Valliance Bank Tower, Suite 1100, 1601 NW Expressway, Oklahoma City, Oklahoma 73118

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

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

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

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~~2, 2021: 30,400,612 shares

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, as amended (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~~natural gas and ~~natural gas~~oil prices; the level of production on our properties; estimates of quantities of ~~oil, NGL and~~ natural gas, oil and NGL 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~~oil, and ~~natural gas.~~NGLs. 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~~2020 (“Annual Report”), and all quarterly reports on Form 10-Q filed subsequently ~~hereto,~~thereto, 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.

The following is a glossary of certain accounting, oil and natural gas industry and other defined terms used in this Form 10-Q:

All references to years in this Form 10-Q, unless otherwise noted, refer to the Company’s fiscal year ~~end of~~ended September 30. For example, references to ~~2020~~2021 mean the fiscal year ended September 30, ~~2020.~~2021.

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. Unless otherwise noted, general references to a quarter refer to the quarterly period ended June 30. For example, the 2021 quarter refers to the quarterly period ended June 30, 2021 and the 2020 quarter refers to the quarterly period ended June 30, 2020.

All references to nine-month periods in this Form 10-Q, unless otherwise noted, refer to the Company’s fiscal nine-month period based on a fiscal year end of September 30. Unless otherwise noted, general references to a period in sections of this Form 10-Q discussing nine-month periods refer to the nine-month period ended June 30. For example, in sections of this Form 10-Q discussing nine-month periods, the 2021 period refers to the nine-month period ended June 30, 2021 and the 2020 period refers to the nine-month period ended June 30, 2020.

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

	June 30, 2020			September 30, 2019			June 30, 2021			September 30, 2020
Assets	(unaudited)						(unaudited)
Current assets:
Cash and cash equivalents	$	2,025,081		$	6,160,691		$	2,908,500		$	10,690,395
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		2,183,216			4,377,646
Natural gas, oil, and NGL sales receivables (net of $0 allowance for uncollectable accounts)								5,114,387			2,943,220
Refundable income taxes		1,640,350			1,505,442			2,379,756			3,805,227
Derivative contracts, net		1,819,977			2,256,639
Other		490,697			177,037			480,600			351,088
Total current assets		8,159,321			14,477,455			10,883,243			17,789,930

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			-
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties								323,187,303			324,886,491
Non-producing natural gas and oil properties								32,894,588			18,993,814
Other								681,125			582,444
								356,763,016			344,462,749
Less accumulated depreciation, depletion and amortization								(259,018,926	)		(263,590,801	)
Net properties and equipment								97,744,090			80,871,948

Operating lease right-of-use assets								628,617			690,316
Other, net		231,387			297,890			558,659			669,641

Total assets	$	91,724,110		$	126,644,947		$	109,814,609		$	100,021,835

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	724,289		$	665,160		$	1,173,258		$	997,637
Derivative contracts, net								6,754,328			281,942
Current portion of operating lease liability								130,973			127,108
Accrued liabilities and other		1,485,708			2,433,466			1,324,482			1,297,363
Short-term debt		2,000,000			-			-			1,750,000
Total current liabilities	$	4,209,997		$	3,098,626			9,383,041			4,454,050

Long-term debt		28,000,000			35,425,000			19,900,000			27,000,000
Deferred income taxes, net		-			5,976,007			212,007			1,329,007
Asset retirement obligations		2,871,603			2,835,781			2,845,919			2,897,522
Derivative contracts, net		140,466			-			1,354,174			425,705
Operating lease liability, net of current portion								822,907			921,625

Total liabilities								34,518,048			37,027,909

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
Class A voting common stock, $0.01666 par value; 36,000,500 shares authorized and 30,200,226 issued at June 30, 2021; 24,000,500 shares authorized and 22,647,306 issued at September 30, 2020								503,136			377,304
Capital in excess of par value		3,375,400			2,967,984			25,844,372			10,649,611
Deferred directors' compensation		1,829,786			2,555,781			1,701,110			1,874,007
Retained earnings		58,244,355			81,848,301			53,033,376			56,244,100
		63,731,050			87,653,575			81,081,994			69,145,022
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	)
Less treasury stock, at cost; 388,545 shares at June 30, 2021, and 411,487 shares at September 30, 2020								(5,785,433	)		(6,151,096	)
Total stockholders' equity		56,502,044			79,309,533			75,296,561			62,993,926
Total liabilities and stockholders' equity	$	91,724,110		$	126,644,947		$	109,814,609		$	100,021,835

(~~See~~The accompanying ~~notes)~~notes are an integral part of these condensed financial statements.)

	Three Months Ended June 30,					Nine Months Ended June 30,					Three Months Ended June 30,						Nine Months Ended June 30,
	2020			2019		2020			2019		2021			2020			2021			2020
Revenues:	(unaudited)					(unaudited)					(unaudited)						(unaudited)
Oil, NGL and natural gas sales	$	3,517,561		$	9,782,337	$	18,329,017		$	31,214,375
Natural gas, oil and NGL sales											$	10,899,820		$	3,517,561		$	25,670,624		$	18,329,017
Lease bonuses and rental income		22,996			229,075		572,787			952,378		259,152			22,996			319,139			572,787
Gains (losses) on derivative contracts		(838,282	)		2,313,195		2,415,401			5,026,123		(5,487,483	)		(838,282	)		(8,089,662	)		2,415,401
Gain on asset sales		3,108			4,017,787		3,275,996			13,114,725		270,070			3,108			313,595			3,275,996
		2,705,383			16,342,394		24,593,201			50,307,601		5,941,559			2,705,383			18,213,696			24,593,201
Costs and expenses:
Lease operating expenses		1,147,948			1,619,690		3,871,818			4,639,749		1,064,989			1,147,948			3,100,052			3,871,818
Transportation, gathering and marketing		956,653			1,529,270		3,696,282			4,601,959		1,538,174			956,653			4,138,653			3,696,282
Production taxes		134,249			488,779		835,284			1,565,038		596,858			134,249			1,316,038			835,284
Depreciation, depletion and amortization		2,464,568			4,383,043		8,793,787			11,820,705		2,137,707			2,464,568			6,176,173			8,793,787
Provision for impairment		358,826			-		29,904,528			-		45,855			358,826			45,855			29,904,528
Interest expense		241,191			526,677		958,429			1,551,831		220,439			241,191			790,202			958,429
General and administrative		1,908,790			1,809,439		6,306,479			5,881,432		2,275,104			1,908,790			6,065,677			6,306,479
Other expense (income)		(73,687	)		66,260		(44,551	)		82,045		235,027			(73,687	)		136,083			(44,551	)
		7,138,538			10,423,158		54,322,056			30,142,759
Total costs and expenses												8,114,153			7,138,538			21,768,733			54,322,056
Income (loss) before provision (benefit) for income taxes		(4,433,155	)		5,919,236		(29,728,855	)		20,164,842		(2,172,594	)		(4,433,155	)		(3,555,037	)		(29,728,855	)

Provision (benefit) for income taxes		(877,940	)		1,315,000		(7,610,940	)		4,756,000		(816,000	)		(877,940	)		(1,102,000	)		(7,610,940	)

Net income (loss)	$	(3,555,215	)	$	4,604,236	$	(22,117,915	)	$	15,408,842	$	(1,356,594	)	$	(3,555,215	)	$	(2,453,037	)	$	(22,117,915	)




Basic and diluted earnings (loss) per common share (Note 5)	$	(0.21	)	$	0.28	$	(1.34	)	$	0.92
Basic and diluted earnings (loss) per common share (Note 4)											$	(0.05	)	$	(0.21	)	$	(0.10	)	$	(1.34	)

Basic and diluted weighted average shares outstanding:
Common shares		16,403,243			16,515,498		16,375,736			16,646,828		28,117,199			16,403,243			24,308,185			16,375,736
Unissued, directors' deferred compensation shares		141,799			170,066		152,500			183,206		192,059			141,799			174,454			152,500
		16,545,042			16,685,564		16,528,236			16,830,034		28,309,258			16,545,042			24,482,639			16,528,236




Dividends declared per share of common stock and paid in period	$	0.01		$	0.04	$	0.09		$	0.12	$	0.01		$	0.01		$	0.03		$	0.09

(~~See~~The accompanying ~~notes)~~notes are an integral part of these condensed financial statements.)

