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.

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 2, 2021: 30,400,612~~February 11, 2022: 34,498,626 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”), 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 natural gas and oil prices; the level of production on our properties; estimates of quantities of natural gas, oil and NGL reserves and their values; general economic or industry conditions; 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 natural gas, oil, and 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, ~~2020~~2021 (“Annual Report”), and all quarterly reports on Form 10-Q filed subsequently 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 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 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 ended September 30. For example, references to ~~2021~~2022 mean the fiscal year ~~ended~~ending September 30, ~~2021.~~2022.

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.~~December 31. For example, the 2022 quarter refers to the quarterly period ended December 31, 2021 and the 2021 quarter refers to the quarterly period ended ~~June 30, 2021 and the 2020 quarter refers to the quarterly period ended June 30,~~December 31, 2020.

All references to ~~nine-month~~three-month periods in this Form 10-Q, unless otherwise noted, refer to the Company’s fiscal ~~nine-month~~three-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~~three-month periods refer to the ~~nine-month~~three-month period ended ~~June 30.~~December 31. For example, in sections of this Form 10-Q discussing ~~nine-month~~three-month periods, the 2022 period refers to the three-month period ended December 31, 2021 and the 2021 period refers to the ~~nine-month~~three-month period ended ~~June 30, 2021 and the 2020 period refers to the nine-month period ended June 30,~~December 31, 2020.

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

	June 30, 2021			September 30, 2020			December 31, 2021			September 30, 2021
Assets	(unaudited)						(unaudited)
Current assets:
Cash and cash equivalents	$	2,908,500		$	10,690,395		$	1,559,350		$	2,438,511
Natural gas, oil, and NGL sales receivables (net of $0 allowance for uncollectable accounts)		5,114,387			2,943,220			8,020,067			6,428,982
Refundable income taxes		2,379,756			3,805,227			-			2,413,942
Other		480,600			351,088			1,333,279			942,082
Total current assets		10,883,243			17,789,930			10,912,696			12,223,517

Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		323,187,303			324,886,491			249,861,777			319,984,874
Non-producing natural gas and oil properties		32,894,588			18,993,814			54,960,073			40,466,098
Other		681,125			582,444			883,310			794,179
		356,763,016			344,462,749			305,705,160			361,245,151
Less accumulated depreciation, depletion and amortization		(259,018,926	)		(263,590,801	)		(195,971,382	)		(257,643,661	)
Net properties and equipment		97,744,090			80,871,948			109,733,778			103,601,490

Operating lease right-of-use assets		628,617			690,316			585,888			607,414
Other, net		558,659			669,641			570,072			578,593

Total assets	$	109,814,609		$	100,021,835		$	121,802,434		$	117,011,014

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	1,173,258		$	997,637		$	612,387		$	772,717
Derivative contracts, net		6,754,328			281,942			6,413,308			12,087,988
Income taxes payable								499,939			334,050
Current portion of operating lease liability		130,973			127,108			133,614			132,287
Accrued liabilities and other		1,324,482			1,297,363			2,047,437			1,809,337
Short-term debt		-			1,750,000
Total current liabilities		9,383,041			4,454,050			9,706,685			15,136,379

Long-term debt		19,900,000			27,000,000			20,000,000			17,500,000
Deferred income taxes, net		212,007			1,329,007			709,906			343,906
Asset retirement obligations		2,845,919			2,897,522			2,157,289			2,836,172
Derivative contracts, net		1,354,174			425,705			132,569			1,696,479
Operating lease liability, net of current portion		822,907			921,625			755,433			789,339

Total liabilities		34,518,048			37,027,909			33,461,882			38,302,275

Stockholders' equity:
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
Class A voting common stock, $0.01666 par value; 54,000,500 shares authorized and 34,405,287 issued at December 31, 2021; 36,000,500 shares authorized and 32,770,433 issued at September 30, 2021								573,192			545,956
Capital in excess of par value		25,844,372			10,649,611			36,741,266			33,213,645
Deferred directors' compensation		1,701,110			1,874,007			1,835,721			1,768,151
Retained earnings		53,033,376			56,244,100			54,798,980			48,966,420
		81,081,994			69,145,022			93,949,159			84,494,172
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	)
Less treasury stock, at cost; 377,232 shares at December 31, 2021, and 388,545 shares at September 30, 2021								(5,608,607	)		(5,785,433	)
Total stockholders' equity		75,296,561			62,993,926			88,340,552			78,708,739
Total liabilities and stockholders' equity	$	109,814,609		$	100,021,835		$	121,802,434		$	117,011,014

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

	Three Months Ended June 30,						Nine Months Ended June 30,						Three Months Ended December 31,
	2021			2020			2021			2020			2021		2020
Revenues:	(unaudited)						(unaudited)						(unaudited)
Natural gas, oil and NGL sales	$	10,899,820		$	3,517,561		$	25,670,624		$	18,329,017		$	13,687,164	$	6,424,979
Lease bonuses and rental income		259,152			22,996			319,139			572,787			78,915		1,433
Gains (losses) on derivative contracts		(5,487,483	)		(838,282	)		(8,089,662	)		2,415,401			2,836,168		(254,036	)
Gain on asset sales		270,070			3,108			313,595			3,275,996
		5,941,559			2,705,383			18,213,696			24,593,201		$	16,602,247	$	6,172,376
Costs and expenses:
Lease operating expenses		1,064,989			1,147,948			3,100,052			3,871,818			1,256,011		1,004,412
Transportation, gathering and marketing		1,538,174			956,653			4,138,653			3,696,282			1,213,604		1,280,965
Production taxes		596,858			134,249			1,316,038			835,284			678,947		276,026
Depreciation, depletion and amortization		2,137,707			2,464,568			6,176,173			8,793,787			1,583,760		2,260,649
Provision for impairment		45,855			358,826			45,855			29,904,528			5,585		-
Interest expense		220,439			241,191			790,202			958,429			176,719		301,898
General and administrative		2,275,104			1,908,790			6,065,677			6,306,479			2,095,557		1,731,097
Other expense (income)		235,027			(73,687	)		136,083			(44,551	)
Losses (gains) on asset sales and other														2,147,815		(16,951	)
Total costs and expenses		8,114,153			7,138,538			21,768,733			54,322,056			9,157,998		6,838,096
Income (loss) before provision (benefit) for income taxes		(2,172,594	)		(4,433,155	)		(3,555,037	)		(29,728,855	)		7,444,249		(665,720	)

Provision (benefit) for income taxes		(816,000	)		(877,940	)		(1,102,000	)		(7,610,940	)		762,000		(69,000	)

Net income (loss)	$	(1,356,594	)	$	(3,555,215	)	$	(2,453,037	)	$	(22,117,915	)	$	6,682,249	$	(596,720	)




Basic and diluted earnings (loss) per common share (Note 4)	$	(0.05	)	$	(0.21	)	$	(0.10	)	$	(1.34	)	$	0.20	$	(0.03	)

Basic and diluted weighted average shares outstanding:
Common shares		28,117,199			16,403,243			24,308,185			16,375,736			32,895,631		22,378,146
Unissued, directors' deferred compensation shares		192,059			141,799			174,454			152,500			232,091		178,090
		28,309,258			16,545,042			24,482,639			16,528,236			33,127,722		22,556,236




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

Dividends declared per share of
common stock and to be paid in quarter ended March 31													$	0.015	$	0.01

(The accompanying 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, 2020		22,647,306	$	377,304	$	10,649,611		$	1,874,007		$	56,244,100			(411,487	)	$	(6,151,096	)	$	62,993,926
Balances at September 30, 2021																								32,770,433	$	545,956	$	33,213,645		$	1,768,151	$	48,966,420			(388,545	)	$	(5,785,433	)	$	78,708,739

Net income (loss)		-		-		-			-			(596,720	)		-			-			(596,720	)		-		-		-			-		6,682,249									6,682,249
Equity offering		153,375		2,555		223,203			-			-			-			-			225,758
Private Placement																								1,519,481		25,315		3,450,258			-		-			-			-			3,475,573
Purchase of treasury stock																								-		-		-			-		-			(700	)		(1,855	)		(1,855	)
Restricted stock awards		-		-		122,978			-			-			-			-			122,978			-		-		255,844			-		-			-			-			255,844
Dividends ($0.02 per share)		-		-		-			-			(454,936	)		-			-			(454,936	)
Dividends ($0.025 per share)																								-		-		-			-		(849,689	)		-			-			(849,689	)
Distribution of restricted stock to officers and directors		-		-		(316,886	)		-			-			21,220			317,239			353			115,373		1,921		(178,481	)		-		-			12,013			178,681			2,121
Increase in deferred directors' compensation charged to expense		-		-		-			44,527			-			-			-			44,527			-		-		-			67,570		-			-			-			67,570
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
Balances at December 31, 2021																								34,405,287	$	573,192	$	36,741,266		$	1,835,721	$	54,798,980			(377,232	)	$	(5,608,607	)	$	88,340,552
(unaudited)
Net income (loss)		-		-		-			-			(499,723	)		-			-			(499,723	)
Equity offering		-		-		(29,240	)		-			-			-			-			(29,240	)
Restricted stock awards		-		-		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		24,545		409		339,913			(340,322	)		-			-			-			-
Increase in deferred directors' compensation charged to expense		-		-		-			55,727			-			-			-			55,727
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)		-		-		-			-			(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		-		-		258,526			-			-			-			-			258,526
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		-		-		-			67,171			-			-			-			67,171
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
	Common Stock				Excess of			Directors'		Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation		Earnings			Shares			Stock			Total

