UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

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

For the period ended  March 31, 2022

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

For the transition period from                      to                        

Commission File Number 001-31759

PHX MINERALS INC.

(Exact name of registrant as specified in its charter)

Delaware	73-1055775
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1601 NW Expressway, Suite 1100, Oklahoma City, Oklahoma  73118

(Address of principal executive offices)

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

Securities registered pursuant in Section 12(b) of the Act:

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§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.

Large accelerated filer   ☐   Accelerated filer   ☐   Non-accelerated filer   ☑   Smaller reporting company   ☑  

Emerging growth company     ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ☐    No  ☑

Outstanding shares of Common Stock at May 3, 2022: 35,225,891 shares.

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements		1
		Condensed Balance Sheets – March 31, 2022, and September 30, 2021		1
		Condensed Statements of Operations – Three and six months ended March 31, 2022 and 2021		2
		Statements of Stockholders’ Equity – Six months ended March 31, 2022 and 2021		3
		Condensed Statements of Cash Flows – Six months ended March 31, 2022 and 2021		4
		Notes to Condensed Financial Statements		5
	Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations		15
	Item 3	Quantitative and Qualitative Disclosures about Market Risk		25
	Item 4	Controls and Procedures		26
Part II	Other Information
	Item 1	Legal Proceedings		26
	Item 1A	Risk Factors		27
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		27
	Item 6	Exhibits		27
	Signatures		28

Special Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (“Form 10-Q”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, 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, 2021 (“Annual Report”), and all quarterly reports on Form 10-Q filed subsequently thereto, including the risks described in Item 1A of this Form 10-Q. Investors should also read the other information in this Form 10-Q and the Annual Report where risk factors are presented and further discussed.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date of which such statement is made, and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as 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.

Glossary of Certain Terms

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

ASC	Accounting Standards Codification.
ASU	Accounting Standards Update.
Bbl	Barrel.
Board	Board of directors of the Company.
BTU	British Thermal Units.
Common Stock	Common Stock, par value $0.01666 per share, of the Company.
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.
FASB	The Financial Accounting Standards Board.
field	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
G&A	General and administrative costs.
GAAP	United States generally accepted accounting principles.
Independent Consulting Petroleum Engineer(s)	DeGolyer and MacNaughton for the 2021 fiscal year and Cawley, Gillespie & Associates beginning in fiscal year 2022.
LOE	Lease operating expense.
MCF	Thousand cubic feet.
MCFE	Natural gas stated on an MCF basis and crude oil and natural gas liquids converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil or natural gas liquids to six MCF of natural gas.
Mmbtu	Million BTU.
minerals, mineral acres or mineral interests	Fee mineral acreage owned in perpetuity by the Company.
NGL	Natural gas liquids.
NYMEX	New York Mercantile Exchange.
play	Term applied to identified areas with potential oil and/or natural gas reserves.
proved reserves	The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.
royalty interest	Well interests in which the Company does not pay a share of the costs to drill, complete and operate a well but receives a smaller proportionate share (as compared to a working interest) of production.
SEC	The United States Securities and Exchange Commission.
undeveloped acreage	Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
working interest	Well interests in which the Company pays a share of the costs to drill, complete and operate a well and receives a proportionate share of production.
WTI	West Texas Intermediate.

Fiscal year references

All references to years in this Form 10-Q, unless otherwise noted, refer to the Company’s fiscal year ended September 30. For example, references to 2022 mean the fiscal year ending September 30, 2022.

Fiscal quarter references

All references to quarters in this Form 10-Q, unless otherwise noted, refer to the Company’s fiscal quarter based on a fiscal year end of September 30. For example, references to first quarter mean the quarter of October 1 through December 31. Unless otherwise noted, general references to a quarter refer to the quarterly period ended March 31. For example, the 2022 quarter refers to the quarterly period ended March 31, 2022 and the 2021 quarter refers to the quarterly period ended March 31, 2021.

Fiscal six-month period references

All references to six-month periods in this Form 10-Q, unless otherwise noted, refer to the Company’s fiscal six-month period based on a fiscal year end of September 30. Unless otherwise noted, general references to a period in sections of this Form 10-Q discussing six-month periods refer to the six-month period ended March 31. For example, in sections of this Form 10-Q discussing six-month periods, the 2022 period refers to the six-month period ended March 31, 2022 and the 2021 period refers to the six-month period ended March 31, 2021.

References to natural gas and oil properties

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

PART I FINANCIAL INFORMATION

ITEM 1 CONDENSED FINANCIAL STATEMENTS

PHX MINERALS INC.

CONDENSED BALANCE SHEETS

	March 31, 2022			September 30, 2021
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	1,703,675		$	2,438,511
Natural gas, oil, and NGL sales receivables (net of $0 allowance for uncollectable accounts)		9,451,366			6,428,982
Refundable income taxes		-			2,413,942
Other		1,188,312			942,082
Total current assets		12,343,353			12,223,517
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		264,135,242			319,984,874
Non-producing natural gas and oil properties		48,878,130			40,466,098
Other		844,582			794,179
		313,857,954			361,245,151
Less accumulated depreciation, depletion and amortization		(196,960,903	)		(257,643,661	)
Net properties and equipment		116,897,051			103,601,490
Operating lease right-of-use assets		564,034			607,414
Other, net		537,199			578,593
Total assets	$	130,341,637		$	117,011,014
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	602,415		$	772,717
Derivative contracts, net		14,793,396			12,087,988
Income taxes payable		253,733			334,050
Current portion of operating lease liability		134,955			132,287
Accrued liabilities and other		1,506,836			1,809,337
Total current liabilities		17,291,335			15,136,379
Long-term debt		24,000,000			17,500,000
Deferred income taxes, net		370,906			343,906
Asset retirement obligations		2,178,023			2,836,172
Derivative contracts, net		1,031,639			1,696,479
Operating lease liability, net of current portion		721,188			789,339
Total liabilities		45,593,091			38,302,275
Stockholders' equity:
Common Stock, $0.01666 par value; 54,000,500 shares authorized and   34,469,449 issued at March 31, 2022; 36,000,500 shares authorized and 32,770,433 issued at September 30, 2021		574,261			545,956
Capital in excess of par value		37,596,944			33,213,645
Deferred directors' compensation		1,407,423			1,768,151
Retained earnings		50,778,525			48,966,420
		90,357,153			84,494,172
Less treasury stock, at cost; 377,232 shares at March 31, 2022, and 388,545 shares    at September 30, 2021		(5,608,607	)		(5,785,433	)
Total stockholders' equity		84,748,546			78,708,739
Total liabilities and stockholders' equity	$	130,341,637		$	117,011,014

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

(1)

PHX MINERALS INC.

CONDENSED STATEMENTS OF OPERATIONS

	Three Months Ended March 31,						Six Months Ended March 31,
	2022			2021			2022			2021
Revenues:	(unaudited)						(unaudited)
Natural gas, oil and NGL sales	$	14,783,865		$	8,345,825		$	28,471,029		$	14,770,804
Lease bonuses and rental income		161,908			58,554			240,823			59,987
Gains (losses) on derivative contracts		(12,983,406	)		(2,348,143	)		(10,147,238	)		(2,602,179	)
	$	1,962,367		$	6,056,236			18,564,614		$	12,228,612
Costs and expenses:
Lease operating expenses		929,454			1,030,651			2,185,465			2,035,063
Transportation, gathering and marketing		1,488,518			1,319,514			2,702,122			2,600,479
Production taxes		697,393			443,154			1,376,340			719,180
Depreciation, depletion and amortization		2,121,116			1,777,817			3,704,876			4,038,466
Provision for impairment		-			-			5,585			-
Interest expense		230,212			267,865			406,931			569,763
General and administrative		2,744,264			2,059,476			4,839,821			3,790,573
Losses (gains) on asset sales and other		(2,261,135	)		(125,518	)		(113,320	)		(142,469	)
Total costs and expenses		5,949,822			6,772,959			15,107,820			13,611,055
Income (loss) before provision (benefit) for income taxes		(3,987,455	)		(716,723	)		3,456,794			(1,382,443	)
Provision (benefit) for income taxes		33,000			(217,000	)		795,000			(286,000	)
Net income (loss)	$	(4,020,455	)	$	(499,723	)	$	2,661,794		$	(1,096,443	)
Basic and diluted earnings (loss) per common share (Note 4)	$	(0.12	)	$	(0.02	)	$	0.08		$	(0.05	)
Basic and diluted weighted average shares outstanding:
Common shares		34,056,316			22,429,777			33,449,594			22,403,678
Unissued, directors' deferred compensation shares		236,139			178,597			234,091			177,923
		34,292,455			22,608,374			33,683,685			22,581,601
Dividends per share of common stock paid in period	$	0.015		$	0.01		$	0.025		$	0.02
Dividends declared per share of
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.)

