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,~~May 6, 2021: ~~22,434,403~~30,401,168 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 (“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 September 30. For example, references to 2021 mean the fiscal year ended September 30, 2021.

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

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			March 31, 2021			September 30, 2020
Assets	(unaudited)						(unaudited)
Current assets:
Cash and cash equivalents	$	1,163,818		$	10,690,395		$	1,270,482		$	10,690,395
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)								4,712,793			2,943,220
Refundable income taxes		3,817,772			3,805,227			2,448,871			3,805,227
Other		1,195,774			351,088			752,248			351,088
Total current assets		9,970,523			17,789,930			9,184,394			17,789,930

Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		329,648,805			324,886,491			329,708,071			324,886,491
Non-producing natural gas and oil properties		22,101,506			18,993,814			21,012,897			18,993,814
Other		582,444			582,444			582,444			582,444
		352,332,755			344,462,749			351,303,412			344,462,749
Less accumulated depreciation, depletion and amortization		(265,704,923	)		(263,590,801	)		(265,863,136	)		(263,590,801	)
Net properties and equipment		86,627,832			80,871,948			85,440,276			80,871,948

Operating lease right-of-use assets		670,065			690,316			649,500			690,316
Other, net		630,429			669,641			593,150			669,641

Total assets	$	97,898,849		$	100,021,835		$	95,867,320		$	100,021,835

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	536,972		$	997,637		$	672,507		$	997,637
Derivative contracts, net		1,189,277			281,942			3,000,530			281,942
Current portion of operating lease liability		149,922			127,108			129,672			127,108
Accrued liabilities and other		1,254,061			1,297,363			1,382,066			1,297,363
Short-term debt		-			1,750,000			-			1,750,000
Total current liabilities		3,130,232			4,454,050			5,184,775			4,454,050

Long-term debt		27,000,000			27,000,000			23,500,000			27,000,000
Deferred income taxes, net		1,260,007			1,329,007			1,041,007			1,329,007
Asset retirement obligations		2,919,495			2,897,522			2,927,662			2,897,522
Derivative contracts, net		385,720			425,705			625,179			425,705
Operating lease liability, net of current portion		867,509			921,625			856,142			921,625

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; 36,000,500 shares authorized; 22,825,226 issued at March 31, 2021, and Class A voting common stock, $0.01666 par value; 24,000,500 shares authorized; 22,647,306 issued at September 30, 2020								380,268			377,304
Capital in excess of par value		10,678,906			10,649,611			11,150,749			10,649,611
Deferred directors' compensation		1,918,534			1,874,007			1,633,939			1,874,007
Retained earnings		55,192,444			56,244,100			54,402,724			56,244,100
		68,169,743			69,145,022			67,567,680			69,145,022
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; 390,267 shares at March 31, 2021, and 411,487 shares at September 30, 2020								(5,835,125	)		(6,151,096	)
Total stockholders' equity		62,335,886			62,993,926			61,732,555			62,993,926
Total liabilities and stockholders' equity	$	97,898,849		$	100,021,835		$	95,867,320		$	100,021,835

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

	Three Months Ended December 31,						Three Months Ended March 31,						Six Months Ended March 31,
	2020			2019			2021			2020			2021			2020
Revenues:	(unaudited)						(unaudited)						(unaudited)
Natural gas, oil and NGL sales	$	6,424,979		$	7,593,838		$	8,345,825		$	7,217,618		$	14,770,804		$	14,811,456
Lease bonuses and rental income		1,433			527,699			58,554			22,092			59,987			549,791
Gains (losses) on derivative contracts		(254,036	)		(817,894	)		(2,348,143	)		4,071,577			(2,602,179	)		3,253,683
Gain on asset sales		20,268			3,272,888			23,257			-			43,525			3,272,888
		6,192,644			10,576,531			6,079,493			11,311,287			12,272,137			21,887,818
Costs and expenses:
Lease operating expenses		1,004,412			1,181,671			1,030,651			1,542,199			2,035,063			2,723,870
Transportation, gathering and marketing		1,280,965			1,383,001			1,319,514			1,356,628			2,600,479			2,739,629
Production taxes		276,026			327,281			443,154			373,754			719,180			701,035
Depreciation, depletion and amortization		2,260,649			2,955,701			1,777,817			3,373,518			4,038,466			6,329,219
Provision for impairment								-			29,545,702			-			29,545,702
Interest expense		301,898			370,665			267,865			346,573			569,763			717,238
General and administrative		1,731,097			2,223,028			2,059,476			2,174,661			3,790,573			4,397,689
Other expense (income)		3,317			(10,930	)		(102,261	)		40,066			(98,944	)		29,136
		6,858,364			8,430,417			6,796,216			38,753,101			13,654,580			47,183,518
Income (loss) before provision (benefit) for income taxes		(665,720	)		2,146,114			(716,723	)		(27,441,814	)		(1,382,443	)		(25,295,700	)

Provision (benefit) for income taxes		(69,000	)		254,000			(217,000	)		(6,987,000	)		(286,000	)		(6,733,000	)

Net income (loss)	$	(596,720	)	$	1,892,114		$	(499,723	)	$	(20,454,814	)	$	(1,096,443	)	$	(18,562,700	)




Basic and diluted earnings (loss) per common share (Note 5)	$	(0.03	)	$	0.11
Basic and diluted earnings (loss) per common share (Note 4)							$	(0.02	)	$	(1.24	)	$	(0.05	)	$	(1.12	)

Basic and diluted weighted average shares outstanding:
Common shares		22,378,146			16,339,673			22,429,777			16,384,687			22,403,678			16,362,057
Unissued, directors' deferred compensation shares		178,090			180,864			178,597			139,390			177,923			186,443
		22,556,236			16,520,537			22,608,374			16,524,077			22,581,601			16,548,500




Dividends declared per share of common stock and paid in period	$	0.01		$	0.04		$	0.01		$	0.04		$	0.02		$	0.08

Dividends declared per share of
common stock and to be paid in quarter ended March 31	$	0.01		$	0.04
common stock and to be paid in quarter ended June 30							$	0.01		$	-

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

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

Balances at September 30, 2020		22,647,306	$	377,304	$	10,649,611		$	1,874,007		$	56,244,100			(411,487	)	$	(6,151,096	)	$	62,993,926

Net income (loss)		-		-		-			-			(596,720	)		-			-			(596,720	)
Equity offering		153,375		2,555		223,203			-			-			-			-			225,758
Restricted stock awards		-		-		122,978			-			-			-			-			122,978
Dividends ($0.02 per share)		-		-		-			-			(454,936	)		-			-			(454,936	)
Distribution of restricted stock to officers and directors		-		-		(316,886	)		-			-			21,220			317,239			353
Increase in deferred directors' compensation charged to expense		-		-		-			44,527			-			-			-			44,527
Balances at December 31, 2020		22,800,681	$	379,859	$	10,678,906		$	1,918,534		$	55,192,444			(390,267	)	$	(5,833,857	)	$	62,335,886
(unaudited)
Net income (loss)		-		-		-			-			(499,723	)		-			-			(499,723	)
Equity offering		-		-		(29,240	)		-			-			-			-			(29,240	)
Restricted stock awards		-		-		161,170			-			-			-			-			161,170
Dividends ($0.01 per share)		-		-		-			-			(289,997	)		-			-			(289,997	)
Distribution of restricted stock to officers and directors		-		-		-			-			-			-			(1,268	)		(1,268	)
Distribution of deferred directors' compensation		24,545		409		339,913			(340,322	)		-			-			-			-
Increase in deferred directors' compensation charged to expense		-		-		-			55,727			-			-			-			55,727
Balances at March 31, 2021		22,825,226	$	380,268	$	11,150,749		$	1,633,939		$	54,402,724			(390,267	)	$	(5,835,125	)	$	61,732,555
(unaudited)

