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  June 30, 2021

☐ 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)

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

Valliance Bank Tower, Suite 1100, 1601 NW Expressway, 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
Class A 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 Class A Common stock (voting) at August 2, 2021: 30,400,612 shares

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements		1
		Condensed Balance Sheets – June 30, 2021, and September 30, 2020		1
		Condensed Statements of Operations – Three and nine months ended June 30, 2021 and 2020		2
		Statements of Stockholders’ Equity – Nine months ended June 30, 2021 and 2020		3
		Condensed Statements of Cash Flows – Nine months ended June 30, 2021 and 2020		5
		Notes to Condensed Financial Statements		6
	Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations		15
	Item 3	Quantitative and Qualitative Disclosures about Market Risk		26
	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, 2020 (“Annual Report”), and all quarterly reports on Form 10-Q filed subsequently thereto, including the risks described in Item 1A of this Form 10-Q. Investors should also read the other information in this Form 10-Q and the Annual Report where risk factors are presented and further discussed.

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

Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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

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 2021 mean the fiscal year ended September 30, 2021.

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

Fiscal nine-month period references

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

References to 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

	June 30, 2021			September 30, 2020
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	2,908,500		$	10,690,395
Natural gas, oil, and NGL sales receivables (net of $0 allowance for uncollectable accounts)		5,114,387			2,943,220
Refundable income taxes		2,379,756			3,805,227
Other		480,600			351,088
Total current assets		10,883,243			17,789,930
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		323,187,303			324,886,491
Non-producing natural gas and oil properties		32,894,588			18,993,814
Other		681,125			582,444
		356,763,016			344,462,749
Less accumulated depreciation, depletion and amortization		(259,018,926	)		(263,590,801	)
Net properties and equipment		97,744,090			80,871,948
Operating lease right-of-use assets		628,617			690,316
Other, net		558,659			669,641
Total assets	$	109,814,609		$	100,021,835
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	1,173,258		$	997,637
Derivative contracts, net		6,754,328			281,942
Current portion of operating lease liability		130,973			127,108
Accrued liabilities and other		1,324,482			1,297,363
Short-term debt		-			1,750,000
Total current liabilities		9,383,041			4,454,050
Long-term debt		19,900,000			27,000,000
Deferred income taxes, net		212,007			1,329,007
Asset retirement obligations		2,845,919			2,897,522
Derivative contracts, net		1,354,174			425,705
Operating lease liability, net of current portion		822,907			921,625
Total liabilities		34,518,048			37,027,909
Stockholders' equity:
Class A voting common stock, $0.01666 par value; 36,000,500 shares authorized and   30,200,226 issued at June 30, 2021; 24,000,500 shares authorized and 22,647,306 issued at September 30, 2020		503,136			377,304
Capital in excess of par value		25,844,372			10,649,611
Deferred directors' compensation		1,701,110			1,874,007
Retained earnings		53,033,376			56,244,100
		81,081,994			69,145,022
Less treasury stock, at cost; 388,545 shares at June 30, 2021, and 411,487 shares    at September 30, 2020		(5,785,433	)		(6,151,096	)
Total stockholders' equity		75,296,561			62,993,926
Total liabilities and stockholders' equity	$	109,814,609		$	100,021,835

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

(1)

PHX MINERALS INC.

CONDENSED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,						Nine Months Ended June 30,
	2021			2020			2021			2020
Revenues:	(unaudited)						(unaudited)
Natural gas, oil and NGL sales	$	10,899,820		$	3,517,561		$	25,670,624		$	18,329,017
Lease bonuses and rental income		259,152			22,996			319,139			572,787
Gains (losses) on derivative contracts		(5,487,483	)		(838,282	)		(8,089,662	)		2,415,401
Gain on asset sales		270,070			3,108			313,595			3,275,996
		5,941,559			2,705,383			18,213,696			24,593,201
Costs and expenses:
Lease operating expenses		1,064,989			1,147,948			3,100,052			3,871,818
Transportation, gathering and marketing		1,538,174			956,653			4,138,653			3,696,282
Production taxes		596,858			134,249			1,316,038			835,284
Depreciation, depletion and amortization		2,137,707			2,464,568			6,176,173			8,793,787
Provision for impairment		45,855			358,826			45,855			29,904,528
Interest expense		220,439			241,191			790,202			958,429
General and administrative		2,275,104			1,908,790			6,065,677			6,306,479
Other expense (income)		235,027			(73,687	)		136,083			(44,551	)
Total costs and expenses		8,114,153			7,138,538			21,768,733			54,322,056
Income (loss) before provision (benefit) for income taxes		(2,172,594	)		(4,433,155	)		(3,555,037	)		(29,728,855	)
Provision (benefit) for income taxes		(816,000	)		(877,940	)		(1,102,000	)		(7,610,940	)
Net income (loss)	$	(1,356,594	)	$	(3,555,215	)	$	(2,453,037	)	$	(22,117,915	)
Basic and diluted earnings (loss) per common share (Note 4)	$	(0.05	)	$	(0.21	)	$	(0.10	)	$	(1.34	)
Basic and diluted weighted average shares outstanding:
Common shares		28,117,199			16,403,243			24,308,185			16,375,736
Unissued, directors' deferred compensation shares		192,059			141,799			174,454			152,500
		28,309,258			16,545,042			24,482,639			16,528,236
Dividends declared per share of common stock and paid in period	$	0.01		$	0.01		$	0.03		$	0.09

