10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

☑ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the period ended  June 30, 2020

☐ 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

PANHANDLE OIL AND GAS 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, Oklahoma  73118

(Address of principal executive offices)

Registrant's telephone number including area code (405) 948-1560

Securities registered pursuant in 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

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 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 definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ☐    No  ☑

Outstanding shares of Class A Common stock (voting) at August 13, 2020: 16,413,718

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements	1
		Condensed Balance Sheets – June 30, 2020, and September 30, 2019	1
		Condensed Statements of Operations – Three and nine months ended June 30, 2020 and 2019	2
		Statements of Stockholders’ Equity – Nine months ended June 30, 2020 and 2019	3
		Condensed Statements of Cash Flows – Nine months ended June 30, 2020 and 2019	5
		Notes to Condensed Financial Statements	6
	Item 2	Management's discussion and analysis of financial condition and results of operations	19
	Item 3	Quantitative and qualitative disclosures about market risk	27
	Item 4	Controls and procedures	27
Part II	Other Information
	Item 1A	Risk Factors	28
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	29
	Item 6	Exhibits	29
	Signatures		29

Special Note Regarding Forward Looking Statements

This Quarterly Report on Form 10-Q (“Form 10-Q”) 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-Q 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 oil and natural gas prices; the level of production on our properties; estimates of quantities of oil, NGL and natural gas reserves and their values; general economic or industry conditions; public health crises, such as the COVID-19 pandemic, and any related actions taken by businesses and governments; 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-Q are subject to risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil, natural gas liquids and natural gas. These risks include, but are not limited to, the risks described in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2019 (“Annual Report”), and all quarterly reports on Form 10-Q filed subsequently hereto, including the risks described in Item 1A of this Form 10-Q. Investors should also read the other information in this Form 10-Q and the Company’s Annual Report where risk factors are presented and further discussed.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q 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 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, oil and natural gas industry and other defined terms used in this Form 10-Q:

ASU	Accounting Standards Update.
Bbl	barrel.
Board	board of directors of the Company.
BTU	British Thermal Units.
completion	the process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.
DD&A	depreciation, depletion and amortization.
EBITDA	earnings before interest, taxes, depreciation and amortization (including impairment). This is a Non-GAAP measure.
ESOP	the Panhandle Oil and Gas Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan.
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.
G&A	general and administrative costs.
GAAP	generally accepted accounting principles.
Independent Consulting Petroleum Engineer(s)	DeGolyer and MacNaughton of Dallas, Texas.
LOE	lease operating expense.
Mcf	thousand cubic feet.
Mcfe	natural gas stated on an Mcf basis and crude oil and natural gas liquids converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil or natural gas liquids to six Mcf of natural gas.
Mmbtu	million BTU.
minerals, mineral acres or mineral interests	fee mineral acreage owned in perpetuity by the Company.
NGL	natural gas liquids.
NYMEX	New York Mercantile Exchange.
play	term applied to identified areas with potential oil and/or natural gas reserves.
proved reserves	the quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.
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.
undeveloped acreage	acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
working interest	well interests in which the Company pays a share of the costs to drill, complete and operate a well and receives a proportionate share of production.
WTI	West Texas Intermediate.

Fiscal year references

All references to years in this Form 10-Q, 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.

Fiscal quarter references

All references to quarters in this Form 10-Q, unless otherwise noted, refer to the Company’s fiscal quarter based on a fiscal year end of September 30. For example, references to first quarter mean the quarter of October 1 through December 31.

References to oil and natural gas properties

References to oil and natural gas properties in this Form 10-Q inherently include natural gas liquids associated with such properties.

PART 1. FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED BALANCE SHEETS

	June 30, 2020			September 30, 2019
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	2,025,081		$	6,160,691
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		2,183,216			4,377,646
Refundable income taxes		1,640,350			1,505,442
Derivative contracts, net		1,819,977			2,256,639
Other		490,697			177,037
Total current assets		8,159,321			14,477,455
Net properties and equipment, based on successful efforts method of accounting		83,038,001			111,427,021
Investments		113,408			205,076
Derivative contracts, net		-			237,505
Deferred income taxes, net		181,993			-
Other, net		231,387			297,890
Total assets	$	91,724,110		$	126,644,947
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	724,289		$	665,160
Accrued liabilities and other		1,485,708			2,433,466
Short-term debt		2,000,000			-
Total current liabilities	$	4,209,997		$	3,098,626
Long-term debt		28,000,000			35,425,000
Deferred income taxes, net		-			5,976,007
Asset retirement obligations		2,871,603			2,835,781
Derivative contracts, net		140,466			-
Stockholders' equity:
Class A voting common stock, $0.01666 par value; 24,000,500 shares authorized;   16,897,306 issued at June 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		281,509			281,509
Capital in excess of par value		3,375,400			2,967,984
Deferred directors' compensation		1,829,786			2,555,781
Retained earnings		58,244,355			81,848,301
		63,731,050			87,653,575
Less treasury stock, at cost; 483,588 shares at June 30, 2020, and 558,051 shares    at September 30, 2019		(7,229,006	)		(8,344,042	)
Total stockholders' equity		56,502,044			79,309,533
Total liabilities and stockholders' equity	$	91,724,110		$	126,644,947

(See accompanying notes)

(1)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,					Nine Months Ended June 30,
	2020			2019		2020			2019
Revenues:	(unaudited)					(unaudited)
Oil, NGL and natural gas sales	$	3,517,561		$	9,782,337	$	18,329,017		$	31,214,375
Lease bonuses and rental income		22,996			229,075		572,787			952,378
Gains (losses) on derivative contracts		(838,282	)		2,313,195		2,415,401			5,026,123
Gain on asset sales		3,108			4,017,787		3,275,996			13,114,725
		2,705,383			16,342,394		24,593,201			50,307,601
Costs and expenses:
Lease operating expenses		1,147,948			1,619,690		3,871,818			4,639,749
Transportation, gathering and marketing		956,653			1,529,270		3,696,282			4,601,959
Production taxes		134,249			488,779		835,284			1,565,038
Depreciation, depletion and amortization		2,464,568			4,383,043		8,793,787			11,820,705
Provision for impairment		358,826			-		29,904,528			-
Interest expense		241,191			526,677		958,429			1,551,831
General and administrative		1,908,790			1,809,439		6,306,479			5,881,432
Other expense (income)		(73,687	)		66,260		(44,551	)		82,045
		7,138,538			10,423,158		54,322,056			30,142,759
Income (loss) before provision (benefit) for income taxes		(4,433,155	)		5,919,236		(29,728,855	)		20,164,842
Provision (benefit) for income taxes		(877,940	)		1,315,000		(7,610,940	)		4,756,000
Net income (loss)	$	(3,555,215	)	$	4,604,236	$	(22,117,915	)	$	15,408,842
Basic and diluted earnings (loss) per common share (Note 5)	$	(0.21	)	$	0.28	$	(1.34	)	$	0.92
Basic and diluted weighted average shares outstanding:
Common shares		16,403,243			16,515,498		16,375,736			16,646,828
Unissued, directors' deferred compensation shares		141,799			170,066		152,500			183,206
		16,545,042			16,685,564		16,528,236			16,830,034
Dividends declared per share of common stock and paid in period	$	0.01		$	0.04	$	0.09		$	0.12

(See accompanying notes)

(2)

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Nine Months Ended June 30, 2020

	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, 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)		-		-		-			-			1,892,114			-			-			1,892,114
Purchase of treasury stock		-		-		-			-			-			(632	)		(7,635	)		(7,635	)
Restricted stock awards		-		-		148,515			-			-			-			-			148,515
Dividends ($0.08 per share)		-		-		-			-			(1,319,899	)		-			-			(1,319,899	)
Distribution of restricted stock    to officers and directors		-		-		(82,821	)		-			-			5,546			82,914			93
Increase in deferred directors'    compensation charged to    expense		-		-		-			86,212			-			-			-			86,212
Balances at December 31, 2019		16,897,306	$	281,509	$	3,033,678		$	2,641,993		$	82,420,516			(553,137	)	$	(8,268,763	)	$	80,108,933
Net income (loss)		-		-		-			-			(20,454,814	)		-			-			(20,454,814	)
Restricted stock awards		-		-		343,101			-			-			-			-			343,101
Distribution of deferred    directors' compensation		-		-		(112,396	)		(603,485	)		-			47,885			715,880			(1	)
Increase in deferred directors'    compensation charged to    expense		-		-		-			53,918			-			-			-			53,918
Balances at March 31, 2020		16,897,306	$	281,509	$	3,264,383		$	2,092,426		$	61,965,702			(505,252	)	$	(7,552,883	)	$	60,051,137
Net income (loss)		-		-		-			-			(3,555,215	)		-			-			(3,555,215	)
Restricted stock awards		-		-		128,196			-			-			-			-			128,196
Dividends ($0.01 per share)		-		-		-			-			(166,132	)		-			-			(166,132	)
Distribution of deferred    directors' compensation		-		-		(17,179	)		(306,698	)		-			21,664			323,877			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			44,058			-			-			-			44,058
Balances at June 30, 2020		16,897,306	$	281,509	$	3,375,400		$	1,829,786		$	58,244,355			(483,588	)	$	(7,229,006	)	$	56,502,044
(unaudited)

(See accompanying notes)

(3)

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)

Nine Months Ended June 30, 2019

	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, 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)		-		-		-			-			12,735,940			-			-			12,735,940
Purchase of treasury stock		-		-		-			-			-			(74,457	)		(1,140,559	)		(1,140,559	)
Restricted stock awards		-		-		159,469			-			-			-			-			159,469
Dividends ($0.08 per share)		-		-		-			-			(1,347,789	)		-			-			(1,347,789	)
Distribution of restricted stock    to officers and directors		425		7		(159,869	)		-			-			9,194			160,022			160
Distribution of deferred    directors' compensation		-		-		(8	)		8			-			-			-			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			80,287			-			-			-			80,287
Balances at December 31, 2018		16,897,306	$	281,509	$	2,824,283		$	3,030,700		$	136,655,096			(210,730	)	$	(3,538,875	)	$	139,252,713
Net income (loss)		-		-		-			-			(1,931,334	)		-			-			(1,931,334	)
Purchase of treasury stock		-		-		-			-			-			(175,175	)		(2,827,126	)		(2,827,126	)
Restricted stock awards		-		-		286,852			-			-			-			-			286,852
Dividends		-		-		-			-			(381	)		-			-			(381	)
Distribution of restricted stock    to officers and directors		-		-		(73,069	)		-			-			4,441			73,144			75
Distribution of deferred    directors' compensation		-		-		(207,842	)		(667,124	)		-			52,399			874,963			(3	)
Increase in deferred directors'    compensation charged to    expense		-		-		-			51,993			-			-			-			51,993
Balances at March 31, 2019		16,897,306	$	281,509	$	2,830,224		$	2,415,569		$	134,723,381			(329,065	)	$	(5,417,894	)	$	134,832,789
Net income (loss)		-		-		-			-			4,604,236			-			-			4,604,236
Purchase of treasury stock		-		-		-			-			-			(182,901	)		(2,497,501	)		(2,497,501	)
Restricted stock awards		-		-		159,911			-						-			-			159,911
Dividends ($0.04 per share)		-		-		-			-			(664,835	)		-			-			(664,835	)
Distribution of restricted stock    to officers and directors		-		-		(52,261	)		-			-			3,384			52,317			56
Increase in deferred directors'    compensation charged to    expense		-		-		-			65,540			-			-			-			65,540
Balances at June 30, 2019		16,897,306	$	281,509	$	2,937,874		$	2,481,109		$	138,662,782			(508,582	)	$	(7,863,078	)	$	136,500,196
(unaudited)

(See accompanying notes)

(4)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Nine months ended June 30,
	2020			2019
Operating Activities	(unaudited)
Net income (loss)	$	(22,117,915	)	$	15,408,842
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		8,793,787			11,820,705
Impairment of producing properties		29,904,528			-
Provision for deferred income taxes		(6,158,000	)		5,150,000
Gain from leasing fee mineral acreage		(567,975	)		(951,832	)
Proceeds from leasing fee mineral acreage		582,458			967,337
Net (gain) loss on sales of assets		(3,258,994	)		(13,114,725	)
Directors' deferred compensation expense		184,188			197,820
Total (gain) loss on derivative contracts		(2,415,401	)		(5,026,123	)
Cash receipts (payments) on settled derivative contracts		3,230,034			(1,099,402	)
Restricted stock awards		619,812			606,232
Other		3,718			15,848
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		2,194,430			1,597,667
Other current assets		(121,635	)		(859,258	)
Accounts payable		31,755			3,270
Income taxes receivable		(134,908	)		(476,846	)
Other non-current assets		6,544			6,949
Accrued liabilities		(950,686	)		86,467
Total adjustments		31,943,655			(1,075,891	)
Net cash provided by operating activities		9,825,740			14,332,951
Investing Activities
Capital expenditures		(196,168	)		(3,349,640	)
Acquisition of minerals and overrides		(10,304,016	)		(5,120,466	)
Investments in partnerships		-			(1,648	)
Proceeds from sales of assets		3,457,500			13,114,969
Net cash provided (used) by investing activities		(7,042,684	)		4,643,215
Financing Activities
Borrowings under Credit Facility		6,061,725			15,053,345
Payments of loan principal		(11,486,725	)		(24,553,345	)
Purchases of treasury stock		(7,635	)		(6,465,186	)
Payments of dividends		(1,486,031	)		(2,013,005	)
Net cash provided (used) by financing activities		(6,918,666	)		(17,978,191	)
Increase (decrease) in cash and cash equivalents		(4,135,610	)		997,975
Cash and cash equivalents at beginning of period		6,160,691			532,502
Cash and cash equivalents at end of period	$	2,025,081		$	1,530,477
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations	$	4		$	27,782
Gross additions to properties and equipment	$	10,335,534		$	8,149,347
Net (increase) decrease in accounts payable for properties and equipment additions		164,650			320,759
Capital expenditures and acquisitions	$	10,500,184		$	8,470,106

(See accompanying notes)

(5)

PANHANDLE OIL AND GAS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Basis of Presentation and Accounting Principles

Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1 through September 30.

Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2019. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Panhandle” or “Company” refer to Panhandle Oil and Gas Inc.

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 is evaluating the new standard and is currently in the process of estimating its financial statement impact; however, the impact is not expected to be material. Historically, the Company's credit losses on oil, NGL and natural gas 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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NOTE 2: Leases

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 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 June 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 lease for office space during the quarter ended March 31, 2020, with a commencement date in the fourth quarter of 2020. The associated lease liability and ROU asset will be recognized at that time and is estimated to be approximately $1 million.

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 lease 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, 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.

NOTE 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 oil, NGL or natural gas 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.

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Oil and natural gas derivative contracts

See Note 10 for discussion of the Company’s accounting for derivative contracts.

Revenues from Contracts with Customers

Oil, NGL and natural gas sales

Sales of oil, NGL and natural gas 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 oil, NGL and natural gas revenues

The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the three and nine months ended June 30, 2020 and 2019:

	Three Months Ended June 30, 2020						Nine Months Ended June 30, 2020
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Oil revenue	$	719,012	$	711,005	$	1,430,017	$	4,680,871	$	4,404,949	$	9,085,820
NGL revenue		129,833		103,023		232,856		548,921		823,559		1,372,480
Natural gas revenue		792,227		1,062,461		1,854,688		3,122,951		4,747,766		7,870,717
Oil, NGL and natural gas sales	$	1,641,072	$	1,876,489	$	3,517,561	$	8,352,743	$	9,976,274	$	18,329,017
	Three Months Ended June 30, 2019						Nine Months Ended June 30, 2019
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Oil revenue	$	1,640,247	$	3,883,220	$	5,523,467	$	5,496,433	$	8,435,619	$	13,932,052
NGL revenue		310,581		515,701		826,282		938,692		2,158,787		3,097,479
Natural gas revenue		1,172,272		2,260,316		3,432,588		4,614,537		9,570,307		14,184,844
Oil, NGL and natural gas sales	$	3,123,100	$	6,659,237	$	9,782,337	$	11,049,662	$	20,164,713	$	31,214,375

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 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 Oil, NGL and natural gas sales receivables line item on the Company’s Balance Sheets. The difference between the Company's estimates and the actual amounts received for oil, NGL and natural gas sales is recorded in the quarter that payment is received from the third party. For the three and nine months ended June 30, 2019, 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.

As noted above, as a non-operator, there are instances when the Company is limited by the information operators provide to us. Through the use of new technological platforms as well as cash received on new wells, in the 2020 third quarter, the Company identified several producing properties on our minerals that had production dates prior to the 2020 third quarter. Estimates of the oil and natural gas sales related to those properties were made and are reflected in the third quarter Oil, NGL and natural gas sales on the Company’s Statements of Operations and on the Company’s Balance Sheets in Oil, NGL and natural gas sales receivables. In connection with obtaining more relevant information identifying additional new wells on Panhandle acreage, we have recorded a change in estimate for new wells to Oil, NGL and natural gas sales totaling $259,336 of which $164,115 related to the production

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periods before October 1, 2019, and $95,221 related to the first and second quarters of 2020. This reduced loss before benefit for income taxes by $237,341 in the three and nine months ended June 30, 2020. This resulted in decreases in both net loss of $189,873 and $0.01 loss per common share for the three months ended June 30, 2020, and decreases in both net loss of $175,632 and $0.01 loss per common share for the nine months ended June 30, 2020.

NOTE 4: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from 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. Excess tax benefits and deficiencies of stock-based compensation are recognized as provision (benefit) for income taxes in the Company’s Statements of Operations.

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. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with detailed well-by-well calculations at fiscal year-end. 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 nine months ended June 30, 2020, was a 26% benefit as compared a 24% provision for the nine months ended June 30, 2019. The effective tax rate for the quarter ended June 30, 2020, was a 20% benefit as compared to a 22% provision for the quarter ended June 30, 2019.

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. 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. In addition to the acceleration of the AMT refund, an additional $31,127 was recognized as an income tax benefit as a result of the NOL carryback provision allowing the Company to use the previously enacted tax rate of 34% rather than the current tax rate of 21%.  

NOTE 5: Basic and Diluted Earnings (Loss) per Common Share

Basic and diluted earnings (loss) per common share is calculated using net income (loss) divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares during the period. 

NOTE 6: Long-Term Debt

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a borrowing base of $32,000,000 as of June 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 its 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 oil and gas 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 the ratio of loan balance to the borrowing base increases. At June 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 June 30, 2020 was $231,387. 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 discretion, believe that there has been a material change in the value of the oil and natural gas properties. On June 24, 2020, the Company entered into the seventh amendment to its amended and restated credit agreement. The amendment reduced the borrowing base from $45,000,000 to $32,000,000 and includes a Quarterly Commitment Reduction, whereby the borrowing base is reduced by

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$1,000,000 each April 15, July 15, October 15 and January 15, commencing on July 15, 2020. The next redetermination is expected to occur in December 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 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 June 30, 2020, the Company was in compliance with the covenants of the Credit Facility,had $30,000,000 outstanding, of which $2,000,000 is classified as short-term debt due to the Quarterly Commitment Reduction,and had$2,000,000of borrowing base availability under theCredit Facility.

NOTE 7: Deferred Compensation Plan for Non-Employee Directors

Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. This plan provides that each outside 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. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination, death or a change-in-control of the Company will the shares recorded for such director be issued under this plan. Directors may elect to receive shares, when issued, over annual time periods up to ten years. The promise to issue such shares in the future is an unsecured obligation of the Company.

NOTE 8: Restricted Stock Plan

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

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. Upon vesting, the market-based shares that do not meet certain market performance criteria 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 vests on December 31, 2020. The restricted stock contains non-forfeitable rights to

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receive dividends and to vote the shares during the vesting period. 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 with a nominal value at their award date.

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. The performance-based shares had a nominal value at their award date.

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 three and nine months ended June 30, 2020 and 2019, related to the Company’s market-based, time-based and performance-based restricted stock:

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2020		2019		2020		2019
Market-based, restricted stock	$	10,247	$	60,406	$	285,150	$	306,685
Time-based, restricted stock		117,949		99,505		334,662		299,547
Performance-based, restricted stock		-		-		-		-
Total compensation expense	$	128,196	$	159,911	$	619,812	$	606,232

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:

	As of June 30, 2020
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	77,900		2.06
Time-based, restricted stock		676,667		2.09
Performance-based, restricted stock		-
Total	$	754,567

NOTE 9: Properties and Equipment

Properties and equipment and related accumulated DD&A as of June 30, 2020, and September 31, 2019, are as follows:

	June 30, 2020			September 30, 2019
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		324,913,067			354,718,398
Non-producing oil and natural gas properties		19,081,485			14,599,023
Other property and equipment		777,104			717,121
		344,771,656			370,034,542
Less accumulated depreciation, depletion and amortization		(261,733,655	)		(258,607,521	)
Net properties and equipment		83,038,001			111,427,021

Divestitures

During the second and third quarters of 2020, the Company had no significant divestitures.

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During the first quarter of 2020, Panhandle 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, $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.

During the third quarter of 2019, the Company sold 166 net mineral acres and producing oil and natural gas properties located in Martin County, Texas, to private buyers for total net consideration of $4.0 million and recorded a gain on the sale of $4.0 million. The cash from the sale was used to purchase minerals and reduce the Company’s outstanding bank debt.

During the second quarter of 2019, the Company had no divestitures.

During the first quarter of 2019, the Company sold 206 net mineral acres and producing oil and natural gas properties located in Lea and Eddy Counties, New Mexico, to a private buyer for total net consideration of $9.1 million and recorded a gain on the sale of $9.1 million. The cash from the sale was used to reduce the Company’s outstanding debt under the Credit Facility.

Acquisitions

During the second and third quarters of 2020, the Company had no significant acquisitions.

During the first quarter of 2020, Panhandle 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).

During the third quarter of 2019, the Company acquired 313 net mineral acres (which include producing oil and natural gas properties) in the Bakken/Three Forks play in North Dakota and in the STACK play in Blaine County, Oklahoma, for $3.3 million.

During the second quarter of 2019, the Company acquired 329 net mineral acres (which include producing oil and natural gas properties) in the STACK play in Blaine and Caddo Counties, Oklahoma, for $1.4 million.

During the first quarter of 2019, the Company acquired 45 net mineral acres (which include producing oil and natural gas properties) in the STACK play in Blaine County, Oklahoma, with undeveloped locations identified in both the Woodford and Meramac Shales for $0.4 million.

Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for retirement of assets and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geologic and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing appropriate prices for the current period. The estimated oil, NGL and natural gas reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, NGL and natural gas price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Crude oil, NGL and natural gas prices are volatile and affected by worldwide production and consumption and are outside the control of management (see Item 1A: Risk Factors for a further discussion of price volatility).

Impairment

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as: inflation rates; future drilling and completion costs; future sales prices for oil, NGL and natural gas; future production costs; estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof; the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior

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report was issued and then utilizes updated projected future price decks current with the period. For the nine months ended June 30, 2020, the assessment resulted in an impairment provision on producing properties of $29,315,807, primarily due to the decline in commodity prices caused by the ongoing COVID-19 pandemic and the early March 2020 failure by a group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts (see Item 1A: Risk Factors).During the three and nine months ended June 30, 2020, impairment on wells that were written off totaled $358,826 and $588,721, respectively.For the three and nine months ended June 30,2019, the assessment resulted in no impairment provisions on producing properties.

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, are the primary reason for impairment in this field. The Company recognized an impairment related to the Eagle Ford at September 30, 2019, of $76.6 million 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, is due to the decline in commodity prices over fiscal 2020.

A further reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.

Asset Retirement Obligation

	June 30, 2020			June 30, 2019
Asset retirement obligations as of beginning of the year	$	2,835,781		$	2,809,378
Wells acquired or drilled		4			27,782
Wells sold or plugged		(61,985	)		(9,669	)
Accretion of discount		97,803			99,996
Asset retirement obligations as of end of period	$	2,871,603		$	2,927,487

NOTE 10: Derivatives

The Company has entered into commodity price derivative agreements, including fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. 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. 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. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. The Company’s derivative contracts are currently with Bank of Oklahoma. The derivative contracts with Bank of Oklahoma are secured under the Credit Facility with Bank of Oklahoma (see Note 6: Long-Term Debt). The derivative instruments have settled or will settle based on the prices below:

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Derivative contracts in place as of June 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
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 - December 2021	10,000 Mmbtu	NYMEX Henry Hub	$2.765
January 2021 - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$2.729
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
Oil fixed price swaps
January - December 2020	2,000 Bbls	NYMEX WTI	$55.28
January - December 2020	2,000 Bbls	NYMEX WTI	$58.65

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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 has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net asset of $1,679,511 as of June 30, 2020, and a net asset of $2,494,144 as of September 30, 2019. 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.

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	18,000		$	-		$	18,000		$	(191,200	)
Natural gas fixed price swaps		268,650			525,200			1,488,970			(294,940	)
Oil costless collars		625,968			(104,394	)		827,664			(359,564	)
Oil fixed price swaps		786,504			(1,914	)		895,400			(253,698	)
Cash received (paid) on derivative contracts, net	$	1,699,122		$	418,892		$	3,230,034		$	(1,099,402	)
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(60,035	)	$	-		$	(32,152	)	$	10,453
Natural gas fixed price swaps		(129,865	)		1,255,469			(815,630	)		2,177,594
Oil costless collars		(757,060	)		128,829			(283,255	)		1,516,144
Oil fixed price swaps		(1,590,444	)		510,005			316,404			2,421,334
Non-cash gain (loss) on derivative contracts, net	$	(2,537,404	)	$	1,894,303		$	(814,633	)	$	6,125,525
Gains (losses) on derivative contracts, net	$	(838,282	)	$	2,313,195		$	2,415,401		$	5,026,123

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 of whether or not to offset, 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 Company’s 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 June 30, 2020, and September 30, 2019. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at June 30, 2020, and September 30, 2019.

	June 30, 2020												September 30, 2019
	Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets		Non-Current Assets
Gross amounts recognized	$	2,028,640		$	208,663		$	57,386		$	197,852		$	2,256,639	$	237,505
Offsetting adjustments		(208,663	)		(208,663	)		(57,386	)		(57,386	)		-		-
Net presentation on Condensed Balance Sheets	$	1,819,977		$	-		$	-		$	140,466		$	2,256,639	$	237,505

(a) See Note 11: Fair Value Measurements for further disclosures regarding fair value of financial instruments.

