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 February ~~8, 2021: 22,434,403~~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 ~~end of~~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 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 December 31, 2020.

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

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

	December 31, 2020			September 30, 2020			December 31, 2021			September 30, 2021
Assets	(unaudited)						(unaudited)
Current assets:
Cash and cash equivalents	$	1,163,818		$	10,690,395		$	1,559,350		$	2,438,511
Natural gas, oil, and NGL sales receivables (net of allowance for uncollectable accounts)		3,793,159			2,943,220
Natural gas, oil, and NGL sales receivables (net of $0 allowance for uncollectable accounts)								8,020,067			6,428,982
Refundable income taxes		3,817,772			3,805,227			-			2,413,942
Other		1,195,774			351,088			1,333,279			942,082
Total current assets		9,970,523			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		329,648,805			324,886,491			249,861,777			319,984,874
Non-producing natural gas and oil properties		22,101,506			18,993,814			54,960,073			40,466,098
Other		582,444			582,444			883,310			794,179
		352,332,755			344,462,749			305,705,160			361,245,151
Less accumulated depreciation, depletion and amortization		(265,704,923	)		(263,590,801	)		(195,971,382	)		(257,643,661	)
Net properties and equipment		86,627,832			80,871,948			109,733,778			103,601,490

Operating lease right-of-use assets		670,065			690,316			585,888			607,414
Other, net		630,429			669,641			570,072			578,593

Total assets	$	97,898,849		$	100,021,835		$	121,802,434		$	117,011,014

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	536,972		$	997,637		$	612,387		$	772,717
Derivative contracts, net		1,189,277			281,942			6,413,308			12,087,988
Income taxes payable								499,939			334,050
Current portion of operating lease liability		149,922			127,108			133,614			132,287
Accrued liabilities and other		1,254,061			1,297,363			2,047,437			1,809,337
Short-term debt		-			1,750,000
Total current liabilities		3,130,232			4,454,050			9,706,685			15,136,379

Long-term debt		27,000,000			27,000,000			20,000,000			17,500,000
Deferred income taxes, net		1,260,007			1,329,007			709,906			343,906
Asset retirement obligations		2,919,495			2,897,522			2,157,289			2,836,172
Derivative contracts, net		385,720			425,705			132,569			1,696,479
Operating lease liability, net of current portion		867,509			921,625			755,433			789,339

Total liabilities								33,461,882			38,302,275

Stockholders' equity:
Class A voting common stock, $0.01666 par value; 24,000,500 shares authorized; 22,800,681 issued at December 31, 2020, and 22,647,306 issued at September 30, 2020		379,859			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		10,678,906			10,649,611			36,741,266			33,213,645
Deferred directors' compensation		1,918,534			1,874,007			1,835,721			1,768,151
Retained earnings		55,192,444			56,244,100			54,798,980			48,966,420
		68,169,743			69,145,022			93,949,159			84,494,172
Less treasury stock, at cost; 390,267 shares at December 31, 2020, and 411,487 shares at September 30, 2020		(5,833,857	)		(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		62,335,886			62,993,926			88,340,552			78,708,739
Total liabilities and stockholders' equity	$	97,898,849		$	100,021,835		$	121,802,434		$	117,011,014

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

	Three Months Ended December 31,						Three Months Ended December 31,
	2020			2019			2021		2020
Revenues:	(unaudited)						(unaudited)
Natural gas, oil and NGL sales	$	6,424,979		$	7,593,838		$	13,687,164	$	6,424,979
Lease bonuses and rental income		1,433			527,699			78,915		1,433
Gains (losses) on derivative contracts		(254,036	)		(817,894	)		2,836,168		(254,036	)
Gain on asset sales		20,268			3,272,888
		6,192,644			10,576,531		$	16,602,247	$	6,172,376
Costs and expenses:
Lease operating expenses		1,004,412			1,181,671			1,256,011		1,004,412
Transportation, gathering and marketing		1,280,965			1,383,001			1,213,604		1,280,965
Production taxes		276,026			327,281			678,947		276,026
Depreciation, depletion and amortization		2,260,649			2,955,701			1,583,760		2,260,649
Provision for impairment								5,585		-
Interest expense		301,898			370,665			176,719		301,898
General and administrative		1,731,097			2,223,028			2,095,557		1,731,097
Other expense (income)		3,317			(10,930	)
		6,858,364			8,430,417
Losses (gains) on asset sales and other								2,147,815		(16,951	)
Total costs and expenses								9,157,998		6,838,096
Income (loss) before provision (benefit) for income taxes		(665,720	)		2,146,114			7,444,249		(665,720	)

Provision (benefit) for income taxes		(69,000	)		254,000			762,000		(69,000	)

Net income (loss)	$	(596,720	)	$	1,892,114		$	6,682,249	$	(596,720	)




Basic and diluted earnings (loss) per common share (Note 5)	$	(0.03	)	$	0.11
Basic and diluted earnings (loss) per common share (Note 4)							$	0.20	$	(0.03	)

Basic and diluted weighted average shares outstanding:
Common shares		22,378,146			16,339,673			32,895,631		22,378,146
Unissued, directors' deferred compensation shares		178,090			180,864			232,091		178,090
		22,556,236			16,520,537			33,127,722		22,556,236




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

Dividends declared per share of
common stock and to be paid in quarter ended March 31	$	0.01		$	0.04		$	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)

	Class A voting				Capital in			Deferred														Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors'		Retained			Treasury			Treasury						Common Stock				Excess of			Directors'		Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation		Earnings			Shares			Stock			Total			Shares		Amount		Par Value			Compensation		Earnings			Shares			Stock			Total

Balances at September 30, 2019		16,897,306	$	281,509	$	2,967,984		$	2,555,781	$	81,848,301			(558,051	)	$	(8,344,042	)	$	79,309,533
Balances at September 30, 2020																							22,647,306	$	377,304	$	10,649,611		$	1,874,007	$	56,244,100			(411,487	)	$	(6,151,096	)	$	62,993,926

Net income (loss)		-		-		-			-		1,892,114			-			-			1,892,114			-		-		-			-		(596,720	)		-			-			(596,720	)
Purchase of treasury stock		-		-		-			-		-			(632	)		(7,635	)		(7,635	)
Equity offering																							153,375		2,555		223,203			-		-			-			-			225,758
Restricted stock awards		-		-		148,515			-		-			-			-			148,515			-		-		122,978			-		-			-			-			122,978
Dividends ($0.08 per share)		-		-		-			-		(1,319,899	)		-			-			(1,319,899	)
Dividends ($0.02 per share)																							-		-		-			-		(454,936	)		-			-			(454,936	)
Distribution of restricted stock to officers and directors		-		-		(82,821	)		-		-			5,546			82,914			93			-		-		(316,886	)		-		-			21,220			317,239			353
Increase in deferred directors' compensation charged to expense		-		-		-			86,212		-			-			-			86,212			-		-		-			44,527		-			-			-			44,527
Balances at December 31, 2019		16,897,306	$	281,509	$	3,033,678		$	2,641,993	$	82,420,516			(553,137	)	$	(8,268,763	)	$	80,108,933
Balances at December 31, 2020																							22,800,681	$	379,859	$	10,678,906		$	1,918,534	$	55,192,444			(390,267	)	$	(5,833,857	)	$	62,335,886
(unaudited)