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)		-		-		-			-		(596,720	)		-			-			(596,720	)
Equity offering		153,375		2,555		223,203			-		-			-			-			225,758
Restricted stock awards		-		-		122,978			-		-			-			-			122,978
Dividends ($0.02 per share)		-		-		-			-		(454,936	)		-			-			(454,936	)
Distribution of restricted stock to officers and directors		-		-		(316,886	)		-		-			21,220			317,239			353
Increase in deferred directors' compensation charged to expense		-		-		-			44,527		-			-			-			44,527
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)

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

Class A voting

Capital in

Deferred

Common Stock

Excess of

Directors'

Retained

Treasury

Treasury

Shares

Amount

Par Value

Compensation

Earnings

Shares

Stock

Total

Balances at September 30, 2019

16,897,306

$
281,509

$
2,967,984

$
2,555,781

$
81,848,301

(558,051
)

$
(8,344,042
)

$
79,309,533

Net income (loss)

-

-

-

-

1,892,114

-

-

1,892,114

Purchase of treasury stock

-

-

-

-

-

(632
)

(7,635
)

(7,635
)
Restricted stock awards

-

-

148,515

-

-

-

-

148,515

Dividends ($0.08 per share)

-

-

-

-

(1,319,899
)

-

-

(1,319,899
)
Distribution of restricted stock
   to officers and directors

-

-

(82,821
)

-

-

5,546

82,914

93

Increase in deferred directors'
   compensation charged to
   expense

-

-

-

86,212

-

-

-

86,212

Balances at December 31, 2019

16,897,306

$
281,509

$
3,033,678

$
2,641,993

$
82,420,516

(553,137
)

$
(8,268,763
)

$
80,108,933

(unaudited)

Net income (loss)

-

-

-

-

(20,454,814
)

-

-

(20,454,814
)
Restricted stock awards

-

-

343,101

-

-

-

-

343,101

Distribution of deferred
   directors' compensation

-

-

(112,396
)

(603,485
)

-

47,885

715,880

(1
)
Increase in deferred directors'
   compensation charged to
   expense

-

-

-

53,918

-

-

-

53,918

Balances at March 31, 2020

16,897,306

$
281,509

$
3,264,383

$
2,092,426

$
61,965,702

(505,252
)

$
(7,552,883
)

$
60,051,137

(unaudited)

Net income (loss)

-

-

-

-

(3,555,215
)

-

-

(3,555,215
)
Restricted stock awards

-

-

128,196

-

-

-

-

128,196

Dividends ($0.01 per share)

-

-

-

-

(166,132
)

-

-

(166,132
)
Distribution of deferred
   directors' compensation

-

-

(17,179
)

(306,698
)

-

21,664

323,877

-

Increase in deferred directors'
   compensation charged to
   expense

-

-

-

44,058

-

-

-

44,058

Balances at June 30, 2020

16,897,306

$
281,509

$
3,375,400

$
1,829,786

$
58,244,355

(483,588
)

$
(7,229,006
)

$
56,502,044

(unaudited)

	Three Months Ended December 31,
	2021			2020
Operating Activities	(unaudited)
Net income (loss)	$	6,682,249		$	(596,720	)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		1,583,760			2,260,649
Impairment of producing properties		5,585			-
Provision for deferred income taxes		366,000			(69,000	)
Gain from leasing fee mineral acreage		(78,922	)		(232	)
Proceeds from leasing fee mineral acreage		95,039			232
Net (gain) loss on sales of assets		2,163,359			(30,862	)
Directors' deferred compensation expense		67,570			44,527
Total (gain) loss on derivative contracts		(2,836,168	)		254,036
Cash receipts (payments) on settled derivative contracts		-			613,314
Restricted stock awards		255,844			122,978
Other		37,138			14,387
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables		(1,591,085	)		(813,167	)
Other current assets		(325,780	)		(676,620	)
Accounts payable		(95,649	)		(398,556	)
Income taxes receivable		2,413,942			(12,545	)
Other non-current assets		10,253			30,958
Income taxes payable		165,889			-
Accrued liabilities		(281,034	)		(271,998	)
Total adjustments		1,955,741			1,068,101
Net cash provided by operating activities		8,637,990			471,381

Investing Activities
Capital expenditures		(192,677	)		(128,083	)
Acquisition of minerals and overriding royalty interests		(11,643,827	)		(7,869,746	)
Net proceeds from sales of assets		4,586,492			-
Net cash provided (used) by investing activities		(7,250,012	)		(7,997,829	)

Financing Activities
Borrowings under Credit Facility		4,000,000			-
Payments of loan principal		(1,500,000	)		(1,750,000	)
Net proceeds from equity issuance		(32,507	)		(24,242	)
Cash receipts from (payments on) off-market derivative contracts		(4,402,422	)		-
Payments of dividends		(332,210	)		(225,887	)
Net cash provided (used) by financing activities		(2,267,139	)		(2,000,129	)

Increase (decrease) in cash and cash equivalents		(879,161	)		(9,526,577	)
Cash and cash equivalents at beginning of period		2,438,511			10,690,395
Cash and cash equivalents at end of period	$	1,559,350		$	1,163,818

Supplemental Schedule of Noncash Investing and Financing Activities:

Dividends declared and unpaid	$	517,479		$	229,049

Gross additions to properties and equipment	$	15,183,829		$	7,986,350
Equity offering used for acquisitions		(3,510,001	)		(250,000	)
Net (increase) decrease in accounts payable for properties and equipment additions		162,676			261,479
Capital expenditures and acquisitions	$	11,836,504		$	7,997,829

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

Nine Months Ended June 30,

2021

2020

Operating Activities

(unaudited)

Net income (loss)

$
(2,453,037
)

$
(22,117,915
)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion and amortization

6,176,173

8,793,787

Impairment of producing properties

45,855

29,904,528

Provision for deferred income taxes

(1,117,000
)

(6,158,000
)
Gain from leasing fee mineral acreage

(316,541
)

(567,975
)
Proceeds from leasing fee mineral acreage

334,938

582,458

Net (gain) loss on sales of assets

(136,596
)

(3,258,994
)
Directors' deferred compensation expense

167,425

184,188

Total (gain) loss on derivative contracts

8,089,662

(2,415,401
)
Cash receipts (payments) on settled derivative contracts

(688,807
)

3,230,034

Restricted stock awards

542,674

619,812

Other

72,126

3,718

Cash provided (used) by changes in assets and liabilities:

Natural gas, oil and NGL sales receivables

(2,134,395
)

2,194,430

Other current assets

(89,957
)

(121,635
)
Accounts payable

209,014

31,755

Income taxes receivable

1,425,471

(134,908
)
Other non-current assets

87,065

6,544

Accrued liabilities

26,263

(950,686
)
Total adjustments

12,693,370

31,943,655

Net cash provided by operating activities

10,240,333

9,825,740

Investing Activities

Capital expenditures

(696,759
)

(196,168
)
Acquisition of minerals and overriding royalty interests

(19,337,265
)

(10,304,016
)
Proceeds from sales of assets

533,371

3,457,500

Net cash provided (used) by investing activities

(19,500,653
)

(7,042,684
)

Financing Activities

Borrowings under Credit Facility

-

6,061,725

Payments of loan principal

(8,850,000
)

(11,486,725
)
Net proceeds from equity issuance

11,088,858

-

Purchases of treasury stock

(2,741
)

(7,635
)
Payments of dividends

(757,692
)

(1,486,031
)
Net cash provided (used) by financing activities

1,478,425

(6,918,666
)

Increase (decrease) in cash and cash equivalents

(7,781,895
)

(4,135,610
)
Cash and cash equivalents at beginning of period

10,690,395

6,160,691

Cash and cash equivalents at end of period

$
2,908,500

$
2,025,081

Supplemental Schedule of Noncash Investing and Financing Activities:

Additions to asset retirement obligations

$
-

$
4

Gross additions to properties and equipment

$
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

(42,154
)

164,650

Capital expenditures and acquisitions

$
20,034,024

$
10,500,184

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

The accompanying unaudited condensed financial statements of 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, ~~2020.~~2021. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “PHX” or “Company” refer to 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.

The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932 (Extractive Activities—Oil and Gas), and upon ~~disposition,~~leasing, 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 9 for discussion of the Company’s accounting for derivative contracts.