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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NOTE 11: 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 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2020:

	Fair Value Measurement at June 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	$	-	$	1,393,727	$	-	$	1,393,727
Derivative Contracts - Collars	$	-	$	285,784	$	-	$	285,784

Level 2 – Market Approach - The fair values of the Company’s swaps and collars are based on a third-party pricing model, which utilizes inputs that are either readily available in the public market, such as natural gas curves and volatility curves, or can be corroborated from active markets. These values are based upon future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

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:

	Quarter Ended June 30,
	2020				2019
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	-	$	-
	Nine Months Ended June 30,
	2020				2019
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	5,288,710	$	29,315,807	$	-	$	-

(a) When indicators of impairment are present, the Company assesses the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off during the three and nine months ended June 30, 2020, in the amounts of $358,826 and $588,721, respectively.

At June 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

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instruments include long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s 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.

NOTE 12: Subsequent Events

Derivative Contracts

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

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	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
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
Oil costless collars
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 21	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 22	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 22	5,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling

Sale of Non-Producing Minerals

On July 28, 2020, the Company closed on the sale of 5,925 open and non-producing net mineral acres in Northwest Oklahoma for total proceeds of $793,617, with the proceeds applied toward debt reduction.

New Tax Regulations

On July 28, 2020, the U.S. Treasury Department released final regulations and proposed regulations with guidance on the business interest expense limitation under IRC Section 163(j). The Section 163(j) business interest expense limitation was modified in

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December 2017 by the Tax Cuts and Jobs Act, and in March 2020 by the CARES Act. Currently, we are in the process of evaluating the effect of these regulations on our consolidated financial statements and related disclosures.

ITEM 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS OVERVIEW

Panhandle is an owner and manager of perpetual oil and natural gas mineral interests in resource plays in the United States. Our principal business is maximizing the value of our existing mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests.

We currently own interests in leasehold acreage and non-operated working interests in oil and natural gas properties. Exploration and development of our oil and natural gas properties are conducted by third-party oil and natural gas exploration and production companies (primarily larger independent operating companies). We do not operate any of our oil and natural gas properties. While we previously have been an active working interest participant in wells drilled on our mineral and leasehold acreage, our current focus is on growth through mineral acquisitions and development of our significant mineral acreage inventory in our core areas of focus, which include the SCOOP/STACK and Arkoma Stack plays in Oklahoma, the Permian Basin in Texas and New Mexico, the Eagle Ford play in Texas, the Fayetteville play in Arkansas, and the Bakken/Three Forks play in North Dakota. We have ceased taking any working interest positions on our mineral and leasehold acreage and do not plan to take any going forward.

RESULTS OF OPERATIONS

Our results of operations are dependent primarily upon our: existing reserve quantities; costs associated with acquiring new reserves; production quantities and related production costs; and oil, NGL and natural gas sales prices. Although a significant amount of our revenue is currently derived from the production and sale of oil, NGL and natural gas on our working interests, a growing portion of our revenue is derived from royalties received from the production and sale of oil, NGL and natural gas.

THREE MONTHS ENDED JUNE 30, 2020, COMPARED TO THREE MONTHS ENDED JUNE 30, 2019

Overview:

The Company recorded a third quarter 2020 net loss of $3,555,215, or $0.21 per share, as compared to a net income of $4,604,236, or $0.28 per share, in the 2019 quarter. The change in net income (loss) was principally the result of decreased oil, NGL, and natural gas sales, loss on derivative contracts in the third quarter and decreased gain on asset sales, partially offset by a decrease in DD&A, transportation, gathering and marketing expenses, production taxes and changes in tax provision (benefit). These items are further discussed below.

Revenue:

Oil, NGL and Natural Gas Sales:

Revenue from oil, NGL and natural gas sales decreased $6,264,776 or 64% for the 2020 quarter. Oil, NGL and natural gas sales were lower due to decreases in oil, NGL and natural gas prices of 55%, 57% and 32%, respectively, and decreases in oil, NGL and natural gas sales volumes of 43%, 35% and 21%, respectively. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the three-month periods of fiscal 2020 and 2019:

	Oil Bbls		Average		NGL Bbls		Average		Mcf		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
6/30/2020		55,138	$	25.94		35,169	$	6.62		1,361,909	$	1.36		1,903,752	$	1.85
6/30/2019		96,065	$	57.50		53,903	$	15.33		1,718,561	$	2.00		2,618,369	$	3.74

Although production is down in all three product categories, it is notable that production is down for working interest volumes and slightly up for royalty interest volumes due to new royalty interest wells brought online, as compared to June 30, 2019. The primary factor for the oil production decrease is attributable to the Eagle Ford Shale working interest wells, where the natural decline on new wells brought online in March 2019 is coupled with recent delays in performing mechanical repairs due to poor economics related to low oil prices. Additionally, decreases are also attributable to the natural decline of the working interest

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production base. NGL production decline is attributable to curtailed production along with the natural decline of the working interest production base in liquid-rich gas areas of the STACK, SCOOP and Arkoma Stack. Natural gas volumes have decreased as a result of curtailments in response to market conditions in the STACK, SCOOP and Arkoma Stack, in addition to the natural decline of working interest production base in all the areas. New royalty interest production has increased, even though we have experienced reduced activity as a result of market conditions; this increase is primarily associated with mineral acquisitions and new wells brought online.

Total Production for the last five quarters was as follows:

Quarter ended	Oil Bbls Sold		NGL Bbls Sold		Mcf Sold		Mcfe Sold
6/30/2020		55,138		35,169		1,361,909		1,903,752
3/31/2020		93,141		47,487		1,529,367		2,373,135
12/31/2019		65,880		39,230		1,647,827		2,278,487
9/30/2019		75,934		52,219		1,786,167		2,555,085
6/30/2019		96,065		53,903		1,718,561		2,618,369

Royalty Interest Production for the last five quarters was as follows:

Quarter ended	Oil Bbls Sold		NGL Bbls Sold		Mcf Sold		Mcfe Sold
6/30/2020		28,468		16,574		544,249		814,501
3/31/2020		54,077		16,188		549,999		971,589
12/31/2019		25,701		11,402		562,813		785,431
9/30/2019		28,411		16,323		591,773		860,177
6/30/2019		27,895		15,797		526,138		788,290

Working Interest Production for the last five quarters was as follows:

Quarter ended	Oil Bbls Sold		NGL Bbls Sold		Mcf Sold		Mcfe Sold
6/30/2020		26,670		18,595		817,660		1,089,251
3/31/2020		39,064		31,299		979,368		1,401,546
12/31/2019		40,179		27,828		1,085,014		1,493,056
9/30/2019		47,523		35,896		1,194,394		1,694,908
6/30/2019		68,170		38,106		1,192,423		1,830,079

Lease Bonuses and Rental Income:

When the Company leases its mineral interests, an upfront cash payment, or lease bonus, is generally received. Lease bonuses and rental income decreased $206,079 in the 2020 quarter.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net asset of $1,679,511 as of June 30, 2020, and a net asset of $2,711,509 as of June 30, 2019. The Company had a net loss on derivative contracts of $838,282 in the 2020 quarter as compared to a net gain of $2,313,195 in the 2019 quarter. During the 2020 quarter, oil and natural gas collars and fixed price swaps experienced an unfavorable change as NYMEX futures experienced an increase in price during the quarter in relation to their previous position to the collars and the fixed prices of the swaps at the beginning of the 2020 quarter. During the 2019 quarter, the oil collars and fixed price swaps experienced a favorable change as NYMEX oil futures experienced a decrease in price during the quarter in relation their previous position to the collars and the fixed prices of the swaps at the beginning of the 2019 quarter. The Company utilizes derivative contracts for the purpose of protecting its return on investments and cash flow. Net cash receivedrelated to derivative contracts settled during the quarter ended June 30, 2020, was $1,699,122 compared to net cash receivedof $418,892 in the same period in the prior year.

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Costs and Expenses:

Lease Operating Expenses (LOE):

The Company is responsible for a portion of LOE relating to a well as a working interest owner. LOE includes normally recurring expenses associated with our working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Total LOE related to field operating costs decreased $471,742 or 29% in the 2020 quarter compared to 2019 quarter. LOE per Mcfe decreased in the 2020 quarter to $0.60 compared to $0.62 in the 2019 quarter. The decrease in LOE per Mcfe is the result of lower gas balancing expenses of $145,807 compared to the 2019 quarter. Had the company not experienced the decrease in gas balancing expenses in the 2019 and 2020 quarters, LOE per Mcfe would have been $0.60 in the 2020 quarter compared to $0.56 in the 2019 quarter. The increase in LOE per Mcfe is primarily the result of production decreasing 27% in the 2020 quarter.

Transportation, Gathering and Marketing:

Transportation, gathering and marketing decreased $572,617 or 37% in the 2020 quarter. This decrease in costs was primarily driven by lower natural gas production in the 2020 quarter compared to the 2019 quarter. Natural gas sales bear the large majority of our transportation, gathering and marketing fees. On a per Mcfe basis, these handling fees were $0.50 in the 2020 quarter as compared to $0.58 in the 2019 quarter. The decrease in rate was principally due to prior period adjustments in the 2020 quarter, which reduced the overall transportation, gathering and marketing fees. Had these adjustments not taken place, our transportation, gathering and marketing fees on a per Mcfe basis would have been $0.55.

Production Taxes:

Production taxes decreased $354,530 or 73% in the 2020 quarter. The decrease in amount was primarily the result of decreased oil, NGL and natural gas sales of $6,264,776 in the 2020 quarter as compared to the 2019 quarter.

Depreciation, Depletion and Amortization (DD&A):

DD&A is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. DD&A decreased $1,918,475 or 44% in the 2020 quarter. DD&A in the 2020 quarter was $1.29 per Mcfe as compared to $1.67 per Mcfe in the 2019 quarter. $1,193,410 of the decrease was a result of production decreasing 27% in the 2020 quarter. Also, DD&A decreased $725,065 as a result of a $0.38 decrease in the DD&A rate per Mcfe. The rate decrease was mainly due to impairments taken at the end of fiscal 2019 and the 2020 second quarter, which lowered the basis of the assets. The rate decrease was partially offset by lower oil, NGL and natural gas prices utilized in the reserve calculations during the 2020 quarter, as compared to the 2019 quarter, 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 forImpairment:

Provision for impairment was $358,826 in the 2020 quarter as compared to no provision for impairment in the 2019 quarter. During the 2020 quarter, impairment of $358,826 was recorded due to a title revision by the operator on one well, and as a result, the remaining cost basis was written off.

Interest expense:

Interest expense was $241,191 in the 2020 quarter as compared to $526,677 in the 2019 quarter. The decrease in interest expense is due to a lower average debt balance in the 2020 quarter as compared to the 2019 quarter.

Income Taxes:

Income taxes changed $2,192,940, from a $1,315,000 provision in the 2019 quarter to a $877,940 benefit in the 2020 quarter. The effective tax rate changed from a 22% provision in the 2019 quarter to a 20% benefit in the 2020 quarter.

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.

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NINE MONTHS ENDED JUNE 30, 2020, COMPARED TO NINE MONTHS ENDED JUNE 30, 2019

Overview:

The Company recorded a nine-month net loss of $22,117,915, or $1.34 per share, in the 2020 period, as compared to net income of $15,408,842, or $0.92 per share, in the 2019 period. The change in net income (loss) was principally the result increased provision for impairment (non-cash), decreased oil, NGL and natural gas sales, decreased gains on derivative contacts and decreased gain on asset sales, partially offset by decreased lease operating expenses, decreased transportation, gathering and marketing expenses, decreased production taxes, decreased DD&A and changes in our tax provision (benefit).

Revenue:

Oil, NGL and Natural Gas Sales:

Revenue from oil, NGL and natural gas sales decreased $12,885,358 or 41% for the 2020 period. Oil, NGL and natural gas sales were down due to decreases in oil, NGL and natural gas prices of 23%, 40% and 35%, respectively, and decreases in oil, NGL and natural gas sales volumes of 15%, 26% and 14%, respectively. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the nine-month periods of fiscal 2020 and 2019:

	Oil Bbls		Average		NGL Bbls		Average		Mcf		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Nine months ended
6/30/2020		214,159	$	42.43		121,887	$	11.26		4,539,103	$	1.73		6,555,378	$	2.80
6/30/2019		253,265	$	55.01		164,040	$	18.88		5,300,594	$	2.68		7,804,424	$	4.00

Although production is down in all three product categories, it is notable that production is down for working interest volumes and slightly up for royalty interest volumes due to new royalty interest wells brought online, as compared to June 30, 2019. The primary factor for the oil production decrease is attributable to the Eagle Ford Shale working interest wells, where the natural decline of new wells brought online March 2019 is coupled with recent delays in performing mechanical repairs due to poor economics related to low oil prices. Additionally, decreases are also attributable to the natural decline of the working interest production base. Royalty interest oil production has increased, as new royalty interest wells are brought onto production on Panhandle minerals in the Bakken, STACK and SCOOP. NGL production decline is attributable to the natural decline of the working interest production base in liquid-rich gas areas of the STACK, SCOOP and Arkoma Stack. The decrease is partially offset by increased royalty interest production in the Bakken and SCOOP, related to new well drilling on Panhandle minerals. Natural gas volumes are lower as a result of the natural decline of working interest production base, along with recent production curtailments in response to market conditions in the STACK, SCOOP and Arkoma Stack. The decrease is partially offset by increased royalty interest production in the Bakken and SCOOP, related to new well drilling on Panhandle minerals.