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

(2)

PHX MINERALS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Nine Months Ended June 30, 2021

	Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total
Balances at September 30, 2020		22,647,306	$	377,304	$	10,649,611		$	1,874,007		$	56,244,100			(411,487	)	$	(6,151,096	)	$	62,993,926
Net income (loss)		-		-		-			-			(596,720	)		-			-			(596,720	)
Equity offering		153,375		2,555		223,203			-			-			-			-			225,758
Restricted stock awards		-		-		122,978			-			-			-			-			122,978
Dividends ($0.02 per share)		-		-		-			-			(454,936	)		-			-			(454,936	)
Distribution of restricted stock    to officers and directors		-		-		(316,886	)		-			-			21,220			317,239			353
Increase in deferred directors'    compensation charged to    expense		-		-		-			44,527			-			-			-			44,527
Balances at December 31, 2020		22,800,681	$	379,859	$	10,678,906		$	1,918,534		$	55,192,444			(390,267	)	$	(5,833,857	)	$	62,335,886
(unaudited)
Net income (loss)		-		-		-			-			(499,723	)		-			-			(499,723	)
Equity offering		-		-		(29,240	)		-			-			-			-			(29,240	)
Restricted stock awards		-		-		161,170			-			-			-			-			161,170
Dividends ($0.01 per share)		-		-		-			-			(289,997	)		-			-			(289,997	)
Distribution of restricted stock    to officers and directors		-		-		-			-			-			(556	)		(1,268	)		(1,268	)
Distribution of deferred    directors' compensation		24,545		409		339,913			(340,322	)		-			-			-			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			55,727			-			-			-			55,727
Balances at March 31, 2021		22,825,226	$	380,268	$	11,150,749		$	1,633,939		$	54,402,724			(390,823	)	$	(5,835,125	)	$	61,732,555
(unaudited)
Net income (loss)		-		-		-			-			(1,356,594	)		-			-			(1,356,594	)
Purchase of treasury stock		-		-		-			-			-			(1,229	)		(2,741	)		(2,741	)
Equity offering		7,375,000		122,868		14,487,472			-			-			-			-			14,610,340
Restricted stock awards		-		-		258,526			-			-			-			-			258,526
Dividends		-		-		-			-			(12,754	)		-			-			(12,754	)
Distribution of restricted stock    to officers and directors		-		-		(52,375	)		-			-			3,507			52,433			58
Increase in deferred directors'    compensation charged to    expense		-		-		-			67,171			-			-			-			67,171
Balances at June 30, 2021		30,200,226	$	503,136	$	25,844,372		$	1,701,110		$	53,033,376			(388,545	)	$	(5,785,433	)	$	75,296,561
(unaudited)

(3)

Nine Months Ended June 30, 2020

	Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total
Balances at September 30, 2019		16,897,306	$	281,509	$	2,967,984		$	2,555,781		$	81,848,301			(558,051	)	$	(8,344,042	)	$	79,309,533
Net income (loss)		-		-		-			-			1,892,114			-			-			1,892,114
Purchase of treasury stock		-		-		-			-			-			(632	)		(7,635	)		(7,635	)
Restricted stock awards		-		-		148,515			-			-			-			-			148,515
Dividends ($0.08 per share)		-		-		-			-			(1,319,899	)		-			-			(1,319,899	)
Distribution of restricted stock    to officers and directors		-		-		(82,821	)		-			-			5,546			82,914			93
Increase in deferred directors'    compensation charged to    expense		-		-		-			86,212			-			-			-			86,212
Balances at December 31, 2019		16,897,306	$	281,509	$	3,033,678		$	2,641,993		$	82,420,516			(553,137	)	$	(8,268,763	)	$	80,108,933
(unaudited)
Net income (loss)		-		-		-			-			(20,454,814	)		-			-			(20,454,814	)
Restricted stock awards		-		-		343,101			-			-			-			-			343,101
Distribution of deferred    directors' compensation		-		-		(112,396	)		(603,485	)		-			47,885			715,880			(1	)
Increase in deferred directors'    compensation charged to    expense		-		-		-			53,918			-			-			-			53,918
Balances at March 31, 2020		16,897,306	$	281,509	$	3,264,383		$	2,092,426		$	61,965,702			(505,252	)	$	(7,552,883	)	$	60,051,137
(unaudited)
Net income (loss)		-		-		-			-			(3,555,215	)		-			-			(3,555,215	)
Restricted stock awards		-		-		128,196			-			-			-			-			128,196
Dividends ($0.01 per share)		-		-		-			-			(166,132	)		-			-			(166,132	)
Distribution of deferred    directors' compensation		-		-		(17,179	)		(306,698	)		-			21,664			323,877			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			44,058			-			-			-			44,058
Balances at June 30, 2020		16,897,306	$	281,509	$	3,375,400		$	1,829,786		$	58,244,355			(483,588	)	$	(7,229,006	)	$	56,502,044
(unaudited)

