Quarterly Report (10-q)

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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  December 31, 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 [phone]

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 February 11, 2022: 34,498,626 shares

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INDEX

 

 

Part I		Financial Information			Page
		Item 1		Condensed Financial Statements		1
				Condensed Balance Sheets – December 31, 2021, and September 30, 2021		1
				Condensed Statements of Operations – Three months ended December 31, 2021 and 2020		2
				Statements of Stockholders’ Equity – Three months ended December 31, 2021 and 2020		3
				Condensed Statements of Cash Flows – Three months ended December 31, 2021 and 2020		4
				Notes to Condensed Financial Statements		5
		Item 2		Management's Discussion and Analysis of Financial Condition and Results of Operations		14
		Item 3		Quantitative and Qualitative Disclosures about Market Risk		21
		Item 4		Controls and Procedures		21
Part II		Other Information
		Item 1		Legal Proceedings		22
		Item 1A		Risk Factors		22
		Item 2		Unregistered Sales of Equity Securities and Use of Proceeds		22
		Item 6		Exhibits		23
		Signatures			23

 

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Special Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (“Form 10-Q”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-Q by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements. Forward-looking statements may include, but are not limited to, statements relating to: our ability to execute our business strategies; the volatility of realized natural gas and oil prices; the level of production on our properties; estimates of quantities of natural gas, oil and NGL reserves and their values; general economic or industry conditions; public health crises, such as the COVID-19 pandemic, and any related actions taken by businesses and governments; legislation or regulatory requirements; conditions of the securities markets; our ability to raise capital; changes in accounting principles, policies or guidelines; financial or political instability; acts of war or terrorism; title defects in the properties in which we invest; and other economic, competitive, governmental, regulatory or technical factors affecting our properties, operations or prices.

We caution you that the forward-looking statements contained in this Form 10-Q are subject to risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas, oil, and NGLs. These risks include, but are not limited to, the risks described in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2021 (“Annual Report”), and all quarterly reports on Form 10-Q filed subsequently thereto, including the risks described in Item 1A of this Form 10-Q. Investors should also read the other information in this Form 10-Q and the Annual Report where risk factors are presented and further discussed.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date of which such statement is made and 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.

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Glossary of Certain Terms

 

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

 

ASC	Accounting Standards Codification.
ASU	Accounting Standards Update.
Bbl	Barrel.
Board	Board of directors of the Company.
BTU	British Thermal Units.
Common Stock	Class A Common Stock, par value $0.01666 per share, of the Company.
completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.
DD&A	Depreciation, depletion and amortization.
EBITDA	Earnings before interest, taxes, depreciation and amortization (including impairment). This is a Non-GAAP measure.
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 2022 mean the fiscal year ending September 30, 2022.

Fiscal quarter references

All references to quarters in this Form 10-Q, unless otherwise noted, refer to the Company’s fiscal quarter based on a fiscal year end of September 30. For example, references to first quarter mean the quarter of October 1 through December 31. Unless otherwise noted, general references to a quarter refer to the quarterly period ended December 31. For example, the 2022 quarter refers to the quarterly period ended December 31, 2021 and the 2021 quarter refers to the quarterly period ended December 31, 2020.

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Fiscal three-month period references

All references to three-month periods in this Form 10-Q, unless otherwise noted, refer to the Company’s fiscal three-month period based on a fiscal year end of September 30. Unless otherwise noted, general references to a period in sections of this Form 10-Q discussing three-month periods refer to the three-month period ended December 31. For example, in sections of this Form 10-Q discussing three-month periods, the 2022 period refers to the three-month period ended December 31, 2021 and the 2021 period refers to the three-month period ended December 31, 2020.

References to natural gas and oil properties

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

 

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PART I FINANCIAL INFORMATION

 

ITEM 1 CONDENSED FINANCIAL STATEMENTS

 

PHX MINERALS INC.