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Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net asset of $1,679,511 as of June 30, 2020, and a net asset of $2,711,509 as of June 30, 2019. The Company had a net gain on derivative contracts of $2,415,401 in the 2020 period as compared to a net gain of $5,026,123 recorded in the 2019 period. The change was principally due to the oil and natural gas collars and fixed price swaps being less favorable in the 2019 period compared to the 2020 period, as NYMEX futures prices decreased, during both the 2019 and 2020 periods, in relation to where they were at the beginning of their respective periods. The Company utilizes derivative contracts for the purpose of protecting its return on investments. Net cash received related to derivative contracts settled during the nine-month period ended June 30, 2020, was $3,230,034 compared to net cash paid of $1,099,402 in the same period in the prior year.

Gain on Asset Sales:

Gain on asset sales was $3,275,996 in the 2020 period. In the first quarter of 2020, the Company sold 530 net mineral acres in Eddy County, New Mexico, for a gain of $3,272,888. During the 2019 period, the Company sold mineral acreage in Lea and Eddy Counties, New Mexico, for a gain of $9,096,938 and Martin County, Texas, for a gain of $4,017,787.

Costs and Expenses:

Lease Operating Expenses (LOE):

The Company is responsible for a portion of LOE relating to a well as a non-operated working interest holder. LOE includes normally recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. LOE decreased $767,931 or 17% in the 2020 period. This decrease was principally the result of the Company selling some marginal properties in fiscal 2019 which had higher operating costs and not participating in newly drilled wells. LOE per Mcfe remained consistent in the 2020 period to $0.59 compared to $0.59 in the 2019 period.

Transportation, Gathering and Marketing:

Transportation, gathering and marketing decreased $905,677 or 20% in the 2020 period. This decrease in costs was primarily driven by lower natural gas production in the 2020 period compared to the 2019 period. Natural gas sales bear the large majority of our transportation, gathering and marketing fees. On a per Mcfe basis, these handling fees were $0.56 in the 2020 period as compared to $0.59 in the 2019 period. The decrease in rate was principally due to increased oil sales as they made up a larger percentage of our total production in the 2020 period compared to the 2019 period, and increased royalty interest revenue, which has a lower deduct rate than working interest revenue. Oil sales incur much smaller transportation, gathering and marketing fees than NGL and natural gas.

Production taxes:

Production taxes decreased $729,754 in the 2020 period. The decrease in amount was primarily the result of decreased oil, NGL and natural gas sales of $12,885,358 in the 2020 period as compared to the 2019 period.

Depreciation, Depletion and Amortization (DD&A):

DD&A is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. DD&A decreased $3,026,918 or 26% in the 2020 period to $1.34 per Mcfe as compared to $1.51 per Mcfe in the 2019 period. DD&A decreased $1,886,059 as a result of production decreasing 16% in the 2020 period compared to the 2019 period. An additional decrease of $1,140,859 was the result of the $0.17 decrease in the DD&A rate per Mcfe. The rate decrease was mainly due to the impairments at the end of fiscal 2019 and the fiscal 2020 second quarter, which lowered the basis of the assets. The rate decrease was partially offset by lower oil, NGL and natural gas 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 for the 2020 period as compared to no provision for impairment in the 2019 period. During the 2020 period, impairment of $29,315,807 was recorded on seven different fields including the Fayetteville and Eagle Ford shales, which represent 89% of our total impairment. The Fayetteville Shale assets are dry-gas assets of which the

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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 $76.6 million 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. The remaining $588,721 of impairment was recorded on other assets. 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.

Interest expense:

Interest expense decreased $593,402 or 38% in the 2020 period. This decrease was mainly due to lower outstanding debt balances ($30.0 million at June 30, 2020, as compared to $41.5 million at June 30, 2019).

General and Administrative Costs (G&A):

G&A expenses are costs not directly associated with the production of oil and natural gas and include the cost of employee salaries and related benefits, office expenses, and fees for professional services. G&A increased $425,047 or 7% in the 2020 period. The increase was primarily the result of higher technical consulting and legal expenses, partially offset by lower personnel 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. The Company expects G&A to decrease going forward as a result of the personnel reduction and other G&A reduction efforts.

Income Taxes:

Income taxes changed $12,366,940, from a $4,756,000 provision in the 2019 period to a $7,610,940 benefit in the 2020 period. The effective tax rate changed from a 24% provision in the 2019 period to a 26% benefit in the 2020 period.

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.

LIQUIDITY AND CAPITAL RESOURCES

The Company had positive working capital of $3,949,324 at June 30, 2020, compared to positive working capital of $11,378,829 at September 30, 2019.

Liquidity:

Cash and cash equivalents were $2,025,081 as of June 30, 2020, compared to $6,160,691 at September 30, 2019, a decrease of $4,135,610. The decrease in cash is primarily associated with the purchase of additional producing mineral assets in December 2019 which was funded primarily from cash associated with the prior sale of non-producing minerals in a tax deferral, like kind exchange. Cash flows for the nine months ended June 30 are summarized as follows:

Net cash provided (used) by:

	2020			2019			Change
Operating activities	$	9,825,740		$	14,332,951		$	(4,507,211	)
Investing activities		(7,042,684	)		4,643,215			(11,685,899	)
Financing activities		(6,918,666	)		(17,978,191	)		11,059,525
Increase (decrease) in cash and cash equivalents	$	(4,135,610	)	$	997,975		$	(5,133,585	)

Operating activities:

Net cash provided by operating activities decreased $4,507,211 during the 2020 period, as compared to the 2019 period, primarily the result of the following:

• Increased net receipts on derivative contracts of $4,329,436.

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• Receipts of oil, NGL and natural gas sales (net of production taxes and gathering, transportation and marketing costs) and other decreased $10,084,612.

• Increased payments for G&A and other expense of $1,083,838 (includes severance to former CEO).

• Decreased field operating expenses of $786,019.

• Decreased interest payments of $540,894.

• Decreased lease bonus receipts of $385,859.

• Decreased income tax payments of $1,390,749.

Investing activities:

Net cash used by investing activities increased $11,685,899 during the 2020 period, as compared to the 2019 period, primarily due to higher acquisition costs of $5,183,550 and lower net proceeds from the sale of assets of $9,657,469, partially offset by lower payments of $3,153,472 for drilling and completion activity during 2020.

Financing activities:

Net cash used by financing activities decreased $11,059,525 during the 2020 period, as compared to the 2019 period, primarily the result of lower net payments on long-term debt of $4,075,000, decreased stock repurchases of $6,457,551 and a decrease of $526,974 in dividend payments as a result of a reduction in the Company’s quarterly dividend from $0.04 per share to $0.01 per share beginning with the June 2020 dividend payment.

Capital Resources:

Capital expenditures to drill and complete wells decreased $3,153,472 or 94% from the 2019 to the 2020 period 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, Panhandle 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, Panhandle 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.

The Company received lease bonus payments during fiscal 2020 totaling $582,458. 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 oil and natural gas price volatility, management continues to evaluate opportunities for product price protection through additional hedging of the Company’s future oil and natural gas production. See Note 10: Derivatives for a complete list of the Company’s outstanding derivative contracts at June 30, 2020, and Note 12: Subsequent Events for a listing of additional contracts entered into through August 11, 2020.

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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:

	Nine months ended
	June 30, 2020
Cash provided by operating activities	$	9,825,740
Cash provided (used) by:
Capital expenditures - acquisitions		(10,304,016	)
Capital expenditures - drilling and completion of wells		(196,168	)
Quarterly dividends of $0.09 per share		(1,486,031	)
Treasury stock purchases		(7,635	)
Net borrowings (payments) on credit facility		(5,425,000	)
Proceeds from sale of assets		3,457,500
Net cash used		(13,961,350	)
Net increase (decrease) in cash	$	(4,135,610	)

Outstanding borrowings on the credit facility at June 30, 2020, were $30,000,000, of which $2,000,000 is classified as current debt.

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 million at June 30, 2020, under its Credit Facility and is 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, and includes 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 oil and natural gas 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 next expected redetermination will occur in December 2020. Net debt as of August 11, 2020 was $26.9 million.

On November 6, 2017, the Company filed a shelf registration statement with the SEC on Form S-3. This filing authorizes the Company to sell up to $75 million in securities, including common stock, preferred stock, debt securities, warrants and units in amounts to be determined at the time of an offering. Any such offering, if it does occur, may take place in one or more transactions. The specific terms of any securities to be sold will be described in supplemental filings with the SEC. The registration statement will expire on November 6, 2020.

Going forward, we expect that capital expenditures to drill and complete wells will be immaterial. Anticipated cash provided by operating activities may be reduced due to more frequent production stoppages, as it is currently not economic for some operators to continue to produce. Based on anticipated cash provided by operating activities for 2020 and availability under the Credit Facility, the Company has sufficient liquidity to fund its ongoing operations.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical accounting policies are those the Company believes are most important to portraying its financial conditions and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. Other than the adoption of ASC 842 on October 1, 2019, (see Note 2: Leases) there have been no material changes to the critical accounting policies previously disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2019.

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CONTRACTUAL OBLIGATIONS

There were no material changes in our contractual obligations and other commitments as disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2019.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue, especially in light of the ongoing COVID-19 pandemic and related economic repercussions. The financial condition, liquidity and results of operations of the Company may be adversely impacted by precipitous changes in oil and natural gas prices. The market price of oil, NGL and natural gas in 2020 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2020 derivative contracts, the price sensitivity in 2020 for each $1.00 per barrel change in wellhead oil price is $329,199 for operating revenue based on the Company’s prior year oil volumes. The price sensitivity in 2020 for each $0.10 per Mcf change in wellhead natural gas price is $708,676 for operating revenue based on the Company’s prior year natural gas volumes.

Commodity Price Risk

The Company utilizes derivative contracts to reduce its exposure to unfavorable changes in oil and natural gas prices. The Company does not enter into these derivatives for speculative or trading purposes. The Company’s derivative contracts are currently 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 price protection against declines in oil and natural gas prices and limit the benefit of future increases in prices. 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 $164,000. 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 $31,000. 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 $174,000. For the Company’s natural gas collars, a change of $.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 $1,641,000.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Credit Facility. Borrowings under the Credit Facility bear 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 June 30, 2020, the Company had $30,000,000 outstanding under the Credit Facility and the effective interest rate was 4.25%. At this point, the Company does not believe that its liquidity has been materially affected by the interest rate uncertainties noted in the last few years and the Company does not believe that its liquidity to fund its ongoing operations will be significantly impacted in the near future.

ITEM 4 CONTROLS AND PROCEDURES

The Company maintains “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the 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 they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this Form 10-Q, the Chief Executive Officer and Chief Financial Officer have concluded the Company’s disclosure controls and procedures were effective to ensure material information relating to the Company is made known to them. Certain changes were made to the Company’s internal controls subsequent to the fiscal quarter for validating the Company’s interest in new wells to remediate the material weakness identified in the second quarter. Specifically, management implemented an additional control consisting of validating ownership by review of source documentation for the new well revenue accrual, and has determined that the control is now operating effectively. Also, during the

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quarter, there were changes to the Company’s key control owners. However, no changes to the control operating effectiveness is expected as the key controls are still in place.  

PART II OTHER INFORMATION

ITEM 1A   RISK FACTORS

Please refer to Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2019. There have been no material changes to our risk factors contained in our Annual Report on Form 10-K for the fiscal year ended September 30, 2019, other than as detailed below.

Failure to maintain effective internal controls in future periods could impact the Company’s ability to report accurately and on a timely basis our financial condition and results of operations.

We are subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, the Sarbanes-Oxley Act of 2002 (“SOX”) and the NYSE rules and regulations. SOX requires, among other things, that we maintain effective disclosure controls and procedures and internal control over financial reporting. We perform system and process evaluation and testing of our internal controls over financial reporting to allow management to report on the effectiveness of our internal control over financial reporting in our Annual Report on Form 10-K filing for each year, as required by Section 404 of SOX. We previously had identified a material weakness in our internal control over financial reporting relating to the completeness and accuracy of the Company’s oil, NGL and natural gas sales revenue accrual, which weaknesses existed during, and was reported in our Quarterly Report on Form 10-Q for, the period ended March 31, 2020. To remediate this material weakness, changes were subsequently made to the Company’s internal control for validating the Company’s interests in new wells. Specifically, management implemented an additional control that requires the validation of interest ownership by a review of source documentation for the new well revenue accrual, which control management believes is now operating effectively.

While we believe we have remediated the material weaknesses as of June 30, 2020, we cannot assure you that this or any other material weakness will not continue to exist or occur or otherwise be discovered in the future. Any failure to maintain internal controls over financial reporting could result in material weaknesses or material misstatements in our financial statements in the future. Any such failure could harm our financial condition and operating results and could cause stockholders to lose confidence in our reported financial information. Any such loss of confidence would have a negative effect on the trading price of our securities, including shares of our common stock.

The ongoing COVID-19 pandemic and the recent OPEC+ price war could disrupt our operations and adversely impact our business and financial results.

The COVID-19 pandemic has resulted in a significant decline in worldwide economic activity, which has led to a precipitous decline in oil prices in response to demand concerns, further exacerbated by the early March 2020 failure by OPEC+ to reach an agreement over proposed oil production cuts and global storage considerations. Oil and natural gas prices are expected to continue to be volatile as a result of these events and the COVID-19 outbreak, and as changes in oil and natural gas inventories, oil demand and economic performance are reported. The COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand.