Sales of natural gas, oil and 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 natural gas, oil and NGL revenues for the three ~~and nine~~ months ended ~~June 30,~~December 31, 2021 and 2020:

	Three Months Ended June 30, 2021						Nine Months Ended June 30, 2021						Three Months Ended December 31, 2021
	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	$	5,200,868	$	3,489,167	$	8,690,035
Oil revenue		1,934,966		1,603,996		3,538,962		4,748,987		4,275,962		9,024,949		1,894,027		1,682,077		3,576,104
NGL revenue		453,935		648,326		1,102,261		1,095,124		1,460,056		2,555,180		625,623		795,402		1,421,025
Natural gas, oil and NGL sales	$	5,412,842	$	5,486,978	$	10,899,820	$	12,424,644	$	13,245,980	$	25,670,624	$	7,720,518	$	5,966,646	$	13,687,164


	Three Months Ended June 30, 2020						Nine Months Ended June 30, 2020						Three Months Ended December 31, 2020
	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	$	1,190,165	$	2,268,636	$	3,458,801
Oil revenue		719,012		711,005		1,430,017		4,680,871		4,404,949		9,085,820		1,096,952		1,244,114		2,341,066
NGL revenue		129,833		103,023		232,856		548,921		823,559		1,372,480		230,338		394,774		625,112
Natural gas, oil and NGL sales	$	1,641,072	$	1,876,489	$	3,517,561	$	8,352,743	$	9,976,274	$	18,329,017	$	2,517,455	$	3,907,524	$	6,424,979

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 natural gas, oil and NGL sales receivables line item on the Company’s balance sheets. The difference between the Company's estimates and the actual amounts received for natural gas, oil and NGL sales is recorded in the quarter that payment is received from the third party. For the three ~~and nine~~ months ended 2020, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was considered a change in estimate. For the three months ended June 30,December 31, 2021, revenue recognized ~~in these~~during the reporting ~~periods~~period related to performance obligations satisfied in prior reporting periods for existing wells was approximately ~~$2.0~~$0.5 million and primarily due to change in price ~~estimates as a result of basis differentials during winter storms.~~estimates. 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 it. Through cash received on new wells, in the ~~2021 third~~2022 first quarter, the Company identified several producing properties on its minerals that had production dates prior to the ~~2021 third~~2022 first quarter. Estimates of the natural gas and oil sales related to those properties were made and are reflected in the ~~third~~first quarter natural gas, oil and NGL sales on the Company’s Statements of Operations and on the Company’s balance sheets in 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,~~December 31, 2021, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling ~~$365,871, of~~$342,361 ,of which ~~$72,717~~$83,569 related to the production periods before October 1, 2020 and ~~$293,154~~$258,792 related to ~~the first and second quarters of~~fiscal 2021. In connection with obtaining more relevant information identifying additional new wells on Company acreage for the three and nine months ended June 30, 2020, the Company recorded a change in estimate for new wells to 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.

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.~~benefits, and the change in valuation allowance from prior year. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that exceeds cost depletion, which is calculated on a unit-of-production basis. The Company completes an evaluation of the expected realization of the Company’s gross deferred tax assets each quarter. 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, if~~Depending upon whether a provision for income taxes ~~is expected for the year, will decrease the effective tax rate, while the effect will increase the effective tax rate if~~or a benefit for income taxes is expected for a year, Federal and Oklahoma excess percentage depletion will either decrease or increase the ~~year.~~effective tax rate, respectively. 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.

As of December 31, 2021, the Company completed an evaluation of the expected realization of its gross deferred tax assets. Due to reversal of deferred tax assets in the current period, the Company is in a net deferred tax liability position as of December 31, 2021. The Company expects to realize its gross deferred tax assets against reversing deferred tax liabilities in future periods. Therefore, in the current period the Company released the valuation allowance against deferred tax assets. The Company continues to maintain a valuation allowance against certain state net operating loss carryforwards that are not expected to be utilized.The Company’s effective tax rate for the ~~nine~~three months ended ~~June 30,~~December 31, 2021 was a ~~31% benefit~~10% provision as compared to a ~~26%~~10% benefit for the ~~nine~~three months ended ~~June 30, 2020. The Company’s effective tax rate for the quarter ended June 30, 2021 was a 38% benefit as compared to a 20% benefit for the quarter ended June 30,~~December 31, 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 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 March 31, 2021, the Company received a tax refund totaling $1.4 million associated with the alternative minimum tax (AMT) credits, which was accelerated by the CARES Act. ~~Additionally,~~During the quarter ended December 31, 2021, the Company ~~has a~~received $2.2 million ~~receivable~~ associated with the carryback of the Company’s 2020 federal net operating loss.

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

For the three ~~and nine~~ months ended ~~June 30,~~December 31, 2021, the Company did not include restricted stock in the diluted EPS calculation because the effect would have been antidilutive. The average shares outstanding of restricted stock excluded from the diluted EPS was 73,208 and 81,663 for the three months ended December 31, 2021 and 2020, respectively.

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

	Three Months Ended June 30,						Nine Months Ended June 30,						Three Months Ended December 31,
	2021			2020			2021			2020			2021		2020
Basic EPS
Numerator:
Basic net income (loss)	$	(1,356,594	)	$	(3,555,215	)	$	(2,453,037	)	$	(22,117,915	)	$	6,682,249	$	(596,720	)
Denominator:
Basic weighted average shares outstanding		28,309,258			16,545,042			24,482,639			16,528,236			33,127,722		22,556,236
Basic EPS	$	(0.05	)	$	(0.21	)	$	(0.10	)	$	(1.34	)	$	0.20	$	(0.03	)

Diluted EPS
Numerator:
Basic net income (loss)	$	(1,356,594	)	$	(3,555,215	)	$	(2,453,037	)	$	(22,117,915	)	$	6,682,249	$	(596,720	)
Diluted net income (loss)		(1,356,594	)		(3,555,215	)		(2,453,037	)		(22,117,915	)		6,682,249		(596,720	)
Denominator:
Basic weighted average shares outstanding		28,309,258			16,545,042			24,482,639			16,528,236			33,127,722		22,556,236
Effects of dilutive securities:
Unvested restricted stock		-			-			-			-			-		-
Diluted weighted average shares outstanding		28,309,258			16,545,042			24,482,639			16,528,236			33,127,722		22,556,236
Diluted EPS	$	(0.05	)	$	(0.21	)	$	(0.10	)	$	(1.34	)	$	0.20	$	(0.03	)

~~The~~The Company has a ~~$200,000,000~~$100,000,000 credit facility (the “Credit Facility”) with a syndicate of banks led by Independent Bank ~~of Oklahoma (“BOKF”), which had~~pursuant to a ~~borrowing base of $28,500,000 as of June 30,~~credit agreement entered into in September 2021 (as amended, the “Credit ~~Facility”~~Agreement”). The Credit Facility ~~matures on November 30, 2023. The Credit Facility is subject to at least semi-annual~~has a current borrowing base ~~determinations, wherein BOKF applies its commodity pricing forecast to the Company’s reserve forecast~~of $32,000,000 as of December 31, 2021, and ~~determines~~ a ~~borrowing base.~~maturity date of September 1, 2025. The Credit Facility is secured by ~~all~~the Company’s personal property and at least 80% of the ~~Company’s~~total value of the proved, developed and producing oil and gas properties. The interest rate is based on ~~BOKF prime plus from 1.00% to 1.75%, or 30-day~~either (a) LIBOR plus an applicable margin ranging from ~~2.50%~~2.750% to ~~3.25%.~~3.750% per annum based on the Company’s Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the U.S. Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on the Company’s Borrowing Base Utilization. The election of ~~BOKF~~Independent Bank prime or LIBOR is at the Company’s discretion. The interest rate spread from ~~BOKF~~Independent Bank 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~~a larger percent of ~~loan balance to~~ the borrowing base ~~increases.~~ is advanced. At ~~June 30,~~December 31, 2021, the effective interest rate was ~~4.00%~~3.75%.

The Company’s debt is recorded at the carrying amount on its balance sheets. The carrying amount of the debt under 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~~“Other, net” on the Company’s balance sheets. Total debt issuance cost, net of amortization, as of ~~June 30,~~December 31, 2021 was ~~$252,001.~~$288,247. The debt issuance cost is amortized over the life of the Credit Facility.

~~On April 7, 2021,~~Determinations of the ~~Company entered into the ninth amendment to the Credit Facility. The amendment, among other things, reduced the Company’s~~ borrowing base under the Credit Facility ~~to $29.0 million, extended~~are made semi-annually (usually June and December) or whenever the ~~maturity date by one year to November 30, 2023, and reduced~~lending banks, in their sole discretion, believe that there has been a material change in the ~~Quarterly Commitment Reductions from $600,000 to $500,000, commencing on April 15, 2021. Additionally, the amendment increased~~value of 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~~natural gas and 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 a pro forma basis does not exceed 2.75 to 1.00. The existing prohibition of all Restricted Payments other than the 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 remain in effect.

oil properties. The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain ~~limits~~restrictions on the Company’s ~~incurrence~~ability to incur debt, grant liens, make fundamental changes and engage in certain transactions with affiliates. The Credit Facility also restricts the Company’s ability to make certain restricted payments if before or after the Restricted Payment (i) the Available Commitment is less than ten percent (10%) of ~~indebtedness, liens, payment of dividends and acquisitions of stock.~~the Borrowing Base or (ii) the Leverage Ratio on a pro forma basis is greater than 2.50 to 1.00. In addition, the Company is required to maintain certain financial ratios, a current ratio (as ~~defined~~described in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to ~~EBITDA ratio~~EBITDAX (as defined in the Credit Facility) of no more than 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,~~December 31, 2021, the Company was in compliance with the covenants of the Credit Facility and had ~~$19,900,000~~$20,000,000 in outstanding borrowings and had $12,000,000 available for borrowing under the Credit ~~Facility, and had $8,600,000 of borrowing base~~

~~availability under the Credit~~ Facility.~~The~~ All capitalized terms ~~that are not defined~~ in this description of the Credit Facility ~~including the description of the ninth amendment,~~that are not otherwise defined in this Form 10-Q shall have the meaning ~~given~~assigned to ~~such terms~~them in the Credit ~~Facility.~~Agreement.