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

	Three months ended December 31,						Three Months Ended December 31,
	2020			2019			2021			2020
Operating Activities	(unaudited)						(unaudited)
Net income (loss)	$	(596,720	)	$	1,892,114		$	6,682,249		$	(596,720	)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		2,260,649			2,955,701			1,583,760			2,260,649
Impairment of producing properties								5,585			-
Provision for deferred income taxes		(69,000	)		658,000			366,000			(69,000	)
Gain from leasing fee mineral acreage		(232	)		(523,384	)		(78,922	)		(232	)
Proceeds from leasing fee mineral acreage		232			537,777			95,039			232
Net (gain) loss on sales of assets		(30,862	)		(3,272,888	)		2,163,359			(30,862	)
Directors' deferred compensation expense		44,527			86,213			67,570			44,527
Total (gain) loss on derivative contracts		254,036			817,894			(2,836,168	)		254,036
Cash receipts (payments) on settled derivative contracts		613,314			901,773			-			613,314
Restricted stock awards		122,978			148,515			255,844			122,978
Other		14,387			8,896			37,138			14,387
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables		(813,167	)		56,160			(1,591,085	)		(813,167	)
Other current assets		(676,620	)		(407,610	)		(325,780	)		(676,620	)
Accounts payable		(398,556	)		(73,831	)		(95,649	)		(398,556	)
Income taxes receivable		(12,545	)		(412,073	)		2,413,942			(12,545	)
Other non-current assets		30,958			1,090			10,253			30,958
Income taxes payable								165,889			-
Accrued liabilities		(271,998	)		(1,275,906	)		(281,034	)		(271,998	)
Total adjustments		1,068,101			206,327			1,955,741			1,068,101
Net cash provided by operating activities		471,381			2,098,441			8,637,990			471,381

Investing Activities
Capital expenditures		(128,083	)		(105,265	)		(192,677	)		(128,083	)
Acquisition of minerals and overrides		(7,869,746	)		(10,172,594	)
Proceeds from sales of assets		-			3,376,049
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		(7,997,829	)		(6,901,810	)		(7,250,012	)		(7,997,829	)

Financing Activities
Borrowings under Credit Facility		-			4,774,297			4,000,000			-
Payments of loan principal		(1,750,000	)		(5,199,297	)		(1,500,000	)		(1,750,000	)
Net proceeds from equity issuance		(24,242	)		-			(32,507	)		(24,242	)
Purchases of treasury stock		-			(7,635	)
Cash receipts from (payments on) off-market derivative contracts								(4,402,422	)		-
Payments of dividends		(225,887	)		(655,980	)		(332,210	)		(225,887	)
Net cash provided (used) by financing activities		(2,000,129	)		(1,088,615	)		(2,267,139	)		(2,000,129	)

Increase (decrease) in cash and cash equivalents		(9,526,577	)		(5,891,984	)		(879,161	)		(9,526,577	)
Cash and cash equivalents at beginning of period		10,690,395			6,160,691			2,438,511			10,690,395
Cash and cash equivalents at end of period	$	1,163,818		$	268,707		$	1,559,350		$	1,163,818

Supplemental Schedule of Noncash Investing and Financing Activities:


Dividends declared and unpaid	$	229,049		$	663,919		$	517,479		$	229,049
Additions to asset retirement obligations	$	-		$	4

Gross additions to properties and equipment	$	7,986,350		$	10,164,680		$	15,183,829		$	7,986,350

Equity offering used for acquisitions		(250,000	)		-			(3,510,001	)		(250,000	)
Net (increase) decrease in accounts payable for properties and equipment additions		261,479			113,179			162,676			261,479
Capital expenditures and acquisitions	$	7,997,829		$	10,277,859		$	11,836,504		$	7,997,829

(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 determines if an arrangement is a lease at inception by considering whether (i) explicitly or implicitly identified assets have been deployed in the agreement and (ii) the Company obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. As of December 31, 2020, none of the Company’s leases were classified as financing leases. Operating lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company signed a new lease for office space during the quarter ended March 31, 2020, with a commencement date in August 2020. The associated lease liability and ROU asset at December 31, 2020, were $1,017,431 and $670,065, respectively. The Company has a lease incentive asset of $331,191, which is included in Other, net on the Company’s Balance Sheets.

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

The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Company will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Company will exercise that option. Lease expense for lease payments will be recognized on a straight-line basis over the lease term. The Company made an accounting policy election to not recognize leases with terms, including applicable options, of less than twelve months on the

Company’s Balance Sheets and recognize those lease payments in the Company’s Statements of Operations on a straight-line basis over the lease term. In the event that the Company’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.

~~The following table represents the maturities of the operating lease liabilities as of December 31, 2020:~~

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 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 109 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 months ended December 31, ~~2020~~2021 and ~~2019:~~

	Three Months Ended December 31, 2020						Three Months Ended December 31, 2021
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	1,190,165	$	2,268,636	$	3,458,801	$	5,200,868	$	3,489,167	$	8,690,035
Oil revenue		1,096,952		1,244,114		2,341,066		1,894,027		1,682,077		3,576,104
NGL revenue		230,338		394,774		625,112		625,623		795,402		1,421,025
Natural gas, oil and NGL sales	$	2,517,455	$	3,907,524	$	6,424,979	$	7,720,518	$	5,966,646	$	13,687,164


	Three Months Ended December 31, 2019						Three Months Ended December 31, 2020
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	1,273,113	$	2,240,330	$	3,513,443	$	1,190,165	$	2,268,636	$	3,458,801
Oil revenue		1,413,211		2,052,301		3,465,512		1,096,952		1,244,114		2,341,066
NGL revenue		222,777		392,106		614,883		230,338		394,774		625,112
Natural gas, oil and NGL sales	$	2,909,101	$	4,684,737	$	7,593,838	$	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.~~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 months ended December 31, ~~2020 and 2019,~~2021, revenue recognized ~~in these~~during the reporting ~~periods~~period related to performance obligations satisfied in prior reporting periods for existing wells was ~~immaterial~~approximately $0.5 million and primarily due to change in price 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 2022 first quarter, the Company identified several producing properties on its minerals that had production dates prior to the 2022 first quarter. Estimates of the natural gas and oil sales related to those properties were made and are reflected in the 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 months ended December 31, 2021, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $342,361 ,of which $83,569 related to the production periods before October 1, 2020 and $258,792 related to fiscal 2021.

