Transportation, gathering and marketing per MCFE	$	0.56	$	0.59	(5%)

Transportation, gathering and marketing decreased $1,277,034 or 21% in 2020, compared to 2019, primarily due to decreased production in 2020. The decrease in transportation, gathering and marketing rate was primarily due to decreased natural gas production coupled with decreased natural gas prices. Natural gas sales cause the majority of the handling. Handling fees are charged either as a percent of sales or based on production volumes.

Production Taxes

	For the Year Ended September 30,
							Percent
	2020			2019			Incr. or (Decr.)
Production taxes	$	1,022,912		$	1,902,636		(46%)
Production taxes as % of sales		4.4	%		4.8	%	(8%)

The decrease in amount was primarily the result of decreased natural gas, oil and NGL sales of $16,040,033 during 2020.

Depreciation, Depletion and Amortization (DD&A)

	For the Year Ended September 30,
					Percent
	2020		2019		Incr. or (Decr.)
Depreciation, depletion and amortization	$	11,313,783	$	18,196,583	(38%)
Depreciation, depletion and amortization per MCFE	$	1.32	$	1.76	(25%)

DD&A decreased $3,108,787 due to natural gas, oil and NGL production volumes decreasing 17% collectively in 2020, compared to 2019. An additional decrease of $3,774,013 was the result of a $0.44 decrease in the DD&A rate per Mcfe. The rate

33

decrease was principally due to large impairments taken during the fourth quarter of fiscal 2019 and the second quarter of fiscal 2020, which lowered the basis of the assets. The rate decrease was partially offset by lower natural gas, oil and NGL prices utilized in the reserve calculations during the 2020 period, as compared to 2019 period, shortening the economic life of wells. This resulted in lower projected remaining reserves on a significant number of wells causing increased units of production DD&A.

Provision for Impairment

Provision for impairment was $29,904,528 in 2020, as compared to $76,824,337 provision for impairment in 2019. During the 2020 period, impairment of $29,315,806 was recorded on seven different fields including the Fayetteville and Eagle Ford shales, which represent 89% of our total impairment. The impairment on assets in these seven fields was caused by lower futures prices associated with our products. Futures prices experienced downward pressure resulting in low pricing as of the end of the fiscal 2020 second quarter. The reduced future net value associated with these fields caused the assets to fail the step one test for impairment as their undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The Fayetteville assets are dry-gas assets, of which the Company acquired a portion in 2011. Low natural gas prices at March 31, 2020, were the primary reason for impairment in this field. The Company recognized an impairment related to the Eagle Ford at September 30, 2019, of $76,560,376, primarily due to the removal of working interest PUDs from the Company’s reserve report. The further impairment of the Eagle Ford assets at March 31, 2020, was due to the decline in commodity prices over fiscal 2020 at that time. The remaining $588,721 and $263,961 of impairment was recorded on other assets in 2020 and 2019, respectively.

Interest Expense

	For the Year Ended September 30,
					Percent
	2020		2019		Incr. or (Decr.)
Interest Expense	$	1,286,788	$	1,995,789	(36%)
Weighted average debt outstanding	$	32,290,257	$	43,092,804	(25%)

The decrease was due to lower interest rates, on average, and a lower outstanding debt balance during 2020.

General and Administrative Costs (G&A)

	For the Year Ended September 30,
					Percent
	2020		2019		Incr. or (Decr.)
General and administrative	$	8,024,901	$	8,565,243	(6%)

The decrease was primarily the result of lower personnel expenses and lower Board expenses. The decrease in personnel expenses was primarily due to the severance of approximately $670,000 upon the resignation of our former CEO toward the end of fiscal 2019, reductions in work force and lower performance-related compensation. Lower Board expenses are due to fewer Board members in 2020 as compared to 2019. Personnel and Board expenses were partially offset by increased technical consulting and legal expenses. The increase in technical consulting was due to increased cost for our then interim (now current) CEO, geologic and engineering fees. The increase in legal expenses was primarily due to additional work provided pertaining to the Company’s proxy statement, equity offering and general business advisement.

Provision (Benefit) for Income Taxes

	For the Year Ended September 30,
							Percent
	2020			2019			Incr. or (Decr.)
Provision (benefit) for income taxes	$	(8,289,000	)	$	(13,481,000	)	(39%)
Effective tax rate		26	%		25	%	3%

In both 2020 and 2019, the tax benefits were the result of a large pretax loss from the impairments in the second quarter of 2020 and the fourth quarter of 2019.

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.

34

Liquidity and Capital Resources

At September 30, 2020, the Company had positive working capital of $13,335,880, as compared to positive working capital of $11,378,829 at September 30, 2019. The slight increase in working capital was primarily driven by increased cash as a result of proceeds from the 2020 equity issuance and increased refundable income taxes, partially offset by decreased derivative contract receivables and increased derivative contract liabilities, decreased sales receivables and short-term debt in 2020.

Liquidity

The Company has sufficient liquidity to manage the financial impact of the COVID-19 pandemic. However, the Company can provide no assurance that this will continue to be the case if the impact of COVID-19 is prolonged for an extended period of time or if there is an extended impact on commodity prices or the economy in general.

Cash and cash equivalents were $10,690,395 as of September 30, 2020, compared to $6,160,691 at September 30, 2019, an increase of $4,529,704. Cash flows for the 12 months ended September 30 are summarized as follows:

Net cash provided (used) by:
	2020			2019			Change
Operating activities	$	11,106,295		$	21,005,684		$	(9,899,389	)
Investing activities		(6,462,518	)		10,325,211			(16,787,729	)
Financing activities		(114,073	)		(25,702,706	)		25,588,633
Increase (decrease) in cash and cash equivalents	$	4,529,704		$	5,628,189		$	(1,098,485	)

Operating activities:

Net cash provided by operating activities decreased $9,899,389 during 2020, as compared to 2019, primarily the result of the following:

• Receipts of natural gas, oil and NGL sales (net of production taxes and gathering, transportation and marketing costs) and other decreased $15,194,689;

• Increased income tax receipts of $1,445,554;

• Increased net receipts on derivative contracts of $3,912,225;

• Decreased payments for interest expense of $724,795;

• Increased payments for G&A and other expense of $1,210,291, which included severance to former CEO;

• Decreased field operating expenses of $1,286,718; and

• Decreased lease bonus receipts of $863,701.

Investing activities:

Net cash used in investing activities increased $16,787,729 during 2020, as compared to 2019, primarily as the result of the following:

• Lower drilling and completion activity during 2020 decreased our capital expenditures by $3,122,871;

• Higher acquisition activity increased our expenditures by $4,625,381; and

• Lower proceeds received from the sale of assets of $15,286,867.

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Financing activities:

Net cash used in financing activities decreased $25,588,633 during 2020, as compared to 2019, primarily as a result of the following:

• Increased net proceeds from equity issuance of $8,220,726 during 2020;

• Decreased stock repurchases by the Company of $7,446,365 during 2020; and

• Decreased net payments on debt of $8,900,000.

Capital Resources

Capital expenditures to drill and complete wells decreased $3,122,871 or 89% in 2020, compared to 2019, as a result of the Company’s strategy to cease participating in any new wells with a working interest at the end of fiscal 2019. The Company currently has no remaining commitments that would require significant capital to drill and complete wells.

Since the Company has decided to cease any further participation in wells with a working interest on its mineral and leasehold acreage, we anticipate that capital expenditures for working interest properties will be minimal going forward, as the expenditures will be limited to capital workovers to enhance existing wells.

On November 14, 2019, the Company closed on the sale of 530 net mineral acres in Eddy County, New Mexico, for $3.4 million. At the time of sale, the assets were mostly amortized and therefore had minimal net book value. Almost all of the value received was a gain on the sale of assets of $3.3 million in the first quarter of 2020. The Company utilized a like-kind exchange under Internal Revenue Code Section 1031 to defer income tax on all of the gain by offsetting it with the STACK/SCOOP mineral acreage acquisition that was purchased during the quarter using qualified exchange accommodation agreements.

On December 18, 2019, the Company closed on the purchase of 700 net mineral acres in Kingfisher, Canadian and Garvin Counties, Oklahoma, for a purchase price of $9.3 million (after customary closing adjustments). This purchase was mostly funded with cash from our like-kind exchange sales.

On July 28 2020, the Company closed on the sale of 5,925 non-producing mineral acres in northwestern Oklahoma for $0.8 million and a gain of $0.7 million, with the proceeds applied toward debt reduction.

On September 1, 2020, the Company closed on an underwritten public offering of 5,750,000 common shares (inclusive of overallotment option) with net proceeds of $8.2 million to PHX.

On October 8, 2020, the Company closed on the purchase of 297 net royalty acres in Grady County, Oklahoma, and 257 net mineral acres and 12 net royalty acres in Harrison, Panola and Nacogdoches Counties, Texas, for a purchase price of $5.5 million and 153,375 shares of PHX common stock, subject to customary closing adjustments. This purchase was mostly funded with cash from the common stock offering discussed above.

On November 12, 2020, the Company closed on the purchase of 134 net mineral acres in San Augustine County, Texas for a purchase price of $750,000.

On December 4, 2020, the Company signed a purchase and sale agreement to purchase an additional 87 net mineral acres in San Augustine County, Texas for a purchase price of $1 million, subject to customary closing adjustments. The Company expects this acquisition to close in the first fiscal quarter of 2021

The Company received lease bonus payments during fiscal 2020 totaling approximately $0.7 million. Looking forward, the cash flow from bonus payments associated with the leasing of drilling rights on the Company’s mineral acreage is difficult to project as the current economic downturn has decreased demand for new leasing by operators. However, management plans to continue to actively pursue leasing opportunities.

With continued natural gas and oil price volatility, management continues to evaluate opportunities for product price protection through additional hedging of the Company’s future natural gas and oil production. See Note 12 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for a complete list of the Company’s outstanding derivative contracts.

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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
	9/30/2020
Cash provided by operating activities	$	11,106,295
Cash used for (provided by):
Capital expenditures - acquisitions		10,288,250
Capital expenditures - drilling and completion of wells		403,136
Quarterly dividends totaling $0.10 per share		1,652,164
Treasury stock purchases		7,635
Net payments (borrowings) on credit facility		6,675,000
Proceeds from sales of assets		(4,228,868	)
Net proceeds from equity issuance		(8,220,726	)
Net cash used		6,576,591
Net increase (decrease) in cash	$	4,529,704

Outstanding borrowings on our credit facility at September 30, 2020, were $28,750,000, of which $1,750,000 is classified as current debt. As of December 1, 2020, outstanding borrowings were $27,250,000.

Looking forward, the Company expects to fund overhead costs and dividend payments from cash provided by operating activities, cash on hand and borrowings utilizing our Credit Facility. The Company intends to use any excess cash to strengthen the Company’s Balance Sheets. The Company had availability of $2,250,000 at September 30, 2020, under its Credit Facility and was in compliance with its debt covenants (current ratio, debt to trailing 12-month EBITDA, as defined by the Credit Facility, and restricted payments limited by leverage ratio). The debt covenants limit the maximum ratio of the Company’s debt to EBITDA to no more than 4:1.

The borrowing base under the Credit Facility was redetermined on June 24, 2020, and reduced from $45 million to $32 million. This amendment included a Quarterly Commitment Reduction, whereby the borrowing base is reduced by $1 million each April 15, July 15, October 15 and January 15, commencing on July 15, 2020. The decrease in the borrowing base was primarily due to the continued decline in natural gas and oil futures prices. Despite the reduction in the borrowing base, we do not expect it will impact the liquidity needed to maintain our normal operating strategies. The borrowing base under the Credit Facility after Quarterly Commitment Reductions was reaffirmed on December 4, 2020 at $30 million. This amendment reduced the Quarterly Commitment Reductions from $1,000,000 to $600,000, reduced the consolidated cash balance in the anti-cash hoarding provision from $2,000,000 to $1,000,000, and changed the debt to EBITDA ratio from 4.0:1.00 to 3.50:1.00.

Based on the Company’s expected capital expenditure levels, anticipated cash provided by operating activities for 2021, combined with availability under its credit facility and shelf registration, 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 borrowing base at September 30, 2020, was $31,000,000 and is secured by all of the Company’s producing gas and oil properties. 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 1.00% to 1.75%, or 30-day LIBOR plus a range of 2.50% to 3.25%. 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. At September 30, 2020, the effective rate was 4.25%.

Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the banks, in their discretion, believe that there has been a material change in the value of the natural gas and oil properties. On June 24, 2020, the Company entered into the Seventh Amendment to its Credit Facility. The amendment reduced the borrowing base from $45,000,000 to $32,000,000 and included a Quarterly Commitment Reduction, whereby the borrowing base is reduced by $1,000,000 each April 15, July 15, October 15 and January 15, commencing on July 15, 2020. The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of

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indebtedness, liens, payment of dividends and acquisitions of stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (as defined in the Credit Facility) of no more than 4.0 to 1.0 based on the trailing twelve months. At September 30, 2020, the Company was in compliance with the covenants of the Credit Facility, had $28,750,000 outstanding, of which $1,750,000 is classified as short-term debt due to the Quarterly Commitment Reduction and had $2,250,000 of borrowing base availability under the Credit Facility.

The Eighth Amendment to the Credit Facility was signed on December 4, 2020.  This amendment reduced the Quarterly Commitment Reductions from $1,000,000 to $600,000, reduced the consolidated cash balance in the anti-cash hoarding provision from $2,000,000 to $1,000,000, and changed the debt to EBITDA ratio from 4.0:1.00 to 3.50:1.00. The borrowing base after Quarterly Commitment Reductions was reaffirmed at $30,000,000.

The table below summarizes the Company’s contractual obligations and commitments as of September 30, 2020:

	Payments due by period
Contractual Obligations			Less than						More than
and Commitments	Total		1 Year		1-3 Years		3-5 Years		5 Years
Debt obligations	$	28,750,000	$	1,750,000	$	27,000,000	$	-	$	-
Building lease	$	1,205,968	$	166,744	$	334,219	$	351,771	$	353,234

The Company’s building lease is accounted for as an operating lease, and a related operating lease right-of-use asset and operating lease liability has been recognized on the Company’s Balance Sheets.

At September 30, 2020, the Company’s derivative contracts were in a net liability position of $707,647. 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 12 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the Company’s derivative contracts.

As of September 30, 2020, the Company’s estimate for asset retirement obligations was $2,897,522. 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 11 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the Company’s asset retirement obligations.

Off-Balance Sheet Arrangements

The Company had no off-balance sheet arrangements during 2020. Other than the lease of office space (before the adoption of ASC 842), the Company had no off-balance sheet arrangements during 2019.

We currently do not have any other off-balance sheet arrangement that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

CRITICAL ACCOUNTING POLICIES

Preparation of financial statements in conformity with GAAP 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: natural gas, crude oil and NGL reserve estimation; derivative contracts; impairment of assets; natural gas, oil and NGL sales revenue accruals; and provision for income taxes. Management’s judgments and estimates 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 natural gas, oil and NGL sales revenue accrual is particularly subject to estimate inaccuracies due to the Company’s status as a non-operator on all of its properties. As such, production and price information obtained from well operators is substantially delayed. This causes the estimation of recent production and prices used in the natural gas, oil and NGL revenue accrual to be subject to future change.

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Natural Gas, Oil and NGL Reserves

Management considers the estimation of the Company’s natural gas, crude oil and NGL reserves to be the most significant of its judgments and estimates. These estimates affect the unaudited standardized measure disclosures included in Note 16 to the financial statements in Item 8 – “Financial Statements and Supplementary Data,” as well as DD&A and impairment calculations. Changes in natural gas, crude oil and NGL 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 the Company’s estimates of natural gas, crude oil and NGL 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 SEC rules, the Company’s 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 2020 DD&A, a 10% change in the DD&A rate per Mcfe would result in a corresponding $1,131,378 annual change in DD&A expense. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future natural gas, crude oil and NGL pricing assumptions are used by management to prepare estimates of natural gas, crude oil and NGL 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 natural gas and oil 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 natural gas, oil and NGL volumes produced to total proved or proved developed reserves is used to amortize the remaining asset basis on each producing property) as natural gas, oil and NGL is produced. The Company’s exploratory wells are all onshore in the continental United States and primarily located in the Mid-Continent area. Generally, expenditures on exploratory wells comprise less than 5% of the Company’s total expenditures for natural gas and oil properties. This accounting method may yield significantly different operating results than the full cost method.

Derivative Contracts

The Company has entered into costless collar contracts and fixed swap contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas and oil. 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 natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in prices. The Company’s derivative contracts are with Bank of Oklahoma. The derivative contracts with Bank of Oklahoma are secured under the 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, 2020, 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 natural gas and oil 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 natural gas, oil and NGL; future production costs; estimates of future natural gas, oil and NGL reserves to be recovered and the timing thereof; economic and regulatory climates and other factors. The Company estimates future net cash flows on its natural gas and oil properties utilizing differentially adjusted forward pricing curves for natural gas, oil and NGL 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 natural gas, oil and NGL reserves. A further reduction in natural

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gas, oil and NGL 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. The decision to not participate in future development on our leasehold acreage can trigger a test for impairment. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.

Natural Gas, Oil and NGL Sales Revenue Accrual

The Company does not operate its natural gas and oil properties and, therefore, receives actual natural gas, oil and NGL 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, as well as public and private sources, and natural gas, oil and NGL 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 natural gas, oil and NGL 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 natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL 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 which takes into account historical data and current pricing. The Company has certain state and federal 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 no longer determined to 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, 2020, the Company had a $96,000 valuation allowance related to Arkansas NOLs. The Company had no other valuation allowances at September 30, 2020. 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 GAAP. 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

Natural gas, oil and NGL prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of natural gas, oil and NGL price trends, and there remains a wide divergence in the opinions held in the industry. The Company can be significantly impacted by changes in natural gas and oil prices. The market price of natural gas, oil and NGL in 2021 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures for acquisitions and production. Excluding the impact of the Company’s 2021 derivative contracts (see below), the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $596,271 for operating revenue based on the Company’s prior year natural gas volumes. The price sensitivity in 2021 for each $1.00 per barrel change in wellhead oil is approximately $269,785 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, 2020, are with Bank of Oklahoma. The derivative contracts with Bank of Oklahoma are secured under the credit facility with Bank of Oklahoma. These arrangements cover only a portion of the Company’s production, provide only partial

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price protection against declines in natural gas and oil prices 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 $146,000. 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 $136,000. For the Company’s gas collars, a change of $0.10 (below or above the collar) in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $1,635,765. For the Company’s oil collars, a change of $1.00 (below or above the collar) in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $71,133. See Note 12 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding our derivative contracts.

Interest Rate 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 1.00% to 1.75%, or 30-day LIBOR plus from 2.50% to 3.25%. At September 30, 2020, the Company had $28,750,000 outstanding under this facility and the effective interest rate was 4.25%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of $287,500 for the year ended September 30, 2020, assuming that our indebtedness remained constant throughout the period. 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 significantly 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	43
Report of Registered Public Accounting Firm on Internal Control Over Financial Reporting	44
Report of Independent Registered Public Accounting Firm	45
Balance Sheets As of September 30, 2020 and 2019	46
Statements of Operations for the Years Ended September 30, 2020, 2019 and 2018	47
Statements of Stockholders’ Equity for the Years Ended September 30, 2020, 2019 and 2018	48
Statements of Cash Flows for the Years Ended September 30, 2020, 2019 and 2018	49
Notes to Financial Statements	51

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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, 2020. 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, 2020, 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

PHX Minerals Inc.

Opinion on Internal Control over Financial Reporting

We have audited PHX Minerals Inc’s internal control over financial reporting as of September 30, 2020, 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, PHX Minerals Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of September 30, 2020, based on the 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, 2020 and 2019, and the related statements of operations, stockholders' equity and cash flows for each of the three years in the period ended September 30, 2020, and the related notes and our report dated December 10, 2020, 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 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 10, 2020

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

PHX Minerals Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of PHX Minerals Inc. (the Company) as of September 30, 2020 and 2019, the related statements of operations, stockholders' equity and cash flows for each of the three years in the period ended September 30, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2020, 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, 2020, 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 10, 2020 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 10, 2020

45

PHX Minerals Inc.

Balance Sheets

	September 30,
	2020			2019
Assets
Current Assets:
Cash and cash equivalents	$	10,690,395		$	6,160,691
Natural gas, oil and NGL sales receivables (net of allowance    for uncollectable accounts)		2,943,220			4,377,646
Refundable income taxes		3,805,227			1,505,442
Derivative contracts, net		-			2,256,639
Other		351,088			177,037
Total current assets		17,789,930			14,477,455
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		324,886,491			354,718,398
Non-producing natural gas and oil properties		18,993,814			14,599,023
Other		582,444			717,121
		344,462,749			370,034,542
Less accumulated depreciation, depletion and amortization		(263,590,801	)		(258,607,521	)
Net properties and equipment		80,871,948			111,427,021
Investments		79,308			205,076
Derivative contracts, net		-			237,505
Operating lease right-of-use assets		690,316			-
Other, net		590,333			297,890
Total assets	$	100,021,835		$	126,644,947
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable	$	997,637		$	665,160
Derivative contracts, net		281,942			-
Current portion of operating lease liability		127,108			-
Accrued liabilities and other		1,297,363			2,433,466
Short-term debt		1,750,000			-
Total current liabilities		4,454,050			3,098,626
Long-term debt		27,000,000			35,425,000
Deferred income taxes		1,329,007			5,976,007
Asset retirement obligations		2,897,522			2,835,781
Derivative contracts, net		425,705			-
Operating lease liability, net of current portion		921,625			-
Stockholders' equity:
Class A voting common stock, $0.01666 par value; 24,000,500 shares authorized;   22,647,306 issued at September 30, 2020, and Class A voting common stock, $0.01666 par   value; 24,000,000 shares authorized; 16,897,306 issued at September 30, 2019		377,304			281,509
Capital in excess of par value		10,649,611			2,967,984
Deferred directors' compensation		1,874,007			2,555,781
Retained earnings		56,244,100			81,848,301
		69,145,022			87,653,575
Treasury stock, at cost; 411,487 shares at September 30, 2020; 558,051 shares    at September 30, 2019		(6,151,096	)		(8,344,042	)
Total stockholders' equity		62,993,926			79,309,533
Total liabilities and stockholders' equity	$	100,021,835		$	126,644,947

See accompanying notes.

46

PHX Minerals Inc.

Statements of Operations

	Year ended September 30,
	2020			2019			2018
Revenues:
Natural gas, oil and NGL sales	$	23,370,003		$	39,410,036		$	48,385,335
Lease bonuses and rentals		690,961			1,547,078			1,580,997
Gains (losses) on derivative contracts		907,419			6,105,145			(4,932,068	)
Gain on asset sales		3,997,436			18,973,426			-
		28,965,819			66,035,685			45,034,264
Costs and expenses:
Lease operating expenses		4,841,541			6,398,522			6,714,448
Transportation, gathering and marketing		4,812,869			6,089,903			6,745,830
Production taxes		1,022,912			1,902,636			2,089,050
Depreciation, depletion and amortization		11,313,783			18,196,583			18,395,040
Provision for impairment		29,904,528			76,824,337			-
Interest expense		1,286,788			1,995,789			1,748,101
General and administrative		8,024,901			8,565,243			7,342,441
Other expense (income)		(466	)		288,610			102,685
		61,206,856			120,261,623			43,137,595
Income (loss) before provision (benefit) for income    taxes		(32,241,037	)		(54,225,938	)		1,896,669
Provision (benefit) for income taxes		(8,289,000	)		(13,481,000	)		(12,739,000	)
Net income (loss)	$	(23,952,037	)	$	(40,744,938	)	$	14,635,669
Basic and diluted earnings (loss) per common share	$	(1.41	)	$	(2.43	)	$	0.86

See accompanying notes.

47

PHX Minerals 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, 2017		16,863,004	$	280,938	$	2,726,444		$	3,459,909		$	113,330,216			(184,988	)	$	(3,089,968	)	$	116,707,539
Net income (loss)		-		-		-			-			14,635,669			-			-			14,635,669
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
Dividends declared ($0.16 per share)		-		-		-			-			(2,698,940	)		-			-			(2,698,940	)
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
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
Net income (loss)		-		-		-			-			(40,744,938	)		-			-			(40,744,938	)
Purchase of treasury stock		-		-		-			-			-			(515,972	)		(7,454,000	)		(7,454,000	)
Issuance of treasury shares to ESOP		-		-		(25,830	)		-			-			26,629			398,104			372,274
Restricted stock awards		-		-		771,797			-			-			-			-			771,797
Dividends declared ($0.16 per share)		-		-		-			-			(2,673,706	)		-			-			(2,673,706	)
Distribution of restricted stock to    officers and directors		425		7		(394,824	)		-			-			24,360			395,230			413
Distribution of deferred directors'    compensation		-		-		(207,850	)		(667,115	)		-			52,399			874,962			(3	)
Common shares to be issued to    directors for services		-		-		-			272,491			-			-			-			272,491
Balances at September 30, 2019		16,897,306	$	281,509	$	2,967,984		$	2,555,781		$	81,848,301			(558,051	)	$	(8,344,042	)	$	79,309,533
Net income (loss)		-		-		-			-			(23,952,037	)		-			-			(23,952,037	)
Purchase of treasury stock		-		-		-			-			-			(632	)		(7,635	)		(7,635	)
Issuance of treasury shares to ESOP		-		-		(974,806	)		-			-			72,101			1,077,910			103,104
Restricted stock awards		-		-		743,897			-			-			-			-			743,897
Dividends declared ($0.10 per share)		-		-		-			-			(1,652,164	)		-			-			(1,652,164	)
Distribution of restricted stock to    officers and directors		-		-		(82,820	)		-			-			5,546			82,914			94
Distribution of deferred directors'    compensation		-		-		(129,575	)		(910,182	)		-			69,549			1,039,757			-
Common shares to be issued to    directors for services		-		-		-			228,408			-			-			-			228,408
Equity offering		5,750,000		95,795		8,124,931			-			-			-			-			8,220,726
Balances at September 30, 2020		22,647,306	$	377,304	$	10,649,611		$	1,874,007		$	56,244,100			(411,487	)	$	(6,151,096	)	$	62,993,926

See accompanying notes.

48

PHX Minerals Inc.

Statements of Cash Flows

	Year ended September 30,
	2020			2019			2018
Operating Activities
Net income (loss)	$	(23,952,037	)	$	(40,744,938	)	$	14,635,669
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		11,313,783			18,196,583			18,395,040
Impairment		29,904,528			76,824,337			-
Provision for deferred income taxes		(4,647,000	)		(12,112,000	)		(12,963,000	)
Gain from leasing fee mineral acreage		(685,927	)		(1,546,298	)		(1,520,262	)
Proceeds from leasing fee mineral acreage		701,948			1,565,649			1,564,225
Net (gain) loss on sales of assets		(3,973,321	)		(18,730,197	)		660,597
ESOP contribution expense		103,104			372,274			382,174
Directors' deferred compensation expense		228,408			272,491			301,715
Total (gain) loss on derivative contracts		(907,419	)		(6,105,145	)		4,932,068
Cash receipts (payments) on settled derivative contracts		4,109,210			196,985			(1,001,893	)
Restricted stock awards		743,897			771,797			655,414
Other		(2,611	)		19,085			6,326
Cash provided (used) by changes in assets and    liabilities:
Natural gas, oil and NGL sales receivables		1,434,426			2,723,983			483,856
Refundable income taxes		(2,299,785	)		(1,472,277	)		456,780
Other current assets		(89,931	)		21,116			57,752
Accounts payable		1,308,731			105,217			(140,600	)
Other non-current assets		(1,044,680	)		7,166			(62,295	)
Accrued liabilities		(1,139,029	)		639,856			100,328
Total adjustments		35,058,332			61,750,622			12,308,225
Net cash provided by operating activities		11,106,295			21,005,684			26,943,894
Investing Activities
Capital expenditures	$	(403,136	)	$	(3,526,007	)	$	(11,590,135	)
Acquisition of minerals and overrides		(10,288,250	)		(5,662,869	)		(11,327,371	)
Investments in partnerships		-			(1,648	)		3,354
Proceeds from sales of assets		4,228,868			19,515,735			1,085,137
Net cash (used in) provided by investing activities		(6,462,518	)		10,325,211			(21,829,015	)
Financing Activities
Borrowings under debt agreement		6,061,725			16,642,481			29,017,800
Payments of loan principal		(12,736,725	)		(32,217,481	)		(30,239,800	)
Net proceeds from equity issuance		8,220,726			-			-
Purchases of treasury stock		(7,635	)		(7,454,000	)		(1,219,228	)
Payments of dividends		(1,652,164	)		(2,673,706	)		(2,698,940	)
Net cash provided by (used in) financing activities		(114,073	)		(25,702,706	)		(5,140,168	)
Increase (decrease) in cash and cash equivalents		4,529,704			5,628,189			(25,289	)
Cash and cash equivalents at beginning of year		6,160,691			532,502			557,791
Cash and cash equivalents at end of year	$	10,690,395		$	6,160,691		$	532,502

(Continued on next page)

49

Supplemental Disclosures of Cash Flow    Information
Interest paid (net of capitalized interest)	$	1,306,967		$	2,031,762		$	1,730,461
Income taxes paid (net of refunds received)	$	(1,342,275	)	$	103,279		$	(232,782	)
Supplemental schedule of noncash investing and    financing activities:
Additions and revisions, net, to asset retirement    obligations	$	4		$	27,782		$	17,216
Gross additions to properties and equipment	$	10,701,284		$	9,248,415		$	21,711,279
Net (increase) decrease in accounts payable for    properties and equipment additions		(9,898	)		(59,539	)		1,206,227
Capital expenditures, including dry hole costs	$	10,691,386		$	9,188,876		$	22,917,506

50

PHX Minerals Inc.