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PHX MINERALS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Six Months Ended March 31, 2022

					Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total
Balances at September 30, 2021		32,770,433	$	545,956	$	33,213,645		$	1,768,151		$	48,966,420			(388,545	)	$	(5,785,433	)	$	78,708,739
Net income (loss)		-		-		-			-			6,682,249									6,682,249
Equity issued to acquire assets		1,519,481		25,315		3,460,988			-			-			-			-			3,486,303
At-the-market offering fees						(10,730	)														(10,730	)
Purchase of treasury stock		-		-		-			-			-			(700	)		(1,855	)		(1,855	)
Restricted stock awards		-		-		255,844			-			-			-			-			255,844
Dividends ($0.025 per share)		-		-		-			-			(849,689	)		-			-			(849,689	)
Distribution of restricted stock    to officers and directors		115,373		1,921		(178,481	)		-			-			12,013			178,681			2,121
Increase in deferred directors'    compensation charged to    expense		-		-		-			67,570			-			-			-			67,570
Balances at December 31, 2021		34,405,287	$	573,192	$	36,741,266		$	1,835,721		$	54,798,980			(377,232	)	$	(5,608,607	)	$	88,340,552
(unaudited)
Net income (loss)		-		-		-			-			(4,020,455	)		-			-			(4,020,455	)
Cost of equity issuance		-		-		(48,166	)		-			-			-			-			(48,166	)
At-the-market offering		2,710		45		7,972			-			-			-			-			8,017
Restricted stock awards		-		-		433,137			-			-			-			-			433,137
Distribution of deferred    directors' compensation		61,452		1,024		462,735			(463,759	)		-			-			-			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			35,461			-			-			-			35,461
Balances at March 31, 2022		34,469,449	$	574,261	$	37,596,944		$	1,407,423		$	50,778,525			(377,232	)	$	(5,608,607	)	$	84,748,546
(unaudited)

Six Months Ended March 31, 2021

					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 issued to acquire assets		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	)
Cost of equity issuance		-		-		(29,240	)		-			-			-			-			(29,240	)
Restricted stock awards		-		-		161,170			-			-			-			-			161,170
Dividends ($0.01 per share)		-		-		-			-			(289,997	)		-			-			(289,997	)
Distribution of restricted stock    to officers and directors		-		-		-			-			-			(556	)		(1,268	)		(1,268	)
Distribution of deferred    directors' compensation		24,545		409		339,913			(340,322	)		-			-			-			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			55,727			-			-			-			55,727
Balances at March 31, 2021		22,825,226	$	380,268	$	11,150,749		$	1,633,939		$	54,402,724			(390,823	)	$	(5,835,125	)	$	61,732,555
(unaudited)

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

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PHX MINERALS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Six Months Ended March 31,
	2022			2021
Operating Activities	(unaudited)
Net income (loss)	$	2,661,794		$	(1,096,443	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		3,704,876			4,038,466
Impairment of producing properties		5,585			-
Provision for deferred income taxes		27,000			(288,000	)
Gain from leasing fee mineral acreage		(239,751	)		(57,493	)
Proceeds from leasing fee mineral acreage		328,783			64,047
Net (gain) loss on sales of assets		(171,285	)		(62,097	)
Directors' deferred compensation expense		103,031			100,254
Total (gain) loss on derivative contracts		10,147,238			2,602,179
Cash receipts (payments) on settled derivative contracts		(176,510	)		315,883
Restricted stock awards		688,981			284,148
Other		28,483			31,544
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables		(3,022,384	)		(1,732,801	)
Other current assets		(205,489	)		(388,864	)
Accounts payable		(91,587	)		(340,404	)
Income taxes receivable		2,413,942			1,356,356
Other non-current assets		64,975			56,545
Income taxes payable		(80,317	)		-
Accrued liabilities		(253,045	)		(206,213	)
Total adjustments		13,272,526			5,773,550
Net cash provided by operating activities		15,934,320			4,677,107
Investing Activities
Capital expenditures		(279,348	)		(425,098	)
Acquisition of minerals and overriding royalty interests		(20,918,274	)		(7,934,504	)
Net proceeds from sales of assets		6,880,972			21,000
Net cash provided (used) by investing activities		(14,316,650	)		(8,338,602	)
Financing Activities
Borrowings under Credit Facility		10,000,000			-
Payments of loan principal		(3,500,000	)		(5,250,000	)
Net cost of equity issuance		(72,657	)		(53,482	)
Cash receipts from (payments on) off-market derivative contracts		(7,930,160	)		-
Payments of dividends		(849,689	)		(454,936	)
Net cash provided (used) by financing activities		(2,352,506	)		(5,758,418	)
Increase (decrease) in cash and cash equivalents		(734,836	)		(9,419,913	)
Cash and cash equivalents at beginning of period		2,438,511			10,690,395
Cash and cash equivalents at end of period	$	1,703,675		$	1,270,482
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid	$	-		$	289,997
Gross additions to properties and equipment	$	24,522,684		$	8,759,616
Value of shares used for acquisitions		(3,510,001	)		(250,000	)
Net (increase) decrease in accounts payable for properties and equipment additions		184,939			(150,014	)
Capital expenditures and acquisitions	$	21,197,622		$	8,359,602

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

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PHX MINERALS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Basis of Presentation and Accounting Principles

Basis of Presentation

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

Recent Accounting Pronouncements

Standard	Description	Date of Adoption	Impact on Financial Statements or Other Significant Matters
Adoption of New Accounting Pronouncements
ASU 2019-12, Simplifying the Accounting for Income Taxes.	This standard is intended to clarify and simplify the accounting for income taxes by removing certain exceptions and amending existing guidance.	Q1 2022	The adoption of this update did not have a material impact on the Company's financial statements and related disclosures.

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.

NOTE 2: Revenues

Lease bonus revenue

The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932 (Extractive Activities—Oil and Gas), and upon leasing, it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral interests being treated as a gain. The excess of lease bonus above the mineral interests basis is shown in the lease bonuses and rental income line item on the Company’s Statements of Operations.

Natural gas and oil derivative contracts

See Note 9 for discussion of the Company’s accounting for derivative contracts.

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Revenues from contracts with customers

Natural gas, oil and NGL sales

Sales of natural gas, oil and NGL are recognized when production is sold to a purchaser and control of the product has been transferred. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation; however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate.

Disaggregation of natural gas, oil and NGL revenues

The following table presents the disaggregation of the Company's natural gas, oil and NGL revenues for the three and six months ended March 31, 2022 and 2021:

	Three Months Ended March 31, 2022						Six Months Ended March 31, 2022
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	5,621,024	$	2,914,969	$	8,535,993	$	10,821,891	$	6,404,138	$	17,226,029
Oil revenue		2,550,462		2,161,244		4,711,706		4,444,489		3,843,321		8,287,810
NGL revenue		707,508		828,658		1,536,166		1,333,131		1,624,059		2,957,190
Natural gas, oil and NGL sales	$	8,878,994	$	5,904,871	$	14,783,865	$	16,599,511	$	11,871,518	$	28,471,029
	Three Months Ended March 31, 2021						Six Months Ended March 31, 2021
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	2,366,427	$	2,006,670	$	4,373,097	$	3,556,592	$	4,275,306	$	7,831,898
Oil revenue		1,717,069		1,427,852		3,144,921		2,814,021		2,671,966		5,485,987
NGL revenue		410,851		416,956		827,807		641,189		811,730		1,452,919
Natural gas, oil and NGL sales	$	4,494,347	$	3,851,478	$	8,345,825	$	7,011,802	$	7,759,002	$	14,770,804

Prior-period performance obligations and contract balances

The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into the timing of when new wells start producing, and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the 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 March 31, 2022, revenue recognized during the reporting period 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 it. Through cash received on new wells, in the 2022 and 2021 second quarters, the Company identified several producing properties on its minerals that had production dates prior to the 2022 and 2021 second quarters. 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 for the three months ended March 31, 2022, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $592,758, of which $156,169 related to the production periods before October 1, 2021 and $436,589 related to the first fiscal quarter of fiscal 2022.