Class A voting

Capital in

Deferred

Common Stock

Excess of

Directors'

Retained

Treasury

Treasury

Shares

Amount

Par Value

Compensation

Earnings

Shares

Stock

Total

Balances at September 30, 2020

22,647,306

$
377,304

$
10,649,611

$
1,874,007

$
56,244,100

(411,487
)

$
(6,151,096
)

$
62,993,926

Net income (loss)

-

-

-

-

(596,720
)

-

-

(596,720
)
Equity Offering

153,375

2,555

223,203

-

-

-

-

225,758

Restricted stock awards

-

-

122,978

-

-

-

-

122,978

Dividends ($0.02 per share)

-

-

-

-

(454,936
)

-

-

(454,936
)
Distribution of restricted stock
   to officers and directors

-

-

(316,886
)

-

-

21,220

317,239

353

Increase in deferred directors'
   compensation charged to
   expense

-

-

-

44,527

-

-

-

44,527

Balances at December 31, 2020

22,800,681

$
379,859

$
10,678,906

$
1,918,534

$
55,192,444

(390,267
)

$
(5,833,857
)

$
62,335,886

(unaudited)

	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			16,897,306	$	281,509	$	2,967,984		$	2,555,781		$	81,848,301			(558,051	)	$	(8,344,042	)	$	79,309,533

Net income (loss)		-		-		-			-		1,892,114			-			-			1,892,114			-		-		-			-			1,892,114			-			-			1,892,114
Purchase of treasury stock		-		-		-			-		-			(632	)		(7,635	)		(7,635	)		-		-		-			-			-			(632	)		(7,635	)		(7,635	)
Restricted stock awards		-		-		148,515			-		-			-			-			148,515			-		-		148,515			-			-			-			-			148,515
Dividends ($0.08 per share)		-		-		-			-		(1,319,899	)		-			-			(1,319,899	)		-		-		-			-			(1,319,899	)		-			-			(1,319,899	)
Distribution of restricted stock to officers and directors		-		-		(82,821	)		-		-			5,546			82,914			93			-		-		(82,821	)		-			-			5,546			82,914			93
Increase in deferred directors' compensation charged to expense		-		-		-			86,212		-			-			-			86,212			-		-		-			86,212			-			-			-			86,212
Balances at December 31, 2019		16,897,306	$	281,509	$	3,033,678		$	2,641,993	$	82,420,516			(553,137	)	$	(8,268,763	)	$	80,108,933			16,897,306	$	281,509	$	3,033,678		$	2,641,993		$	82,420,516			(553,137	)	$	(8,268,763	)	$	80,108,933
(unaudited)
Net income (loss)																							-		-		-			-			(20,454,814	)		-			-			(20,454,814	)
Restricted stock awards																							-		-		343,101			-			-			-			-			343,101
Distribution of deferred directors' compensation																							-		-		(112,396	)		(603,485	)		-			47,885			715,880			(1	)
Increase in deferred directors' compensation charged to expense																							-		-		-			53,918			-			-			-			53,918
Balances at March 31, 2020																							16,897,306	$	281,509	$	3,264,383		$	2,092,426		$	61,965,702			(505,252	)	$	(7,552,883	)	$	60,051,137
(unaudited)

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

	Three months ended December 31,						Six Months Ended March 31,
	2020			2019			2021			2020
Operating Activities	(unaudited)						(unaudited)
Net income (loss)	$	(596,720	)	$	1,892,114		$	(1,096,443	)	$	(18,562,700	)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		2,260,649			2,955,701			4,038,466			6,329,219
Impairment of producing properties								-			29,545,702
Provision for deferred income taxes		(69,000	)		658,000			(288,000	)		(4,711,000	)
Gain from leasing fee mineral acreage		(232	)		(523,384	)		(57,493	)		(544,979	)
Proceeds from leasing fee mineral acreage		232			537,777			64,047			559,462
Net (gain) loss on sales of assets		(30,862	)		(3,272,888	)		(62,097	)		(3,265,449	)
Directors' deferred compensation expense		44,527			86,213			100,254			140,130
Total (gain) loss on derivative contracts		254,036			817,894			2,602,179			(3,253,683	)
Cash receipts (payments) on settled derivative contracts		613,314			901,773			315,883			1,530,912
Restricted stock awards		122,978			148,515			284,148			491,616
Other		14,387			8,896			31,544			7,225
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables		(813,167	)		56,160			(1,732,801	)		1,168,943
Other current assets		(676,620	)		(407,610	)		(388,864	)		(232,349	)
Accounts payable		(398,556	)		(73,831	)		(340,404	)		117,561
Income taxes receivable		(12,545	)		(412,073	)		1,356,356			(2,072,428	)
Other non-current assets		30,958			1,090			56,545			50,010
Accrued liabilities		(271,998	)		(1,275,906	)		(206,213	)		(1,189,850	)
Total adjustments		1,068,101			206,327			5,773,550			24,671,042
Net cash provided by operating activities		471,381			2,098,441			4,677,107			6,108,342

Investing Activities
Capital expenditures		(128,083	)		(105,265	)		(425,098	)		(139,755	)
Acquisition of minerals and overrides		(7,869,746	)		(10,172,594	)		(7,934,504	)		(10,254,016	)
Proceeds from sales of assets		-			3,376,049			21,000			3,376,049
Net cash provided (used) by investing activities		(7,997,829	)		(6,901,810	)		(8,338,602	)		(7,017,722	)

Financing Activities
Borrowings under Credit Facility		-			4,774,297			-			5,561,725
Payments of loan principal		(1,750,000	)		(5,199,297	)		(5,250,000	)		(8,986,725	)
Net proceeds from equity issuance		(24,242	)		-			(53,482	)		-
Purchases of treasury stock		-			(7,635	)		-			(7,635	)
Payments of dividends		(225,887	)		(655,980	)		(454,936	)		(1,319,899	)
Net cash provided (used) by financing activities		(2,000,129	)		(1,088,615	)		(5,758,418	)		(4,752,534	)

Increase (decrease) in cash and cash equivalents		(9,526,577	)		(5,891,984	)		(9,419,913	)		(5,661,914	)
Cash and cash equivalents at beginning of period		10,690,395			6,160,691			10,690,395			6,160,691
Cash and cash equivalents at end of period	$	1,163,818		$	268,707		$	1,270,482		$	498,777

Supplemental Schedule of Noncash Investing and Financing Activities:


Dividends declared and unpaid	$	229,049		$	663,919		$	289,997		$	-
Additions to asset retirement obligations	$	-		$	4		$	-		$	4

Gross additions to properties and equipment	$	7,986,350		$	10,164,680		$	8,759,616		$	10,229,121

Equity offering used for acquisitions		(250,000	)		-			(250,000	)		-
Net (increase) decrease in accounts payable for properties and equipment additions		261,479			113,179			(150,014	)		164,650
Capital expenditures and acquisitions	$	7,997,829		$	10,277,859		$	8,359,602		$	10,393,771

(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. 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 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 has transferred. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and

prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation; however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate.