Notes to Financial Statements

September 30, 2020, 2019 and 2018

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

The Company’s principal line of business is maximizing the value of its existing mineral and royalty assets through active management and expanding its asset base through acquisitions of additional mineral and royalty interests.  The Company owns mineral and leasehold properties and other natural gas and oil interests, which are all located in the contiguous United States, primarily in Oklahoma, Texas, North Dakota, Arkansas and New Mexico, with properties located in several other states. The Company’s natural gas, oil and NGL production is from interests in 6,510 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 44%, 48% and 8% of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in 2020. Approximately 69%, 19% and 12% of the Company’s total sales volumes in 2020 were derived from natural gas, oil and NGL, respectively. Substantially all the Company’s natural gas, oil and NGL production is sold through the operators of the wells. From time to time, the Company sells certain non-material, non-core or small-interest natural gas and oil 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 natural gas, crude oil and NGL 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 natural gas, crude oil and NGL 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 natural gas, crude oil and NGL prices as estimated by management are used. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Management uses projected future natural gas, crude oil and NGL pricing assumptions to prepare estimates of natural gas, crude oil and NGL reserves used in formulating management’s overall operating decisions.

As a non-operator, the Company receives actual natural gas, oil and NGL sales volumes and prices more than a month after the information is available to the operators of the wells. Because of the delay in information on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, as well as public and private sources, and natural gas, oil and NGL 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 natural gas, oil and NGL 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 natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.

Basis of Presentation

51

PHX Minerals Inc.

Notes to Financial Statements (continued)

Certain amounts (lease operating expenses and transportation, gathering and marketing in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation.

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.

Natural Gas, Oil and NGL Sales

The Company sells natural gas, oil and NGL to various customers, recognizing revenues as natural gas, oil and NGL is produced and sold.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers of natural gas, oil and NGL or operators of the natural gas and oil properties. Natural gas, oil and NGL 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 natural gas, oil and NGL 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 2020, 2019 and 2018 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.

Natural Gas and Oil Producing Activities

The Company follows the successful efforts method of accounting for natural gas and oil 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. Natural gas and oil mineral and leasehold costs are capitalized when incurred. 

Leasing of Mineral Rights

The Company generates lease bonuses by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances 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 income. 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 utilizes derivative contracts to reduce its exposure to short-term fluctuations in the price of natural gas and oil. These derivates are recorded at fair value on the balance sheet. The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges.

Properties and Equipment

Depreciation, Depletion and Amortization

52

PHX Minerals Inc.

Notes to Financial Statements (continued)

Depreciation, depletion and amortization of the costs of producing natural gas and oil 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. Leasehold 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 natural gas and oil properties include non-producing minerals, which had a net book value of $13,556,020 and $9,673,787 at September 30, 2020 and 2019, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Oklahoma, Texas, North Dakota, Arkansas and New Mexico. As mentioned, these mineral rights are perpetual and have been accumulated over the 94-year life of the Company. There are approximately 190,990 net acres of non-producing minerals in more than 6,380 tracts owned by the Company. An average tract contains approximately 30 acres and the average cost per acre is $71. Since inception, the Company has continually generated an interest in several thousand natural gas and oil 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 (unlike natural gas and oil 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 Company’s mineral ownership consists 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 (by mineral deed).

When a new well is drilled on the Company’s mineral acreage, all of the non-producing mineral costs for the associated mineral deed are transferred to producing minerals and are amortized straight-line over a 20-year period (insignificant fields are amortized over 10-year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on the Company’s minerals, and future development will deplete these assets over a long period. Given that we are moving all of the costs to the first new well drilled on each mineral deed, we believe that a straight-line amortization over a 20-year period is appropriate, as these wells and future development will deplete these assets over a fairly long period.

Capitalized Interest

During 2020, 2019 and 2018, interest of $0, $38,606 and $89,023, respectively, was included in the Company’s capital expenditures. Interest of $1,286,788, $1,995,789 and $1,748,101, 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.

Accrued Liabilities

The following table shows the balances for the years ended September 30, 2020 and 2019, relating to the Company’s accrued liabilities:

	Year Ended September 30,
	2020		2019
Accrued compensation	$	481,062	$	1,446,710
Revenues payable		281,380		396,954
Accrued ad valorem		228,010		260,550
Other		306,911		329,252
Total accrued liabilities	$	1,297,363	$	2,433,466

The decrease in accrued compensation from 2019 to 2020 is primarily due to the one-time severance with the Company’s former CEO of approximately $670,000 upon his resignation at the end of fiscal 2019 as well as lower performance-related compensation in 2020.

53

PHX Minerals Inc.

Notes to Financial Statements (continued)

Asset Retirement Obligations

The Company owns interests in natural gas and oil 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 asset retirement obligations.

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 the Company being responsible for its proportionate share of the costs involved (on working interest wells only). The Company 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, 2020 and 2019, 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 (time-based), subject to certain share price performance standards (market-based) or subject to company performance standards (performance-based). Restricted stock awards to the non-employee directors provide for annual 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.

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PHX Minerals Inc.

Notes to Financial Statements (continued)

The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduced the U.S. federal corporate tax rate from 35% to 21%. As of September 30, 2018, we completed our estimates accounting for the tax effects of the Act. Based on these estimates, we recognized an amount which was included as a component of income tax expense (benefit) from continuing operations in 2018.

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 in 2018 was $12,464,000 income tax benefit.

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, 2019, was a 25% benefit, as compared to a 26% benefit for the year ended September 30, 2020.

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 2017.

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, 2020, 2019 and 2018, the Company’s interest and penalties were not material. The Company does not believe it has any material uncertain tax positions.

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PHX Minerals Inc.

Notes to Financial Statements (continued)

Recent Accounting Pronouncements

Standard	Description	Date of Adoption	Impact on Financial Statements or Other Significant Matters
Adoption of New Accounting Pronouncements
ASU 2016-02, Leases (Topic 842)	This update will supersede the lease requirements in Topic 840, Leases, by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet.	Q1 2020	See Note 2: Leases for further details related the Company’s adoption of this standard.
ASU 2018-11, Leases (Topic 842), Targeted Improvements and ASC 842	This update will allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the financial statements, and will allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if any, rather than in the earliest period presented.	Q1 2020	See Note 2: Leases for further details related the Company’s adoption of this standard.
New Accounting Pronouncements yet to be Adopted
ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.	This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost.	Q1 2021	The standard is effective for interim and annual periods beginning after December 15, 2019, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company evaluated the new standard and determined the impact to not be material. Historically, the Company's credit losses on natural gas, oil and NGL sales receivables have been immaterial.

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

2. LEASES AND COMMITMENTS

Impact of ASC 842 Adoption

On October 1, 2019, the Company adopted ASU 2016-02, Leases (Topic 842) using the modified retrospective method. This ASU, as subsequently amended by ASU 2018-01, ASU 2018-10, ASU 2018-11 and ASU 2018-20, requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous guidance. The Company elected the practical expedient under ASU 2018-11, and used October 1, 2019, the beginning of the period of adoption, as its date of initial application. The Company elected the set of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard.

The Company’s existing operating lease right-of-use (“ROU”) assets and operating lease obligations were less than 1% of the Company's total assets as of December 31, 2019, had remaining terms of less than 12 months and were not considered material to the Company; and therefore, the adoption of the standard had no related impact on the Company’s Balance Sheets as of October 1, 2019. Additionally, there was no related impact on the Company’s Statements of Operations, and the standard had no impact on the Company’s debt covenant compliance under existing agreements.

Assessment of Leases

The Company determines if an arrangement is a lease at inception by considering whether (i) explicitly or implicitly identified assets have been deployed in the agreement and (ii) the Company obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. As of September

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PHX Minerals Inc.

Notes to Financial Statements (continued)

30, 2020, none of the Company’s leases were classified as financing leases. Operating lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company signed a new seven-year lease for office space during the quarter ended March 31, 2020, with a commencement date in August 2020. The associated lease liability and ROU asset at September 30, 2020, were $1,048,733 and $690,316, respectively. The Company has a lease incentive asset of $344,000, which is included in Other, net on the Company’s Balance Sheets.    

ROU assets represent the Company’s right to use an underlying asset for the lease term, and operating lease liabilities represent the Company’s obligation to make payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs and prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Company uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments.

The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Company will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Company will exercise that option. Lease expense for lease payments will be recognized on a straight-line basis over the lease term. The Company made an accounting policy election to not recognize leases with terms, including applicable options, of less than twelve months on the Company’s Balance Sheets and recognize those lease payments in the Company’s Statements of Operations on a straight-line basis over the lease term. In the event that the Company’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.

The following table represents the maturities of the operating lease liabilities as of September 30, 2020:

2021	$	166,744
2022		166,744
2023		167,475
2024		175,520
2025		176,251
Thereafter		353,234
Total lease payments	$	1,205,968
Less: Imputed interest		(157,235	)
Total	$	1,048,733

3. REVENUES

Lease bonus income

The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in Accounting Standards Codification (“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 rental income line item on the Company’s Statements of Operations.

Natural gas and oil derivative contracts

See Note 12 for discussion of the Company’s accounting for derivative contracts.

Revenues from Contracts with Customers

Natural gas, oil and NGL sales

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PHX Minerals Inc.

Notes to Financial Statements (continued)

Sales of natural gas, oil and NGL are recognized when production is sold to a purchaser and control has transferred. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation; however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate.

Disaggregation of natural gas, oil and NGL revenues

The following table presents the disaggregation of the Company's natural gas, oil and NGL revenues for the year ended September 30, 2020.

	Year Ended September 30, 2020
	Royalty Interest		Working Interest		Total
Natural gas revenue	$	3,987,660	$	6,268,094	$	10,255,754
Oil revenue		5,691,837		5,496,533		11,188,370
NGL revenue		776,426		1,149,453		1,925,879
Natural gas, oil and NGL sales	$	10,455,923	$	12,914,080	$	23,370,003

Performance obligations

The Company satisfies the performance obligations under its natural gas and oil sales contracts upon delivery of its production and related transfer of title to purchasers. Upon delivery of production, the Company has a right to receive consideration from its purchasers in amounts that correspond with the value of the production transferred.

Allocation of transaction price to remaining performance obligations

Natural gas, oil and NGL sales

As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606, which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment relate specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient.

Prior-period performance obligations and contract balances

The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited control and visibility into the timing of when new wells start producing, and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the natural gas, oil and NGL sales receivables line item on the Company’s Balance Sheets. The difference between the Company's estimates and the actual amounts received for natural gas, oil and NGL sales is recorded in the quarter that payment is received from the third party. For the years ended September 30, 2020, 2019 and 2018, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was immaterial and considered a change in estimate.

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PHX Minerals Inc.

Notes to Financial Statements (continued)

4. INCOME TAXES

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

	2020			2019			2018
Current:
Federal	$	(3,642,000	)	$	(1,388,000	)	$	204,000
State		-			19,000			20,000
		(3,642,000	)		(1,369,000	)		224,000
Deferred:
Federal		(3,611,000	)		(9,763,000	)		(13,240,000	)
State		(1,036,000	)		(2,349,000	)		277,000
		(4,647,000	)		(12,112,000	)		(12,963,000	)
	$	(8,289,000	)	$	(13,481,000	)	$	(12,739,000	)

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:

	2020			2019			2018
Provision (benefit) for income taxes at statutory rate	$	(6,765,705	)	$	(11,387,447	)	$	465,253
Percentage depletion		(258,300	)		(431,340	)		(577,780	)
State income taxes, net of federal provision (benefit)		(939,310	)		(1,986,850	)		36,980
Effect of NOL Carryback Rate		(610,803	)		-			-
State NOL Valuation Allowance		96,000			-			-
Restricted stock tax benefit		58,000			185,000			(69,000	)
Deferred directors’ compensation benefit		79,000			(38,000	)		(134,000	)
Law change (a)		-			-			(12,464,000	)
Other		52,118			177,637			3,547
	$	(8,289,000	)	$	(13,481,000	)	$	(12,739,000	)

(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%.

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PHX Minerals Inc.

Notes to Financial Statements (continued)

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

	2020		2019
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible    drilling costs capitalized for financial purposes and    expensed for tax purposes	$	3,880,307	$	8,885,776
Derivative contracts		-		619,392
		3,880,307		9,505,168
Deferred tax assets:
State net operating loss carry forwards, net of valuation allowance		391,193		431,977
Federal net operating loss carry forwards		369,523		-
Statutory depletion carryover		346,414		85,680
AMT credit carry forwards		-		1,387,042
Asset retirement obligations		499,708		459,810
Deferred directors' compensation		436,225		602,394
Restricted stock expense		220,301		119,697
Derivative contracts		176,963		-
Business interest limitation		-		358,110
Other		110,973		84,451
		2,551,300		3,529,161
Net deferred tax liabilities	$	1,329,007	$	5,976,007

Included in state net operating loss carry forwards at September 30, 2020, the Company had a deferred tax asset of $350,543 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring in 2037. There is no valuation allowance for the OK NOLs, as management believes they will be utilized before they expire. The Company had a deferred tax asset of $95,611 related to Arkansas state income tax net operating loss (AR NOL) carry forwards, which begin to expire in 2022. The Company has a full valuation allowance for the AR NOLs, as it is more likely than not that these will not be utilized before expiration. There is no valuation allowance for the federal NOLs, nor do they expire.

The federal Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 Net Operating Losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. On July 28, 2020, final regulations were issued under Section 163(j) which modified the calculation under the previous proposed regulations of adjusted taxable income for purposes of the 50% limitation on interest expense. Under the final regulations, depreciation, amortization, and depletion capitalizable under Section 263A is now added back to tentative taxable income.  This change allows all interest expense to be deductible for 2020 and reduces the associated deferred tax asset to zero. During the quarter ended June 30, 2020, the Company filed for a tax refund associated with the AMT credits totaling $1.4 million, which was accelerated due to the CARES Act. Additionally, the Company has a $2.2 million receivable associated with the carryback of the 2020 federal net operating loss.

5. 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 $31,000,000 as of September 30, 2020, and a maturity date of November 30, 2022 (as amended, the “Credit Facility”). The Credit Facility is subject to at least semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The Credit Facility is secured by all of the Company’s producing gas and oil properties. The interest rate is based on BOK prime plus from 1.00% to 1.75%, or 30-day LIBOR plus from 2.50% to 3.25%. 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, 2020, the effective interest rate was 4.25%.

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PHX Minerals Inc.

Notes to Financial Statements (continued)

The Company’s debt is recorded at the carrying amount on its Balance Sheets. The carrying amount of the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in Other, net on the Company’s Balance Sheets. Total debt issuance cost net of amortization as of September 30, 2020, was $246,724. The debt issuance cost is amortized over the life of the credit facility.

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 natural gas and oil properties. On June 24, 2020, the Company entered into the Seventh Amendment to its Credit Facility. The amendment reduced the borrowing base from $45,000,000 to $32,000,000 and included a Quarterly Commitment Reduction, whereby the borrowing base is reduced by $1,000,000 each April 15, July 15, October 15 and January 15, commencing on July 15, 2020. The next redetermination occurred in December 2020. See Note 15: Subsequent Events for further discussion. The Credit Facility 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 stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (as defined in the Credit Facility) of no more than 4.0 to 1.0 based on the trailing twelve months. At September 30, 2020, the Company was in compliance with the covenants of the Credit Facility, had $28,750,000 outstanding, of which $1,750,000 is classified as short-term debt due to the Quarterly Commitment Reduction, and had $2,250,000 of borrowing base availability under the Credit Facility.

6. STOCKHOLDERS’ EQUITY

Upon approval by the stockholders 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. For the year ended September 30, 2020, $7,635 had been spent to purchase 632 shares. The shares are held in treasury and are accounted for using the cost method.

7. EARNINGS (LOSS) PER SHARE

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

	Year Ended September 30,
	2020			2019			2018
Numerator for basic and diluted earnings (loss) per share:
Net income (loss)	$	(23,952,037	)	$	(40,744,938	)	$	14,635,669
Denominator for basic and diluted earnings per share:
Weighted average shares (including for 2020, 2019    and 2018, unissued, vested directors' shares of    154,142, 168,586 and 205,736, respectively)		17,010,934			16,743,746			16,952,664

8. 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 shares of the Company’s Common Stock held by the plan as of September 30, 2020, are allocated to

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PHX Minerals Inc.

Notes to Financial Statements (continued)

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
2020		72,101	$	103,104
2019		26,629	$	372,274
2018		20,632	$	382,174

9. DEFERRED COMPENSATION PLAN FOR DIRECTORS

Annually, independent directors may elect to be included in the Company’s 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 at each quarter end. 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, 2020, there were 177,678 shares (179,226 shares at September 30, 2019) recorded under the Plan. The deferred balance outstanding at September 30, 2020, under the Plan was $1,874,007 ($2,555,781 at September 30, 2019). Expenses totaling $228,408, $272,491 and $301,715 were charged to the Company’s results of operations for the years ended September 30, 2020, 2019 and 2018, respectively, and are included in general and administrative expense in the accompanying Statements of Operations.

10. RESTRICTED STOCK PLAN

In March 2010, stockholders approved the Company’s 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 stockholders. In March 2014, stockholders 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. In March 2020, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan to 750,000 shares. 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 stockholders.

In June 2010, the Company began awarding shares of the Company’s Common Stock as restricted stock (time-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 (market-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.

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PHX Minerals Inc.

Notes to Financial Statements (continued)

In May 2014, the Company also began awarding shares of the Company’s Common Stock as restricted stock (time-based) to its non-employee directors. The restricted stock vests annually during the calendar year. 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.

Effective in May 2014, the Board adopted stock repurchase resolutions to allow management, at its discretion, to purchase the Company’s common stock as treasury shares up to an amount equal to the aggregate number of shares of common stock awarded pursuant to the Amended 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

Effective in May 2018, the Board of directors approved an amendment to the Company’s existing stock repurchase program (the “Repurchase Program”). As amended, the Repurchase Program continues to allow the Company to repurchase up to $1.5 million of the Company’s common stock at management’s discretion. The Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $1.5 million of the Company’s common stock is authorized and approved whenever the previous amount is utilized. In addition, 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 Amended 2010 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.

On December 11, 2019, the Company awarded 10,038 time-based shares and 15,058 market-based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year period and contains non-forfeitable rights to receive dividends and voting rights during the vesting period. The market-based shares that do not meet certain market performance criteria at a certain date are forfeited. The time-based and market-based shares had fair values on their award date of $122,062 and $160,401, respectively. The fair values for the time-based and the market-based awards will be recognized as compensation expense ratably over the vesting period. The fair value of the market-based shares on their award date is calculated by simulating the Company’s stock prices as compared to the S&P Oil & Gas Exploration & Production ETF (XOP) prices utilizing a Monte Carlo model covering the market performance period (December 11, 2019, through December 11, 2022).

On January 2, 2020, the Company awarded 22,300 time-based shares of the Company’s common stock as restricted stock to its non-employee directors. The restricted stock contains non-forfeitable rights to receive dividends and to vote the shares during the vesting period. The restricted stock vests on December 31, 2020. These time-based shares had a fair value on their award date of $246,640.

On January 16, 2020, upon naming a new Chief Executive Officer, the Company awarded 53,476 time-based shares and 21,988 market-based shares of the Company’s common stock as restricted stock, with the same vesting criteria as the December 11, 2019 awards discussed above. The time-based and market-based shares had fair values on their award date of $500,000 and $179,334, respectively. An additional 37,045 of performance-based shares were awarded to the Company’s officers at that time. Based on the performance criteria linked to return on capital employed it is probable none of these awards will vest, and they have no value as of September 30, 2020.

On March 9, 2020, upon naming a new Chief Financial Officer, the Company awarded 16,340 time-based shares, 2,534 market-based shares and 2,534 performance-based shares of the Company’s common stock as restricted stock, with the same vesting criteria as the December 11, 2019, and January 16, 2020, awards discussed above. The time-based and market-based shares had fair values on their award date of $72,550 and $9,814, respectively. Based on the performance criteria linked to return on capital employed it is probable none of the performance-based share awards will vest, and they have no value as of September 30, 2020.

Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur. The dilutive impact of all restricted stock plans is immaterial for all periods presented.

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PHX Minerals Inc.

Notes to Financial Statements (continued)

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2020, 2019 and 2018, related to the Company’s market-based, time-based and performance-based restricted stock:

	Year Ended September 30,
	2020		2019		2018
Market-based, restricted stock	$	295,397	$	367,091	$	276,272
Time-based, restricted stock		448,500		404,706		379,142
Performance-based, restricted stock		-		-		-
Total compensation expense	$	743,897	$	771,797	$	655,414

A summary of the Company’s unrecognized compensation cost for its unvested market-based, time-based and 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 Average Period (in years)
Market-based, restricted stock	$	67,653		1.83
Time-based, restricted stock		562,829		1.97
Performance-based, restricted stock		-
Total	$	630,482

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

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

	Market-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Time-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Performance-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value
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		-		$	-
Granted		43,287			8.24		27,978			15.61		-			-
Vested		-			-		(24,785	)		18.30		-			-
Forfeited		(89,321	)		10.08		(13,153	)		18.23		-			-
Unvested shares as of September 30,    2019		46,670		$	10.21		18,707		$	17.54		-		$	-
Granted		39,579			8.83		102,154			9.21		39,579			-
Vested		-			-		(20,410	)		13.35		-			-
Forfeited		(24,779	)		11.34		(9,929	)		13.93		(4,765	)		-
Unvested shares as of September 30,    2020		61,470		$	8.87		90,522		$	9.49		34,814		$	-

The intrinsic value of the vested shares in 2020 was $85,306.

64

PHX Minerals Inc.

Notes to Financial Statements (continued)

11. PROPERTIES AND EQUIPMENT

Impairment

During the quarter ended March 31, 2020, impairment of $19.3 million and $7.3 million was recorded on our Fayetteville Shale and Eagle Ford fields, respectively. The remaining $2.7 million of impairment was taken on other producing assets. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of March 31, 2020, using a discount rate of 10% for proved developed and assigning no value to undeveloped locations. The Fayetteville Shale assets are dry-gas assets of which the Company acquired a portion in 2011. Low natural gas prices at March 31, 2020, were the primary reason for impairment in this field. The Company recognized an impairment related to the Eagle Ford at September 30, 2019, discussed below. The further impairment of the Eagle Ford assets at March 31, 2020, was due to the decline in commodity prices over fiscal 2020.

At the end of 2019, impairment of $76.6 million was recorded on our Eagle Ford assets. The remaining $0.3 million of impairment was taken on other assets. The impairment on the Eagle Ford assets was caused by the Company making the strategic decision to cease participating with a working interest on its mineral and leasehold acreage going forward and therefore removing all working interest PUDs from the Company’s reserve reports. The removal of the PUDs caused the Eagle Ford assets to fail the step one test for impairment, as its undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The Company determined the fair value based on discounted cash flows of the properties as well as active market bids received from interested potential buyers. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of year-end, using a discount rate of 10% for proved developed and assigning no value to undeveloped locations. Market bids received from interested potential buyers corroborated the fair value of the discounted cash flows as of year-end. The fair value was determined to be $9.1 million based on the discounted cash flows and market quotes. The Company decided not to sell the assets after the marketing process was complete, as we believed that the market conditions were not ideal for selling at that time and that the highest and best use of the assets was to continue to own and produce out the Eagle Ford properties.

A further reduction in natural gas, oil and NGL 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 2020 fiscal year, the Company sold 530 net mineral acres in Eddy County, New Mexico, for $3,376,049 and recorded a net gain on sales of $3,272,499. The total net book value that was removed from the Balance Sheets due to this sale was approximately $104,000. The Company utilized a like-kind exchange under Internal Revenue Code Section 1031 to defer income tax on all of the gain by offsetting it with the STACK/SCOOP mineral acreage acquisition that was purchased during the quarter using qualified exchange accommodation. The Company also sold 5,925 open and non-producing net mineral acres in Northwest Oklahoma for $769,745 and recorded a net gain on sales of $717,640. The total net book value that was removed from the Balance Sheets due to this sale was approximately $52,000.  On the Statements of Operations, the net gain is reflected in the Gain on asset sales line item.

During the 2019 fiscal year, the Company sold 112 non-core wells and 890 net mineral and non-participating royalty interest acres for $19,515,735 and recorded a net gain on sales of $18,730,197. The total net book value that was removed from the Balance Sheets due to these sales was approximately $786,000. On the Statements of Operations, the net gain is reflected in the Gain on asset sales line item with a balance of $18,973,426 with an offset to the Loss on asset sales line item in the amount of $243,228.

Acquisitions

During the 2020 fiscal year, the Company closed on the purchase of 700 net mineral acres in Kingfisher, Canadian and Garvin Counties, Oklahoma, for a purchase price of $9,293,384 (after customary closing adjustments). These mineral purchases were accounted for as asset acquisitions.

During the 2019 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 790 net mineral acres for $5,727,257 or an average of approximately $7,200 per net mineral acre. These mineral purchases were accounted for as asset acquisitions.

65

PHX Minerals Inc.

Notes to Financial Statements (continued)

Asset Retirement Obligations

The following table shows the activity for the years ended September 30, 2020 and 2019, relating to the Company’s asset retirement obligations:

	2020			2019
Asset retirement obligations as of beginning of the year	$	2,835,781		$	2,809,378
Wells acquired or drilled		4			27,783
Wells sold or plugged		(68,668	)		(134,090	)
Accretion of discount		130,405			132,710
Asset retirement obligations as of end of the year	$	2,897,522		$	2,835,781

As a non-operator, the Company does not control the plugging of wells in which it has a working interest and is not involved in the negotiation of the terms of the plugging contracts. This estimate relies on information gathered from outside sources as well as relevant information received directly from operators.

12. 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 natural gas and oil. 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 natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in prices. All of the Company’s derivative contracts at September 30, 2020, were with Bank of Oklahoma. All of the Company’s derivative contracts at September 30, 2019, were with Bank of Oklahoma and Koch Supply and Trading LP. The Company’s derivative contracts with Bank of Oklahoma are secured under its credit facility with Bank of Oklahoma. The derivative contracts with Koch were unsecured. The derivative instruments have settled or will settle based on the prices below.

66

PHX Minerals Inc.

Notes to Financial Statements (continued)

Derivative contracts in place as of September 30, 2020

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - October 2020	10,000 Mmbtu	NYMEX Henry Hub	$2.20 floor / $2.59 ceiling
November 2020 - December 2021	50,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.90 ceiling
November 2020 - December 2021	40,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2020	26,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
December 2020	28,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
January 2021	32,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
February 2021	25,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
March 2021	30,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
April 2021	31,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
May 2021	32,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
June 2021	30,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
July 2021	31,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
August 2021	12,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
September 2021	11,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
October 2021	9,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
November 2021	8,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
December 2021	10,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
January 2022	25,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
November - December 2020	53,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
January 2021	72,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
February 2021	48,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
March 2021	61,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
April 2021	63,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
May 2021	69,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
June 2021	61,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
July 2021	83,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
August - September 2021	27,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
October 2021	20,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2021	14,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
December 2021	4,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
January 2022	77,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2020	54,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
December 2020	55,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
January 2021	64,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
February 2021	52,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
March - April 2021	62,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
May 2021	66,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
June 2021	60,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
July 2021	64,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
August 2021	24,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
September 2021	18,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
October 2021	19,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
November - December 2021	20,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
January - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling

67

PHX Minerals Inc.

Notes to Financial Statements (continued)

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas fixed price swaps
January - December 2020	80,000 Mmbtu	NYMEX Henry Hub	$	2.750
April - October 2020	10,000 Mmbtu	NYMEX Henry Hub	$	2.405
November 2020 - March 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.661
January 2021 - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$	2.729
January 2021 - December 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.765
November 2020	26,500 Mmbtu	NYMEX Henry Hub	$	2.582
December 2020	28,000 Mmbtu	NYMEX Henry Hub	$	2.582
January 2021	32,000 Mmbtu	NYMEX Henry Hub	$	2.582
February 2021	25,500 Mmbtu	NYMEX Henry Hub	$	2.582
March 2021	30,500 Mmbtu	NYMEX Henry Hub	$	2.582
April 2021	31,500 Mmbtu	NYMEX Henry Hub	$	2.582
May 2021	32,500 Mmbtu	NYMEX Henry Hub	$	2.582
June 2021	30,500 Mmbtu	NYMEX Henry Hub	$	2.582
July 2021	31,500 Mmbtu	NYMEX Henry Hub	$	2.582
August 2021	12,500 Mmbtu	NYMEX Henry Hub	$	2.582
September 2021	11,000 Mmbtu	NYMEX Henry Hub	$	2.582
October 2021	9,000 Mmbtu	NYMEX Henry Hub	$	2.582
November 2021	8,000 Mmbtu	NYMEX Henry Hub	$	2.582
December 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.582
January 2022	25,500 Mmbtu	NYMEX Henry Hub	$	2.582
Oil costless collars
January - December 2020	2,000 Bbls	NYMEX WTI	$55.00 floor / $62.00 ceiling
August - October 2020	1,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
November - December 2020	500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
January 2021	2,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
February 2021	1,500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
March - July 2021	2,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
January 2022	2,500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
August - October 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
November - December 2020	500 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
January - July 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
August - September 2021	500 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
January 2022	3,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
August 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
September - November 2020	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
December 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 2021	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 2021	1,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
March - April 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
May 2021	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
June - July 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
August 2021	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 2022	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 2022	5,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
Oil fixed price swaps
January - December 2020	2,000 Bbls	NYMEX WTI	$	55.28
January - December 2020	2,000 Bbls	NYMEX WTI	$	58.65
January - December 2020	2,000 Bbls	NYMEX WTI	$	60.00
January - December 2020	2,000 Bbls	NYMEX WTI	$	58.05

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PHX Minerals Inc.

Notes to Financial Statements (continued)

July - December 2020	2,000 Bbls	NYMEX WTI	$	58.10
January - December 2021	8,000 Bbls	NYMEX WTI	$	37.00

The Company’s fair value of derivative contracts was a net liability of $707,647 as of September 30, 2020, and a net asset of $2,494,144 as of September 30, 2019. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations. Cash receipts in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods.