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~~Common Stock rather than cash for all or a portion of their annual retainers and Board 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.

Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur. The following table summarizes the Company’s pre-tax compensation expense for the three ~~and nine~~ months ended ~~June 30,~~December 31, 2021 and 2020 related to the Company’s market-based, time-based and performance-based restricted stock:

	Three Months Ended				Nine Months Ended				Three Months Ended
	June 30,				June 30,				December 31,
	2021		2020		2021		2020		2021		2020
Market-based, restricted stock	$	79,118	$	10,247	$	168,483	$	285,150	$	77,482	$	10,247
Time-based, restricted stock		179,408		117,949		374,191		334,662		178,362		112,731
Performance-based, restricted stock		-		-		-		-		-		-
Total compensation expense	$	258,526	$	128,196	$	542,674	$	619,812	$	255,844	$	122,978

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 is shown in the following table:

	As of June 30, 2021				As of December 31, 2021
	Unrecognized Compensation Cost		Weighted Average Period (in years)		Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	725,627		2.43	$	569,027		1.97
Time-based, restricted stock		552,371		1.01		194,601		0.96
Performance-based, restricted stock		-				-
Total	$	1,277,998			$	763,628

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

	June 30, 2021			September 30, 2020			December 31, 2021			September 30, 2021
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties	$	323,187,303		$	324,886,491		$	249,861,777		$	319,984,874
Non-producing natural gas and oil properties		32,894,588			18,993,814			54,960,073			40,466,098
Other property and equipment		681,125			582,444			883,310			794,179
		356,763,016			344,462,749			305,705,160			361,245,151
Less accumulated depreciation, depletion and amortization		(259,018,926	)		(263,590,801	)		(195,971,382	)		(257,643,661	)
Net properties and equipment	$	97,744,090		$	80,871,948		$	109,733,778		$	103,601,490

All purchases made in ~~2020~~2021 and ~~2021~~2022 were offor mineral and royalty acreage and were accounted for as asset acquisitions.

The Company divested approximately 700 working interest wellbores during the three months ended December 31, 2021, which resulted in reductions to producing natural gas and oil properties of approximately $71.1 million, accumulated depreciation, depletion and amortization of approximately $63.6 million, asset retirement obligation of approximately $0.7 million, and a loss on sale of assets of approximately $2.2 million. The net proceeds from these divestitures was approximately $4.6 million.

Management considers the estimation of the Company’s natural gas, oil and NGL reserves to be the most significant of its judgments and estimates. Changes in natural gas, oil and 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, with assistance from Company staff, prepares estimates of natural gas, oil and 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 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 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 natural gas, oil and NGL pricing assumptions are used by management to prepare estimates of natural gas, oil and NGL reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Natural gas, oil and NGL prices are volatile, affected by worldwide production and consumption, and are outside the control of management.

Company management monitors all long-lived assets, principally natural gas and oil properties, for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates; future drilling and completion costs; future sales prices for natural gas, oil and NGL; future production costs; estimates of future natural gas, oil and NGL reserves to be recovered and the timing thereof; the economic and regulatory climates; and other factors. The need to test a

property for impairment may result from significant declines in sales prices or unfavorable adjustments to 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,~~December 31, 2021 and 2020, management’s assessment resulted in an0 impairment ~~provision of $37,879~~provisions on producing ~~properties and $7,976~~properties. The Company wrote off $5,585 on wells ~~that~~assigned with 0 consideration received during the ~~Company wrote off.~~

~~For the nine~~three months ended June 30, 2020, 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. During the three and nine months ended June 30, 2020, impairment on wells that were written off totaled $358,826 and $588,721, respectively. December 31, 2021.

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 natural gas and 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.~~BP Energy Company (“BP”). The derivative contracts with ~~BOKF~~BP are secured under the Credit Facility with ~~BOKF~~Independent Bank (see Note 5: Long-Term Debt). The derivative instruments have settled or will settle based on the prices below:

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 liability of ~~$8,108,502~~$6,545,877 as of ~~June 30,~~December 31, 2021, and a net liability of ~~$707,647~~$13,784,467 as of September 30, ~~2020.~~2021. 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:

	Three Months Ended						Nine Months Ended						Three Months Ended
	June 30,						June 30,						December 31,
	2021			2020			2021			2020			2021			2020
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	(11,975	)	$	18,000		$	(21,064	)	$	18,000		$	-		$	(8,967	)
Natural gas fixed price swaps		(20,185	)		268,650			(18,943	)		1,488,970
Natural gas fixed price swaps⁽¹⁾														(1,352,192	)		(1,863	)
Oil costless collars		(346,786	)		625,968			(370,432	)		827,664			-			88,944
Oil fixed price swaps		(625,744	)		786,504			(278,368	)		895,400
Oil fixed price swaps⁽¹⁾														(362,139	)		535,200
Cash received (paid) on derivative contracts, net	$	(1,004,690	)	$	1,699,122		$	(688,807	)	$	3,230,034		$	(1,714,331	)	$	613,314
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(1,732,932	)	$	(60,035	)	$	(1,135,852	)	$	(32,152	)	$	79,971		$	678,961
Natural gas fixed price swaps		(953,201	)		(129,865	)		(670,605	)		(815,630	)		4,477,934			288,887
Oil costless collars		(680,443	)		(757,060	)		(1,787,689	)		(283,255	)		-			(410,886	)
Oil fixed price swaps		(1,116,217	)		(1,590,444	)		(3,806,709	)		316,404			(7,406	)		(1,424,312	)
Non-cash gain (loss) on derivative contracts, net	$	(4,482,793	)	$	(2,537,404	)	$	(7,400,855	)	$	(814,633	)	$	4,550,499		$	(867,350	)
Gains (losses) on derivative contracts, net	$	(5,487,483	)	$	(838,282	)	$	(8,089,662	)	$	2,415,401		$	2,836,168		$	(254,036	)

(1) Excludes $2,688,091 of cash paid to settle off-market derivative contracts that are not reflected on the statement of operations.													(1) Excludes $2,688,091 of cash paid to settle off-market derivative contracts that are not reflected on the statement of operations.

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice of whether or not to offset, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Company’s balance sheets.

The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's balance sheets at ~~June 30,~~December 31, 2021 and September 30, ~~2020.~~2021. The Company has offset all amounts subject to master netting agreements in the Company's balance sheets at ~~June 30,~~December 31, 2021 and September 30, ~~2020.~~2021.

	June 30, 2021												September 30, 2020								December 31, 2021												September 30, 2021
	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			Current Liabilities			Non-Current Liabilities		Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets			Current Liabilities			Non-Current Liabilities
Gross amounts recognized	$	130,690		$	6,885,018		$	144,462		$	1,498,636		$	864,466		$	1,146,408		$	425,705	$	386,069		$	6,799,377		$	364,782		$	497,351		$	17,395		$	12,105,383		$	1,696,479
Offsetting adjustments		(130,690	)		(130,690	)		(144,462	)		(144,462	)		(864,466	)		(864,466	)		-		(386,069	)		(386,069	)		(364,782	)		(364,782	)		(17,395	)		(17,395	)		-
Net presentation on Condensed Balance Sheets	$	-		$	6,754,328		$	-		$	1,354,174		$	-		$	281,942		$	425,705
Net presentation on condensed balance sheets																					$	-		$	6,413,308		$	-		$	132,569		$	-		$	12,087,988		$	1,696,479

(a) See Note 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 at ~~June 30,~~December 31, 2021:

	Fair Value Measurement at June 30, 2021										Fair Value Measurement at December 31, 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	$	-	$	(4,542,115	)	$	-	$	(4,542,115	)	$	-	$	(6,625,848	)	$	-	$	(6,625,848	)
Derivative Contracts - Collars	$	-	$	(3,566,387	)	$	-	$	(3,566,387	)	$	-	$	79,971		$	-	$	79,971

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:

(a) When indicators of impairment are present, the Company assesses the carrying value of its natural gas and oil properties for impairment. This assessment utilizes estimates of future cash flows as well as other market data. Significant judgments and assumptions in these assessments include estimates of future natural gas, oil and NGL prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying values in excess of their calculated fair values. This table excludes impairments on properties that were written off during the three and nine months ended June 30, 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,~~December 31, 2021 and September 30, ~~2020,~~2021, 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, the valuation of which is classified as Level 2 as the carrying amount of the Company’s debt under the 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 December 31, 2021, the Company entered into new derivative contracts as summarized in the table below:

Subsequent to December 31, 2021, the Company purchased 267 net royalty acres for $2.5 million and sold 7,201 net mineral acres for $2.1 million.