	Class A voting				Capital in			Deferred															Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury						Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total			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
Balances at September 30, 2020																								22,647,306	$	377,304	$	10,649,611		$	1,874,007		$	56,244,100			(411,487	)	$	(6,151,096	)	$	62,993,926

Net income (loss)		-		-		-			-			1,892,114			-			-			1,892,114			-		-		-			-			(596,720	)		-			-			(596,720	)
Purchase of treasury stock		-		-		-			-			-			(632	)		(7,635	)		(7,635	)
Equity offering																								153,375		2,555		223,203			-			-			-			-			225,758
Restricted stock awards		-		-		148,515			-			-			-			-			148,515			-		-		122,978			-			-			-			-			122,978
Dividends ($0.08 per share)		-		-		-			-			(1,319,899	)		-			-			(1,319,899	)
Dividends ($0.02 per share)																								-		-		-			-			(454,936	)		-			-			(454,936	)
Distribution of restricted stock to officers and directors		-		-		(82,821	)		-			-			5,546			82,914			93			-		-		(316,886	)		-			-			21,220			317,239			353
Increase in deferred directors' compensation charged to expense		-		-		-			86,212			-			-			-			86,212			-		-		-			44,527			-			-			-			44,527
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
Balances at December 31, 2020																								22,800,681	$	379,859	$	10,678,906		$	1,918,534		$	55,192,444			(390,267	)	$	(5,833,857	)	$	62,335,886
(unaudited)
Net income (loss)		-		-		-			-			(20,454,814	)		-			-			(20,454,814	)		-		-		-			-			(499,723	)		-			-			(499,723	)
Equity offering																								-		-		(29,240	)		-			-			-			-			(29,240	)
Restricted stock awards		-		-		343,101			-			-			-			-			343,101			-		-		161,170			-			-			-			-			161,170
Dividends ($0.01 per share)																								-		-		-			-			(289,997	)		-			-			(289,997	)
Distribution of restricted stock to officers and directors																								-		-		-			-			-			(556	)		(1,268	)		(1,268	)
Distribution of deferred directors' compensation		-		-		(112,396	)		(603,485	)		-			47,885			715,880			(1	)		24,545		409		339,913			(340,322	)		-			-			-			-
Increase in deferred directors' compensation charged to expense		-		-		-			53,918			-			-			-			53,918			-		-		-			55,727			-			-			-			55,727
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
Balances at March 31, 2021																								22,825,226	$	380,268	$	11,150,749		$	1,633,939		$	54,402,724			(390,823	)	$	(5,835,125	)	$	61,732,555
(unaudited)
Net income (loss)		-		-		-			-			(3,555,215	)		-			-			(3,555,215	)		-		-		-			-			(1,356,594	)		-			-			(1,356,594	)
Purchase of treasury stock																								-		-		-			-			-			(1,229	)		(2,741	)		(2,741	)
Equity offering																								7,375,000		122,868		14,487,472			-			-			-			-			14,610,340
Restricted stock awards		-		-		128,196			-			-			-			-			128,196			-		-		258,526			-			-			-			-			258,526
Dividends ($0.01 per share)		-		-		-			-			(166,132	)		-			-			(166,132	)
Distribution of deferred directors' compensation		-		-		(17,179	)		(306,698	)		-			21,664			323,877			-
Dividends																								-		-		-			-			(12,754	)		-			-			(12,754	)
Distribution of restricted stock to officers and directors																								-		-		(52,375	)		-			-			3,507			52,433			58
Increase in deferred directors' compensation charged to expense		-		-		-			44,058			-			-			-			44,058			-		-		-			67,171			-			-			-			67,171
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
Balances at June 30, 2021																								30,200,226	$	503,136	$	25,844,372		$	1,701,110		$	53,033,376			(388,545	)	$	(5,785,433	)	$	75,296,561
(unaudited)

	Class A voting				Capital in			Deferred															Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury						Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total			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
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)		-		-		-			-			12,735,940			-			-			12,735,940			-		-		-			-			1,892,114			-			-			1,892,114
Purchase of treasury stock		-		-		-			-			-			(74,457	)		(1,140,559	)		(1,140,559	)		-		-		-			-			-			(632	)		(7,635	)		(7,635	)
Restricted stock awards		-		-		159,469			-			-			-			-			159,469			-		-		148,515			-			-			-			-			148,515
Dividends ($0.08 per share)		-		-		-			-			(1,347,789	)		-			-			(1,347,789	)		-		-		-			-			(1,319,899	)		-			-			(1,319,899	)
Distribution of restricted stock to officers and directors		425		7		(159,869	)		-			-			9,194			160,022			160			-		-		(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
(unaudited)
Net income (loss)																								-		-		-			-			(20,454,814	)		-			-			(20,454,814	)
Restricted stock awards																								-		-		343,101			-			-			-			-			343,101
Distribution of deferred directors' compensation		-		-		(8	)		8			-			-			-			-			-		-		(112,396	)		(603,485	)		-			47,885			715,880			(1	)
Increase in deferred directors' compensation charged to expense		-		-		-			80,287			-			-			-			80,287			-		-		-			53,918			-			-			-			53,918
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
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
(unaudited)
Net income (loss)		-		-		-			-			(1,931,334	)		-			-			(1,931,334	)		-		-		-			-			(3,555,215	)		-			-			(3,555,215	)
Purchase of treasury stock		-		-		-			-			-			(175,175	)		(2,827,126	)		(2,827,126	)
Restricted stock awards		-		-		286,852			-			-			-			-			286,852			-		-		128,196			-			-			-			-			128,196
Dividends		-		-		-			-			(381	)		-			-			(381	)
Distribution of restricted stock to officers and directors		-		-		(73,069	)		-			-			4,441			73,144			75
Dividends ($0.01 per share)																								-		-		-			-			(166,132	)		-			-			(166,132	)
Distribution of deferred directors' compensation		-		-		(207,842	)		(667,124	)		-			52,399			874,963			(3	)		-		-		(17,179	)		(306,698	)		-			21,664			323,877			-
Increase in deferred directors' compensation charged to expense		-		-		-			51,993			-			-			-			51,993			-		-		-			44,058			-			-			-			44,058
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
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~~The accompanying ~~notes)~~notes are an integral part of these condensed financial statements.)

	Nine months ended June 30,						Nine Months Ended June 30,
	2020			2019			2021			2020
Operating Activities	(unaudited)						(unaudited)
Net income (loss)	$	(22,117,915	)	$	15,408,842		$	(2,453,037	)	$	(22,117,915	)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		8,793,787			11,820,705			6,176,173			8,793,787
Impairment of producing properties		29,904,528			-			45,855			29,904,528
Provision for deferred income taxes		(6,158,000	)		5,150,000			(1,117,000	)		(6,158,000	)
Gain from leasing fee mineral acreage		(567,975	)		(951,832	)		(316,541	)		(567,975	)
Proceeds from leasing fee mineral acreage		582,458			967,337			334,938			582,458
Net (gain) loss on sales of assets		(3,258,994	)		(13,114,725	)		(136,596	)		(3,258,994	)
Directors' deferred compensation expense		184,188			197,820			167,425			184,188
Total (gain) loss on derivative contracts		(2,415,401	)		(5,026,123	)		8,089,662			(2,415,401	)
Cash receipts (payments) on settled derivative contracts		3,230,034			(1,099,402	)		(688,807	)		3,230,034
Restricted stock awards		619,812			606,232			542,674			619,812
Other		3,718			15,848			72,126			3,718
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		2,194,430			1,597,667
Natural gas, oil and NGL sales receivables								(2,134,395	)		2,194,430
Other current assets		(121,635	)		(859,258	)		(89,957	)		(121,635	)
Accounts payable		31,755			3,270			209,014			31,755
Income taxes receivable		(134,908	)		(476,846	)		1,425,471			(134,908	)
Other non-current assets		6,544			6,949			87,065			6,544
Accrued liabilities		(950,686	)		86,467			26,263			(950,686	)
Total adjustments		31,943,655			(1,075,891	)		12,693,370			31,943,655
Net cash provided by operating activities		9,825,740			14,332,951			10,240,333			9,825,740

Investing Activities
Capital expenditures		(196,168	)		(3,349,640	)		(696,759	)		(196,168	)
Acquisition of minerals and overrides		(10,304,016	)		(5,120,466	)
Investments in partnerships		-			(1,648	)
Acquisition of minerals and overriding royalty interests								(19,337,265	)		(10,304,016	)
Proceeds from sales of assets		3,457,500			13,114,969			533,371			3,457,500
Net cash provided (used) by investing activities		(7,042,684	)		4,643,215			(19,500,653	)		(7,042,684	)

Financing Activities
Borrowings under Credit Facility		6,061,725			15,053,345			-			6,061,725
Payments of loan principal		(11,486,725	)		(24,553,345	)		(8,850,000	)		(11,486,725	)
Net proceeds from equity issuance								11,088,858			-
Purchases of treasury stock		(7,635	)		(6,465,186	)		(2,741	)		(7,635	)
Payments of dividends		(1,486,031	)		(2,013,005	)		(757,692	)		(1,486,031	)
Net cash provided (used) by financing activities		(6,918,666	)		(17,978,191	)		1,478,425			(6,918,666	)

Increase (decrease) in cash and cash equivalents		(4,135,610	)		997,975			(7,781,895	)		(4,135,610	)
Cash and cash equivalents at beginning of period		6,160,691			532,502			10,690,395			6,160,691
Cash and cash equivalents at end of period	$	2,025,081		$	1,530,477		$	2,908,500		$	2,025,081

Supplemental Schedule of Noncash Investing and Financing Activities:


Additions to asset retirement obligations	$	4		$	27,782		$	-		$	4

Gross additions to properties and equipment	$	10,335,534		$	8,149,347		$	23,794,178		$	10,335,534

Equity offering used for acquisitions								(3,718,000	)		-
Net (increase) decrease in accounts payable for properties and equipment additions		164,650			320,759			(42,154	)		164,650
Capital expenditures and acquisitions	$	10,500,184		$	8,470,106		$	20,034,024		$	10,500,184

(~~See~~The accompanying ~~notes)~~notes are an integral part of these condensed financial statements.)

The accompanying unaudited condensed financial statements of ~~Panhandle Oil and Gas~~PHX Minerals 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 fiscal 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.~~2020. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” ~~“Panhandle”~~“PHX” or “Company” refer to ~~Panhandle Oil and Gas~~PHX Minerals Inc.

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.

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.

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.

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, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ~~Accounting Standards Codification (“ASC”)~~ASC 932 (Extractive Activities—Oil and Gas), and upon disposition, 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.

See Note 109 for discussion of the Company’s accounting for derivative contracts.

~~Sales of~~ oil ~~NGL~~ and ~~natural gas~~NGL are recognized when production is sold to a purchaser and control of the product has been 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.