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 it 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, when~~Depending upon whether a provision for income taxes ~~is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when~~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 ~~quarter~~three months ended December 31, ~~2020,~~2021 was a 10% ~~benefit~~provision as compared to a ~~12% provision~~10% benefit for the ~~quarter~~three months ended December 31, ~~2019.~~2020.

The federal Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 Net Operating Losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the ~~30%~~ limitation on interest expense deductibility under Section 163(j) of the Internal Revenue Code (“IRC”), from 30% to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. On July 28, 2020, final regulations were issued under Section 163(j) of the IRC, which modified the calculation under the previous proposed regulations of adjusted taxable income for purposes of the 50% limitation on interest expense. Under the final regulations, depreciation, amortization, and depletion capitalizable under Section 263A of the IRC is ~~now~~ added back to tentative taxable income. This change ~~allows~~allowed all interest expense to be deductible for 2020 and ~~reduces~~reduced the associated deferred tax asset to 0. During the quarter ended ~~June 30, 2020,~~March 31, 2021, the Company ~~filed for~~received a tax refund totaling $1.4 million associated with the alternative minimum tax (AMT) credits, ~~totaling $1.4 million,~~ which was accelerated ~~due to~~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 months ended 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.

~~The~~The Company has a ~~$200,000,000~~$100,000,000 credit facility (the “Credit Facility”) with a ~~group~~syndicate of banks ~~headed~~led by Independent Bank ~~of Oklahoma (BOK) with~~pursuant to a credit agreement entered into in September 2021 (as amended, the “Credit Agreement”). The Credit Facility has a current borrowing base of ~~$30,000,000~~$32,000,000 as of December 31, ~~2020,~~2021, and a maturity date of November 30, 2022 (as amended, the “Credit Facility”). The Credit Facility is subject to at least semi-annual borrowing base determinations, wherein BOK applies its commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base.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 ~~BOK 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 ~~BOK~~Independent Bank prime or LIBOR is at the Company’s discretion. The interest rate spread from ~~BOK~~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 December 31, ~~2020,~~2021, the effective interest rate was ~~4.25%~~3.75%.

The Company’s debt is recorded at the carrying amount on its ~~Balance Sheets.~~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.~~balance sheets. Total debt issuance cost, net of amortization, as of December 31, ~~2020~~2021 was ~~$219,931.~~$288,247. The debt issuance cost is amortized over the life of the Credit Facility.

Determinations of the borrowing base under the Credit Facility are made semi-annually (usually in June and December) or whenever the lending banks, in their sole discretion, believe that there has been a material change in the value of the Company’s natural gas and oil properties. On December 4, 2020, the Company entered into the eighth amendment to the Credit Facility. The amendment reduced the Quarterly Commitment Reductions from $1,000,000 to $600,000, reduced the consolidated cash balance in the anti-cash hoarding provision from $2,000,000 to $1,000,000, and changed the debt to EBITDA ratio from 4.0:1.00 to 3.50:1.00. The borrowing base after Quarterly Commitment Reductions was reaffirmed at $30,000,000. The next redetermination is expected to occur in June 2021. 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 (as defined in the Credit Facility) for a period of eighteen (18) months fixing prices on oil or gas expected to be produced. At December 31, ~~2020,~~2021, the Company was in compliance with the covenants of the Credit Facility and had ~~$27,000,000~~$20,000,000 in outstanding borrowings and had $12,000,000 available for borrowing under the Credit ~~Facility and had $3,000,000~~Facility. All capitalized terms in this description of ~~borrowing base availability under~~ the Credit ~~Facility.~~Facility that are not otherwise defined in this Form 10-Q shall have the meaning assigned to them in the Credit 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 ~~the~~their annual retainers and Board ~~meeting fees~~ and committee meeting fees. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares ~~(i) on the dates of the Board and committee meetings, and (ii)~~ on the payment dates of the annual retainers. Only upon a director’s retirement, termination or death or a change-in-control of the Company will the shares recorded for such director be issued under this plan. Directors may elect to receive shares, when issued, over annual time periods of up to ten years. The promise to issue such shares in the future is an unsecured obligation of the Company.

On January 2, 2020, the Company awarded 22,300 time-based shares of the Company’s common stock as restricted stock to its non-employee directors. On December 31, 2020, 19,327 shares of restricted stock vested, and 2,973 shares were repurchased due to a director’s early retirement. The restricted stock contains non-forfeitable rights to receive dividends and to vote the shares during the vesting period. These time-based shares had a fair value on their award date of $246,640.

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

The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, ~~2020~~2021 and ~~2019,~~2020 related to the Company’s market-based, time-based and performance-based restricted stock:

	Three Months Ended				Three Months Ended
	December 31,				December 31,
	2020		2019		2021		2020
Market-based, restricted stock	$	10,247	$	74,142	$	77,482	$	10,247
Time-based, restricted stock		112,731		74,373		178,362		112,731
Performance-based, restricted stock		-		-		-		-
Total compensation expense	$	122,978	$	148,515	$	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 ~~are~~is shown in the following table:

	As of December 31, 2020				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	$	57,406		1.60	$	569,027		1.97
Time-based, restricted stock		450,098		1.90		194,601		0.96
Performance-based, restricted stock		-				-
Total	$	507,504			$	763,628

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

	December 31, 2020			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		329,648,805			324,886,491		$	249,861,777		$	319,984,874
Non-producing natural gas and oil properties		22,101,506			18,993,814			54,960,073			40,466,098
Other property and equipment		582,444			582,444			883,310			794,179
		352,332,755			344,462,749			305,705,160			361,245,151
Less accumulated depreciation, depletion and amortization		(265,704,923	)		(263,590,801	)		(195,971,382	)		(257,643,661	)
Net properties and equipment		86,627,832			80,871,948		$	109,733,778		$	103,601,490

~~During the first quarter of 2021, the Company had no significant divestitures.~~

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

~~On December 17, 2020, the Company closed on the purchase of an additional 89 net mineral acres in San Augustine County, Texas for a purchase price of $1 million~~.

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

On October 8, 2020, the Company closed on the purchase of 297 net royalty acres in Grady County, Oklahoma, and 237 net mineral acres and 12 net royalty acres in Harrison, Panola and Nacogdoches Counties, Texas, for a purchase price of $5.5 million and 153,375 shares of PHX common stock. This purchase was largely funded with cash from the common stock offering that closed on September 1, 2020.

All purchases made in ~~These first quarter~~ 2021 ~~purchases~~ and 2022 were for mineral and royalty acreage and were accounted for as asset acquisitions.