PHX is an owner and manager of perpetual natural gas and 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 natural gas and oil properties. Exploration and development of our natural gas and oil properties is conducted by third-party natural gas and oil exploration and production companies (primarily larger independent operating companies). We do not operate any of our natural gas and oil

properties. While we previously were an active working interest participant in wells drilled on our mineral and leasehold acreage, our current focus is on growth through mineral acquisitions in our core areas of focus in the SCOOP and Haynesville and development of our significant mineral acreage inventory in our core areas of focus, which include the SCOOP, STACK and Arkoma Stack plays in Oklahoma, the Permian Basin in Texas and New Mexico, the Haynesville and Eagle Ford plays in Texas, the Fayetteville play in Arkansas, and the Bakken/Three Forks play in North Dakota. We have ceased taking 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 depend primarily upon our existing reserve quantities; costs associated with acquiring new reserves; production quantities and related production costs; and natural gas, oil and NGL prices. Although a significant amount of our revenue continues to be derived from the production and sale of 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 and NGL.

THREE MONTHS ENDED ~~JUNE 30,~~DECEMBER 31, 2021 COMPARED TO THREE MONTHS ENDED ~~JUNE 30,~~DECEMBER 31, 2020

We recorded ~~a third~~first quarter ~~2021~~2022 net ~~loss~~income of ~~$1,356,594,~~$6,682,249, or ~~$0.05~~$0.20 per share, as compared to a net loss of ~~$3,555,215,~~$596,720, or ~~$0.21~~$0.03 per share, in the ~~2020~~first fiscal 2021 quarter. The change in net ~~loss~~income was principally the result of increased natural gas, oil and NGL sales, and ~~decreased LOE, DD&A and impairment expense,~~an increase in non-cash gain on derivative contracts, partially offset by ~~an increase in losses~~a loss on ~~derivative contracts, G&A, transportation, gathering and marketing expenses and production taxes.~~sales of assets. These items are further discussed below.

For the three months ended ~~June 30,~~December 31, 2021, the increase in natural gas, oil and NGL sales was primarily due to increases in natural gas, oil and NGL prices of ~~145%~~136%, ~~146%~~86% and ~~256%~~111%, respectively, and an increase in natural gas ~~oil~~ and NGL volumes of ~~38%~~7% and 8%, ~~1% and 33%, respectively.~~respectively, partially offset by a decrease in oil volumes of 18%. The following table outlines our production and average sales prices for natural gas, oil and NGL for the three-month periods of fiscal ~~2021~~2022 and ~~2020:~~2021:

~~Production increased across all three product categories~~The production increase in royalty volumes during the three months ended ~~June 30,~~December 31, 2021, as compared to the three months ended ~~June 30,~~December 31, 2020, ~~due to improved market conditions, resulting in (i) previously curtailed, high interest~~resulted from acquisition wells ~~being worked over and brought fully back online~~ in the ~~STACK, Arkoma Stack,~~Haynesville Shale and ~~Fayetteville Shale, (ii) acquisitions~~SCOOP plays coming online. The decrease 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~~working interest volumes resulted from naturally declining production in ~~high interest~~high-interest wells ~~such as~~in the Eagle Ford ~~Shale.~~Shale and divestiture of low-value legacy working interest in Oklahoma.

Quarter ended	Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold		Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold
12/31/2021										1,574,265		48,074		44,256		2,128,248
9/30/2021										1,609,101		54,043		46,369		2,211,570
6/30/2021		1,879,343		55,492		46,753		2,492,813		1,879,343		55,492		46,753		2,492,813
3/31/2021		1,735,820		56,269		37,228		2,296,802		1,735,820		56,269		37,228		2,296,802
12/31/2020		1,475,456		58,675		41,138		2,074,334		1,475,456		58,675		41,138		2,074,334
9/30/2020		1,423,602		55,626		46,737		2,037,779
6/30/2020		1,361,909		55,138		35,169		1,903,752

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

Quarter ended	Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold		Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold
12/31/2021										949,523		25,996		19,953		1,225,220
9/30/2021										705,397		29,442		19,364		998,230
6/30/2021		908,471		31,095		18,255		1,204,571		908,471		31,095		18,255		1,204,571
3/31/2021		924,969		31,768		19,088		1,230,105		924,969		31,768		19,088		1,230,105
12/31/2020		487,925		27,840		14,948		744,653		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

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

Quarter ended	Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold		Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold
12/31/2021										624,742		22,078		24,303		903,028
9/30/2021										903,704		24,601		27,005		1,213,340
6/30/2021		970,872		24,397		28,498		1,288,242		970,872		24,397		28,498		1,288,242
3/31/2021		810,851		24,501		18,140		1,066,697		810,851		24,501		18,140		1,066,697
12/31/2020		987,531		30,835		26,190		1,329,681		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

When we lease our mineral interests, we generally receive an upfront cash payment, or lease bonus. Lease bonuses and rental income increased ~~$236,156~~$77,482 in the ~~2021~~2022 quarter compared to the ~~2020~~2021 quarter primarily as the result of increased leasing activity in the ~~2021~~2022 quarter.

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 for positions that have settled within the period. The net gain (loss) on derivative instruments for the periods indicated includes the following:

	For the Three Months Ended June 30,							For the Three Months Ended December 31,
							Percent							Percent
	2021			2020			Incr. or (Decr.)	2021			2020			Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net(1)	$	(1,004,690	)	$	1,699,122		(159%)	$	(1,714,331	)	$	613,314		(380%)
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(4,482,793	)	$	(2,537,404	)	(77%)	$	4,550,499		$	(867,350	)	625%
Gains (losses) on derivative contracts, net	$	(5,487,483	)	$	(838,282	)	(555%)	$	2,836,168		$	(254,036	)	1,216%

	As of June 30,							As of December 31,
	2021			2020				2021			2020
Fair value of derivative contracts
Net asset (net liability)	$	(8,108,502	)	$	1,679,511		(583%)	$	(6,545,877	)	$	(1,574,997	)	316%

(1) Excludes $2,688,091 of cash paid to settle off-market derivative contracts that are not reflected on the statement of operations.								(1) Excludes $2,688,091 of cash paid to settle off-market derivative contracts that are not reflected on the statement of operations.

The change in net ~~losses~~(loss) gain on derivative contracts ~~in both periods were principally~~was due to the natural gas and oil collars and fixed price swaps being ~~less~~more beneficial in the quarter ended December 31, 2021 in relation to their respective contracted volumes and ~~prices at the beginning of the periods.~~prices.

Our natural gas and oil costless collar contracts and fixed price swaps in place at ~~June 30,~~December 31, 2021 had expiration dates ~~of July 2021~~ through ~~February~~December 2023. We utilize derivative contracts for the purpose of protecting our cash flow and return on investments.

	For the Three Months Ended June 30,					For the Three Months Ended December 31,
					Percent					Percent
	2021		2020		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Lease operating expenses	$	1,064,989	$	1,147,948	(7%)	$	1,256,011	$	1,004,412	25%
Lease operating expenses per MCFE	$	0.43	$	0.60	(28%)	$	0.59	$	0.48	23%

We are responsible for a portion of LOE relating to a well as a working interest owner. LOE includes normal recurring and nonrecurring expenses associated with our working interests necessary to produce hydrocarbons from our natural gas and oil wells, including maintenance, repairs, salt water disposal, insurance and workover expenses. Total LOE related to field operating costs ~~decreased $82,959,~~increased $251,599, or 7%25%, in the ~~2021~~2022 quarter compared to the ~~2020~~2021 quarter. The ~~decrease~~increase in LOE ~~per Mcfe~~ was principally the result of ~~our strategic decision to not participate with a working interest~~increased workover expenses and inflation on services in ~~new wells and~~ the ~~increase in royalty interest production as a percentage of total production.~~2022 quarter.

	For the Three Months Ended June 30,					For the Three Months Ended December 31,
					Percent					Percent
	2021		2020		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Transportation, gathering and marketing	$	1,538,174	$	956,653	61%	$	1,213,604	$	1,280,965	(5%)
Transportation, gathering and marketing per MCFE	$	0.62	$	0.50	24%	$	0.57	$	0.62	(8%)

Transportation, gathering and marketing ~~increased $581,521,~~decreased $67,361, or ~~61%~~5%, in the ~~2021~~2022 quarter compared to the ~~2020 quarter. This increase in costs was primarily driven by higher production in the~~ 2021 ~~quarter compared to the 2020~~ quarter. The ~~increase~~decrease in rate per Mcfe was primarily due to the divestiture of assets with higher deduct rates and the increase in natural gas sales in ~~relation to other products.~~fields with lower deduct rates. Natural gas sales bear the large majority of our transportation, gathering and marketing fees.

	For the Three Months Ended June 30,							For the Three Months Ended December 31,
							Percent							Percent
	2021			2020			Incr. or (Decr.)	2021			2020			Incr. or (Decr.)
Production taxes	$	596,858		$	134,249		345%	$	678,947		$	276,026		146%
Production taxes as % of sales		5.5	%		3.8	%	45%		5.0	%		4.3	%	16%

Production taxes are paid on produced natural gas and oil based on a 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,~~$402,921, or ~~345%~~146%, in the ~~2021~~2022 quarter as compared to the ~~2020~~2021 quarter. The increase in amount was primarily the result of increased natural gas, oil and NGL sales of ~~$7,382,259~~$7,262,185 and increases in sales volumes from states with higher tax rates in the ~~2021~~2022 quarter as compared to the ~~2020~~2021 quarter.