	For the Year Ended September 30,
	2020			2019			2018
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	28,510		$	(191,200	)	$	451,700
Natural gas fixed price swaps		1,687,600			817,160			748,125
Oil costless collars		1,011,472			(169,256	)		(822,893	)
Oil fixed price swaps		1,381,628			(259,719	)		(1,378,825	)
Cash received (paid) on derivative contracts, net	$	4,109,210		$	196,985		$	(1,001,893	)
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(706,015	)	$	10,453		$	(222,337	)
Natural gas fixed price swaps		(1,535,122	)		1,350,909			(425,865	)
Oil costless collars		(538,022	)		1,687,685			(1,026,163	)
Oil fixed price swaps		(422,632	)		2,859,113			(2,255,810	)
Non-cash gain (loss) on derivative contracts, net	$	(3,201,791	)	$	5,908,160		$	(3,930,175	)
Gains (losses) on derivative contracts, net	$	907,419		$	6,105,145		$	(4,932,068	)

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, 2020, and September 30, 2019. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2020, and September 30, 2019.

	9/30/2020								9/30/2019
	Fair Value								Fair Value
	Commodity Contracts								Commodity Contracts
	Current  Assets			Current Liabilities			Non-Current Liabilities		Current  Assets		Non-Current Assets
Gross amounts recognized	$	864,466		$	1,146,408		$	425,705	$	2,256,639	$	237,505
Offsetting adjustments		(864,466	)		(864,466	)		-		-		-
Net presentation on Balance Sheets	$	-		$	281,942		$	425,705	$	2,256,639	$	237,505

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.

13. 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.

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PHX Minerals Inc.

Notes to Financial Statements (continued)

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 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, 2020
	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	$	-	$	(64,801	)	$	-	$	(64,801	)
Derivative Contracts - Collars	$	-	$	(642,846	)	$	-	$	(642,846	)

	Fair Value Measurement at September 30, 2019
	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	$	-	$	1,892,954	$	-	$	1,892,954
Derivative Contracts - Collars	$	-	$	601,190	$	-	$	601,190

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,
	2020				2019				2018
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	5,288,710	$	29,315,807	$	9,101,032	$	76,824,337	$	-	$	-

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PHX Minerals Inc.

Notes to Financial Statements (continued)

^(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 natural gas, oil and NGL 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. This table excludes $588,721 of impairments on properties that were written off during 2020.

At September 30, 2020, and September 30, 2019, 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 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.

14. INFORMATION ON NATURAL GAS AND OIL PRODUCING ACTIVITIES

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

The following table shows sales, by percentage, through various operators/purchasers during 2020, 2019 and 2018.

	2020			2019			2018
Company A		23	%		23	%		24	%
Company B		6	%		8	%		16	%
Company C		5	%		8	%		11	%

The loss of any of these major purchasers of natural gas, oil and NGL production could have a material adverse effect on the ability of the Company to produce and sell its natural gas, oil and NGL production.

15. SUBSEQUENT EVENTS

Name Change

Effective October 8, 2020, the Company officially changed its name to PHX Minerals Inc. to more accurately reflect its business strategy.

Acquisitions

On October 8, 2020, the Company closed on the purchase of 297 net royalty acres in Grady County, Oklahoma, and 257 net mineral acres and 12 net royalty acres in Harrison, Panola and Nacogdoches Counties, Texas, for a purchase price of $5.5 million and 153,375 shares of PHX common stock. This purchase was largely funded with cash from the common stock offering that closed on September 1, 2020.

On November 12, 2020, the Company closed on the purchase of 134 net mineral acres in San Augustine County, Texas for a purchase price of $750,000.

On December 4, 2020, the Company signed a purchase and sale agreement to purchase an additional 87 net mineral acres in San Augustine County, Texas for a purchase price of $1 million, subject to customary closing adjustments. The Company expects this acquisition to close in the first fiscal quarter of 2021.

Borrowing Base Redetermination

The Eighth Amendment to the Credit Facility was signed on December 4, 2020.  This amendment reduced the Quarterly Commitment Reductions from $1,000,000 to $600,000, reduced the consolidated cash balance in the anti-cash hoarding provision

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PHX Minerals Inc.

Notes to Financial Statements (continued)

from $2,000,000 to $1,000,000, and changed the debt to EBITDA ratio from 4.0:1.00 to 3.50:1.00. The borrowing base after Quarterly Commitment Reductions was reaffirmed at $30,000,000.

Derivative Contracts

Subsequent to September 30, 2020, the Company entered into new derivative contracts as summarized in the table below:

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
August 2021 - July 2022	100,000 Mmbtu	NYMEX Henry Hub	$2.50 floor / $3.17 ceiling
February - June 2022	100,000 Mmbtu	NYMEX Henry Hub	$2.50 floor / $3.15 ceiling
Oil costless collars
August 2021 - July 2022	1,500 Bbls	NYMEX WTI	$37.00 floor / $47.10 ceiling
Oil fixed price swaps
February - June 2022	4,000 Bbls	NYMEX WTI	$	39.51
July - December 2022	1,500 Bbls	NYMEX WTI	$	39.51
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.78
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.50
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.05

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

Aggregate Capitalized Costs

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

	2020			2019
Producing properties	$	324,886,491		$	354,718,398
Non-producing minerals		18,808,689			14,413,899
Non-producing leasehold		185,125			185,124
		343,880,305			369,317,421
Accumulated depreciation, depletion and amortization		(263,277,422	)		(258,063,849	)
Net capitalized costs	$	80,602,883		$	111,253,572

Costs Incurred

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

	2020		2019		2018
Property acquisition costs	$	10,453,119	$	6,235,905	$	11,409,673
Exploration costs		-		-		-
Development costs		273,825		3,012,095		10,291,476
	$	10,726,944	$	9,248,000	$	21,701,149

72

PHX Minerals Inc.

Notes to Financial Statements (continued)

Estimated Quantities of Proved Natural Gas, Oil and NGL Reserves

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

Proved natural gas and oil reserves are those quantities of natural gas and oil 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. 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 natural gas or oil 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, prepared the Company’s natural gas, oil and NGL reserves estimates as of September 30, 2020, 2019 and 2018.

The Company’s net proved natural gas, oil and NGL reserves, which are located in the contiguous United States, as of September 30, 2020, 2019 and 2018, 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, Minerals Operations, Freda Webb. 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 40 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, Minerals 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, gas and oil production, well test data, commodity prices, operating costs, 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.

73

PHX Minerals Inc.

Notes to Financial Statements (continued)

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers (SPE) entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. 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. Based on the current stage of field development, production performance, development plans and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The 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 the Company its intention to drill.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. These analyses were 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 effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

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 natural gas, oil and NGL reserves are summarized as follows:

	Proved Reserves
	Natural Gas			Oil			NGL			Total
	(Mcf)			(Barrels)			(Barrels)			Bcfe
September 30, 2017		121,195,120			5,509,667			2,384,699			168.6
Revisions of previous estimates		(29,247	)		(1,407,995	)		303,728			(6.7	)
Acquisitions (divestitures)		(1,782,949	)		236,690			24,765			(0.2	)
Extensions, discoveries and other additions		9,400,374			1,982,624			476,174			24.2
Production		(8,721,262	)		(336,564	)		(255,176	)		(12.3	)
September 30, 2018		120,062,036			5,984,422			2,934,190			173.6
Revisions of previous estimates		(35,644,135	)		(3,266,351	)		(890,046	)		(60.6	)
Acquisitions (divestitures)		(948,496	)		(322,023	)		(18,881	)		(3.0	)
Extensions, discoveries and other additions		3,891,262			313,241			164,276			6.8
Production		(7,086,761	)		(329,199	)		(216,259	)		(10.4	)
September 30, 2019		80,273,906			2,380,090			1,973,280			106.4
Revisions of previous estimates		(34,666,426	)		(1,094,923	)		(774,214	)		(45.9	)
Acquisitions (divestitures)		911,853			57,721			70,933			1.7
Extensions, discoveries and other additions		1,816,144			260,555			118,480			4.1
Production		(5,962,704	)		(269,786	)		(168,622	)		(8.6	)
September 30, 2020		42,372,773			1,333,657			1,219,857			57.7

The prices used to calculate reserves and future cash flows from reserves for natural gas, oil and NGL, respectively, were as follows: September 30, 2020 - $1.62/Mcf, $40.18/Bbl, $9.95/Bbl; September 30, 2019 - $2.48/Mcf, $54.40/Bbl, $19.30/Bbl; September 30, 2018 - $2.56/Mcf, $62.86/Bbl, $26.13/Bbl.

74

PHX Minerals Inc.

Notes to Financial Statements (continued)

The revisions of previous estimates from 2019 to 2020 were primarily the result of:

• Negative pricing revisions of 35.8 Bcfe due to natural gas and oil wells reaching their economic limits earlier than was projected in 2019 due lower gas and oil prices and decreased operator activity in 2019 and a change in strategy to remove PUD locations not permitted, in progress, or drilled and uncompleted (DUC); proved developed revisions of 20.4 Bcfe and PUD revisions of 15.4 Bcfe.

• Negative revisions of 10.1 Bcfe. Proved developed negative revisions of 8.7 Bcfe were the result of lower performance of high-interest Woodford natural gas wells in the STACK and Arkoma Stack in Oklahoma and, to a lesser extent, lower performance of the Eagle Ford Shale oil properties in southern Texas. Proved undeveloped revisions were negative 1.4 Bcfe, due to changes to scheduled first production date, expected performance, costs and other reserve parameters.

Acquisitions and divestitures were the result of:

• The acquisition of 2.4 Bcfe, predominately in the active drilling program of the Woodford and Mississippian in the SCOOP and STACK plays in Oklahoma and the Bakken in North Dakota, of which 1.1 Bcfe were proved developed and 1.3 Bcfe were proved undeveloped.

• The sale of 0.7 Bcfe, predominately in the Permian Basin in New Mexico, of which 0.2 Bcfe were proved developed and 0.5 Bcfe were proved undeveloped.

Extensions, discoveries and other additions from 2019 to 2020 are principally attributable to:

• Proved developed reserve extensions, discoveries and other additions of 4.1 Bcfe, of which 1.7 Bcfe were proved developed and 2.4 Bcfe were proved undeveloped reserves, resulting from:

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

b) The Company’s royalty interest ownership in ongoing development of unconventional natural gas, oil and NGL 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 unconventional natural gas, oil and NGL utilizing horizontal drilling in the Bakken Shale in North Dakota.

Production of 8.6 Bcfe from the Company’s natural gas and oil properties.

	Proved Developed Reserves						Proved Undeveloped Reserves
	Natural Gas		Oil		NGL		Natural Gas		Oil		NGL
	(Mcf)		(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)
September 30, 2018		83,151,954		2,334,587		2,085,706		36,910,082		3,649,835		848,484
September 30, 2019		67,713,193		1,863,096		1,747,242		12,560,713		516,994		226,038
September 30, 2020		40,924,083		1,148,989		1,135,864		1,448,690		184,668		83,993

The following details the changes in proved undeveloped reserves for 2020 (Mcfe):

Beginning proved undeveloped reserves	17,018,905
Proved undeveloped reserves transferred to proved developed	(399,894	)
Revisions	(16,767,540	)
Extensions and discoveries	2,405,590
Sales	(479,415	)
Purchases	1,283,010
Ending proved undeveloped reserves	3,060,656

75

PHX Minerals Inc.

Notes to Financial Statements (continued)

For the fiscal year ending September 30, 2020, our beginning PUD reserves were 17.0 Bcfe. Total net PUD reserves decreased by 14.0 Bcfe, as compared to September 30, 2019. In 2020, a total of 0.4 Bcfe (2% of the beginning balance) was transferred to proved developed. The remaining 13.6 Bcfe (80% of the beginning balance) of negative revisions to PUD reserves consist of  (i) pricing revisions of -15.4 Bcfe resulting from the impact of COVID-19 and reduced pricing leading to an unprecedented decrease in operator activity in 2020, and a decision to remove PUD locations not permitted, in progress, or drilled and uncompleted (DUC), (ii) sales and performance revisions of -1.8 Bcfe, and (iii) purchases and extensions of  3.6 Bcfe. 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 2.4 Bcfe of PUD reserves in 2020 within the active drilling program areas of (i) STACK Meramec and Woodford in western Oklahoma, (ii) the SCOOP Woodford Shale in western Oklahoma’s Anadarko Basin, (iii) the Arkoma Stack in eastern Oklahoma, (iv) the Bakken in North Dakota. These additions result from continuing development and additional well performance data in each of the referenced plays. Additionally, the Company purchased 1.3 Bcfe in the STACK Meramec and Woodford in Oklahoma and sold 0.5 Bcfe, predominately in the Permian Basin in New Mexico.

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

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

	2020			2019			2018
Future cash inflows	$	134,179,216		$	366,697,321		$	759,899,074
Future production costs		(66,136,222	)		(153,935,373	)		(259,413,766	)
Future development and asset retirement costs		(1,957,225	)		(1,917,937	)		(89,518,449	)
Future income tax expense		(13,224,535	)		(47,788,416	)		(95,872,182	)
Future net cash flows		52,861,234			163,055,595			315,094,677
10% annual discount		(21,727,081	)		(77,494,066	)		(158,768,823	)
Standardized measure of discounted future net    cash flows	$	31,134,153		$	85,561,529		$	156,325,854

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PHX Minerals Inc.

Notes to Financial Statements (continued)

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

	2020			2019			2018
Beginning of year	$	85,561,529		$	156,325,854		$	80,832,575
Changes resulting from:
Sales of natural gas, oil and NGL, net of    production costs		(12,692,681	)		(25,072,122	)		(32,836,007	)
Net change in sales prices and production costs		(46,499,344	)		(76,588,460	)		47,533,281
Net change in future development and asset    retirement costs		(20,571	)		43,607,535			1,580,942
Extensions and discoveries		2,841,807			7,074,245			34,667,557
Revisions of quantity estimates		(28,332,653	)		(60,308,497	)		(8,391,223	)
Acquisitions (divestitures) of reserves-in-place		1,169,819			(3,134,783	)		(307,472	)
Accretion of discount		11,039,792			20,457,930			12,602,209
Net change in income taxes		17,037,980			23,413,194			(3,057,128	)
Change in timing and other, net		1,028,475			(213,367	)		23,701,120
Net change		(54,427,376	)		(70,764,325	)		75,493,279
End of year	$	31,134,153		$	85,561,529		$	156,325,854

17. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

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

	Fiscal 2020
	Quarter Ended
	December 31		March 31			June 30			September 30
Revenues	$	10,576,531	$	11,311,287		$	2,705,383		$	4,372,618
Income (loss) before provision for    income taxes	$	2,146,114	$	(27,441,814	)	$	(4,433,155	)	$	(2,512,182	)
Net income (loss)	$	1,892,114	$	(20,454,814	)	$	(3,555,215	)	$	(1,834,122	)
Earnings (loss) per share	$	0.11	$	(1.24	)	$	(0.21	)	$	(0.07	)
	Fiscal 2019
	Quarter Ended
	December 31		March 31			June 30			September 30
Revenues	$	26,328,994	$	7,636,213		$	16,342,394		$	15,728,084
Income (loss) before provision for    income taxes	$	16,306,940	$	(2,061,334	)	$	5,919,236		$	(74,390,780	)
Net income (loss)	$	12,735,940	$	(1,931,334	)	$	4,604,236		$	(56,153,780	)
Earnings (loss) per share	$	0.75	$	(0.11	)	$	0.28		$	(3.35	)

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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 Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The Company’s disclosure controls and procedures have been designed to meet, and management believes that they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this report, the Chief Executive Officer and Chief Financial Officer have concluded that, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective.

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

The Company’s management is responsible for establishing and maintaining adequate “internal control over financial reporting,” as such term is defined in Exchange Act Rule 13a-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. The Company’s management, including the Chief Executive Officer and Chief Financial Officer, 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, 2020.

Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s independent registered public accounting firm, Ernst & Young LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of September 30, 2020, presented preceding the Company’s financial statements included in this Form 10-K. Additionally, the financial statements for the years ended September 30, 2019 and 2018, covered in this 2020 Annual Report on Form 10-K, have also been audited by the Company’s independent registered public accounting firm, whose report is presented preceding their report on the Company’s internal control over financial reporting.

(c)       CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Certain changes were made to the Company’s internal controls during the fiscal fourth quarter for validating the Company’s interest in new wells to remediate the material weakness identified in the second quarter. There were no other 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, 2020, or subsequent to the date the assessment was completed.

ITEM 9B OTHER INFORMATION

None

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PART III

The information called for by Part III of Form 10-K (Item 10 – Directors and Executive Officers and Corporate Governance, 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 Accounting 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.

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PART IV

ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

(1.1)	Underwriting Agreement between Panhandle Oil and Gas Inc. and Stifel, Nicolaus & Company, Incorporated dated August 28, 2020 (incorporated by reference to Form 8-K dated September 1, 2020)
(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, and to Form 10-QSB dated March 31, 1999, and to Forms 10-Q dated March 31, 2007, March 9, 2020, and to Form 8-K dated October 13, 2020)
	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, April 3, 2018, and October 13, 2020)
(3.1)	Amended and Restated Certificate of Incorporation of PHX Minerals Inc. (incorporated by reference to Form S-3 dated October 19, 2020)
(4)	Instruments defining the rights of security holders (incorporated by reference to Certificate of Incorporation and By-Laws listed above)
(5.1)	Opinion of Derrick & Briggs, LLP (incorporated by reference to Form 8-K dated September 1, 2020)
*(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)
(10.8)	Sixth Amendment to Amended and Restated Credit Agreement and Joinder dated August 6, 2019 (Incorporated by reference to Form 10-Q dated August 8, 2019)
(10.9)	Agreement for Purchase and Sale by and between Panhandle Oil and Gas Inc. and Red Stone Resources, LLC (Oklahoma Assets) dated August 24, 2020 (incorporated by reference to Form 8-K dated August 27, 2020)
(10.10)	Agreement for Purchase and Sale by and between Panhandle Oil and Gas Inc. and Red Stone Resources, LLC, for itself and as successor-in-interest by merger to Macedonia Minerals, LLC, a former Texas limited liability company, and Red Stone Operating, LLC (Texas Assets) dated August 24, 2020 (incorporated by reference to Form 8-K dated August 27, 2020)
*(10.11)	Change-in-Control Agreement between Panhandle Oil and Gas Inc. and Chad L. Stephens dated January 16, 2020 (incorporated by reference to Form 8-K dated January 17, 2020)
*(10.12)	Amended and Restated Change-in-Control Agreement between Panhandle Oil and Gas Inc. and Chad L. Stephens dated February 25, 2020 (incorporated by reference to Form 8-K dated February 25, 2020)
*(10.13)	Form of Amended and Restated Change-in-Control Agreement for Other Executive Officers to provide certain severance payments and benefits to executive officers should a Change-in-Control occur, as defined by the agreement, and which supersedes the change-in-control agreements previously entered into by such executive officers (incorporated by reference to Form 8-K dated February 25, 2020)
(10.14)	Amendment No. 1 to Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan dated March 3, 2020 (incorporated by reference to Form 8-K dated March 9, 2020)
(10.15)	Seventh Amendment to Amended and Restated Credit Agreement and Joinder dated June 24, 2020 (incorporated by reference to Form 8-K dated June 25, 2020)

80

(10.16)	Eighth Amendment to Amended and Restated Credit Agreement and Joinder dated December 4, 2020 (incorporated by reference to Form 8-K dated December 7, 2020)
*(10.17)	Form of Amended and Restated Change-in-Control Executive Severance Agreement
(10.18)	PHX Minerals Inc. Amended 2010 Restricted Stock Plan
(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
(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
(104)	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*	Indicates management contract or compensatory plan or arrangement

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.

PHX MINERALS INC.

By: /s/ Chad L. Stephens

Chad L. Stephens

President and Chief Executive Officer

Date:  December 10, 2020

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Pursuant to the requirements of 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/ Chad L. Stephens Chad L. Stephens	President and Chief Executive Officer	December 10, 2020
/s/Ralph D’Amico Ralph D’Amico	Vice President and Chief Financial Officer	December 10, 2020
/s/ Mark T. Behrman Mark T. Behrman	Lead Independent Director	December 10, 2020
/s/ Lee M. Canaan Lee M. Canaan	Director	December 10, 2020
/s/ Peter B. Delaney Peter B. Delaney	Director	December 10, 2020
/s/ Christopher T. Fraser Christopher T. Fraser	Director	December 10, 2020

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EX-10.17

Exhibit 10.17

AMENDED AND RESTATED CHANGE-IN-CONTROL EXECUTIVE SEVERANCE AGREEMENT

This Amended and Restated Change-in-Control Executive Severance Agreement (this “Agreement”), executed as of November 9, 2020 and dated effective as of November 9, 2020, is between PHX Minerals Inc., an Oklahoma corporation (the “Company”), and (the “Executive”).

Statement of Purpose

The Company desires, for its continued success, to have the benefit of services of experienced management personnel like the Executive. The Board of Directors of the Company therefore believes that it is in the best interest of the Company that,     in the event of any prospective change in control of the Company, the Executive be reasonably secure in his employment and position with the Company, so that the Executive can exercise independent judgment as to the best interest of the Company and its shareholders, without distraction by any personal uncertainties or risks regarding the executive’s continued employment with the Company created by the possibility of a change-in-control of the Company. The Board believes that this Agreement will create an environment that is best suited to maximizing shareholder value and retaining executive loyalty and focus when they are needed most and will further align the interests of Executive with the interests of the Company’s shareholders.

Agreement

In consideration of the statements made in the Statement of Purpose and the mutual agreements set forth below, the Company and the Executive agree as follows:

1.Protection. In order to protect Executive against the possible consequences of a “Change-in-Control” of the Company (as defined in Section 2) and to induce Executive to remain in the employ of the Company and in consideration of Executive agreeing to remain in the employ of the Company subject to the terms and conditions set forth below, this Agreement sets forth the severance benefits which the Company agrees will be provided to Executive in the event his employment with the Company is terminated on or subsequent to a Change-in- Control of the Company under the circumstances described below.

2.Definitions. For purposes of this Agreement, the following capitalized terms shall have the following meanings:

(a) “Board” means the Board of Directors of the Company.

(b) “Cause” means:

(i)the willful and continued failure of the Executive to perform substantially the Executive’s duties with the Company (other than a failure resulting from incapacity due to physical or mental illness), within a reasonable period of time after a written demand for substantial performance is delivered to the Executive by the Board which demand specifically identifies the manner in which the Board believes that the Executive has not substantially performed the Executive’s duties; or

(ii)the willful engaging by the Executive in illegal conduct, gross misconduct or a clearly established violation of the Company’s written policies and procedures, in each case, which is materially and demonstrably injurious to the Company, monetarily or otherwise.

For purposes of this paragraph (b), no act or failure to act, on the part of the Executive, will be considered “willful” unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that the Executive’s action  or omission was in the best interests of the Company. Any act, or failure to act, based on authority given pursuant to a resolution duly adopted by the Board or based on the advice of counsel for the Company will be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests   of the Company.

(c) “Change-in-Control” means the occurrence of any one or more of

the following:

(i)any “person” (as such term is used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company) is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company representing 50% or more of the total voting power represented by the Company’s then outstanding Voting Securities;

(ii)during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, and any new director, whose election by the Board or nomination for election by the Company’s shareholders was approved by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute a majority of the Board;

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(iii)the shareholders of the Company approve a merger or consolidation of the Company with any other corporation and such merger or consolidation of the Company with such other corporation is consummated, other than a merger or consolidation that would result in the Voting Securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into Voting Securities of the surviving entity) at least 80% of the total voting power represented by the Voting Securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or

(iv)involuntary dissolution of the Company.

(d) “Code” means the Internal Revenue Code of 1986, as amended.

(e) “Date of Termination” means (i) if Executive’s employment is terminated by the Company for “Cause,” the date specified in the Notice of Termination, and (ii) if Executive’s employment is terminated for any other reason, the date on which a Notice of Termination is given.

(f) “Effective Date” means November 9, 2020.

(g) “Good Reason” shall include:

(i)the assignment to Executive of any position which results, in the aggregate, in a material reduction in Executive’s rank, authority, duties, status, or responsibilities as an officer of the Company or Executive is assigned duties and obligations inconsistent with his position with the Company;

(ii)Executive’s annual base salary is reduced below the higher of Executive’s base salary in effect immediately before the Change-in-Control or Executive’s base salary in effect at any time after the Change-in-Control;

(iii)Executive is removed from or denied participation in incentive plans, benefit plans, or perquisites generally provided by the Company to other executives with a comparable level of responsibility, title or stature;

(iv)a failure to provide (or a reduction in, if previously provided) incentive compensation opportunities, benefits or perquisites that are provided other executives with comparable responsibility, title or stature;

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(v)the failure by the Company to continue to provide the Executive with benefits similar in all material respects to those enjoyed by the Executive under any Plan in which the Executive was participating at any time within three months before the Change-in-Control, the taking of action by the Company which would directly or indirectly materially reduce any of such benefits or deprive the Executive of any material fringe benefit enjoyed by the Executive at any time three months before the Change-in-Control, or the failure by the Company to provide the Executive with the number of paid vacation days to which the Executive is entitled on the basis of years of service with the Company in accordance with the Company’s normal vacation policy in effect at any time within three months before the Change-in-Control.

(vi)the failure of the Company to obtain a satisfactory agreement from any successor to assume and agree to perform this Agreement satisfactory in form and substance to Executive;

(vii)any purported termination of the Executive’s employment which is not effected pursuant to a Notice of Termination satisfying its requirements, and for purposes of this Agreement, no such purported termination shall be effective; or

(viii)any material breach of this Agreement by the Company not described in paragraphs (i) through (viii) above.

(h) “Notice of Termination” means a written and dated notice which indicates the Date of Termination (not earlier than the date on which the notice is provided), and which indicates the specific termination provision in this Agreement relied on and which sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive’s employment under the provision so indicated.

(i) “Plan” means any bonus, incentive compensation, retirement, stock ownership or purchase, pension, deferred compensation, or welfare benefits plan, policy, practice, program or arrangement of (including any separate contract or agreement with) the Company for its employees.

(j) “Voting Securities” means the Company’s Class A Common Stock, par value $0.01666 per share, and any other securities of the Company that vote generally in the election of directors.

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3.Change-in-Control. No benefits shall be payable hereunder unless there shall have been a Change-in-Control of the Company, and Executive’s employment by the Company shall have been terminated in accordance with Section 5 below.

4.Rights Provided By Agreement. This Agreement does not constitute a guarantee of continued employment but instead provides for certain rights and benefits in the event Executive’s employment with the Company terminates under the circumstances provided herein.

5. Termination Following Change-in-Control.

(a) Severance Payment. If, on the occurrence of a Change-in- Control or, within two (2) years following the occurrence of a Change-in-Control, (i) Executive’s employment with the Company is terminated by the Company other than for Cause or Executive’s death, or (ii) Executive resigns for Good Reason, then the Company shall pay to Executive as severance pay in a lump sum, in cash, on or before the fifth day following the Date of Termination, an amount equal to (A) two (2) times the average of the base salary and contributions made by the Company to its 401(k) Plan on Executive’s behalf paid to Executive during the two (2) calendar years preceding the Change-in-Control (or the annual average for any shorter period, if applicable) plus (B) two times the Executive’s average bonus amount paid for the last two calendar year period prior to the Change-in-Control event (or if not yet determined for that calendar year in which the Change-in-Control occurs, the Executive’s targeted bonus for the preceding calendar year if applicable, or if there is no two year bonus history, the amount shall be two times target bonus). In addition, the Company shall promptly reimburse Executive each month for all costs incurred by Executive of purchasing COBRA continuing coverage (as described in Section 4980B of the Code) for Executive and all of Executive’s dependents following Executive’s Date of Termination for twelve months.

(b) Notice of Termination. Any termination of Executive’s employment by Executive for Good Reason shall be communicated by Notice of Termination to the Company. Executive shall not be deemed to have been terminated for Cause unless and until there shall have been delivered to him a copy  of a Notice of Termination from the Board, after reasonable notice to Executive and an opportunity for Executive, together with his counsel, to be heard before the Board, finding that, in the good faith opinion of the Board, Executive was guilty of conduct set forth above in clauses (i) or (ii) in Section 5(a) and specifying the particulars thereof in detail.

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6.Term of Agreement. This Agreement will continue in effect until the earlier of:

(a) The termination or cessation of the Executive’s employment

with the Company before a Change-in-Control; or

(b) The Company’s performance of all of its obligations, and the Executive’s receipt of all of the payments and benefits to which he is entitled, under this Agreement after a Change-in-Control.

7. [RESERVED]

8.Mitigation. Executive shall not be required to mitigate the amount of  any payment provided for in this Agreement by seeking other employment or otherwise, nor shall the amount of any payment provided for in this Agreement be reduced by any compensation earned by Executive as the result of any other employment, consulting relationship, or other business activity after the Date of Termination.

9.No Set-Off. The Company’s obligations under this Agreement are absolute and unconditional, and not subject to any set-off, counterclaim, recoupment, defense, or other right that the Company or any affiliate may have against the Executive.

10.Tax Withholding. The Company shall withhold from any payment or benefits under this Agreement (whether or not otherwise acknowledged under this Agreement) all federal, state, local, or other taxes as may be legally required to be withheld.

11.Executive’s Legal Expenses. The Company shall pay the Executive an amount equal to the reasonable legal fees and other expenses incurred in good faith by him in obtaining or retaining payments and benefits under this Agreement, including all such fees and expenses (if any) in enforcing, in good faith, any right or benefit provided by this Agreement or in connection with the contest or defense of any tax audit or proceeding by the Internal Revenue Service to the extent that Section 3999 of the Code is alleged or claimed to apply to any payment or benefit provided under this Agreement. The Company will be obligated under the preceding sentence even if the Executive is not successful in any enforcement claim or counterclaim by him, or in any such tax contest or defense, so long as the Executive acted in good faith. The Company shall make any payment required by this Section 11 within thirty (30) days after written notice from the Executive requesting payment and providing such evidence of the incurrence of those fees and expenses as the Company may reasonably request. In the event of a dispute over the Executive’s legal expenses, the Executive may retain the Company’s legal counsel; provided, however, to the extent the Executive believes such representation would result in a conflict of interest, the Executive may retain separate legal counsel to represent him at the expense of the Company.

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12.Non-Exclusivity of Rights. Nothing in this Agreement shall prevent or limit the Executive’s continuing or future participation in any benefit, bonus, incentive or other plan or program provided by the Company or any of its affiliated companies and for which the Executive may qualify, nor shall anything herein limit or otherwise affect such rights as the Executive may have under any agreements with the Company or an of its affiliated companies. Amounts which are vested benefits or which the Executive is otherwise entitled to receive under any plan or program of the Company or any of its affiliated companies at or subsequent to the Date of Termination shall be payable in accordance with such plan or program.