The Company divested approximately 700 working interest wellbores during the ~~first quarter~~three months ended December 31, 2021, which resulted in reductions to producing natural gas and oil properties of ~~2020, PHX closed~~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 ~~the purchase~~sale of ~~700~~assets of approximately $2.2 million. The net ~~mineral acres in Kingfisher, Canadian and Garvin Counties, Oklahoma, for a purchase price of $9.3~~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,~~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, ~~and~~ affected by worldwide production and consumption, and are outside the control of management.

~~All~~Company management monitors all long-lived assets, principally natural gas and oil properties, ~~are monitored~~ for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such ~~as:~~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~~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 ~~both~~ the three months ended December 31, ~~2020~~2021 and ~~2019, the~~2020, management’s assessment resulted in 0 impairment provisions on producing properties. The Company wrote off $5,585 on wells assigned with 0 consideration received during the three months ended 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 ~~Bank of Oklahoma~~BP are secured under the Credit Facility with Independent Bank ~~of Oklahoma~~ (see Note 6:5: Long-Term Debt). The derivative instruments have settled or will settle based on the prices below:

Contract period (Calendar Year)

Contract total volume

Index

Contract average price
Natural gas costless collars

2021

2,924,500 Mmbtu

NYMEX Henry Hub

$2.33 floor / $3.03 ceiling
2022

1,402,500 Mmbtu

NYMEX Henry Hub

$2.47 floor / $3.14 ceiling
Natural gas fixed price swaps

2021

1,014,500 Mmbtu

NYMEX Henry Hub

$2.69
2022

125,500 Mmbtu

NYMEX Henry Hub

$2.70
Oil costless collars

2021

51,000 Bbls

NYMEX WTI

$36.74 floor / $44.79 ceiling
2022

23,500 Bbls

NYMEX WTI

$36.89 floor / $45.73 ceiling
Oil fixed price swaps

2021

96,000 Bbls

NYMEX WTI

$37.00
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

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 ~~$1,574,997~~$6,545,877 as of December 31, ~~2020,~~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						Three Months Ended
	December 31,						December 31,
	2020			2019			2021			2020
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	(8,967	)	$	-		$	-		$	(8,967	)
Natural gas fixed price swaps		(1,863	)		719,800
Natural gas fixed price swaps⁽¹⁾								(1,352,192	)		(1,863	)
Oil costless collars		88,944			113,699			-			88,944
Oil fixed price swaps		535,200			68,274
Oil fixed price swaps⁽¹⁾								(362,139	)		535,200
Cash received (paid) on derivative contracts, net	$	613,314		$	901,773		$	(1,714,331	)	$	613,314
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	678,961		$	5,900		$	79,971		$	678,961
Natural gas fixed price swaps		288,887			(571,809	)		4,477,934			288,887
Oil costless collars		(410,886	)		(480,456	)		-			(410,886	)
Oil fixed price swaps		(1,424,312	)		(673,302	)		(7,406	)		(1,424,312	)
Non-cash gain (loss) on derivative contracts, net	$	(867,350	)	$	(1,719,667	)	$	4,550,499		$	(867,350	)
Gains (losses) on derivative contracts, net	$	(254,036	)	$	(817,894	)	$	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.~~balance sheets.

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

	December 31, 2020												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	$	201,842		$	1,391,119		$	93,019		$	478,739		$	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		(201,842	)		(201,842	)		(93,019	)		(93,019	)		(864,466	)		(864,466	)		-		(386,069	)		(386,069	)		(364,782	)		(364,782	)		(17,395	)		(17,395	)		-
Net presentation on Condensed Balance Sheets	$	-		$	1,189,277		$	-		$	385,720		$	-		$	281,942		$	425,705
Net presentation on condensed balance sheets																					$	-		$	6,413,308		$	-		$	132,569		$	-		$	12,087,988		$	1,696,479

(a) See Note ~~11:~~10: Fair Value Measurements for further disclosures regarding fair value of financial instruments.

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

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are

observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis at December 31, ~~2020:~~2021:

	Fair Value Measurement at December 31, 2020										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	$	-	$	(1,200,226	)	$	-	$	(1,200,226	)	$	-	$	(6,625,848	)	$	-	$	(6,625,848	)
Derivative Contracts - Collars	$	-	$	(374,771	)	$	-	$	(374,771	)	$	-	$	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.

At December 31, ~~2020,~~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, ~~which~~ 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, ~~2020,~~2021, the Company entered into new derivative contracts as summarized in the table below:

Subsequent to December 31, ~~2020,~~2021, the Company ~~paid down an additional $1,000,000 under the Credit Facility, bringing the total outstanding debt balance to $26,000,000, as of February 1, 2021.~~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 ~~are~~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 ~~have been~~were an active working interest participant in wells drilled on our mineral and leasehold acreage, our current focus is on growth through mineral acquisitions 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 ~~are dependent~~depend primarily upon ~~our:~~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 ~~is currently~~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 DECEMBER 31, ~~2020,~~2021 COMPARED TO THREE MONTHS ENDED DECEMBER 31, ~~2019~~2020

~~The Company~~We recorded a first quarter ~~2021~~2022 net income of $6,682,249, or $0.20 per share, as compared to a net loss of $596,720, or $0.03 per share, ~~as compared to a net income of $1,892,114, or $0.11 per share,~~ in the ~~2020~~first fiscal 2021 quarter. The change in net income ~~(loss)~~ was principally the result of ~~decreased~~increased natural gas, oil and NGL sales, ~~decreased~~and an increase in non-cash gain on ~~asset sales and decreased lease bonuses and rental income,~~derivative contracts, partially offset by a ~~decrease in G&A, LOE, transportation, gathering and marketing expenses, production taxes, depreciation, depletion and amortization and changes in tax provision (benefit).~~loss on sales of assets. These items are further discussed below.