	For the Three Months Ended June 30,					For the Three Months Ended December 31,
					Percent					Percent
	2021		2020		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Depreciation, depletion and amortization	$	2,137,707	$	2,464,568	(13%)	$	1,583,760	$	2,260,649	(30%)
Depreciation, depletion and amortization per MCFE	$	0.86	$	1.29	(33%)	$	0.74	$	1.09	(32%)

DD&A is the amount of cost basis of natural gas and oil properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production 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 ~~$326,861,~~$676,889, or ~~13%~~30%, in the ~~2021~~2022 quarter compared to the ~~2020~~2021 quarter, of which ~~$1,086,750~~$735,649 of the decrease resulted from a ~~$0.43~~$0.35 decrease in the DD&A rate per Mcfe, partially offset by an increase of ~~$759,889~~$58,760 resulting from production increasing ~~31%~~3% in the ~~2021~~2022 quarter. The rate decrease was mainly due to an increase in reserves during the ~~2021~~2022 quarter, as compared to the ~~2020~~2021 quarter.

We had a ~~$45,855~~$5,585 provision for impairment in the 2022 quarter as compared to no provision for impairment in the 2021 ~~quarter as compared to a $358,826 provision for impairment in the 2020~~ quarter. During the ~~2021~~2022 quarter, impairment ~~of $37,879~~ was related to ~~one field.~~ ~~These assets were written down~~working interest wells that we wrote off and assigned the interests 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.~~operator.

	For the Three Months Ended June 30,					For the Three Months Ended December 31,
					Percent					Percent
	2021		2020		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Interest expense	$	220,439	$	241,191	(9%)	$	176,719	$	301,898	(41%)
Weighted average debt outstanding	$	21,801,648	$	31,071,740	(30%)	$	18,206,522	$	27,796,196	(34%)

The decrease in interest expense is due to a lower average debt balance in the ~~2021~~2022 quarter as compared to the ~~2020~~2021 quarter.

Income taxes changed ~~$61,940,~~$831,000, from a ~~$877,940~~$69,000 benefit in the ~~2020~~2021 quarter to a ~~$816,000 benefit~~$762,000 provision in the ~~2021~~2022 quarter. The change in income taxes resulted primarily from increasing from a net loss of $596,720 in the ~~reduction~~2021 quarter to net income of $6,682,249 in ~~net loss.~~the 2022 quarter, partially offset by a reversal of valuation allowance in the 2022 quarter.

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

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.

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. The change in net income (loss) was principally the result of increased natural gas, oil and NGL sales and decreased LOE, DD&A, impairment expense and G&A, partially offset by an increase in losses on derivative contracts, transportation, gathering and marketing expenses, production taxes and a reduction in gain on asset sales and income tax benefit. These items are further discussed below.

The increase in natural gas, oil and NGL sales was primarily due to increases in natural gas, oil and NGL prices of 60%, 25% and 81%, respectively, and an increase in natural gas and NGL volumes of 12% and 3%, respectively. The following table outlines our production and average sales prices for natural gas, oil and NGL for the nine-month periods of fiscal 2021 and 2020:

Natural gas volumes increased during the nine months ended June 30, 2021, as compared to the nine months ended June 30, 2020, primarily as a result of (i) acquisitions in the 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 in the Fayetteville Shale and production downtime and curtailments in response to market conditions in the SCOOP. The decrease in 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 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 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 loss on derivative contracts in the current period was principally due to the natural gas and oil collars and fixed price swaps being less beneficial in relation to their respective contracted volumes and prices at the beginning of 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 our cash flow and return on investments.

We are responsible for a portion of LOE relating to a well as a working interest owner. LOE includes normal recurring and nonrecurring expenses associated with our working interests necessary to produce hydrocarbons from our natural gas and oil wells, including maintenance, repairs, salt water disposal, insurance and workover expenses. Total LOE related to field operating costs decreased $771,766, or 20%, in the 2021 period compared to the 2020 period. 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 increase in royalty interest production as a percentage of total production.

Transportation, gathering and marketing increased $442,371, or 12%, in the 2021 period compared to the 2020 period. This increase in costs was primarily driven by higher production in the 2021 period compared to the 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.

Production taxes are paid on produced natural gas and oil based on a 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 2021 period compared to the 2020 period. The increase in amount was primarily the result of increased prices and production volumes in the 2021 period as compared to the 2020 period.

DD&A is the amount of cost basis of natural gas and oil properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production 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 $2,617,614, or 30%, in the 2021 period, of which $3,031,099 of the decrease resulted from a $0.44 decrease in the DD&A rate per 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 an increase in reserves during the 2021 period, as compared to the 2020 period.

We had a $45,855 provision for impairment in the 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 represented 89% of our total impairment.~~ The impairment in these seven fields was caused by lower future prices reducing future net cash flows associated with these fields, which caused 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.

~~The decrease in interest expense is due to a lower average debt balance in the 2021 period as compared to the 2020 period.~~

~~Income taxes changed $6,508,940, from a $7,610,940 benefit in the 2020 period to a $1,102,000 benefit in the 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~~2022 quarter increased $364,460 as compared to the ~~2020 period.~~2021 quarter. The ~~decrease~~increase was primarily due to ~~our cost reduction efforts.~~increased activity during the 2022 quarter.

We had positive working capital (current assets less current liabilities excluding current derivatives) of ~~$1,500,202~~$7,619,319 at ~~June 30,~~December 31, 2021, compared to positive working capital of ~~$13,335,880~~$9,175,126 at September 30, ~~2020, which included $7.3 million of cash used for the fiscal 2021 first quarter acquisitions.~~

Cash and cash equivalents were ~~$2,908,500~~$1,559,350 as of ~~June 30,~~December 31, 2021, compared to ~~$10,690,395~~$2,438,511 at September 30, ~~2020,~~2021, a decrease of ~~$7,781,895.~~$879,161. The decrease in cash is primarily associated with the closing of previously announced acquisitions, which were funded by ~~the~~cash on hand, cash from operating activities and proceeds from the ~~issuance~~sale of ~~equity in September 2020.~~assets. Cash flows for the ~~nine~~three months ended ~~June 30,~~December 31, 2021, and 2020 are summarized as follows:

Net cash provided (used) by:	For the Nine Months Ended June 30,									For the Three Months Ended December 31,
	2021			2020			Change			2021			2020			Change

Operating activities	$	10,240,333		$	9,825,740		$	414,593		$	8,637,990		$	471,381		$	8,166,609
Investing activities		(19,500,653	)		(7,042,684	)		(12,457,969	)		(7,250,012	)		(7,997,829	)		747,817
Financing activities		1,478,425			(6,918,666	)		8,397,091			(2,267,139	)		(2,000,129	)		(267,010	)
Increase (decrease) in cash and cash equivalents	$	(7,781,895	)	$	(4,135,610	)	$	(3,646,285	)	$	(879,161	)	$	(9,526,577	)	$	8,647,416

Net cash provided by operating activities increased ~~$414,593~~$8,166,609 during the ~~2021~~2022 period, as compared to the ~~2020~~2021 period, primarily as the result of the following:

Net cash used by investing activities ~~increased $12,457,969~~decreased $747,817 during the ~~2021~~2022 period, as compared to the ~~2020~~2021 period, primarily due to higher ~~acquisition costs of $9,033,249, lower~~ net proceeds from the sale of assets of ~~$2,924,129~~$4,586,492, partially offset by higher acquisition costs of $3,774,081 and higher payments of ~~$500,591~~$64,594 for drilling and completion activity during the ~~2021~~2022 period.

Net cash ~~provided~~used by financing activities increased ~~$8,397,091~~$267,010 during the ~~2021~~2022 period, as compared to the ~~2020~~2021 period, primarily due to ~~higher net proceeds from equity issuance~~increased cash payments on off-market derivative contracts of ~~$11,088,858, a decrease~~$4,402,422 and an increase of ~~$728,339~~$106,323 in dividend payments, ~~as a result of a reduction in our quarterly dividend from $0.04 per share to $0.01 per share beginning with the June 2020 dividend payment and decreased stock repurchases of $4,894,~~ which were partially offset by higher net ~~payments~~borrowings on long-term debt of ~~$8,850,000~~$2,500,000 in the ~~2021~~2022 period compared to ~~$5,425,000~~net payments of $1,750,000 in the ~~2020~~2021 period.

~~Capital~~We had no capital expenditures to drill and complete new wells ~~increased $500,591, or 255%, from~~in the ~~2020 period to the~~ 2022 and2021 ~~period~~ periods, as a result of ~~increased workover activity~~our strategy to cease participating in ~~the 2021 period.~~new wells with a working interest after fiscal year 2019. We currently have no remaining commitments that would require significant capital to drill and complete 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.~~wells.