(6)

In connection with obtaining more relevant information on new wells on Company acreage for the three months ended March 31, 2021, the Company 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.

NOTE 3: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from excess federal and Oklahoma percentage depletion, which are permanent tax benefits, and the change in valuation allowance from prior year. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that exceeds cost depletion, which is calculated on a unit-of-production basis. The Company completes an evaluation of the expected realization of the Company’s gross deferred tax assets each quarter. Excess tax benefits and deficiencies of stock-based compensation are recognized as provision (benefit) for income taxes in the Company’s Statements of Operations.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with detailed well-by-well calculations at fiscal year-end. Depending upon whether a provision for income taxes or a benefit for income taxes is expected for a year, federal and Oklahoma excess percentage depletion will either decrease or increase the effective tax rate, respectively. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant.

As of March 31, 2022, the Company completed an evaluation of the expected realization of its gross deferred tax assets. As a result of its evaluation, the Company concluded a valuation allowance is required and for the six months ended March 31, 2022, the net impact of the change in the Company’s valuation allowance against its deferred tax assets from September 30, 2021 is an increase of $42,000 recorded in the income tax provision. The Company’s effective tax rate for the six months ended March 31, 2022 was a 23% provision as compared to a 21% benefit for the six months ended March 31, 2021.

The federal Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 Net Operating Losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the limitation on interest expense deductibility under Section 163(j) of the Internal Revenue Code (“IRC”), from 30% to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. On July 28, 2020, final regulations were issued under Section 163(j) of the IRC, which modified the calculation under the previous proposed regulations of adjusted taxable income for purposes of the 50% limitation on interest expense. Under the final regulations, depreciation, amortization, and depletion capitalizable under Section 263A of the IRC is added back to tentative taxable income.  This change allowed all interest expense to be deductible for 2020 and reduced the associated deferred tax asset to zero. During the quarter ended March 31, 2021, the Company received a tax refund totaling $1.4 million associated with the alternative minimum tax (AMT) credits, which was accelerated by the CARES Act. During the quarter ended December 31, 2021, the Company received $2.2 million associated with the carryback of the Company’s 2020 federal net operating loss.

NOTE 4: Basic and Diluted Earnings (Loss) Per Common Share (“EPS”)

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

For the three and six months ended March 31, 2022, the Company did not include restricted stock in the diluted EPS calculation because the effect would have been antidilutive. The average shares outstanding of restricted stock excluded from the diluted EPS was 161,295 and 116,768, respectively, for the three and six months ended March 31, 2022, and 375,004 and 228,333, respectively, for the three and six months ended March 31, 2021.

(7)

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

	Three Months Ended March 31,						Six Months Ended March 31,
	2022			2021			2022		2021
Basic EPS
Numerator:
Basic net income (loss)	$	(4,020,455	)	$	(499,723	)	$	2,661,794	$	(1,096,443	)
Denominator:
Basic weighted average shares outstanding		34,292,455			22,608,374			33,683,685		22,581,601
Basic EPS	$	(0.12	)	$	(0.02	)	$	0.08	$	(0.05	)
Diluted EPS
Numerator:
Basic net income (loss)	$	(4,020,455	)	$	(499,723	)	$	2,661,794	$	(1,096,443	)
Diluted net income (loss)		(4,020,455	)		(499,723	)		2,661,794		(1,096,443	)
Denominator:
Basic weighted average shares outstanding		34,292,455			22,608,374			33,683,685		22,581,601
Effects of dilutive securities:
Unvested restricted stock		-			-			-		-
Diluted weighted average shares outstanding		34,292,455			22,608,374			33,683,685		22,581,601
Diluted EPS	$	(0.12	)	$	(0.02	)	$	0.08	$	(0.05	)

NOTE 5: Long-Term Debt

The Company has a $100,000,000 credit facility (the “Credit Facility”) with a syndicate of banks led by Independent Bank pursuant to a credit agreement entered into in September 2021 (as amended, the “Credit Agreement”). The Credit Facility has a borrowing base of $32,000,000 as of March 31, 2022, and a maturity date of September 1, 2025. The Credit Facility is secured by the Company’s personal property and at least 80% of the total value of the proved, developed and producing oil and gas properties. The interest rate is based on either (a) LIBOR plus an applicable margin ranging from 2.750% to 3.750% per annum based on the Company’s Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the U.S. Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on the Company’s Borrowing Base Utilization. The election of Independent Bank prime or LIBOR is at the Company’s discretion. The interest rate spread from Independent Bank prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At March 31, 2022, the effective interest rate was 3.82%.

The Company’s debt is recorded at the carrying amount on its balance sheets. The carrying amount of the debt under the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in “Other, net” on the Company’s balance sheets. Total debt issuance cost, net of amortization, as of March 31, 2022 was $267,798. The debt issuance cost is amortized over the life of the Credit Facility.

Determinations of the borrowing base under the Credit Facility are made semi-annually (usually June and December) or whenever the lending banks, in their sole discretion, believe that there has been a material change in the value of the Company’s natural gas and oil properties. The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain restrictions on the Company’s ability to incur debt, grant liens, make fundamental changes and engage in certain transactions with affiliates. The Credit Facility also restricts the Company’s ability to make certain restricted payments if before or after the Restricted Payment (i) the Available Commitment is less than ten percent (10%) of the Borrowing Base or (ii) the Leverage Ratio on a pro forma basis is greater than 2.50 to 1.00. In addition, the Company is required to maintain certain financial ratios, a current ratio (as described in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to EBITDAX (as defined in the Credit Facility) of no more than 3.5 to 1.0 based on the trailing twelve months. At March 31, 2022, the Company was in compliance with the covenants of the Credit Facility, had $24,000,000 in outstanding borrowings and had $8,000,000 available for borrowing under the Credit Facility. All capitalized terms in this description of the Credit Facility that are not otherwise defined in this Form 10-Q shall have the meaning assigned to them in the Credit Agreement.

(8)

NOTE 6: Deferred Compensation Plan for Non-Employee Directors

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

NOTE 7: Restricted Stock Plan

On March 2, 2022, the Company awarded shares of common stock in the form of time-based and market-based restricted stock to the directors, employees and officers of the Company.  Non-employee directors received 138,249 time-based shares with a fair value on the award date of $387,095. These shares vest in December of 2022.  Officers were awarded 402,086 market-based shares with a fair value on their award date of $1,679,757. Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 126,013 time-based shares with a fair value on the award date of $352,838.  The shares issued to employees time-vest ratably over a three-year period ending in December of 2024, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December of 2024.  All shares awarded on March 2, 2022 have voting rights during the vesting period.

Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur. The following table summarizes the Company’s pre-tax compensation expense for the three and six months ended March 31, 2022 and 2021 related to the Company’s market-based, time-based and performance-based restricted stock:

	Three Months Ended				Six Months Ended
	March 31,				March 31,
	2022		2021		2022		2021
Market-based, restricted stock	$	313,872	$	79,118	$	391,354	$	89,365
Time-based, restricted stock		119,265		82,052		297,627		194,783
Performance-based, restricted stock		-		-		-		-
Total compensation expense	$	433,137	$	161,170	$	688,981	$	284,148

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

	As of March 31, 2022
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	1,934,912		1.71
Time-based, restricted stock		815,269		1.54
Performance-based, restricted stock		-
Total	$	2,750,181

NOTE 8: Properties and Equipment

Properties and equipment and related accumulated DD&A as of March 31, 2022 and September 30, 2021 are as follows:

	March 31, 2022			September 30, 2021
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties	$	264,135,242		$	319,984,874
Non-producing natural gas and oil properties		48,878,130			40,466,098
Other property and equipment		844,582			794,179
		313,857,954			361,245,151
Less accumulated depreciation, depletion and amortization		(196,960,903	)		(257,643,661	)
Net properties and equipment	$	116,897,051		$	103,601,490

(9)

Acquisitions

The Company made the following property acquisitions during the six-month periods ended March 31, 2022 and 2021.