The following table presents the disaggregation of the Company's ~~oil, NGL and~~ natural gas, oil and NGL revenues for the three and nine months ended June 30, ~~2020~~2021 and ~~2019:~~2020:

	Three Months Ended June 30, 2020						Nine Months Ended June 30, 2020						Three Months Ended June 30, 2021						Nine Months Ended June 30, 2021
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue													$	3,023,941	$	3,234,656	$	6,258,597	$	6,580,533	$	7,509,962	$	14,090,495
Oil revenue	$	719,012	$	711,005	$	1,430,017	$	4,680,871	$	4,404,949	$	9,085,820		1,934,966		1,603,996		3,538,962		4,748,987		4,275,962		9,024,949
NGL revenue		129,833		103,023		232,856		548,921		823,559		1,372,480		453,935		648,326		1,102,261		1,095,124		1,460,056		2,555,180
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
Natural gas, oil and NGL sales													$	5,412,842	$	5,486,978	$	10,899,820	$	12,424,644	$	13,245,980	$	25,670,624


	Three Months Ended June 30, 2019						Nine Months Ended June 30, 2019						Three Months Ended June 30, 2020						Nine Months Ended June 30, 2020
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue													$	792,227	$	1,062,461	$	1,854,688	$	3,122,951	$	4,747,766	$	7,870,717
Oil revenue	$	1,640,247	$	3,883,220	$	5,523,467	$	5,496,433	$	8,435,619	$	13,932,052		719,012		711,005		1,430,017		4,680,871		4,404,949		9,085,820
NGL revenue		310,581		515,701		826,282		938,692		2,158,787		3,097,479		129,833		103,023		232,856		548,921		823,559		1,372,480
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
Natural gas, oil and NGL sales													$	1,641,072	$	1,876,489	$	3,517,561	$	8,352,743	$	9,976,274	$	18,329,017

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, oil and NGL sales receivables line item on the Company’s ~~Balance Sheets.~~balance sheets. The difference between the Company's estimates and the actual amounts received for ~~oil, NGL and~~ natural gas, oil and NGL sales is recorded in the quarter that payment is received from the third party. For the three and nine months ended ~~June 30, 2019,~~2020, 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. For the three months ended June 30, 2021, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was approximately $2.0 million and primarily due to change in price estimates as a result of basis differentials during winter storms. This is 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.~~it. Through ~~the use of new technological platforms as well as~~ cash received on new wells, in the ~~2020~~2021 third quarter, the Company identified several producing properties on ~~our~~its minerals that had production dates prior to the ~~2020~~2021 third quarter. Estimates of the ~~oil~~natural gas and ~~natural gas~~oil sales related to those properties were made and are reflected in the third quarter ~~Oil, NGL and~~ natural gas, oil and NGL sales on the Company’s Statements of Operations and on the Company’s ~~Balance Sheets~~balance sheets in ~~Oil, NGL and~~ natural gas, oil and NGL sales receivables. In connection with obtaining more relevant information on new wells on Company acreage for the three and nine months ended June 30, 2021, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $365,871, of which $72,717 related to the production periods before October 1, 2020 and $293,154 related to the first and second quarters of 2021. In connection with obtaining more relevant information identifying additional new wells on ~~Panhandle~~Company acreage ~~we have~~for the three and nine months ended June 30, 2020, the Company recorded a change in estimate for new wells to ~~Oil, NGL and~~ natural gas, oil and NGL 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.

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~~if a provision for income taxes is expected for the year, ~~decreases~~will decrease the effective tax rate, while the effect ~~is to~~will increase the effective tax rate ~~when~~if 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 Company’s effective tax rate for the nine months ended June 30, ~~2020,~~2021 was a ~~26%~~31% benefit as compared to a ~~24% provision~~26% benefit for the nine months ended June 30, ~~2019.~~2020. The Company’s effective tax rate for the quarter ended June 30, ~~2020,~~2021 was a ~~20%~~38% benefit as compared to a ~~22% provision~~20% benefit for the quarter ended June 30, ~~2019.~~2020.

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 under Section 163(j) of the Internal Revenue Code (“IRC”) from 30% to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. On July 28, 2020, final regulations were issued under Section 163(j) of the IRC, which modified the calculation under the previous proposed regulations of adjusted taxable income for purposes of the 50% limitation on interest expense. Under the final regulations, depreciation, amortization, and depletion capitalizable under Section 263A of the IRC is added back to tentative taxable income. This change allowed all interest expense to be deductible for 2020 and reduced the associated deferred tax asset to 0. During the quarter ended ~~June 30, 2020,~~March 31, 2021, the Company ~~filed for~~received a tax refund totaling $1.4 million associated with the ~~AMT~~alternative minimum tax (AMT) credits, ~~totaling $1.4 million,~~ which was accelerated ~~due to~~by the CARES Act. ~~In addition to~~Additionally, the ~~acceleration~~Company has a $2.2 million receivable associated with the carryback 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%. Company’s 2020 federal net operating loss.

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.

For the three and nine months ended June 30, 2021, the Company did not include restricted stock in the diluted EPS calculation because the effect would have been antidilutive.

The following table presents a reconciliation of the components of basic and diluted EPS.

The Company has a $200,000,000 credit facility with a ~~group~~syndicate of banks ~~headed~~led by Bank of Oklahoma ~~(BOK) with~~(“BOKF”), which had a borrowing base of ~~$32,000,000~~$28,500,000 as of June 30, ~~2020, and a maturity date of November 30, 2022~~2021 (as amended, the “Credit Facility”). The Credit Facility matures on November 30, 2023. The Credit Facility is subject to at least semi-annual borrowing base ~~determination,~~determinations, wherein ~~BOK~~BOKF 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~~BOKF prime plus from 1.00% to 1.75%, or 30-day LIBOR plus from 2.50% to 3.25%. The election of ~~BOK~~BOKF prime or LIBOR is at the Company’s discretion. The interest rate spread from ~~BOK~~BOKF 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,~~2021, the effective interest rate was ~~4.25%~~4.00%.

The Company’s debt is recorded at the carrying amount on its ~~Balance Sheets.~~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.~~balance sheets. Total debt issuance cost, net of amortization as of June 30, ~~2020~~2021 was ~~$231,387.~~$252,001. The debt issuance cost is amortized over the life of the ~~credit facility.~~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,~~April 7, 2021, the Company entered into the ~~seventh~~ninth amendment to ~~its amended and restated credit agreement.~~the Credit Facility. The amendment, among other things, reduced the Company’s borrowing base ~~from $45,000,000~~under the Credit Facility to ~~$32,000,000~~$29.0 million, extended the maturity date by one year to November 30, 2023, and ~~includes a~~reduced the Quarterly Commitment ~~Reduction, whereby the borrowing base is reduced by~~

~~$1,000,000 each~~Reductions from $600,000 to $500,000, commencing on April 15, ~~July 15, October 15~~2021. Additionally, the amendment increased the Company’s distribution allowance from $1.0 million to $1.5 million per annum for a period of one year from the date of the amendment and ~~January 15, commencing~~extended this allowance beyond the date that is one year following the date of the amendment so long as (i) the Available Commitment is greater than or equal to 20% of the Total Commitment and (ii) the Leverage Ratio on ~~July 15, 2020.~~a pro forma basis does not exceed 2.75 to 1.00. The ~~next redetermination is expected~~existing prohibition of all Restricted Payments other than the subject distribution allowance and the existing requirement that immediately after giving effect to ~~occur~~a permitted Restricted Payment, no Default or Event of Default may exist or result therefrom remain in ~~December 2020.~~ effect.

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 ratio (as defined in the Credit Facility) of no more than ~~4.0~~3.5 to 1.0 based on the trailing twelve months. Pursuant to the Credit Facility, the Company is also required to enter into and maintain certain Swap Agreements for a period of eighteen (18) months fixing prices on oil or gas expected to be produced. At June 30, ~~2020,~~2021, the Company was in compliance with the covenants of the Credit Facility, had ~~$30,000,000~~$19,900,000 outstanding ~~of which $2,000,000 is classified as short-term debt due to~~under the ~~Quarterly Commitment Reduction,~~Credit Facility, and had ~~$2,000,000~~$8,600,000 of borrowing base

availability under the Credit Facility.The capitalized terms that are not defined in this description of the Credit Facility, including the description of the ninth amendment, have the meaning given to such terms in the Credit Facility.

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~~their annual retainers and 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 or 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 of up to ten years. The promise to issue such shares in the future is an unsecured obligation of the Company.

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~~2021 and ~~2019,~~2020 related to the Company’s market-based, time-based and performance-based restricted stock:

	Three Months Ended				Nine Months Ended				Three Months Ended				Nine Months Ended
	June 30,				June 30,				June 30,				June 30,
	2020		2019		2020		2019		2021		2020		2021		2020
Market-based, restricted stock	$	10,247	$	60,406	$	285,150	$	306,685	$	79,118	$	10,247	$	168,483	$	285,150
Time-based, restricted stock		117,949		99,505		334,662		299,547		179,408		117,949		374,191		334,662
Performance-based, restricted stock		-		-		-		-		-		-		-		-
Total compensation expense	$	128,196	$	159,911	$	619,812	$	606,232	$	258,526	$	128,196	$	542,674	$	619,812

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~~is shown in the following table:

	As of June 30, 2020				As of June 30, 2021
	Unrecognized Compensation Cost		Weighted Average Period (in years)		Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	77,900		2.06	$	725,627		2.43
Time-based, restricted stock		676,667		2.09		552,371		1.01
Performance-based, restricted stock		-				-
Total	$	754,567			$	1,277,998

Properties and equipment and related accumulated DD&A as of June 30, ~~2020,~~2021 and September ~~31, 2019,~~30, 2020 are as follows:

	June 30, 2020			September 30, 2019			June 30, 2021			September 30, 2020
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
Producing natural gas and oil properties							$	323,187,303		$	324,886,491
Non-producing natural gas and oil properties								32,894,588			18,993,814
Other property and equipment		777,104			717,121			681,125			582,444
		344,771,656			370,034,542			356,763,016			344,462,749
Less accumulated depreciation, depletion and amortization		(261,733,655	)		(258,607,521	)		(259,018,926	)		(263,590,801	)
Net properties and equipment		83,038,001			111,427,021		$	97,744,090		$	80,871,948

All purchases made in 2020 and 2021 were of mineral and royalty acreage and were accounted for as asset acquisitions.