CONDENSED BALANCE SHEETS

		December 31, 2021				September 30, 2021
Assets		(unaudited)
Current assets:
Cash and cash equivalents		$	1,559,350			$	2,438,511
Natural gas, oil, and NGL sales receivables (net of $0 allowance for uncollectable accounts)			8,020,067				6,428,982
Refundable income taxes			-				2,413,942
Other			1,333,279				942,082
Total current assets			10,912,696				12,223,517
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties			249,861,777				319,984,874
Non-producing natural gas and oil properties			54,960,073				40,466,098
Other			883,310				794,179
			305,705,160				361,245,151
Less accumulated depreciation, depletion and amortization			(195,971,382	)			(257,643,661	)
Net properties and equipment			109,733,778				103,601,490
Operating lease right-of-use assets			585,888				607,414
Other, net			570,072				578,593
Total assets		$	121,802,434			$	117,011,014
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable		$	612,387			$	772,717
Derivative contracts, net			6,413,308				12,087,988
Income taxes payable			499,939				334,050
Current portion of operating lease liability			133,614				132,287
Accrued liabilities and other			2,047,437				1,809,337
Total current liabilities			9,706,685				15,136,379
Long-term debt			20,000,000				17,500,000
Deferred income taxes, net			709,906				343,906
Asset retirement obligations			2,157,289				2,836,172
Derivative contracts, net			132,569				1,696,479
Operating lease liability, net of current portion			755,433				789,339
Total liabilities			33,461,882				38,302,275
Stockholders' equity:
Class A voting common stock, $0.01666 par value; 54,000,500 shares authorized and   34,405,287 issued at December 31, 2021; 36,000,500 shares authorized and 32,770,433 issued at September 30, 2021			573,192				545,956
Capital in excess of par value			36,741,266				33,213,645
Deferred directors' compensation			1,835,721				1,768,151
Retained earnings			54,798,980				48,966,420
			93,949,159				84,494,172
Less treasury stock, at cost; 377,232 shares at December 31, 2021, and 388,545 shares    at September 30, 2021			(5,608,607	)			(5,785,433	)
Total stockholders' equity			88,340,552				78,708,739
Total liabilities and stockholders' equity		$	121,802,434			$	117,011,014

 

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

(1)

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PHX MINERALS INC.

CONDENSED STATEMENTS OF OPERATIONS

 

		Three Months Ended December 31,
		2021				2020
Revenues:		(unaudited)
Natural gas, oil and NGL sales		$	13,687,164			$	6,424,979
Lease bonuses and rental income			78,915				1,433
Gains (losses) on derivative contracts			2,836,168				(254,036	)
		$	16,602,247			$	6,172,376
Costs and expenses:
Lease operating expenses			1,256,011				1,004,412
Transportation, gathering and marketing			1,213,604				1,280,965
Production taxes			678,947				276,026
Depreciation, depletion and amortization			1,583,760				2,260,649
Provision for impairment			5,585				-
Interest expense			176,719				301,898
General and administrative			2,095,557				1,731,097
Losses (gains) on asset sales and other			2,147,815				(16,951	)
Total costs and expenses			9,157,998				6,838,096
Income (loss) before provision (benefit) for income taxes			7,444,249				(665,720	)
Provision (benefit) for income taxes			762,000				(69,000	)
Net income (loss)		$	6,682,249			$	(596,720	)
Basic and diluted earnings (loss) per common share (Note 4)		$	0.20			$	(0.03	)
Basic and diluted weighted average shares outstanding:
Common shares			32,895,631				22,378,146
Unissued, directors' deferred compensation shares			232,091				178,090
			33,127,722				22,556,236
Dividends declared per share of common stock and paid in period		$	0.01			$	0.01
Dividends declared per share of
common stock and to be paid in quarter ended March 31		$	0.015			$	0.01

 

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

(2)

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PHX MINERALS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Three Months Ended December 31, 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, 2021			32,770,433			$	545,956			$	33,213,645			$	1,768,151			$	48,966,420				(388,545	)		$	(5,785,433	)		$	78,708,739
Net income (loss)			-				-				-				-				6,682,249												6,682,249
Private Placement			1,519,481				25,315				3,450,258				-				-				-				-				3,475,573
Purchase of treasury stock			-				-				-				-				-				(700	)			(1,855	)			(1,855	)
Restricted stock awards			-				-				255,844				-				-				-				-				255,844
Dividends ($0.025 per share)			-				-				-				-				(849,689	)			-				-				(849,689	)
Distribution of restricted stock    to officers and directors			115,373				1,921				(178,481	)			-				-				12,013				178,681				2,121
Increase in deferred directors'    compensation charged to    expense			-				-				-				67,570				-				-				-				67,570
Balances at December 31, 2021			34,405,287			$	573,192			$	36,741,266			$	1,835,721			$	54,798,980				(377,232	)		$	(5,608,607	)		$	88,340,552
(unaudited)

 

 