Quarter Ended (4)	Net royalty acres (1)(2)		Cash	Number of shares (3)		Total Purchase Price (1)	Area of Interest
March 31, 2022
		58	$0.5 million	-		$0.5 million	SCOOP / OK
		500	$6.4 million	-		$6.4 million	Haynesville / LA
		68	$0.7 million	-		$0.7 million	Haynesville / TX
		166	$1.3 million	-		$1.3 million	SCOOP / OK
		33	$0.4 million	-		$0.4 million	Haynesville / TX
December 31, 2021
		426	$5.8 million	-		$5.8 million	Haynesville / LA
		847	$0.6 million		1,519,481	$4.1 million	Haynesville / LA
		172	$1.4 million	-		$1.4 million	SCOOP / OK
		103	$0.6 million	-		$0.6 million	Haynesville / TX
		116	$1.7 million	-		$1.7 million	Haynesville / LA
		220	$1.2 million	-		$1.2 million	SCOOP / OK
March 31, 2021
	No significant acquisitions
December 31, 2020
		142	$1.0 million	-		$1.0 million	Haynesville / TX
		184	$0.8 million	-		$0.8 million	Haynesville / TX
		386	$3.5 million	-		$3.5 million	Haynesville / TX
		297	$2.0 million		153,375	$2.3 million	SCOOP / OK
(1) Excludes subsequent closing adjustments and insignificant acquisitions.
(2) An estimated net royalty equivalent was used for the minerals included in the net royalty acres.
(3) The Company’s policy is to classify all costs associated with equity issuances as financial costs in the Statements of Cash Flows.
(4) Presented in chronological order with most recent at top.

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

Divestitures

The Company made the following property divestitures during the six-month periods ended March 31, 2022 and 2021.

Quarter Ended	Net mineral acres(1)/ Wellbores(2)	Sale Price	Gain/(Loss)	Location
March 31, 2022
	7,071 acres	$1.6 million	$1.6 million	NM / TX
	130 acres	$0.5 million	$0.5 million	TX
December 31, 2021
	98 wellbores	$2.0 million	($3.5) million	OK
	95 wellbores	$0.5 million	$0.2 million	OK / TX
	499 wellbores	$2.1 million	$1.1 million	AR
March 31, 2021
	No significant divestitures
December 31, 2020
	No significant divestitures
(1) Number of net mineral acres sold.
(2) Number of wellbores associated with working interests sold.

(10)

Natural Gas, Oil and NGL Reserves

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

Impairment

Company management monitors all long-lived assets, principally natural gas and oil properties, for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates; future drilling and completion costs; future sales prices for natural gas, oil and NGL; future production costs; estimates of future natural gas, oil and NGL reserves to be recovered and the timing thereof; the economic and regulatory climates; and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to natural gas, oil and NGL reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For the three and six months ended March 31, 2022 and 2021, management’s assessment resulted in no impairment provisions on producing properties. The Company wrote off $5,585 on wells assigned with zero consideration received during the six months ended March 31, 2022.

NOTE 9: Derivatives

The Company has entered into commodity price derivative agreements, including fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of 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 BP Energy Company (“BP”). The derivative contracts with BP are secured under the Credit Facility with Independent Bank (see Note 5: Long-Term Debt). The derivative instruments have settled or will settle based on the prices below:

Derivative contracts in place as of March 31, 2022

Fiscal Period	Contract total volume	Index	Contract average price
Natural gas costless collars
Remaining 2022	480,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.23 ceiling
2023	500,000 Mmbtu	NYMEX Henry Hub	$3.32 floor / $4.54 ceiling
2024	60,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $4.70 ceiling
Natural gas fixed price swaps
Remaining 2022	1,785,000 Mmbtu	NYMEX Henry Hub	$2.98
2023	2,100,000 Mmbtu	NYMEX Henry Hub	$3.24
2024	380,000 Mmbtu	NYMEX Henry Hub	$3.41
Oil fixed price swaps
Remaining 2022	76,500 Bbls	NYMEX WTI	$44.91
2023	66,750 Bbls	NYMEX WTI	$62.11
2024	11,250 Bbls	NYMEX WTI	$73.35

(11)

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 $15,825,035 as of March 31, 2022, and a net liability of $13,784,467 as of September 30, 2021. Cash receipts or payments in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods:

	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2022			2021			2022			2021
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	(152,190	)	$	(122	)	$	(152,190	)	$	(9,089	)
Natural gas fixed price swaps(1)		(474,935	)		3,105			(1,827,127	)		1,242
Oil costless collars		-			(112,590	)		-			(23,646	)
Oil fixed price swaps(1)		(583,641	)		(187,824	)		(945,781	)		347,376
Cash received (paid) on derivative contracts, net	$	(1,210,766	)	$	(297,431	)	$	(2,925,098	)	$	315,883
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(1,465,603	)	$	(81,881	)	$	(1,385,632	)	$	597,080
Natural gas fixed price swaps		(7,686,898	)		(6,291	)		(3,208,963	)		282,596
Oil costless collars		-			(696,360	)		-			(1,107,246	)
Oil fixed price swaps		(2,620,139	)		(1,266,180	)		(2,627,545	)		(2,690,492	)
Non-cash gain (loss) on derivative contracts, net	$	(11,772,640	)	$	(2,050,712	)	$	(7,222,140	)	$	(2,918,062	)
Gains (losses) on derivative contracts, net	$	(12,983,406	)	$	(2,348,143	)	$	(10,147,238	)	$	(2,602,179	)
(1) For the three and six months ended March 31, 2022, excludes $2,493,481 and $5,181,572, respectively, of cash paid to settle off-market derivative contracts that are not reflected on the Condensed Statements of Operations. Total cash paid related to off-market derivatives was $7,930,160 for the six months ended March 31, 2022 and is reflected in the Financing Activities section of the Condensed Statements of Cash Flows.

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 March 31, 2022 and September 30, 2021. The Company has offset all amounts subject to master netting agreements in the Company's balance sheets at March 31, 2022 and September 30, 2021.

	March 31, 2022												September 30, 2021
	Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets			Current Liabilities			Non-Current Liabilities
Gross amounts recognized	$	60,347		$	14,853,743		$	31,174		$	1,062,813		$	17,395		$	12,105,383		$	1,696,479
Offsetting adjustments		(60,347	)		(60,347	)		(31,174	)		(31,174	)		(17,395	)		(17,395	)		-
Net presentation on condensed balance sheets	$	-		$	14,793,396		$	-		$	1,031,639		$	-		$	12,087,988		$	1,696,479

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

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

(12)

NOTE 10: Fair Value Measurements

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis at March 31, 2022:

	Fair Value Measurement at March 31, 2022
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)			(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(14,439,403	)	$	-	$	(14,439,403	)
Derivative Contracts - Collars	$	-	$	(1,385,632	)	$	-	$	(1,385,632	)

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.

At March 31, 2022 and September 30, 2021, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments. Financial instruments include long-term debt, the valuation of which is classified as Level 2 as the carrying amount of the Company’s debt under the Credit Facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

NOTE 11: Commitments and Contingencies

Litigation

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.

(13)

NOTE 12: Subsequent Events

Derivative Contracts

Subsequent to March 31, 2022, the Company entered into new derivative contracts as summarized in the table below:

	Contract
Contract period	total volume	Index	Contract price
Natural gas costless collars
January 2023 - March 2023	180,000 Mmbtu	NYMEX Henry Hub	$6.00 floor / $13.00 ceiling
July 2022 - March 2023	315,000 Mmbtu	NYMEX Henry Hub	$6.00 floor / $12.40 ceiling
Oil costless collars
January 2023 - June 2023	15,000 Bbls	NYMEX WTI	$75.00 floor / $96.00 ceiling

Borrowings

Subsequent to March 31, 2022, the Company borrowed $4.3 million under its Credit Facility to fund the acquisition expected to close by the end of May discussed below.  