~~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~~

Natural Gas, Oil 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 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.

~~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.

Management considers the estimation of the Company’s ~~crude~~natural gas, oil ~~NGL~~ and ~~natural gas~~NGL reserves to be the most significant of its judgments and estimates. Changes in ~~crude~~natural gas, oil ~~NGL~~ and ~~natural gas~~NGL 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,~~independent consulting petroleum engineer, with assistance from Company staff, prepares estimates of ~~crude~~natural gas, oil ~~NGL~~ and ~~natural gas~~NGL 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, oil and NGL 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, oil and NGL 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~~natural gas, oil ~~NGL~~ and ~~natural gas~~NGL pricing assumptions are used by management to prepare estimates of ~~crude~~natural gas, oil ~~NGL~~ and ~~natural gas~~NGL reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. ~~Crude~~Natural gas, oil ~~NGL~~ and ~~natural gas~~NGL 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).~~management.

~~All~~Company management monitors all long-lived assets, principally ~~oil and~~ natural gas and oil properties, ~~are monitored~~ for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such ~~as:~~as inflation rates; future drilling and completion costs; future sales prices for natural gas, oil ~~NGL~~ and ~~natural gas;~~NGL; future production costs; estimates of future ~~oil, NGL and~~ natural gas, oil and NGL reserves to be recovered and the timing thereof; the economic and regulatory ~~climates~~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, oil and NGL 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 three and nine months ended June 30, 2021, management’s assessment resulted in an impairment provision of $37,879 on producing properties and $7,976 on wells that the Company wrote off.

For the nine months ended June 30, 2020, ~~the~~management’s 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).~~pandemic. 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.~~

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~~natural gas and ~~natural gas.~~oil. 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~~BOKF are secured under the Credit Facility with ~~Bank of Oklahoma~~BOKF (see Note 6:5: Long-Term Debt). The derivative instruments have settled or will settle based on the prices below:

	~~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~~

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~~liability of ~~$1,679,511~~$8,108,502 as of June 30, ~~2020,~~2021, and a net ~~asset~~liability of ~~$2,494,144~~$707,647 as of September 30, ~~2019.~~2020. Cash receipts or payments 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.~~periods:

	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	June 30,						June 30,						June 30,						June 30,
	2020			2019			2020			2019			2021			2020			2021			2020
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	18,000		$	-		$	18,000		$	(191,200	)	$	(11,975	)	$	18,000		$	(21,064	)	$	18,000
Natural gas fixed price swaps		268,650			525,200			1,488,970			(294,940	)		(20,185	)		268,650			(18,943	)		1,488,970
Oil costless collars		625,968			(104,394	)		827,664			(359,564	)		(346,786	)		625,968			(370,432	)		827,664
Oil fixed price swaps		786,504			(1,914	)		895,400			(253,698	)		(625,744	)		786,504			(278,368	)		895,400
Cash received (paid) on derivative contracts, net	$	1,699,122		$	418,892		$	3,230,034		$	(1,099,402	)	$	(1,004,690	)	$	1,699,122		$	(688,807	)	$	3,230,034
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(60,035	)	$	-		$	(32,152	)	$	10,453		$	(1,732,932	)	$	(60,035	)	$	(1,135,852	)	$	(32,152	)
Natural gas fixed price swaps		(129,865	)		1,255,469			(815,630	)		2,177,594			(953,201	)		(129,865	)		(670,605	)		(815,630	)
Oil costless collars		(757,060	)		128,829			(283,255	)		1,516,144			(680,443	)		(757,060	)		(1,787,689	)		(283,255	)
Oil fixed price swaps		(1,590,444	)		510,005			316,404			2,421,334			(1,116,217	)		(1,590,444	)		(3,806,709	)		316,404
Non-cash gain (loss) on derivative contracts, net	$	(2,537,404	)	$	1,894,303		$	(814,633	)	$	6,125,525		$	(4,482,793	)	$	(2,537,404	)	$	(7,400,855	)	$	(814,633	)
Gains (losses) on derivative contracts, net	$	(838,282	)	$	2,313,195		$	2,415,401		$	5,026,123		$	(5,487,483	)	$	(838,282	)	$	(8,089,662	)	$	2,415,401

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.~~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~~balance sheets at June 30, ~~2020,~~2021 and September 30, ~~2019.~~2020. The Company has offset all amounts subject to master netting agreements in the Company's ~~Balance Sheets~~balance sheets at June 30, ~~2020,~~2021 and September 30, ~~2019.~~2020.

	June 30, 2020												September 30, 2019				June 30, 2021												September 30, 2020
	Fair Value (a)												Fair Value (a)				Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts				Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets		Non-Current Assets		Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets			Current Liabilities			Non-Current Liabilities
Gross amounts recognized	$	2,028,640		$	208,663		$	57,386		$	197,852		$	2,256,639	$	237,505	$	130,690		$	6,885,018		$	144,462		$	1,498,636		$	864,466		$	1,146,408		$	425,705
Offsetting adjustments		(208,663	)		(208,663	)		(57,386	)		(57,386	)		-		-		(130,690	)		(130,690	)		(144,462	)		(144,462	)		(864,466	)		(864,466	)		-
Net presentation on Condensed Balance Sheets	$	1,819,977		$	-		$	-		$	140,466		$	2,256,639	$	237,505	$	-		$	6,754,328		$	-		$	1,354,174		$	-		$	281,942		$	425,705

(a) See Note ~~11:~~10: 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.

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~~at June 30, ~~2020:~~2021:

	Fair Value Measurement at June 30, 2020								Fair Value Measurement at June 30, 2021
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair		Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value		(Level 1)		(Level 2)			(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	1,393,727	$	-	$	1,393,727	$	-	$	(4,542,115	)	$	-	$	(4,542,115	)
Derivative Contracts - Collars	$	-	$	285,784	$	-	$	285,784	$	-	$	(3,566,387	)	$	-	$	(3,566,387	)

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				Quarter Ended June 30,
	Fair Value		Impairment		Fair Value		Impairment		2021				2020
									Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	-	$	-	$	587	$	37,879	$	-	$	-

	Nine Months Ended June 30,								Nine Months Ended June 30,
	2020				2019				2021				2020
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment

Producing Properties (a)	$	5,288,710	$	29,315,807	$	-	$	-	$	587	$	37,879	$	5,288,710	$	29,315,807

(a) When indicators of impairment are present,, the Company assesses the carrying value of its ~~producing~~natural gas and oil properties for impairment. This assessment ~~utilized~~utilizes estimates of future cash ~~flows.~~flows as well as other market data. Significant judgments and assumptions in these assessments include estimates of future ~~oil, NGL and~~ natural gas, oil and NGL prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying ~~value~~values in excess of their calculated fair ~~values~~.values. This table excludes impairments on properties that were written off during the three and nine months ended June 30, 2021 in the amount of $7,976 and during the three and nine months ended June 30, 2020, in the amounts of $358,826 and $588,721, respectively.

At June 30, ~~2020,~~2021 and September 30, ~~2019,~~ 2020, 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 of which 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.

The Company may be the subject of threatened or pending legal actions and contingencies in the normal course of conducting our business. The Company provides for costs related to these matters when a loss is probable and the amount can be reasonably estimated. The effect of the outcome of these matters on our future results of operations and liquidity cannot be predicted because any such effect depends on future results of operations and the amount or timing of the resolution of such matters. For certain types of claims, the Company maintains insurance coverage for personal injury and property damage, product liability and other liability coverages in amounts and with deductibles that it believes are prudent, but there can be no assurance that these coverages will be applicable or adequate to cover adverse outcomes of claims or legal proceedings against the Company.

~~Subsequent to June 30, 2020, the Company entered into new derivative contracts as summarized in the table below:~~There were no subsequent events requiring disclosure.

	~~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~~

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.

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.

~~Panhandle~~PHX is an owner and manager of perpetual ~~oil~~natural gas and ~~natural gas~~oil 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 also currently own interests in leasehold acreage and non-operated working interests in ~~oil and~~ natural gas and oil properties. Exploration and development of our ~~oil and~~ natural gas and oil properties ~~are~~is conducted by third-party ~~oil~~natural gas and ~~natural gas~~oil exploration and production companies (primarily larger independent operating companies). We do not operate any of our ~~oil and~~ natural gas and oil

properties. While we previously ~~have been~~were 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/~~SCOOP, STACK and Arkoma Stack plays in Oklahoma, the Permian Basin in Texas and New Mexico, the Haynesville and Eagle Ford ~~play~~plays 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 working interest positions going forward.

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

THREE MONTHS ENDED JUNE 30, ~~2020,~~2021 COMPARED TO THREE MONTHS ENDED JUNE 30, ~~2019~~2020

~~The Company~~We recorded a third quarter ~~2020~~2021 net loss of $1,356,594, or $0.05 per share, as compared to a 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~~2020 quarter. The change in net ~~income (loss)~~loss was principally the result of ~~decreased oil, NGL, and~~increased natural gas, oil and NGL sales ~~loss~~and decreased LOE, DD&A and impairment expense, partially offset by an increase in losses on derivative contracts, ~~in the third quarter and decreased gain on asset sales, partially offset by a decrease in DD~~G&A, transportation, gathering and marketing expenses and production ~~taxes and changes in tax provision (benefit).~~taxes. These items are further discussed below.