Three Months Ended December 31, 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, 2020			22,647,306			$	377,304			$	10,649,611			$	1,874,007			$	56,244,100				(411,487	)		$	(6,151,096	)		$	62,993,926
Net income (loss)			-				-				-				-				(596,720	)			-				-				(596,720	)
Equity offering			153,375				2,555				223,203				-				-				-				-				225,758
Restricted stock awards			-				-				122,978				-				-				-				-				122,978
Dividends ($0.02 per share)			-				-				-				-				(454,936	)			-				-				(454,936	)
Distribution of restricted stock    to officers and directors			-				-				(316,886	)			-				-				21,220				317,239				353
Increase in deferred directors'    compensation charged to    expense			-				-				-				44,527				-				-				-				44,527
Balances at December 31, 2020			22,800,681			$	379,859			$	10,678,906			$	1,918,534			$	55,192,444				(390,267	)		$	(5,833,857	)		$	62,335,886
(unaudited)

 

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

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PHX MINERALS INC.

CONDENSED STATEMENTS OF CASH FLOWS

 

		Three Months Ended December 31,
		2021				2020
Operating Activities		(unaudited)
Net income (loss)		$	6,682,249			$	(596,720	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			1,583,760				2,260,649
Impairment of producing properties			5,585				-
Provision for deferred income taxes			366,000				(69,000	)
Gain from leasing fee mineral acreage			(78,922	)			(232	)
Proceeds from leasing fee mineral acreage			95,039				232
Net (gain) loss on sales of assets			2,163,359				(30,862	)
Directors' deferred compensation expense			67,570				44,527
Total (gain) loss on derivative contracts			(2,836,168	)			254,036
Cash receipts (payments) on settled derivative contracts			-				613,314
Restricted stock awards			255,844				122,978
Other			37,138				14,387
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables			(1,591,085	)			(813,167	)
Other current assets			(325,780	)			(676,620	)
Accounts payable			(95,649	)			(398,556	)
Income taxes receivable			2,413,942				(12,545	)
Other non-current assets			10,253				30,958
Income taxes payable			165,889				-
Accrued liabilities			(281,034	)			(271,998	)
Total adjustments			1,955,741				1,068,101
Net cash provided by operating activities			8,637,990				471,381
Investing Activities
Capital expenditures			(192,677	)			(128,083	)
Acquisition of minerals and overriding royalty interests			(11,643,827	)			(7,869,746	)
Net proceeds from sales of assets			4,586,492				-
Net cash provided (used) by investing activities			(7,250,012	)			(7,997,829	)
Financing Activities
Borrowings under Credit Facility			4,000,000				-
Payments of loan principal			(1,500,000	)			(1,750,000	)
Net proceeds from equity issuance			(32,507	)			(24,242	)
Cash receipts from (payments on) off-market derivative contracts			(4,402,422	)			-
Payments of dividends			(332,210	)			(225,887	)
Net cash provided (used) by financing activities			(2,267,139	)			(2,000,129	)
Increase (decrease) in cash and cash equivalents			(879,161	)			(9,526,577	)
Cash and cash equivalents at beginning of period			2,438,511				10,690,395
Cash and cash equivalents at end of period		$	1,559,350			$	1,163,818
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid		$	517,479			$	229,049
Gross additions to properties and equipment		$	15,183,829			$	7,986,350
Equity offering used for acquisitions			(3,510,001	)			(250,000	)
Net (increase) decrease in accounts payable for properties and equipment additions			162,676				261,479
Capital expenditures and acquisitions		$	11,836,504			$	7,997,829

 

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

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PHX MINERALS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Basis of Presentation and Accounting Principles

Basis of Presentation

The accompanying unaudited condensed financial statements of PHX Minerals Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full fiscal year. The Company’s fiscal year runs from October 1 through September 30.

Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2021. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “PHX” or “Company” refer to PHX Minerals Inc.

Recent Accounting Pronouncements

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

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

NOTE 2: Revenues

Lease bonus revenue

The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932 (Extractive Activities—Oil and Gas), and upon leasing, it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral 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 months ended December 31, 2021 and 2020:

 

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

 

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 months ended December 31, 2021, revenue recognized during the reporting period related to performance obligations satisfied in prior reporting periods for existing wells was approximately $0.5 million and primarily due to change in price estimates. This is considered a change in estimate.   

As noted above, as a non-operator, there are instances when the Company is limited by the information operators provide to it. Through cash received on new wells, in the 2022 first quarter, the Company identified several producing properties on its minerals that had production dates prior to the 2022 first quarter. Estimates of the natural gas and oil sales related to those properties were made and are reflected in the first quarter natural gas, oil and NGL sales on the Company’s Statements of Operations and on the Company’s balance sheets in natural gas, oil and NGL sales receivables. In connection with obtaining more relevant information on new wells on Company acreage for the three months ended December 31, 2021, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $342,361 ,of which $83,569 related to the production periods before October 1, 2020 and $258,792 related to fiscal 2021.