13. Successors and Binding Effect.

(a) Successor Must Assume Agreement. The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. Failure of the Company to obtain such assumption and agreement prior to the effectiveness of any such succession shall be a breach of this Agreement and shall entitle the Executive to compensation from the Company in the same amount and on the same terms as the Executive would be entitled to hereunder if the Executive terminated employment for Good Reason following a Change-in-Control of the Company, except that for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed the date of termination of employment. As used in this Agreement, “Company” shall mean the Company as hereinbefore defined and any successor to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement by operation of law or otherwise.

(b) Binding Effect. This Agreement shall inure to the benefit of and be enforceable by the Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Executive should die while any amount would still be payable to the Executive hereunder if the Executive had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to the Executive’s devisee, legatee or other designee or, if there is no such designee, to the Executive’s estate.

14.Interest. If any amounts due and payable hereunder to Executive are not paid by the Company or its successor when due, the unpaid amount will bear interest at the per annum rate equal to twelve percent (12%) (the provision for such interest is not intended to alter, and shall not be construed as altering, the Company’s obligation to pay, and the Executive’s right to receive, all payments due hereunder in a timely manner).

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15. Miscellaneous.

15.1 Amendment of Agreement. No supplement, modification, or amendment of this Agreement shall be binding unless executed in writing by both of the parties hereto. No waiver of any of the provisions of this Agreement shall be binding unless in the form of a writing signed by the party against whom enforcement of the waiver is sought, and no such waiver shall operate as a waiver of any other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver. Except as specifically provided herein, no failure to exercise or any delay in exercising any right or remedy hereunder shall constitute a waiver thereof.

15.2 Severability. If any provision (or portion thereof) of this Agreement shall be held by a court of competent jurisdiction to be invalid, void, or otherwise unenforceable, the remaining provisions shall remain enforceable to the fullest extent permitted by law. Furthermore, to the fullest extent possible, the provisions of this Agreement (including, without limitation, each portion of this Agreement containing any provision held to be invalid, void, or otherwise unenforceable, that is not itself invalid, void, or unenforceable) shall be construed so as to give effect to the intent manifested by the provision held invalid, void, or unenforceable.

15.3 Governing Law. This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of Oklahoma applicable to contracts made and to be performed in such State without giving effect to the principles of conflicts of laws.

15.4 Notices.All notices, requests, consents and other communications hereunder to any party shall be deemed to be sufficient if contained in a written document: (i) delivered in person, (ii) sent by facsimile (with a copy sent by first class mail, postage prepaid), (iii) sent by nationally recognized overnight courier service, or (iv) mailed by first class certified or registered mail, return receipt requested, postage prepaid, addressed to such party at the address set forth below or such other address as may hereafter be designated on the signature pages of this Agreement or in writing by such party to the other party.

Notices provided in accordance with this Section 15.4 shall be deemed to have been delivered: (i) if personally delivered, upon delivery; (ii) if sent by facsimile transmission, upon electronic confirmation by the sender when received; (iii) if sent by overnight courier service, 24 hours after deposit with that service; or (iv) if sent by certified or registered mail, return receipt requested, 48 hours after deposit in the mail.

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To Company:PHX Minerals Inc.

1601 NW Expressway, Suite 1100 Oklahoma City, OK 73118

Attention: Chief Executive Officer Facsimile: 405.948.2038

and

To Executive:At Executive’s current home address on file.

15.5 Specific Performance, Etc. The parties recognize that if any provision of this Agreement is violated by the Company, the Executive may be without an adequate remedy at law. Accordingly, in the event of any such violation, the Executive shall be entitled, if the Executive so elects, to institute proceedings, either in law or at equity, to obtain damages, to enforce specific performance, to enjoin such violation, or to obtain any relief or any combination of the foregoing as the Executive may elect to pursue.

15.6 Counterparts.This Agreement may be executed in counterparts, each of which shall for all purposes be deemed to be an original but all of which together shall constitute one and the same agreement. Only one such counterpart signed by the party against whom enforceability is sought needs to be produced to evidence the existence of this Agreement.

15.7 Waiver and Amendment. No term or condition of this Agreement shall be deemed waived other than by a writing signed by the party against whom or which enforcement of the waiver is sought. Without limiting the generality of the preceding sentence, a party’s failure to insist upon the other party’s strict compliance with any provision of this Agreement or to assert any right that a party may have under this Agreement shall not be deemed a waiver of that provision or that right. Any written waiver shall operate only as to the specific term or condition waived under the specific circumstances and shall not constitute a waiver of that term or condition for the future or a waiver of any other term or condition. No amendment or modification of this Agreement shall be deemed effective unless stated in a writing signed by the parties hereto.

15.8 Entire Agreement. This Agreement, including the Statement of Purpose, contains the parties’ entire agreement regarding the subject matter of this Agreement and supersedes all prior agreements and understandings between them regarding that subject matter. The parties have made no agreements, representations or warranties regarding the subject matter of this Agreement that are not set forth in this Agreement.

15.9 Headings. All headings in this Agreement are for convenience only and are not intended to affect the meaning of any provision hereof.

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In Witness Whereof, the parties have executed and delivered this Agreement as of the Effective Date.

“COMPANY”	PHX Minerals Inc.
	By:
“EXECUTIVE”

ACKNOWLEDGED ON BEHALF OF THE BOARD BY:

By:
	Mark T. Behrman
	Lead Independent Director

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EX-10.18

Exhibit 10.18

PHX MINERALS INC.

AMENDED

2010 RESTRICTED STOCK PLAN

March 5, 2014

APPENDIX A

TABLE OF CONTENTS

Section 1. Introduction			1
	1.1.	Purpose of the Plan	1
	1.2.	Nature of Sales of Restricted Stock	1
	1.3.	Effective Date and Term of Plan	1
Section 2. Definitions And Construction			1
	2.1.	Definitions	1
	2.2.	Construction	2
Section 3. Eligibility			2
	3.1.	In General	2
Section 4. Administration Of The Plan			2
	4.1.	In General	2
Section 5. Shares Subject To The Plan			3
	5.1.	Number of Shares	3
Section 6. Restricted Stock			3
	6.1.	Sale of Restricted Stock	3
	6.2.	The Restricted Period	3
	6.3.	Escrow	3
	6.4.	Dividends	4
	6.5.	Repurchase of Restricted Stock	4
	6.6.	Expiration of Restricted Period	4
	6.7.	Rights as a Shareholder	4
Section 7. Adjustments			4
	7.1.	Changes in Capitalization	4
Section 8. Change In Control			4
	8.1.	Consequences of a Change In Control on Restricted Stock	4
	8.2.	Change In Control Defined	5
Section 9. General Provisions			5
	9.1.	Transferability of Restricted Stock	5
	9.2.	Termination of Status	5
	9.3.	Withholding	5
	9.4.	Other Conditions on Delivery of Stock	6
Section 10. Miscellaneous			6
	10.1.	No Right to Continued Employment	6
	10.2.	Amendment	6
	10.3.	Compliance with Code Section 409A	6
	10.4.	Governing Law	6

(i)

PHX MINERALS INC.

AMENDED

2010RESTRICTEDSTOCKPLAN SECTION 1.INTRODUCTION

1.1. Purpose of the Plan. The Plan provides an essential long-term component to the Company’s total compensation package for its officers and directors reflecting the importance the Company places on aligning the interest of its officers and directors with those of its shareholders and provides incentives for officers and directors to remain with the Company. The Plan will enhance the Company’s ability to attract, retain and motivate officers and directors of the Company.

1.2.  Nature of Sales of Restricted Stock.  The  Plan is intended to permit the  Sale  by  the Company of Shares of Restricted Stock to its officers and directors subject to various vesting based on the passage of time or other conditions to vesting and other restrictions on the transferability of the Shares sold. The transfer restrictions on these Shares will be removed based on the vesting restrictions contained in the Stock Restriction Agreement between the Company and the affected Participant. Except as otherwise provided by the Plan, each Sale hereunder may be made alone or in addition or in relation to any other Sale. The terms of each Sale need not be identical, and the Compensation Committee need not treat Participantsuniformly.

1.3. Effective Date and Term of Plan.  If approved by shareholders at the Company’s  2014 Annual Shareholders Meeting, the Plan will be effective as of March 5, 2014. No sales to Participants shall be permitted under the Plan after March 5, 2024 but the vesting periods forShares

previously sold may extend beyond that date.

SECTION 2. DEFINITIONS AND CONSTRUCTION

2.1.Definitions. When used in this Plan, the following terms shall have the meanings set  forth below, unless the context clearly requires a differentmeaning:
(a)	“Board” means the Board of Directors of the Company.
(b)	“Change in Control” shall have the meaning set forth in Section 8.2.
(c)	“Code” means the Internal Revenue Code of 1986, as amended.
(d)	“Common Stock” means the Company’s Class A Common Stock, par value $0.01666 per share.
(e)	“Company” means PHX Minerals Inc.
(f)	“Compensation Committee” shall mean the Compensation Committee of the Board.
(g)	“Disability” shall mean incapacity due to physical or mental illness as determined by the Compensation Committee.

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(h)	“Effective Date” means the first date set forth in Section 1.3.
(i)	“Fair Market Value” means the closing sales price (for the primary trading session) of a Share on the date the Restricted Period ends. For any date that is not a trading day, the Fair Market Value of a Share for such date will be determined by using the closing sales price for the immediately preceding tradingday.
(j)	“Participant” means any officer or director who purchases Restricted Stock.
(k)	“Plan” means this Amended 2010 Restricted Stock Plan.
(l)	“Repurchase” shall have the meaning as set forth in Section 6.5.
(m)	“Restricted Period” means the period of time during which the transfer of the Shares of Restricted Stock shall be restricted and after which the shares of Restricted Stock shall be vested.
(n)	“Restricted Stock” means Shares sold under this Plan.
(o)	“Sale” means a sale of shares of Restricted Stock made under the Plan.
(p)	“Share” means a share of Class A Common Stock, par value $0.01666 per share, of the Company.
(q)	“Stock Restriction Agreement” means all agreements between the Company and a Participant covering the Sale of Restricted Stock under this Plan.
2.2. Construction. When used in the Plan, (a) the terms “include” and “including” shall be deemed to include the phrase “but not limited to” and (b) masculine pronouns shall include the feminine.

SECTION 3. ELIGIBILITY

3.1.   In General.  Any natural person is eligible to purchase Restricted Stock if such individual  is a current officer or director of the Company or any of the Company’s present or future subsidiary entities as determined by the Compensation Committee.

SECTION 4. ADMINISTRATION OF THE PLAN

4.1.InGeneral.
(a)	The Plan will be administered by the Compensation Committee. The Compensation Committee shall have authority to determine the Participants and terms and conditions of any Sale of Restricted Stock, and to adopt, amend and repeal such administrative rules, guidelines and practices relating to the Plan as it shall deem advisable.
(b)	The Compensation Committee shall have full discretionary authority to construe and interpret the terms of the Plan and any Stock Restriction Agreement, and to determine all facts necessary to administer the Plan and any Stock Restriction Agreement. The Compensation Committee may correct any defect, supply any omission or reconcile any inconsistency in the Plan or any Stock Restriction Agreement in the manner and to the extent it shalldeem necessary or advisable.

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(c) All decisions by the Compensation Committee shall be made in its sole discretion and shall be final and binding on all persons having or claiming any interest in the Plan or in any purchase of Restricted Stock. No director or person acting pursuant to the authority delegated by the Compensation Committee shall be liable for any action or determination relating to or under the Plan made in good faith.

SECTION 5. SHARES SUBJECT TO THE PLAN

5.1.Number ofShares.
(a)	Subject to adjustment under Section 7.1, Sales of Restricted Stock may be made under the Plan for up to 750,000 Shares.
(b)	If Shares sold hereunder are repurchased by the Company prior to the vesting of such Shares the repurchased Shares shall again be available for sale by the Company to officers under the Plan. Shares issued under the Plan may consist in whole or in part of authorized but unissued shares or treasury shares.

SECTION 6. RESTRICTED STOCK

6.1. Sale of Restricted Stock. The Compensation  Committee  may  sell  Shares  of  Restricted Stock to such officers and directors as it determines. The sales price of Shares shall be at  a significant discount to the Fair Market Value of the Shares, generally at a per Share price equal to the par value of the Shares sold. Sales of Restricted Stock shall be subject to such restrictions on transfer and the Repurchase of Restricted Stock by the Company and such other terms and conditions, subject to the provisions of the Plan, as determined by the CompensationCommittee.

6.2. Restricted Period. At the time a Sale of Restricted Stock is made to a Participant, the Compensation Committee shall establish a period of time during which the transfer of the Shares of Restricted Stock shall be restricted and after which the Shares of Restricted Stock shall be vested (the “Restricted Period”). Each Sale of Restricted Stock may have a different Restricted Period. The Compensation Committee shall determine the Restricted Period for all RestrictedStock.

6.3. Escrow. Each Participant purchasing Restricted Stock shall enter into a Stock Restriction Agreement with the Company setting forth the terms, conditions and restrictions of the Sale. Any certificates representing Shares of Restricted Stock shall be registered in the name of the Participant and deposited with the Company, or an escrow agent as determined by the Compensation Committee, together with a stock power for each certificate endorsed in blank by the Participant. Each such certificate shall bear a legend in substantially the following form:

The transferability of this certificate and the shares of Common Stock represented by it are subject to the terms and conditions contained in the PHX Minerals Inc. 2010 Restricted Stock Plan (the “Plan”), and an agreement entered into between the registered owner and PHX Minerals Inc. Copies of the Plan and the agreement are on file at the principal office of PHX Minerals Inc.

Alternatively, in the discretion of the Company, ownership of the Shares of Restricted Stock and the appropriate restrictions shall be reflected in the records of the Company’s transfer agent and no

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physical stock certificates shall be issued prior to vesting.

6.4.   Dividends.   Unless otherwise  determined by the Compensation Committee  or provided in the Stock Restriction Agreement, Participants holding Restricted Stock will be eligible to receive all dividends paid with respect to such Shares. If any dividends or distributions are paid in Shares,  or consist of a dividend or distribution to holders of Shares other than an ordinary cash dividend, the Shares or other property will be subject to the same restrictions on transferability as the Restricted Stock with respect to which they were paid and such Shares or other property shall be deposited with the Company or in escrow as provided in Section6.3.

6.5. Repurchase of Restricted Stock. In the event any Shares of Restricted Stock under  the terms of the Stock Restriction Agreement (including any additional shares of Restricted Stock that may result from changes in capitalization of the Company as provided in Section 7.1) do not vest, the Company shall repurchase (“Repurchase”) such Shares from the affected Participant for a price equal to the original sale price. All repurchased Shares shall be surrendered to the Company and the stock certificates representing such Shares shall becancelled.

6.6.  Expiration of Restricted Period.  Upon the expiration of the Restricted Period and the satisfaction of any other conditions prescribed by the Compensation Committee or set forth in the Stock Restriction Agreement, the restrictions applicable to the Restricted Stock shall lapse and, unless otherwise instructed by the Participant, a stock certificate for the number of Shares of Restricted Stock with respect to which the restrictions have lapsed shall be released by the Company or from escrow and delivered, free of all such restrictions and legends, except any that may be imposed by law, to the Participant or the Participant’s estate, as the case maybe.

6.7.Rights  asaShareholder.Subject to the terms and conditions of the Plan, each Participant receiving Restricted Stock shall have all the rights of a shareholderwith respect to the

Shares of Restricted Stock during the Restricted Period, including the right to vote any shares of Restricted Stock and to receive payment of dividends subject to the provisions in Section 6.4.

SECTION 7. ADJUSTMENTS

7.1. Changes in Capitalization. In the event of any stock split, reverse stock split, stock dividend, recapitalization, combination of shares, reclassification of shares, spin-off or other similar change in capitalization or event, or any dividend or distribution to holders of Shares other than an ordinary cash dividend, (a) the number and class of securities available under this Plan, (b) the number of Shares sold under this Plan and (c) the price payable to a Participant upon the Repurchase, shall be equitably adjusted in the manner determined by the Compensation Committee.

SECTION 8. CHANGE IN CONTROL

8.1. Consequences of a Change In Control on Restricted Stock. Upon the occurrence of a Change In Control, except to the extent specifically provided to the contrary in the applicable Stock Restriction Agreement, all restrictions and conditions on all Restricted Stock then outstanding shall automatically lapse and be deemed terminated or satisfied, as applicable.

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8.2.ChangeInControlDefined.ForpurposesofthisPlan,“ChangeInControl”shall mean the occurrence of any one or more of the following:
(i)	any “person” (as such term is used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company) is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company representing 50% or more of the total voting power represented by the Company’s then outstanding Voting Securities; or
(ii)	during any period of two consecutive years, individuals who at the beginning of such period constitute the Board of Directors of the Company (the “Incumbent Board”), and any new director, whose election by the Board or nomination by the Board for election by the Company’s shareholders was approved by a vote of at least two-thirds (⅔) of the directors then still in office who either were directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute a majority of the Board; or
(iii)	the shareholders of the Company approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation that would result in the Voting Securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into Voting Securities of the surviving entity) at least 80% of the total voting power represented by the Voting Securities of the Company or such surviving entity outstanding immediately after such merger or consolidation;or
(iv)	involuntary dissolution of the Company.
As used in this Section 8.2, the term “Voting Securities” means the Company’s Class A Common Stock, par value $0.01666 per share, and any other securities of the Company that vote generally in the election of directors.

SECTION 9. GENERAL PROVISIONS

9.1. Transferability of Restricted Stock. Except as the Compensation Committee may otherwise determine or provide in a Stock Restriction Agreement, Restricted Stock may not be sold, assigned, transferred, pledged or otherwise encumbered by Participants holding Restricted Stock, either voluntarily or by operation of law, except by will or the laws of descent and distribution or, pursuant to a qualified domestic relations order. References herein to a Participant, to the extent relevant in the context, shall include references to authorized transferees.

9.2. Termination of Status. The Compensation Committee shall determine the effect on Restricted Stock of the Disability, death, early or normal retirement, termination or other cessation of employment, authorized leave of absence or other change in the employment of a Participant.

9.3.Withholding.TheParticipantmustsatisfyallapplicablefederal,state,andlocalorother incomeandemploymenttaxwithholdingobligationsbeforetheCompanywillauthorizetheShares

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to be released from escrow to the Participant. The Company may decide to satisfy the withholding obligations through additional withholding on salary or wages. If the Company elects not to or cannot withhold from other compensation, the Participant must pay the Company the full amount, if any, required for withholding. Payment of withholding obligations is due before the Company will authorize the release of the Shares. If approved by the Compensation Committee, a Participant may satisfy such tax obligations in whole or in part by delivery of a portion of the Restricted Stock creating the tax obligation, valued at Fair Market Value; provided, however, except as otherwise provided by the Compensation Committee, that the total tax withholding where Restricted Stock is being used to satisfy such tax obligations cannot exceed the Company’s minimum statutory withholding obligations (based on minimum statutory withholding rates for federal and state tax purposes, including payroll taxes, that are applicable to such supplemental taxable income). Shares surrendered to satisfy tax withholding requirements cannot be subject to any repurchase, forfeiture, unfulfilled vesting or other similarrequirements.

9.4. Other Conditions on Delivery of Stock. The Company will not be obligated to remove restrictions from Shares previously delivered under the Plan until (a) all conditions of the Sale have been met or removed to the satisfaction of the Company, (b) in the opinion of the Company’s counsel, all other legal matters in connection with the delivery of such Shares have been satisfied, including any applicable securities laws and any applicable stock exchange or stock market rules and regulations, and (c) the Participant has executed and delivered to the Company such representations oragreementsastheCompanymayconsiderappropriatetosatisfytherequirementsofanyapplicable

laws, rules or regulations.

SECTION 10. MISCELLANEOUS

10.1. No Right to Continued Employment. No Participant under the Plan who is an officer of the Company shall have any right, because of his or her participation, to continue in the employment of the Company for any period of time or to any right to continue his or her present or any other rate of compensation.

10.2. Amendment. The Compensation Committee may amend, suspend or terminate the Plan or any portion of the Plan at any time; provided that if at any time the approval of the Company’s shareholders is required for any modification or amendment under applicable laws and rules, the Compensation Committee may not effect such modification or amendment without such approval. Unless otherwise specified in the amendment, any amendment to the Plan adopted in accordance with this Section 10.2 shall apply to, and be binding on, the holders of all Shares of Restricted Stock outstanding under the Plan at the time the amendment is adopted, provided the Compensation Committee determines that such amendment, taking into account any related action, does not materially and adversely affect the rights of existing Participants under thePlan.

10.3. Compliance with Code  Section 409A.  No Sale of Restricted Stock shall provide for a deferral of compensation within the meaning of section 409A of theCode.

10.4. Governing Law. The provisions of the Plan and all Sales of Restricted Stock made hereunder shall be governed by and interpreted in accordance with the laws of the State of Oklahoma, excluding choice-of-law principles that would require the application of the laws of a

jurisdiction other than the State of Oklahoma.

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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-8 No. 333-245670) pertaining to the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan of PHX Minerals Inc. of our reports dated December 10, 2020, with respect to the financial statements of PHX Minerals Inc., and the effectiveness of internal control over financial reporting of PHX Minerals Inc., included in this Annual Report (Form 10-K) for the year ended September 30, 2020.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

December 10, 2020

EX-23.2

EXHIBIT 23.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

December 10, 2020

PHX Minerals Inc.

Valliance Bank Tower, Suite 1100

1601 NW Expressway

Oklahoma City, OK 73118

Ladies and Gentlemen:

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

• Report as of September 30, 2020 on Reserves and Revenue of Certain Properties with interests attributable to Panhandle Oil and Gas Inc.;

• Report as of September 30, 2019 on Reserves and Revenue of Certain Properties with interests attributable to Panhandle Oil and Gas Inc.; and

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

We further consent to the inclusion of our report of third party dated October 6, 2020, 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, Chad L. Stephens, certify that:

1. I have reviewed this annual report on Form 10- K of PHX Minerals 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/ Chad L. Stephens

Chad L. Stephens

Chief Executive Officer

Date:   December 10, 2020

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Ralph D’Amico, certify that:

1. I have reviewed this annual report on Form 10- K of PHX Minerals 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/ Ralph D’Amico

Ralph D’Amico

Chief Financial Officer

Date: December 10, 2020 

EX-32.1

Exhibit 32.1

PHX Minerals Inc.

1601 NW Expressway Suite #1100

Oklahoma City, OK  73118

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Chad L. Stephens, Chief Executive Officer of PHX Minerals 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, 2020, 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/ Chad L. Stephens

Chad L. Stephens

President,

Chief Executive Officer

December 10, 2020

EX-32.2

Exhibit 32.2

PHX Minerals Inc.

1601 NW Expressway Suite #1100

Oklahoma City, OK  73118

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Ralph D’Amico, Chief Financial Officer of PHX Minerals 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, 2020, 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/ Ralph D’Amico

Ralph D’Amico

Vice President,

Chief Financial Officer

December 10, 2020

EX-99

Exhibit 99

DeGolyer and MacNaughton

5001 Spring Valley Road 

Suite 800 East

Dallas, Texas 75244 

October 6, 2020

Panhandle Oil and Gas Inc.

1601 NW Expressway

Suite 1100

Oklahoma City, Oklahoma 73118

Pursuant to your request, this report of third party presents an independent evaluation, as of September 30, 2020, 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 6, 2020. The properties evaluated herein are located in Arkansas, Kansas, 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, 2020. 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, 2020. 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 for proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is defined as 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 production taxes, ad valorem taxes, operating expenses, transportation expenses,

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and abandonment costs from future gross revenue. Operating expenses include field operating expenses, processing expenses, and an allocation of overhead that directly relates to production activities. 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 nominal discount rate of 10 percent 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 includes data supplied by IHS Markit Inc; Copyright 2020 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 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 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 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

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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 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.

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(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.

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.

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(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 the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers (SPE) entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. 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.

Based on the current stage of field development, production performance, the development plans provided by Panhandle, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

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The 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.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were 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 effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

Data provided by Panhandle from wells drilled through September 30, 2020, 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 March 2020. Estimated cumulative production, as of September 30, 2020, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 6 months.

Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C₅₊) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 United States

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DeGolyer and MacNaughton

gallons. 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 usage, flare, and shrinkage resulting from field separation and processing. Gas quantities 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 quantities included in this report are expressed in millions of cubic feet (MMcf).

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.

Panhandle has represented that it holds several thousand individual working and royalty interests that generate less than $150 per month in revenue. Reserves for these properties, representing approximately 7.8 percent of the total net reserves of the properties evaluated herein, were summarized by state or area and estimated in the aggregate rather than on a property-by-property basis.

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 West Texas Intermediate (WTI) pricing, 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. The oil, condensate, and NGL prices were calculated using differentials furnished by

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Panhandle to the reference price of $43.55 per barrel and held constant thereafter. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were $40.18 per barrel of oil and condensate and $9.95 per barrel of NGL.

Gas Prices

Panhandle has represented that the gas prices were based on Henry Hub pricing, 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. The gas prices were calculated for each property using differentials furnished by Panhandle to the reference price of $2.04 per million Btu and held constant thereafter. Btu factors provided by Panhandle were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $1.616 per thousand cubic feet of gas.

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 calculated using rates provided by Panhandle based on recent 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. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Panhandle for all properties and were not adjusted for inflation. At the request of Panhandle, abandonment costs and any associated negative

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future net revenue have been included herein for those proved developed producing properties for which reserves were estimated to be zero. The undeveloped locations are royalties, therefore no operating expenses, capital costs, or abandonment costs are incurred. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of undeveloped reserves estimated herein.

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, NGL, and gas 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 FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; 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.

Summary of Conclusions

The estimated net proved reserves, as of September 30, 2020, 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):

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	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of September 30, 2020
	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)
Proved Developed	1,149	1,136	40,924
Proved Undeveloped	185	84	1,449
Total Proved	1,334	1,220	42,373

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of September 30, 2020, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):

Proved Developed (M$) Total Proved (M$)

Future Gross Revenue	123,740	134,179
Production and Ad Valorem Taxes	6,491	7,063
Operating and Transportation Expenses	57,985	59,073
Abandonment Costs	1,957	1,957
Future Net Revenue	57,307	66,086
Present Worth at 10 Percent	33,271	38,930

Note: Future income taxes have not been taken into account in the preparation of these estimates.

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, 2020, 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 MacNAUGHTON Texas 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 Vice President with DeGolyer and MacNaughton, which firm did prepare this report of third party addressed to Panhandle dated
October 6, 2020, and that I, as 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 36 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

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Document and Entity Information - USD ($)

12 Months Ended

Sep. 30, 2020

Dec. 03, 2020

Mar. 31, 2020

Cover [Abstract]

Entity Registrant Name

PHX MINERALS INC.

Entity Central Index Key

0000315131

Document Type

10-K

Document Period End Date

Sep. 30, 2020

Amendment Flag

false

Document Fiscal Year Focus

2020

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 Interactive Data Current

Yes

Entity Filer Category

Accelerated Filer

ICFR Auditor Attestation Flag

true

Entity Emerging Growth Company

false

Entity Small Business

true

Entity Shell Company

false

Entity File Number

001-31759

Entity Tax Identification Number

73-1055775

Entity Address, Address Line One

Valliance Bank Tower

Entity Address, Address Line Two

Suite 1100

Entity Address, Address Line Three

1601 NW Expressway

Entity Address, City or Town

Oklahoma City

Entity Address, State or Province

OK

Entity Address, Postal Zip Code

73118

City Area Code

405

Local Phone Number

948-1560

Entity Incorporation, State or Country Code

OK

Entity Common Stock, Shares Outstanding

22,389,194

Entity Public Float

$ 56,675,049

Document Annual Report

true

Document Transition Report

false

Title of each class

Class A Common Stock, $0.01666 par value

Trading Symbol(s)

PHX

Name of each exchange on which registered

NYSE

Documents Incorporated by Reference

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of PHX Minerals Inc. (to be filed no later than 120 days after September 30, 2020) relating to the Annual Meeting of Stockholders to be held on March 2, 2021, are incorporated into Part III of this Form 10-K.