For the three months ended June 30, 2021, the increase in natural gas, oil and NGL sales ~~decreased $6,264,776 or 64% for the 2020 quarter. Oil, NGL and~~was primarily due to increases in natural gas, ~~sales were lower due to decreases in~~ oil ~~NGL~~ and ~~natural gas~~NGL prices of ~~55%~~145%, ~~57%~~146% and ~~32%~~256%, respectively, and ~~decreases~~an increase in ~~oil, NGL and~~ natural gas, ~~sales~~oil and NGL volumes of ~~43%~~38%, ~~35%~~1% and ~~21%~~33%, respectively. The following table outlines ~~the Company’s~~our production and average sales prices for ~~oil, NGL and~~ natural gas, oil and NGL for the three-month periods of fiscal ~~2020~~2021 and ~~2019:~~2020:

		Oil Bbls		Average		NGL Bbls		Average		Mcf		Average		Mcfe		Average			Mcf		Average		Oil Bbls		Average		NGL Bbls		Average		Mcfe		Average
		Sold		Price		Sold		Price		Sold		Price		Sold		Price			Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended	Three months ended																	Three months ended
6/30/2021																				1,879,343	$	3.33		55,492	$	63.77		46,753	$	23.58		2,492,813	$	4.37
6/30/2020			55,138	$	25.94		35,169	$	6.62		1,361,909	$	1.36		1,903,752	$	1.85			1,361,909	$	1.36		55,138	$	25.94		35,169	$	6.62		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~~Production increased across 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,~~during the three months ended June 30, 2021, as compared to the three months ended June 30, ~~2019. The primary factor for~~2020, due to improved market conditions, resulting in (i) previously curtailed, high interest wells being worked over and brought fully back online in the ~~oil~~STACK, Arkoma Stack, and Fayetteville Shale, (ii) acquisitions in the STACK and Haynesville, and (iii) increased drilling and completions activity in the STACK and SCOOP. These increases were partially offset by plays with naturally declining production ~~decrease is attributable to~~in high interest wells, such as 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 interestShale.

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.

When ~~the Company leases its~~we lease our mineral interests, we generally receive an upfront cash payment, or lease ~~bonus, is generally received.~~bonus. Lease bonuses and rental income ~~decreased $206,079~~increased $236,156 in the 2021 quarter compared to the 2020 quarter primarily as the result of increased leasing activity in the 2021 quarter.

~~The~~We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts ~~was a~~for positions that have settled within the period. The net ~~asset of $1,679,511 as of June 30, 2020, and a~~gain (loss) on derivative instruments for the periods indicated includes the following:

The net ~~asset of $2,711,509 as of June 30, 2019. The Company had a net loss~~losses on derivative contracts ~~of $838,282~~ in ~~the 2020 quarter as compared~~both periods were principally due 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~~being less beneficial in relation to their ~~previous position to the collars~~respective contracted volumes and ~~the fixed~~ prices ~~of the swaps~~ at the beginning of the ~~2019 quarter. The Company utilizes~~periods.

Our natural gas and oil costless collar contracts and fixed price swaps in place at June 30, 2021 had expiration dates of July 2021 through February 2023. We utilize derivative contracts for the purpose of protecting ~~its~~our cash flow and return on investments and cash flow. Net cash received related to derivative contracts settled during the quarter ended June 30, 2020, was $1,699,122 compared to net cash received of $418,892 in the same period in the prior year.investments.

~~The Company is~~We are responsible for a portion of LOE relating to a well as a working interest owner. LOE includes ~~normally~~normal recurring and nonrecurring expenses associated with our working interests necessary to produce hydrocarbons from our ~~oil and~~ natural gas and oil wells, ~~as well as certain nonrecurring expenses, such as well repairs.~~ including maintenance, repairs, salt water disposal, insurance and workover expenses. Total LOE related to field operating costs decreased ~~$471,742~~$82,959, or ~~29%~~7%, in the ~~2020~~2021 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 iswas principally the result of ~~lower gas balancing expenses of $145,807 compared~~our strategic decision to ~~the 2019 quarter. Had the company~~ not ~~experienced~~participate with a working interest in new wells and 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~~royalty interest production as a percentage of ~~production decreasing 27% in the 2020 quarter.~~total production.

Transportation, gathering and marketing ~~decreased $572,617~~increased $581,521, or ~~37%~~61%, in the 2021 quarter compared to the 2020 quarter. This ~~decrease~~increase in costs was primarily driven by ~~lower natural gas~~higher production in the ~~2020~~2021 quarter compared to the ~~2019~~2020 quarter. The increase in rate per Mcfe was primarily due to the increase in natural gas sales in relation to other products. Natural gas sales bear the large majority of our transportation, gathering and marketing fees. On

Production taxes are paid on produced natural gas and oil based on a ~~per Mcfe basis, these handling fees were $0.50~~percentage of revenues from products sold at both fixed and variable rates established by federal, state or local taxing authorities. Production taxes increased $462,609, or 345%, in the ~~2020~~2021 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 decreased $354,530 or 73% in~~ the 2020 quarter. The ~~decrease~~increase in amount was primarily the result of ~~decreased oil, NGL and~~increased natural gas, oil and NGL sales of ~~$6,264,776~~$7,382,259 in the ~~2020~~2021 quarter as compared to the ~~2019~~2020 quarter.

DD&A is the amount of cost basis of ~~oil~~natural gas and ~~natural gas~~oil properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production ~~basis.~~basis for working interest, and on a straight-line basis for producing and non-producing minerals. Estimates of proved developed producing reserves are a major component of the calculation of depletion. DD&A decreased ~~$1,918,475~~$326,861, or ~~44%~~13%, in the ~~2020 quarter. DD&A in~~2021 quarter compared to the 2020 quarter, ~~was $1.29 per Mcfe as compared to $1.67 per Mcfe in the 2019 quarter. $1,193,410~~of which $1,086,750 of the decrease ~~was~~resulted from a ~~result of production decreasing 27% in the 2020 quarter. Also, DD&A decreased $725,065 as a result of a $0.38~~$0.43 decrease in the DD&A rate per ~~Mcfe.~~Mcfe, partially offset by an increase of $759,889 resulting from production increasing 31% in the 2021 quarter. 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~~an increase in ~~the reserve calculations~~reserves during the ~~2020~~2021 quarter, as compared to the ~~2019 quarter, shortening the economic life of wells. This resulted in lower projected remaining reserves on~~2020 quarter.

We had a ~~significant number of wells causing increased units of production DD&A.~~

~~Provision for impairment was $358,826 in the 2020 quarter as compared to no~~$45,855 provision for impairment in the ~~2019~~2021 quarter as compared to a $358,826 provision for impairment in the 2020 quarter. During the 2021 quarter, impairment of $37,879 was related to one field. These assets were written down to their fair market value as required by GAAP. 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 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~~2021 quarter as compared to the ~~2019~~2020 quarter.

Income taxes changed ~~$2,192,940,~~$61,940, 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%~~$816,000 benefit in the ~~2020~~2021 quarter. The change in income taxes resulted primarily from the reduction in net loss.

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.

G&A are costs not directly associated with the production of natural gas and oil and include the cost of employee salaries and related benefits, office expenses and fees for professional services. G&A for the 2021 quarter increased $366,314 as compared to the 2020 quarter. The increase was primarily due to increased professional services.

NINE MONTHS ENDED JUNE 30, ~~2020,~~2021 COMPARED TO NINE MONTHS ENDED JUNE 30, ~~2019~~2020

~~The Company~~We recorded a nine-month net loss of $2,453,037, or $0.10 per share, for the 2021 period, as compared to a 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 of increased ~~provision for impairment (non-cash), decreased oil, NGL and~~ natural gas, oil and NGL sales ~~decreased gains on derivative contacts~~ and decreased ~~gain on asset sales,~~LOE, DD&A, impairment expense and G&A, partially offset by ~~decreased lease operating expenses, decreased~~an increase in losses on derivative contracts, transportation, gathering and marketing expenses, ~~decreased~~ production taxes ~~decreased DD&A~~ and ~~changes~~a reduction in ~~our~~gain on asset sales and income tax ~~provision (benefit).~~benefit. These items are further discussed below.