For the three months ended December 31, 2021, the increase in natural gas, oil and NGL sales was primarily due to ~~decreases~~increases in natural gas, oil and NGL prices of ~~24%~~136%, 86% and 3%111%, respectively, and ~~decreases~~an increase in natural gas and NGL volumes of 7% and 8%, respectively, partially offset by a decrease in oil volumes of ~~10% and 11%, respectively.~~18%. The following table outlines ~~the Company’s~~our production and average sales prices for natural gas, oil and NGL for the three-month periods of fiscal ~~2021~~2022 and ~~2020:~~2021:

Mcf

Average

Oil Bbls

Average

NGL Bbls

Average

Mcfe

Average

Sold

Price

Sold

Price

Sold

Price

Sold

Price

Three months ended

12/31/2020

1,475,456

$
2.34

58,675

$
39.90

41,138

$
15.20

2,074,334

$
3.10

12/31/2019

1,647,827

$
2.13

65,880

$
52.60

39,230

$
15.67

2,278,487

$
3.33

	Mcf		Average		Oil Bbls		Average		NGL Bbls		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
12/31/2021		1,574,265	$	5.52		48,074	$	74.39		44,256	$	32.11		2,128,248	$	6.43
12/30/2020		1,475,456	$	2.34		58,675	$	39.90		41,138	$	15.20		2,074,335	$	3.10

The production increase in royalty volumes during the three months ended December 31, 2021, as compared to the three months ended December 31, 2020, resulted from acquisition wells in the Haynesville Shale and SCOOP plays coming online. The decrease in ~~oil production was primarily due to postponement of workovers due to prevailing economic conditions, as well as~~working interest volumes resulted from naturally declining production in ~~high interest~~high-interest wells in the Eagle ~~Ford. This decrease was partially offset by new wells brought online~~Ford Shale and divestiture of low-value legacy working interest in the SCOOP and STACK plays. The increase in NGL production was primarily attributable to increased production on high interest wells in liquid-rich gas areas of the STACK play. Natural gas volumes decreased as a result of naturally declining production in the Fayetteville Shale, Arkoma Stack and STACK plays, as well as production downtime in high-interest wells and curtailments in response to market conditions in the Arkoma Stack and STACK plays.Oklahoma.

Quarter ended

Mcf Sold

Oil Bbls Sold

NGL Bbls Sold

Mcfe Sold

12/31/2020

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

3/31/2020

1,529,367

93,141

47,487

2,373,135

12/31/2019

1,647,827

65,880

39,230

2,278,487

Quarter ended	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
3/31/2021		1,735,820		56,269		37,228		2,296,802
12/31/2020		1,475,456		58,675		41,138		2,074,334

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

12/31/2020

487,925

27,840

14,948

744,653

9/30/2020

491,234

27,326

20,181

776,276

6/30/2020

544,249

28,468

16,574

814,501

3/31/2020

549,999

54,077

16,188

971,589

12/31/2019

562,813

25,701

11,402

785,431

Quarter ended	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
3/31/2021		924,969		31,768		19,088		1,230,105
12/31/2020		487,925		27,840		14,948		744,653

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

12/31/2020

987,531

30,835

26,190

1,329,681

9/30/2020

932,368

28,300

26,556

1,261,503

6/30/2020

817,660

26,670

18,595

1,089,251

3/31/2020

979,368

39,064

31,299

1,401,546

12/31/2019

1,085,014

40,179

27,828

1,493,056

Quarter ended	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
3/31/2021		810,851		24,501		18,140		1,066,697
12/31/2020		987,531		30,835		26,190		1,329,681

When ~~the Company leases its~~we lease our mineral interests, we generally receive an upfront cash payment, or lease ~~bonus, is generally received.~~bonus. Lease bonuses and rental income ~~decreased $526,266~~increased $77,482 in the 2022 quarter compared to the 2021 quarter primarily as the result of increased leasing activity in the 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 December 31,							For the Three Months Ended December 31,
							Percent							Percent
	2020			2019			Incr. or (Decr.)	2021			2020			Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net(1)	$	613,314		$	901,773		(32%)	$	(1,714,331	)	$	613,314		(380%)
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(867,350	)	$	(1,719,667	)	50%	$	4,550,499		$	(867,350	)	625%
Gains (losses) on derivative contracts, net	$	(254,036	)	$	(817,894	)	69%	$	2,836,168		$	(254,036	)	1,216%

	As of December 31,							As of December 31,
	2020			2019				2021			2020
Fair value of derivative contracts
Net asset (net liability)	$	(1,574,997	)	$	774,477		(303%)	$	(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 ~~loss~~(loss) gain on derivative contracts ~~in both periods~~ was ~~principally~~ 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. During the 2021 quarter, we received $613,314 on settled derivative contracts as compared to $901,733 received in the 2020 quarter.~~prices.

~~The Company’s~~Our natural gas and oil costless collar contracts and fixed price swaps in place at December 31, ~~2020,~~2021 had expiration dates ~~of January 2021~~ through December ~~2022. The Company utilizes~~2023. We utilize derivative contracts for the purpose of protecting ~~its~~our cash flow and return on investments.

	For the Three Months Ended December 31,					For the Three Months Ended December 31,
					Percent					Percent
	2020		2019		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Lease operating expenses	$	1,004,412	$	1,181,671	(15%)	$	1,256,011	$	1,004,412	25%
Lease operating expenses per MCFE	$	0.48	$	0.52	(8%)	$	0.59	$	0.48	23%

~~The Company is~~We are responsible for a portion of LOE relating to a well as a working interest owner. LOE includes ~~normally~~normal recurring and nonrecurring expenses associated with ~~the Company’s~~our working interests necessary to produce hydrocarbons from our natural gas and oil wells, including maintenance, repairs, salt water disposal, insurance and workover ~~expenses related to oil and natural gas properties.~~expenses. Total LOE related to field operating costs ~~decreased $177,259,~~increased $251,599, or ~~15%~~25%, in the ~~2021~~2022 quarter compared to the ~~2020~~2021 quarter. The ~~decrease~~increase in LOE ~~rate~~ was principally the result of increased workover expenses and inflation on services in the ~~Company’s strategic decision to not participate with a working interest in new wells.~~2022 quarter.

	For the Three Months Ended December 31,					For the Three Months Ended December 31,
					Percent					Percent
	2020		2019		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Transportation, gathering and marketing	$	1,280,965	$	1,383,001	(7%)	$	1,213,604	$	1,280,965	(5%)
Transportation, gathering and marketing per MCFE	$	0.62	$	0.61	2%	$	0.57	$	0.62	(8%)

Transportation, gathering and marketing decreased ~~$102,036~~$67,361, or 7%5%, in the ~~2021 quarter. This decrease in costs was primarily driven by lower production in the 2021~~2022 quarter compared to the ~~2020~~2021 quarter. The ~~increase~~decrease in rate per Mcfe was primarily due to the ~~change~~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 ~~the Company’s~~our transportation, gathering and marketing fees.