In the event oil prices remain low, there is a risk that, among other things:

• the Company’s revenues, cash flows and profitability may decline substantially, which could also indirectly impact expected production by reducing the amount of funds available to acquire future mineral and royalty interests;

• the Company’s access to capital sources could be restricted, which could lead to reduced liquidity;

• reserves relating to the Company’s producing properties may become uneconomic to produce resulting in impairment of producing properties; and

• operators and other working interest owners may be unable to execute their drilling and exploration programs resulting in lower production or inability to prove reserves on nonproducing properties.

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The occurrence of certain of these events could have a material adverse effect on the Company’s business and financial results. We cannot predict when prices will improve or stabilize. The COVID-19 pandemic may also intensify the risks described in other risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2019.

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended June 30, 2020, the Company did not repurchase any shares of the Company’s common stock.

Upon approval by the shareholders of the 2010 Stock Plan in March 2010, as amended in May 2018, the Board approved to continue 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 $1.5 million 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 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.

ITEM 6 EXHIBITS

(a)	EXHIBITS	Exhibit 31.1 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002
		Exhibit 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002
		Exhibit 32.1 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002
		Exhibit 32.2 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002
		Exhibit 101.INS – XBRL Instance Document
		Exhibit 101.SCH – XBRL Taxonomy Extension Schema Document
		Exhibit 101.CAL – XBRL Taxonomy Extension Calculation Linkbase Document
		Exhibit 101.LAB – XBRL Taxonomy Extension Labels Linkbase Document
		Exhibit 101.PRE – XBRL Taxonomy Extension Presentation Linkbase Document
		Exhibit 101.DEF – XBRL Taxonomy Extension Definition Linkbase Document

SIGNATURES

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

PANHANDLE OIL AND GAS INC.
	PANHANDLE OIL AND GAS INC.
August 13, 2020	/s/ Chad L. Stephens
Date	Chad L. Stephens, President,
	Chief Executive Officer
August 13, 2020	/s/ Ralph D’Amico
Date	Ralph D’Amico, Vice President,
	Chief Financial Officer

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EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Chad L. Stephens, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Panhandle Oil and Gas Inc. (the Company);

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(s) 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 (the registrant’s fourth fiscal quarter in the case of an annual report) 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(s) 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: August 13, 2020

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Ralph D’Amico, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Panhandle Oil and Gas Inc. (the Company);

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(s) 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 (the registrant’s fourth fiscal quarter in the case of an annual report) 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(s) 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: August 13, 2020

EX-32.1

EXHIBIT 32.1

Panhandle Oil and Gas 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 Panhandle Oil and Gas Inc., (the “Issuer”), 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 Issuer’s Quarterly Report on Form 10-Q for the period that ended June 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 Issuer.

/s/ Chad L. Stephens

Chad L. Stephens

President,

Chief Executive Officer

August 13, 2020

EX-32.2

EXHIBIT 32.2

Panhandle Oil and Gas 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 Panhandle Oil and Gas Inc., (the “Issuer”), 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 Issuer’s Quarterly Report on Form 10-Q for the period that ended June 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 Issuer.

/s/ Ralph D’Amico

Ralph D’Amico

Vice President,

Chief Financial Officer

August 13, 2020

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Document and Entity Information - shares	9 Months Ended
	Jun. 30, 2020	Aug. 13, 2020
Cover [Abstract]
Entity Registrant Name	PANHANDLE OIL & GAS INC,
Entity Central Index Key	0000315131
Document Type	10-Q
Document Period End Date	Jun. 30, 2020
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
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
Document Quarterly Report	true
Document Transition Report	false
Entity Common Stock, Shares Outstanding		16,413,718
Title of each class	Class A Common Stock, $0.01666 par value
Trading Symbol(s)	PHX
Name of each exchange on which registered	NYSE

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Condensed Balance Sheets - USD ($)		Jun. 30, 2020	Sep. 30, 2019
Current assets:
Cash and cash equivalents		$ 2,025,081	$ 6,160,691
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		2,183,216	4,377,646
Refundable income taxes		1,640,350	1,505,442
Derivative contracts, net	[1]	1,819,977	2,256,639
Other		490,697	177,037
Total current assets		8,159,321	14,477,455
Net properties and equipment, based on successful efforts method of accounting		83,038,001	111,427,021
Investments		113,408	205,076
Derivative contracts, net	[1]		237,505
Deferred income taxes, net		181,993
Other, net		231,387	297,890
Total assets		91,724,110	126,644,947
Current liabilities:
Accounts payable		724,289	665,160
Accrued liabilities and other		1,485,708	2,433,466
Short-term debt		2,000,000
Total current liabilities		4,209,997	3,098,626
Long-term debt		28,000,000	35,425,000
Deferred income taxes, net			5,976,007
Asset retirement obligations		2,871,603	2,835,781
Derivative contracts, net	[1]	140,466
Stockholders' equity:
Class A voting common stock, $0.01666 par value; 24,000,500 shares authorized; 16,897,306 issued at June 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		281,509	281,509
Capital in excess of par value		3,375,400	2,967,984
Deferred directors' compensation		1,829,786	2,555,781
Retained earnings		58,244,355	81,848,301
Stockholders' Equity		63,731,050	87,653,575
Less treasury stock, at cost; 483,588 shares at June 30, 2020, and 558,051 shares at September 30, 2019		(7,229,006)	(8,344,042)
Total stockholders' equity		56,502,044	79,309,533
Total liabilities and stockholders' equity		$ 91,724,110	$ 126,644,947

[1] See Note 11: Fair Value Measurements for further disclosures regarding fair value of financial instruments.

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Condensed Balance Sheets (Parenthetical) - $ / shares	Jun. 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	16,897,306	16,897,306
Treasury stock, shares	483,588	558,051

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Condensed Statements Of Operations - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Revenues:
Revenues	$ 3,517,561	$ 9,782,337	$ 18,329,017	$ 31,214,375
Gains (losses) on derivative contracts	(838,282)	2,313,195	2,415,401	5,026,123
Gain on asset sales	3,108	4,017,787	3,275,996	13,114,725
Revenues	2,705,383	16,342,394	24,593,201	50,307,601
Costs and expenses:
Lease operating expenses	1,147,948	1,619,690	3,871,818	4,639,749
Transportation, gathering and marketing	956,653	1,529,270	3,696,282	4,601,959
Production taxes	134,249	488,779	835,284	1,565,038
Depreciation, depletion and amortization	2,464,568	4,383,043	8,793,787	11,820,705
Provision for impairment	358,826		29,904,528
Interest expense	241,191	526,677	958,429	1,551,831
General and administrative	1,908,790	1,809,439	6,306,479	5,881,432
Other expense (income)	(73,687)	66,260	(44,551)	82,045
Total costs and expenses	7,138,538	10,423,158	54,322,056	30,142,759
Income (loss) before provision (benefit) for income taxes	(4,433,155)	5,919,236	(29,728,855)	20,164,842
Provision (benefit) for income taxes	(877,940)	1,315,000	(7,610,940)	4,756,000
Net income (loss)	$ (3,555,215)	$ 4,604,236	$ (22,117,915)	$ 15,408,842
Basic and diluted earnings (loss) per common share	$ (0.21)	$ 0.28	$ (1.34)	$ 0.92
Basic and diluted weighted average shares outstanding:
Common shares	16,403,243	16,515,498	16,375,736	16,646,828
Unissued, directors' deferred compensation shares	141,799	170,066	152,500	183,206
Basic and diluted weighted average shares outstanding	16,545,042	16,685,564	16,528,236	16,830,034
Dividends declared per share of common stock and paid in period	$ 0.01	$ 0.04	$ 0.09	$ 0.12
Oil, NGL and Natural Gas [Member]
Revenues:
Revenues	$ 3,517,561	$ 9,782,337	$ 18,329,017	$ 31,214,375
Lease Bonuses and Rental Income [Member]
Revenues:
Revenues	$ 22,996	$ 229,075	$ 572,787	$ 952,378

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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, 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)	12,735,940				12,735,940
Purchase of treasury stock	(1,140,559)					$ (1,140,559)
Purchase of treasury stock, shares						(74,457)
Restricted stock awards	159,469		159,469
Dividends	(1,347,789)				(1,347,789)
Distribution of restricted stock to officers and directors	160	$ 7	(159,869)			$ 160,022
Distribution of restricted stock to officers and directors, shares		425				9,194
Distribution of deferred Directors' compensation			(8)	8
Increase in deferred directors' compensation charged to expense	80,287			80,287
Balances at Dec. 31, 2018	139,252,713	$ 281,509	2,824,283	3,030,700	136,655,096	$ (3,538,875)
Balances, shares at Dec. 31, 2018		16,897,306
Balances, Treasury shares at Dec. 31, 2018						(210,730)
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)	15,408,842
Balances at Jun. 30, 2019	136,500,196	$ 281,509	2,937,874	2,481,109	138,662,782	$ (7,863,078)
Balances, shares at Jun. 30, 2019		16,897,306
Balances, Treasury shares at Jun. 30, 2019						(508,582)
Balances at Dec. 31, 2018	139,252,713	$ 281,509	2,824,283	3,030,700	136,655,096	$ (3,538,875)
Balances, shares at Dec. 31, 2018		16,897,306
Balances, Treasury shares at Dec. 31, 2018						(210,730)
Net income (loss)	(1,931,334)				(1,931,334)
Purchase of treasury stock	(2,827,126)					$ (2,827,126)
Purchase of treasury stock, shares						(175,175)
Restricted stock awards	286,852		286,852
Dividends	(381)				(381)
Distribution of restricted stock to officers and directors	75		(73,069)			$ 73,144
Distribution of restricted stock to officers and directors, shares						4,441
Distribution of deferred Directors' compensation	(3)		(207,842)	(667,124)		$ 874,963
Distribution of deferred directors' compensation, shares						52,399
Increase in deferred directors' compensation charged to expense	51,993			51,993
Balances at Mar. 31, 2019	134,832,789	$ 281,509	2,830,224	2,415,569	134,723,381	$ (5,417,894)
Balances, shares at Mar. 31, 2019		16,897,306
Balances, Treasury shares at Mar. 31, 2019						(329,065)
Net income (loss)	4,604,236				4,604,236
Purchase of treasury stock	(2,497,501)					$ (2,497,501)
Purchase of treasury stock, shares						(182,901)
Restricted stock awards	159,911		159,911
Dividends	(664,835)				(664,835)
Distribution of restricted stock to officers and directors	56		(52,261)			$ 52,317
Distribution of restricted stock to officers and directors, shares						3,384
Increase in deferred directors' compensation charged to expense	65,540			65,540
Balances at Jun. 30, 2019	136,500,196	$ 281,509	2,937,874	2,481,109	138,662,782	$ (7,863,078)
Balances, shares at Jun. 30, 2019		16,897,306
Balances, Treasury shares at Jun. 30, 2019						(508,582)
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)	$ 1,892,114				1,892,114
Purchase of treasury stock	(7,635)					$ (7,635)
Purchase of treasury stock, shares						(632)
Restricted stock awards	148,515		148,515
Dividends	(1,319,899)				(1,319,899)
Distribution of restricted stock to officers and directors	93		(82,821)			$ 82,914
Distribution of restricted stock to officers and directors, shares						5,546
Increase in deferred directors' compensation charged to expense	86,212			86,212
Balances at Dec. 31, 2019	80,108,933	$ 281,509	3,033,678	2,641,993	82,420,516	$ (8,268,763)
Balances, shares at Dec. 31, 2019		16,897,306
Balances, Treasury shares at Dec. 31, 2019						(553,137)
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)	$ (22,117,915)
Balances at Jun. 30, 2020	$ 56,502,044	$ 281,509	3,375,400	1,829,786	58,244,355	$ (7,229,006)
Balances, shares at Jun. 30, 2020		16,897,306
Balances, Treasury shares at Jun. 30, 2020	(483,588)					(483,588)
Balances at Dec. 31, 2019	$ 80,108,933	$ 281,509	3,033,678	2,641,993	82,420,516	$ (8,268,763)
Balances, shares at Dec. 31, 2019		16,897,306
Balances, Treasury shares at Dec. 31, 2019						(553,137)
Net income (loss)	(20,454,814)				(20,454,814)
Restricted stock awards	343,101		343,101
Distribution of deferred Directors' compensation	(1)		(112,396)	(603,485)		$ 715,880
Distribution of deferred directors' compensation, shares						47,885
Increase in deferred directors' compensation charged to expense	53,918			53,918
Balances at Mar. 31, 2020	60,051,137	$ 281,509	3,264,383	2,092,426	61,965,702	$ (7,552,883)
Balances, shares at Mar. 31, 2020		16,897,306
Balances, Treasury shares at Mar. 31, 2020						(505,252)
Net income (loss)	(3,555,215)				(3,555,215)
Restricted stock awards	128,196		128,196
Dividends	(166,132)				(166,132)
Distribution of deferred Directors' compensation			(17,179)	(306,698)		$ 323,877
Distribution of deferred directors' compensation, shares						21,664
Increase in deferred directors' compensation charged to expense	44,058			44,058
Balances at Jun. 30, 2020	$ 56,502,044	$ 281,509	$ 3,375,400	$ 1,829,786	$ 58,244,355	$ (7,229,006)
Balances, shares at Jun. 30, 2020		16,897,306
Balances, Treasury shares at Jun. 30, 2020	(483,588)					(483,588)