The following table presents the disaggregation of the Company's natural gas, oil and NGL revenues for the three and six months ended ~~December~~March 31, ~~2020~~2021 and ~~2019:~~

	Three Months Ended December 31, 2020						Three Months Ended March 31, 2021						Six Months Ended March 31, 2021
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	1,190,165	$	2,268,636	$	3,458,801	$	2,366,427	$	2,006,670	$	4,373,097	$	3,556,592	$	4,275,306	$	7,831,898
Oil revenue		1,096,952		1,244,114		2,341,066		1,717,069		1,427,852		3,144,921		2,814,021		2,671,966		5,485,987
NGL revenue		230,338		394,774		625,112		410,851		416,956		827,807		641,189		811,730		1,452,919
Natural gas, oil and NGL sales	$	2,517,455	$	3,907,524	$	6,424,979	$	4,494,347	$	3,851,478	$	8,345,825	$	7,011,802	$	7,759,002	$	14,770,804


	Three Months Ended December 31, 2019						Three Months Ended March 31, 2020						Six Months Ended March 31, 2020
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	1,273,113	$	2,240,330	$	3,513,443	$	1,057,610	$	1,444,976	$	2,502,586	$	2,330,724	$	3,685,305	$	6,016,029
Oil revenue		1,413,211		2,052,301		3,465,512		2,548,648		1,641,643		4,190,291		3,961,859		3,693,944		7,655,803
NGL revenue		222,777		392,106		614,883		196,311		328,430		524,741		419,088		720,536		1,139,624
Natural gas, oil and NGL sales	$	2,909,101	$	4,684,737	$	7,593,838	$	3,802,569	$	3,415,049	$	7,217,618	$	6,711,671	$	8,099,785	$	14,811,456

The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into the timing of when new wells start producing, and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the natural gas, oil and NGL sales receivables line item on the Company’s Balance Sheets. The difference between the Company's estimates and the actual amounts received for natural gas, oil and NGL sales is recorded in the quarter that payment is received from the third party. For the three and six months ended ~~December~~March 31, ~~2020~~2021 and ~~2019,~~2020, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was immaterial and considered a change in estimate.

As noted above, as a non-operator, there are instances when the Company is limited by the information operators provide to us. Through cash received on new wells, in the 2021 second quarter, the Company identified several producing properties on our minerals that had production dates prior to the 2021 second quarter. Estimates of the natural gas and oil sales related to those properties were made and are reflected in the second 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, we have recorded a change in estimate for new wells to Natural gas, oil and NGL sales totaling $562,428 of which $246,405 related to the production periods before October 1, 2020, and $316,023 related to the first quarter of 2021.

Through the use of new technological platforms as well as cash received on new wells, in the 2020 second quarter, the Company identified several producing properties on our minerals that had production dates prior to the 2020 second quarter. Estimates of the natural gas and oil sales related to those properties were made and are reflected in the second 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 identifying additional new wells on Company acreage, we have recorded a change in estimate for new wells to Natural gas, oil and NGL sales totaling $1,140,171 of which $651,681 related to the production periods before October 1, 2019, and $488,490 related to first quarter of 2020.

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis. Excess tax benefits and deficiencies of stock-based compensation are recognized as provision (benefit) for income taxes in the Company’s Statements of Operations.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with detailed well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the ~~quarter~~six months ended ~~December~~March 31, ~~2020,~~2021, was a ~~10%~~21% benefit as compared to a ~~12% provision~~27% benefit for the six months ended March 31, 2020. The effective tax rate for the quarter ended ~~December~~March 31, ~~2019.~~2021, was a 30% benefit as compared to a 25% benefit for the quarter ended March 31, 2020.

The federal Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 Net Operating Losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the 30% limitation on interest expense deductibility under Section 163(j) of the Internal Revenue Code (“IRC”) 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 all interest expense to be deductible for 2020 and reduces 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 associated with the alternative minimum tax (AMT) credits totaling $1.4 million, which was accelerated due to the CARES Act. Additionally, the Company has a $2.2 million receivable associated with the carryback of the 2020 federal net operating loss.

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

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a borrowing base of ~~$30,000,000~~$29,400,000 as of ~~December~~March 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. The Credit Facility is secured by all of the Company’s producing oil and gas properties. The interest rate is based on BOK prime plus from 1.00% to 1.75%, or 30-day LIBOR plus from 2.50% to 3.25%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as the ratio of loan balance to the borrowing base increases. At ~~December~~March 31, ~~2020,~~2021, the effective interest rate was ~~4.25%~~4.00%.

The Company’s debt is recorded at the carrying amount on its Balance Sheets. The carrying amount of the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in Other, net on the Company’s Balance Sheets. Total debt issuance cost net of amortization as of ~~December~~March 31, ~~2020~~2021 was ~~$219,931.~~$195,073. The debt issuance cost is amortized over the life of the Credit Facility.

Determinations of the borrowing base are made semi-annually (usually in June and December) or whenever the banks, in their 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~~occurred in ~~June~~April 2021. See Note 12: Subsequent Events for further discussion.

The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA ratio (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~~March 31, ~~2020,~~2021, the Company was in compliance with the covenants of the Credit Facility, had ~~$27,000,000~~$23,500,000 outstanding under the Credit Facility and had ~~$3,000,000~~$5,900,000 of borrowing base availability under the Credit Facility.

Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. This plan provides that each outside director may individually elect to be credited with future unissued shares of Company common stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination, death or a change-in-control of the Company will the shares recorded for such director be issued under this plan. Directors may elect to receive shares, when issued, over annual time periods 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,~~March 22, 2021, the Company awarded ~~22,300~~125,000 time-based shares of the Company’s common stock as restricted stock to its non-employee directors. These time-based shares had a fair value on their award date of $396,252. On ~~December 31, 2020, 19,327~~January 5, 2021, the Company awarded 303,750 market-based shares of the Company’s common stock as restricted stock ~~vested, and 2,973~~to certain officers. Upon vesting, the market-based shares ~~were repurchased due to a director’s early retirement.~~that do not meet certain performance criteria are forfeited. The ~~restricted stock contains~~market-based shares contain non-forfeitable rights to receive dividends and to vote the shares during the vesting period. These ~~time-based~~market-based shares had a fair value on their award date of ~~$246,640.~~$826,457.

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

The following table summarizes the Company’s pre-tax compensation expense for the three and six months ended ~~December~~March 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				Six Months Ended
	December 31,				March 31,				March 31,
	2020		2019		2021		2020		2021		2020
Market-based, restricted stock	$	10,247	$	74,142	$	79,118	$	200,761	$	89,365	$	274,903
Time-based, restricted stock		112,731		74,373		82,052		142,340		194,783		216,713
Performance-based, restricted stock		-		-		-		-		-		-
Total compensation expense	$	122,978	$	148,515	$	161,170	$	343,101	$	284,148	$	491,616

A summary of the Company’s unrecognized compensation cost for its unvested market-based, time-based and performance-based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table:

	As of December 31, 2020				As of March 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	$	804,745		2.67
Time-based, restricted stock		450,098		1.90		764,298		1.21
Performance-based, restricted stock		-				-
Total	$	507,504			$	1,569,043

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

	December 31, 2020			September 30, 2020			March 31, 2021			September 30, 2020
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		329,648,805			324,886,491		$	329,708,071		$	324,886,491
Non-producing natural gas and oil properties		22,101,506			18,993,814			21,012,897			18,993,814
Other property and equipment		582,444			582,444			582,444			582,444
		352,332,755			344,462,749			351,303,412			344,462,749
Less accumulated depreciation, depletion and amortization		(265,704,923	)		(263,590,801	)		(265,863,136	)		(263,590,801	)
Net properties and equipment		86,627,832			80,871,948		$	85,440,276		$	80,871,948

During the first and second quarters of 2021, the Company had no significant divestitures.

During the second quarter of ~~2021,~~2020, 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 January 21, 2021, the Company closed on the purchase of 11 net mineral acres in Harrison County, Texas, for a consideration of $362,486.