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

(4)

PHX MINERALS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Nine Months Ended June 30,
	2021			2020
Operating Activities	(unaudited)
Net income (loss)	$	(2,453,037	)	$	(22,117,915	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		6,176,173			8,793,787
Impairment of producing properties		45,855			29,904,528
Provision for deferred income taxes		(1,117,000	)		(6,158,000	)
Gain from leasing fee mineral acreage		(316,541	)		(567,975	)
Proceeds from leasing fee mineral acreage		334,938			582,458
Net (gain) loss on sales of assets		(136,596	)		(3,258,994	)
Directors' deferred compensation expense		167,425			184,188
Total (gain) loss on derivative contracts		8,089,662			(2,415,401	)
Cash receipts (payments) on settled derivative contracts		(688,807	)		3,230,034
Restricted stock awards		542,674			619,812
Other		72,126			3,718
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables		(2,134,395	)		2,194,430
Other current assets		(89,957	)		(121,635	)
Accounts payable		209,014			31,755
Income taxes receivable		1,425,471			(134,908	)
Other non-current assets		87,065			6,544
Accrued liabilities		26,263			(950,686	)
Total adjustments		12,693,370			31,943,655
Net cash provided by operating activities		10,240,333			9,825,740
Investing Activities
Capital expenditures		(696,759	)		(196,168	)
Acquisition of minerals and overriding royalty interests		(19,337,265	)		(10,304,016	)
Proceeds from sales of assets		533,371			3,457,500
Net cash provided (used) by investing activities		(19,500,653	)		(7,042,684	)
Financing Activities
Borrowings under Credit Facility		-			6,061,725
Payments of loan principal		(8,850,000	)		(11,486,725	)
Net proceeds from equity issuance		11,088,858			-
Purchases of treasury stock		(2,741	)		(7,635	)
Payments of dividends		(757,692	)		(1,486,031	)
Net cash provided (used) by financing activities		1,478,425			(6,918,666	)
Increase (decrease) in cash and cash equivalents		(7,781,895	)		(4,135,610	)
Cash and cash equivalents at beginning of period		10,690,395			6,160,691
Cash and cash equivalents at end of period	$	2,908,500		$	2,025,081
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations	$	-		$	4
Gross additions to properties and equipment	$	23,794,178		$	10,335,534
Equity offering used for acquisitions		(3,718,000	)		-
Net (increase) decrease in accounts payable for properties and equipment additions		(42,154	)		164,650
Capital expenditures and acquisitions	$	20,034,024		$	10,500,184

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

(5)

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, 2020. 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
New Accounting Pronouncements yet to be Adopted
ASU 2019-12, Simplifying the Accounting for Income Taxes.	This standard is intended to clarify and simplify the accounting for income taxes by removing certain exceptions and amending existing guidance.	Q1 2022	This standard is effective for public business entities beginning after December 15, 2020, with early adoption permitted. The Company does not believe the adoption of this standard will have a material impact on its 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 disposition, it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as a gain. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rental income line item on the Company’s Statements of Operations.

Natural gas and oil derivative contracts

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

Revenues from contracts with customers

Natural gas, oil and NGL sales

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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 nine months ended June 30, 2021 and 2020:

	Three Months Ended June 30, 2021						Nine Months Ended June 30, 2021
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	3,023,941	$	3,234,656	$	6,258,597	$	6,580,533	$	7,509,962	$	14,090,495
Oil revenue		1,934,966		1,603,996		3,538,962		4,748,987		4,275,962		9,024,949
NGL revenue		453,935		648,326		1,102,261		1,095,124		1,460,056		2,555,180
Natural gas, oil and NGL sales	$	5,412,842	$	5,486,978	$	10,899,820	$	12,424,644	$	13,245,980	$	25,670,624
	Three Months Ended June 30, 2020						Nine Months Ended June 30, 2020
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	792,227	$	1,062,461	$	1,854,688	$	3,122,951	$	4,747,766	$	7,870,717
Oil revenue		719,012		711,005		1,430,017		4,680,871		4,404,949		9,085,820
NGL revenue		129,833		103,023		232,856		548,921		823,559		1,372,480
Natural gas, oil and NGL sales	$	1,641,072	$	1,876,489	$	3,517,561	$	8,352,743	$	9,976,274	$	18,329,017

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 nine months ended 2020, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was considered a change in estimate. For the three months ended June 30, 2021, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was approximately $2.0 million and primarily due to change in price estimates as a result of basis differentials during winter storms. This is considered a change in estimate.   

As noted above, as a non-operator, there are instances when the Company is limited by the information operators provide to it. Through cash received on new wells, in the 2021 third quarter, the Company identified several producing properties on its minerals that had production dates prior to the 2021 third quarter. Estimates of the natural gas and oil sales related to those properties were made and are reflected in the third quarter natural gas, oil and NGL sales on the Company’s Statements of Operations and on the Company’s balance sheets in natural gas, oil and NGL sales receivables. In connection with obtaining more relevant information on new wells on Company acreage for the three and nine months ended June 30, 2021, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $365,871, of which $72,717 related to the production periods before October 1, 2020 and $293,154 related to the first and second quarters of 2021. In connection with obtaining more relevant information identifying additional new wells on Company acreage for the three and nine months ended June 30, 2020, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $259,336, of which $164,115 related to the production periods before October 1, 2019 and $95,221 related to the first and second quarters of 2020.