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Statements Of Stockholders' Equity (Parenthetical) - $ / shares	3 Months Ended
	Jun. 30, 2020	Dec. 31, 2019	Jun. 30, 2019	Dec. 31, 2018
Statement Of Stockholders Equity [Abstract]
Dividends per share	$ 0.01	$ 0.08	$ 0.04	$ 0.08

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Condensed Statements Of Cash Flows - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Sep. 30, 2019
Operating Activities
Net income (loss)			$ (22,117,915)	$ 15,408,842
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	$ 2,464,568	$ 4,383,043	8,793,787	11,820,705
Impairment of producing properties	358,826		29,904,528
Provision for deferred income taxes			(6,158,000)	5,150,000
Gain from leasing fee mineral acreage			(567,975)	(951,832)
Proceeds from leasing fee mineral acreage			582,458	967,337
Net (gain) loss on sales of assets			(3,258,994)	(13,114,725)
Directors' deferred compensation expense			184,188	197,820
Total (gain) loss on derivative contracts	838,282	(2,313,195)	(2,415,401)	(5,026,123)
Cash receipts (payments) on settled derivative contracts			3,230,034	(1,099,402)
Restricted stock awards	128,196	159,911	619,812	606,232
Other			3,718	15,848
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables			2,194,430	1,597,667
Other current assets			(121,635)	(859,258)
Accounts payable			31,755	3,270
Income taxes receivable			(134,908)	(476,846)
Other non-current assets			6,544	6,949
Accrued liabilities			(950,686)	86,467
Total adjustments			31,943,655	(1,075,891)
Net cash provided by operating activities			9,825,740	14,332,951
Investing Activities
Capital expenditures			(196,168)	(3,349,640)
Acquisition of minerals and overrides			(10,304,016)	(5,120,466)
Investments in partnerships				(1,648)
Proceeds from sales of assets			3,457,500	13,114,969
Net cash provided (used) by investing activities			(7,042,684)	4,643,215
Financing Activities
Borrowings under Credit Facility			6,061,725	15,053,345
Payments of loan principal			(11,486,725)	(24,553,345)
Purchases of treasury stock			(7,635)	(6,465,186)
Payments of dividends			(1,486,031)	(2,013,005)
Net cash provided (used) by financing activities			(6,918,666)	(17,978,191)
Increase (decrease) in cash and cash equivalents			(4,135,610)	997,975
Cash and cash equivalents at beginning of period			6,160,691	532,502	$ 532,502
Cash and cash equivalents at end of period	$ 2,025,081	$ 1,530,477	2,025,081	1,530,477	$ 6,160,691
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations			4	27,782
Gross additions to properties and equipment			10,335,534	8,149,347
Net (increase) decrease in accounts payable for properties and equipment additions			164,650	320,759
Capital expenditures and acquisitions			$ 10,500,184	$ 8,470,106

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Basis of Presentation and Accounting Principles

9 Months Ended

Jun. 30, 2020

Accounting Policies [Abstract]

Basis of Presentation and Accounting Principles

NOTE 1: Basis of Presentation and Accounting Principles

Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1 through September 30.

Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2019. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Panhandle” or “Company” refer to Panhandle Oil and Gas Inc.

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 is evaluating the new standard and is currently in the process of estimating its financial statement impact; however, the impact is not expected to be material. Historically, the Company's credit losses on oil, NGL and natural gas 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

9 Months Ended

Jun. 30, 2020

Leases [Abstract]

Leases

NOTE 2: Leases

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 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 June 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 lease for office space during the quarter ended March 31, 2020, with a commencement date in the fourth quarter of 2020. The associated lease liability and ROU asset will be recognized at that time and is estimated to be approximately $1 million.

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 lease 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, 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.

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Revenues

9 Months Ended

Jun. 30, 2020

Revenue From Contract With Customer [Abstract]

Revenues

NOTE 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 oil, NGL or natural gas 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.

Oil and natural gas derivative contracts

See Note 10 for discussion of the Company’s accounting for derivative contracts.

Revenues from Contracts with Customers

Oil, NGL and natural gas sales

Sales of oil, NGL and natural gas 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 oil, NGL and natural gas revenues

The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the three and nine months ended June 30, 2020 and 2019:

	Three Months Ended June 30, 2020						Nine Months Ended June 30, 2020
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Oil revenue	$	719,012	$	711,005	$	1,430,017	$	4,680,871	$	4,404,949	$	9,085,820
NGL revenue		129,833		103,023		232,856		548,921		823,559		1,372,480
Natural gas revenue		792,227		1,062,461		1,854,688		3,122,951		4,747,766		7,870,717
Oil, NGL and natural gas sales	$	1,641,072	$	1,876,489	$	3,517,561	$	8,352,743	$	9,976,274	$	18,329,017
	Three Months Ended June 30, 2019						Nine Months Ended June 30, 2019
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Oil revenue	$	1,640,247	$	3,883,220	$	5,523,467	$	5,496,433	$	8,435,619	$	13,932,052
NGL revenue		310,581		515,701		826,282		938,692		2,158,787		3,097,479
Natural gas revenue		1,172,272		2,260,316		3,432,588		4,614,537		9,570,307		14,184,844
Oil, NGL and natural gas sales	$	3,123,100	$	6,659,237	$	9,782,337	$	11,049,662	$	20,164,713	$	31,214,375

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 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 Oil, NGL and natural gas sales receivables line item on the Company’s Balance Sheets. The difference between the Company's estimates and the actual amounts received for oil, NGL and natural gas sales is recorded in the quarter that payment is received from the third party. For the three and nine months ended June 30, 2019, 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.

As noted above, as a non-operator, there are instances when the Company is limited by the information operators provide to us. Through the use of new technological platforms as well as cash received on new wells, in the 2020 third quarter, the Company identified several producing properties on our minerals that had production dates prior to the 2020 third quarter. Estimates of the oil and natural gas sales related to those properties were made and are reflected in the third quarter Oil, NGL and natural gas sales on the Company’s Statements of Operations and on the Company’s Balance Sheets in Oil, NGL and natural gas sales receivables. In connection with obtaining more relevant information identifying additional new wells on Panhandle acreage, we have recorded a change in estimate for new wells to Oil, NGL and natural gas sales totaling $259,336 of which $164,115 related to the production periods before October 1, 2019, and $95,221 related to the first and second quarters of 2020. This reduced loss before benefit for income taxes by $237,341 in the three and nine months ended June 30, 2020. This resulted in decreases in both net loss of $189,873 and $0.01 loss per common share for the three months ended June 30, 2020, and decreases in both net loss of $175,632 and $0.01 loss per common share for the nine months ended June 30, 2020.

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Income Taxes

9 Months Ended

Jun. 30, 2020

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 4: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from 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. Excess tax benefits and deficiencies of stock-based compensation are recognized as provision (benefit) for income taxes in the Company’s Statements of Operations.

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. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with detailed well-by-well calculations at fiscal year-end. 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 nine months ended June 30, 2020, was a 26% benefit as compared a 24% provision for the nine months ended June 30, 2019. The effective tax rate for the quarter ended June 30, 2020, was a 20% benefit as compared to a 22% provision for the quarter ended June 30, 2019.

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. 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. In addition to the acceleration of the AMT refund, an additional $31,127 was recognized as an income tax benefit as a result of the NOL carryback provision allowing the Company to use the previously enacted tax rate of 34% rather than the current tax rate of 21%.  

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Basic And Diluted Earnings (Loss) Per Common Share

9 Months Ended

Jun. 30, 2020

Earnings Per Share [Abstract]

Basic And Diluted Earnings (Loss) Per Common Share

NOTE 5: Basic and Diluted Earnings (Loss) per Common Share

Basic and diluted earnings (loss) per common share is calculated using net income (loss) divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares during the period. 

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Long-Term Debt

9 Months Ended

Jun. 30, 2020

Debt Disclosure [Abstract]

Long-Term Debt

NOTE 6: Long-Term Debt

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a borrowing base of $32,000,000 as of June 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 its 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 oil and gas 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 the ratio of loan balance to the borrowing base increases. At June 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 June 30, 2020 was $231,387. 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 discretion, believe that there has been a material change in the value of the oil and natural gas properties. On June 24, 2020, the Company entered into the seventh amendment to its amended and restated credit agreement. The amendment reduced the borrowing base from $45,000,000 to $32,000,000 and includes 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 is expected to occur in December 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 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 June 30, 2020, the Company was in compliance with the covenants of the Credit Facility, had $30,000,000 outstanding, of which $2,000,000 is classified as short-term debt due to the Quarterly Commitment Reduction, and had $2,000,000 of borrowing base availability under the Credit Facility.

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Deferred Compensation Plan For Non-Employee Directors

9 Months Ended

Jun. 30, 2020

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Deferred Compensation Plan For Non-Employee Directors

NOTE 7: Deferred Compensation Plan for Non-Employee Directors

Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. This plan provides that each outside 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. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination, death or a change-in-control of the Company will the shares recorded for such director be issued under this plan. Directors may elect to receive shares, when issued, over annual time periods up to ten years. The promise to issue such shares in the future is an unsecured obligation of the Company.

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Restricted Stock Plan

9 Months Ended

Jun. 30, 2020

Restricted Stock Plan [Abstract]

Restricted Stock Plan

NOTE 8: Restricted Stock Plan

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

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. Upon vesting, the market-based shares that do not meet certain market performance criteria 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 vests on December 31, 2020. The restricted stock contains non-forfeitable rights to receive dividends and to vote the shares during the vesting period. 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 with a nominal value at their award date.

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. The performance-based shares had a nominal value at their award date.

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 three and nine months ended June 30, 2020 and 2019, related to the Company’s market-based, time-based and performance-based restricted stock:

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2020		2019		2020		2019
Market-based, restricted stock	$	10,247	$	60,406	$	285,150	$	306,685
Time-based, restricted stock		117,949		99,505		334,662		299,547
Performance-based, restricted stock		-		-		-		-
Total compensation expense	$	128,196	$	159,911	$	619,812	$	606,232

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:

	As of June 30, 2020
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	77,900		2.06
Time-based, restricted stock		676,667		2.09
Performance-based, restricted stock		-
Total	$	754,567

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Properties And Equipment

9 Months Ended

Jun. 30, 2020

Property Plant And Equipment [Abstract]

Properties And Equipment

NOTE 9: Properties and Equipment

Properties and equipment and related accumulated DD&A as of June 30, 2020, and September 31, 2019, are as follows:

	June 30, 2020			September 30, 2019
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		324,913,067			354,718,398
Non-producing oil and natural gas properties		19,081,485			14,599,023
Other property and equipment		777,104			717,121
		344,771,656			370,034,542
Less accumulated depreciation, depletion and amortization		(261,733,655	)		(258,607,521	)
Net properties and equipment		83,038,001			111,427,021

Divestitures

During the second and third quarters of 2020, the Company had no significant divestitures.

During the first quarter of 2020, Panhandle 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, $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.

During the third quarter of 2019, the Company sold 166 net mineral acres and producing oil and natural gas properties located in Martin County, Texas, to private buyers for total net consideration of $4.0 million and recorded a gain on the sale of $4.0 million. The cash from the sale was used to purchase minerals and reduce the Company’s outstanding bank debt.

During the second quarter of 2019, the Company had no divestitures.

During the first quarter of 2019, the Company sold 206 net mineral acres and producing oil and natural gas properties located in Lea and Eddy Counties, New Mexico, to a private buyer for total net consideration of $9.1 million and recorded a gain on the sale of $9.1 million. The cash from the sale was used to reduce the Company’s outstanding debt under the Credit Facility.

Acquisitions

During the second and third quarters of 2020, the Company had no significant acquisitions.

During the first quarter of 2020, Panhandle 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).

During the third quarter of 2019, the Company acquired 313 net mineral acres (which include producing oil and natural gas properties) in the Bakken/Three Forks play in North Dakota and in the STACK play in Blaine County, Oklahoma, for $3.3 million.

During the second quarter of 2019, the Company acquired 329 net mineral acres (which include producing oil and natural gas properties) in the STACK play in Blaine and Caddo Counties, Oklahoma, for $1.4 million.

During the first quarter of 2019, the Company acquired 45 net mineral acres (which include producing oil and natural gas properties) in the STACK play in Blaine County, Oklahoma, with undeveloped locations identified in both the Woodford and Meramac Shales for $0.4 million.

Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for retirement of assets and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geologic and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing appropriate prices for the current period. The estimated oil, NGL and natural gas reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, NGL and natural gas price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Crude oil, NGL and natural gas prices are volatile and affected by worldwide production and consumption and are outside the control of management (see Item 1A: Risk Factors for a further discussion of price volatility).

Impairment

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as: inflation rates; future drilling and completion costs; future sales prices for oil, NGL and natural gas; future production costs; estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof; the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For the nine months ended June 30, 2020, the assessment resulted in an impairment provision on producing properties of $29,315,807, primarily due to the decline in commodity prices caused by the ongoing COVID-19 pandemic and the early March 2020 failure by a group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts (see Item 1A: Risk Factors). During the three and nine months ended June 30, 2020, impairment on wells that were written off totaled $358,826 and $588,721, respectively. For the three and nine months ended June 30, 2019, the assessment resulted in no impairment provisions on producing properties.