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.

These ~~first quarter~~fiscal year 2021 purchases were accounted for as asset acquisitions.

During the first quarter of 2020, 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.

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

All long-lived assets, principally natural gas and oil properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as: inflation rates; future drilling and completion costs; future sales prices for natural gas, oil and NGL; future production costs; estimates of future natural gas, oil and NGL reserves to be recovered and the timing thereof; the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to natural gas, oil and NGL reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For ~~both~~ the three and six months ended ~~December~~March 31, ~~2020 and 2019,~~2021, the assessment resulted in 0 impairment provisions on producing properties.

During the quarter ended March 31, 2020, the Company recorded an impairment in the carrying value of evaluated oil and gas properties of $29.5 million, of which $19.3 million and $7.3 million was recorded on our Fayetteville Shale and Eagle Ford fields, respectively. The remaining $2.9 million of impairment was taken on other producing assets. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of March 31, 2020, using a discount rate of 10% for proved developed and assigning 0 value to undeveloped locations. The Fayetteville Shale assets are dry-gas assets of which the Company acquired a portion in 2011. Low natural gas prices at March 31, 2020, were the primary reason for impairment in this field. The impairment of the Eagle Ford assets at March 31, 2020, was due to the decline in commodity prices over fiscal 2020.

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. The derivative contracts with Bank of Oklahoma are secured under the Credit Facility with 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

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

Remaining 2021

2,207,500 Mmbtu

NYMEX Henry Hub

$2.35 floor / $3.04 ceiling

2022

1,402,500 Mmbtu

NYMEX Henry Hub

$2.47 floor / $3.14 ceiling

2,200,500 Mmbtu

NYMEX Henry Hub

$2.40 floor / $3.12 ceiling

2023

86,000 Mmbtu

NYMEX Henry Hub

$2.25 floor / $2.96 ceiling

Natural gas fixed price swaps

2021

1,014,500 Mmbtu

NYMEX Henry Hub

$2.69

Remaining 2021

1,166,500 Mmbtu

NYMEX Henry Hub

$2.80

2022

125,500 Mmbtu

NYMEX Henry Hub

$2.70

377,500 Mmbtu

NYMEX Henry Hub

$2.61

2023

84,000 Mmbtu

NYMEX Henry Hub

$2.56

Oil costless collars

2021

51,000 Bbls

NYMEX WTI

$36.74 floor / $44.79 ceiling

Remaining 2021

33,500 Bbls

NYMEX WTI

$36.76 floor / $45.00 ceiling

2022

23,500 Bbls

NYMEX WTI

$36.89 floor / $45.73 ceiling

68,500 Bbls

NYMEX WTI

$40.25 floor / $50.35 ceiling

Oil fixed price swaps

2021

96,000 Bbls

NYMEX WTI

$37.00

Remaining 2021

87,000 Bbls

NYMEX WTI

$39.37

2022

59,000 Bbls

NYMEX WTI

$41.51

59,000 Bbls

NYMEX WTI

$41.51

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~~$3,625,709 as of ~~December~~March 31, ~~2020,~~2021, and a net liability of $707,647 as of September 30, 2020. Cash receipts or payments in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods:

	Three Months Ended						Three Months Ended						Six Months Ended
	December 31,						March 31,						March 31,
	2020			2019			2021			2020			2021			2020
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	(8,967	)	$	-		$	(122	)	$	-		$	(9,089	)	$	-
Natural gas fixed price swaps		(1,863	)		719,800			3,105			500,520			1,242			1,220,320
Oil costless collars		88,944			113,699			(112,590	)		87,997			(23,646	)		201,696
Oil fixed price swaps		535,200			68,274			(187,824	)		40,622			347,376			108,896
Cash received (paid) on derivative contracts, net	$	613,314		$	901,773		$	(297,431	)	$	629,139		$	315,883		$	1,530,912
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	678,961		$	5,900		$	(81,881	)	$	21,983		$	597,080		$	27,883
Natural gas fixed price swaps		288,887			(571,809	)		(6,291	)		(113,956	)		282,596			(685,765	)
Oil costless collars		(410,886	)		(480,456	)		(696,360	)		954,260			(1,107,246	)		473,804
Oil fixed price swaps		(1,424,312	)		(673,302	)		(1,266,180	)		2,580,151			(2,690,492	)		1,906,849
Non-cash gain (loss) on derivative contracts, net	$	(867,350	)	$	(1,719,667	)	$	(2,050,712	)	$	3,442,438		$	(2,918,062	)	$	1,722,771
Gains (losses) on derivative contracts, net	$	(254,036	)	$	(817,894	)	$	(2,348,143	)	$	4,071,577		$	(2,602,179	)	$	3,253,683

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

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

	December 31, 2020												September 30, 2020								March 31, 2021												September 30, 2020
	Fair Value (a)												Fair Value (a)								Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts								Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets			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	$	106,480		$	3,107,010		$	177,756		$	802,935		$	864,466		$	1,146,408		$	425,705
Offsetting adjustments		(201,842	)		(201,842	)		(93,019	)		(93,019	)		(864,466	)		(864,466	)		-		(106,480	)		(106,480	)		(177,756	)		(177,756	)		(864,466	)		(864,466	)		-
Net presentation on Condensed Balance Sheets	$	-		$	1,189,277		$	-		$	385,720		$	-		$	281,942		$	425,705	$	-		$	3,000,530		$	-		$	625,179		$	-		$	281,942		$	425,705

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

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

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2

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

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

	Fair Value Measurement at December 31, 2020										Fair Value Measurement at March 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	)	$	-	$	(2,472,697	)	$	-	$	(2,472,697	)
Derivative Contracts - Collars	$	-	$	(374,771	)	$	-	$	(374,771	)	$	-	$	(1,153,012	)	$	-	$	(1,153,012	)

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 producing properties for impairment. This assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future natural gas, oil and NGL prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off during the three months ended March 31, 2020 in the amount $229,895.

At March 31, 2021, and September 30, 2020, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments. Financial instruments include long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s Credit Facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

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

~~Subsequent to December 31, 2020,~~On April 7, 2021, the Company entered into ~~new derivative contracts~~a Ninth Amendment (the “Amendment”) to its Amended and Restated Credit Agreement, dated November 25, 2013 (as amended from time to time, the “Credit Facility”) with BOKF, NA dba Bank of Oklahoma, as ~~summarized~~lender, issuing bank and administrative agent for several banks and other financial institutions and lenders thereto. The Amendment, among other things, reduces the Company’s borrowing base under the Credit Facility to $29.0 million, extends the maturity date one year to November 30, 2023 and reduces the Quarterly Commitment Reductions from $600,000 to $500,000, commencing on April 15, 2021. Additionally, the Amendment increases the Company’s distribution allowance from $1.0 million to $1.5 million per annum for a period of one year from the date of the Amendment and extends this allowance beyond the date that is one year following the date of the Amendment so long as (i) the Available Commitment is greater than or equal to 20% of the Total Commitment and (ii) the Leverage Ratio on a pro forma basis does not exceed 2.75 to 1.00. The existing prohibition of all Restricted Payments other than the subject distribution allowance and the existing requirement that immediately after giving effect to a permitted Restricted Payment, no Default or Event of Default may exist or result therefrom are to remain in effect.