~~Revenue from oil, NGL and~~The increase in natural gas, oil and NGL sales ~~decreased $12,885,358 or 41% for the 2020 period. Oil, NGL and~~was primarily due to increases in natural gas, ~~sales were down due to decreases in~~ oil ~~NGL~~ and ~~natural gas~~NGL prices of ~~23%~~60%, ~~40%~~25% and ~~35%~~81%, respectively, and ~~decreases~~an increase in ~~oil, NGL and~~ natural gas ~~sales~~and NGL volumes of ~~15%, 26%~~12% and ~~14%~~3%, respectively. The following table outlines ~~the Company’s~~our production and average sales prices for ~~oil, NGL and~~ natural gas, oil and NGL for the nine-month periods of fiscal ~~2020~~2021 and ~~2019:~~

		Oil Bbls		Average		NGL Bbls		Average		Mcf		Average		Mcfe		Average		Mcf		Average		Oil Bbls		Average		NGL Bbls		Average		Mcfe		Average
		Sold		Price		Sold		Price		Sold		Price		Sold		Price		Sold		Price		Sold		Price		Sold		Price		Sold		Price
Nine months ended	Nine months ended
6/30/2021																			5,090,619	$	2.77		170,437	$	52.95		125,118	$	20.42		6,863,949	$	3.74
6/30/2020			214,159	$	42.43		121,887	$	11.26		4,539,103	$	1.73		6,555,378	$	2.80		4,539,103	$	1.73		214,159	$	42.43		121,887	$	11.26		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~~Natural gas volumes ~~and slightly up for royalty interest volumes due to new royalty interest wells brought online,~~increased during the nine months ended June 30, 2021, as compared to the nine months ended 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 lower2020, primarily as a result of (i) acquisitions in the ~~natural decline of working interest~~Haynesville Shale, (ii) maintenance workovers on high-interest wells in the Arkoma Stack, and (iii) increased drilling and completion activity in the STACK. These gas volumes were partially offset by naturally declining production ~~base, along with recent~~in the Fayetteville Shale and production downtime and curtailments in response to market conditions in the ~~STACK, SCOOP and Arkoma Stack.~~SCOOP. The decrease isin oil production was primarily due to naturally declining production in high-interest wells brought online during the first quarter of 2020 in the Bakken, as well as reduced drilling and completion activity in 2021 due to prevailing economic conditions compared to 2020 in the Eagle Ford and SCOOP. Oil production decreases were partially offset by increased ~~royalty interest~~drilling and completion activity in the STACK. The increased activity in the STACK also resulted in increased NGL production, which was partially offset by production downtime and curtailments in high-interest wells in in the SCOOP as well as naturally declining production in liquid-rich gas areas of the ~~Bakken and SCOOP, related to new well drilling on Panhandle minerals.~~Anadarko Granite Wash.

When we lease our mineral interests, we generally receive an upfront cash payment, or lease bonus. Lease bonuses and rental income decreased $253,648 in the 2021 period compared to the 2020 period due to general slowdown in leasing activity.

The net ~~asset of $2,711,509 as of June 30, 2019. The Company had a net gain~~loss on derivative contracts ~~of $2,415,401~~ in the ~~2020~~current period ~~as compared to a net gain of $5,026,123 recorded in the 2019 period. The change~~ was principally due to the ~~oil~~natural gas and ~~natural gas~~oil 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,~~beneficial in relation to ~~where they were~~their respective contracted volumes and prices at the beginning of ~~their respective periods. The Company utilizes~~the period.

Our natural gas and oil costless collar contracts and fixed price swaps in place at June 30, 2021 had expiration dates of July 2021 through February 2023. We utilize derivative contracts for the purpose of protecting ~~its~~our cash flow and 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 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.~~

~~The Company is~~We are responsible for a portion of LOE relating to a well as a ~~non-operated~~ working interest ~~holder.~~owner. LOE includes ~~normally~~normal recurring and nonrecurring expenses associated with our ~~non-operated~~ working interests necessary to produce hydrocarbons from our ~~oil and~~ natural gas and oil wells, ~~as well as certain~~ ~~nonrecurring expenses, such as well repairs.~~including maintenance, repairs, salt water disposal, insurance and workover expenses. Total LOE related to field operating costs decreased ~~$767,931~~$771,766, or ~~17%~~20%, in the 2021 period compared to the 2020 period. ~~This~~The decrease in LOE per Mcfe was principally the result of our strategic decision to not participate with a working interest in new wells and the ~~Company selling some marginal properties~~increase 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.~~royalty interest production as a percentage of total production.

Transportation, gathering and marketing ~~decreased $905,677~~increased $442,371, or ~~20%~~12%, in the 2021 period compared to the 2020 period. This ~~decrease~~increase in costs was primarily driven by ~~lower natural gas~~higher production in the ~~2020~~2021 period compared to the ~~2019~~2020 period. The increase in rate per Mcfe was primarily due to the increase in natural gas sales in relation to other products. Natural gas sales bear the large majority of our transportation, gathering and marketing fees. On

Production taxes are paid on produced natural gas and oil based on a ~~per Mcfe basis, these handling fees were $0.56~~percentage of revenues from products sold at both fixed and variable rates established by federal, state or local taxing authorities. Production taxes increased $480,754, or 58%, 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~~2021 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 decreased $729,754 in the~~ 2020 period. The ~~decrease~~increase in amount was primarily the result of ~~decreased oil, NGL~~increased prices and ~~natural gas sales of $12,885,358~~production volumes in the ~~2020~~2021 period as compared to the ~~2019~~2020 period.

DD&A is the amount of cost basis of ~~oil~~natural gas and ~~natural gas~~oil properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production ~~basis.~~ basis for working interest, and on a straight-line basis for producing and non-producing minerals. Estimates of proved developed producing reserves are a major component of the calculation of depletion. DD&A decreased ~~$3,026,918~~$2,617,614, or ~~26%~~30%, in the ~~2020~~2021 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~~which $3,031,099 of the ~~$0.17~~decrease resulted from a $0.44 decrease in the DD&A rate per ~~Mcfe.~~Mcfe, partially offset by an increase of $413,485 resulting from production increasing 5% in the 2021 period. 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 utilizedan increase in ~~the reserve calculations~~reserves during the ~~2020~~2021 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.~~2020 period.

~~Provision for impairment was~~ ~~$29,904,528 for the 2020 period as compared to no~~We had a $45,855 provision for impairment in the ~~2019~~2021 period as compared to a $29,904,528 provision for impairment in the 2020 period. During the 2021 quarter, impairment of $37,879 was related to one field. These assets were written down to their fair market value as required by GAAP. During the 2020 period, impairment of $29,315,807 was recorded on seven different fields including the Fayetteville and Eagle Ford shales, which ~~represent~~represented 89% of our total impairment. ~~The Fayetteville Shale assets are dry-gas assets of which the~~

Company acquired a portion in 2011. Low natural gas prices at March 31, 2020, were the primary reason for impairment in this field. The Company recognized an impairment related to the Eagle Ford at September 30, 2019, 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~~future 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~~reducing future net ~~value~~cash flows associated with these fields, which caused ~~the~~these assets to fail the step one test for impairment as their undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The remaining $588,721 of impairment in the 2020 period was recorded on other assets.

~~Interest~~The decrease in interest expense ~~decreased $593,402 or 38%~~is due to a lower average debt balance in the ~~2020 period. This decrease was mainly due to lower outstanding debt balances ($30.0 million at June 30, 2020,~~2021 period as compared to ~~$41.5 million at June 30, 2019).~~

~~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 changed ~~$12,366,940,~~$6,508,940, 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%~~$1,102,000 benefit in the ~~2020~~2021 period. The income tax change resulted primarily from the reduction in net loss.

G&A are costs not directly associated with the production of natural gas and oil and include the cost of employee salaries and related benefits, office expenses and fees for professional services. G&A for the 2021 period decreased $240,802 as compared to the 2020 period. The decrease was primarily due to our cost reduction efforts.

~~The Company~~We had positive working capital of ~~$3,949,324~~$1,500,202 at June 30, ~~2020,~~2021, compared to positive working capital of ~~$11,378,829~~$13,335,880 at September 30, ~~2019.~~2020, which included $7.3 million of cash used for the fiscal 2021 first quarter acquisitions.

Cash and cash equivalents were ~~$2,025,081~~$2,908,500 as of June 30, ~~2020,~~2021, compared to ~~$6,160,691~~$10,690,395 at September 30, ~~2019,~~2020, a decrease of ~~$4,135,610.~~$7,781,895. The decrease in cash is primarily associated with the ~~purchase~~closing of ~~additional producing mineral assets~~previously announced acquisitions, which were funded by the proceeds from the issuance of equity 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.~~September 2020. Cash flows for the nine months ended June 30, 2021 and 2020 are summarized as follows:

Net cash provided (used) by:										For the Nine Months Ended June 30,
	2020			2019			Change			2021			2020			Change

Operating activities	$	9,825,740		$	14,332,951		$	(4,507,211	)	$	10,240,333		$	9,825,740		$	414,593
Investing activities		(7,042,684	)		4,643,215			(11,685,899	)		(19,500,653	)		(7,042,684	)		(12,457,969	)
Financing activities		(6,918,666	)		(17,978,191	)		11,059,525			1,478,425			(6,918,666	)		8,397,091
Increase (decrease) in cash and cash equivalents	$	(4,135,610	)	$	997,975		$	(5,133,585	)	$	(7,781,895	)	$	(4,135,610	)	$	(3,646,285	)

Net cash provided by operating activities ~~decreased $4,507,211~~increased $414,593 during the ~~2020~~2021 period, as compared to the ~~2019~~2020 period, primarily as the result of the following:

Net cash used by investing activities increased ~~$11,685,899~~$12,457,969 during the ~~2020~~2021 period, as compared to the ~~2019~~2020 period, primarily due to higher acquisition costs of ~~$5,183,550 and~~$9,033,249, lower net proceeds from the sale of assets of ~~$9,657,469, partially offset by lower~~$2,924,129 and higher payments of ~~$3,153,472~~$500,591 for drilling and completion activity during ~~2020.~~the 2021 period.

Net cash ~~used~~provided by financing activities ~~decreased $11,059,525~~increased $8,397,091 during the ~~2020~~2021 period, as compared to the ~~2019~~2020 period, primarily ~~the result~~due to higher net proceeds from equity issuance of ~~lower net payments on long-term debt of $4,075,000, decreased stock repurchases of $6,457,551 and~~$11,088,858, a decrease of ~~$526,974~~$728,339 in dividend payments as a result of a reduction in ~~the Company’s~~our quarterly dividend from $0.04 per share to $0.01 per share beginning with the June 2020 dividend ~~payment.~~payment and decreased stock repurchases of $4,894, which were partially offset by higher net payments on long-term debt of $8,850,000 in the 2021 period compared to $5,425,000 in the 2020 period.