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

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

As of December 31, 2021, the Company completed an evaluation of the expected realization of its gross deferred tax assets. Due to reversal of deferred tax assets in the current period, the Company is in a net deferred tax liability position as of December 31, 2021. The Company expects to realize its gross deferred tax assets against reversing deferred tax liabilities in future periods. Therefore, in the current period the Company released the valuation allowance against deferred tax assets. The Company continues to maintain a valuation allowance against certain state net operating loss carryforwards that are not expected to be utilized.  The Company’s effective tax rate for the three months ended December 31, 2021 was a 10% provision as compared to a 10% benefit for the three months ended December 31, 2020.

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

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

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

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

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

	Three Months Ended December 31,
	2021				2020
Basic EPS
Numerator:
Basic net income (loss)	$	6,682,249			$	(596,720	)
Denominator:
Basic weighted average shares outstanding		33,127,722				22,556,236
Basic EPS	$	0.20			$	(0.03	)
Diluted EPS
Numerator:
Basic net income (loss)	$	6,682,249			$	(596,720	)
Diluted net income (loss)		6,682,249				(596,720	)
Denominator:
Basic weighted average shares outstanding		33,127,722				22,556,236
Effects of dilutive securities:
Unvested restricted stock		-				-
Diluted weighted average shares outstanding		33,127,722				22,556,236
Diluted EPS	$	0.20			$	(0.03	)

 

 

NOTE 5: Long-Term Debt

The Company has a $100,000,000 credit facility (the “Credit Facility”) with a syndicate of banks led by Independent Bank pursuant to a credit agreement entered into in September 2021 (as amended, the “Credit Agreement”). The Credit Facility has a current borrowing base of $32,000,000 as of December 31, 2021, and a maturity date of September 1, 2025. The Credit Facility is secured by the Company’s personal property and at least 80% of the total value of the proved, developed and producing oil and gas properties. The interest rate is based on either (a) LIBOR plus an applicable margin ranging from 2.750% to 3.750% per annum based on the Company’s Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the U.S. Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on the Company’s Borrowing Base Utilization. The election of Independent Bank prime or LIBOR is at the Company’s discretion. The interest rate spread from Independent Bank prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At December 31, 2021, the effective interest rate was 3.75%.

The Company’s debt is recorded at the carrying amount on its balance sheets. The carrying amount of the debt under the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in “Other, net” on the Company’s balance sheets. Total debt issuance cost, net of amortization, as of December 31, 2021 was $288,247. The debt issuance cost is amortized over the life of the Credit Facility.

Determinations of the borrowing base under the Credit Facility are made semi-annually (usually June and December) or whenever the lending banks, in their sole discretion, believe that there has been a material change in the value of the Company’s natural gas and oil properties. The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain restrictions on the Company’s ability to incur debt, grant liens, make fundamental changes and engage in certain transactions with affiliates. The Credit Facility also restricts the Company’s ability to make certain restricted payments if before or after the Restricted Payment (i) the Available Commitment is less than ten percent (10%) of the Borrowing Base or (ii) the Leverage Ratio on a pro forma basis is greater than 2.50 to 1.00. In addition, the Company is required to maintain certain financial ratios, a current ratio (as described in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to EBITDAX (as defined in the Credit Facility) of no more than 3.5 to 1.0 based on the trailing twelve months. At December 31, 2021, the Company was in compliance with the covenants of the Credit Facility and had $20,000,000 in outstanding borrowings and had $12,000,000 available for borrowing under the Credit Facility. All capitalized terms in this description of the Credit Facility that are not otherwise defined in this Form 10-Q shall have the meaning assigned to them in the Credit Agreement.

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NOTE 6: Deferred Compensation Plan for Non-Employee Directors

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

NOTE 7: Restricted Stock Plan

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 months ended December 31, 2021 and 2020 related to the Company’s market-based, time-based and performance-based restricted stock:

 

		Three Months Ended
		December 31,
		2021				2020
Market-based, restricted stock		$	77,482			$	10,247
Time-based, restricted stock			178,362				112,731
Performance-based, restricted stock			-				-
Total compensation expense		$	255,844			$	122,978

 

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

 

		As of December 31, 2021
		Unrecognized Compensation Cost				Weighted Average Period (in years)
Market-based, restricted stock		$	569,027				1.97
Time-based, restricted stock			194,601				0.96
Performance-based, restricted stock			-
Total		$	763,628

 