Acquisitions

Subsequent to March 31, 2022, the Company closed on an additional acquisition of 185 net royalty acres located in the SCOOP play of Oklahoma and the Haynesville play of Louisiana for approximately $1.5 million in cash, and the Company has an additional 983 net royalty acres pending acquisition and under purchase and sale agreements, which are expected to close by the end of May 2022 for approximately $9.4 million in cash.    

(14)

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

BUSINESS OVERVIEW

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

We also currently own interests in leasehold acreage and non-operated working interests in natural gas and oil properties. Exploration and development of our natural gas and oil properties is conducted by third-party natural gas and oil exploration and production companies (primarily larger independent operating companies). We do not operate any of our natural gas and oil properties. While we previously were an active working interest participant in wells drilled on our mineral and leasehold acreage, our current focus is on growth through mineral acquisitions in our core areas of focus in the SCOOP and Haynesville and development of our significant mineral acreage inventory. We have ceased taking working interest positions on our mineral and leasehold acreage and do not plan to take any working interest positions going forward.

RESULTS OF OPERATIONS

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

THREE MONTHS ENDED MARCH 31, 2022 COMPARED TO THREE MONTHS ENDED MARCH 31, 2021

Overview:

We recorded a second quarter 2022 net loss of $4,020,455, or $0.12 per share, as compared to a net loss of $499,723, or $0.02 per share, in the second fiscal 2021 quarter. The change in net loss was principally the result of increased unrealized losses associated with our hedge contracts, offset by increased natural gas, oil and NGL sales and gains on asset sales. These items are further discussed below.

Revenue:

Natural Gas, Oil and NGL Sales:

	For the Three Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	14,783,865	$	8,345,825	77%

For the three months ended March 31, 2022, the increase in natural gas, oil and NGL sales was primarily due to increases in natural gas, oil and NGL prices of 77%, 63% and 71%, respectively, and an increase in natural gas and NGL volumes of 10% and 8%, respectively, partially offset by a decrease in oil volumes of 8%. The following table outlines our production and average sales prices for natural gas, oil and NGL for the three-month periods of fiscal 2022 and 2021:

	MCF		Average		Oil Bbls		Average		NGL Bbls		Average		MCFE		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
3/31/2022		1,908,030	$	4.47		51,631	$	91.26		40,371	$	38.05		2,460,042	$	6.01
3/31/2021		1,735,820	$	2.52		56,269	$	55.89		37,228	$	22.24		2,296,802	$	3.63

(15)

The production increase in royalty volumes during the three months ended March 31, 2022, as compared to the three months ended March 31, 2021, resulted from acquired wells in the Haynesville Shale and SCOOP plays coming online.  The decrease in working interest volumes resulted from naturally declining production in high-interest wells in the Arkoma Stack and the divestiture of low-value legacy working interests in Oklahoma.

Total production for the last five quarters was as follows:

Quarter ended	MCF Sold		Oil Bbls Sold		NGL Bbls Sold		MCFE Sold
3/31/2022		1,908,030		51,631		40,371		2,460,042
12/31/2021		1,574,265		48,074		44,256		2,128,248
9/30/2021		1,609,101		54,043		46,369		2,211,570
6/30/2021		1,879,343		55,492		46,753		2,492,813
3/31/2021		1,735,820		56,269		37,228		2,296,802

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

Quarter ended	MCF Sold		Oil Bbls Sold		NGL Bbls Sold		MCFE Sold
3/31/2022		1,261,949		28,758		18,852		1,547,609
12/31/2021		949,523		25,996		19,953		1,225,220
9/30/2021		705,397		29,442		19,364		998,230
6/30/2021		908,471		31,095		18,255		1,204,571
3/31/2021		924,969		31,768		19,088		1,230,105

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

Quarter ended	MCF Sold		Oil Bbls Sold		NGL Bbls Sold		MCFE Sold
3/31/2022		646,081		22,873		21,519		912,433
12/31/2021		624,742		22,078		24,303		903,028
9/30/2021		903,704		24,601		27,005		1,213,340
6/30/2021		970,872		24,397		28,498		1,288,242
3/31/2021		810,851		24,501		18,140		1,066,697

Lease Bonuses and Rental Income:

	For the Three Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Lease bonuses and rental income	$	161,908	$	58,554	177%

When we lease our mineral interests, we generally receive an upfront cash payment, or lease bonus. Lease bonuses and rental income increased $103,354 in the 2022 quarter compared to the 2021 quarter primarily as the result of increased leasing activity in the 2022 quarter.

(16)

Gains (Losses) on Derivative Contracts:

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period. The net gain (loss) on derivative instruments for the periods indicated includes the following:

	For the Three Months Ended March 31,
							Percent
	2022			2021			Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net(1)	$	(1,210,766	)	$	(297,431	)	(307%)
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(11,772,640	)	$	(2,050,712	)	(474%)
Gains (losses) on derivative contracts, net	$	(12,983,406	)	$	(2,348,143	)	(453%)
	As of March 31,
	2022			2021
Fair value of derivative contracts
Net asset (net liability)	$	(15,825,035	)	$	(3,625,709	)	(336%)
(1) Excludes $2,493,481 of cash paid to settle off-market derivative contracts that are not reflected on the Condensed Statements of Operations for the quarter ended March 31, 2022.

The change in net (loss) gain on derivative contracts was due to the natural gas and oil collars and fixed price swaps being less beneficial in the quarter ended March 31, 2022 in relation to their respective contracted volumes and prices.

Our natural gas and oil costless collar contracts and fixed price swaps in place at March 31, 2022 had expiration dates through December 2023. We utilize derivative contracts for the purpose of protecting our cash flow and return on investments.

Costs and Expenses:

Lease Operating Expenses (LOE):

	For the Three Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Lease operating expenses	$	929,454	$	1,030,651	(10%)
Lease operating expenses per working interest MCFE	$	1.02	$	0.97	5%
Lease operating expenses per total MCFE	$	0.38	$	0.45	(16%)

We are responsible for a portion of LOE relating to a well as a working interest owner. LOE includes normal recurring and nonrecurring expenses associated with our working interests necessary to produce hydrocarbons from our natural gas and oil wells, including maintenance, repairs, salt water disposal, insurance and workover expenses. Total LOE related to field operating costs decreased $101,197, or 10%, in the 2022 quarter compared to the 2021 quarter. The decrease in LOE was principally the result of the divestiture of higher LOE working interest properties, partially offset by cost inflation associated with field operating activities.

Transportation, Gathering and Marketing:

	For the Three Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Transportation, gathering and marketing	$	1,488,518	$	1,319,514	13%
Transportation, gathering and marketing per MCFE	$	0.61	$	0.57	7%

Transportation, gathering and marketing costs increased $169,004, or 13%, in the 2022 quarter compared to the 2021 quarter. This increase in costs was primarily driven by higher production in the 2022 quarter compared to the 2021 quarter. The increase in transportation, gathering and marketing costs per MCFE was primarily due to the increase in natural gas sales in Arkansas, which has higher transportation, gathering and marketing costs in relation to other regions.

(17)

Production Taxes:

	For the Three Months Ended March 31,
							Percent
	2022			2021			Incr. or (Decr.)
Production taxes	$	697,393		$	443,154		57%
Production taxes as % of sales		4.7	%		5.3	%	(11%)

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 $254,239, or 57%, in the 2022 quarter as compared to the 2021 quarter. The increase in amount was primarily the result of increased natural gas, oil and NGL sales of $6,438,040 and increases in sales volumes from states with higher tax rates in the 2022 quarter as compared to the 2021 quarter.

Depreciation, Depletion and Amortization (DD&A):

	For the Three Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Depreciation, depletion and amortization	$	2,121,116	$	1,777,817	19%
Depreciation, depletion and amortization per MCFE	$	0.86	$	0.77	12%

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 increased $343,299, or 19%, in the 2022 quarter compared to the 2021 quarter, of which $217,604 of the increase resulted from a $0.09 increase in the DD&A rate per MCFE and $125,695 of such increase resulted from production increasing 7% in the 2022 quarter. In addition to the increase in production, there was a large transfer of non-producing minerals, which are amortized over 33 years, to producing minerals, which are amortized over 20 years, in the 2022 quarter.