Capital expenditures to drill and complete wells ~~decreased $3,153,472~~increased $500,591, or ~~94%~~255%, from the ~~2019~~2020 period to the ~~2020~~2021 period as a result of increased workover activity in the ~~Company’s strategy to cease participating in any new wells with a working interest at the end of fiscal 2019. The Company~~2021 period. We currently ~~has~~have no remaining commitments that would require significant capital to drill and complete ~~wells.~~wells since we ceased participating with a working interest in new wells at the end of fiscal 2019. All capital expenditures associated with workover activity during the 2021 period were part of the joint interest billing process under the

joint operating agreement that allows the operators to incur certain costs and charge proportionate amount to non-operated partners without asking for consent in advance.

Since ~~the Company has~~we decided to cease any further participation ~~in wells~~ with a working interest on ~~its~~our 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~~September 1, 2020, we completed an underwritten public offering of ~~530~~5,750,000 common shares (inclusive of overallotment option) with net ~~mineral acres in Eddy County, New Mexico, for $3.4~~proceeds of $8.2 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~~October 8, 2020, we closed on the purchase of ~~700~~297 net ~~mineral~~royalty acres in ~~Kingfisher, Canadian~~Grady County, Oklahoma, and ~~Garvin~~386 net royalty acres in Harrison, Panola and Nacogdoches Counties, ~~Oklahoma,~~Texas, for a purchase price of ~~$9.3~~$5.5 million ~~(after~~and 153,375 shares of our common stock, subject to customary closing ~~adjustments).~~adjustments. This purchase was mostly funded with cash from the common stock offering discussed above.

On November 12, 2020, we closed on the purchase of 184 net royalty acres in San Augustine County, Texas, for a purchase price of $750,000.

On December 17, 2020, we closed on the purchase of an additional 142 net royalty acres in San Augustine County, Texas, for a purchase price of $1 million.

On April 20, 2021, we completed an underwritten public offering of 6,175,000 common shares (inclusive of overallotment option which closed on April 23, 2021) with net proceeds of approximately $11.1 million.

On April 30, 2021, we closed on the acquisition of certain mineral and royalty assets located in Stephens, Carter, Canadian, McClain, Murray, and Garvin Counties, Oklahoma, for aggregate consideration of approximately $10.9 million, consisting of approximately $8.5 million in cash and the issuance of 1,200,000 shares of our ~~like-kind exchange sales.~~common stock. This acquisition included mineral and royalty assets totaling approximately 2,514 net royalty acres in the SCOOP. The acquisition had an effective date of November 1, 2020.

~~The Company~~On June 23, 2021, we closed on the purchase of 131 net royalty acres in the Haynesville, for a purchase price of $1 million.

On June 30, 2021, we closed on the purchase of 262 net royalty acres in the Haynesville, for a purchase price of $1.3 million.

We received lease bonus payments during ~~fiscal 2020~~the 2021 nine-month period totaling ~~$582,458. Looking forward, the~~$334,938. The cash flow from bonus payments associated with the leasing of drilling rights on ~~the Company’s~~our mineral acreage is difficult to ~~project~~predict as the ~~current~~ economic downturn due to COVID has decreased demand for new leasing by operators. However, management plans to continue to actively pursue leasing opportunities.

With continued ~~oil~~natural gas and ~~natural gas~~oil price volatility, management continues to evaluate opportunities for product price protection through additional hedging of ~~the Company’s~~our future ~~oil and~~ natural gas and oil production. Additionally, pursuant to the Credit Facility, we are required to enter into and maintain certain Swap Agreements (as defined in the Credit Facility) for a period of eighteen (18) months fixing prices on oil or gas expected to be produced. See Note ~~10:~~9: Derivatives in the notes to our condensed financial statements included in this Form 10-Q for a complete list of ~~the Company’s~~our outstanding derivative contracts at June 30, ~~2020, and Note 12: Subsequent Events for a listing of additional contracts entered into through August 11, 2020.~~2021.

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

	Nine months ended			Nine Months Ended
	June 30, 2020			June 30, 2021
Cash provided by operating activities	$	9,825,740		$	10,240,333
Cash provided (used) by:

Capital expenditures - acquisitions		(10,304,016	)		(19,337,265	)
Capital expenditures - drilling and completion of wells		(196,168	)		(696,759	)
Quarterly dividends of $0.09 per share		(1,486,031	)
Quarterly dividends of $0.01 per share					(757,692	)
Treasury stock purchases		(7,635	)		(2,741	)
Net borrowings (payments) on credit facility		(5,425,000	)		(8,850,000	)
Proceeds from sale of assets		3,457,500			533,371
Net proceeds from equity issuance					11,088,858
Net cash used		(13,961,350	)		(18,022,228	)

Net increase (decrease) in cash	$	(4,135,610	)	$	(7,781,895	)

Outstanding borrowings on the ~~credit facility~~Credit Facility at June 30, ~~2020,~~2021 were ~~$30,000,000, of which $2,000,000 is classified as current debt.~~$19,900,000.

~~Looking forward, the Company expects~~We expect to fund overhead costs and any dividend payments from cash provided by operating activities, cash on hand and borrowings ~~utilizing our~~on the Credit Facility. ~~The Company intends~~We intend to use ~~any~~ excess cash to ~~strengthen the Company’s Balance Sheets. The Company~~repay outstanding debt and fund mineral acquisitions. We had availability of $2$8.6 million at June 30, ~~2020,~~2021 under ~~its~~our Credit Facility and iswere in compliance with ~~its~~all 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~~our debt to EBITDA to no more than 4:3.5:1.

The Credit Facility was amended through a ninth amendment on April 7, 2021 (the “Ninth Amendment”). The Ninth Amendment reduced our borrowing base under the Credit Facility ~~was redetermined on June 24, 2020,~~to $29.0 million, extended the maturity date one year to November 30, 2023 and reduced the Quarterly Commitment Reductions from ~~$45~~$600,000 to $500,000, commencing on April 15, 2021. Additionally, the Ninth Amendment increased our distribution allowance from $1.0 million to ~~$32~~$1.5 million per annum for a period of one year from the date of the Ninth Amendment and ~~includes~~extends this allowance beyond the date that is one year following the date of the Ninth Amendment so long as (i) the Available Commitment is greater than or equal to 20% of the Total Commitment and (ii) the Leverage Ratio on a ~~Quarterly Commitment Reduction, whereby~~pro forma basis does not exceed 2.75 to 1.00. The existing prohibition of all Restricted Payments other than the ~~borrowing base~~subject distribution allowance and the existing requirement that immediately after giving effect to a permitted Restricted Payment, no Default or Event of Default may exist or result therefrom are to remain in effect. The Ninth Amendment also provides that any cash actually received by us in an equity raise is ~~reduced by $1 million each April 15, July 15, October 15~~considered “Excluded Cash” (previously, this was limited to cash actually received in an equity raise on or prior to December 24, 2020) 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~~that we may use such cash for acquisitions without BOKF’s prior written consent. We do not expect that the reduction in the borrowing base ~~we do not expect it~~ will impact the liquidity needed to maintain our normal operating strategies. ~~The~~We expect the next ~~expected~~ redetermination will occur in December ~~2020. Net debt as~~2021. The capitalized terms that are not defined in this description of ~~August 11, 2020 was $26.9 million.~~the Ninth Amendment have the meaning given to such terms in the Credit Facility.

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~~We expect that capital expenditures to drill and complete future 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~~2021 and availability under the Credit Facility, ~~the Company has~~management believes we have sufficient liquidity to fund ~~its~~our ongoing operations.

Critical accounting policies are those ~~the Company believes~~we believe are most important toin portraying ~~its~~our financial ~~conditions~~condition 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~~326 on October 1, ~~2019, (see Note 2: Leases)~~2020, there have been no material changes to the critical accounting policies previously disclosed in ~~the Company’s~~our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2019.~~

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.~~2020.

~~Oil,~~Natural gas, oil and NGL ~~and natural gas~~ prices have 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~~Our financial condition, liquidity and results of operations ~~of the Company~~ may be adversely impacted by precipitous changes in ~~oil~~natural gas and ~~natural gas~~oil prices. The market price of ~~oil, NGL and~~ natural gas, oil and NGL in ~~2020~~2021 will impact the amount of cash generated from operating activities, which will in turn impact the level of ~~the Company’s~~our capital expenditures and production.We utilize derivative contracts to reduce our exposure to unfavorable changes in natural gas and oil prices. We do not enter into these derivatives for speculative or trading purposes. Our derivative contracts are currently with BOKF and are secured under the Credit Facility. These arrangements cover only a portion of our production, provide only partial price protection against declines in natural gas and oil prices and limit the benefit of future increases in prices. Excluding the impact of ~~the Company’s 2020~~our 2021 derivative contracts, the price sensitivity in ~~2020~~2021 for each $1.00 per barrel change in wellhead oil price is ~~$329,199~~$269,785 for operating revenue based on ~~the Company’s~~our prior year oil volumes. The price sensitivity in ~~2020~~2021 for each $0.10 per Mcf change in wellhead natural gas price is ~~$708,676~~$596,271 for operating revenue based on ~~the Company’s~~our prior year natural gas volumes.

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.

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~~BOKF 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~~2021, we had ~~$30,000,000~~$19,900,000 outstanding under the Credit Facility and the effective interest rate was ~~4.25%~~4.00%. ~~At this point,~~An increase or decrease of 1.00% in the ~~Company does~~interest rate would have a corresponding increase or decrease in our annual net income of approximately $199,000, based on the balance outstanding at June 30, 2021.

We do not believe that ~~its~~our liquidity has been materially affected by the interest rate uncertainties noted in the last few years, and ~~the Company does~~we do not believe that ~~its~~our liquidity to fund ~~its~~our ongoing operations will be significantly impacted in the near future.