	For the Three Months Ended December 31,							For the Three Months Ended December 31,
							Percent							Percent
	2020			2019			Incr. or (Decr.)	2021			2020			Incr. or (Decr.)
Production taxes	$	276,026		$	327,281		(16%)	$	678,947		$	276,026		146%
Production taxes as % of sales		4.3	%		4.3	%	(—%)		5.0	%		4.3	%	16%

Production taxes are paid on produced ~~oil~~natural gas and ~~natural gas~~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 ~~decreased $51,255,~~increased $402,921, or ~~16%~~146%, in the 2022 quarter as compared to the 2021 quarter. The ~~decrease~~increase in amount was primarily the result of ~~decreased~~increased natural gas, oil and NGL sales of ~~$1,168,859~~$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 December 31,					For the Three Months Ended December 31,
					Percent					Percent
	2020		2019		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Depreciation, depletion and amortization	$	2,260,649	$	2,955,701	(24%)	$	1,583,760	$	2,260,649	(30%)
Depreciation, depletion and amortization per MCFE	$	1.09	$	1.30	(16%)	$	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.~~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 ~~$695,052,~~$676,889, or ~~24%~~30%, in the 2022 quarter compared to the 2021 ~~quarter. $265,399~~quarter, of which $735,649 of the decrease resulted from ~~production decreasing 9% in the 2021 quarter. Also, DD&A decreased $429,653 as~~ a ~~result of a $0.21~~$0.35 decrease in the DD&A rate per ~~Mcfe.~~Mcfe, partially offset by an increase of $58,760 resulting from production increasing 3% in the 2022 quarter. The rate decrease was mainly due to ~~impairments taken at the end of fiscal 2019 and the 2020 second quarter, which lowered the basis of the assets. The rate decrease was partially offset by lower natural gas, oil and NGL prices utilized~~an increase in ~~the reserve calculations~~reserves during the ~~2021~~2022 quarter, as compared to the ~~2020~~2021 quarter.

We had a $5,585 provision for impairment in the 2022 quarter ~~shortening~~as compared to no provision for impairment in the ~~economic life of wells. This resulted in lower projected remaining reserves on a significant number of~~2021 quarter. During the 2022 quarter, impairment was related to working interest wells ~~causing increased units of production DD&A.~~that we wrote off and assigned the interests to the operator.

	For the Three Months Ended December 31,					For the Three Months Ended December 31,
					Percent					Percent
	2020		2019		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Interest Expense	$	301,898	$	370,665	(19%)
Interest expense						$	176,719	$	301,898	(41%)
Weighted average debt outstanding	$	27,796,196	$	35,094,158	(21%)	$	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 ~~$323,000,~~$831,000, from ~~a $254,000 provision in the 2020 quarter to~~ a $69,000 benefit in the 2021 ~~quarter. The effective tax rate changed from~~quarter to a ~~12%~~$762,000 provision in the ~~2020~~2022 quarter. The change in income taxes resulted primarily from increasing from a net loss of $596,720 in the 2021 quarter to ~~a 10% benefit~~net income of $6,682,249 in the ~~2021~~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 ~~expenses~~ 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 ~~decreased $491,931~~for the 2022 quarter increased $364,460 as compared to the ~~2020~~2021 quarter. The ~~decrease~~increase was primarily due to ~~cost reduction efforts by~~increased activity during the ~~Company.~~2022 quarter.

~~The Company~~We had positive working capital (current assets less current liabilities excluding current derivatives) of ~~$6,840,291~~$7,619,319 at December 31, ~~2020,~~2021, compared to positive working capital of ~~$13,335,880~~$9,175,126 at September 30, ~~2020, which included $7.3 million related to the first quarter acquisitions.~~2021.

Cash and cash equivalents were ~~$1,163,818~~$1,559,350 as of December 31, ~~2020,~~2021, compared to ~~$10,690,395~~$2,438,511 at September 30, ~~2020,~~2021, a decrease of ~~$9,526,577.~~$879,161. The decrease in cash is primarily associated with the closing of previously announced acquisitions, which were funded by cash on hand, cash from operating activities and proceeds from the ~~equity raise from September 2020.~~sale of assets. Cash flows for the three months ended December 31, 2021, and 2020 are summarized as follows:

Net cash provided (used) by:	For the Three Months Ended December 31,									For the Three Months Ended December 31,
	2020			2019			Change			2021			2020			Change

Operating activities	$	471,381		$	2,098,441		$	(1,627,060	)	$	8,637,990		$	471,381		$	8,166,609
Investing activities		(7,997,829	)		(6,901,810	)		(1,096,019	)		(7,250,012	)		(7,997,829	)		747,817
Financing activities		(2,000,129	)		(1,088,615	)		(911,514	)		(2,267,139	)		(2,000,129	)		(267,010	)
Increase (decrease) in cash and cash equivalents	$	(9,526,577	)	$	(5,891,984	)	$	(3,634,593	)	$	(879,161	)	$	(9,526,577	)	$	8,647,416

Net cash provided by operating activities ~~decreased $1,627,060~~increased $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 $1,096,019~~decreased $747,817 during the ~~2021~~2022 period, as compared to the ~~2020~~2021 period, primarily due to ~~lower~~higher net proceeds from the sale of assets of ~~$3,376,049~~$4,586,492, partially offset by higher acquisition costs of $3,774,081 and higher payments of ~~$22,818~~$64,594 for drilling and completion activity ~~partially offset by lower acquisition costs of $2,302,848~~ during ~~2021.~~the 2022 period.

Net cash used by financing activities increased ~~$911,514~~$267,010 during the ~~2021~~2022 period, as compared to the ~~2020~~2021 period, primarily ~~the result~~due to increased cash payments on off-market derivative contracts of $4,402,422 and an increase of $106,323 in dividend payments, which were partially offset by higher net ~~payments~~borrowings on long-term debt of $2,500,000 in the 2022 period compared to net payments of $1,750,000 in the 2021 compared to $425,000 in the prior year period, partially offset by decreased stock repurchases of $7,635 and a decrease of $430,093 in dividend payments as a result of a reduction in the Company’s quarterly dividend from $0.04 per share to $0.01 per share beginning with the June 2020 dividend payment.period.

~~Capital~~We had no capital expenditures to drill and complete new wells ~~increased $22,818, or 22%, from~~in the ~~2020 to the~~ 2022 and2021 ~~period~~ periods, as a result of ~~increased workover activity~~our strategy to cease participating in ~~the 2021 period. The Company~~new wells with a working interest after fiscal year 2019. We currently ~~has~~have no remaining commitments that would require significant capital to drill and complete ~~wells as the Company ceased participating in any new wells with a working interest at the end of fiscal 2019.~~wells.

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

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

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 .

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

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

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

On October 8, 2020, the Company closed on the purchase of 297 net royalty acres in Grady County, Oklahoma, and 237 net mineral acres and 12 net royalty acres in Harrison, Panola and Nacogdoches Counties, Texas, for a purchase price of $5.5 million and 153,375 shares of PHX common stock, subject to customary closing adjustments. This purchase was mostly funded with cash from the common stock offering discussed above.