Provision for Impairment:

We had no provision for impairment in the 2022 and 2021 quarters.

Interest expense:

	For the Three Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Interest expense	$	230,212	$	267,865	(14%)
Weighted average debt outstanding	$	22,466,667	$	25,705,556	(13%)

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

Income Tax Expense:

	For the Three Months Ended March 31,
						Percent
	2022		2021			Incr. or (Decr.)
Provision (benefit) for income taxes	$	33,000	$	(217,000	)	115%

Income taxes changed $250,000, from a $217,000 benefit in the 2021 quarter to a $33,000 provision in the 2022 quarter. The change in income taxes resulted primarily from an increase in projected income for fiscal year 2022 compared to fiscal year 2021.

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.

(18)

General and Administrative Costs (G&A):

	For the Three Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
General and administrative	$	2,744,264	$	2,059,476	33%

G&A are costs not directly associated with the production of natural gas and oil and include the cost of employee salaries and related benefits, office expenses and fees for professional services. G&A for the 2022 quarter increased $684,788 as compared to the 2021 quarter. The increase was primarily due to legal expenses associated with reincorporating in the state of Delaware, increased transaction activity and restricted stock expense during the 2022 quarter.

Losses (Gains) on Asset Sales and Other:

	For the Three Months Ended March 31,
							Percent
	2022			2021			Incr. or (Decr.)
Losses (gains) on asset sales and other	$	(2,261,135	)	$	(125,518	)	1,701%

The increase in gains on asset sales and other is primarily related to divestitures during the 2022 quarter.

SIX MONTHS ENDED MARCH 31, 2022 COMPARED TO SIX MONTHS ENDED MARCH 31, 2021

Overview:

We recorded a six-month net income of $2,661,794, or $0.08 per share, for the 2022 period, as compared to a net loss of $1,096,443, or $0.05 per share, in the 2021 period. The change in net income (loss) was principally the result of increased natural gas, oil and NGL sales and lease bonuses and rental income, and decreased DD&A and interest expense, partially offset by an increase in losses on derivative contracts, LOE, transportation, gathering and marketing expenses, production taxes and a reduction in income tax benefit. These items are further discussed below.

Revenue:

Natural Gas, Oil and NGL Sales:

	For the Six Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	28,471,029	$	14,770,804	93%

The increase in natural gas, oil and NGL sales was primarily due to increases in natural gas, oil and NGL prices of 103%, 74% and 88%, respectively, and an increase in natural gas and NGL volumes of 8% and 8%, respectively, partially offset by a decrease in oil volumes of 13%. The following table outlines our production and average sales prices for natural gas, oil and NGL for the six-month periods of fiscal 2022 and 2021:

	MCF		Average		Oil Bbls		Average		NGL Bbls		Average		MCFE		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Six months ended
3/31/2022		3,482,295	$	4.95		99,705	$	83.12		84,627	$	34.94		4,588,290	$	6.21
3/31/2021		3,211,276	$	2.44		114,945	$	47.73		78,365	$	18.54		4,371,139	$	3.38

(19)

Natural gas volumes increased during the six months ended March 31, 2022, as compared to the six months ended March 31, 2021, primarily as a result of new wells associated with recent acquisitions in the Haynesville Shale and SCOOP plays coming online. These gas volumes were partially offset by naturally declining production in high-interest wells in the Arkoma Stack and divestitures in the Fayetteville.  NGL production also increased as a result of new wells brought online in the SCOOP, as well as increased production from liquids-rich gas wells in the Anadarko Granite Wash. The decrease in oil production was a result of naturally declining production in working interest wells in the Eagle Ford play and royalty wells in the Bakken play, due to our strategy of no longer participating with working interests in new drilling in the Eagle Ford, and reduced drilling activity in the Bakken, as well as naturally declining production in high-interest wells brought online in the STACK during fiscal year 2021. Oil production decreases were partially offset by new wells in the SCOOP.

Lease Bonuses and Rental Income:

	For the Six Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Lease bonuses and rental income	$	240,823	$	59,987	301%

When we lease our mineral interests, we generally receive an upfront cash payment, or lease bonus. Lease bonuses and rental income increased $180,836 in the 2022 period compared to the 2021 period primarily as the result of increased leasing activity in the 2022 period.

Gains (Losses) on Derivative Contracts:

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. Our gain (loss) on derivative contracts amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period. The net gain (loss) on derivative instruments for the periods indicated includes the following:

	For the Six Months Ended March 31,
							Percent
	2022			2021			Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net(1)	$	(2,925,098	)	$	315,883		(1,026%)
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(7,222,140	)	$	(2,918,062	)	(147%)
Gains (losses) on derivative contracts, net	$	(10,147,238	)	$	(2,602,179	)	290%
	As of March 31,
	2022			2021
Fair value of derivative contracts
Net asset (net liability)	$	(15,825,035	)	$	(3,625,709	)	(336%)
(1) Excludes $5,181,572 of cash paid to settle off-market derivative contracts that are not reflected on the Condensed Statements of Operations.

The change in net (loss) gain on derivative contracts was due to the natural gas and oil collars and fixed price swaps being less beneficial in the 2022 period in relation to their respective contracted volumes and prices at the beginning of the period.

Our natural gas and oil costless-collar contracts and fixed-price swaps in place at March 31, 2022 had expiration dates through December 2023. We utilize derivative contracts for the purpose of protecting our cash flow and return on investments.

(20)

Costs and Expenses:

Lease Operating Expenses (LOE):

	For the Six Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Lease operating expenses	$	2,185,465	$	2,035,063	7%
Lease operating expenses per working interest MCFE	$	1.20	$	0.85	42%
Lease operating expenses per MCFE	$	0.48	$	0.47	2%

We are responsible for a portion of LOE relating to a well as a working interest owner. LOE includes normal recurring and nonrecurring expenses associated with our working interests necessary to produce hydrocarbons from our natural gas and oil wells, including maintenance, repairs, salt water disposal, insurance and workover expenses. Total LOE related to field operating costs increased $150,402, or 7%, in the 2022 period compared to the 2021 period. The increase in LOE was principally the result of increased workover expenses and inflation on services in the 2022 period.

Transportation, Gathering and Marketing:

	For the Six Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Transportation, gathering and marketing	$	2,702,122	$	2,600,479	4%
Transportation, gathering and marketing per MCFE	$	0.59	$	0.59	—%

Transportation, gathering and marketing increased $101,643, or 4%, in the 2022 period compared to the 2021 period. This increase in costs was primarily driven by higher production in the 2022 period compared to the 2021 period.

Production Taxes:

	For the Six Months Ended March 31,
							Percent
	2022			2021			Incr. or (Decr.)
Production taxes	$	1,376,340		$	719,180		91%
Production taxes as % of sales		4.8	%		4.9	%	(2%)

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 $657,160, or 91%, in the 2022 period compared to the 2021 period. The increase was primarily the result of increased prices and production volumes in the 2022 period as compared to the 2021 period.

Depreciation, Depletion and Amortization (DD&A):

	For the Six Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Depreciation, depletion and amortization	$	3,704,876	$	4,038,466	(8%)
Depreciation, depletion and amortization per MCFE	$	0.81	$	0.92	(12%)

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 $333,590, or 8%, in the 2022 period compared to the 2021 period, of which $533,366 of the decrease resulted from a $0.11 decrease in the DD&A rate per MCFE, partially offset by an increase of $199,776 resulting from production increasing 5% in the 2022 period compared to the 2021 period. The DD&A rate per MCFE decrease was mainly due to an increase in reserves during the 2022 period compared to the 2021 period.

Provision for Impairment:

We had a $5,585 provision for impairment in the 2022 period as compared to no provision for impairment in the 2021 period. During the 2022 period, impairment was related to working interest wells in which we assigned our interests to the operator.