NOTE 8: Properties and Equipment

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

		December 31, 2021				September 30, 2021
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		$	249,861,777			$	319,984,874
Non-producing natural gas and oil properties			54,960,073				40,466,098
Other property and equipment			883,310				794,179
			305,705,160				361,245,151
Less accumulated depreciation, depletion and amortization			(195,971,382	)			(257,643,661	)
Net properties and equipment		$	109,733,778			$	103,601,490

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Acquisitions

 

Quarter Ended		Net royalty acres (1)(2)				Purchase Price (1)		Area of Interest
December 31, 2021
			426			$5.8 million		Haynesville / LA
			847			$4.1 million		Haynesville / LA
			172			$1.4 million		SCOOP / OK
			103			$0.6 million		Haynesville / TX
			116			$1.7 million		Haynesville / LA
			220			$1.2 million		SCOOP / OK
December 31, 2020
			142			$1.0 million		Haynesville / TX
			184			$0.8 million		Haynesville / TX
			386			$3.5 million		Haynesville / TX
			297			$2.3 million		SCOOP / OK
(1) Excludes subsequent closing adjustments and insignificant acquisitions.
(2) An estimated net royalty equivalent was used for the minerals included in the net royalty acres.

 

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

Divestitures

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

 

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

 

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

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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 months ended December 31, 2021 and 2020, management’s assessment resulted in no impairment provisions on producing properties. The Company wrote off $5,585 on wells assigned with zero consideration received during the three months ended December 31, 2021.

NOTE 9: Derivatives

The Company has entered into commodity price derivative agreements, including fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas and oil. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. The Company’s derivative contracts are currently with BP Energy Company (“BP”). The derivative contracts with BP are secured under the Credit Facility with Independent Bank (see Note 5: Long-Term Debt). The derivative instruments have settled or will settle based on the prices below:

Derivative contracts in place as of December 31, 2021

 

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

 

The Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $6,545,877 as of December 31, 2021, and a net liability of $13,784,467 as of September 30, 2021. Cash receipts or payments in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods:

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	Three Months Ended
	December 31,
	2021				2020
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	-			$	(8,967	)
Natural gas fixed price swaps(1)		(1,352,192	)			(1,863	)
Oil costless collars		-				88,944
Oil fixed price swaps(1)		(362,139	)			535,200
Cash received (paid) on derivative contracts, net	$	(1,714,331	)		$	613,314
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	79,971			$	678,961
Natural gas fixed price swaps		4,477,934				288,887
Oil costless collars		-				(410,886	)
Oil fixed price swaps		(7,406	)			(1,424,312	)
Non-cash gain (loss) on derivative contracts, net	$	4,550,499			$	(867,350	)
Gains (losses) on derivative contracts, net	$	2,836,168			$	(254,036	)
(1) Excludes $2,688,091 of cash paid to settle off-market derivative contracts that are not reflected on the statement of operations.

 

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

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

 

		December 31, 2021																September 30, 2021
		Fair Value (a)																Fair Value (a)
		Commodity Contracts																Commodity Contracts
		Current Assets				Current Liabilities				Non-Current Assets				Non-Current Liabilities				Current Assets				Current Liabilities				Non-Current Liabilities
Gross amounts recognized		$	386,069			$	6,799,377			$	364,782			$	497,351			$	17,395			$	12,105,383			$	1,696,479
Offsetting adjustments			(386,069	)			(386,069	)			(364,782	)			(364,782	)			(17,395	)			(17,395	)			-
Net presentation on condensed balance sheets		$	-			$	6,413,308			$	-			$	132,569			$	-			$	12,087,988			$	1,696,479

 

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

 

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

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

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

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

 

		Fair Value Measurement at December 31, 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		$	-			$	(6,625,848	)		$	-			$	(6,625,848	)
Derivative Contracts - Collars		$	-			$	79,971			$	-			$	79,971

 

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

 

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

 

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

(a) When indicators of impairment are present, the Company assesses the carrying value of its natural gas and oil properties for impairment. This assessment utilizes estimates of future cash flows as well as other market data. Significant judgments and assumptions in these assessments include estimates of future natural gas, oil and NGL prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying values in excess of their calculated fair values.