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Balance Sheets - USD ($)	Sep. 30, 2020	Sep. 30, 2019
Current Assets:
Cash and cash equivalents	$ 10,690,395	$ 6,160,691
Natural gas, oil and NGL sales receivables (net of allowance for uncollectable accounts)	2,943,220	4,377,646
Refundable income taxes	3,805,227	1,505,442
Derivative contracts, net		2,256,639
Other	351,088	177,037
Total current assets	17,789,930	14,477,455
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties	324,886,491	354,718,398
Non-producing natural gas and oil properties	18,993,814	14,599,023
Other	582,444	717,121
Gross properties and equipment, at cost, based on successful efforts accounting	344,462,749	370,034,542
Less accumulated depreciation, depletion and amortization	(263,590,801)	(258,607,521)
Net properties and equipment	80,871,948	111,427,021
Investments	79,308	205,076
Derivative contracts, net		237,505
Operating lease right-of-use assets	690,316
Other, net	590,333	297,890
Total assets	100,021,835	126,644,947
Current Liabilities:
Accounts payable	997,637	665,160
Derivative contracts, net	281,942
Current portion of operating lease liability	127,108
Accrued liabilities and other	1,297,363	2,433,466
Short-term debt	1,750,000
Total current liabilities	4,454,050	3,098,626
Long-term debt	27,000,000	35,425,000
Deferred income taxes	1,329,007	5,976,007
Asset retirement obligations	2,897,522	2,835,781
Derivative contracts, net	425,705
Operating lease liability, net of current portion	921,625
Stockholders' equity:
Class A voting common stock, $0.01666 par value; 24,000,500 shares authorized; 22,647,306 issued at September 30, 2020, and Class A voting common stock, $0.01666 par value; 24,000,000 shares authorized; 16,897,306 issued at September 30, 2019	377,304	281,509
Capital in excess of par value	10,649,611	2,967,984
Deferred directors' compensation	1,874,007	2,555,781
Retained earnings	56,244,100	81,848,301
Stockholders' Equity	69,145,022	87,653,575
Treasury stock, at cost; 411,487 shares at September 30, 2020; 558,051 shares at September 30, 2019	(6,151,096)	(8,344,042)
Total stockholders' equity	62,993,926	79,309,533
Total liabilities and stockholders' equity	$ 100,021,835	$ 126,644,947

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Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2020	Sep. 30, 2019
Statement Of Financial Position [Abstract]
Common stock, par value	$ 0.01666	$ 0.01666
Common stock, shares authorized	24,000,500	24,000,000
Common stock, shares issued	22,647,306	16,897,306
Treasury stock, shares	411,487	558,051

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Statements Of Operations - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Revenues:
Revenues	$ 23,370,003
Gains (losses) on derivative contracts	907,419	$ 6,105,145	$ (4,932,068)
Gain on asset sales	3,997,436	18,973,426
Revenues	28,965,819	66,035,685	45,034,264
Costs and expenses:
Lease operating expenses	4,841,541	6,398,522	6,714,448
Transportation, gathering and marketing	4,812,869	6,089,903	6,745,830
Production taxes	1,022,912	1,902,636	2,089,050
Depreciation, depletion and amortization	11,313,783	18,196,583	18,395,040
Provision for impairment	29,904,528	76,824,337
Interest expense	1,286,788	1,995,789	1,748,101
General and administrative	8,024,901	8,565,243	7,342,441
Other expense (income)	(466)	288,610	102,685
Total costs and expenses	61,206,856	120,261,623	43,137,595
Income (loss) before provision (benefit) for income taxes	(32,241,037)	(54,225,938)	1,896,669
Provision (benefit) for income taxes	(8,289,000)	(13,481,000)	(12,739,000)
Net income (loss)	$ (23,952,037)	$ (40,744,938)	$ 14,635,669
Basic and diluted earnings (loss) per common share	$ (1.41)	$ (2.43)	$ 0.86
Natural Gas, Oil and NGL [Member]
Revenues:
Revenues	$ 23,370,003	$ 39,410,036	$ 48,385,335
Lease Bonuses and Rental Income [Member]
Revenues:
Revenues	$ 690,961	$ 1,547,078	$ 1,580,997

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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, 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)
Net income (loss)	14,635,669				14,635,669
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
Dividends declared	(2,698,940)				(2,698,940)
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
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)
Net income (loss)	(40,744,938)				(40,744,938)
Purchase of treasury stock	(7,454,000)					$ (7,454,000)
Purchase of treasury stock, shares						(515,972)
Issuance of treasury shares to ESOP	372,274		(25,830)			$ 398,104
Issuance of treasury shares to ESOP, shares						26,629
Restricted stock awards	771,797		771,797
Dividends declared	(2,673,706)				(2,673,706)
Distribution of restricted stock to officers and directors	413	$ 7	(394,824)			$ 395,230
Distribution of restricted stock to officers and directors, shares		425				24,360
Distribution of deferred directors' compensation	(3)		(207,850)	(667,115)		$ 874,962
Distribution of deferred directors' compensation, shares						52,399
Common shares to be issued to directors for services	272,491			272,491
Balances at Sep. 30, 2019	$ 79,309,533	$ 281,509	2,967,984	2,555,781	81,848,301	$ (8,344,042)
Balances, shares at Sep. 30, 2019		16,897,306
Balances, Treasury shares at Sep. 30, 2019	(558,051)					(558,051)
Net income (loss)	$ (23,952,037)				(23,952,037)
Purchase of treasury stock	(7,635)					$ (7,635)
Purchase of treasury stock, shares						(632)
Issuance of treasury shares to ESOP	103,104		(974,806)			$ 1,077,910
Issuance of treasury shares to ESOP, shares						72,101
Restricted stock awards	743,897		743,897
Dividends declared	(1,652,164)				(1,652,164)
Distribution of restricted stock to officers and directors	94		(82,820)			$ 82,914
Distribution of restricted stock to officers and directors, shares						5,546
Distribution of deferred directors' compensation			(129,575)	(910,182)		$ 1,039,757
Distribution of deferred directors' compensation, shares						69,549
Common shares to be issued to directors for services	228,408			228,408
Equity offering	8,220,726	$ 95,795	8,124,931
Equity offering, shares		5,750,000
Balances at Sep. 30, 2020	$ 62,993,926	$ 377,304	$ 10,649,611	$ 1,874,007	$ 56,244,100	$ (6,151,096)
Balances, shares at Sep. 30, 2020		22,647,306
Balances, Treasury shares at Sep. 30, 2020	(411,487)					(411,487)

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Statements Of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Statement Of Stockholders Equity [Abstract]
Dividends per share	$ 0.10	$ 0.16	$ 0.16

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Statements Of Cash Flows - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Operating Activities
Net income (loss)	$ (23,952,037)	$ (40,744,938)	$ 14,635,669
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	11,313,783	18,196,583	18,395,040
Impairment	29,904,528	76,824,337
Provision for deferred income taxes	(4,647,000)	(12,112,000)	(12,963,000)
Gain from leasing fee mineral acreage	(685,927)	(1,546,298)	(1,520,262)
Proceeds from leasing fee mineral acreage	701,948	1,565,649	1,564,225
Net (gain) loss on sales of assets	(3,973,321)	(18,730,197)	660,597
ESOP contribution expense	103,104	372,274	382,174
Directors' deferred compensation expense	228,408	272,491	301,715
Total (gain) loss on derivative contracts	(907,419)	(6,105,145)	4,932,068
Cash receipts (payments) on settled derivative contracts	4,109,210	196,985	(1,001,893)
Restricted stock awards	743,897	771,797	655,414
Other	(2,611)	19,085	6,326
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables	1,434,426	2,723,983	483,856
Refundable income taxes	(2,299,785)	(1,472,277)	456,780
Other current assets	(89,931)	21,116	57,752
Accounts payable	1,308,731	105,217	(140,600)
Other non-current assets	(1,044,680)	7,166	(62,295)
Accrued liabilities	(1,139,029)	639,856	100,328
Total adjustments	35,058,332	61,750,622	12,308,225
Net cash provided by operating activities	11,106,295	21,005,684	26,943,894
Investing Activities
Capital expenditures	(403,136)	(3,526,007)	(11,590,135)
Acquisition of minerals and overrides	(10,288,250)	(5,662,869)	(11,327,371)
Investments in partnerships		(1,648)	3,354
Proceeds from sales of assets	4,228,868	19,515,735	1,085,137
Net cash (used in) provided by investing activities	(6,462,518)	10,325,211	(21,829,015)
Financing Activities
Borrowings under debt agreement	6,061,725	16,642,481	29,017,800
Payments of loan principal	(12,736,725)	(32,217,481)	(30,239,800)
Net proceeds from equity issuance	8,220,726
Purchases of treasury stock	(7,635)	(7,454,000)	(1,219,228)
Payments of dividends	(1,652,164)	(2,673,706)	(2,698,940)
Net cash provided by (used in) financing activities	(114,073)	(25,702,706)	(5,140,168)
Increase (decrease) in cash and cash equivalents	4,529,704	5,628,189	(25,289)
Cash and cash equivalents at beginning of year	6,160,691	532,502	557,791
Cash and cash equivalents at end of year	10,690,395	6,160,691	532,502
Supplemental Disclosures of Cash Flow Information
Interest paid (net of capitalized interest)	1,306,967	2,031,762	1,730,461
Income taxes paid (net of refunds received)	(1,342,275)	103,279	(232,782)
Supplemental schedule of noncash investing and financing activities:
Additions and revisions, net, to asset retirement obligations	4	27,782	17,216
Gross additions to properties and equipment	10,701,284	9,248,415	21,711,279
Net (increase) decrease in accounts payable for properties and equipment additions	(9,898)	(59,539)	1,206,227
Capital expenditures	$ 10,691,386	$ 9,188,876	$ 22,917,506

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Summary Of Significant Accounting Policies

12 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

The Company’s principal line of business is maximizing the value of its existing mineral and royalty assets through active management and expanding its asset base through acquisitions of additional mineral and royalty interests.  The Company owns mineral and leasehold properties and other natural gas and oil interests, which are all located in the contiguous United States, primarily in Oklahoma, Texas, North Dakota, Arkansas and New Mexico, with properties located in several other states. The Company’s natural gas, oil and NGL production is from interests in 6,510 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 44%, 48% and 8% of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in 2020. Approximately 69%, 19% and 12% of the Company’s total sales volumes in 2020 were derived from natural gas, oil and NGL, respectively. Substantially all the Company’s natural gas, oil and NGL production is sold through the operators of the wells. From time to time, the Company sells certain non-material, non-core or small-interest natural gas and oil 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 natural gas, crude oil and NGL 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 natural gas, crude oil and NGL 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 natural gas, crude oil and NGL prices as estimated by management are used. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Management uses projected future natural gas, crude oil and NGL pricing assumptions to prepare estimates of natural gas, crude oil and NGL reserves used in formulating management’s overall operating decisions.

As a non-operator, the Company receives actual natural gas, oil and NGL sales volumes and prices more than a month after the information is available to the operators of the wells. Because of the delay in information on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, as well as public and private sources, and natural gas, oil and NGL 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 natural gas, oil and NGL 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 natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.

Basis of Presentation

Certain amounts (lease operating expenses and transportation, gathering and marketing in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation.

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.

Natural Gas, Oil and NGL Sales

The Company sells natural gas, oil and NGL to various customers, recognizing revenues as natural gas, oil and NGL is produced and sold.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers of natural gas, oil and NGL or operators of the natural gas and oil properties. Natural gas, oil and NGL 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 natural gas, oil and NGL 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 2020, 2019 and 2018 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.

Natural Gas and Oil Producing Activities

The Company follows the successful efforts method of accounting for natural gas and oil 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. Natural gas and oil mineral and leasehold costs are capitalized when incurred. 

Leasing of Mineral Rights

The Company generates lease bonuses by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances 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 income. 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 utilizes derivative contracts to reduce its exposure to short-term fluctuations in the price of natural gas and oil. These derivates are recorded at fair value on the balance sheet. The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges.

Properties and Equipment

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization of the costs of producing natural gas and oil 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. Leasehold 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 natural gas and oil properties include non-producing minerals, which had a net book value of $13,556,020 and $9,673,787 at September 30, 2020 and 2019, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Oklahoma, Texas, North Dakota, Arkansas and New Mexico. As mentioned, these mineral rights are perpetual and have been accumulated over the 94-year life of the Company. There are approximately 190,990 net acres of non-producing minerals in more than 6,380 tracts owned by the Company. An average tract contains approximately 30 acres and the average cost per acre is $71. Since inception, the Company has continually generated an interest in several thousand natural gas and oil 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 (unlike natural gas and oil 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 Company’s mineral ownership consists 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 (by mineral deed).

When a new well is drilled on the Company’s mineral acreage, all of the non-producing mineral costs for the associated mineral deed are transferred to producing minerals and are amortized straight-line over a 20-year period (insignificant fields are amortized over 10-year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on the Company’s minerals, and future development will deplete these assets over a long period. Given that we are moving all of the costs to the first new well drilled on each mineral deed, we believe that a straight-line amortization over a 20-year period is appropriate, as these wells and future development will deplete these assets over a fairly long period.

Capitalized Interest

During 2020, 2019 and 2018, interest of $0, $38,606 and $89,023, respectively, was included in the Company’s capital expenditures. Interest of $1,286,788, $1,995,789 and $1,748,101, 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.

Accrued Liabilities

The following table shows the balances for the years ended September 30, 2020 and 2019, relating to the Company’s accrued liabilities:

	Year Ended September 30,
	2020		2019
Accrued compensation	$	481,062	$	1,446,710
Revenues payable		281,380		396,954
Accrued ad valorem		228,010		260,550
Other		306,911		329,252
Total accrued liabilities	$	1,297,363	$	2,433,466

The decrease in accrued compensation from 2019 to 2020 is primarily due to the one-time severance with the Company’s former CEO of approximately $670,000 upon his resignation at the end of fiscal 2019 as well as lower performance-related compensation in 2020.

Asset Retirement Obligations

The Company owns interests in natural gas and oil 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 asset retirement obligations.

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 the Company being responsible for its proportionate share of the costs involved (on working interest wells only). The Company 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, 2020 and 2019, 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 (time-based), subject to certain share price performance standards (market-based) or subject to company performance standards (performance-based). Restricted stock awards to the non-employee directors provide for annual 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 reduced the U.S. federal corporate tax rate from 35% to 21%. As of September 30, 2018, we completed our estimates accounting for the tax effects of the Act. Based on these estimates, we recognized an amount which was included as a component of income tax expense (benefit) from continuing operations in 2018.

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 in 2018 was $12,464,000 income tax benefit.

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, 2019, was a 25% benefit, as compared to a 26% benefit for the year ended September 30, 2020.

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 2017.

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, 2020, 2019 and 2018, the Company’s interest and penalties were not material. The Company does not believe it has any material uncertain tax positions.

Recent Accounting Pronouncements

Standard	Description	Date of Adoption	Impact on Financial Statements or Other Significant Matters
Adoption of New Accounting Pronouncements
ASU 2016-02, Leases (Topic 842)	This update will supersede the lease requirements in Topic 840, Leases, by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet.	Q1 2020	See Note 2: Leases for further details related the Company’s adoption of this standard.
ASU 2018-11, Leases (Topic 842), Targeted Improvements and ASC 842	This update will allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the financial statements, and will allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if any, rather than in the earliest period presented.	Q1 2020	See Note 2: Leases for further details related the Company’s adoption of this standard.
New Accounting Pronouncements yet to be Adopted
ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.	This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost.	Q1 2021	The standard is effective for interim and annual periods beginning after December 15, 2019, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company evaluated the new standard and determined the impact to not be material. Historically, the Company's credit losses on natural gas, oil and NGL sales receivables have been immaterial.

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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Leases and Commitments

12 Months Ended

Sep. 30, 2020

Leases [Abstract]

Leases and Commitments

2. LEASES AND COMMITMENTS

Impact of ASC 842 Adoption

On October 1, 2019, the Company adopted ASU 2016-02, Leases (Topic 842) using the modified retrospective method. This ASU, as subsequently amended by ASU 2018-01, ASU 2018-10, ASU 2018-11 and ASU 2018-20, requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous guidance. The Company elected the practical expedient under ASU 2018-11, and used October 1, 2019, the beginning of the period of adoption, as its date of initial application. The Company elected the set of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard.

The Company’s existing operating lease right-of-use (“ROU”) assets and operating lease obligations were less than 1% of the Company's total assets as of December 31, 2019, had remaining terms of less than 12 months and were not considered material to the Company; and therefore, the adoption of the standard had no related impact on the Company’s Balance Sheets as of October 1, 2019. Additionally, there was no related impact on the Company’s Statements of Operations, and the standard had no impact on the Company’s debt covenant compliance under existing agreements.

Assessment of Leases

The Company determines if an arrangement is a lease at inception by considering whether (i) explicitly or implicitly identified assets have been deployed in the agreement and (ii) the Company obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. As of September

30, 2020, none of the Company’s leases were classified as financing leases. Operating lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company signed a new seven-year lease for office space during the quarter ended March 31, 2020, with a commencement date in August 2020. The associated lease liability and ROU asset at September 30, 2020, were $1,048,733 and $690,316, respectively. The Company has a lease incentive asset of $344,000, which is included in Other, net on the Company’s Balance Sheets.    

ROU assets represent the Company’s right to use an underlying asset for the lease term, and operating lease liabilities represent the Company’s obligation to make payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs and prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Company uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments.

The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Company will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Company will exercise that option. Lease expense for lease payments will be recognized on a straight-line basis over the lease term. The Company made an accounting policy election to not recognize leases with terms, including applicable options, of less than twelve months on the Company’s Balance Sheets and recognize those lease payments in the Company’s Statements of Operations on a straight-line basis over the lease term. In the event that the Company’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.

The following table represents the maturities of the operating lease liabilities as of September 30, 2020:

2021	$	166,744
2022		166,744
2023		167,475
2024		175,520
2025		176,251
Thereafter		353,234
Total lease payments	$	1,205,968
Less: Imputed interest		(157,235	)
Total	$	1,048,733

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Revenues

12 Months Ended

Sep. 30, 2020

Revenue From Contract With Customer [Abstract]

Revenues

3. REVENUES

Lease bonus income

The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in Accounting Standards Codification (“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 rental income line item on the Company’s Statements of Operations.

Natural gas and oil derivative contracts

See Note 12 for discussion of the Company’s accounting for derivative contracts.

Revenues from Contracts with Customers

Natural gas, oil and NGL sales

Sales of natural gas, oil and NGL are recognized when production is sold to a purchaser and control has transferred. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation; however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate.

Disaggregation of natural gas, oil and NGL revenues

The following table presents the disaggregation of the Company's natural gas, oil and NGL revenues for the year ended September 30, 2020.

	Year Ended September 30, 2020
	Royalty Interest		Working Interest		Total
Natural gas revenue	$	3,987,660	$	6,268,094	$	10,255,754
Oil revenue		5,691,837		5,496,533		11,188,370
NGL revenue		776,426		1,149,453		1,925,879
Natural gas, oil and NGL sales	$	10,455,923	$	12,914,080	$	23,370,003

Performance obligations

The Company satisfies the performance obligations under its natural gas and oil sales contracts upon delivery of its production and related transfer of title to purchasers. Upon delivery of production, the Company has a right to receive consideration from its purchasers in amounts that correspond with the value of the production transferred.

Allocation of transaction price to remaining performance obligations

Natural gas, oil and NGL sales

As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606, which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment relate specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient.

Prior-period performance obligations and contract balances

The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited control and visibility into the timing of when new wells start producing, and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the natural gas, oil and NGL sales receivables line item on the Company’s Balance Sheets. The difference between the Company's estimates and the actual amounts received for natural gas, oil and NGL sales is recorded in the quarter that payment is received from the third party. For the years ended September 30, 2020, 2019 and 2018, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was immaterial and considered a change in estimate.

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Income Taxes

12 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

Income Taxes

4. INCOME TAXES

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

	2020			2019			2018
Current:
Federal	$	(3,642,000	)	$	(1,388,000	)	$	204,000
State		-			19,000			20,000
		(3,642,000	)		(1,369,000	)		224,000
Deferred:
Federal		(3,611,000	)		(9,763,000	)		(13,240,000	)
State		(1,036,000	)		(2,349,000	)		277,000
		(4,647,000	)		(12,112,000	)		(12,963,000	)
	$	(8,289,000	)	$	(13,481,000	)	$	(12,739,000	)

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:

	2020			2019			2018
Provision (benefit) for income taxes at statutory rate	$	(6,765,705	)	$	(11,387,447	)	$	465,253
Percentage depletion		(258,300	)		(431,340	)		(577,780	)
State income taxes, net of federal provision (benefit)		(939,310	)		(1,986,850	)		36,980
Effect of NOL Carryback Rate		(610,803	)		-			-
State NOL Valuation Allowance		96,000			-			-
Restricted stock tax benefit		58,000			185,000			(69,000	)
Deferred directors’ compensation benefit		79,000			(38,000	)		(134,000	)
Law change (a)		-			-			(12,464,000	)
Other		52,118			177,637			3,547
	$	(8,289,000	)	$	(13,481,000	)	$	(12,739,000	)

(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:

	2020		2019
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible    drilling costs capitalized for financial purposes and    expensed for tax purposes	$	3,880,307	$	8,885,776
Derivative contracts		-		619,392
		3,880,307		9,505,168
Deferred tax assets:
State net operating loss carry forwards, net of valuation allowance		391,193		431,977
Federal net operating loss carry forwards		369,523		-
Statutory depletion carryover		346,414		85,680
AMT credit carry forwards		-		1,387,042
Asset retirement obligations		499,708		459,810
Deferred directors' compensation		436,225		602,394
Restricted stock expense		220,301		119,697
Derivative contracts		176,963		-
Business interest limitation		-		358,110
Other		110,973		84,451
		2,551,300		3,529,161
Net deferred tax liabilities	$	1,329,007	$	5,976,007

Included in state net operating loss carry forwards at September 30, 2020, the Company had a deferred tax asset of $350,543 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring in 2037. There is no valuation allowance for the OK NOLs, as management believes they will be utilized before they expire. The Company had a deferred tax asset of $95,611 related to Arkansas state income tax net operating loss (AR NOL) carry forwards, which begin to expire in 2022. The Company has a full valuation allowance for the AR NOLs, as it is more likely than not that these will not be utilized before expiration. There is no valuation allowance for the federal NOLs, nor do they expire.

The federal Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 Net Operating Losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. On July 28, 2020, final regulations were issued under Section 163(j) which modified the calculation under the previous proposed regulations of adjusted taxable income for purposes of the 50% limitation on interest expense. Under the final regulations, depreciation, amortization, and depletion capitalizable under Section 263A is now added back to tentative taxable income.  This change allows all interest expense to be deductible for 2020 and reduces the associated deferred tax asset to zero. During the quarter ended June 30, 2020, the Company filed for a tax refund associated with the AMT credits totaling $1.4 million, which was accelerated due to the CARES Act. Additionally, the Company has a $2.2 million receivable associated with the carryback of the 2020 federal net operating loss.

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Debt

12 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Debt

5. 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 $31,000,000 as of September 30, 2020, and a maturity date of November 30, 2022 (as amended, the “Credit Facility”). The Credit Facility is subject to at least semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The Credit Facility is secured by all of the Company’s producing gas and oil properties. The interest rate is based on BOK prime plus from 1.00% to 1.75%, or 30-day LIBOR plus from 2.50% to 3.25%. 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, 2020, the effective interest rate was 4.25%.

The Company’s debt is recorded at the carrying amount on its Balance Sheets. The carrying amount of the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in Other, net on the Company’s Balance Sheets. Total debt issuance cost net of amortization as of September 30, 2020, was $246,724. The debt issuance cost is amortized over the life of the credit facility.

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 natural gas and oil properties. On June 24, 2020, the Company entered into the Seventh Amendment to its Credit Facility. The amendment reduced the borrowing base from $45,000,000 to $32,000,000 and included a Quarterly Commitment Reduction, whereby the borrowing base is reduced by $1,000,000 each April 15, July 15, October 15 and January 15, commencing on July 15, 2020. The next redetermination occurred in December 2020. See Note 15: Subsequent Events for further discussion. The Credit Facility 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 stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (as defined in the Credit Facility) of no more than 4.0 to 1.0 based on the trailing twelve months. At September 30, 2020, the Company was in compliance with the covenants of the Credit Facility, had $28,750,000 outstanding, of which $1,750,000 is classified as short-term debt due to the Quarterly Commitment Reduction, and had $2,250,000 of borrowing base availability under the Credit Facility.

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Stockholders' Equity

12 Months Ended

Sep. 30, 2020

Stockholders Equity Note [Abstract]

Stockholders' Equity

6. STOCKHOLDERS’ EQUITY

Upon approval by the stockholders 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. For the year ended September 30, 2020, $7,635 had been spent to purchase 632 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, 2020

Earnings Per Share [Abstract]

Earnings (Loss) Per Share

7. EARNINGS (LOSS) PER SHARE

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

	Year Ended September 30,
	2020			2019			2018
Numerator for basic and diluted earnings (loss) per share:
Net income (loss)	$	(23,952,037	)	$	(40,744,938	)	$	14,635,669
Denominator for basic and diluted earnings per share:
Weighted average shares (including for 2020, 2019    and 2018, unissued, vested directors' shares of    154,142, 168,586 and 205,736, respectively)		17,010,934			16,743,746			16,952,664

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Employee Stock Ownership Plan

12 Months Ended

Sep. 30, 2020

Share Based Arrangements To Obtain Goods And Services [Abstract]

Employee Stock Ownership Plan

8. 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 shares of the Company’s Common Stock held by the plan as of September 30, 2020, 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
2020		72,101	$	103,104
2019		26,629	$	372,274
2018		20,632	$	382,174

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Deferred Compensation Plan For Directors

12 Months Ended

Sep. 30, 2020

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Deferred Compensation Plan For Directors

9. DEFERRED COMPENSATION PLAN FOR DIRECTORS

Annually, independent directors may elect to be included in the Company’s 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 at each quarter end. 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, 2020, there were 177,678 shares (179,226 shares at September 30, 2019) recorded under the Plan. The deferred balance outstanding at September 30, 2020, under the Plan was $1,874,007 ($2,555,781 at September 30, 2019). Expenses totaling $228,408, $272,491 and $301,715 were charged to the Company’s results of operations for the years ended September 30, 2020, 2019 and 2018, respectively, and are included in general and administrative expense in the accompanying Statements of Operations.

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Restricted Stock Plan

12 Months Ended

Sep. 30, 2020

Restricted Stock Plan [Abstract]

Restricted Stock Plan

10. RESTRICTED STOCK PLAN

In March 2010, stockholders approved the Company’s 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 stockholders. In March 2014, stockholders 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. In March 2020, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan to 750,000 shares. 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 stockholders.

In June 2010, the Company began awarding shares of the Company’s Common Stock as restricted stock (time-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 (market-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 (time-based) to its non-employee directors. The restricted stock vests annually during the calendar year. 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.

Effective in May 2014, the Board adopted stock repurchase resolutions to allow management, at its discretion, to purchase the Company’s common stock as treasury shares up to an amount equal to the aggregate number of shares of common stock awarded pursuant to the Amended 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

Effective in May 2018, the Board of directors approved an amendment to the Company’s existing stock repurchase program (the “Repurchase Program”). As amended, the Repurchase Program continues to allow the Company to repurchase up to $1.5 million of the Company’s common stock at management’s discretion. The Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $1.5 million of the Company’s common stock is authorized and approved whenever the previous amount is utilized. In addition, 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 Amended 2010 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.

On December 11, 2019, the Company awarded 10,038 time-based shares and 15,058 market-based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year period and contains non-forfeitable rights to receive dividends and voting rights during the vesting period. The market-based shares that do not meet certain market performance criteria at a certain date are forfeited. The time-based and market-based shares had fair values on their award date of $122,062 and $160,401, respectively. The fair values for the time-based and the market-based awards will be recognized as compensation expense ratably over the vesting period. The fair value of the market-based shares on their award date is calculated by simulating the Company’s stock prices as compared to the S&P Oil & Gas Exploration & Production ETF (XOP) prices utilizing a Monte Carlo model covering the market performance period (December 11, 2019, through December 11, 2022).

On January 2, 2020, the Company awarded 22,300 time-based shares of the Company’s common stock as restricted stock to its non-employee directors. The restricted stock contains non-forfeitable rights to receive dividends and to vote the shares during the vesting period. The restricted stock vests on December 31, 2020. These time-based shares had a fair value on their award date of $246,640.

On January 16, 2020, upon naming a new Chief Executive Officer, the Company awarded 53,476 time-based shares and 21,988 market-based shares of the Company’s common stock as restricted stock, with the same vesting criteria as the December 11, 2019 awards discussed above. The time-based and market-based shares had fair values on their award date of $500,000 and $179,334, respectively. An additional 37,045 of performance-based shares were awarded to the Company’s officers at that time. Based on the performance criteria linked to return on capital employed it is probable none of these awards will vest, and they have no value as of September 30, 2020.

On March 9, 2020, upon naming a new Chief Financial Officer, the Company awarded 16,340 time-based shares, 2,534 market-based shares and 2,534 performance-based shares of the Company’s common stock as restricted stock, with the same vesting criteria as the December 11, 2019, and January 16, 2020, awards discussed above. The time-based and market-based shares had fair values on their award date of $72,550 and $9,814, respectively. Based on the performance criteria linked to return on capital employed it is probable none of the performance-based share awards will vest, and they have no value as of September 30, 2020.

Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur. The dilutive impact of all restricted stock plans is immaterial for all periods presented.

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2020, 2019 and 2018, related to the Company’s market-based, time-based and performance-based restricted stock:

	Year Ended September 30,
	2020		2019		2018
Market-based, restricted stock	$	295,397	$	367,091	$	276,272
Time-based, restricted stock		448,500		404,706		379,142
Performance-based, restricted stock		-		-		-
Total compensation expense	$	743,897	$	771,797	$	655,414

A summary of the Company’s unrecognized compensation cost for its unvested market-based, time-based and 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 Average Period (in years)
Market-based, restricted stock	$	67,653		1.83
Time-based, restricted stock		562,829		1.97
Performance-based, restricted stock		-
Total	$	630,482

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

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

	Market-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Time-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Performance-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value
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		-		$	-
Granted		43,287			8.24		27,978			15.61		-			-
Vested		-			-		(24,785	)		18.30		-			-
Forfeited		(89,321	)		10.08		(13,153	)		18.23		-			-
Unvested shares as of September 30,    2019		46,670		$	10.21		18,707		$	17.54		-		$	-
Granted		39,579			8.83		102,154			9.21		39,579			-
Vested		-			-		(20,410	)		13.35		-			-
Forfeited		(24,779	)		11.34		(9,929	)		13.93		(4,765	)		-
Unvested shares as of September 30,    2020		61,470		$	8.87		90,522		$	9.49		34,814		$	-

The intrinsic value of the vested shares in 2020 was $85,306.

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Properties And Equipment

12 Months Ended

Sep. 30, 2020

Property Plant And Equipment [Abstract]

Properties And Equipment

11. PROPERTIES AND EQUIPMENT

Impairment

During the quarter ended March 31, 2020, impairment of $19.3 million and $7.3 million was recorded on our Fayetteville Shale and Eagle Ford fields, respectively. The remaining $2.7 million of impairment was taken on other producing assets. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of March 31, 2020, using a discount rate of 10% for proved developed and assigning no value to undeveloped locations. The Fayetteville Shale assets are dry-gas assets of which the Company acquired a portion in 2011. Low natural gas prices at March 31, 2020, were the primary reason for impairment in this field. The Company recognized an impairment related to the Eagle Ford at September 30, 2019, discussed below. The further impairment of the Eagle Ford assets at March 31, 2020, was due to the decline in commodity prices over fiscal 2020.