(21)

Interest expense:

	For the Six Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
Interest expense	$	406,931	$	569,763	(29%)
Weighted average debt outstanding	$	20,313,187	$	26,762,363	(24%)

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

Income Tax Expense:

	For the Six Months Ended March 31,
						Percent
	2022		2021			Incr. or (Decr.)
Provision (benefit) for income taxes	$	795,000	$	(286,000	)	378%

Income taxes changed $1,081,000, from a $286,000 benefit in the 2021 period to a $795,000 provision in the 2022 period. The change in income taxes resulted primarily from an increase in projected income for fiscal year 2022 compared to fiscal year 2021.

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.

General and Administrative Costs (G&A):

	For the Six Months Ended March 31,
					Percent
	2022		2021		Incr. or (Decr.)
General and administrative	$	4,839,821	$	3,790,573	28%

G&A are costs not directly associated with the production of natural gas and oil and include the cost of employee salaries and related benefits, office expenses and fees for professional services. G&A for the 2022 period increased $1,049,248 as compared to the 2021 period. The increase was primarily due to legal expenses associated with reincorporating in the state of Delaware, increased transaction activity and restricted stock expense during the 2022 period.

LIQUIDITY AND CAPITAL RESOURCES

We had positive working capital (current assets less current liabilities excluding current derivatives) of $9,845,414 at March 31, 2022, compared to positive working capital of $9,175,126 at September 30, 2021.

Liquidity:

Cash and cash equivalents were $1,703,675 as of March 31, 2022, compared to $2,438,511 at September 30, 2021, a decrease of $734,836. The decrease in cash is primarily associated with the closing of previously announced acquisitions, which were funded by cash on hand, cash from operating activities, borrowings under our Credit Facility and proceeds from the sale of assets. Cash flows for the six months ended March 31, 2022, and 2021 are summarized as follows:

Net cash provided (used) by:	For the Six Months Ended March 31,
	2022			2021			Change
Operating activities	$	15,934,320		$	4,677,107		$	11,257,213
Investing activities		(14,316,650	)		(8,338,602	)		(5,978,048	)
Financing activities		(2,352,506	)		(5,758,418	)		3,405,912
Increase (decrease) in cash and cash equivalents	$	(734,836	)	$	(9,419,913	)	$	8,685,077

(22)

Operating activities:

Net cash provided by operating activities increased $11,257,213 during the 2022 period, as compared to the 2021 period, primarily as the result of the following:

• receipts on natural gas, oil and NGL sales (net of production taxes and gathering, transportation and marketing costs) and other increasing by $11,765,691;

• increased income tax receipts of $211,330;

• decreased interest payments of $336,180;

• decreased field operating expenses of $127,647; and

• increased lease bonus receipts of $264,736;

partially offset by:

• increased payments for G&A and other expense of $955,978; and

• decreased net receipts from derivative contracts of $492,393.

Investing activities:

Net cash used by investing activities increased $5,978,048 during the 2022 period, as compared to the 2021 period, primarily due to higher acquisition costs of $12,983,770, partially offset by higher net proceeds from the sale of assets of $6,859,972 and lower payments of $145,750 for capital expenditures on legacy working interest wells during the 2022 period.

Financing activities:

Net cash used by financing activities decreased $3,405,912 during the 2022 period, as compared to the 2021 period, primarily due to higher net borrowings on long-term debt of $6,500,000 in the 2022 period compared to net payments of $5,250,000 in the 2021 period, partially offset by increased cash payments on off-market derivative contracts of $7,930,160 and an increase of $394,753 in dividend payments during the 2022 period.

Capital Resources:

We had no capital expenditures to drill and complete new wells in the 2022 and 2021 periods, as a result of our strategy to cease participating in new wells with a working interest after fiscal year 2019. We currently have no remaining commitments that would require significant capital to drill and complete wells.

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

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Over the past five quarters, we made the following property acquisitions:

Quarter Ended (4)	Net royalty acres (1)(2)		Cash	Number of shares (3)		Purchase Price (1)	Area of Interest
March 31, 2022
		58	$0.5 million	-		$0.5 million	SCOOP / OK
		500	$6.4 million	-		$6.4 million	Haynesville / LA
		68	$0.7 million	-		$0.7 million	Haynesville / TX
		166	$1.3 million	-		$1.3 million	SCOOP / OK
		33	$0.4 million	-		$0.4 million	Haynesville / TX
December 31, 2021
		426	$5.8 million	-		$5.8 million	Haynesville / LA
		847	$0.6 million		1,519,481	$4.1 million	Haynesville / LA
		172	$1.4 million	-		$1.4 million	SCOOP / OK
		103	$0.6 million	-		$0.6 million	Haynesville / TX
		116	$1.7 million	-		$1.7 million	Haynesville / LA
		220	$1.2 million	-		$1.2 million	SCOOP / OK
September 30, 2021
		817	$0.7 million		2,349,207	$7.3 million	Haynesville / LA, TX
June 30, 2021
		262	$1.3 million	-		$1.3 million	Haynesville / LA
		131	$1.0 million	-		$1.0 million	Haynesville / TX
		2,514	$9.5 million		1,200,000	$13.0 million	SCOOP / OK
March 31, 2021
	No significant acquisitions
(1) Excludes subsequent closing adjustments and insignificant acquisitions.
(2) An estimated net royalty equivalent was used for the minerals included in the net royalty acres.
(3) The Company’s policy is to classify all costs associated with equity issuances as financial costs in the Statements of Cash Flows.
(4) Presented in chronological order with most recent at top.

We received lease bonus payments during the 2022 period totaling approximately $0.3 million. Management plans to continue to actively pursue leasing opportunities.

With continued natural gas and oil price volatility, management continues to evaluate opportunities for product price protection through additional hedging of our future natural gas and oil production. See Note 9: Derivatives in the notes to our condensed financial statements included in this Form 10-Q for a complete list of our outstanding derivative contracts at March 31, 2022.

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

	Six Months Ended
	March 31, 2022
Cash provided by operating activities	$	15,934,320
Cash provided (used) by:
Capital expenditures - acquisitions		(20,918,274	)
Capital expenditures - legacy working interest wells		(279,348	)
Quarterly dividends		(849,689	)
Net borrowings (payments) on credit facility		6,500,000
Net proceeds from sale of assets		6,880,972
Cash receipts from (payments on) off-market derivative contracts		(7,930,160	)
Net cost of equity issuance		(72,657	)
Net cash used		(16,669,156	)
Net increase (decrease) in cash	$	(734,836	)

Outstanding borrowings under our Credit Facility at March 31, 2022 were $24,000,000.

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Looking forward, we expect to fund overhead costs, mineral and royalty acquisitions and dividend payments from cash provided by operating activities, cash on hand and borrowings under our Credit Facility. We had availability of $8.0 million at March 31, 2022 under our Credit Facility and were in compliance with all debt covenants (current ratio, debt to trailing 12-month EBITDAX, as defined in the Credit Agreement, and restricted payments limited by leverage ratio). The debt covenants in our Credit Agreement limit the maximum ratio of our debt to EBITDAX to no more than 3.5:1.

We have our $100,000,000 Credit Facility with a group of banks led by Independent Bank pursuant to the Credit Agreement entered into in September 2021. The Credit Facility has a borrowing base of $32,000,000 as of March 31, 2022, and a maturity date of September 1, 2025. Interest on the Credit Facility will be calculated based on either (a) LIBOR plus an applicable margin ranging from 2.750% to 3.750% per annum based on our Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the US Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on our Borrowing Base Utilization. Under the terms of the Credit Facility, a 5% interest penalty may apply to any outstanding amount not paid when due or that remains outstanding while an event of default exists. The Credit Facility contains financial and various other covenants that are common in such agreements, including a (a) maximum ratio of consolidated Funded Indebtedness to consolidated pro forma EBITDAX of 3.50 to 1.00, calculated on a rolling four-quarter basis, and (b) minimum ratio of consolidated Current Assets to consolidated Current Liabilities (excluding the Loan Balance) of 1.00 to 1.00. Other negative covenants include restrictions on our ability to incur debt, grant liens, make fundamental changes and engage in certain transactions with affiliates. The Credit Facility also restricts our ability to make certain restricted payments if both before and after the Restricted Payment (i) the Available Commitment is less than or equal to ten percent (10%) of the Borrowing Base or (ii) the Leverage Ratio on a pro forma basis is greater than 2.50 to 1.00. All capitalized terms in this description of the Credit Facility that are not otherwise defined in this Form 10-Q shall have the meaning assigned to them in the Credit Agreement.