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

NOTE 11: Commitments and Contingencies

Litigation

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

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NOTE 12: Subsequent Events

Derivative Contracts

Subsequent to December 31, 2021, the Company entered into new derivative contracts as summarized in the table below:

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

 

Acquisitions

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

ITEM 2

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

BUSINESS OVERVIEW

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

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

RESULTS OF OPERATIONS

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

THREE MONTHS ENDED DECEMBER 31, 2021 COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2020

Overview:

We recorded first quarter 2022 net income of $6,682,249, or $0.20 per share, as compared to a net loss of $596,720, or $0.03 per share, in the first fiscal 2021 quarter. The change in net income was principally the result of increased natural gas, oil and NGL sales, and an increase in non-cash gain on derivative contracts, partially offset by a loss on sales of assets. These items are further discussed below.

Revenue:

Natural Gas, Oil and NGL Sales:

	For the Three Months Ended December 31,
									Percent
	2021				2020				Incr. or (Decr.)
Natural gas, oil and NGL sales	$	13,687,164			$	6,424,979			113%

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

 

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

The production increase in royalty volumes during the three months ended December 31, 2021, as compared to the three months ended December 31, 2020, resulted from acquisition wells in the Haynesville Shale and SCOOP plays coming online.  The decrease in working interest volumes resulted from naturally declining production in high-interest wells in the Eagle Ford Shale and divestiture of low-value legacy working interest in Oklahoma.

Total production for the last five quarters was as follows:

 

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

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

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

 

 

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

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

 

Lease Bonuses and Rental Income:

	For the Three Months Ended December 31,
									Percent
	2021				2020				Incr. or (Decr.)
Lease bonuses and rental income	$	78,915			$	1,433			5,407%

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

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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 December 31,
									Percent
	2021				2020				Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net(1)	$	(1,714,331	)		$	613,314			(380%)
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	4,550,499			$	(867,350	)		625%
Gains (losses) on derivative contracts, net	$	2,836,168			$	(254,036	)		1,216%
	As of December 31,
	2021				2020
Fair value of derivative contracts
Net asset (net liability)	$	(6,545,877	)		$	(1,574,997	)		316%
(1) Excludes $2,688,091 of cash paid to settle off-market derivative contracts that are not reflected on the statement of operations.

The change in net (loss) gain on derivative contracts was due to the natural gas and oil collars and fixed price swaps being more beneficial in the quarter ended December 31, 2021 in relation to their respective contracted volumes and prices.

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

Costs and Expenses:

Lease Operating Expenses (LOE):

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

We are responsible for a portion of LOE relating to a well as a working interest owner. LOE includes normal recurring and nonrecurring expenses associated with our working interests necessary to produce hydrocarbons from our natural gas and oil wells, including maintenance, repairs, salt water disposal, insurance and workover expenses. Total LOE related to field operating costs increased $251,599, or 25%, in the 2022 quarter compared to the 2021 quarter. The increase in LOE was principally the result of increased workover expenses and inflation on services in the 2022 quarter.

Transportation, Gathering and Marketing:

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

Transportation, gathering and marketing decreased $67,361, or 5%, in the 2022 quarter compared to the 2021 quarter. The decrease in rate per Mcfe was primarily due to the divestiture of assets with higher deduct rates and the increase in natural gas sales in fields with lower deduct rates. Natural gas sales bear the large majority of our transportation, gathering and marketing fees.

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Production Taxes:

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

Production taxes are paid on produced natural gas and oil based on a percentage of revenues from products sold at both fixed and variable rates established by federal, state or local taxing authorities. Production taxes increased $402,921, or 146%, in the 2022 quarter as compared to the 2021 quarter. The increase in amount was primarily the result of increased natural gas, oil and NGL sales of $7,262,185 and increases in sales volumes from states with higher tax rates in the 2022 quarter as compared to the 2021 quarter.

 

Depreciation, Depletion and Amortization (DD&A):

	For the Three Months Ended December 31,
									Percent
	2021				2020				Incr. or (Decr.)
Depreciation, depletion and amortization	$	1,583,760			$	2,260,649			(30%)
Depreciation, depletion and amortization per MCFE	$	0.74			$	1.09			(32%)

DD&A is the amount of cost basis of natural gas and oil properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis for working interest, and on a straight-line basis for producing and non-producing minerals. Estimates of proved developed producing reserves are a major component of the calculation of depletion. DD&A decreased $676,889, or 30%, in the 2022 quarter compared to the 2021 quarter, of which $735,649 of the decrease resulted from a $0.35 decrease in the DD&A rate per Mcfe, partially offset by an increase of $58,760 resulting from production increasing 3% in the 2022 quarter. The rate decrease was mainly due to an increase in reserves during the 2022 quarter, as compared to the 2021 quarter.

Provision for Impairment:

We had a $5,585 provision for impairment in the 2022 quarter as compared to no provision for impairment in the 2021 quarter. During the 2022 quarter, impairment was related to working interest wells that we wrote off and assigned the interests to the operator.