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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. 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. Excess tax benefits and deficiencies of stock-based compensation are recognized as provision (benefit) for income taxes in the Company’s Statements of Operations.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with detailed well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion, if a provision for income taxes is expected for the year, will decrease the effective tax rate, while the effect will increase the effective tax rate if a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The Company’s effective tax rate for the nine months ended June 30, 2021 was a 31% benefit as compared to a 26% benefit for the nine months ended June 30, 2020. The Company’s effective tax rate for the quarter ended June 30, 2021 was a 38% benefit as compared to a 20% benefit for the quarter ended June 30, 2020.

The federal Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 Net Operating Losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the limitation on interest expense deductibility under Section 163(j) of the Internal Revenue Code (“IRC”) from 30% to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. On July 28, 2020, final regulations were issued under Section 163(j) of the IRC, which modified the calculation under the previous proposed regulations of adjusted taxable income for purposes of the 50% limitation on interest expense. Under the final regulations, depreciation, amortization, and depletion capitalizable under Section 263A of the IRC is added back to tentative taxable income.  This change allowed all interest expense to be deductible for 2020 and reduced the associated deferred tax asset to 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. Additionally, the Company has a $2.2 million receivable 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 common share is calculated using net income (loss) divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares, during the period. 

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

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

	Three Months Ended June 30,						Nine Months Ended June 30,
	2021			2020			2021			2020
Basic EPS
Numerator:
Basic net income (loss)	$	(1,356,594	)	$	(3,555,215	)	$	(2,453,037	)	$	(22,117,915	)
Denominator:
Basic weighted average shares outstanding		28,309,258			16,545,042			24,482,639			16,528,236
Basic EPS	$	(0.05	)	$	(0.21	)	$	(0.10	)	$	(1.34	)
Diluted EPS
Numerator:
Basic net income (loss)	$	(1,356,594	)	$	(3,555,215	)	$	(2,453,037	)	$	(22,117,915	)
Diluted net income (loss)		(1,356,594	)		(3,555,215	)		(2,453,037	)		(22,117,915	)
Denominator:
Basic weighted average shares outstanding		28,309,258			16,545,042			24,482,639			16,528,236
Effects of dilutive securities:
Unvested restricted stock		-			-			-			-
Diluted weighted average shares outstanding		28,309,258			16,545,042			24,482,639			16,528,236
Diluted EPS	$	(0.05	)	$	(0.21	)	$	(0.10	)	$	(1.34	)

NOTE 5: Long-Term Debt

The Company has a $200,000,000 credit facility with a syndicate of banks led by Bank of Oklahoma (“BOKF”), which had a borrowing base of $28,500,000 as of June 30, 2021 (as amended, the “Credit Facility”). The Credit Facility matures on November 30, 2023. The Credit Facility is subject to at least semi-annual borrowing base determinations, wherein BOKF applies its commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The Credit Facility is secured by all of the Company’s producing oil and gas properties. The interest rate is based on BOKF prime plus from 1.00% to 1.75%, or 30-day LIBOR plus from 2.50% to 3.25%. The election of BOKF prime or LIBOR is at the Company’s discretion. The interest rate spread from BOKF prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as the ratio of loan balance to the borrowing base increases. At June 30, 2021, the effective interest rate was 4.00%.

The Company’s debt is recorded at the carrying amount on its balance sheets. The carrying amount of the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in Other, net on the Company’s balance sheets. Total debt issuance cost, net of amortization as of June 30, 2021 was $252,001. The debt issuance cost is amortized over the life of the Credit Facility.

On April 7, 2021, the Company entered into the ninth amendment to the Credit Facility. The amendment, among other things, reduced the Company’s borrowing base under the Credit Facility to $29.0 million, extended the maturity date by one year to November 30, 2023, and reduced the Quarterly Commitment Reductions from $600,000 to $500,000, commencing on April 15, 2021. Additionally, the amendment increased the Company’s distribution allowance from $1.0 million to $1.5 million per annum for a period of one year from the date of the amendment and extended this allowance beyond the date that is one year following the date of the amendment so long as (i) the Available Commitment is greater than or equal to 20% of the Total Commitment and (ii) the Leverage Ratio on a pro forma basis does not exceed 2.75 to 1.00. The existing prohibition of all Restricted Payments other than the subject distribution allowance and the existing requirement that immediately after giving effect to a permitted Restricted Payment, no Default or Event of Default may exist or result therefrom remain in effect.

The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA ratio (as defined in the Credit Facility) of no more than 3.5 to 1.0 based on the trailing twelve months. Pursuant to the Credit Facility, the Company is also required to enter into and maintain certain Swap Agreements for a period of eighteen (18) months fixing prices on oil or gas expected to be produced. At June 30, 2021, the Company was in compliance with the covenants of the Credit Facility, had $19,900,000 outstanding under the Credit Facility, and had $8,600,000 of borrowing base

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

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 (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination or death or a change-in-control of the Company will the shares recorded for such director be issued under this plan. Directors may elect to receive shares, when issued, over annual time periods of up to ten years. The promise to issue such shares in the future is an unsecured obligation of the Company.