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

~~On December 17, 2020, the Company closed on the purchase of an additional 89 net mineral acres in San Augustine County, Texas for a purchase price of $1 million.~~

~~The Company~~We received lease bonus payments during the first fiscal ~~2021~~2022 quarter totaling $232. Looking forward, the cash flow from bonus payments associated with the leasing of drilling rights on the Company’s mineral acreage is difficult to project as the current economic downturn has decreased demand for new leasing by operators. However, 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 ~~the Company’s~~our future natural gas and oil production. ~~Additionally, pursuant to the Credit Facility, the Company is required to enter into and maintain certain Swap Agreements (as defined~~See Note 9: Derivatives in the ~~Credit Facility) for a period of eighteen (18) months fixing prices on oil or gas expected~~notes to ~~be produced. See Note 10: Derivatives~~our condensed financial statements included in this Form 10-Q for a complete list of ~~the Company’s~~our outstanding derivative contracts at December 31, ~~2020, and Note 13: Subsequent Events for a listing of additional contracts entered into through February 4,~~ 2021.

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

	Three months ended			Three Months Ended
	December 31, 2020			December 31, 2021
Cash provided by operating activities	$	471,381		$	8,637,990
Cash provided (used) by:

Capital expenditures - acquisitions		(7,869,746	)		(11,643,827	)
Capital expenditures - drilling and completion of wells		(128,083	)		(192,677	)
Quarterly dividends of $0.01 per share		(225,887	)		(332,210	)
Net borrowings (payments) on credit facility		(1,750,000	)		2,500,000
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		(24,242	)		(32,507	)
Net cash used		(9,997,958	)		(9,517,151	)

Net increase (decrease) in cash	$	(9,526,577	)	$	(879,161	)

Outstanding borrowings on the Credit Facility at December 31, ~~2020,~~2021 were ~~$27,000,000. As of February 1, 2021, outstanding borrowings were $26,000,000.~~$20,000,000.

Looking forward, ~~the Company expects~~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 ~~utilizing the~~from our Credit Facility. ~~The Company intends to use any excess cash to repay outstanding debt which would strengthen the Company’s Balance Sheet. The Company~~We had availability of $3$12.0 million at December 31, ~~2020,~~2021 under ~~its~~our Credit Facility and iswere in compliance with ~~its~~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 ~~the Company’s~~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 has a 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 ~~was redetermined~~will be calculated based on ~~December 4, 2020.~~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 US 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, 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 ~~amendment reduced~~Credit Facility contains financial and 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 ~~Quarterly~~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 Restricted Payment (i) the Available Commitment ~~Reductions from $1,000,000~~is less than or equal to ~~$600,000, reduced~~ten percent (10%) of the ~~consolidated cash balance~~Borrowing Base or (ii) the Leverage Ratio on a pro forma basis is greater than 2.50 to 1.00. All capitalized terms in this description of the Credit Facility that are not otherwise defined in this Form 10-Q shall have the meaning assigned to them in the anti-cash hoarding provision from $2,000,000 to $1,000,000, and changed the debt to EBITDA ratio from 4.0:1.00 to 3.50:1.00. The borrowing base after Quarterly Commitment Reductions was reaffirmed at $30,000,000, and includes a Quarterly Commitment Reduction, whereby the borrowing base is reduced by $600,000 each April 15, July 15, October 15 and January 15, commencingCredit Agreement.

~~reduction in the borrowing base, we do not expect it will impact the liquidity needed to maintain~~ our ~~normal operating strategies.~~ ~~The next~~ expected ~~redetermination will occur in June 2021.~~

~~Going forward, we expect that~~ capital expenditures to drill and complete wells are expected to be immaterial. Anticipated cash provided by operating activities may be reduced due to more frequent production stoppages, as it is currently not economic for some operators to continue to produce in the current economic environment. Based onexpenditure levels, anticipated cash provided by operating activities for ~~2021 and~~2022, combined with availability under ~~the~~our Credit Facility and potential future sales of Common Stock under our currently effective shelf registration statement, including pursuant to the ~~Company has~~ATM Agreement described below, we expect to have sufficient liquidity to fund ~~its~~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 ~~the Company believes~~we believe are most important toin portraying ~~its~~our financial ~~conditions~~condition and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. ~~Other than the adoption of ASC 326 on October 1, 2020, there~~There have been no material changes to the critical accounting policies previously disclosed in ~~the Company’s~~our Annual Report on Form 10-K for the fiscal year ended September 30, ~~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.~~2021.

Natural gas, oil and NGL prices historically have 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. The financial condition, liquidity and results of operations of~~opinions held in the ~~Company may~~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 ~~the Company’s~~our capital expenditures for acquisitions and production. Excluding the impact of ~~the Company’s 2021~~our 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 the Company’s 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 ~~the Company’s~~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.

The Company utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. The Company’s derivative contracts are currently with Bank of Oklahoma. The derivative contracts with Bank of Oklahoma are secured under the Credit Facility with Bank of Oklahoma. These arrangements cover only a portion of the Company’s production, provide only partial price protection against declines in natural gas and oil prices and limit the benefit of future increases in prices. For the Company’s oil fixed price swaps, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $162,000. For the Company’s oil collars, a change of $1.00 (below or above the collar) in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $76,471. For the Company’s natural gas fixed price swaps, a change of $0.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $113,000. For the Company’s natural gas collars, a change of $.10 (below or above the collar) in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $420,305.

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 BOK 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 December 31, ~~2020, the Company~~2021, we had ~~$27,000,000~~$20,000,000 outstanding under the Credit Facility and the effective interest rate was ~~4.25%~~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 $270,000, based on~~operations, of $200,000 for the ~~balance outstanding at~~three months ended December 31, ~~2020.~~

~~The Company does~~2021, assuming that our indebtedness remained constant throughout the period. At this point, we do not believe that ~~its~~our liquidity has been materially affected by the ~~interest rate~~debt market uncertainties noted in the last few years, and ~~the Company does~~we do not believe that ~~its~~our liquidity ~~to fund its 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.

~~The Company maintains~~We maintain “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed in reports ~~the Company files~~we file or ~~submits~~submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including ~~the Company’s~~our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating ~~its~~our disclosure controls and procedures, management ~~recognized~~recognizes that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. ~~The Company’s~~Our disclosure controls and procedures have been designed to meet, and management believes they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this Form 10-Q, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures were not effective ~~to ensure~~as of December 31, 2021 as a result of the material ~~information relating~~weakness discovered during the audit process related to the ~~Company is made known~~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 the tax provision and related disclosures are correct for the quarter ended December 31, 2021, we engaged a large public accounting firm to ~~them.~~ 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 ~~the Company’s~~our internal ~~control~~controls over financial reporting, other than discussed above, that have materially affected, or are reasonably likely to materially affect, ~~the Company’s~~our internal control over financial reporting made during the fiscal quarter or subsequent to the date the assessment was completed.