At the end of 2019, impairment of $76.6 million was recorded on our Eagle Ford assets. The remaining $0.3 million of impairment was taken on other assets. The impairment on the Eagle Ford assets was caused by the Company making the strategic decision to cease participating with a working interest on its mineral and leasehold acreage going forward and therefore removing all working interest PUDs from the Company’s reserve reports. The removal of the PUDs caused the Eagle Ford assets to fail the step one test for impairment, as its undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The Company determined the fair value based on discounted cash flows of the properties as well as active market bids received from interested potential buyers. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of year-end, using a discount rate of 10% for proved developed and assigning no value to undeveloped locations. Market bids received from interested potential buyers corroborated the fair value of the discounted cash flows as of year-end. The fair value was determined to be $9.1 million based on the discounted cash flows and market quotes. The Company decided not to sell the assets after the marketing process was complete, as we believed that the market conditions were not ideal for selling at that time and that the highest and best use of the assets was to continue to own and produce out the Eagle Ford properties.

A further reduction in natural gas, oil and NGL 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 2020 fiscal year, the Company sold 530 net mineral acres in Eddy County, New Mexico, for $3,376,049 and recorded a net gain on sales of $3,272,499. The total net book value that was removed from the Balance Sheets due to this sale was approximately $104,000. The Company utilized a like-kind exchange under Internal Revenue Code Section 1031 to defer income tax on all of the gain by offsetting it with the STACK/SCOOP mineral acreage acquisition that was purchased during the quarter using qualified exchange accommodation. The Company also sold 5,925 open and non-producing net mineral acres in Northwest Oklahoma for $769,745 and recorded a net gain on sales of $717,640. The total net book value that was removed from the Balance Sheets due to this sale was approximately $52,000.  On the Statements of Operations, the net gain is reflected in the Gain on asset sales line item.

During the 2019 fiscal year, the Company sold 112 non-core wells and 890 net mineral and non-participating royalty interest acres for $19,515,735 and recorded a net gain on sales of $18,730,197. The total net book value that was removed from the Balance Sheets due to these sales was approximately $786,000. On the Statements of Operations, the net gain is reflected in the Gain on asset sales line item with a balance of $18,973,426 with an offset to the Loss on asset sales line item in the amount of $243,228.

Acquisitions

During the 2020 fiscal year, the Company closed on the purchase of 700 net mineral acres in Kingfisher, Canadian and Garvin Counties, Oklahoma, for a purchase price of $9,293,384 (after customary closing adjustments). These mineral purchases were accounted for as asset acquisitions.

During the 2019 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 790 net mineral acres for $5,727,257 or an average of approximately $7,200 per net mineral acre. These mineral purchases were accounted for as asset acquisitions.

Asset Retirement Obligations

The following table shows the activity for the years ended September 30, 2020 and 2019, relating to the Company’s asset retirement obligations:

	2020			2019
Asset retirement obligations as of beginning of the year	$	2,835,781		$	2,809,378
Wells acquired or drilled		4			27,783
Wells sold or plugged		(68,668	)		(134,090	)
Accretion of discount		130,405			132,710
Asset retirement obligations as of end of the year	$	2,897,522		$	2,835,781

As a non-operator, the Company does not control the plugging of wells in which it has a working interest and is not involved in the negotiation of the terms of the plugging contracts. This estimate relies on information gathered from outside sources as well as relevant information received directly from operators.

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Derivatives

12 Months Ended

Sep. 30, 2020

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivatives

12. 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 natural gas and oil. 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 natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in prices. All of the Company’s derivative contracts at September 30, 2020, were with Bank of Oklahoma. All of the Company’s derivative contracts at September 30, 2019, were with Bank of Oklahoma and Koch Supply and Trading LP. The Company’s derivative contracts with Bank of Oklahoma are secured under its credit facility with Bank of Oklahoma. The derivative contracts with Koch were unsecured. The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of September 30, 2020

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - October 2020	10,000 Mmbtu	NYMEX Henry Hub	$2.20 floor / $2.59 ceiling
November 2020 - December 2021	50,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.90 ceiling
November 2020 - December 2021	40,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2020	26,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
December 2020	28,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
January 2021	32,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
February 2021	25,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
March 2021	30,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
April 2021	31,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
May 2021	32,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
June 2021	30,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
July 2021	31,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
August 2021	12,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
September 2021	11,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
October 2021	9,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
November 2021	8,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
December 2021	10,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
January 2022	25,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
November - December 2020	53,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
January 2021	72,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
February 2021	48,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
March 2021	61,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
April 2021	63,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
May 2021	69,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
June 2021	61,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
July 2021	83,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
August - September 2021	27,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
October 2021	20,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2021	14,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
December 2021	4,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
January 2022	77,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2020	54,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
December 2020	55,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
January 2021	64,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
February 2021	52,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
March - April 2021	62,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
May 2021	66,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
June 2021	60,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
July 2021	64,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
August 2021	24,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
September 2021	18,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
October 2021	19,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
November - December 2021	20,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
January - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas fixed price swaps
January - December 2020	80,000 Mmbtu	NYMEX Henry Hub	$	2.750
April - October 2020	10,000 Mmbtu	NYMEX Henry Hub	$	2.405
November 2020 - March 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.661
January 2021 - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$	2.729
January 2021 - December 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.765
November 2020	26,500 Mmbtu	NYMEX Henry Hub	$	2.582
December 2020	28,000 Mmbtu	NYMEX Henry Hub	$	2.582
January 2021	32,000 Mmbtu	NYMEX Henry Hub	$	2.582
February 2021	25,500 Mmbtu	NYMEX Henry Hub	$	2.582
March 2021	30,500 Mmbtu	NYMEX Henry Hub	$	2.582
April 2021	31,500 Mmbtu	NYMEX Henry Hub	$	2.582
May 2021	32,500 Mmbtu	NYMEX Henry Hub	$	2.582
June 2021	30,500 Mmbtu	NYMEX Henry Hub	$	2.582
July 2021	31,500 Mmbtu	NYMEX Henry Hub	$	2.582
August 2021	12,500 Mmbtu	NYMEX Henry Hub	$	2.582
September 2021	11,000 Mmbtu	NYMEX Henry Hub	$	2.582
October 2021	9,000 Mmbtu	NYMEX Henry Hub	$	2.582
November 2021	8,000 Mmbtu	NYMEX Henry Hub	$	2.582
December 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.582
January 2022	25,500 Mmbtu	NYMEX Henry Hub	$	2.582
Oil costless collars
January - December 2020	2,000 Bbls	NYMEX WTI	$55.00 floor / $62.00 ceiling
August - October 2020	1,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
November - December 2020	500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
January 2021	2,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
February 2021	1,500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
March - July 2021	2,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
January 2022	2,500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
August - October 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
November - December 2020	500 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
January - July 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
August - September 2021	500 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
January 2022	3,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
August 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
September - November 2020	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
December 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 2021	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 2021	1,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
March - April 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
May 2021	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
June - July 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
August 2021	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 2022	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 2022	5,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
Oil fixed price swaps
January - December 2020	2,000 Bbls	NYMEX WTI	$	55.28
January - December 2020	2,000 Bbls	NYMEX WTI	$	58.65
January - December 2020	2,000 Bbls	NYMEX WTI	$	60.00
January - December 2020	2,000 Bbls	NYMEX WTI	$	58.05

July - December 2020	2,000 Bbls	NYMEX WTI	$	58.10
January - December 2021	8,000 Bbls	NYMEX WTI	$	37.00

The Company’s fair value of derivative contracts was a net liability of $707,647 as of September 30, 2020, and a net asset of $2,494,144 as of September 30, 2019. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations. Cash receipts in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods.

	For the Year Ended September 30,
	2020			2019			2018
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	28,510		$	(191,200	)	$	451,700
Natural gas fixed price swaps		1,687,600			817,160			748,125
Oil costless collars		1,011,472			(169,256	)		(822,893	)
Oil fixed price swaps		1,381,628			(259,719	)		(1,378,825	)
Cash received (paid) on derivative contracts, net	$	4,109,210		$	196,985		$	(1,001,893	)
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(706,015	)	$	10,453		$	(222,337	)
Natural gas fixed price swaps		(1,535,122	)		1,350,909			(425,865	)
Oil costless collars		(538,022	)		1,687,685			(1,026,163	)
Oil fixed price swaps		(422,632	)		2,859,113			(2,255,810	)
Non-cash gain (loss) on derivative contracts, net	$	(3,201,791	)	$	5,908,160		$	(3,930,175	)
Gains (losses) on derivative contracts, net	$	907,419		$	6,105,145		$	(4,932,068	)

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, 2020, and September 30, 2019. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2020, and September 30, 2019.

	9/30/2020								9/30/2019
	Fair Value								Fair Value
	Commodity Contracts								Commodity Contracts
	Current  Assets			Current Liabilities			Non-Current Liabilities		Current  Assets		Non-Current Assets
Gross amounts recognized	$	864,466		$	1,146,408		$	425,705	$	2,256,639	$	237,505
Offsetting adjustments		(864,466	)		(864,466	)		-		-		-
Net presentation on Balance Sheets	$	-		$	281,942		$	425,705	$	2,256,639	$	237,505

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.

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Fair Value Measurements

12 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

13. 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 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, 2020
	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	$	-	$	(64,801	)	$	-	$	(64,801	)
Derivative Contracts - Collars	$	-	$	(642,846	)	$	-	$	(642,846	)

	Fair Value Measurement at September 30, 2019
	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	$	-	$	1,892,954	$	-	$	1,892,954
Derivative Contracts - Collars	$	-	$	601,190	$	-	$	601,190

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,
	2020				2019				2018
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	5,288,710	$	29,315,807	$	9,101,032	$	76,824,337	$	-	$	-

^{(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 natural gas, oil and NGL 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. This table excludes $588,721 of impairments on properties that were written off during 2020.}

At September 30, 2020, and September 30, 2019, 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 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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Information On Natural Gas And Oil Producing Activities

12 Months Ended

Sep. 30, 2020

Oil And Gas Exploration And Production Industries Disclosures [Abstract]

Information On Natural Gas And Oil Producing Activities

14. INFORMATION ON NATURAL GAS AND OIL PRODUCING ACTIVITIES

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

The following table shows sales, by percentage, through various operators/purchasers during 2020, 2019 and 2018.

	2020			2019			2018
Company A		23	%		23	%		24	%
Company B		6	%		8	%		16	%
Company C		5	%		8	%		11	%

The loss of any of these major purchasers of natural gas, oil and NGL production could have a material adverse effect on the ability of the Company to produce and sell its natural gas, oil and NGL production.

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Subsequent Events

12 Months Ended

Sep. 30, 2020

Subsequent Events [Abstract]

Subsequent Events

15. SUBSEQUENT EVENTS

Name Change

Effective October 8, 2020, the Company officially changed its name to PHX Minerals Inc. to more accurately reflect its business strategy.

Acquisitions

On October 8, 2020, the Company closed on the purchase of 297 net royalty acres in Grady County, Oklahoma, and 257 net mineral acres and 12 net royalty acres in Harrison, Panola and Nacogdoches Counties, Texas, for a purchase price of $5.5 million and 153,375 shares of PHX common stock. This purchase was largely funded with cash from the common stock offering that closed on September 1, 2020.

On November 12, 2020, the Company closed on the purchase of 134 net mineral acres in San Augustine County, Texas for a purchase price of $750,000.

On December 4, 2020, the Company signed a purchase and sale agreement to purchase an additional 87 net mineral acres in San Augustine County, Texas for a purchase price of $1 million, subject to customary closing adjustments. The Company expects this acquisition to close in the first fiscal quarter of 2021.

Borrowing Base Redetermination

The Eighth Amendment to the Credit Facility was signed on December 4, 2020.  This amendment reduced the Quarterly Commitment Reductions from $1,000,000 to $600,000, reduced the consolidated cash balance in the anti-cash hoarding provision

from $2,000,000 to $1,000,000, and changed the debt to EBITDA ratio from 4.0:1.00 to 3.50:1.00. The borrowing base after Quarterly Commitment Reductions was reaffirmed at $30,000,000.

Derivative Contracts

Subsequent to September 30, 2020, the Company entered into new derivative contracts as summarized in the table below:

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
August 2021 - July 2022	100,000 Mmbtu	NYMEX Henry Hub	$2.50 floor / $3.17 ceiling
February - June 2022	100,000 Mmbtu	NYMEX Henry Hub	$2.50 floor / $3.15 ceiling
Oil costless collars
August 2021 - July 2022	1,500 Bbls	NYMEX WTI	$37.00 floor / $47.10 ceiling
Oil fixed price swaps
February - June 2022	4,000 Bbls	NYMEX WTI	$	39.51
July - December 2022	1,500 Bbls	NYMEX WTI	$	39.51
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.78
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.50
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.05

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Supplementary Information On Natural Gas, Oil And NGL Reserves

12 Months Ended

Sep. 30, 2020

Extractive Industries [Abstract]

Supplementary Information On Natural Gas, Oil And NGL Reserves

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

Aggregate Capitalized Costs

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

	2020			2019
Producing properties	$	324,886,491		$	354,718,398
Non-producing minerals		18,808,689			14,413,899
Non-producing leasehold		185,125			185,124
		343,880,305			369,317,421
Accumulated depreciation, depletion and amortization		(263,277,422	)		(258,063,849	)
Net capitalized costs	$	80,602,883		$	111,253,572

Costs Incurred

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

	2020		2019		2018
Property acquisition costs	$	10,453,119	$	6,235,905	$	11,409,673
Exploration costs		-		-		-
Development costs		273,825		3,012,095		10,291,476
	$	10,726,944	$	9,248,000	$	21,701,149

Estimated Quantities of Proved Natural Gas, Oil and NGL Reserves

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

Proved natural gas and oil reserves are those quantities of natural gas and oil 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. 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 natural gas or oil 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, prepared the Company’s natural gas, oil and NGL reserves estimates as of September 30, 2020, 2019 and 2018.

The Company’s net proved natural gas, oil and NGL reserves, which are located in the contiguous United States, as of September 30, 2020, 2019 and 2018, 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, Minerals Operations, Freda Webb. 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 40 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, Minerals 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, gas and oil production, well test data, commodity prices, operating costs, 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.

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers (SPE) entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. 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. Based on the current stage of field development, production performance, development plans and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The 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 the Company its intention to drill.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. These analyses were 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 effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

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 natural gas, oil and NGL reserves are summarized as follows:

	Proved Reserves
	Natural Gas			Oil			NGL			Total
	(Mcf)			(Barrels)			(Barrels)			Bcfe
September 30, 2017		121,195,120			5,509,667			2,384,699			168.6
Revisions of previous estimates		(29,247	)		(1,407,995	)		303,728			(6.7	)
Acquisitions (divestitures)		(1,782,949	)		236,690			24,765			(0.2	)
Extensions, discoveries and other additions		9,400,374			1,982,624			476,174			24.2
Production		(8,721,262	)		(336,564	)		(255,176	)		(12.3	)
September 30, 2018		120,062,036			5,984,422			2,934,190			173.6
Revisions of previous estimates		(35,644,135	)		(3,266,351	)		(890,046	)		(60.6	)
Acquisitions (divestitures)		(948,496	)		(322,023	)		(18,881	)		(3.0	)
Extensions, discoveries and other additions		3,891,262			313,241			164,276			6.8
Production		(7,086,761	)		(329,199	)		(216,259	)		(10.4	)
September 30, 2019		80,273,906			2,380,090			1,973,280			106.4
Revisions of previous estimates		(34,666,426	)		(1,094,923	)		(774,214	)		(45.9	)
Acquisitions (divestitures)		911,853			57,721			70,933			1.7
Extensions, discoveries and other additions		1,816,144			260,555			118,480			4.1
Production		(5,962,704	)		(269,786	)		(168,622	)		(8.6	)
September 30, 2020		42,372,773			1,333,657			1,219,857			57.7

The prices used to calculate reserves and future cash flows from reserves for natural gas, oil and NGL, respectively, were as follows: September 30, 2020 - $1.62/Mcf, $40.18/Bbl, $9.95/Bbl; September 30, 2019 - $2.48/Mcf, $54.40/Bbl, $19.30/Bbl; September 30, 2018 - $2.56/Mcf, $62.86/Bbl, $26.13/Bbl.

The revisions of previous estimates from 2019 to 2020 were primarily the result of:

• Negative pricing revisions of 35.8 Bcfe due to natural gas and oil wells reaching their economic limits earlier than was projected in 2019 due lower gas and oil prices and decreased operator activity in 2019 and a change in strategy to remove PUD locations not permitted, in progress, or drilled and uncompleted (DUC); proved developed revisions of 20.4 Bcfe and PUD revisions of 15.4 Bcfe.

• Negative revisions of 10.1 Bcfe. Proved developed negative revisions of 8.7 Bcfe were the result of lower performance of high-interest Woodford natural gas wells in the STACK and Arkoma Stack in Oklahoma and, to a lesser extent, lower performance of the Eagle Ford Shale oil properties in southern Texas. Proved undeveloped revisions were negative 1.4 Bcfe, due to changes to scheduled first production date, expected performance, costs and other reserve parameters.

Acquisitions and divestitures were the result of:

• The acquisition of 2.4 Bcfe, predominately in the active drilling program of the Woodford and Mississippian in the SCOOP and STACK plays in Oklahoma and the Bakken in North Dakota, of which 1.1 Bcfe were proved developed and 1.3 Bcfe were proved undeveloped.

• The sale of 0.7 Bcfe, predominately in the Permian Basin in New Mexico, of which 0.2 Bcfe were proved developed and 0.5 Bcfe were proved undeveloped.

Extensions, discoveries and other additions from 2019 to 2020 are principally attributable to:

• Proved developed reserve extensions, discoveries and other additions of 4.1 Bcfe, of which 1.7 Bcfe were proved developed and 2.4 Bcfe were proved undeveloped reserves, resulting from:

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

b) The Company’s royalty interest ownership in ongoing development of unconventional natural gas, oil and NGL 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 unconventional natural gas, oil and NGL utilizing horizontal drilling in the Bakken Shale in North Dakota.

Production of 8.6 Bcfe from the Company’s natural gas and oil properties.

	Proved Developed Reserves						Proved Undeveloped Reserves
	Natural Gas		Oil		NGL		Natural Gas		Oil		NGL
	(Mcf)		(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)
September 30, 2018		83,151,954		2,334,587		2,085,706		36,910,082		3,649,835		848,484
September 30, 2019		67,713,193		1,863,096		1,747,242		12,560,713		516,994		226,038
September 30, 2020		40,924,083		1,148,989		1,135,864		1,448,690		184,668		83,993

The following details the changes in proved undeveloped reserves for 2020 (Mcfe):

Beginning proved undeveloped reserves	17,018,905
Proved undeveloped reserves transferred to proved developed	(399,894	)
Revisions	(16,767,540	)
Extensions and discoveries	2,405,590
Sales	(479,415	)
Purchases	1,283,010
Ending proved undeveloped reserves	3,060,656

For the fiscal year ending September 30, 2020, our beginning PUD reserves were 17.0 Bcfe. Total net PUD reserves decreased by 14.0 Bcfe, as compared to September 30, 2019. In 2020, a total of 0.4 Bcfe (2% of the beginning balance) was transferred to proved developed. The remaining 13.6 Bcfe (80% of the beginning balance) of negative revisions to PUD reserves consist of  (i) pricing revisions of -15.4 Bcfe resulting from the impact of COVID-19 and reduced pricing leading to an unprecedented decrease in operator activity in 2020, and a decision to remove PUD locations not permitted, in progress, or drilled and uncompleted (DUC), (ii) sales and performance revisions of -1.8 Bcfe, and (iii) purchases and extensions of  3.6 Bcfe. 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 2.4 Bcfe of PUD reserves in 2020 within the active drilling program areas of (i) STACK Meramec and Woodford in western Oklahoma, (ii) the SCOOP Woodford Shale in western Oklahoma’s Anadarko Basin, (iii) the Arkoma Stack in eastern Oklahoma, (iv) the Bakken in North Dakota. These additions result from continuing development and additional well performance data in each of the referenced plays. Additionally, the Company purchased 1.3 Bcfe in the STACK Meramec and Woodford in Oklahoma and sold 0.5 Bcfe, predominately in the Permian Basin in New Mexico.

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

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

	2020			2019			2018
Future cash inflows	$	134,179,216		$	366,697,321		$	759,899,074
Future production costs		(66,136,222	)		(153,935,373	)		(259,413,766	)
Future development and asset retirement costs		(1,957,225	)		(1,917,937	)		(89,518,449	)
Future income tax expense		(13,224,535	)		(47,788,416	)		(95,872,182	)
Future net cash flows		52,861,234			163,055,595			315,094,677
10% annual discount		(21,727,081	)		(77,494,066	)		(158,768,823	)
Standardized measure of discounted future net    cash flows	$	31,134,153		$	85,561,529		$	156,325,854

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

	2020			2019			2018
Beginning of year	$	85,561,529		$	156,325,854		$	80,832,575
Changes resulting from:
Sales of natural gas, oil and NGL, net of    production costs		(12,692,681	)		(25,072,122	)		(32,836,007	)
Net change in sales prices and production costs		(46,499,344	)		(76,588,460	)		47,533,281
Net change in future development and asset    retirement costs		(20,571	)		43,607,535			1,580,942
Extensions and discoveries		2,841,807			7,074,245			34,667,557
Revisions of quantity estimates		(28,332,653	)		(60,308,497	)		(8,391,223	)
Acquisitions (divestitures) of reserves-in-place		1,169,819			(3,134,783	)		(307,472	)
Accretion of discount		11,039,792			20,457,930			12,602,209
Net change in income taxes		17,037,980			23,413,194			(3,057,128	)
Change in timing and other, net		1,028,475			(213,367	)		23,701,120
Net change		(54,427,376	)		(70,764,325	)		75,493,279
End of year	$	31,134,153		$	85,561,529		$	156,325,854

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Quarterly Results Of Operations (Unaudited)

12 Months Ended

Sep. 30, 2020

Quarterly Financial Information Disclosure [Abstract]

Quarterly Results Of Operations

17. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

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

	Fiscal 2020
	Quarter Ended
	December 31		March 31			June 30			September 30
Revenues	$	10,576,531	$	11,311,287		$	2,705,383		$	4,372,618
Income (loss) before provision for    income taxes	$	2,146,114	$	(27,441,814	)	$	(4,433,155	)	$	(2,512,182	)
Net income (loss)	$	1,892,114	$	(20,454,814	)	$	(3,555,215	)	$	(1,834,122	)
Earnings (loss) per share	$	0.11	$	(1.24	)	$	(0.21	)	$	(0.07	)
	Fiscal 2019
	Quarter Ended
	December 31		March 31			June 30			September 30
Revenues	$	26,328,994	$	7,636,213		$	16,342,394		$	15,728,084
Income (loss) before provision for    income taxes	$	16,306,940	$	(2,061,334	)	$	5,919,236		$	(74,390,780	)
Net income (loss)	$	12,735,940	$	(1,931,334	)	$	4,604,236		$	(56,153,780	)
Earnings (loss) per share	$	0.75	$	(0.11	)	$	0.28		$	(3.35	)

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Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Nature Of Business

Nature of Business

The Company’s principal line of business is maximizing the value of its existing mineral and royalty assets through active management and expanding its asset base through acquisitions of additional mineral and royalty interests.  The Company owns mineral and leasehold properties and other natural gas and oil interests, which are all located in the contiguous United States, primarily in Oklahoma, Texas, North Dakota, Arkansas and New Mexico, with properties located in several other states. The Company’s natural gas, oil and NGL production is from interests in 6,510 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 44%, 48% and 8% of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in 2020. Approximately 69%, 19% and 12% of the Company’s total sales volumes in 2020 were derived from natural gas, oil and NGL, respectively. Substantially all the Company’s natural gas, oil and NGL production is sold through the operators of the wells. From time to time, the Company sells certain non-material, non-core or small-interest natural gas and oil 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 natural gas, crude oil and NGL 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 natural gas, crude oil and NGL 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 natural gas, crude oil and NGL prices as estimated by management are used. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Management uses projected future natural gas, crude oil and NGL pricing assumptions to prepare estimates of natural gas, crude oil and NGL reserves used in formulating management’s overall operating decisions.

As a non-operator, the Company receives actual natural gas, oil and NGL sales volumes and prices more than a month after the information is available to the operators of the wells. Because of the delay in information on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, as well as public and private sources, and natural gas, oil and NGL 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 natural gas, oil and NGL 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 natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.

Basis Of Presentation

Basis of Presentation

Certain amounts (lease operating expenses and transportation, gathering and marketing in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation.

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.

Natural Gas, Oil and NGL Sales

Natural Gas, Oil and NGL Sales

The Company sells natural gas, oil and NGL to various customers, recognizing revenues as natural gas, oil and NGL is produced and sold.

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 natural gas, oil and NGL or operators of the natural gas and oil properties. Natural gas, oil and NGL 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 natural gas, oil and NGL 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 2020, 2019 and 2018 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.

Natural Gas and Oil Producing Activities

Natural Gas and Oil Producing Activities

The Company follows the successful efforts method of accounting for natural gas and oil 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. Natural gas and oil mineral and leasehold costs are capitalized when incurred. 

Leasing Of Mineral Rights

Leasing of Mineral Rights

The Company generates lease bonuses by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances 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 income. 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 utilizes derivative contracts to reduce its exposure to short-term fluctuations in the price of natural gas and oil. These derivates are recorded at fair value on the balance sheet. The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges.

Depreciation, Depletion and Amortization

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization of the costs of producing natural gas and oil 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. Leasehold 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 natural gas and oil properties include non-producing minerals, which had a net book value of $13,556,020 and $9,673,787 at September 30, 2020 and 2019, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Oklahoma, Texas, North Dakota, Arkansas and New Mexico. As mentioned, these mineral rights are perpetual and have been accumulated over the 94-year life of the Company. There are approximately 190,990 net acres of non-producing minerals in more than 6,380 tracts owned by the Company. An average tract contains approximately 30 acres and the average cost per acre is $71. Since inception, the Company has continually generated an interest in several thousand natural gas and oil 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 (unlike natural gas and oil 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 Company’s mineral ownership consists 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 (by mineral deed).

When a new well is drilled on the Company’s mineral acreage, all of the non-producing mineral costs for the associated mineral deed are transferred to producing minerals and are amortized straight-line over a 20-year period (insignificant fields are amortized over 10-year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on the Company’s minerals, and future development will deplete these assets over a long period. Given that we are moving all of the costs to the first new well drilled on each mineral deed, we believe that a straight-line amortization over a 20-year period is appropriate, as these wells and future development will deplete these assets over a fairly long period.

Capitalized Interest

Capitalized Interest

During 2020, 2019 and 2018, interest of $0, $38,606 and $89,023, respectively, was included in the Company’s capital expenditures. Interest of $1,286,788, $1,995,789 and $1,748,101, 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.

Accrued Liabilities

Accrued Liabilities

The following table shows the balances for the years ended September 30, 2020 and 2019, relating to the Company’s accrued liabilities:

	Year Ended September 30,
	2020		2019
Accrued compensation	$	481,062	$	1,446,710
Revenues payable		281,380		396,954
Accrued ad valorem		228,010		260,550
Other		306,911		329,252
Total accrued liabilities	$	1,297,363	$	2,433,466

The decrease in accrued compensation from 2019 to 2020 is primarily due to the one-time severance with the Company’s former CEO of approximately $670,000 upon his resignation at the end of fiscal 2019 as well as lower performance-related compensation in 2020.

Asset Retirement Obligations

Asset Retirement Obligations

The Company owns interests in natural gas and oil 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 asset retirement obligations.

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 the Company being responsible for its proportionate share of the costs involved (on working interest wells only). The Company 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, 2020 and 2019, 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 (time-based), subject to certain share price performance standards (market-based) or subject to company performance standards (performance-based). Restricted stock awards to the non-employee directors provide for annual 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 reduced the U.S. federal corporate tax rate from 35% to 21%. As of September 30, 2018, we completed our estimates accounting for the tax effects of the Act. Based on these estimates, we recognized an amount which was included as a component of income tax expense (benefit) from continuing operations in 2018.

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 in 2018 was $12,464,000 income tax benefit.

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, 2019, was a 25% benefit, as compared to a 26% benefit for the year ended September 30, 2020.

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 2017.

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, 2020, 2019 and 2018, the Company’s interest and penalties were not material. The Company does not believe it has any material uncertain tax positions.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Standard	Description	Date of Adoption	Impact on Financial Statements or Other Significant Matters
Adoption of New Accounting Pronouncements
ASU 2016-02, Leases (Topic 842)	This update will supersede the lease requirements in Topic 840, Leases, by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet.	Q1 2020	See Note 2: Leases for further details related the Company’s adoption of this standard.
ASU 2018-11, Leases (Topic 842), Targeted Improvements and ASC 842	This update will allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the financial statements, and will allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if any, rather than in the earliest period presented.	Q1 2020	See Note 2: Leases for further details related the Company’s adoption of this standard.
New Accounting Pronouncements yet to be Adopted
ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.	This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost.	Q1 2021	The standard is effective for interim and annual periods beginning after December 15, 2019, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company evaluated the new standard and determined the impact to not be material. Historically, the Company's credit losses on natural gas, oil and NGL sales receivables have been immaterial.

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, 2020

Accounting Policies [Abstract]

Summary Of Accrued Liabilities

The following table shows the balances for the years ended September 30, 2020 and 2019, relating to the Company’s accrued liabilities:

	Year Ended September 30,
	2020		2019
Accrued compensation	$	481,062	$	1,446,710
Revenues payable		281,380		396,954
Accrued ad valorem		228,010		260,550
Other		306,911		329,252
Total accrued liabilities	$	1,297,363	$	2,433,466

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Leases and Commitments (Tables)

12 Months Ended

Sep. 30, 2020

Leases [Abstract]

Maturities of Operating Lease Liabilities

The following table represents the maturities of the operating lease liabilities as of September 30, 2020:

2021	$	166,744
2022		166,744
2023		167,475
2024		175,520
2025		176,251
Thereafter		353,234
Total lease payments	$	1,205,968
Less: Imputed interest		(157,235	)
Total	$	1,048,733

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Revenues (Tables)

12 Months Ended

Sep. 30, 2020

Revenue From Contract With Customer [Abstract]

Summary of Disaggregation of Natural Gas, Oil and NGL Revenues

The following table presents the disaggregation of the Company's natural gas, oil and NGL revenues for the year ended September 30, 2020.