NOTE 7: Restricted Stock Plan

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

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
Market-based, restricted stock	$	79,118	$	10,247	$	168,483	$	285,150
Time-based, restricted stock		179,408		117,949		374,191		334,662
Performance-based, restricted stock		-		-		-		-
Total compensation expense	$	258,526	$	128,196	$	542,674	$	619,812

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

	As of June 30, 2021
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	725,627		2.43
Time-based, restricted stock		552,371		1.01
Performance-based, restricted stock		-
Total	$	1,277,998

NOTE 8: Properties and Equipment

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

	June 30, 2021			September 30, 2020
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties	$	323,187,303		$	324,886,491
Non-producing natural gas and oil properties		32,894,588			18,993,814
Other property and equipment		681,125			582,444
		356,763,016			344,462,749
Less accumulated depreciation, depletion and amortization		(259,018,926	)		(263,590,801	)
Net properties and equipment	$	97,744,090		$	80,871,948

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Acquisitions

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

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

Divestitures

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

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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 nine months ended June 30, 2021, management’s assessment resulted in an impairment provision of $37,879 on producing properties and $7,976 on wells that the Company wrote off.

For the nine months ended June 30, 2020, management’s assessment resulted in an impairment provision on producing properties of $29,315,807, primarily due to the decline in commodity prices caused by the ongoing COVID-19 pandemic. During the three and nine months ended June 30, 2020, impairment on wells that were written off totaled $358,826 and $588,721, respectively. 

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

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Derivative contracts in place as of June 30, 2021

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

The Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $8,108,502 as of June 30, 2021, and a net liability of $707,647 as of September 30, 2020. Cash receipts or payments in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2021			2020			2021			2020
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	(11,975	)	$	18,000		$	(21,064	)	$	18,000
Natural gas fixed price swaps		(20,185	)		268,650			(18,943	)		1,488,970
Oil costless collars		(346,786	)		625,968			(370,432	)		827,664
Oil fixed price swaps		(625,744	)		786,504			(278,368	)		895,400
Cash received (paid) on derivative contracts, net	$	(1,004,690	)	$	1,699,122		$	(688,807	)	$	3,230,034
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(1,732,932	)	$	(60,035	)	$	(1,135,852	)	$	(32,152	)
Natural gas fixed price swaps		(953,201	)		(129,865	)		(670,605	)		(815,630	)
Oil costless collars		(680,443	)		(757,060	)		(1,787,689	)		(283,255	)
Oil fixed price swaps		(1,116,217	)		(1,590,444	)		(3,806,709	)		316,404
Non-cash gain (loss) on derivative contracts, net	$	(4,482,793	)	$	(2,537,404	)	$	(7,400,855	)	$	(814,633	)
Gains (losses) on derivative contracts, net	$	(5,487,483	)	$	(838,282	)	$	(8,089,662	)	$	2,415,401

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

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

	June 30, 2021												September 30, 2020
	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	$	130,690		$	6,885,018		$	144,462		$	1,498,636		$	864,466		$	1,146,408		$	425,705
Offsetting adjustments		(130,690	)		(130,690	)		(144,462	)		(144,462	)		(864,466	)		(864,466	)		-
Net presentation on Condensed Balance Sheets	$	-		$	6,754,328		$	-		$	1,354,174		$	-		$	281,942		$	425,705

(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.

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 June 30, 2021:

	Fair Value Measurement at June 30, 2021
	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	$	-	$	(4,542,115	)	$	-	$	(4,542,115	)
Derivative Contracts - Collars	$	-	$	(3,566,387	)	$	-	$	(3,566,387	)

Level 2 – Market Approach - The fair values of the Company’s swaps and collars are based on a third-party pricing model, which utilizes inputs that are either readily available in the public market, such as natural gas curves and volatility curves, or can be corroborated from active markets. These values are based upon future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

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The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy:

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

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

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

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.

NOTE 12: Subsequent Events

There were no subsequent events requiring disclosure.

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

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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 and development of our significant mineral acreage inventory in our core areas of focus, which include the SCOOP, STACK and Arkoma Stack plays in Oklahoma, the Permian Basin in Texas and New Mexico, the Haynesville and Eagle Ford plays in Texas, the Fayetteville play in Arkansas, and the Bakken/Three Forks play in North Dakota. We have ceased taking working interest positions on our mineral and leasehold acreage and do not plan to take any working interest positions going forward.

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, a growing portion of our revenue is derived from royalties received from the production and sale of natural gas, oil and NGL.