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, are the primary reason for impairment in this field. The Company recognized an impairment related to the Eagle Ford at September 30, 2019, of $76.6 million 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, is due to the decline in commodity prices over fiscal 2020.

A further reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.

Asset Retirement Obligation

	June 30, 2020			June 30, 2019
Asset retirement obligations as of beginning of the year	$	2,835,781		$	2,809,378
Wells acquired or drilled		4			27,782
Wells sold or plugged		(61,985	)		(9,669	)
Accretion of discount		97,803			99,996
Asset retirement obligations as of end of period	$	2,871,603		$	2,927,487

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Derivatives

9 Months Ended

Jun. 30, 2020

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivatives

NOTE 10: Derivatives

The Company has entered into commodity price derivative agreements, including fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. 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. 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. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. The Company’s derivative contracts are currently with Bank of Oklahoma. The derivative contracts with Bank of Oklahoma are secured under the Credit Facility with Bank of Oklahoma (see Note 6: Long-Term Debt). The derivative instruments have settled or will settle based on the prices below:

Derivative contracts in place as of June 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
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 - December 2021	10,000 Mmbtu	NYMEX Henry Hub	$2.765
January 2021 - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$2.729
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
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 has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net asset of $1,679,511 as of June 30, 2020, and a net asset of $2,494,144 as of September 30, 2019. 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.

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	18,000		$	-		$	18,000		$	(191,200	)
Natural gas fixed price swaps		268,650			525,200			1,488,970			(294,940	)
Oil costless collars		625,968			(104,394	)		827,664			(359,564	)
Oil fixed price swaps		786,504			(1,914	)		895,400			(253,698	)
Cash received (paid) on derivative contracts, net	$	1,699,122		$	418,892		$	3,230,034		$	(1,099,402	)
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(60,035	)	$	-		$	(32,152	)	$	10,453
Natural gas fixed price swaps		(129,865	)		1,255,469			(815,630	)		2,177,594
Oil costless collars		(757,060	)		128,829			(283,255	)		1,516,144
Oil fixed price swaps		(1,590,444	)		510,005			316,404			2,421,334
Non-cash gain (loss) on derivative contracts, net	$	(2,537,404	)	$	1,894,303		$	(814,633	)	$	6,125,525
Gains (losses) on derivative contracts, net	$	(838,282	)	$	2,313,195		$	2,415,401		$	5,026,123

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 of whether or not to offset, 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 Company’s 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 June 30, 2020, and September 30, 2019. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at June 30, 2020, and September 30, 2019.

	June 30, 2020												September 30, 2019
	Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets		Non-Current Assets
Gross amounts recognized	$	2,028,640		$	208,663		$	57,386		$	197,852		$	2,256,639	$	237,505
Offsetting adjustments		(208,663	)		(208,663	)		(57,386	)		(57,386	)		-		-
Net presentation on Condensed Balance Sheets	$	1,819,977		$	-		$	-		$	140,466		$	2,256,639	$	237,505

(a) See Note 11: Fair Value Measurements for further disclosures regarding fair value of financial instruments.

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

9 Months Ended

Jun. 30, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

NOTE 11: 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 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2020:

	Fair Value Measurement at June 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	$	-	$	1,393,727	$	-	$	1,393,727
Derivative Contracts - Collars	$	-	$	285,784	$	-	$	285,784

Level 2 – Market Approach - The fair values of the Company’s swaps and collars are based on a third-party pricing model, which utilizes inputs that are either readily available in the public market, such as natural gas curves and volatility curves, or can be corroborated from active markets. These values are based upon future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

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:

	Quarter Ended June 30,
	2020				2019
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	-	$	-
	Nine Months Ended June 30,
	2020				2019
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	5,288,710	$	29,315,807	$	-	$	-

(a) When indicators of impairment are present, the Company assesses the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off during the three and nine months ended June 30, 2020, in the amounts of $358,826 and $588,721, respectively.

At June 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 long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s 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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Subsequent Events

9 Months Ended

Jun. 30, 2020

Subsequent Events [Abstract]

Subsequent Events

NOTE 12: Subsequent Events

Derivative Contracts

Subsequent to June 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
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
Oil costless collars
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 21	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 22	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 22	5,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling

Sale of Non-Producing Minerals

On July 28, 2020, the Company closed on the sale of 5,925 open and non-producing net mineral acres in Northwest Oklahoma for total proceeds of $793,617, with the proceeds applied toward debt reduction.

New Tax Regulations

On July 28, 2020, the U.S. Treasury Department released final regulations and proposed regulations with guidance on the business interest expense limitation under IRC Section 163(j). The Section 163(j) business interest expense limitation was modified in December 2017 by the Tax Cuts and Jobs Act, and in March 2020 by the CARES Act. Currently, we are in the process of evaluating the effect of these regulations on our consolidated financial statements and related disclosures.

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Basis of Presentation and Accounting Principles (Policies)

9 Months Ended

Jun. 30, 2020

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1 through September 30.

Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2019. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Panhandle” or “Company” refer to Panhandle Oil and Gas Inc.

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 is evaluating the new standard and is currently in the process of estimating its financial statement impact; however, the impact is not expected to be material. Historically, the Company's credit losses on oil, NGL and natural gas 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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Revenues (Tables)

9 Months Ended

Jun. 30, 2020

Revenue From Contract With Customer [Abstract]

Summary of Disaggregation of Oil, NGL and Natural Gas Revenues

The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the three and nine months ended June 30, 2020 and 2019:

	Three Months Ended June 30, 2020						Nine Months Ended June 30, 2020
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Oil revenue	$	719,012	$	711,005	$	1,430,017	$	4,680,871	$	4,404,949	$	9,085,820
NGL revenue		129,833		103,023		232,856		548,921		823,559		1,372,480
Natural gas revenue		792,227		1,062,461		1,854,688		3,122,951		4,747,766		7,870,717
Oil, NGL and natural gas sales	$	1,641,072	$	1,876,489	$	3,517,561	$	8,352,743	$	9,976,274	$	18,329,017
	Three Months Ended June 30, 2019						Nine Months Ended June 30, 2019
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Oil revenue	$	1,640,247	$	3,883,220	$	5,523,467	$	5,496,433	$	8,435,619	$	13,932,052
NGL revenue		310,581		515,701		826,282		938,692		2,158,787		3,097,479
Natural gas revenue		1,172,272		2,260,316		3,432,588		4,614,537		9,570,307		14,184,844
Oil, NGL and natural gas sales	$	3,123,100	$	6,659,237	$	9,782,337	$	11,049,662	$	20,164,713	$	31,214,375

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Restricted Stock Plan (Tables)

9 Months Ended

Jun. 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 three and nine months ended June 30, 2020 and 2019, related to the Company’s market-based, time-based and performance-based restricted stock:

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2020		2019		2020		2019
Market-based, restricted stock	$	10,247	$	60,406	$	285,150	$	306,685
Time-based, restricted stock		117,949		99,505		334,662		299,547
Performance-based, restricted stock		-		-		-		-
Total compensation expense	$	128,196	$	159,911	$	619,812	$	606,232

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:

	As of June 30, 2020
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	77,900		2.06
Time-based, restricted stock		676,667		2.09
Performance-based, restricted stock		-
Total	$	754,567

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Properties And Equipment (Tables)

9 Months Ended

Jun. 30, 2020

Property Plant And Equipment [Abstract]

Summary of Properties and Equipment and Related Accumulated DD&A

Properties and equipment and related accumulated DD&A as of June 30, 2020, and September 31, 2019, are as follows:

	June 30, 2020			September 30, 2019
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		324,913,067			354,718,398
Non-producing oil and natural gas properties		19,081,485			14,599,023
Other property and equipment		777,104			717,121
		344,771,656			370,034,542
Less accumulated depreciation, depletion and amortization		(261,733,655	)		(258,607,521	)
Net properties and equipment		83,038,001			111,427,021

Schedule of Asset Retirement Obligation

Asset Retirement Obligation

	June 30, 2020			June 30, 2019
Asset retirement obligations as of beginning of the year	$	2,835,781		$	2,809,378
Wells acquired or drilled		4			27,782
Wells sold or plugged		(61,985	)		(9,669	)
Accretion of discount		97,803			99,996
Asset retirement obligations as of end of period	$	2,871,603		$	2,927,487

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Derivatives (Tables)

9 Months Ended

Jun. 30, 2020

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of June 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
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 - December 2021	10,000 Mmbtu	NYMEX Henry Hub	$2.765
January 2021 - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$2.729
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
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 June 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
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
Oil costless collars
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 21	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 22	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 22	5,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling

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

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	18,000		$	-		$	18,000		$	(191,200	)
Natural gas fixed price swaps		268,650			525,200			1,488,970			(294,940	)
Oil costless collars		625,968			(104,394	)		827,664			(359,564	)
Oil fixed price swaps		786,504			(1,914	)		895,400			(253,698	)
Cash received (paid) on derivative contracts, net	$	1,699,122		$	418,892		$	3,230,034		$	(1,099,402	)
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(60,035	)	$	-		$	(32,152	)	$	10,453
Natural gas fixed price swaps		(129,865	)		1,255,469			(815,630	)		2,177,594
Oil costless collars		(757,060	)		128,829			(283,255	)		1,516,144
Oil fixed price swaps		(1,590,444	)		510,005			316,404			2,421,334
Non-cash gain (loss) on derivative contracts, net	$	(2,537,404	)	$	1,894,303		$	(814,633	)	$	6,125,525
Gains (losses) on derivative contracts, net	$	(838,282	)	$	2,313,195		$	2,415,401		$	5,026,123

Summary Of Derivative Contracts

	June 30, 2020												September 30, 2019
	Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets		Non-Current Assets
Gross amounts recognized	$	2,028,640		$	208,663		$	57,386		$	197,852		$	2,256,639	$	237,505
Offsetting adjustments		(208,663	)		(208,663	)		(57,386	)		(57,386	)		-		-
Net presentation on Condensed Balance Sheets	$	1,819,977		$	-		$	-		$	140,466		$	2,256,639	$	237,505

(a) See Note 11: Fair Value Measurements for further disclosures regarding fair value of financial instruments.

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Fair Value Measurements (Tables)

9 Months Ended

Jun. 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 as of June 30, 2020:

	Fair Value Measurement at June 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	$	-	$	1,393,727	$	-	$	1,393,727
Derivative Contracts - Collars	$	-	$	285,784	$	-	$	285,784

Level 2 – Market Approach - The fair values of the Company’s swaps and collars are based on a third-party pricing model, which utilizes inputs that are either readily available in the public market, such as natural gas curves and volatility curves, or can be corroborated from active markets. These values are based upon future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

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:

	Quarter Ended June 30,
	2020				2019
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	-	$	-
	Nine Months Ended June 30,
	2020				2019
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	5,288,710	$	29,315,807	$	-	$	-

(a) When indicators of impairment are present, the Company assesses the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off during the three and nine months ended June 30, 2020, in the amounts of $358,826 and $588,721, respectively.

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Subsequent Events (Tables)

9 Months Ended

Jun. 30, 2020

Subsequent Events [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of June 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
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 - December 2021	10,000 Mmbtu	NYMEX Henry Hub	$2.765
January 2021 - February 2022	50,000 Mmbtu	NYMEX Henry Hub	$2.729
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
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 June 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
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
Oil costless collars
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 21	500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
January 22	2,500 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling
February 22	5,000 Bbls	NYMEX WTI	$37.00 floor / $45.00 ceiling

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Leases (Narrative) (Details) - USD ($) $ in Millions	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%
Scenario Forecast [Member]
Lessee Lease Description [Line Items]
Lease liability	$ 1
ROU Asset	$ 1

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Revenues (Summary Of Disaggregation Of Company's Oil, NGL And Natural Gas Revenues) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	$ 3,517,561	$ 9,782,337	$ 18,329,017	$ 31,214,375
Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	1,641,072	3,123,100	8,352,743	11,049,662
Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	1,876,489	6,659,237	9,976,274	20,164,713
Oil [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	1,430,017	5,523,467	9,085,820	13,932,052
Oil [Member] | Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	719,012	1,640,247	4,680,871	5,496,433
Oil [Member] | Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	711,005	3,883,220	4,404,949	8,435,619
NGL [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	232,856	826,282	1,372,480	3,097,479
NGL [Member] | Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	129,833	310,581	548,921	938,692
NGL [Member] | Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	103,023	515,701	823,559	2,158,787
Natural Gas [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	1,854,688	3,432,588	7,870,717	14,184,844
Natural Gas [Member] | Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	792,227	1,172,272	3,122,951	4,614,537
Natural Gas [Member] | Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	$ 1,062,461	$ 2,260,316	$ 4,747,766	$ 9,570,307