The Amendment also provides that any cash actually received by the Company in an equity raise is considered “Excluded Cash” (previously, this was limited to cash actually received by the Company in an equity raise on or prior to December 24, 2020) and that such cash may be used for acquisitions by the Company without BOKF’s prior written consent. The capitalized terms which are not defined in this description of the Amendment shall have the meaning given to such terms in the ~~table below:~~

Subsequent to ~~December~~March 31, ~~2020,~~2021, the Company paid down an additional ~~$1,000,000~~$1,750,000 under the Credit Facility, bringing the total outstanding debt balance to ~~$26,000,000,~~$21,750,000, as of ~~February~~April 28, 2021.

Subsequent to March 31, 2021, the Company closed on an underwritten public offering of 6,175,000 common shares (inclusive of overallotment option) with estimated net proceeds of $11.2 million to the Company. The Company intends to use the net proceeds of the offering to fund the Acquisition (as hereinafter defined) and for general corporate purposes.

On April 30, 2021, the Company closed on the acquisition of certain mineral and royalty assets located in Stephens, Carter, Canadian, McClain, Murray, and Garvin Counties, Oklahoma, for aggregate consideration of approximately $10,939,875 (the “Acquisition”), pursuant to a Purchase and Sale Agreement (the “Purchase Agreement”) entered into by the Company with Palmetto Investment Partners, LLC, Palmetto Investment Partners II, LLC and Crestwood Exploration Partners, LLC, on April 14, 2021. The Acquisition includes mineral and royalty assets totaling approximately 2,514 net royalty acres and 1,889 net mineral acres in the SCOOP play. The Acquisition has an effective date of November 1, ~~2021.~~2020.

Total consideration for the Acquisition after purchase price adjustments included a cash payment of approximately $8,539,875 and the issuance of 1,200,000 shares of common stock (the “Equity Consideration”), which are being held in escrow to satisfy potential indemnification claims under the Purchase Agreement. The Purchase Agreement includes registration rights relating to the Equity Considerationpursuant to which the Company agrees to register with the Securities and Exchange Commission the shares constituting the Equity Consideration. The Company agrees to file a resale registration statement and to use reasonable best efforts to cause such registration statement to be declared effective as promptly as possible after the filing thereof.

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 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 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 an active working interest participant in wells drilled on our mineral and leasehold acreage, our current focus is on growth through mineral acquisitions and development of our significant mineral acreage inventory in our core areas of focus, which include the SCOOP, STACK and Arkoma Stack plays in Oklahoma, the Permian Basin in Texas and New Mexico, the 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 going forward.

Our results of operations are dependent primarily upon our: existing reserve quantities; costs associated with acquiring new reserves; production quantities and related production costs; and natural gas, oil and NGL prices. Although a significant amount of our revenue is currently 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~~MARCH 31, ~~2020,~~2021, COMPARED TO THREE MONTHS ENDED ~~DECEMBER~~MARCH 31, ~~2019~~2020

The Company recorded a ~~first~~second quarter 2021 net loss of ~~$596,720,~~$499,723, or ~~$0.03~~$0.02 per share, as compared to a net ~~income~~loss of ~~$1,892,114,~~$20,454,814, or ~~$0.11~~$1.24 per share, in the 2020 quarter. The change in net ~~income (loss)~~loss was principally the result of ~~decreased~~increased natural gas, oil and NGL sales ~~decreased gain on asset sales~~ and decreased ~~lease bonuses and rental income, partially offset by a decrease in~~ G&A, LOE, transportation, gathering and marketing expenses, ~~production taxes,~~ depreciation, depletion and amortization and ~~changes~~impairment expense, partially offset by a decrease in gain (losses) on derivative contracts and income tax ~~provision (benefit).~~benefit. These items are further discussed below.

The ~~decrease~~increase in natural gas, oil and NGL sales was primarily due to ~~decreases~~increases in natural gas, oil and NGL prices of 54%, 24% and 3%101%, respectively, and ~~decreases~~an increase in natural gas ~~and oil~~ volumes of ~~10%~~13%, partially offset by a decrease in oil and ~~11%~~NGL volumes of 40% and 22%, respectively. The following table outlines the Company’s production and average sales prices for natural gas, oil and NGL for the three-month periods of fiscal 2021 and 2020:

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
3/31/2021		1,735,820	$	2.52		56,269	$	55.89		37,228	$	22.24		2,296,802	$	3.63
3/31/2020		1,529,367	$	1.64		93,141	$	44.99		47,487	$	11.05		2,373,135	$	3.04

The decrease in oil production was primarily due to ~~postponement~~naturally declining production in high-interest wells brought online during the first quarter of ~~workovers~~2020 in the Bakken play, as well as reduced drilling and completion activity in 2021, compared to 2020 in the Eagle Ford and SCOOP plays due to prevailing economic conditions. The decrease in NGL production was primarily attributable

to production downtime and curtailments in high-interest wells in response to market conditions in the SCOOP and STACK plays, as well as naturally declining production in high interest wells in the Eagle Ford. This decrease was partially offset by new wells brought online 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~~Anadarko Granite Wash play. Natural gas volumes ~~decreased~~increased as a result of acquisitions in the Haynesville Shale, which were partially offset by naturally declining production in the Fayetteville Shale, ~~Arkoma Stack~~production downtime and ~~STACK plays, as well as production downtime~~curtailments in high-interest wells ~~and curtailments~~ in response to market conditions in the ~~Arkoma Stack~~STACK and ~~STACK~~SCOOP plays.

Quarter ended	Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold		Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold
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		1,475,456		58,675		41,138		2,074,334
9/30/2020		1,423,602		55,626		46,737		2,037,779		1,423,602		55,626		46,737		2,037,779
6/30/2020		1,361,909		55,138		35,169		1,903,752		1,361,909		55,138		35,169		1,903,752
3/31/2020		1,529,367		93,141		47,487		2,373,135		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		Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold
3/31/2021										924,969		31,768		19,088		1,230,105
12/31/2020		487,925		27,840		14,948		744,653		487,925		27,840		14,948		744,653
9/30/2020		491,234		27,326		20,181		776,276		491,234		27,326		20,181		776,276
6/30/2020		544,249		28,468		16,574		814,501		544,249		28,468		16,574		814,501
3/31/2020		549,999		54,077		16,188		971,589		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		Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold
3/31/2021										810,851		24,501		18,140		1,066,697
12/31/2020		987,531		30,835		26,190		1,329,681		987,531		30,835		26,190		1,329,681
9/30/2020		932,368		28,300		26,556		1,261,503		932,368		28,300		26,556		1,261,503
6/30/2020		817,660		26,670		18,595		1,089,251		817,660		26,670		18,595		1,089,251
3/31/2020		979,368		39,064		31,299		1,401,546		979,368		39,064		31,299		1,401,546
12/31/2019		1,085,014		40,179		27,828		1,493,056

When the Company leases its mineral interests, an upfront cash payment, or lease bonus, is generally received. Lease bonuses and rental income increased $36,462 in the 2021 quarter primarily as the result of increased leasing activity in the second quarter of 2021.

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:

The net loss on derivative contracts in the current period was principally due to the natural gas and oil collars and fixed price swaps being less beneficial in relation to their respective contracted volumes and prices at the beginning of the period, compared to such natural gas and oil collars and fixed price swaps being more beneficial in the second quarter of 2020 causing a net gain.

The Company’s natural gas and oil costless collar contracts and fixed price swaps in place at March 31, 2021, had expiration dates of April 2021 through February 2023. The Company utilizes derivative contracts for the purpose of protecting its cash flow and return on investments.

The Company is responsible for a portion of LOE relating to a well as a working interest owner. LOE includes normally recurring and nonrecurring expenses associated with the Company’s 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 natural gas and oil properties. Total LOE related to field operating costs decreased $511,548, or 33%, in the 2021 quarter compared to the 2020 quarter. The decrease in LOE rate was principally the result of the Company’s strategic decision to not participate with a working interest in new wells.