	Year Ended September 30, 2020
	Royalty Interest		Working Interest		Total
Natural gas revenue	$	3,987,660	$	6,268,094	$	10,255,754
Oil revenue		5,691,837		5,496,533		11,188,370
NGL revenue		776,426		1,149,453		1,925,879
Natural gas, oil and NGL sales	$	10,455,923	$	12,914,080	$	23,370,003

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Income Taxes (Tables)

12 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

Summary Of Provision (Benefit) For Income Taxes

	2020			2019			2018
Current:
Federal	$	(3,642,000	)	$	(1,388,000	)	$	204,000
State		-			19,000			20,000
		(3,642,000	)		(1,369,000	)		224,000
Deferred:
Federal		(3,611,000	)		(9,763,000	)		(13,240,000	)
State		(1,036,000	)		(2,349,000	)		277,000
		(4,647,000	)		(12,112,000	)		(12,963,000	)
	$	(8,289,000	)	$	(13,481,000	)	$	(12,739,000	)

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

	2020			2019			2018
Provision (benefit) for income taxes at statutory rate	$	(6,765,705	)	$	(11,387,447	)	$	465,253
Percentage depletion		(258,300	)		(431,340	)		(577,780	)
State income taxes, net of federal provision (benefit)		(939,310	)		(1,986,850	)		36,980
Effect of NOL Carryback Rate		(610,803	)		-			-
State NOL Valuation Allowance		96,000			-			-
Restricted stock tax benefit		58,000			185,000			(69,000	)
Deferred directors’ compensation benefit		79,000			(38,000	)		(134,000	)
Law change (a)		-			-			(12,464,000	)
Other		52,118			177,637			3,547
	$	(8,289,000	)	$	(13,481,000	)	$	(12,739,000	)

(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

	2020		2019
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible    drilling costs capitalized for financial purposes and    expensed for tax purposes	$	3,880,307	$	8,885,776
Derivative contracts		-		619,392
		3,880,307		9,505,168
Deferred tax assets:
State net operating loss carry forwards, net of valuation allowance		391,193		431,977
Federal net operating loss carry forwards		369,523		-
Statutory depletion carryover		346,414		85,680
AMT credit carry forwards		-		1,387,042
Asset retirement obligations		499,708		459,810
Deferred directors' compensation		436,225		602,394
Restricted stock expense		220,301		119,697
Derivative contracts		176,963		-
Business interest limitation		-		358,110
Other		110,973		84,451
		2,551,300		3,529,161
Net deferred tax liabilities	$	1,329,007	$	5,976,007

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Earnings (Loss) Per Share (Tables)

12 Months Ended

Sep. 30, 2020

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,
	2020			2019			2018
Numerator for basic and diluted earnings (loss) per share:
Net income (loss)	$	(23,952,037	)	$	(40,744,938	)	$	14,635,669
Denominator for basic and diluted earnings per share:
Weighted average shares (including for 2020, 2019    and 2018, unissued, vested directors' shares of    154,142, 168,586 and 205,736, respectively)		17,010,934			16,743,746			16,952,664

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Employee Stock Ownership Plan (Tables)

12 Months Ended

Sep. 30, 2020

Share Based Arrangements To Obtain Goods And Services [Abstract]

Summary Of Plan Contributions

Year	Shares		Amount
2020		72,101	$	103,104
2019		26,629	$	372,274
2018		20,632	$	382,174

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Restricted Stock Plan (Tables)

12 Months Ended

Sep. 30, 2020

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, 2020, 2019 and 2018, related to the Company’s market-based, time-based and performance-based restricted stock:

	Year Ended September 30,
	2020		2019		2018
Market-based, restricted stock	$	295,397	$	367,091	$	276,272
Time-based, restricted stock		448,500		404,706		379,142
Performance-based, restricted stock		-		-		-
Total compensation expense	$	743,897	$	771,797	$	655,414

Summary Of Unrecognized Compensation Cost

A summary of the Company’s unrecognized compensation cost for its unvested market-based, time-based and 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 Average Period (in years)
Market-based, restricted stock	$	67,653		1.83
Time-based, restricted stock		562,829		1.97
Performance-based, restricted stock		-
Total	$	630,482

Summary Of Status And Changes In Unvested Shares Of Restricted Stock Awards

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

	Market-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Time-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Performance-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value
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		-		$	-
Granted		43,287			8.24		27,978			15.61		-			-
Vested		-			-		(24,785	)		18.30		-			-
Forfeited		(89,321	)		10.08		(13,153	)		18.23		-			-
Unvested shares as of September 30,    2019		46,670		$	10.21		18,707		$	17.54		-		$	-
Granted		39,579			8.83		102,154			9.21		39,579			-
Vested		-			-		(20,410	)		13.35		-			-
Forfeited		(24,779	)		11.34		(9,929	)		13.93		(4,765	)		-
Unvested shares as of September 30,    2020		61,470		$	8.87		90,522		$	9.49		34,814		$	-

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Properties And Equipment (Tables)

12 Months Ended

Sep. 30, 2020

Property Plant And Equipment [Abstract]

Schedule of Asset Retirement Obligations

The following table shows the activity for the years ended September 30, 2020 and 2019, relating to the Company’s asset retirement obligations:

	2020			2019
Asset retirement obligations as of beginning of the year	$	2,835,781		$	2,809,378
Wells acquired or drilled		4			27,783
Wells sold or plugged		(68,668	)		(134,090	)
Accretion of discount		130,405			132,710
Asset retirement obligations as of end of the year	$	2,897,522		$	2,835,781

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Derivatives (Tables)

12 Months Ended

Sep. 30, 2020

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of September 30, 2020

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - October 2020	10,000 Mmbtu	NYMEX Henry Hub	$2.20 floor / $2.59 ceiling
November 2020 - December 2021	50,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.90 ceiling
November 2020 - December 2021	40,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2020	26,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
December 2020	28,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
January 2021	32,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
February 2021	25,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
March 2021	30,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
April 2021	31,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
May 2021	32,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
June 2021	30,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
July 2021	31,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
August 2021	12,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
September 2021	11,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
October 2021	9,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
November 2021	8,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
December 2021	10,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
January 2022	25,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
November - December 2020	53,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
January 2021	72,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
February 2021	48,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
March 2021	61,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
April 2021	63,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
May 2021	69,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
June 2021	61,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
July 2021	83,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
August - September 2021	27,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
October 2021	20,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2021	14,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
December 2021	4,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
January 2022	77,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2020	54,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
December 2020	55,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
January 2021	64,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
February 2021	52,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
March - April 2021	62,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
May 2021	66,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
June 2021	60,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
July 2021	64,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
August 2021	24,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
September 2021	18,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
October 2021	19,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
November - December 2021	20,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
January - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas fixed price swaps
January - December 2020	80,000 Mmbtu	NYMEX Henry Hub	$	2.750
April - October 2020	10,000 Mmbtu	NYMEX Henry Hub	$	2.405
November 2020 - March 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.661
January 2021 - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$	2.729
January 2021 - December 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.765
November 2020	26,500 Mmbtu	NYMEX Henry Hub	$	2.582
December 2020	28,000 Mmbtu	NYMEX Henry Hub	$	2.582
January 2021	32,000 Mmbtu	NYMEX Henry Hub	$	2.582
February 2021	25,500 Mmbtu	NYMEX Henry Hub	$	2.582
March 2021	30,500 Mmbtu	NYMEX Henry Hub	$	2.582
April 2021	31,500 Mmbtu	NYMEX Henry Hub	$	2.582
May 2021	32,500 Mmbtu	NYMEX Henry Hub	$	2.582
June 2021	30,500 Mmbtu	NYMEX Henry Hub	$	2.582
July 2021	31,500 Mmbtu	NYMEX Henry Hub	$	2.582
August 2021	12,500 Mmbtu	NYMEX Henry Hub	$	2.582
September 2021	11,000 Mmbtu	NYMEX Henry Hub	$	2.582
October 2021	9,000 Mmbtu	NYMEX Henry Hub	$	2.582
November 2021	8,000 Mmbtu	NYMEX Henry Hub	$	2.582
December 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.582
January 2022	25,500 Mmbtu	NYMEX Henry Hub	$	2.582
Oil costless collars
January - December 2020	2,000 Bbls	NYMEX WTI	$55.00 floor / $62.00 ceiling
August - October 2020	1,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
November - December 2020	500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
January 2021	2,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
February 2021	1,500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
March - July 2021	2,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
January 2022	2,500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
August - October 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
November - December 2020	500 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
January - July 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
August - September 2021	500 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
January 2022	3,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
August 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
September - November 2020	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
December 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 2021	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 2021	1,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
March - April 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
May 2021	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
June - July 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
August 2021	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 2022	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 2022	5,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
Oil fixed price swaps
January - December 2020	2,000 Bbls	NYMEX WTI	$	55.28
January - December 2020	2,000 Bbls	NYMEX WTI	$	58.65
January - December 2020	2,000 Bbls	NYMEX WTI	$	60.00
January - December 2020	2,000 Bbls	NYMEX WTI	$	58.05

July - December 2020	2,000 Bbls	NYMEX WTI	$	58.10
January - December 2021	8,000 Bbls	NYMEX WTI	$	37.00

Subsequent to September 30, 2020, the Company entered into new derivative contracts as summarized in the table below:

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
August 2021 - July 2022	100,000 Mmbtu	NYMEX Henry Hub	$2.50 floor / $3.17 ceiling
February - June 2022	100,000 Mmbtu	NYMEX Henry Hub	$2.50 floor / $3.15 ceiling
Oil costless collars
August 2021 - July 2022	1,500 Bbls	NYMEX WTI	$37.00 floor / $47.10 ceiling
Oil fixed price swaps
February - June 2022	4,000 Bbls	NYMEX WTI	$	39.51
July - December 2022	1,500 Bbls	NYMEX WTI	$	39.51
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.78
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.50
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.05

Summary of Gain or Loss on Derivative Contracts, Net

Cash receipts in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods

	For the Year Ended September 30,
	2020			2019			2018
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	28,510		$	(191,200	)	$	451,700
Natural gas fixed price swaps		1,687,600			817,160			748,125
Oil costless collars		1,011,472			(169,256	)		(822,893	)
Oil fixed price swaps		1,381,628			(259,719	)		(1,378,825	)
Cash received (paid) on derivative contracts, net	$	4,109,210		$	196,985		$	(1,001,893	)
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(706,015	)	$	10,453		$	(222,337	)
Natural gas fixed price swaps		(1,535,122	)		1,350,909			(425,865	)
Oil costless collars		(538,022	)		1,687,685			(1,026,163	)
Oil fixed price swaps		(422,632	)		2,859,113			(2,255,810	)
Non-cash gain (loss) on derivative contracts, net	$	(3,201,791	)	$	5,908,160		$	(3,930,175	)
Gains (losses) on derivative contracts, net	$	907,419		$	6,105,145		$	(4,932,068	)

Summary Of Derivative Contracts

	9/30/2020								9/30/2019
	Fair Value								Fair Value
	Commodity Contracts								Commodity Contracts
	Current  Assets			Current Liabilities			Non-Current Liabilities		Current  Assets		Non-Current Assets
Gross amounts recognized	$	864,466		$	1,146,408		$	425,705	$	2,256,639	$	237,505
Offsetting adjustments		(864,466	)		(864,466	)		-		-		-
Net presentation on Balance Sheets	$	-		$	281,942		$	425,705	$	2,256,639	$	237,505

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Fair Value Measurements (Tables)

12 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

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, 2020
	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	$	-	$	(64,801	)	$	-	$	(64,801	)
Derivative Contracts - Collars	$	-	$	(642,846	)	$	-	$	(642,846	)

	Fair Value Measurement at September 30, 2019
	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	$	-	$	1,892,954	$	-	$	1,892,954
Derivative Contracts - Collars	$	-	$	601,190	$	-	$	601,190

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,
	2020				2019				2018
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	5,288,710	$	29,315,807	$	9,101,032	$	76,824,337	$	-	$	-

^{(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 natural gas, oil and NGL 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. This table excludes $588,721 of impairments on properties that were written off during 2020.}

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Information On Natural Gas And Oil Producing Activities (Tables)

12 Months Ended

Sep. 30, 2020

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 2020, 2019 and 2018.

	2020			2019			2018
Company A		23	%		23	%		24	%
Company B		6	%		8	%		16	%
Company C		5	%		8	%		11	%

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Subsequent Events (Tables)

12 Months Ended

Sep. 30, 2020

Subsequent Events [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of September 30, 2020

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - October 2020	10,000 Mmbtu	NYMEX Henry Hub	$2.20 floor / $2.59 ceiling
November 2020 - December 2021	50,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.90 ceiling
November 2020 - December 2021	40,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2020	26,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
December 2020	28,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
January 2021	32,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
February 2021	25,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
March 2021	30,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
April 2021	31,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
May 2021	32,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
June 2021	30,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
July 2021	31,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
August 2021	12,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
September 2021	11,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
October 2021	9,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
November 2021	8,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
December 2021	10,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
January 2022	25,500 Mmbtu	NYMEX Henry Hub	$2.30 floor / $2.85 ceiling
November - December 2020	53,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
January 2021	72,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
February 2021	48,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
March 2021	61,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
April 2021	63,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
May 2021	69,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
June 2021	61,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
July 2021	83,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
August - September 2021	27,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
October 2021	20,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2021	14,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
December 2021	4,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
January 2022	77,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.10 ceiling
November 2020	54,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
December 2020	55,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
January 2021	64,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
February 2021	52,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
March - April 2021	62,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
May 2021	66,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
June 2021	60,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
July 2021	64,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
August 2021	24,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
September 2021	18,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
October 2021	19,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
November - December 2021	20,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling
January - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$2.30 floor / $3.00 ceiling

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas fixed price swaps
January - December 2020	80,000 Mmbtu	NYMEX Henry Hub	$	2.750
April - October 2020	10,000 Mmbtu	NYMEX Henry Hub	$	2.405
November 2020 - March 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.661
January 2021 - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$	2.729
January 2021 - December 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.765
November 2020	26,500 Mmbtu	NYMEX Henry Hub	$	2.582
December 2020	28,000 Mmbtu	NYMEX Henry Hub	$	2.582
January 2021	32,000 Mmbtu	NYMEX Henry Hub	$	2.582
February 2021	25,500 Mmbtu	NYMEX Henry Hub	$	2.582
March 2021	30,500 Mmbtu	NYMEX Henry Hub	$	2.582
April 2021	31,500 Mmbtu	NYMEX Henry Hub	$	2.582
May 2021	32,500 Mmbtu	NYMEX Henry Hub	$	2.582
June 2021	30,500 Mmbtu	NYMEX Henry Hub	$	2.582
July 2021	31,500 Mmbtu	NYMEX Henry Hub	$	2.582
August 2021	12,500 Mmbtu	NYMEX Henry Hub	$	2.582
September 2021	11,000 Mmbtu	NYMEX Henry Hub	$	2.582
October 2021	9,000 Mmbtu	NYMEX Henry Hub	$	2.582
November 2021	8,000 Mmbtu	NYMEX Henry Hub	$	2.582
December 2021	10,000 Mmbtu	NYMEX Henry Hub	$	2.582
January 2022	25,500 Mmbtu	NYMEX Henry Hub	$	2.582
Oil costless collars
January - December 2020	2,000 Bbls	NYMEX WTI	$55.00 floor / $62.00 ceiling
August - October 2020	1,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
November - December 2020	500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
January 2021	2,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
February 2021	1,500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
March - July 2021	2,000 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
January 2022	2,500 Bbls	NYMEX WTI	$36.00 floor / $43.60 ceiling
August - October 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
November - December 2020	500 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
January - July 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
August - September 2021	500 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
January 2022	3,000 Bbls	NYMEX WTI	$37.00 floor / $44.50 ceiling
August 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
September - November 2020	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
December 2020	1,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 2021	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 2021	1,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
March - April 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
May 2021	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
June - July 2021	2,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
August 2021	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 2022	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 2022	5,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
Oil fixed price swaps
January - December 2020	2,000 Bbls	NYMEX WTI	$	55.28
January - December 2020	2,000 Bbls	NYMEX WTI	$	58.65
January - December 2020	2,000 Bbls	NYMEX WTI	$	60.00
January - December 2020	2,000 Bbls	NYMEX WTI	$	58.05

July - December 2020	2,000 Bbls	NYMEX WTI	$	58.10
January - December 2021	8,000 Bbls	NYMEX WTI	$	37.00

Subsequent to September 30, 2020, the Company entered into new derivative contracts as summarized in the table below:

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
August 2021 - July 2022	100,000 Mmbtu	NYMEX Henry Hub	$2.50 floor / $3.17 ceiling
February - June 2022	100,000 Mmbtu	NYMEX Henry Hub	$2.50 floor / $3.15 ceiling
Oil costless collars
August 2021 - July 2022	1,500 Bbls	NYMEX WTI	$37.00 floor / $47.10 ceiling
Oil fixed price swaps
February - June 2022	4,000 Bbls	NYMEX WTI	$	39.51
July - December 2022	1,500 Bbls	NYMEX WTI	$	39.51
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.78
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.50
March - December 2022	1,000 Bbls	NYMEX WTI	$	43.05

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

12 Months Ended

Sep. 30, 2020

Extractive Industries [Abstract]

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

	2020			2019
Producing properties	$	324,886,491		$	354,718,398
Non-producing minerals		18,808,689			14,413,899
Non-producing leasehold		185,125			185,124
		343,880,305			369,317,421
Accumulated depreciation, depletion and amortization		(263,277,422	)		(258,063,849	)
Net capitalized costs	$	80,602,883		$	111,253,572

Summary Of Costs Incurred In Natural Gas and Oil Producing Activities

	2020		2019		2018
Property acquisition costs	$	10,453,119	$	6,235,905	$	11,409,673
Exploration costs		-		-		-
Development costs		273,825		3,012,095		10,291,476
	$	10,726,944	$	9,248,000	$	21,701,149

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

	Proved Reserves
	Natural Gas			Oil			NGL			Total
	(Mcf)			(Barrels)			(Barrels)			Bcfe
September 30, 2017		121,195,120			5,509,667			2,384,699			168.6
Revisions of previous estimates		(29,247	)		(1,407,995	)		303,728			(6.7	)
Acquisitions (divestitures)		(1,782,949	)		236,690			24,765			(0.2	)
Extensions, discoveries and other additions		9,400,374			1,982,624			476,174			24.2
Production		(8,721,262	)		(336,564	)		(255,176	)		(12.3	)
September 30, 2018		120,062,036			5,984,422			2,934,190			173.6
Revisions of previous estimates		(35,644,135	)		(3,266,351	)		(890,046	)		(60.6	)
Acquisitions (divestitures)		(948,496	)		(322,023	)		(18,881	)		(3.0	)
Extensions, discoveries and other additions		3,891,262			313,241			164,276			6.8
Production		(7,086,761	)		(329,199	)		(216,259	)		(10.4	)
September 30, 2019		80,273,906			2,380,090			1,973,280			106.4
Revisions of previous estimates		(34,666,426	)		(1,094,923	)		(774,214	)		(45.9	)
Acquisitions (divestitures)		911,853			57,721			70,933			1.7
Extensions, discoveries and other additions		1,816,144			260,555			118,480			4.1
Production		(5,962,704	)		(269,786	)		(168,622	)		(8.6	)
September 30, 2020		42,372,773			1,333,657			1,219,857			57.7

Summary Of Proved Developed And Undeveloped Reserves

	Proved Developed Reserves						Proved Undeveloped Reserves
	Natural Gas		Oil		NGL		Natural Gas		Oil		NGL
	(Mcf)		(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)
September 30, 2018		83,151,954		2,334,587		2,085,706		36,910,082		3,649,835		848,484
September 30, 2019		67,713,193		1,863,096		1,747,242		12,560,713		516,994		226,038
September 30, 2020		40,924,083		1,148,989		1,135,864		1,448,690		184,668		83,993

Summary Of Proved Undeveloped Reserves

Beginning proved undeveloped reserves	17,018,905
Proved undeveloped reserves transferred to proved developed	(399,894	)
Revisions	(16,767,540	)
Extensions and discoveries	2,405,590
Sales	(479,415	)
Purchases	1,283,010
Ending proved undeveloped reserves	3,060,656

Summary Of Standardized Measure Of Discounted Future Net Cash Flows

	2020			2019			2018
Future cash inflows	$	134,179,216		$	366,697,321		$	759,899,074
Future production costs		(66,136,222	)		(153,935,373	)		(259,413,766	)
Future development and asset retirement costs		(1,957,225	)		(1,917,937	)		(89,518,449	)
Future income tax expense		(13,224,535	)		(47,788,416	)		(95,872,182	)
Future net cash flows		52,861,234			163,055,595			315,094,677
10% annual discount		(21,727,081	)		(77,494,066	)		(158,768,823	)
Standardized measure of discounted future net    cash flows	$	31,134,153		$	85,561,529		$	156,325,854

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

	2020			2019			2018
Beginning of year	$	85,561,529		$	156,325,854		$	80,832,575
Changes resulting from:
Sales of natural gas, oil and NGL, net of    production costs		(12,692,681	)		(25,072,122	)		(32,836,007	)
Net change in sales prices and production costs		(46,499,344	)		(76,588,460	)		47,533,281
Net change in future development and asset    retirement costs		(20,571	)		43,607,535			1,580,942
Extensions and discoveries		2,841,807			7,074,245			34,667,557
Revisions of quantity estimates		(28,332,653	)		(60,308,497	)		(8,391,223	)
Acquisitions (divestitures) of reserves-in-place		1,169,819			(3,134,783	)		(307,472	)
Accretion of discount		11,039,792			20,457,930			12,602,209
Net change in income taxes		17,037,980			23,413,194			(3,057,128	)
Change in timing and other, net		1,028,475			(213,367	)		23,701,120
Net change		(54,427,376	)		(70,764,325	)		75,493,279
End of year	$	31,134,153		$	85,561,529		$	156,325,854

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Quarterly Results Of Operations (Unaudited) (Tables)

12 Months Ended

Sep. 30, 2020

Quarterly Financial Information Disclosure [Abstract]

Summary Of The Company's Quarterly Results Of Operations

	Fiscal 2020
	Quarter Ended
	December 31		March 31			June 30			September 30
Revenues	$	10,576,531	$	11,311,287		$	2,705,383		$	4,372,618
Income (loss) before provision for    income taxes	$	2,146,114	$	(27,441,814	)	$	(4,433,155	)	$	(2,512,182	)
Net income (loss)	$	1,892,114	$	(20,454,814	)	$	(3,555,215	)	$	(1,834,122	)
Earnings (loss) per share	$	0.11	$	(1.24	)	$	(0.21	)	$	(0.07	)
	Fiscal 2019
	Quarter Ended
	December 31		March 31			June 30			September 30
Revenues	$	26,328,994	$	7,636,213		$	16,342,394		$	15,728,084
Income (loss) before provision for    income taxes	$	16,306,940	$	(2,061,334	)	$	5,919,236		$	(74,390,780	)
Net income (loss)	$	12,735,940	$	(1,931,334	)	$	4,604,236		$	(56,153,780	)
Earnings (loss) per share	$	0.75	$	(0.11	)	$	0.28		$	(3.35	)

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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	Sep. 30, 2020 USD ($) a Item $ / a	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of Oil, NGL and Natural Gas Production Units | Item			6,510
Oil, NGL and natural gas revenues were derived from the sale of natural gas			44.00%
Oil, NGL and natural gas revenues were derived from the sale of oil			48.00%
Oil, NGL and natural gas revenues were derived from the sale of NGL			8.00%
Bad debt expense			$ 0	$ 0	$ 0
Book value of Non-producing oil and natural gas			$ 13,556,020	9,673,787
Percentage of perpetual ownership of mineral interests in Oklahoma, North Dakota, Texas, Arkansas and New Mexico			91.00%
Accumulated period perpetual rights			94 years
Non Producing Minerals Area | a			190,990
Number of tracts owned | Item			6,380
Amount of acres average tract contains | a			30
Tracts Average Cost Per Acre | $ / a			71
Amortized Period of Non-producing Minerals			33 years
Straight-line amortized period of Producing Minerals			20 years
Straight-line amortized period of insignificant fields			10 years
Amount of Capitalized Interest Included in the Company's Capital Expenditures			$ 0	38,606	89,023
Interest Expense			$ 1,286,788	$ 1,995,789	1,748,101
U.S. federal corporate tax rate	35.00%	21.00%	21.00%
Remeasurement of deferred income tax benefit, amount					$ 12,464,000
Effective tax rate			(26.00%)	(25.00%)
One-time Severance [Member]
Summary Of Significant Accounting Policies [Line Items]
Decrease in accrued compensation				$ (670,000)
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] | Oil [Member]
Summary Of Significant Accounting Policies [Line Items]
Total sale volume from sale of Oil, NGL and Natural gas			19.00%
Sales Revenue, Net [Member] | Product Concentration Risk [Member] | NGL [Member]
Summary Of Significant Accounting Policies [Line Items]
Total sale volume from sale of Oil, NGL and Natural gas			12.00%
Sales Revenue, Net [Member] | Product Concentration Risk [Member] | Natural Gas [Member]
Summary Of Significant Accounting Policies [Line Items]
Total sale volume from sale of Oil, NGL and Natural gas			69.00%

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Summary Of Significant Accounting Policies (Summary Of Accrued Liabilities) (Details) - USD ($)	Sep. 30, 2020	Sep. 30, 2019
Payables And Accruals [Abstract]
Accrued compensation	$ 481,062	$ 1,446,710
Revenues payable	281,380	396,954
Accrued ad valorem	228,010	260,550
Other	306,911	329,252
Total accrued liabilities	$ 1,297,363	$ 2,433,466

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Leases and Commitments (Narrative) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2020	Sep. 30, 2020	Dec. 31, 2019
Lessee Lease Description [Line Items]
Maximum percentage of operating lease right use assets to assets			1.00%
Maximum percentage of operating lease obligations to assets			1.00%
Lease term for office space	7 years
Lease commencement date	2020-08
Lease liability		$ 1,048,733
ROU Asset		690,316
Other, Net [Member]
Lessee Lease Description [Line Items]
Lease incentive asset		$ 344,000

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Leases and Commitments - Maturities of Operating Lease Liabilities (Details)	Sep. 30, 2020 USD ($)
Operating Lease Liabilities Payments Due [Abstract]
2021	$ 166,744
2022	166,744
2023	167,475
2024	175,520
2025	176,251
Thereafter	353,234
Total lease payments	1,205,968
Less: Imputed interest	(157,235)
Total	$ 1,048,733

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Revenues (Summary Of Disaggregation Of Company's Natural Gas, Oil and NGL Revenues) (Details)	12 Months Ended
	Sep. 30, 2020 USD ($)
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	$ 23,370,003
Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	10,455,923
Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	12,914,080
Oil [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	11,188,370
Oil [Member] | Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	5,691,837
Oil [Member] | Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	5,496,533
NGL [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	1,925,879
NGL [Member] | Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	776,426
NGL [Member] | Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	1,149,453
Natural Gas [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	10,255,754
Natural Gas [Member] | Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	3,987,660
Natural Gas [Member] | Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Natural gas, oil and NGL sales	$ 6,268,094

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Revenues (Narrative) (Details)	12 Months Ended
	Sep. 30, 2020
Disaggregation Of Revenue [Line Items]
Revenue, practical expedient, financing component	true
Minimum [Member]
Disaggregation Of Revenue [Line Items]
New wells production statements period	30 days
Maximum [Member]
Disaggregation Of Revenue [Line Items]
New wells production statements period	90 days

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Income Taxes (Summary of Provision (Benefit) for Income Taxes) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Federal	$ (3,642,000)	$ (1,388,000)	$ 204,000
State		19,000	20,000
Current	(3,642,000)	(1,369,000)	224,000
Federal	(3,611,000)	(9,763,000)	(13,240,000)
State	(1,036,000)	(2,349,000)	277,000
Deferred	(4,647,000)	(12,112,000)	(12,963,000)
Provision (benefit) for income taxes	$ (8,289,000)	$ (13,481,000)	$ (12,739,000)

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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, 2020	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Provision (benefit) for income taxes at statutory rate		$ (6,765,705)	$ (11,387,447)	$ 465,253
Percentage depletion		(258,300)	(431,340)	(577,780)
State income taxes, net of federal provision (benefit)		(939,310)	(1,986,850)	36,980
Effect of NOL Carryback Rate		(610,803)
State NOL Valuation Allowance		96,000
Restricted stock tax benefit		58,000	185,000	(69,000)
Deferred directors’ compensation benefit		79,000	(38,000)	(134,000)
Law change	[1]			(12,464,000)
Other		52,118	177,637	3,547
Provision (benefit) for income taxes		$ (8,289,000)	$ (13,481,000)	$ (12,739,000)

[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, 2020
Income Tax Disclosure [Abstract]
U.S. federal corporate tax rate	35.00%	21.00%	21.00%

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Income Taxes (Summary of Deferred Tax Assets and Liabilities) (Details) - USD ($)	Sep. 30, 2020	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$ 3,880,307	$ 8,885,776
Derivative contracts		619,392
Total deferred tax liabilities	3,880,307	9,505,168
State net operating loss carry forwards, net of valuation allowance	391,193	431,977
Federal net operating loss carry forwards	369,523
Statutory depletion carryover	346,414	85,680
AMT credit carry forwards		1,387,042
Asset retirement obligations	499,708	459,810
Deferred directors' compensation	436,225	602,394
Restricted stock expense	220,301	119,697
Derivative contracts	176,963
Business interest limitation		358,110
Other	110,973	84,451
Total Deferred tax assets	2,551,300	3,529,161
Net deferred tax liabilities	$ 1,329,007	$ 5,976,007