Interest expense:

	For the Three Months Ended December 31,
									Percent
	2021				2020				Incr. or (Decr.)
Interest expense	$	176,719			$	301,898			(41%)
Weighted average debt outstanding	$	18,206,522			$	27,796,196			(34%)

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

Income Tax Expense:

	For the Three Months Ended December 31,
									Percent
	2021				2020				Incr. or (Decr.)
Provision (benefit) for income taxes	$	762,000			$	(69,000	)		1,204%

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

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

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General and Administrative Costs (G&A):

	For the Three Months Ended December 31,
									Percent
	2021				2020				Incr. or (Decr.)
General and administrative	$	2,095,557			$	1,731,097			21%

G&A are costs not directly associated with the production of natural gas and oil and include the cost of employee salaries and related benefits, office expenses and fees for professional services. G&A for the 2022 quarter increased $364,460 as compared to the 2021 quarter. The increase was primarily due to increased activity during the 2022 quarter.

LIQUIDITY AND CAPITAL RESOURCES

We had positive working capital (current assets less current liabilities excluding current derivatives) of $7,619,319 at December 31, 2021, compared to positive working capital of $9,175,126 at September 30, 2021.

Liquidity:

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

 

Net cash provided (used) by:		For the Three Months Ended December 31,
		2021				2020				Change
Operating activities		$	8,637,990			$	471,381			$	8,166,609
Investing activities			(7,250,012	)			(7,997,829	)			747,817
Financing activities			(2,267,139	)			(2,000,129	)			(267,010	)
Increase (decrease) in cash and cash equivalents		$	(879,161	)		$	(9,526,577	)		$	8,647,416

Operating activities:

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

•

Receipts on natural gas, oil and NGL sales (net of production taxes and gathering, transportation and marketing costs) and other increasing by $6,594,748;

•

Increased income tax receipts of $2,196,377;

•

Decreased interest payments of $115,788;

•

Decreased field operating expenses of $310,058;

•

Increased lease bonus receipts of $94,807;

•

Increased payments for G&A and other expense of $531,855; and

•

Decreased net receipts from derivative contracts of $613,314.

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Investing activities:

Net cash used by investing activities decreased $747,817 during the 2022 period, as compared to the 2021 period, primarily due to higher net proceeds from the sale of assets of $4,586,492, partially offset by higher acquisition costs of $3,774,081 and higher payments of $64,594 for drilling and completion activity during the 2022 period.

Financing activities:

Net cash used by financing activities increased $267,010 during the 2022 period, as compared to the 2021 period, primarily due to increased cash payments on off-market derivative contracts of $4,402,422 and an increase of $106,323 in dividend payments, which were partially offset by higher net borrowings on long-term debt of $2,500,000 in the 2022 period compared to net payments of $1,750,000 in the 2021 period.

Capital Resources:

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

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

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

Quarter Ended		Net royalty acres (1)(2)				Purchase Price (1)		Area of Interest
December 31, 2021
			426			$5.8 million		Haynesville / LA
			847			$4.1 million		Haynesville / LA
			172			$1.4 million		SCOOP / OK
			103			$0.6 million		Haynesville / TX
			116			$1.7 million		Haynesville / LA
			220			$1.2 million		SCOOP / OK
September 30, 2021
			817			$7.3 million		Haynesville / LA, TX
June 30, 2021
			262			$1.3 million		Haynesville / LA
			131			$1.0 million		Haynesville / TX
			2,514			$13.0 million		SCOOP / OK
March 31, 2021
		No significant acquisitions
December 31, 2020
			142			$1.0 million		Haynesville / TX
			184			$0.8 million		Haynesville / TX
			386			$3.5 million		Haynesville / TX
			297			$2.3 million		SCOOP / OK
(1) Excludes subsequent closing adjustments and insignificant acquisitions.
(2) An estimated net royalty equivalent was used for the minerals included in the net royalty acres  .

We received lease bonus payments during the first fiscal 2022 quarter totaling approximately $0.1 million. Management plans to continue to actively pursue leasing opportunities.