Transportation, gathering and marketing decreased $37,114, or 3%, in the 2021 quarter. This decrease in costs was primarily driven by slightly lower production in the 2021 quarter compared to the 2020 quarter. The consistent rate per Mcfe was primarily due to the change in natural gas sales in relation to other products. Natural gas sales bear the large majority of the Company’s transportation, gathering and marketing fees.

Production taxes are paid on produced natural gas and oil based on a percentage of revenues from products sold at both fixed and variable rates established by federal, state or local taxing authorities. Production taxes increased $69,400, or 19%, in the 2021 quarter. The increase in amount was primarily the result of increased natural gas, oil and NGL sales of $1,128,207 in the 2021 quarter as compared to the 2020 quarter.

DD&A is the amount of cost basis of natural gas and oil properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis for working interest, and on a straight-line basis for producing and non-producing minerals. Estimates of proved developed producing reserves are a major component of the calculation of depletion. DD&A decreased $1,595,701, or 47%, in the 2021 quarter, of which $108,393 of the decrease resulted from production decreasing 3% in the 2021 quarter and $1,487,308 of such decrease resulted from a $0.65 decrease in the DD&A rate per Mcfe. The rate decrease was mainly due to impairments taken at the end of 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 in the reserve calculations during the 2021 quarter, as compared to the 2020 quarter, shortening the economic life of wells. This resulted in lower projected remaining reserves on a significant number of wells causing increased units of production DD&A.

There was no provision for impairment in the 2021 quarter as compared to $29,545,702 provision for impairment in the 2020 quarter. During the 2020 quarter, impairment of $29,315,807 was recorded on seven different fields, including the Fayetteville and Eagle Ford shales, which represented 90% of our total impairment in the second quarter of 2020. The Fayetteville Shale assets are dry-gas assets of which the Company acquired a portion in 2011. Low natural gas prices at March 31, 2020, were the primary reason for impairment in this field. Impairment of the Eagle Ford assets at March 31, 2020, was due to the decline in commodity prices over fiscal 2020. The impairment on assets in these seven fields was caused by lower futures prices associated with our products. Futures prices experienced downward pressure resulting in low pricing as of the end of the 2020 quarter. The reduced future net value associated with these fields caused the assets to fail the step one test for impairment as their undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The remaining $229,895 of impairment was recorded on other assets.

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

Income taxes changed $6,770,000, from a $6,987,000 benefit in the 2020 quarter to a $217,000 benefit in the 2021 quarter. The effective tax rate changed from a 25% benefit in the 2020 quarter to a 30% benefit in the 2021 quarter. The change in income taxes resulted primarily from the change in net loss.

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

G&A 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 $115,185 as compared to the 2020 quarter. The decrease was primarily due to cost reduction efforts by the Company.

The Company recorded a six-month net loss of $1,096,443, or $0.05 per share, in the 2021 period, as compared to a net loss of $18,562,700, or $1.12 per share, in the 2020 period. The change in net income (loss) was principally the result of decreased G&A, LOE, transportation, gathering and marketing expenses, depreciation, depletion and amortization and impairment expense, partially offset by a decrease in natural gas, oil and NGL sales, gain (losses) on derivative contracts, gain on asset sales and income tax benefit. These items are further discussed below.

Natural gas, oil and NGL sales remained relatively consistent with decreases in oil and NGL volumes of 28% and 10%, respectively, partially offset by increases in natural gas and NGL prices of 29% and 41%, respectively. The following table outlines the Company’s production and average sales prices for natural gas, oil and NGL for the six-month periods of fiscal 2021 and 2020:

The decrease in oil production was primarily due to naturally declining production in high-interest wells brought online during the first quarter of 2020 in the Bakken play, as well as reduced drilling and completion activity in 2021, compared to 2020 in the Eagle Ford and SCOOP plays due to prevailing economic conditions. The decrease in NGL production was primarily attributable to production downtime and curtailments in high-interest wells in response to market conditions in the SCOOP play as well as naturally declining production in liquid-rich gas areas of the Anadarko Granite Wash play. Natural gas volumes increased as a result of acquisitions in the Haynesville Shale, which were partially offset by naturally declining production in the Fayetteville Shale, production downtime and curtailments in high-interest wells in response to market conditions in the STACK and SCOOP plays.

When the Company leases its mineral interests, an upfront cash payment, or lease bonus, is generally received. Lease bonuses and rental income decreased ~~$526,266~~$489,804 in the 2021 ~~quarter.~~period due to general slowdown in leasing activity.

	For the Three Months Ended December 31,							For the Six Months Ended March 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	$	613,314		$	901,773		(32%)	$	315,883		$	1,530,912	(79%)
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(867,350	)	$	(1,719,667	)	50%	$	(2,918,062	)	$	1,722,771	(269%)
Gains (losses) on derivative contracts, net	$	(254,036	)	$	(817,894	)	69%	$	(2,602,179	)	$	3,253,683	(180%)

	As of December 31,							As of March 31,
	2020			2019				2021			2020
Fair value of derivative contracts
Net asset (net liability)	$	(1,574,997	)	$	774,477		(303%)	$	(3,625,709	)	$	4,216,915	(186%)

The net loss on derivative contracts in ~~both periods~~the current period was principally due to the natural gas and oil collars and fixed price swaps being less beneficial in relation to their respective contracted volumes and prices at the beginning of the ~~periods. During the 2021 quarter, we received $613,314 on settled derivative contracts as~~period, compared to ~~$901,733 received~~such natural gas and oil collars and fixed price swaps being more beneficial in the 2020 ~~quarter.~~period causing a net gain.

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

	For the Three Months Ended December 31,					For the Six Months Ended March 31,
					Percent					Percent
	2020		2019		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Lease operating expenses	$	1,004,412	$	1,181,671	(15%)	$	2,035,063	$	2,723,870	(25%)
Lease operating expenses per MCFE	$	0.48	$	0.52	(8%)	$	0.47	$	0.59	(20%)

and oil properties. Total LOE related to field operating costs decreased ~~$177,259,~~$688,807, or ~~15%~~25%, in the 2021 ~~quarter~~period compared to the 2020 ~~quarter.~~period. The decrease in LOE ~~rate~~expense was principally the result of the Company’s strategic decision to not participate with a working interest in new wells.

	For the Three Months Ended December 31,					For the Six Months Ended March 31,
					Percent					Percent
	2020		2019		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Transportation, gathering and marketing	$	1,280,965	$	1,383,001	(7%)	$	2,600,479	$	2,739,629	(5%)
Transportation, gathering and marketing per MCFE	$	0.62	$	0.61	2%	$	0.59	$	0.59	(—%)

Transportation, gathering and marketing decreased ~~$102,036~~$139,150, or 7%5%, in the 2021 ~~quarter.~~period. This decrease in costs was primarily driven by lower production in the 2021 ~~quarter~~period compared to the 2020 ~~quarter.~~period. The ~~increase in~~consistent rate per Mcfe was primarily due to the change in natural gas sales in relation to other products. Natural gas sales bear the large majority of the Company’s transportation, gathering and marketing fees.

	For the Three Months Ended December 31,							For the Six Months Ended March 31,
							Percent							Percent
	2020			2019			Incr. or (Decr.)	2021			2020			Incr. or (Decr.)
Production taxes	$	276,026		$	327,281		(16%)	$	719,180		$	701,035		3%
Production taxes as % of sales		4.3	%		4.3	%	(—%)		4.9	%		4.7	%	4%

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 $18,145, or ~~16%~~3%, in the 2021 ~~quarter.~~period. The ~~decrease~~increase in amount was primarily the result of increased prices partially offset by decreased ~~natural gas, oil and NGL sales of $1,168,859~~production volumes in the 2021 ~~quarter~~period as compared to the 2020 ~~quarter.~~period.