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Income Taxes (Narrative) (Details) - USD ($)			3 Months Ended	12 Months Ended
	Jul. 28, 2020	Mar. 27, 2020	Jun. 30, 2020	Sep. 30, 2020	Sep. 30, 2019
Income Tax Contingency [Line Items]
Total Deferred tax assets				$ 2,551,300	$ 3,529,161
Tax receivable associated with carryback of net operating loss				3,805,227	$ 1,505,442
CARES Act [Member]
Income Tax Contingency [Line Items]
Net operating losses carryback term		5 years
Net operating losses carryback term start year		2018
Net operating losses carryback term end year		2020
Net operating losses carryback percentage.		80.00%
Net operating losses percentage of increase limitation on interest expense deductibility	50.00%	30.00%
Net operating losses carryback percentage of adjusted taxable income		50.00%
Total Deferred tax assets	$ 0
Refundable tax credit due to AMT credits			$ 1,400,000
Federal [Member]
Income Tax Contingency [Line Items]
Operating loss carry forwards valuation allowance				0
Federal [Member] | CARES Act [Member]
Income Tax Contingency [Line Items]
Tax receivable associated with carryback of net operating loss				2,200,000
Oklahoma [Member]
Income Tax Contingency [Line Items]
State net operating loss carry forwards				$ 350,543
Net operating loss carry forwards expiration period				2037
Operating loss carry forwards valuation allowance				$ 0
Arkansas [Member]
Income Tax Contingency [Line Items]
State net operating loss carry forwards				$ 95,611
Net operating loss carry forwards expiration period				2022
Operating loss carry forwards valuation allowance				$ 95,611

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Debt (Details) - USD ($)		12 Months Ended
	Jun. 24, 2020	Sep. 30, 2020	Jun. 23, 2020
Line Of Credit Facility [Line Items]
Short-term debt		$ 1,750,000
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving loan credit facility		200,000,000
Borrowing base of credit facility	$ 32,000,000	$ 31,000,000	$ 45,000,000
Credit facility maturity		Nov. 30, 2022
Effective Interest rate		4.25%
Debt issuance cost net of amortization		$ 246,724
Borrowing base of credit facility, quarterly reduction amount	$ 1,000,000
Borrowing base of credit facility, quarterly reduction term description		Quarterly Commitment Reduction, whereby the borrowing base is reduced by $1,000,000 each April 15, July 15, October 15 and January 15, commencing on July 15, 2020.
Funded debt to EBITDA ratio		400.00%
Credit facility outstanding amount		$ 28,750,000
Short-term debt		1,750,000
Availability under outstanding credit facility		$ 2,250,000
Revolving Credit Facility [Member] | Minimum [Member]
Line Of Credit Facility [Line Items]
Current ratio		100.00%
Revolving Credit Facility [Member] | Minimum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis		1.00%
Revolving Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis		2.50%
Revolving Credit Facility [Member] | Maximum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis		1.75%
Revolving Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis		3.25%

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Stockholders' Equity (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018	May 31, 2018
Equity, Class of Treasury Stock [Line Items]
Purchase of additional common stock authorized				$ 1,500,000
Purchase of treasury stock	$ 7,635	$ 7,454,000	$ 1,219,228
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	$ 7,635
Purchase of treasury stock, shares	632

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Earnings (Loss) Per Share (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Earnings Per Share [Abstract]
Net income (loss)	$ (1,834,122)	$ (3,555,215)	$ (20,454,814)	$ 1,892,114	$ (56,153,780)	$ 4,604,236	$ (1,931,334)	$ 12,735,940	$ (23,952,037)	$ (40,744,938)	$ 14,635,669
Denominator for basic and diluted earnings per share - Weighted average shares (including for 2020, 2019 and 2018, unissued, vested directors' shares of 154,142, 168.586 and 205.736, respectively)									17,010,934	16,743,746	16,952,664

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Earnings (Loss) Per Share (Parenthetical) (Details) - shares	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Earnings Per Share [Abstract]
Vested directors' shares	154,142	168,586	205,736

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Employee Stock Ownership Plan (Narrative) (Details)	12 Months Ended
	Sep. 30, 2020
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

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Employee Stock Ownership Plan (Summary Of Plan Contributions) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Share Based Arrangements To Obtain Goods And Services [Abstract]
Shares Contributed to the ESOP	72,101	26,629	20,632
Amount Contributed to the ESOP	$ 103,104	$ 372,274	$ 382,174

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Deferred Compensation Plan For Directors (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Deferred Compensation Plan For Directors [Line Items]
Number of shares credited to directors deferred fee account	177,678	179,226
Outstanding deferred balance	$ 1,874,007	$ 2,555,781
Total expenses charged to the company's results of operations	$ 228,408	$ 272,491	$ 301,715
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
	Mar. 09, 2020	Jan. 16, 2020	Jan. 02, 2020	Dec. 11, 2019	Sep. 30, 2020	Mar. 31, 2020	May 31, 2018	Mar. 31, 2014	Mar. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of vested shares					$ 85,306
Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period				3 years
Time-Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded	16,340	53,476		10,038
Fair value of shares awarded	$ 72,550	$ 500,000		$ 122,062
Time-Based Restricted Stock [Member] | Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded			22,300
Fair value of shares awarded			$ 246,640
Share based payment award vesting date			Dec. 31, 2020
Market-Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded	2,534	21,988		15,058
Fair value of shares awarded	$ 9,814	$ 179,334		$ 160,401
Performance Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded	2,534	37,045
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Repurchase of common stock authorized							$ 1,500,000
2010 Stock Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock authorized						750,000		500,000	200,000

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Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 743,897	$ 771,797	$ 655,414
Market-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	295,397	367,091	276,272
Time-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 448,500	$ 404,706	$ 379,142

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Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details)	12 Months Ended
	Sep. 30, 2020 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 630,482
Market-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 67,653
Weighted Average Period (in years)	1 year 9 months 29 days
Time-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 562,829
Weighted Average Period (in years)	1 year 11 months 19 days

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Restricted Stock Plan (Summary Of Changes In Unvested Shares Of Restricted Stock Awards) (Details) - $ / shares	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Market-Based Unvested Restricted Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares, Beginning balance	46,670	92,704	99,090
Unvested Restricted Shares, Granted	39,579	43,287	29,099
Unvested Restricted Shares, Vested			(35,485)
Unvested Restricted Shares, Forfeited	(24,779)	(89,321)
Unvested shares, Ending balance	61,470	46,670	92,704
Weighted Average Grant Date Fair Value, Beginning balance	$ 10.21	$ 11.00	$ 11.33
Weighted Average Grant Date Fair Value, Granted	8.83	8.24	11.34
Weighted Average Grant Date Fair Value, Vested			12.18
Weighted Average Grant Date Fair Value, Forfeited	11.34	10.08
Weighted Average Grant Date Fair Value, Ending balance	$ 8.87	$ 10.21	$ 11.00
Time-Based Unvested Restricted Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares, Beginning balance	18,707	28,667	24,997
Unvested Restricted Shares, Granted	102,154	27,978	19,918
Unvested Restricted Shares, Vested	(20,410)	(24,785)	(16,248)
Unvested Restricted Shares, Forfeited	(9,929)	(13,153)
Unvested shares, Ending balance	90,522	18,707	28,667
Weighted Average Grant Date Fair Value, Beginning balance	$ 17.54	$ 20.40	$ 19.41
Weighted Average Grant Date Fair Value, Granted	9.21	15.61	20.77
Weighted Average Grant Date Fair Value, Vested	13.35	18.30	19.34
Weighted Average Grant Date Fair Value, Forfeited	13.93	18.23
Weighted Average Grant Date Fair Value, Ending balance	$ 9.49	$ 17.54	$ 20.40
Performance Based Unvested Restricted Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested Restricted Shares, Granted	39,579
Unvested Restricted Shares, Forfeited	(4,765)
Unvested shares, Ending balance	34,814

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Properties And Equipment (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2020 USD ($)	Sep. 30, 2020 USD ($) a	Sep. 30, 2019 USD ($) a Item $ / a	Sep. 30, 2018 USD ($)
Property Plant And Equipment [Line Items]
Impairment		$ 29,904,528	$ 76,824,337
Percentage of discount rate for developed location	10.00%		10.00%
Undeveloped location assigned value	$ 0		$ 0
Fair value of discounted cash flows and market quoted amount			9,100,000
Proceeds from sales of assets		4,228,868	19,515,735	$ 1,085,137
Gain (loss) on sale of oil and gas properties		3,997,436	18,973,426
Decrease in net book value			$ 786,000
Number of non-core wells sold | Item			112
Mineral and non-participating royalty acreage sold | a			890
Net gain (loss) on sale of assets		$ 3,973,321	$ 18,730,197	$ (660,597)
Gain (Loss) on Asset Sales [Member]
Property Plant And Equipment [Line Items]
Gain (loss) on sale of oil and gas properties			$ (243,228)
Eddy County, New Mexico [Member]
Property Plant And Equipment [Line Items]
Mineral acreage sold | a		530
Proceeds from sales of assets		$ 3,376,049
Gain (loss) on sale of oil and gas properties		3,272,499
Decrease in net book value		$ 104,000
Northwest Oklahoma [Member]
Property Plant And Equipment [Line Items]
Mineral acreage sold | a		5,925
Proceeds from sales of assets		$ 769,745
Gain (loss) on sale of oil and gas properties		717,640
Decrease in net book value		$ 52,000
Kingfisher, Canadian [Member]
Property Plant And Equipment [Line Items]
Mineral acreage acquired | a		700
Purchase price of mineral acreage acquired		$ 9,293,384
Garvin County, Oklahoma [Member]
Property Plant And Equipment [Line Items]
Mineral acreage acquired | a		700
Purchase price of mineral acreage acquired		$ 9,293,384
Oklahoma and North Dakota [Member]
Property Plant And Equipment [Line Items]
Mineral acreage acquired | a			790
Purchase price of mineral acreage acquired			$ 5,727,257
Net mineral price per acre | $ / a			7,200
Other Assets [Member]
Property Plant And Equipment [Line Items]
Impairment			$ 300,000
Fayetteville Shale [Member]
Property Plant And Equipment [Line Items]
Impairment	19,300,000
Eagle Ford [Member]
Property Plant And Equipment [Line Items]
Impairment	7,300,000
Other Producing Assets [Member]
Property Plant And Equipment [Line Items]
Impairment	$ 2,700,000
Eagle Ford Assets [Member]
Property Plant And Equipment [Line Items]
Impairment			$ 76,600,000

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Properties And Equipment - Summary of Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Asset Retirement Obligation
Asset retirement obligations as of beginning of the year	$ 2,835,781	$ 2,809,378
Wells acquired or drilled	4	27,783
Wells sold or plugged	(68,668)	(134,090)
Accretion of discount	130,405	132,710
Asset retirement obligations as of end of the year	$ 2,897,522	$ 2,835,781

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Derivatives (Summary Of Derivative Instruments Contracts) (Details)	Sep. 30, 2020 MMBTU $ / MMBTU $ / bbl bbl
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	10,000
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.20
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.59
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.90
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	40,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	26,500
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	28,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	32,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	25,500
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	30,500
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	31,500
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	32,500
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	30,500
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	31,500
Natural Gas Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	12,500
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Fourteen [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	11,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fourteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fourteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifteen [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	9,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixteen [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	8,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventeen [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	10,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Eighteen [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	25,500
Natural Gas Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Nineteen [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	53,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	72,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty One [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	48,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Two [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	61,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Three [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	63,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Four [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	69,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Five [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	61,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Six [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	83,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	27,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	20,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	14,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	4,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty One [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	77,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Two [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	54,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Three [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	55,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Four [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	64,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Five [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	52,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Six [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	62,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Seven [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	66,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Eight [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	60,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Nine [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	64,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	24,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty One [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	18,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Two [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	19,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Three [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	20,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Four [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.00
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Five [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	80,000
Contract price	2.750
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Six [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	10,000
Contract price	2.405
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Seven [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	10,000
Contract price	2.661
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Eight [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	50,000
Contract price	2.729
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Nine [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	10,000
Contract price	2.765
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	26,500
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty One [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	28,000
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Two [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	32,000
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Three [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	25,500
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Four [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	30,500
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Five [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	31,500
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Six [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	32,500
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Seven [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	30,500
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Eight [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	31,500
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Nine [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	12,500
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	11,000
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty One [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	9,000
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty Two [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	8,000
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty Three [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	10,000
Contract price	2.582
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty Four [Member]
Derivative [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	25,500
Contract price	2.582
Oil Costless Collars [Member] | Derivative Contract Period Sixty Five [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Sixty Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	55.00
Oil Costless Collars [Member] | Derivative Contract Period Sixty Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	62.00
Oil Costless Collars [Member] | Derivative Contract Period Sixty Six [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Sixty Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Sixty Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Sixty Seven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Sixty Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Sixty Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Sixty Eight [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Sixty Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Sixty Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Sixty Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,500
Oil Costless Collars [Member] | Derivative Contract Period Sixty Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Sixty Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Seventy [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Seventy [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Seventy One [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,500
Oil Costless Collars [Member] | Derivative Contract Period Seventy One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Seventy Two [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Seventy Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Seventy Three [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Seventy Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Seventy Four [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Seventy Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Seventy Five [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Seventy Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Seventy Six [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Seventy Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Seventy Seven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Seventy Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Eight [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Seventy Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Seventy Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,500
Oil Costless Collars [Member] | Derivative Contract Period Eighty [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty One [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,500
Oil Costless Collars [Member] | Derivative Contract Period Eighty One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Two [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Eighty Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Three [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,500
Oil Costless Collars [Member] | Derivative Contract Period Eighty Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Four [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Eighty Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Five [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Eighty Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Six [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,500
Oil Costless Collars [Member] | Derivative Contract Period Eighty Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Seven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	5,000
Oil Costless Collars [Member] | Derivative Contract Period Eighty Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Fixed Price Swaps [Member] | Derivative Contract Period Eighty Eight [Member]
Derivative [Line Items]
Contract price | $ / bbl	55.28
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Eighty Nine [Member]
Derivative [Line Items]
Contract price | $ / bbl	58.65
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety [Member]
Derivative [Line Items]
Contract price | $ / bbl	60.00
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety One [Member]
Derivative [Line Items]
Contract price | $ / bbl	58.05
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Two [Member]
Derivative [Line Items]
Contract price | $ / bbl	58.10
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Three [Member]
Derivative [Line Items]
Contract price | $ / bbl	37.00
Production volume covered per month - Oil | bbl	8,000

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Derivatives (Narrative) (Details) - USD ($)	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value of derivative contracts, Liability	$ 707,647
Fair value of derivative contracts, asset		$ 2,494,144

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Derivatives (Schedule of Gain or Loss on Derivative Contracts, Net) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	$ 4,109,210	$ 196,985	$ (1,001,893)
Non-cash gain (loss) on derivative contracts, net	(3,201,791)	5,908,160	(3,930,175)
Gains (losses) on derivative contracts, net	907,419	6,105,145	(4,932,068)
Natural Gas Costless Collars [Member]
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	28,510	(191,200)	451,700
Non-cash gain (loss) on derivative contracts, net	(706,015)	10,453	(222,337)
Natural Gas Fixed Price Swaps [Member]
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	1,687,600	817,160	748,125
Non-cash gain (loss) on derivative contracts, net	(1,535,122)	1,350,909	(425,865)
Oil Costless Collars [Member]
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	1,011,472	(169,256)	(822,893)
Non-cash gain (loss) on derivative contracts, net	(538,022)	1,687,685	(1,026,163)
Oil Fixed Price Swaps [Member]
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	1,381,628	(259,719)	(1,378,825)
Non-cash gain (loss) on derivative contracts, net	$ (422,632)	$ 2,859,113	$ (2,255,810)

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Derivatives (Summary Of Derivative Contracts) (Details) - USD ($)	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gross amounts recognized - Current Assets	$ 864,466	$ 2,256,639
Offsetting adjustments - Current Assets	(864,466)
Derivative contracts, net		2,256,639
Gross amounts recognized - Non-Current Assets		237,505
Derivative contracts, net		$ 237,505
Gross amounts recognized - Current Liabilities	1,146,408
Offsetting adjustments - Current Liabilities	(864,466)
Derivative contracts, net	281,942
Gross amounts recognized - Non-Current Liabilities	425,705
Derivative contracts, net	$ 425,705

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Fair Value Measurements (Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($)	Sep. 30, 2020	Sep. 30, 2019
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ (64,801)	$ 1,892,954
Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	(64,801)	1,892,954
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	(642,846)	601,190
Collars [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ (642,846)	$ 601,190

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Fair Value Measurements (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, 2020	Sep. 30, 2019
Fair Value Disclosures [Abstract]
Producing Properties, Fair Value	[1]	$ 5,288,710	$ 9,101,032
Producing Properties, Impairment	[1]	$ 29,315,807	$ 76,824,337

[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 natural gas, oil and NGL 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. This table excludes $588,721 of impairments on properties that were written off during 2020.}

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Fair Value Measurements (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Parenthetical) (Details)	12 Months Ended
	Sep. 30, 2020 USD ($)
Fair Value Disclosures [Abstract]
Impairment for written-off wells	$ 588,721

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Information On Natural Gas And Oil Producing Activities (Details)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Company A [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	23.00%	23.00%	24.00%
Company B [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	6.00%	8.00%	16.00%
Company C [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	5.00%	8.00%	11.00%

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Subsequent Events - Additional Information (Details)					12 Months Ended
	Dec. 04, 2020 USD ($) a	Nov. 12, 2020 USD ($) a	Oct. 08, 2020 USD ($) a shares	Jun. 24, 2020 USD ($)	Sep. 30, 2020 USD ($)	Jun. 23, 2020 USD ($)
Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Borrowing base of credit facility, quarterly reduction amount				$ 1,000,000
Borrowing base of credit facility, quarterly reduction term description					Quarterly Commitment Reduction, whereby the borrowing base is reduced by $1,000,000 each April 15, July 15, October 15 and January 15, commencing on July 15, 2020.
Funded debt to EBITDA ratio					400.00%
Borrowing base of credit facility				32,000,000	$ 31,000,000	$ 45,000,000
Revolving Credit Facility [Member] | Eighth Amendment to the Credit Facility [Member]
Subsequent Event [Line Items]
Borrowing base of credit facility, quarterly reduction amount				1,000,000
Borrowing base of credit facility, quarterly reduction term description					This amendment reduced the Quarterly Commitment Reductions from $1,000,000 to $600,000
Consolidated cash balance in anti-cash hoarding provision				$ 2,000,000
Funded debt to EBITDA ratio				400.00%
Subsequent Event [Member]
Subsequent Event [Line Items]
Purchase price of mineral acreage acquired			$ 5,500,000
Shares issued as consideration | shares			153,375
Common stock offering closing date			Sep. 01, 2020
Subsequent Event [Member] | Revolving Credit Facility [Member] | Eighth Amendment to the Credit Facility [Member]
Subsequent Event [Line Items]
Borrowing base of credit facility, quarterly reduction amount	$ 600,000
Consolidated cash balance in anti-cash hoarding provision	$ 1,000,000
Funded debt to EBITDA ratio	350.00%
Borrowing base of credit facility	$ 30,000,000
Subsequent Event [Member] | Grady County, Oklahoma [Member]
Subsequent Event [Line Items]
Royalty acres acquired | a			297
Subsequent Event [Member] | Harrison, Panola [Member]
Subsequent Event [Line Items]
Mineral acreage acquired | a			257
Subsequent Event [Member] | Nacogdoches Counties, Texas [Member]
Subsequent Event [Line Items]
Royalty acres acquired | a			12
Subsequent Event [Member] | San Augustine County, Texas [Member]
Subsequent Event [Line Items]
Mineral acreage acquired | a	87	134
Purchase price of mineral acreage acquired	$ 1,000,000	$ 750,000
Purchase and sales agreement date	Dec. 04, 2020

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Subsequent Events - Summary of New Derivative Instruments Contracts (Details) - Subsequent Event [Member]	Dec. 10, 2020 MMBTU $ / MMBTU $ / bbl bbl
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Four [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	100,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Four [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / MMBTU	2.50
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Four [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / MMBTU	3.17
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Five [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	100,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Five [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / MMBTU	2.50
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Five [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / MMBTU	3.15
Oil Costless Collars [Member] | Derivative Contract Period Ninety Six [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	1,500
Oil Costless Collars [Member] | Derivative Contract Period Ninety Six [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	37.00
Oil Costless Collars [Member] | Derivative Contract Period Ninety Six [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	47.10
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Seven [Member]
Subsequent Event [Line Items]
Contract price	39.51
Production volume covered per month - Oil | bbl	4,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Eight [Member]
Subsequent Event [Line Items]
Contract price	39.51
Production volume covered per month - Oil | bbl	1,500
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Nine [Member]
Subsequent Event [Line Items]
Contract price	43.78
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period One Hundred [Member]
Subsequent Event [Line Items]
Contract price	43.50
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period One Hundred and One [Member]
Subsequent Event [Line Items]
Contract price	43.05
Production volume covered per month - Oil | bbl	1,000

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Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Capitalized Costs of Natural Gas and Oil Properties and Related Depreciation, Depletion and Amortization) (Details) - USD ($)	Sep. 30, 2020	Sep. 30, 2019
Extractive Industries [Abstract]
Producing properties	$ 324,886,491	$ 354,718,398
Non-producing minerals	18,808,689	14,413,899
Non-producing leasehold	185,125	185,124
Gross capitalized costs	343,880,305	369,317,421
Accumulated depreciation, depletion and amortization	(263,277,422)	(258,063,849)
Net capitalized costs	$ 80,602,883	$ 111,253,572

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Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Costs Incurred in Natural Gas and oil Producing Activities) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Extractive Industries [Abstract]
Property acquisition costs	$ 10,453,119	$ 6,235,905	$ 11,409,673
Development costs	273,825	3,012,095	10,291,476
Total cost incurred	$ 10,726,944	$ 9,248,000	$ 21,701,149

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Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Net Quantities of Proved, Developed and Undeveloped Natural Gas Oil and NGL Reserves) (Details)	12 Months Ended
	Sep. 30, 2020 Bcfe bbl Mcf	Sep. 30, 2019 Bcfe bbl Mcf	Sep. 30, 2018 Bcfe bbl Mcf
Reserve Quantities [Line Items]
Proved Natural Gas and Oil Reserves, Beginning Balance | Bcfe	106.4	173.6	168.6
Revisions of previous estimates | Bcfe	(45.9)	(60.6)	(6.7)
Acquisitions (divestitures) | Bcfe	1.7	(3.0)	(0.2)
Extensions, discoveries and other additions | Bcfe	4.1	6.8	24.2
Production | Bcfe	(8.6)	(10.4)	(12.3)
Proved Natural Gas and Oil Reserves, Ending Balance | Bcfe	57.7	106.4	173.6
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Natural Gas and Oil Reserves, Beginning Balance | Mcf	80,273,906	120,062,036	121,195,120
Revisions of previous estimates | Mcf	(34,666,426)	(35,644,135)	(29,247)
Acquisitions (divestitures) | Mcf	911,853	(948,496)	(1,782,949)
Extensions, discoveries and other additions | Mcf	1,816,144	3,891,262	9,400,374
Production | Mcf	(5,962,704)	(7,086,761)	(8,721,262)
Proved Natural Gas and Oil Reserves, Ending Balance | Mcf	42,372,773	80,273,906	120,062,036
Oil [Member]
Reserve Quantities [Line Items]
Proved Natural Gas and Oil Reserves, Beginning Balance	2,380,090	5,984,422	5,509,667
Revisions of previous estimates	(1,094,923)	(3,266,351)	(1,407,995)
Acquisitions (divestitures)	57,721	(322,023)	236,690
Extensions, discoveries and other additions	260,555	313,241	1,982,624
Production	(269,786)	(329,199)	(336,564)
Proved Natural Gas and Oil Reserves, Ending Balance	1,333,657	2,380,090	5,984,422
NGL [Member]
Reserve Quantities [Line Items]
Proved Natural Gas and Oil Reserves, Beginning Balance	1,973,280	2,934,190	2,384,699
Revisions of previous estimates	(774,214)	(890,046)	303,728
Acquisitions (divestitures)	70,933	(18,881)	24,765
Extensions, discoveries and other additions	118,480	164,276	476,174
Production	(168,622)	(216,259)	(255,176)
Proved Natural Gas and Oil Reserves, Ending Balance	1,219,857	1,973,280	2,934,190

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Supplementary Information On Natural Gas, Oil And NGL Reserves (Narrative) (Details)	12 Months Ended
	Sep. 30, 2020 Mcfe $ / bbl $ / Mcf	Sep. 30, 2020 Bcfe Mcfe $ / bbl $ / Mcf	Sep. 30, 2020 Mcfe $ / bbl $ / Mcf	Sep. 30, 2019 Bcfe $ / bbl	Sep. 30, 2018 Bcfe $ / bbl $ / Mcf	Sep. 30, 2019 Bcfe	Sep. 30, 2019 $ / Mcf	Sep. 30, 2019 Mcfe
Supplementary Oil And Gas Disclosures [Line Items]
Negative pricing revisions		35.8
Negative revisions, developed		20.4
Negative revisions, undeveloped		15.4
Negative revisions		10.1
Negative revisions, undeveloped		1.4
Proved developed reserve extensions, discoveries and other additions		4.1
Proved developed reserve		1.7
Proved undeveloped reserve		2.4
Production of oil and natural gas properties		8.6		10.4	12.3
Proved undeveloped Reserves	3,060,656	3,060,656	3,060,656			17.0		17,018,905
Net PUD reserves decreased		14.0
Proved undeveloped reserves transferred to proved developed		0.4	399,894
Percentage transferred to proved developed	2.00%
Remaining revisions of proved undeveloped reserves		13.6
Revisions percentage of proved undeveloped reserves	80.00%
Proved undeveloped reserves revisions of sales and performance		1.8
Proved undeveloped reserves revisions of purchases and extensions		3.6
Proved undeveloped reserves, additions		2.4
COVID-19 [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Negative revisions, undeveloped		15.4
STACK and Arkoma Stack [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Negative revisions, developed		8.7
Eddy County, New Mexico [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Divestiture of permain basin		0.7
Proved developed sale		0.2
Proved undeveloped sale		0.5
Additional proved undeveloped sale		0.5
Oklahoma [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Additional proved undeveloped acquisition		1.3
Oil [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Price used to calculate reserves and future cash flows from reserves | $ / bbl	40.18	40.18	40.18	54.40	62.86
NGL [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Price used to calculate reserves and future cash flows from reserves | $ / bbl	9.95	9.95	9.95	19.30	26.13
Natural Gas [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Price used to calculate reserves and future cash flows from reserves | $ / Mcf	1.62	1.62	1.62		2.56		2.48
Oil, NGL And Natural Gas [Member] | Woodford, Mississippian, Oklahoma and North Dakota [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Acquisition		2.4
Proved developed acquisition		1.1
Proved undeveloped acquisition		1.3

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Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Proved Developed and Undeveloped Reserves) (Details)	Sep. 30, 2020 bbl Mcf	Sep. 30, 2019 bbl Mcf	Sep. 30, 2018 bbl Mcf
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | Mcf	40,924,083	67,713,193	83,151,954
Proved Undeveloped Reserves (Volume) | Mcf	1,448,690	12,560,713	36,910,082
Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	1,148,989	1,863,096	2,334,587
Proved Undeveloped Reserves (Volume)	184,668	516,994	3,649,835
NGL [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	1,135,864	1,747,242	2,085,706
Proved Undeveloped Reserves (Volume)	83,993	226,038	848,484

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Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Proved Undeveloped Reserves) (Details) - 12 months ended Sep. 30, 2020	Bcfe	Mcfe
Extractive Industries [Abstract]
Beginning proved undeveloped reserves	17.0	17,018,905
Proved undeveloped reserves transferred to proved developed	(0.4)	(399,894)
Revisions		(16,767,540)
Extensions and discoveries		2,405,590
Sales		(479,415)
Purchases		1,283,010
Ending proved undeveloped reserves		3,060,656

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Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($)	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Extractive Industries [Abstract]
Future cash inflows	$ 134,179,216	$ 366,697,321	$ 759,899,074
Future production costs	(66,136,222)	(153,935,373)	(259,413,766)
Future development and asset retirement costs	(1,957,225)	(1,917,937)	(89,518,449)
Future income tax expense	(13,224,535)	(47,788,416)	(95,872,182)
Future net cash flows	52,861,234	163,055,595	315,094,677
10% annual discount	(21,727,081)	(77,494,066)	(158,768,823)
Standardized measure of discounted future net cash flows	$ 31,134,153	$ 85,561,529	$ 156,325,854	$ 80,832,575

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Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Extractive Industries [Abstract]
Beginning Balance	$ 85,561,529	$ 156,325,854	$ 80,832,575
Sales of natural gas, oil and NGL, net of production costs	(12,692,681)	(25,072,122)	(32,836,007)
Net change in sales prices and production costs	(46,499,344)	(76,588,460)	47,533,281
Net change in future development and asset retirement costs	(20,571)	43,607,535	1,580,942
Extensions and discoveries	2,841,807	7,074,245	34,667,557
Revisions of quantity estimates	(28,332,653)	(60,308,497)	(8,391,223)
Acquisitions (divestitures) of reserves-in-place	1,169,819	(3,134,783)	(307,472)
Accretion of discount	11,039,792	20,457,930	12,602,209
Net change in income taxes	17,037,980	23,413,194	(3,057,128)
Change in timing and other, net	1,028,475	(213,367)	23,701,120
Net change	(54,427,376)	(70,764,325)	75,493,279
Ending Balance	$ 31,134,153	$ 85,561,529	$ 156,325,854

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Quarterly Results Of Operations (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 4,372,618	$ 2,705,383	$ 11,311,287	$ 10,576,531	$ 15,728,084	$ 16,342,394	$ 7,636,213	$ 26,328,994	$ 28,965,819	$ 66,035,685	$ 45,034,264
Income (loss) before provision for income taxes	(2,512,182)	(4,433,155)	(27,441,814)	2,146,114	(74,390,780)	5,919,236	(2,061,334)	16,306,940
Net income (loss)	$ (1,834,122)	$ (3,555,215)	$ (20,454,814)	$ 1,892,114	$ (56,153,780)	$ 4,604,236	$ (1,931,334)	$ 12,735,940	$ (23,952,037)	$ (40,744,938)	$ 14,635,669
Earnings (loss) per share	$ (0.07)	$ (0.21)	$ (1.24)	$ 0.11	$ (3.35)	$ 0.28	$ (0.11)	$ 0.75	$ (1.41)	$ (2.43)	$ 0.86