Since we decided to cease any further participation with a working interest on 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 September 1, 2020,~~Over the past five quarters, we ~~completed an underwritten public offering of 5,750,000 common shares (inclusive of overallotment option) with net proceeds of $8.2 million.~~

~~On October 8, 2020, we closed on~~made the purchase of 297 net royalty acres in Grady County, Oklahoma, and 386 net royalty acres in Harrison, Panola and Nacogdoches Counties, Texas, for a purchase price of $5.5 million and 153,375 shares of our common stock, subject to customary closing adjustments. This purchase was mostly funded with cash from the common stock offering discussed above.following acquisitions:

~~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 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.

~~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 the ~~2021 nine-month period~~first fiscal 2022 quarter totaling $334,938. The cash flow from bonus payments associated with the leasing of drilling rights on our mineral acreage is difficult to predict as the economic downturn due to COVID has decreased demand for new leasing by operators. However, managementapproximately $0.1 million. Management plans to continue to actively pursue leasing opportunities.

With continued natural gas and oil price volatility, management continues to evaluate opportunities for product price protection through additional hedging of our future 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 9: Derivatives in the notes to our condensed financial statements included in this Form 10-Q for a complete list of our outstanding derivative contracts at ~~June 30,~~December 31, 2021.

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

	Nine Months Ended			Three Months Ended
	June 30, 2021			December 31, 2021
Cash provided by operating activities	$	10,240,333		$	8,637,990
Cash provided (used) by:

Capital expenditures - acquisitions		(19,337,265	)		(11,643,827	)
Capital expenditures - drilling and completion of wells		(696,759	)		(192,677	)
Quarterly dividends of $0.01 per share		(757,692	)		(332,210	)
Treasury stock purchases		(2,741	)
Net borrowings (payments) on credit facility		(8,850,000	)		2,500,000
Proceeds from sale of assets		533,371
Net proceeds from sale of assets					4,586,492
Cash receipts from (payments on) off-market derivative contracts					(4,402,422	)
Net proceeds from equity issuance		11,088,858			(32,507	)
Net cash used		(18,022,228	)		(9,517,151	)

Net increase (decrease) in cash	$	(7,781,895	)	$	(879,161	)

Outstanding borrowings on the Credit Facility at ~~June 30,~~December 31, 2021 were ~~$19,900,000.~~$20,000,000.

WeLooking forward, we expect to fund overhead costs, mineral and ~~any~~royalty acquisitions and dividend payments from cash provided by operating activities, cash on hand and borrowings ~~on the~~from our Credit Facility. ~~We intend to use excess cash to repay outstanding debt and fund mineral acquisitions.~~ We had availability of ~~$8.6~~$12.0 million at ~~June 30,~~December 31, 2021 under our Credit Facility and were in compliance with all debt covenants (current ratio, debt to trailing 12-month ~~EBITDA,~~EBITDAX, as defined byin the Credit ~~Facility,~~Agreement, and restricted payments limited by leverage ratio). The debt covenants in the Credit Facility limit the maximum ratio of our debt to ~~EBITDA~~EBITDAX to no more than 3.5:1.

We have our $100,000,000 Credit Facility with a group of banks led by Independent Bank pursuant to the Credit Agreement entered into in September 2021. The Credit Facility ~~was amended through~~has a ~~ninth amendment on April 7, 2021 (the “Ninth Amendment”).~~ ~~The Ninth Amendment reduced our~~current borrowing base ~~under~~of $32,000,000 as of December 31, 2021, and a maturity date of September 1, 2025. Interest on the Credit Facility will be calculated based on either (a) LIBOR plus an applicable margin ranging from 2.750% to $29.0 million, extended the maturity date one year to November 30, 2023 and reduced the Quarterly Commitment Reductions from $600,000 to $500,000, commencing on April 15, 2021. Additionally, the Ninth Amendment increased our distribution allowance from $1.0 million to $1.5 million3.750% per annum based on our Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for ~~a period~~such day, or (2) the overnight cost of federal funds as announced by the US Federal Reserve System in effect on such day plus one-half of one ~~year~~percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on our Borrowing Base Utilization. Under the ~~date~~terms of the ~~Ninth Amendment~~Credit Facility, a 5% interest penalty may apply to any outstanding amount not paid when due or that remains outstanding while an event of default exists. The Credit Facility contains financial and ~~extends this allowance beyond~~various other covenants that are common in such agreements, including a (a) maximum ratio of consolidated Funded Indebtedness to consolidated pro forma EBITDAX of 3.50 to 1.00, calculated on a rolling four-quarter basis, and (b) minimum ratio of consolidated Current Assets to consolidated Current Liabilities (excluding the ~~date that is one year following~~Loan Balance) of 1.00 to 1.00. Other negative covenants include restrictions on our ability to incur debt, grant liens, make fundamental changes and engage in certain transactions with affiliates. The Credit Facility also restricts our ability to make certain restricted payments if both before and after the ~~date of the Ninth Amendment so long as~~Restricted Payment (i) the Available Commitment is ~~greater~~less than or equal to ~~20%~~ten percent (10%) of the ~~Total Commitment and~~Borrowing Base or (ii) the Leverage Ratio on a pro forma basis ~~does not exceed 2.75~~is greater than 2.50 to 1.00. The existing prohibition of all Restricted Payments other than the 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 considered “Excluded Cash” (previously, this was limited to cash actually received in an equity raise on or prior to December 24, 2020) and that we may use such cash for acquisitions without BOKF’s prior written consent. W~~e do not expect that the reduction in the borrowing base will impact the liquidity needed to maintain our normal operating strategies. We expect the next redetermination will occur in December 2021.~~ ~~The~~All capitalized terms ~~that are not defined~~ in this description of the ~~Ninth Amendment~~Credit Facility that are not otherwise defined in this Form 10-Q shall have the meaning ~~given~~assigned to ~~such terms~~them in the Credit ~~Facility.~~Agreement.

~~We expect that~~Based on our expected capital ~~expenditures to drill and complete future wells will be immaterial. Based on~~expenditure levels, anticipated cash provided by operating activities for ~~2021 and~~2022, combined with availability under ~~the~~our Credit Facility ~~management believes~~and potential future sales of Common Stock under our currently effective shelf registration statement, including pursuant to the ATM Agreement described below, we expect to have sufficient liquidity to fund our ongoing operations.

On August 25, 2021, we entered into an At-The-Market Equity Offering Sales Agreement (the “ATM Agreement”) with Stifel, Nicolaus & Company, Incorporated, as sales agent and/or principal (“Stifel”), pursuant to which we may offer and sell, from time to time through or to Stifel, up to 3,000,000 shares of our Common Stock. During the quarter ended December 31, 2021, we did not sell any shares of Common Stock pursuant to the ATM Agreement, and as of December 31, 2021, we have sold a total of 221,000 shares of Common Stock pursuant to the ATM Agreement for aggregate proceeds of approximately $0.7 million, net of commissions paid.

Critical accounting policies are those we believe are most important in portraying our financial 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 326 on October 1, 2020, there~~There have been no material changes to the critical accounting policies previously disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2020.~~2021.

There ~~were~~have been 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, ~~2020.~~

Natural gas, oil and NGL prices historically have ~~historically~~ been volatile, and this volatility is expected to ~~continue, especially~~continue. Uncertainty continues to exist as to the direction of natural gas, oil and NGL price trends, and there remains a wide divergence in ~~light of~~ the ~~ongoing COVID-19 pandemic and related economic repercussions. Our financial condition, liquidity and results of operations may~~opinions held in the industry. We can be ~~adversely~~significantly impacted by ~~precipitous~~ changes in natural gas and oil prices. The market price of natural gas, oil and NGL in ~~2021~~2022 will impact the amount of cash generated from operating activities, which will in turn impact the level of our capital expenditures for acquisitions 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 our ~~2021~~2022 derivative contracts, the price sensitivity ~~in 2021 for each $1.00 per barrel change in wellhead oil price is $269,785 for operating revenue based on our prior year oil volumes. The price sensitivity in 2021~~ for each $0.10 per Mcf change in wellhead natural gas price is ~~$596,271~~approximately $669,972 for operating revenue based on our prior year natural gas volumes. The price sensitivity in 2022 for each $1.00 per barrel change in wellhead oil is approximately $224,479 for operating revenue based on our prior year oil volumes.

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to ~~the~~our Credit Facility. ~~Borrowings~~Interest under our Credit Facility is calculated based on either (a) LIBOR plus an applicable margin ranging from 2.750% to 3.750% per annum based on our Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the U.S. Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on our Borrowing Base Utilization. Under the terms of the Credit Facility, ~~bear~~a 5% interest ~~at the BOKF prime rate plus from 1.00%~~penalty may apply to ~~1.75%,~~any outstanding amount not paid when due or ~~30 day LIBOR plus from 2.50% to 3.25%.~~that remains outstanding while an event of default exists. At ~~June 30,~~December 31, 2021, we had ~~$19,900,000~~$20,000,000 outstanding under the Credit Facility and the effective interest rate was ~~4.00%~~3.75%. AnThe impact of a 1% increase ~~or decrease of 1.00%~~ in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding ~~increase or~~ decrease in our ~~annual net income~~results of ~~approximately $199,000, based on~~operations, of $200,000 for the ~~balance outstanding at June 30, 2021.~~

Wethree months ended December 31, 2021, assuming that our indebtedness remained constant throughout the period. At this point, we do not believe that our liquidity has been materially affected by the ~~interest rate~~debt market uncertainties noted in the last few years, and we do not believe that our liquidity ~~to fund our ongoing operations~~ will be significantly impacted in the near future. All capitalized terms in this description of the interest rate under the Credit Facility that are not otherwise defined in this Form 10-Q shall have the meaning assigned to them in the Credit Agreement.