~~The Company maintains~~We maintain “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~~we file or ~~submits~~submit 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~~our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating ~~its~~our disclosure controls and procedures, management ~~recognized~~recognizes 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~~Our 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~~our disclosure controls and procedures were effective to ensure material information relating to ~~the Company~~us is made known to ~~them. Certain~~management. There were no changes ~~were~~in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting made toduring the ~~Company’s internal controls~~fiscal quarter or subsequent to the ~~fiscal quarter for validating~~date 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 theassessment was completed.

~~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.~~

We may be the subject of threatened or pending legal actions and contingencies in the normal course of conducting our business. We provide for costs related to these matters when a loss is probable and the amount can be reasonably estimated. The effect of the outcome of these matters on our future results of operations and liquidity cannot be predicted because any such effect depends on future results of operations and the amount or timing of the resolution of such matters. For certain types of claims, we maintain insurance coverage for personal injury and property damage, product liability and other liability coverages in amounts and with deductibles that we believe are prudent, but there can be no assurance that these coverages will be applicable or adequate to cover adverse outcomes of claims or legal proceedings against us. We are not a party to any pending legal proceedings that we believe would, individually or in the aggregate, have a material adverse effect on our financial condition, operating results or cash flow.

~~Please~~We are subject to certain risks and hazards due to the nature of our business activities. For a discussion of these risks, 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~~2020. There have been no material changes 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 discoveredrisk factors contained 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 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.~~2020. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

~~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~~our Board approved to continue to allow ~~the Company~~us to repurchase up to $1.5 million of ~~the Company’s~~our common stock at management’s ~~discretion. The~~discretion (the “Repurchase Program”). Our 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~~our 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~~us to ~~its~~our ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

On October 8, 2020, we issued 153,375 shares of our common stock to Red Stone Resources, LLC as part of the consideration for an asset purchase from Red Stone Resources, LLC. In exchange for the shares, we received a $250,000 credit against the purchase price for the assets. The shares were issued in reliance upon the exemption from registration provided by Rule 506 of Regulation D of the Securities Act. These shares were registered with the SEC in March 2021.

On April 30, 2021, we issued 1,200,000 shares of our common stock to Crestwood Exploration Partners, LLC, Palmetto Investment Partners, LLC and Palmetto Investment Partners II, LLC as part of the consideration for a purchase of mineral and royalty assets. In exchange for the shares, we received a $2,400,000 credit against the purchase price for the assets. The shares were issued in reliance upon the exemption from registration provided by Rule 506 of Regulation D of the Securities Act. These shares were registered under a registration statement on Form S-3 filed with the SEC on May 26, 2021. The shares issued in connection with the acquisition are being held in escrow in the names of the sellers to satisfy potential indemnification claims, and to the extent not returned to us, the shares held in escrow will be released 180 days after the closing date of the acquisition.

The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on payment of dividends.

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.


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

Part I	Financial Information		Page

	Item 1	Condensed Financial Statements		1

		Condensed Balance Sheets – June 30, ~~2020,~~2021, and September 30, ~~2019~~2020		1

		Condensed Statements of Operations – Three and nine months ended June 30, ~~2020~~2021 and ~~2019~~2020		2

		Statements of Stockholders’ Equity – Nine months ended June 30, ~~2020~~2021 and ~~2019~~2020		3

		Condensed Statements of Cash Flows – Nine months ended June 30, ~~2020~~2021 and ~~2019~~2020		5

		Notes to Condensed Financial Statements		6

	Item 2	Management's ~~discussion~~Discussion and ~~analysis~~Analysis of ~~financial condition~~Financial Condition and ~~results~~Results of ~~operations~~Operations		1915

	Item 3	Quantitative and ~~qualitative disclosures~~Qualitative Disclosures about ~~market risk~~Market Risk		2726

	Item 4	Controls and ~~procedures~~Procedures		2726

Part II	Other Information

	Item 1	Legal Proceedings		26

	Item 1A	Risk Factors		2827

	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		2927

	Item 6	Exhibits		2927

	Signatures		2928

ASC	Accounting Standards Codification.
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~~PHX Minerals 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	United States 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.

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~~2019-12, Simplifying the Accounting for Income Taxes.	This standard ~~changes how entities will measure credit losses~~is intended to clarify and simplify the accounting for ~~most financial assets~~income taxes by removing certain exceptions 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.amending existing guidance.	Q1 ~~2021~~2022	~~The~~This standard is effective for ~~interim and annual periods~~public business entities 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.~~2020, with early adoption permitted. The Company ~~is evaluating~~does not believe the ~~new~~adoption of this standard ~~and is currently in the process of estimating~~will have a material impact on its financial ~~statement impact; however, the impact is not expected to be material. Historically, the Company's credit losses on oil, NGL~~statements and ~~natural gas sales receivables have been immaterial.~~related disclosures.

Quarter Ended	Net royalty acres ⁽¹⁾⁽²⁾		Purchase Price ⁽¹⁾	Area of Interest

June 30, 2021
		262	$1.3 million	Haynesville / LA
		131	$1.0 million	Haynesville / TX
		2,514	$10.9 million	SCOOP / OK
March 31, 2021
	No significant acquisitions
December 31, 2020
		142	$1.0 million	Haynesville / TX
		184	$0.8 million	Haynesville / TX
		386	$3.5 million	Haynesville / TX
		297	$2.3 million	SCOOP / OK
September 30, 2020
	No significant acquisitions
June 30, 2020
	No significant acquisitions
March 31, 2020
	No significant acquisitions
December 31, 2019
	964		$9.3 million	SCOOP / OK
(1) Excludes subsequent closing adjustments and insignificant acquisitions.
(2) An estimated net royalty equivalent was used for the minerals included in the net royalty acres.

Quarter Ended	Net mineral acres		Sale Price	Gain/(Loss)	Location
June 30, 2021
		2,857	$0.3 million	$0.2 million	Central Basin Platform, TX
March 31, 2021
	No significant divestitures
December 31, 2020
	No significant divestitures
September 30, 2020
		5,925	$0.8 million	$0.7 million	Northwest OK
June 30, 2020
	No significant divestitures
March 31, 2020
	No significant divestitures
December 31, 2019
	530		$3.4 million	$3.3 million	Eddy County, NM

	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


Contract period (Calendar Year)	Contract total volume	Index	Contract average price
Natural gas costless collars
Remaining 2021	1,462,000 Mmbtu	NYMEX Henry Hub	$2.37 floor / $3.06 ceiling
2022	2,540,500 Mmbtu	NYMEX Henry Hub	$2.42 floor / $3.17 ceiling
2023	166,000 Mmbtu	NYMEX Henry Hub	$2.37 floor / $3.26 ceiling
Natural gas fixed price swaps
Remaining 2021	742,000 Mmbtu	NYMEX Henry Hub	$2.81
2022	547,500 Mmbtu	NYMEX Henry Hub	$2.73
2023	84,000 Mmbtu	NYMEX Henry Hub	$2.56
Oil costless collars
Remaining 2021	15,000 Bbls	NYMEX WTI	$36.87 floor / $45.76 ceiling
2022	68,500 Bbls	NYMEX WTI	$40.25 floor / $50.35 ceiling
Oil fixed price swaps
Remaining 2021	63,000 Bbls	NYMEX WTI	$40.27
2022	59,000 Bbls	NYMEX WTI	$41.51

	For the Three Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	10,899,820	$	3,517,561	210%

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

(a)	EXHIBITS	Exhibit 3.1 – Amended and Restated Certificate of Incorporation of PHX Minerals Inc. (incorporated by reference to Exhibit 3.1 to Form 8-K filed with the SEC March 8, 2021) Exhibit 10.1 – Ninth Amendment to Amended and Restated Credit Agreement, dated April 7, 2021, by and among PHX Minerals Inc., the lenders party thereto, and BOKF, NA dba Bank of Oklahoma, as administrative agent for the lenders and as issuing bank (incorporated by reference to Exhibit 10.1 to Form 8-K filed with the SEC on April 8, 2021) Exhibit 10.2 – Purchase and Sale Agreement dated April 14, 2021, by and among PHX Minerals Inc., as Buyer, and Palmetto Investments Partners, LLC, Palmetto Investments Partners II, LLC and Crestwood Exploration Partners, LLC, as Sellers (incorporated by reference to Exhibit 10.1 to Form 8-K filed with the SEC on April 15, 2021) Exhibit 31.1 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Executive Officer
		Exhibit 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Financial Officer
		Exhibit 32.1 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002 by Chief Executive Officer
		Exhibit 32.2 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002 by Chief Financial Officer
		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 Exhibit 104 – Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

~~PANHANDLE OIL AND GAS~~PHX MINERALS INC.
		~~PANHANDLE OIL AND GAS~~PHX MINERALS INC.

August ~~13, 2020~~5, 2021		/s/ Chad L. Stephens
Date		Chad L. Stephens, President,
		Chief Executive Officer

August ~~13, 2020~~5, 2021		/s/ Ralph D’Amico
Date		Ralph D’Amico, Vice President,
		Chief Financial Officer

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

Quarter ended	Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold
6/30/2021		908,471		31,095		18,255		1,204,571
3/31/2021		924,969		31,768		19,088		1,230,105
12/31/2020		487,925		27,840		14,948		744,653
9/30/2020		491,234		27,326		20,181		776,276
6/30/2020		544,249		28,468		16,574		814,501

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

Quarter ended	Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold
6/30/2021		970,872		24,397		28,498		1,288,242
3/31/2021		810,851		24,501		18,140		1,066,697
12/31/2020		987,531		30,835		26,190		1,329,681
9/30/2020		932,368		28,300		26,556		1,261,503
6/30/2020		817,660		26,670		18,595		1,089,251