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

Overview:

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

Revenue:

Natural Gas, Oil and NGL Sales:

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

For the three months ended June 30, 2021, the increase in natural gas, oil and NGL sales was primarily due to increases in natural gas, oil and NGL prices of 145%, 146% and 256%, respectively, and an increase in natural gas, oil and NGL volumes of 38%, 1% and 33%, respectively. The following table outlines our production and average sales prices for natural gas, oil and NGL for the three-month periods of fiscal 2021 and 2020:

	Mcf		Average		Oil Bbls		Average		NGL Bbls		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
6/30/2021		1,879,343	$	3.33		55,492	$	63.77		46,753	$	23.58		2,492,813	$	4.37
6/30/2020		1,361,909	$	1.36		55,138	$	25.94		35,169	$	6.62		1,903,752	$	1.85

Production increased across all three product categories during the three months ended June 30, 2021, as compared to the three months ended June 30, 2020, due to improved market conditions, resulting in (i) previously curtailed, high interest wells being worked over and brought fully back online in the STACK, Arkoma Stack, and Fayetteville Shale, (ii) acquisitions in the STACK and Haynesville, and (iii) increased drilling and completions activity in the STACK and SCOOP. These increases were partially offset by plays with naturally declining production in high interest wells, such as the Eagle Ford Shale.

Total Production for the last five quarters was as follows:

Quarter ended	Mcf Sold		Oil Bbls Sold		NGL Bbls Sold		Mcfe Sold
6/30/2021		1,879,343		55,492		46,753		2,492,813
3/31/2021		1,735,820		56,269		37,228		2,296,802
12/31/2020		1,475,456		58,675		41,138		2,074,334
9/30/2020		1,423,602		55,626		46,737		2,037,779
6/30/2020		1,361,909		55,138		35,169		1,903,752

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

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

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

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

Lease Bonuses and Rental Income:

	For the Three Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Lease bonuses and rental income	$	259,152	$	22,996	1,027%

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

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 June 30,
							Percent
	2021			2020			Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net	$	(1,004,690	)	$	1,699,122		(159%)
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(4,482,793	)	$	(2,537,404	)	(77%)
Gains (losses) on derivative contracts, net	$	(5,487,483	)	$	(838,282	)	(555%)
	As of June 30,
	2021			2020
Fair value of derivative contracts
Net asset (net liability)	$	(8,108,502	)	$	1,679,511		(583%)

The net losses on derivative contracts in both periods were principally due to the natural gas and oil collars and fixed price swaps being less beneficial in relation to their respective contracted volumes and prices at the beginning of the periods.

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

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Costs and Expenses:

Lease Operating Expenses (LOE):

	For the Three Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Lease operating expenses	$	1,064,989	$	1,147,948	(7%)
Lease operating expenses per MCFE	$	0.43	$	0.60	(28%)

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

Transportation, Gathering and Marketing:

	For the Three Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Transportation, gathering and marketing	$	1,538,174	$	956,653	61%
Transportation, gathering and marketing per MCFE	$	0.62	$	0.50	24%

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

Production Taxes:

	For the Three Months Ended June 30,
							Percent
	2021			2020			Incr. or (Decr.)
Production taxes	$	596,858		$	134,249		345%
Production taxes as % of sales		5.5	%		3.8	%	45%

Production taxes are paid on produced natural gas and oil based on a percentage of revenues from products sold at both fixed and variable rates established by federal, state or local taxing authorities. Production taxes increased $462,609, or 345%, in the 2021 quarter as compared to the 2020 quarter. The increase in amount was primarily the result of increased natural gas, oil and NGL sales of $7,382,259 in the 2021 quarter as compared to the 2020 quarter.

Depreciation, Depletion and Amortization (DD&A):

	For the Three Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Depreciation, depletion and amortization	$	2,137,707	$	2,464,568	(13%)
Depreciation, depletion and amortization per MCFE	$	0.86	$	1.29	(33%)

DD&A is the amount of cost basis of natural gas and oil properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis for working interest, and on a straight-line basis for producing and non-producing minerals. Estimates of proved developed producing reserves are a major component of the calculation of depletion. DD&A decreased $326,861, or 13%, in the 2021 quarter compared to the 2020 quarter, of which $1,086,750 of the decrease resulted from a $0.43 decrease in the DD&A rate per Mcfe, partially offset by an increase of $759,889 resulting from production increasing 31% in the 2021 quarter. The rate decrease was mainly due to an increase in reserves during the 2021 quarter, as compared to the 2020 quarter.

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Provision for Impairment:

We had a $45,855 provision for impairment in the 2021 quarter as compared to a $358,826 provision for impairment in the 2020 quarter. During the 2021 quarter, impairment of $37,879 was related to one field. These assets were written down to their fair market value as required by GAAP. During the 2020 quarter, impairment of $358,826 was recorded due to a title revision by the operator on one well, and as a result, the remaining cost basis was written off.

Interest expense:

	For the Three Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Interest expense	$	220,439	$	241,191	(9%)
Weighted average debt outstanding	$	21,801,648	$	31,071,740	(30%)

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

Income Tax Expense:

	For the Three Months Ended June 30,
							Percent
	2021			2020			Incr. or (Decr.)
Provision (benefit) for income taxes	$	(816,000	)	$	(877,940	)	7%

Income taxes changed $61,940, from a $877,940 benefit in the 2020 quarter to a $816,000 benefit in the 2021 quarter. The change in income taxes resulted primarily from the reduction in net loss.