	For the Three Months Ended December 31,					For the Six Months Ended March 31,
					Percent					Percent
	2020		2019		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Depreciation, depletion and amortization	$	2,260,649	$	2,955,701	(24%)	$	4,038,466	$	6,329,219	(36%)
Depreciation, depletion and amortization per MCFE	$	1.09	$	1.30	(16%)	$	0.92	$	1.36	(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,~~$2,290,753, or ~~24%~~36%, in the 2021 ~~quarter. $265,399~~period, of which $381,457 of the decrease resulted from production decreasing 9%6% in the 2021 ~~quarter. Also, DD&A decreased $429,653 as~~period and $1,909,296 of the decrease resulted from a ~~result of a $0.21~~$0.44 decrease in the DD&A rate per Mcfe. The rate decrease was mainly due to impairments taken at the end of ~~fiscal 2019 and~~ the 2020 second quarter, which lowered the basis of the assets. The rate decrease was partially offset by lower natural gas, oil and NGL prices utilized in the reserve calculations during the 2021 ~~quarter,~~period, as compared to the 2020 ~~quarter,~~period, shortening the economic life of wells. This resulted in lower projected remaining reserves on a significant number of wells causing increased units of production DD&A.

~~(16)~~There was no provision for impairment in the 2021 period as compared to $29,545,702 provision for impairment in the 2020 period. During the 2020 period, impairment of $29,315,807 was recorded on seven different fields, including the Fayetteville and Eagle Ford shales, which represented 90% of our total impairment. The Fayetteville Shale assets are dry-gas assets of which the Company acquired a portion in 2011. Low natural gas prices at March 31, 2020, were the primary reason for impairment in this field. Impairment of the Eagle Ford assets at March 31, 2020, was due to the decline in commodity prices over fiscal 2020. The impairment on assets in these seven fields was caused by lower futures prices associated with our products. Futures prices experienced downward pressure resulting in low pricing as of the end of the 2020 period. The reduced future net value associated with these fields caused the assets to fail the step one test for impairment as their undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The remaining $229,895 of impairment was recorded on other assets.

	For the Three Months Ended December 31,					For the Six Months Ended March 31,
					Percent					Percent
	2020		2019		Incr. or (Decr.)	2021		2020		Incr. or (Decr.)
Interest Expense	$	301,898	$	370,665	(19%)	$	569,763	$	717,238	(21%)
Weighted average debt outstanding	$	27,796,196	$	35,094,158	(21%)	$	26,762,363	$	34,354,950	(22%)

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

Income taxes changed ~~$323,000,~~$6,447,000, from a ~~$254,000 provision~~$6,733,000 benefit in the 2020 ~~quarter~~period to a ~~$69,000~~$286,000 benefit in the 2021 ~~quarter.~~period. The effective tax rate changed from a ~~12% provision~~27% benefit in the 2020 ~~quarter~~period to a ~~10%~~21% benefit in the 2021 ~~quarter.~~period. The income tax change resulted primarily from the change in net loss.

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~~$607,116 as compared to the 2020 ~~quarter.~~period. The decrease was primarily due to cost reduction efforts by the Company.

The Company had positive working capital of ~~$6,840,291~~$3,999,619 at ~~December~~March 31, ~~2020,~~2021, compared to positive working capital of $13,335,880 at September 30, 2020, which included $7.3 million ~~related to~~of cash used for the first quarter acquisitions.

Cash and cash equivalents were ~~$1,163,818~~$1,270,482 as of ~~December~~March 31, ~~2020,~~2021, compared to $10,690,395 at September 30, 2020, a decrease of ~~$9,526,577.~~$9,419,913. The decrease in cash is primarily associated with the closing of previously announced acquisitions, which were funded by the equity raise from September 2020. Cash flows for the ~~three~~six months ended ~~December~~March 31 are summarized as follows:

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

Operating activities	$	471,381		$	2,098,441		$	(1,627,060	)	$	4,677,107		$	6,108,342		$	(1,431,235	)
Investing activities		(7,997,829	)		(6,901,810	)		(1,096,019	)		(8,338,602	)		(7,017,722	)		(1,320,880	)
Financing activities		(2,000,129	)		(1,088,615	)		(911,514	)		(5,758,418	)		(4,752,534	)		(1,005,884	)
Increase (decrease) in cash and cash equivalents	$	(9,526,577	)	$	(5,891,984	)	$	(3,634,593	)	$	(9,419,913	)	$	(5,661,914	)	$	(3,757,999	)

Net cash provided by operating activities decreased ~~$1,627,060~~$1,431,235 during the 2021 period, as compared to the 2020 period, primarily the result of the following:

Net cash used by investing activities increased ~~$1,096,019~~$1,320,880 during the 2021 period, as compared to the 2020 period, primarily due to lower net proceeds from the sale of assets of ~~$3,376,049~~$3,355,049 and higher payments of ~~$22,818~~$285,343 for drilling and completion activity, partially offset by lower acquisition costs of ~~$2,302,848~~$2,319,512 during 2021.

Net cash used by financing activities increased ~~$911,514~~$1,005,884 during the 2021 period, as compared to the 2020 period, primarily the result of higher net payments on long-term debt of ~~$1,750,000~~$5,250,000 in 2021 compared to ~~$425,000~~$3,425,000 in the prior year period, partially offset by decreased stock repurchases of $7,635 and a decrease of ~~$430,093~~$864,963 in dividend payments as a result of a reduction in the Company’s quarterly dividend from $0.04 per share to $0.01 per share beginning with the June 2020 dividend payment.

Capital expenditures to drill and complete wells increased ~~$22,818,~~$285,343, or ~~22%~~204%, from the 2020 to the 2021 period as a result of increased workover activity in the 2021 period. The Company currently has 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.

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

On November 14, 2019, 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. The value received was a gain on the sale of assets of $3.3 million in the first quarter of 2020. The Company utilized a like-kind exchange under Internal Revenue Code Section 1031 to defer income tax on all of the gain by offsetting it with the STACK/SCOOP mineral acreage acquisition that was purchased during the quarter using qualified exchange accommodation agreements.

On December 18, 2019, 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.~~the Company.

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.

On January 21, 2021, the Company closed on the purchase of 11 net mineral acres in Harrison Counties, Texas, for a consideration of $362,486.

Subsequent the second quarter of 2021, the Company closed on an underwritten public offering of 6,175,000 common shares (inclusive of overallotment option) with estimated net proceeds of $11.2 million to the Company. The Company intends to use the net proceeds of the offering to fund the Acquisition (as hereinafter defined) and for general corporate purposes.

On April 30, 2021, the Company closed on the acquisition of certain mineral and royalty assets located in Stephens, Carter, Canadian, McClain, Murray, and Garvin Counties, Oklahoma, for aggregate consideration of approximately $10,939,875 (the “Acquisition”). The Acquisition includes mineral and royalty assets totaling approximately 2,514 net royalty acres and 1,889 net mineral acres in the SCOOP play. The Acquisition has an effective date of November 1, 2020. Total consideration for the Acquisition after purchase price adjustments included a cash payment of approximately $8,539,875 and the issuance of 1,200,000 shares of common stock.

The Company received lease bonus payments during fiscal 2021 totaling ~~$232.~~$64,047. Looking forward, the cash flow from bonus payments associated with the leasing of drilling rights on the Company’s mineral acreage is difficult to project as the current economic downturn has decreased demand for new leasing by operators. However, management plans to continue to actively pursue leasing opportunities.