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Revenues (Narrative) (Details) - USD ($)	3 Months Ended		6 Months Ended	9 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Mar. 31, 2020	Jun. 30, 2020	Jun. 30, 2019	Sep. 30, 2019
Disaggregation Of Revenue [Line Items]
Revenue, practical expedient, financing component				true
Revenues	$ 3,517,561	$ 9,782,337		$ 18,329,017	$ 31,214,375
Decrease in loss before benefit for income taxes	237,341			237,341
Decrease in net loss	$ 189,873			$ 175,632
Decrease in loss per common share	$ 0.01			$ 0.01
Oil, NGL and Natural Gas [Member]
Disaggregation Of Revenue [Line Items]
Revenues	$ 3,517,561	$ 9,782,337		$ 18,329,017	$ 31,214,375
Oil, NGL and Natural Gas [Member] | New Wells on Panhandle Acreage [Member]
Disaggregation Of Revenue [Line Items]
Revenues			$ 95,221	$ 259,336		$ 164,115
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 (Narrative) (Details) - USD ($)		3 Months Ended		9 Months Ended
	Mar. 27, 2020	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Income Tax Contingency [Line Items]
Effective tax rate		(20.00%)	22.00%	(26.00%)	24.00%
Income tax (benefit) provision		$ (877,940)	$ 1,315,000	$ (7,610,940)	$ 4,756,000
Current tax rate				21.00%
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	30.00%
Net operating losses carryback percentage of adjusted taxable income	50.00%
Refundable tax credit due to AMT credits		1,400,000
Income tax (benefit) provision		$ (31,127)
Previously enacted tax rate	34.00%

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Long-Term Debt (Details) - USD ($)		9 Months Ended
	Jun. 24, 2020	Jun. 30, 2020	Jun. 23, 2020
Line Of Credit Facility [Line Items]
Short-term debt		$ 2,000,000
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	$ 32,000,000	$ 45,000,000
Credit facility maturity		Nov. 30, 2022
Effective Interest rate		4.25%
Debt issuance cost net of amortization		$ 231,387
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		$ 30,000,000
Short-term debt		2,000,000
Availability under outstanding credit facility		$ 2,000,000
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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Deferred Compensation Plan For Non-Employee Directors (Details)	9 Months Ended
	Jun. 30, 2020
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 ($)	Mar. 09, 2020	Jan. 16, 2020	Jan. 02, 2020	Dec. 11, 2019	Mar. 31, 2020	May 31, 2018	Mar. 31, 2014	Mar. 31, 2010
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 ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 128,196	$ 159,911	$ 619,812	$ 606,232
Market-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	10,247	60,406	285,150	306,685
Time-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 117,949	$ 99,505	$ 334,662	$ 299,547

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Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details)	9 Months Ended
	Jun. 30, 2020 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 754,567
Market-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 77,900
Weighted Average Period (in years)	2 years 21 days
Time-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 676,667
Weighted Average Period (in years)	2 years 1 month 2 days

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Properties And Equipment - Summary of Properties and Equipment and Related Accumulated DD&A (Details) - USD ($)	Jun. 30, 2020	Sep. 30, 2019
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties	$ 324,913,067	$ 354,718,398
Non-producing oil and natural gas properties	19,081,485	14,599,023
Other property and equipment	777,104	717,121
Gross properties and equipment, at cost, based on successful efforts accounting	344,771,656	370,034,542
Less accumulated depreciation, depletion and amortization	(261,733,655)	(258,607,521)
Net properties and equipment	$ 83,038,001	$ 111,427,021

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Properties And Equipment (Details)	3 Months Ended						9 Months Ended			12 Months Ended
	Jun. 30, 2020 USD ($)	Mar. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) a	Jun. 30, 2019 USD ($) a	Mar. 31, 2019 USD ($) a Asset	Dec. 31, 2018 USD ($) a	Jun. 30, 2020 USD ($)		Jun. 30, 2019 USD ($) a	Sep. 30, 2019 USD ($)
Property Plant And Equipment [Line Items]
Proceeds from sales of assets							$ 3,457,500		$ 13,114,969
Gain on sale of oil and gas properties	$ 3,108			$ 4,017,787			$ 3,275,996		13,114,725
Number of assets sold | Asset					0
Computation of Oil, Natural Gas and NGL Reserves							12 months
Impairment				$ 0			$ 29,315,807	[1]	$ 0
Impairment written-off	358,826						588,721
Impairment	$ 358,826						$ 29,904,528
Percentage of discount rate for developed location		10.00%
Undeveloped location assigned value		$ 0
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								$ 76,600,000
Other Producing Assets [Member]
Property Plant And Equipment [Line Items]
Impairment		$ 2,700,000
Lea and Eddy Counties, New Mexico [Member]
Property Plant And Equipment [Line Items]
Mineral acreage sold | a			530			206
Proceeds from sales of assets			$ 3,400,000
Gain on sale of oil and gas properties			$ 3,300,000			$ 9,100,000
Proceeds from sales of assets						$ 9,100,000
Martin County, Texas [Member]
Property Plant And Equipment [Line Items]
Mineral acreage sold | a				166					166
Gain on sale of oil and gas properties				$ 4,000,000
Proceeds from sales of assets				$ 4,000,000
Kingfisher, Canadian [Member]
Property Plant And Equipment [Line Items]
Mineral acreage acquired | a			700
Purchase price of mineral acreage acquired			$ 9,300,000
Blaine County, Oklahoma [Member]
Property Plant And Equipment [Line Items]
Mineral acreage acquired | a			700	313	329	45
Purchase price of mineral acreage acquired			$ 9,300,000	$ 3,300,000	$ 1,400,000	$ 400,000

[1] When indicators of impairment are present, the Company assesses the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off during the three and nine months ended June 30, 2020, in the amounts of $358,826 and $588,721, respectively.

XML

Properties And Equipment - Summary of Asset Retirement Obligation (Details) - USD ($)	9 Months Ended
	Jun. 30, 2020	Jun. 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	27,782
Wells sold or plugged	(61,985)	(9,669)
Accretion of discount	97,803	99,996
Asset retirement obligations as of end of period	$ 2,871,603	$ 2,927,487

XML

Derivatives (Summary Of Derivative Instruments Contracts) (Details)	Jun. 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 Fixed Price Swaps [Member] | Derivative Contract Period Nineteen [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 Twenty [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 Twenty One [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 Twenty Two [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 Twenty Three [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 Twenty Four [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 Twenty Five [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 Twenty Six [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 Twenty Seven [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 Twenty Eight [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 Twenty Nine [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 Thirty [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 Thirty One [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 Thirty Two [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 Thirty Three [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 Thirty Four [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 Thirty Five [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 Thirty Six [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 Thirty Seven [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 Thirty Eight [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 Thirty Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Thirty Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	55.00
Oil Costless Collars [Member] | Derivative Contract Period Thirty Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	62.00
Oil Costless Collars [Member] | Derivative Contract Period Forty [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Forty [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Forty [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Forty One [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Forty One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Forty One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Forty Two [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Forty Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Forty Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Forty Three [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,500
Oil Costless Collars [Member] | Derivative Contract Period Forty Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Forty Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Forty Four [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Forty Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Forty Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Costless Collars [Member] | Derivative Contract Period Forty Five [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,500
Oil Costless Collars [Member] | Derivative Contract Period Forty Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	36.00
Oil Costless Collars [Member] | Derivative Contract Period Forty Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	43.60
Oil Fixed Price Swaps [Member] | Derivative Contract Period Forty Six [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 Forty Seven [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 Forty Eight [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 Forty Nine [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 Fifty [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 Fifty One [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 ($)	Jun. 30, 2020	Sep. 30, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value of derivative contracts, asset	$ 1,679,511	$ 2,494,144

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Derivatives (Schedule of Gain or Loss on Derivative Contracts, Net) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	$ 1,699,122	$ 418,892	$ 3,230,034	$ (1,099,402)
Non-cash gain (loss) on derivative contracts, net	(2,537,404)	1,894,303	(814,633)	6,125,525
Gains (losses) on derivative contracts, net	(838,282)	2,313,195	2,415,401	5,026,123
Natural Gas Costless Collars [Member]
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	18,000		18,000	(191,200)
Non-cash gain (loss) on derivative contracts, net	(60,035)		(32,152)	10,453
Natural Gas Fixed Price Swaps [Member]
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	268,650	525,200	1,488,970	(294,940)
Non-cash gain (loss) on derivative contracts, net	(129,865)	1,255,469	(815,630)	2,177,594
Oil Costless Collars [Member]
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	625,968	(104,394)	827,664	(359,564)
Non-cash gain (loss) on derivative contracts, net	(757,060)	128,829	(283,255)	1,516,144
Oil Fixed Price Swaps [Member]
Derivative [Line Items]
Cash received (paid) on derivative contracts, net	786,504	(1,914)	895,400	(253,698)
Non-cash gain (loss) on derivative contracts, net	$ (1,590,444)	$ 510,005	$ 316,404	$ 2,421,334

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Derivatives (Summary Of Derivative Contracts) (Details) - USD ($)		Jun. 30, 2020	Sep. 30, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gross amounts recognized - Current Assets	[1]	$ 2,028,640	$ 2,256,639
Offsetting adjustments - Current Assets	[1]	(208,663)
Derivative contracts, net	[1]	1,819,977	2,256,639
Gross amounts recognized - Non-Current Assets	[1]	57,386	237,505
Offsetting adjustments - Non-Current Assets	[1]	(57,386)
Derivative contracts, net	[1]		$ 237,505
Gross amounts recognized - Current Liabilities	[1]	208,663
Offsetting adjustments - Current Liabilities	[1]	(208,663)
Gross amounts recognized - Non-Current Liabilities	[1]	197,852
Offsetting adjustments - Non-Current Liabilities	[1]	(57,386)
Derivative contracts, net	[1]	$ 140,466

[1] See Note 11: Fair Value Measurements for further disclosures regarding fair value of financial instruments.

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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)	Jun. 30, 2020 USD ($)
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ 1,393,727
Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	1,393,727
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	285,784
Collars [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ 285,784

XML

Fair Value Measurements (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Details) - USD ($)		3 Months Ended	9 Months Ended
		Jun. 30, 2019	Jun. 30, 2020		Jun. 30, 2019
Fair Value Disclosures [Abstract]
Producing Properties, Fair Value	[1]		$ 5,288,710
Producing Properties, Impairment		$ 0	$ 29,315,807	[1]	$ 0

[1] When indicators of impairment are present, the Company assesses the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off during the three and nine months ended June 30, 2020, in the amounts of $358,826 and $588,721, respectively.

XML

Fair Value Measurements (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Parenthetical) (Details) - USD ($)	3 Months Ended	9 Months Ended
	Jun. 30, 2020	Jun. 30, 2020
Fair Value Disclosures [Abstract]
Impairment for written-off wells	$ 358,826	$ 588,721

XML

Subsequent Events - Summary of New Derivative Instruments Contracts (Details) - Subsequent Event [Member]	Aug. 13, 2020 MMBTU $ / MMBTU $ / bbl bbl
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Two [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	53,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Two [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Two [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Three [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	72,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Three [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Three [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Four [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	48,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Four [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Four [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Five [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	61,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Five [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Five [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Six [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	63,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Six [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Six [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Seven [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	69,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Seven [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Seven [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Eight [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	61,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Eight [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Eight [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Nine [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	83,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Nine [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifty Nine [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	27,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty One [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	20,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty One [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty One [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Two [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	14,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Two [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Two [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Three [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	4,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Three [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Three [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Four [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	77,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Four [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Four [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.10
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Five [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	54,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Five [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Five [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Six [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	55,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Six [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Six [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Seven [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	64,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Seven [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Seven [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Eight [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	52,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Eight [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Eight [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Nine [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	62,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Nine [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixty Nine [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	66,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy One [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	60,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy One [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy One [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Two [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	64,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Two [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Two [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Three [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	24,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Three [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Three [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Four [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	18,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Four [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Four [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Five [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	19,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Five [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Five [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Six [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	20,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Six [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Six [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Seven [Member]
Subsequent Event [Line Items]
Production volume covered per month - Gas/Natural gas | MMBTU	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Seven [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price	2.30
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventy Seven [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price	3.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Eight [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Seventy Eight [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Eight [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Seventy Nine [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Seventy Nine [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Seventy Nine [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Eighty [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Eighty [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Eighty One [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Eighty One [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty One [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Eighty Two [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Eighty Two [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Two [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	44.50
Oil Costless Collars [Member] | Derivative Contract Period Eighty Three [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Eighty Three [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Three [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Four [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Eighty Four [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Four [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Five [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Eighty Five [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Five [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Six [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	2,500
Oil Costless Collars [Member] | Derivative Contract Period Eighty Six [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Six [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Seven [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	1,500
Oil Costless Collars [Member] | Derivative Contract Period Eighty Seven [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Seven [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Eight [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Eighty Eight [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Eight [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Nine [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	2,500
Oil Costless Collars [Member] | Derivative Contract Period Eighty Nine [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Eighty Nine [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Ninety [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Ninety [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Ninety [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Ninety One [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	500
Oil Costless Collars [Member] | Derivative Contract Period Ninety One [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Ninety One [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Ninety Two [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	2,500
Oil Costless Collars [Member] | Derivative Contract Period Ninety Two [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Ninety Two [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Ninety Three [Member]
Subsequent Event [Line Items]
Production volume covered per month - Oil | bbl	5,000
Oil Costless Collars [Member] | Derivative Contract Period Ninety Three [Member] | Minimum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	37.00
Oil Costless Collars [Member] | Derivative Contract Period Ninety Three [Member] | Maximum [Member]
Subsequent Event [Line Items]
Contract price | $ / bbl	45.00

XML

Subsequent Events - Additional Information (Details)		9 Months Ended
	Jul. 28, 2020 USD ($) a	Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)
Subsequent Event [Line Items]
Proceeds from sales of assets		$ 3,457,500	$ 13,114,969
Subsequent Event [Member] | Northwest Oklahoma [Member]
Subsequent Event [Line Items]
Mineral acreage sold | a	5,925
Proceeds from sales of assets	$ 793,617