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 we file or 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 our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management 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. 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 ~~our~~that the Company’s disclosure controls and procedures were not effective as of December 31, 2021 as a result of the material weakness discovered during the audit process related to the fiscal year ended September 30, 2021

We are currently evaluating remediation options for the material weakness and anticipate a full remediation in the upcoming quarters. To ensure ~~material information relating~~the tax provision and related disclosures are correct for the quarter ended December 31, 2021, we engaged a large public accounting firm to ~~us is made known to management.~~ prepare and review the provision and related income calculations and disclosures. We also added enhanced

communication protocols between our tax provision preparer, management, and the external auditors, and held additional meetings throughout the quarter with our tax preparer. There were no changes in our internal ~~control~~controls over financial reporting, other than discussed above, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting made during the fiscal quarter or subsequent to the date the assessment was completed.

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.

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 our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2020.~~2021. There have been no material changes to the risk factors contained in the Annual Report on Form 10-K for the fiscal year ended September 30, ~~2020.~~2021. 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.

Upon approval by the shareholders of the 2010 Stock Plan in March 2010, as amended in May 2018, our Board approved to continue to allow us to repurchase up to $1.5 million of our ~~common stock~~Common Stock at management’s 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 our ~~common stock~~Common Stock is authorized and approved whenever the previous $1.5 million is utilized. In addition, the number of shares allowed to be purchased under the Repurchase Program is no longer capped at an amount equal to the aggregate number of shares of ~~common stock~~Common Stock (i) awarded pursuant to the 2010 Restricted Stock Plan ~~(ii) contributed by us to our ESOP,~~ and ~~(iii)~~(ii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

~~On October 8, 2020, we issued 153,375~~ We did not make any repurchases of shares of our ~~common stock to Red Stone Resources, LLC as part of~~Common Stock during 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 Marchfiscal quarter ended December 31, 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.

The Purchase and Sale Agreement contains schedules and exhibits that have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to furnish a supplemental copy of any such omitted exhibit or schedule to the SEC upon request.

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,~~December 31, 2021, and September 30, ~~2020~~2021		1

		Condensed Statements of Operations – Three ~~and nine~~ months ended ~~June 30,~~December 31, 2021 and 2020		2

		Statements of Stockholders’ Equity – ~~Nine~~Three months ended ~~June 30,~~December 31, 2021 and 2020		3

		Condensed Statements of Cash Flows – ~~Nine~~Three months ended ~~June 30,~~December 31, 2021 and 2020		54

		Notes to Condensed Financial Statements		65

	Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations		1514

	Item 3	Quantitative and Qualitative Disclosures about Market Risk		2621

	Item 4	Controls and Procedures		2621

Part II	Other Information

	Item 1	Legal Proceedings		2622

	Item 1A	Risk Factors		2722

	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		2722

	Item 6	Exhibits		2723

	Signatures		2823

ASC	Accounting Standards Codification.
ASU	Accounting Standards Update.
Bbl	~~barrel.~~Barrel.
Board	~~board~~Board of directors of the Company.
BTU	British Thermal Units.
Common Stock	Class A Common Stock, par value $0.01666 per share, of the Company.
completion	~~the~~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,~~Depreciation, depletion and amortization.
EBITDA	~~earnings~~Earnings before interest, taxes, depreciation and amortization (including impairment). This is a Non-GAAP measure.
ESOP	~~the~~The PHX Minerals Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan.
FASB	~~the~~The Financial Accounting Standards Board.
field	anAn 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~~General and administrative costs.
GAAP	United States generally accepted accounting principles.
Independent Consulting Petroleum Engineer(s)	DeGolyer and MacNaughton of Dallas, Texas.
LOE	~~lease~~Lease operating expense.
Mcf	~~thousand~~Thousand cubic feet.
Mcfe	~~natural~~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~~Million BTU.
minerals, mineral acres or mineral interests	~~fee~~Fee mineral acreage owned in perpetuity by the Company.
NGL	~~natural~~Natural gas liquids.
NYMEX	New York Mercantile Exchange.
play	~~term~~Term applied to identified areas with potential oil and/or natural gas reserves.
proved reserves	~~the~~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~~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~~The United States Securities and Exchange Commission.
undeveloped acreage	~~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~~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 ~~yet to be Adopted~~
ASU 2019-12, Simplifying the Accounting for Income Taxes.	This standard is intended to clarify and simplify the accounting for income taxes by removing certain exceptions and amending existing guidance.	Q1 2022	~~This standard is effective for public business entities beginning after December 15, 2020, with early adoption permitted.~~ The ~~Company does not believe the~~ adoption of this ~~standard will~~update did not have a material impact on ~~its~~the Company's financial statements and related disclosures.


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


Fiscal Period	Contract total volume	Index	Contract average price
Natural gas costless collars
Remaining 2022	610,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.19 ceiling
2023	500,000 Mmbtu	NYMEX Henry Hub	$3.32 floor / $4.54 ceiling
2024	60,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $4.70 ceiling
Natural gas fixed price swaps
Remaining 2022	2,818,000 Mmbtu	NYMEX Henry Hub	$2.94
2023	1,980,000 Mmbtu	NYMEX Henry Hub	$3.22
2024	360,000 Mmbtu	NYMEX Henry Hub	$3.40
Oil fixed price swaps
Remaining 2022	113,000 Bbls	NYMEX WTI	$44.25
2023	43,500 Bbls	NYMEX WTI	$52.84
2024	4,500 Bbls	NYMEX WTI	$67.55

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

	Nine Months Ended June 30,
	2021				2020
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	587	$	37,879	$	5,288,710	$	29,315,807

	Quarter Ended December 31,
	2021				2020
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	-	$	-

	Contract
Contract period	total volume	Index	Contract price
Oil fixed price swaps
January - December 2023	9,000 Bbls	NYMEX WTI	$70.05

	Mcf		Average		Oil Bbls		Average		NGL Bbls		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
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		1,361,909	$	1.36		55,138	$	25.94		35,169	$	6.62		1,903,752	$	1.85

Quarter Ended	Net royalty acres ⁽¹⁾⁽²⁾		Purchase Price ⁽¹⁾	Area of Interest
December 31, 2021
		426	$5.8 million	Haynesville / LA
		847	$4.1 million	Haynesville / LA
		172	$1.4 million	SCOOP / OK
		103	$0.6 million	Haynesville / TX
		116	$1.7 million	Haynesville / LA
		220	$1.2 million	SCOOP / OK
September 30, 2021
		817	$7.3 million	Haynesville / LA, TX
June 30, 2021
		262	$1.3 million	Haynesville / LA
		131	$1.0 million	Haynesville / TX
		2,514	$13.0 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
(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 .

(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~~10-K filed ~~with the SEC March 8,~~December 13, 2021).
		*Exhibit 10.1 – ~~Ninth Amendment to Amended~~Purchase and ~~Restated Credit~~Sale Agreement, dated ~~April 7,~~November 10, 2021, by and ~~among~~between PHX Minerals Inc., ~~the lenders party thereto,~~as Buyer, and ~~BOKF, NA dba Bank of Oklahoma,~~Vendera Resources III, LP and Vendera Management III LLC, collectively as ~~administrative agent for the lenders and as issuing bank~~Seller (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed ~~with the SEC on April 8,~~November 12, 2021).
		*Exhibit 10.2 – Purchase and Sale Agreement, dated ~~April 14,~~December 6, 2021, by and among PHX Minerals Inc., as Buyer, and ~~Palmetto Investments~~Merrimac Properties Partners, LLC ~~Palmetto Investments Partners II, LLC~~ and ~~Crestwood Exploration~~Quarter Horse Energy Partners, LLC, collectively as ~~Sellers~~Seller (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed ~~with~~December 9, 2021).
		*Exhibit 10.3 – Purchase and Sale Agreement, dated December 6, 2021, by and between PHX Minerals Inc., as Buyer, and Palmetto Investment Partners II, LLC, as Seller (incorporated by reference to Exhibit 10.2 to the ~~SEC~~Current Report on ~~April 15,~~Form 8-K filed December 9, 2021).
		*Exhibit 10.4 – First Amendment to Credit Agreement dated as of December 6, 2021, by and among PHX Minerals Inc., each lender party thereto, and Independent Bank, as Administrative Agent and L/C Issuer (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed December 9, 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)

PHX MINERALS INC.
		PHX MINERALS INC.

~~August 5, 2021~~February 14, 2022		/s/ Chad L. Stephens
Date		Chad L. Stephens, President,
		Chief Executive Officer

~~August 5, 2021~~February 14, 2022		/s/ Ralph D’Amico
Date		Ralph D’Amico, Vice President,
		Chief Financial Officer