With continued natural gas and oil price volatility, management continues to evaluate opportunities for product price protection through additional hedging of the Company’s future natural gas and oil production. Additionally, pursuant to the Credit Facility, the Company is required to enter into and maintain certain Swap Agreements (as defined in the Credit Facility) for a period of eighteen (18) months fixing prices on oil or gas expected to be produced. See Note ~~10:~~9: Derivatives for a complete list of the Company’s outstanding derivative contracts at ~~December~~March 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 cash provided by operating activities and resultant change to cash is summarized in the table below:

	Three months ended			Six Months Ended
	December 31, 2020			March 31, 2021
Cash provided by operating activities	$	471,381		$	4,677,107
Cash provided (used) by:

Capital expenditures - acquisitions		(7,869,746	)		(7,934,504	)
Capital expenditures - drilling and completion of wells		(128,083	)		(425,098	)
Quarterly dividends of $0.01 per share		(225,887	)		(454,936	)
Net borrowings (payments) on credit facility		(1,750,000	)		(5,250,000	)
Proceeds from sale of assets					21,000
Net proceeds from equity issuance		(24,242	)		(53,482	)
Net cash used		(9,997,958	)		(14,097,020	)

Net increase (decrease) in cash	$	(9,526,577	)	$	(9,419,913	)

Outstanding borrowings on the Credit Facility at ~~December~~March 31, ~~2020,~~2021, were ~~$27,000,000.~~$23,500,000. As of ~~February 1,~~April 28, 2021, outstanding borrowings were ~~$26,000,000.~~$21,750,000.

Looking forward, the Company expects to fund overhead costs and any dividend payments from cash provided by operating activities, cash on hand and borrowings utilizing the Credit Facility. The Company intends to use any excess cash to repay outstanding debt which would strengthen the Company’s Balance Sheet. The Company had availability of $3$5.9 million at ~~December~~March 31, ~~2020,~~2021, under its Credit Facility and is in compliance with its debt covenants (current ratio, debt to trailing 12-month EBITDA, as defined by the Credit Facility, and restricted payments limited by leverage ratio). The debt covenants limit the maximum ratio of the Company’s debt to EBITDA to no more than 3.5:1.

The borrowing base under the Credit Facility was redetermined on December 4, 2020. 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, 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, commencing on January 15, 2021. ~~Despite the~~

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

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 on anticipated cash provided by operating activities for 2021 and availability under the Credit Facility, the Company has sufficient liquidity to fund its ongoing operations.

Critical accounting policies are those the Company believes are most important to portraying its financial conditions and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. Other than the adoption of ASC 326 on October 1, 2020, there have been no material changes to the critical accounting policies previously disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2020.

There were no material changes in our contractual obligations and other commitments as disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2020.

Natural gas, oil and NGL prices historically have been volatile, and this volatility is expected to continue, especially in light of the ongoing COVID-19 pandemic and related economic repercussions. The financial condition, liquidity and results of operations of the Company may be adversely impacted by precipitous changes in natural gas and oil prices. The market price of natural gas, oil and NGL in 2021 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2021 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 for operating revenue based on the Company’s prior year natural gas 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.~~$151,000. 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.~~$104,427. 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.~~$160,000. 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.~~$436,808.

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Credit Facility. Borrowings under the Credit Facility bear interest at the BOK prime rate plus from 1.00% to 1.75%, or 30 day LIBOR plus from 2.50% to 3.25%. At ~~December~~March 31, ~~2020,~~2021, the Company had ~~$27,000,000~~$23,500,000 outstanding under the Credit Facility and the effective interest rate was ~~4.25%~~4.00%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately ~~$270,000,~~$235,000, based on the balance outstanding at ~~December~~March 31, ~~2020.~~2021.

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

The Company maintains “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The Company’s disclosure controls and procedures have been designed to meet, and management believes they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this Form 10-Q, the Chief Executive Officer and Chief Financial Officer have concluded the Company’s disclosure controls and procedures were effective to ensure material information relating to the Company is made known to them. There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter or subsequent to the date the assessment was completed.

The Company is subject to certain risks and hazards due to the nature of its business activities. For a discussion of these risks, please refer to Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2020. 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. Additional risks and uncertainties not currently known to the Company or that the Company currently deems to be immaterial also may materially adversely affect business, financial condition or future results.

During the three months ended ~~December~~March 31, ~~2020,~~2021, the Company did not repurchase any shares of the Company’s common stock.

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

On October 8, 2020, the Company issued 153,375 shares of 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 reliance upon the exemption from registration provided by Rule 506 of Regulation D of the Securities Act of 1933.

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

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

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

		Condensed Statements of Cash Flows – ~~Three~~Six months ended ~~December~~March 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		2024

	Item 4	Controls and Procedures		2125

Part II	Other Information

	Item 1	Legal Proceedings		2125

	Item 1A	Risk Factors		2125

	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		2125

	Item 6	Exhibits		2226

	Signatures		2226

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

Standard	Description	Date of Adoption	Impact on Financial Statements or Other Significant Matters
~~Adoption of~~ New Accounting Pronouncements yet to be Adopted
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~~This standard is effective for ~~interim and annual periods~~public business entities beginning after December 15, ~~2019, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption.~~2020, with early adoption permitted. The Company ~~adopted~~does not believe the ~~new~~adoption of this standard ~~using the modified retrospective approach, and it did not~~will have a material impact on ~~the Company's~~its 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 March 31,
	2021				2020
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	5,288,710	$	29,315,807

	Six Months Ended March 31,
	2021				2020
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	5,288,710	$	29,315,807

	~~Production volume~~
~~Contract period~~	~~covered per month~~	~~Index~~	~~Contract price~~
~~Natural gas costless collars~~
~~January - December 2022~~	~~45,000 Mmbtu~~Credit Facility.	~~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 - December 2021~~	~~3,000 Bbls~~	~~NYMEX WTI~~	~~$50.74~~

	For the Three Months Ended March 31,
					Percent
	2021		2020		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	8,345,825	$	7,217,618	16%

(a)	EXHIBITS	Exhibit 3.1 – Amended and Restated Certificate of Incorporation of PHX Minerals Inc. Exhibit 10.1 – Eighth Amendment to Amended and Restated Credit Agreement, dated December 4, 2020, by and among PHX Minerals Inc., the lenders party thereto and BOFK, NA dba Bank of Oklahoma, as administrative agent for the lenders and as issuing bank (incorporated by reference to Form ~~8-K~~10-Q dated ~~December 7, 2020)~~February 8, 2021) Exhibit 31.1 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002
		Exhibit 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002
		Exhibit 32.1 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002
		Exhibit 32.2 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002
		Exhibit 101.INS – XBRL Instance Document
		Exhibit 101.SCH – XBRL Taxonomy Extension Schema Document
		Exhibit 101.CAL – XBRL Taxonomy Extension Calculation Linkbase Document
		Exhibit 101.LAB – XBRL Taxonomy Extension Labels Linkbase Document
		Exhibit 101.PRE – XBRL Taxonomy Extension Presentation Linkbase Document
		Exhibit 101.DEF – XBRL Taxonomy Extension Definition Linkbase Document Exhibit 104 – Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

PHX MINERALS INC.
		PHX MINERALS INC.

~~February 8,~~May 6, 2021		/s/ Chad L. Stephens
Date		Chad L. Stephens, President,
		Chief Executive Officer

~~February 8,~~May 6, 2021		/s/ Ralph D’Amico
Date		Ralph D’Amico, Vice President,
		Chief Financial Officer