With continued natural gas and oil price volatility, management continues to evaluate opportunities for product price protection through additional hedging of our future natural gas and oil production. 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 December 31, 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:

		Three Months Ended
		December 31, 2021
Cash provided by operating activities		$	8,637,990
Cash provided (used) by:
Capital expenditures - acquisitions			(11,643,827	)
Capital expenditures - drilling and completion of wells			(192,677	)
Quarterly dividends of $0.01 per share			(332,210	)
Net borrowings (payments) on credit facility			2,500,000
Net proceeds from sale of assets			4,586,492
Cash receipts from (payments on) off-market derivative contracts			(4,402,422	)
Net proceeds from equity issuance			(32,507	)
Net cash used			(9,517,151	)
Net increase (decrease) in cash		$	(879,161	)

 

Outstanding borrowings on the Credit Facility at December 31, 2021 were $20,000,000.

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

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

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

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

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

 

CONTRACTUAL OBLIGATIONS

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

ITEM 3

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Natural gas, oil and NGL prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of natural gas, oil and NGL price trends, and there remains a wide divergence in the opinions held in the industry. We can be significantly impacted by changes in natural gas and oil prices. The market price of natural gas, oil and NGL in 2022 will impact the amount of cash generated from operating activities, which will in turn impact the level of our capital expenditures for acquisitions and production. Excluding the impact of our 2022 derivative contracts, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $669,972 for operating revenue based on our prior year natural gas volumes. The price sensitivity in 2022 for each $1.00 per barrel change in wellhead oil is approximately $224,479 for operating revenue based on our prior year oil volumes.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to our Credit Facility. Interest under our Credit Facility is calculated based on either (a) LIBOR plus an applicable margin ranging from 2.750% to 3.750% per annum based on our Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the U.S. Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on our Borrowing Base Utilization. Under the terms of the Credit Facility, a 5% interest penalty may apply to any outstanding amount not paid when due or that remains outstanding while an event of default exists. At December 31, 2021, we had $20,000,000 outstanding under the Credit Facility and the effective interest rate was 3.75%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of $200,000 for the three months ended December 31, 2021, assuming that our indebtedness remained constant throughout the period. At this point, we do not believe that our liquidity has been materially affected by the debt market uncertainties noted in the last few years, and we do not believe that our liquidity will be significantly impacted in the near future. All capitalized terms in this description of the interest rate under the Credit Facility that are not otherwise defined in this Form 10-Q shall have the meaning assigned to them in the Credit Agreement.

ITEM 4

CONTROLS AND PROCEDURES

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

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

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

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.

ITEM 1A   RISK FACTORS

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

ITEM 2

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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 and (ii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. We did not make any repurchases of shares of our Common Stock during the fiscal quarter ended December 31, 2021.

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.

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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 10-K filed December 13, 2021).
				*Exhibit 10.1 – Purchase and Sale Agreement, dated November 10, 2021, by and between PHX Minerals Inc., as Buyer, and Vendera Resources III, LP and Vendera Management III LLC, collectively as Seller (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed November 12, 2021).
				*Exhibit 10.2 – Purchase and Sale Agreement, dated December 6, 2021, by and among PHX Minerals Inc., as Buyer, and Merrimac Properties Partners, LLC and Quarter Horse Energy Partners, LLC, collectively as Seller (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed December 9, 2021).
				*Exhibit 10.3 – Purchase and Sale Agreement, dated December 6, 2021, by and between PHX Minerals Inc., as Buyer, and Palmetto Investment Partners II, LLC, as Seller (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed December 9, 2021).
				*Exhibit 10.4 – First Amendment to Credit Agreement dated as of December 6, 2021, by and among PHX Minerals Inc., each lender party thereto, and Independent Bank, as Administrative Agent and L/C Issuer (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed December 9, 2021).
				Exhibit 31.1 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Executive Officer
				Exhibit 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Financial Officer
				Exhibit 32.1 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002 by Chief Executive Officer
				Exhibit 32.2 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002 by Chief Financial Officer
				Exhibit 101.INS – XBRL Instance Document
				Exhibit 101.SCH – XBRL Taxonomy Extension Schema Document
				Exhibit 101.CAL – XBRL Taxonomy Extension Calculation Linkbase Document
				Exhibit 101.LAB – XBRL Taxonomy Extension Labels Linkbase Document
				Exhibit 101.PRE – XBRL Taxonomy Extension Presentation Linkbase Document
				Exhibit 101.DEF – XBRL Taxonomy Extension Definition Linkbase Document Exhibit 104 – Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
			*	The Purchase and Sale Agreement contains schedules and exhibits that have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to furnish a supplemental copy of any such omitted exhibit or schedule to the SEC upon request.

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.
February 14, 2022		/s/ Chad L. Stephens
Date		Chad L. Stephens, President,
		Chief Executive Officer
February 14, 2022		/s/ Ralph D’Amico
Date		Ralph D’Amico, Vice President,
		Chief Financial Officer

 

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