~~The Company~~We may be the subject of threatened or pending legal actions and contingencies in the normal course of conducting our business. ~~The Company provides~~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, ~~the Company maintains~~we maintain insurance coverage for personal injury and property damage, product liability and other liability coverages in amounts and with deductibles that ~~it believes~~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 ~~Company.~~aggregate, have a material adverse effect on our financial condition, operating results or cash flow.

~~The Company is~~We are subject to certain risks and hazards due to the nature of ~~its~~our business activities. For a discussion of these risks, please refer to Item 1A of ~~the Company’s~~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 ~~the Company~~us or that ~~the Company~~we currently ~~deems~~deem to be immaterial also may materially adversely affect our business, financial condition or future results.

~~During the three months ended December 31, 2020, the Company did not repurchase any shares of the Company’s common stock.~~

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

~~On October 8, 2020, the Company issued 153,375~~ We did not make any repurchases of shares of our Common Stock during the Company’s common stock to Red Stone Resources, LLC as part of the consideration for an asset purchase from Red Stone Resources, LLC. In exchange for the shares, the Company received a $250,000 credit against the purchase price for the assets. The shares were issued in reliancefiscal quarter ended December 31, 2021.

Restrictions upon the ~~exemption from registration provided by Rule 506~~payment of ~~Regulation D~~dividends

The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on payment of ~~the Securities Act of 1933.~~dividends.

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


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

Part I	Financial Information		Page

	Item 1	Condensed Financial Statements		1

		Condensed Balance Sheets – December 31, ~~2020,~~2021, and September 30, ~~2020~~2021		1

		Condensed Statements of Operations – Three months ended December 31, ~~2020~~2021 and ~~2019~~2020		2

		Statements of Stockholders’ Equity – Three months ended December 31, ~~2020~~2021 and ~~2019~~2020		3

		Condensed Statements of Cash Flows – Three months ended December 31, ~~2020~~2021 and ~~2019~~2020		4

		Notes to Condensed Financial Statements		5

	Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations		1314

	Item 3	Quantitative and Qualitative Disclosures about Market Risk		2021

	Item 4	Controls and Procedures		21

Part II	Other Information

	Item 1	Legal Proceedings		2122

	Item 1A	Risk Factors		2122

	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		2122

	Item 6	Exhibits		2223

	Signatures		2223

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 Panhandle Oil and Gas~~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
ASU ~~2016-13,~~2019-12, ~~Financial Instruments~~–~~Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments~~Simplifying the Accounting for Income Taxes.	This standard ~~changes how entities will measure credit losses~~is intended to clarify and simplify the accounting for ~~most financial assets~~income taxes by removing certain exceptions and certain other instruments that are not measured at fair value through net income. The standard replaced the incurred loss approach with an expected loss model for instruments measured at amortized cost.amending existing guidance.	Q1 ~~2021~~2022	The standard is effective for interim and annual periods beginning after December 15, 2019, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company adopted the new standard using the modified retrospective approach, and itadoption of this update did not have a material impact on the Company's financial statements and related disclosures.

Remaining 2021	$	125,058
2022		166,744
2023		167,475
2024		175,520
2025		176,251
Thereafter		353,234
Total lease payments	$	1,164,282
Less: Imputed interest		(146,851	)
Total	$	1,017,431

Quarter Ended	Wellbores⁽¹⁾	Sale Price	Gain/(Loss)	Location
December 31, 2021
	98 wellbores	$2.0 million	($3.5) million	OK
	95 wellbores	$0.5 million	$0.2 million	OK / TX
	499 wellbores	$2.1 million	$1.1 million	AR
December 31, 2020
	No significant divestitures
(1) Number of Wellbores associated with working interests sold.


Contract period (Calendar Year)	Contract total volume	Index	Contract average price
Natural gas costless collars
2021	2,924,500 Mmbtu	NYMEX Henry Hub	$2.33 floor / $3.03 ceiling
2022	1,402,500 Mmbtu	NYMEX Henry Hub	$2.47 floor / $3.14 ceiling
Natural gas fixed price swaps
2021	1,014,500 Mmbtu	NYMEX Henry Hub	$2.69
2022	125,500 Mmbtu	NYMEX Henry Hub	$2.70
Oil costless collars
2021	51,000 Bbls	NYMEX WTI	$36.74 floor / $44.79 ceiling
2022	23,500 Bbls	NYMEX WTI	$36.89 floor / $45.73 ceiling
Oil fixed price swaps
2021	96,000 Bbls	NYMEX WTI	$37.00
2022	59,000 Bbls	NYMEX WTI	$41.51

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

	~~Production volume~~Contract
Contract period	~~covered per month~~total volume	Index	Contract price
~~Natural gas costless collars~~
~~January - December 2022~~	~~45,000 Mmbtu~~	~~NYMEX Henry Hub~~	~~$2.30 floor / $3.15 ceiling~~
~~Natural gas fixed price swaps~~
~~March - December 2021~~	~~50,000 Mmbtu~~	~~NYMEX Henry Hub~~	~~$2.97~~
~~Oil costless collars~~
~~January - December 2022~~	~~3,000 Bbls~~	~~NYMEX WTI~~	~~$40.00 floor / $52.15 ceiling~~
Oil fixed price swaps
~~August~~January - December ~~2021~~2023	~~3,000~~9,000 Bbls	NYMEX WTI	$~~50.74~~70.05

(a)	EXHIBITS		Exhibit 3.1 – Amended and Restated Certificate of Incorporation of PHX Minerals Inc. (incorporated by reference to Exhibit 3.1 to Form 10-K filed December 13, 2021).
			*Exhibit 10.1 – ~~Eighth Amendment~~Purchase and Sale Agreement, dated November 10, 2021, by and between PHX Minerals Inc., as Buyer, and Vendera Resources III, LP and Vendera Management III LLC, collectively as Seller (incorporated by reference to ~~Amended~~Exhibit 10.1 to the Current Report on Form 8-K filed November 12, 2021).
			*Exhibit 10.2 – Purchase and ~~Restated Credit~~Sale Agreement, dated December ~~4, 2020,~~6, 2021, by and among PHX Minerals Inc., ~~the lenders party thereto~~as Buyer, and ~~BOFK, NA dba Bank of Oklahoma,~~Merrimac Properties Partners, LLC and Quarter Horse Energy Partners, 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 December 9, 2021).
			*Exhibit 10.3 – Purchase and Sale Agreement, dated December ~~7, 2020)~~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 Current Report on 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)

		*	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.

PHX MINERALS INC.
		PHX MINERALS INC.

February ~~8, 2021~~14, 2022		/s/ Chad L. Stephens
Date		Chad L. Stephens, President,
		Chief Executive Officer

February ~~8, 2021~~14, 2022		/s/ Ralph D’Amico
Date		Ralph D’Amico, Vice President,
		Chief Financial Officer