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

General and Administrative Costs (G&A):

	For the Three Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
General and administrative	$	2,275,104	$	1,908,790	19%

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

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

Overview:

We recorded a nine-month net loss of $2,453,037, or $0.10 per share, for the 2021 period, as compared to a net loss of $22,117,915, or $1.34 per share, in the 2020 period. The change in net income (loss) was principally the result of increased natural gas, oil and NGL sales and decreased LOE, DD&A, impairment expense and G&A, partially offset by an increase in losses on derivative contracts, transportation, gathering and marketing expenses, production taxes and a reduction in gain on asset sales and income tax benefit. These items are further discussed below.

Revenue:

Natural Gas, Oil and NGL Sales:

	For the Nine Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	25,670,624	$	18,329,017	40%

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

	Mcf		Average		Oil Bbls		Average		NGL Bbls		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Nine months ended
6/30/2021		5,090,619	$	2.77		170,437	$	52.95		125,118	$	20.42		6,863,949	$	3.74
6/30/2020		4,539,103	$	1.73		214,159	$	42.43		121,887	$	11.26		6,555,378	$	2.80

Natural gas volumes increased during the nine months ended June 30, 2021, as compared to the nine months ended June 30, 2020, primarily as a result of (i) acquisitions in the Haynesville Shale, (ii) maintenance workovers on high-interest wells in the Arkoma Stack, and (iii) increased drilling and completion activity in the STACK.  These gas volumes were partially offset by naturally declining production in the Fayetteville Shale and production downtime and curtailments in response to market conditions in the SCOOP. The decrease in oil production was primarily due to naturally declining production in high-interest wells brought online during the first quarter of 2020 in the Bakken, as well as reduced drilling and completion activity in 2021 due to prevailing economic conditions compared to 2020 in the Eagle Ford and SCOOP. Oil production decreases were partially offset by increased drilling and completion activity in the STACK. The increased activity in the STACK also resulted in increased NGL production, which was partially offset by production downtime and curtailments in high-interest wells in in the SCOOP as well as naturally declining production in liquid-rich gas areas of the Anadarko Granite Wash.

Lease Bonuses and Rental Income:

	For the Nine Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Lease bonuses and rental income	$	319,139	$	572,787	(44%)

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

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 Nine Months Ended June 30,
							Percent
	2021			2020			Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net	$	(688,807	)	$	3,230,034		(121%)
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(7,400,855	)	$	(814,633	)	(808%)
Gains (losses) on derivative contracts, net	$	(8,089,662	)	$	2,415,401		(435%)
	As of June 30,
	2021			2020
Fair value of derivative contracts
Net asset (net liability)	$	(8,108,502	)	$	1,679,511		(583%)

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

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

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Costs and Expenses:

Lease Operating Expenses (LOE):

	For the Nine Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Lease operating expenses	$	3,100,052	$	3,871,818	(20%)
Lease operating expenses per MCFE	$	0.45	$	0.59	(24%)

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

Transportation, Gathering and Marketing:

	For the Nine Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Transportation, gathering and marketing	$	4,138,653	$	3,696,282	12%
Transportation, gathering and marketing per MCFE	$	0.60	$	0.56	7%

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

Production Taxes:

	For the Nine Months Ended June 30,
							Percent
	2021			2020			Incr. or (Decr.)
Production taxes	$	1,316,038		$	835,284		58%
Production taxes as % of sales		5.1	%		4.6	%	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 $480,754, or 58%, in the 2021 period compared to the 2020 period. The increase in amount was primarily the result of increased prices and production volumes in the 2021 period as compared to the 2020 period.

Depreciation, Depletion and Amortization (DD&A):

	For the Nine Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Depreciation, depletion and amortization	$	6,176,173	$	8,793,787	(30%)
Depreciation, depletion and amortization per MCFE	$	0.90	$	1.34	(33%)

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

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Provision for Impairment:

We had a $45,855 provision for impairment in the 2021 period as compared to a $29,904,528 provision for impairment in the 2020 period. During the 2021 quarter, impairment of $37,879 was related to one field. These assets were written down to their fair market value as required by GAAP. During the 2020 period, impairment of $29,315,807 was recorded on seven different fields including the Fayetteville and Eagle Ford shales, which represented 89% of our total impairment. The impairment in these seven fields was caused by lower future prices reducing future net cash flows associated with these fields, which caused these assets to fail the step one test for impairment as their undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The remaining $588,721 of impairment in the 2020 period was recorded on other assets.

Interest expense:

	For the Nine Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
Interest expense	$	790,202	$	958,429	(18%)
Weighted average debt outstanding	$	25,108,791	$	33,264,541	(25%)

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

Income Tax Expense:

	For the Nine Months Ended June 30,
							Percent
	2021			2020			Incr. or (Decr.)
Provision (benefit) for income taxes	$	(1,102,000	)	$	(7,610,940	)	86%

Income taxes changed $6,508,940, from a $7,610,940 benefit in the 2020 period to a $1,102,000 benefit in the 2021 period. The income tax change resulted primarily from the reduction in net loss.

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 Nine Months Ended June 30,
					Percent
	2021		2020		Incr. or (Decr.)
General and administrative	$	6,065,677	$	6,306,479	(4%)

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

LIQUIDITY AND CAPITAL RESOURCES

We had positive working capital of $1,500,202 at June 30, 2021, compared to positive working capital of $13,335,880 at September 30, 2020, which included $7.3 million of cash used for the fiscal 2021 first quarter acquisitions.