Based on our expected capital expenditure levels, anticipated cash provided by operating activities for 2022, combined with availability under our Credit Facility and potential future sales of Common Stock under our currently effective shelf registration statement, including pursuant to the ATM Agreement described below, we expect to have sufficient liquidity to fund our ongoing operations.

On August 25, 2021, we entered into an At-The-Market Equity Offering Sales Agreement (the “ATM Agreement”) with Stifel, Nicolaus & Company, Incorporated, as sales agent and/or principal (“Stifel”), pursuant to which we may offer and sell, from time to time through or to Stifel, up to 3,000,000 shares of our Common Stock. During the quarter ended March 31, 2022, we sold 2,710 shares of Common Stock pursuant to the ATM Agreement for net proceeds of $8,017, and as of March 31, 2022, we have sold a total of 223,710 shares of Common Stock pursuant to the ATM Agreement for aggregate proceeds of approximately $0.7 million, net of commissions paid.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical accounting policies are those we believe are most important in portraying our financial condition and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. There have been no material changes to the critical accounting policies previously disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2021.

CONTRACTUAL OBLIGATIONS

There have been no material changes in our contractual obligations and other commitments as disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2021.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Natural gas, oil and NGL prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of natural gas, oil and NGL price trends, and there remains a wide divergence in the opinions held in the industry. We can be significantly impacted by changes in natural gas and oil prices. The market price of natural gas, oil and NGL in 2022 will impact the amount of cash generated from operating activities, which will in turn impact the level of our capital expenditures for acquisitions and production. Excluding the impact of our 2022 derivative contracts, the price sensitivity for each $0.10 per MCF change in wellhead natural gas price is approximately $669,972 for operating revenue based on our prior year natural

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gas volumes. The price sensitivity in 2022 for each $1.00 per barrel change in wellhead oil is approximately $224,479 for operating revenue based on our prior year oil volumes.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to our Credit Facility. Interest under our Credit Facility is calculated based on either (a) LIBOR plus an applicable margin ranging from 2.750% to 3.750% per annum based on our Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the U.S. Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on our Borrowing Base Utilization. Under the terms of the Credit Facility, a 5% interest penalty may apply to any outstanding amount not paid when due or that remains outstanding while an event of default exists. At March 31, 2022, we had $24,000,000 outstanding under the Credit Facility and the effective interest rate was 3.82%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of $240,000 for the six months ended March 31, 2022, assuming that our indebtedness remained constant throughout the period. At this point, we do not believe that our liquidity has been materially affected by the debt market uncertainties noted in the last few years, and we do not believe that our liquidity will be significantly impacted in the near future. All capitalized terms in this description of the interest rate under the Credit Facility that are not otherwise defined in this Form 10-Q shall have the meaning assigned to them in the Credit Agreement.

ITEM 4 CONTROLS AND PROCEDURES

We maintain “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Our disclosure controls and procedures have been designed to meet, and management believes they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this Form 10-Q, our Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures were not effective as of March 31, 2022 as a result of the material weakness disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2021, which was discovered during the audit process related to the fiscal year ended September 30, 2021. Subsequent to March 31, 2022, this material weakness was remediated as described below.

As disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2021, management, together with the Company’s independent registered public accounting firm, identified a material weakness in one of the Company’s internal controls related to the review of the annual income tax provision prepared by a third-party firm.  Specifically, the Company’s review of the annual income tax provision did not include a process to sufficiently evaluate deferred tax assets to determine if a valuation allowance was necessary.  Additionally, the review was not sufficiently detailed to identify a material misstatement in deferred income taxes.  After discovery of this material weakness, we designed and implemented a remediation plan to address the material weakness.  Our remediation plan included engaging a large public accounting firm to prepare and review the Company’s annual income tax provision and related income calculations and disclosures.  We also added enhanced communication protocols between our tax provision preparer, management, and the external auditors, and held additional meetings throughout the six-month period ended March 31, 2022 with our tax preparer.  Our management has monitored the effectiveness of these and other processes, procedures and controls and has successfully completed the testing necessary to conclude that, subsequent to March 31, 2022 and prior to the filing of this Form 10-Q, the material weakness has been remediated.  With the exception of the remediation efforts described above, there has been no change in our internal control over financial reporting that occurred during the fiscal quarter ended March 31, 2022 and during the subsequent time period through the filing of this Form 10-Q that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION

ITEM 1 LEGAL PROCEEDINGS

We may be the subject of threatened or pending legal actions and contingencies in the normal course of conducting our business. We provide for costs related to these matters when a loss is probable and the amount can be reasonably estimated. The effect of the outcome of these matters on our future results of operations and liquidity cannot be predicted because any such effect depends on future results of operations and the amount or timing of the resolution of such matters. For certain types of claims, we maintain

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insurance coverage for personal injury and property damage, product liability and other liability coverages in amounts and with deductibles that we believe are prudent, but there can be no assurance that these coverages will be applicable or adequate to cover adverse outcomes of claims or legal proceedings against us. We are not a party to any pending legal proceedings that we believe would, individually or in the aggregate, have a material adverse effect on our financial condition, operating results or cash flow.

ITEM 1A   RISK FACTORS

We are subject to certain risks and hazards due to the nature of our business activities.  For a discussion of these risks, please refer to Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 30, 2021. There have been no material changes to the risk factors contained in the Annual Report on Form 10-K for the fiscal year ended September 30, 2021. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In May 2014, the Board adopted stock repurchase resolutions (the “Repurchase Program”) to allow management, at its discretion, to purchase the Company’s Common Stock as treasury shares. Effective in May 2018, the Board approved an amendment to the Repurchase Program. As amended, the Repurchase Program continues to allow the Company to repurchase up to $1.5 million of the Company’s Common Stock at management’s discretion. Our Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $1.5 million of our Common Stock is authorized and approved whenever the previous $1.5 million is utilized. In addition, the number of shares allowed to be purchased under the Repurchase Program, as amended, is no longer capped at an amount equal to the aggregate number of shares of Common Stock (i) awarded pursuant to our 2010 Restricted Stock Plan, as amended, and (ii) credited to the accounts of directors pursuant to our Deferred Compensation Plan for Non-Employee Directors. We did not make any repurchases of shares of our Common Stock during the fiscal quarter ended March 31, 2022.

Restrictions upon the payment of dividends

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

ITEM 6 EXHIBITS

(a)	Exhibit No.	Description
	2.1	Agreement and Plan of Merger, dated as of March 31, 2022, by and between PHX Minerals Inc., an Oklahoma corporation, and PHX Minerals (DE) Inc., a Delaware corporation (incorporated by reference to Exhibit 2.1 to Form 8-K12B filed April 5, 2022).
	3.1	Certificate of Incorporation of PHX Minerals Inc., as amended (incorporated by reference to Exhibit 3.1 to Form 8-K12B filed April 5, 2022).
	3.2	Bylaws of PHX Minerals Inc. (incorporated by reference to Exhibit 3.2 to Form 8-K12B filed April 5, 2022).
	31.1	Certification under Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Executive Officer
	31.2	Certification under Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Financial Officer
	32.1	Certification under Section 906 of the Sarbanes-Oxley Act of 2002 by Chief Executive Officer
	32.2	Certification under Section 906 of the Sarbanes-Oxley Act of 2002 by Chief Financial Officer
	99.1	Description of Capital Stock of PHX Minerals Inc. (incorporated by reference to Exhibit 99.1 to Form 8-K12B filed April 5, 2022).
	101.INS	Inline XBRL Instance Document
	101.SCH	Inline XBRL Taxonomy Extension Schema Document
	101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
	101.LAB	Inline XBRL Taxonomy Extension Labels Linkbase Document
	101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
	101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
	104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURES

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

PHX MINERALS INC.
	PHX MINERALS INC.
May 9, 2022	/s/ Chad L. Stephens
Date	Chad L. Stephens, President,
	Chief Executive Officer
May 9, 2022	/s/ Ralph D’Amico
Date	Ralph D’Amico, Vice President,
	Chief Financial Officer

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