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Liquidity:

Cash and cash equivalents were $2,908,500 as of June 30, 2021, compared to $10,690,395 at September 30, 2020, a decrease of $7,781,895. The decrease in cash is primarily associated with the closing of previously announced acquisitions, which were funded by the proceeds from the issuance of equity in September 2020. Cash flows for the nine months ended June 30, 2021 and 2020 are summarized as follows:

Net cash provided (used) by:	For the Nine Months Ended June 30,
	2021			2020			Change
Operating activities	$	10,240,333		$	9,825,740		$	414,593
Investing activities		(19,500,653	)		(7,042,684	)		(12,457,969	)
Financing activities		1,478,425			(6,918,666	)		8,397,091
Increase (decrease) in cash and cash equivalents	$	(7,781,895	)	$	(4,135,610	)	$	(3,646,285	)

Operating activities:

Net cash provided by operating activities increased $414,593 during the 2021 period, as compared to the 2020 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 $2,043,793;

• Decreased payments for G&A and other expense of $1,257,342 (the 2020 period included severance to our former CEO);

• Decreased field operating expenses of $985,309;

• Decreased interest payments of $191,567;

• Increased income tax receipts of $102,509.

• Decreased net receipts on derivative contracts of $3,918,840; and

• Decreased lease bonus receipts of $247,087.

Investing activities:

Net cash used by investing activities increased $12,457,969 during the 2021 period, as compared to the 2020 period, primarily due to higher acquisition costs of $9,033,249, lower net proceeds from the sale of assets of $2,924,129 and higher payments of $500,591 for drilling and completion activity during the 2021 period.

Financing activities:

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

Capital Resources:

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

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

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

On September 1, 2020, we completed an underwritten public offering of 5,750,000 common shares (inclusive of overallotment option) with net proceeds of $8.2 million.

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

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

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

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

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

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

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

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

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

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

	Nine Months Ended
	June 30, 2021
Cash provided by operating activities	$	10,240,333
Cash provided (used) by:
Capital expenditures - acquisitions		(19,337,265	)
Capital expenditures - drilling and completion of wells		(696,759	)
Quarterly dividends of $0.01 per share		(757,692	)
Treasury stock purchases		(2,741	)
Net borrowings (payments) on credit facility		(8,850,000	)
Proceeds from sale of assets		533,371
Net proceeds from equity issuance		11,088,858
Net cash used		(18,022,228	)
Net increase (decrease) in cash	$	(7,781,895	)

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

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

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

We expect that capital expenditures to drill and complete future wells will be immaterial. Based on anticipated cash provided by operating activities for 2021 and availability under the Credit Facility, management believes we have sufficient liquidity to fund our ongoing operations.

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. Other than the adoption of ASC 326 on October 1, 2020, there have been no material changes to the critical accounting policies previously disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2020.

CONTRACTUAL OBLIGATIONS

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

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ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Natural gas, oil and NGL prices have historically been volatile, and this volatility is expected to continue, especially in light of the ongoing COVID-19 pandemic and related economic repercussions. Our financial condition, liquidity and results of operations may be adversely impacted by precipitous changes in natural gas and oil prices. The market price of natural gas, oil and NGL in 2021 will impact the amount of cash generated from operating activities, which will in turn impact the level of our capital expenditures and production. We utilize derivative contracts to reduce our exposure to unfavorable changes in natural gas and oil prices. We do not enter into these derivatives for speculative or trading purposes. Our derivative contracts are currently with BOKF and are secured under the Credit Facility. These arrangements cover only a portion of our production, provide only partial price protection against declines in natural gas and oil prices and limit the benefit of future increases in prices. Excluding the impact of our 2021 derivative contracts, the price sensitivity in 2021 for each $1.00 per barrel change in wellhead oil price is $269,785 for operating revenue based on our prior year oil volumes. The price sensitivity in 2021 for each $0.10 per Mcf change in wellhead natural gas price is $596,271 for operating revenue based on our prior year natural gas volumes.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Credit Facility. Borrowings under the Credit Facility bear interest at the BOKF prime rate plus from 1.00% to 1.75%, or 30 day LIBOR plus from 2.50% to 3.25%. At June 30, 2021, we had $19,900,000 outstanding under the Credit Facility and the effective interest rate was 4.00%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $199,000, based on the balance outstanding at June 30, 2021.

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

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, the Chief Executive Officer and Chief Financial Officer have concluded our disclosure controls and procedures were effective to ensure material information relating to us is made known to management. There were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting made during the fiscal quarter or subsequent to the date the assessment was completed.

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 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.

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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, 2020. There have been no material changes to the risk factors contained in the Annual Report on Form 10-K for the fiscal year ended September 30, 2020. Additional risks and uncertainties not currently known to 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

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

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

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

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

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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.
August 5, 2021	/s/ Chad L. Stephens
Date	Chad L. Stephens, President,
	Chief Executive Officer
August 5, 2021	/s/ Ralph D’Amico
Date	Ralph D’Amico, Vice President,
	Chief Financial Officer

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