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, 2023

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

For the transition period from to

Commission File Number 001-31759

PHX MINERALS INC.

(Exact name of registrant as specified in its charter)

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

1320 South University Drive, Suite 720, Fort Worth, Texas 76107

(Address of principal executive offices)

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

Emerging growth company ☐

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

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

Outstanding shares of Common Stock at August 7, 2023: 37,000,340 shares.

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements		1
		Condensed Balance Sheets – June 30, 2023 and December 31, 2022		1
		Condensed Statements of Operations – Three and six months ended June 30, 2023 and 2022		2
		Statements of Stockholders’ Equity – Six months ended June 30, 2023 and 2022		3
		Condensed Statements of Cash Flows – Six months ended June 30, 2023 and 2022		5
		Notes to Condensed Financial Statements		6
	Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations		16
	Item 3	Quantitative and Qualitative Disclosures about Market Risk		27
	Item 4	Controls and Procedures		27
Part II	Other Information
	Item 1	Legal Proceedings		28
	Item 1A	Risk Factors		28
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		28
	Item 6	Exhibits		29
	Signatures		29

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 Form 10-Q 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, 2022 (“Annual Report”), and any quarterly or transition reports on Form 10-Q filed subsequently thereto, including any risks described in Item 1A of this Form 10-Q. Investors should also read the other information in this Form 10-Q and the Annual Report where risk factors are presented and further discussed.

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

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

Glossary of Certain Terms

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

ASC	Accounting Standards Codification.
ASU	Accounting Standards Update.
Bbl	Barrel.
Board	Board of directors of the Company.
BTU	British Thermal Units.
Common Stock	Common Stock, par value $0.01666 per share, of the Company.
completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.
DD&A	Depreciation, depletion and amortization.
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)	Cawley, Gillespie & Associates.
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.
SOFR	The Secured Overnight Financing Rate.
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.

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, 2023			December 31, 2022
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	1,267,627		$	2,115,652
Natural gas, oil, and NGL sales receivables (net of $0 allowance for uncollectable accounts)		5,839,904			9,783,996
Refundable income taxes		675,268			-
Held for sale assets		-			6,420,051
Derivative contracts, net		1,371,377			-
Other		370,896			1,543,956
Total current assets		9,525,072			19,863,655
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		189,868,020			181,431,139
Non-producing natural gas and oil properties		61,180,555			57,781,644
Other		1,347,124			1,122,436
		252,395,699			240,335,219
Less accumulated depreciation, depletion and amortization		(110,426,239	)		(107,085,212	)
Net properties and equipment		141,969,460			133,250,007
Derivative contracts, net		-			141,345
Operating lease right-of-use assets		640,799			706,871
Other, net		596,874			695,399
Total assets	$	152,732,205		$	154,657,277
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	270,780		$	504,466
Derivative contracts, net		-			1,534,034
Income taxes payable		-			576,427
Current portion of operating lease liability		226,389			217,656
Held for sale liabilities		-			889,155
Accrued liabilities and other		1,342,795			3,121,522
Total current liabilities		1,839,964			6,843,260
Long-term debt		23,750,000			33,300,000
Deferred income taxes, net		5,132,906			2,453,906
Asset retirement obligations		1,041,177			1,027,777
Derivative contracts, net		83,857			-
Operating lease liability, net of current portion		814,169			929,208
Total liabilities		32,662,073			44,554,151
Stockholders' equity:
Common Stock, $0.01666 par value; 54,000,500 shares authorized and   35,938,900 issued at June 30, 2023; 54,000,500 shares authorized and 35,938,206 issued at December 31, 2022		598,742			598,731
Capital in excess of par value		43,782,600			43,344,916
Deferred directors' compensation		1,368,956			1,541,070
Retained earnings		77,555,195			68,925,774
		123,305,493			114,410,491
Less treasury stock, at cost; 225,723 shares at June 30, 2023, and 300,272 shares    at December 31, 2022		(3,235,361	)		(4,307,365	)
Total stockholders' equity		120,070,132			110,103,126
Total liabilities and stockholders' equity	$	152,732,205		$	154,657,277

(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,						Six Months Ended June 30,
	2023			2022			2023			2022
Revenues:	(unaudited)						(unaudited)
Natural gas, oil and NGL sales	$	7,231,164		$	19,561,568		$	19,088,411		$	34,345,433
Lease bonuses and rental income		111,991			209,329			425,141			371,237
Gains (losses) on derivative contracts		183,006			(2,387,226	)		3,985,826			(15,370,632	)
	$	7,526,161		$	17,383,671			23,499,378		$	19,346,038
Costs and expenses:
Lease operating expenses		314,150			900,807			859,917			1,830,261
Transportation, gathering and marketing		906,373			1,430,136			2,035,129			2,918,654
Production taxes		461,893			925,197			1,043,326			1,622,590
Depreciation, depletion and amortization		2,210,332			2,022,832			4,100,322			4,143,948
Provision for impairment		-			6,277			2,073			6,277
Interest expense		524,294			286,345			1,081,767			516,557
General and administrative		3,177,103			2,877,614			6,159,012			5,621,878
Losses (gains) on asset sales and other		139,307			(630,547	)		(4,195,121	)		(2,891,682	)
Total costs and expenses		7,733,452			7,818,661			11,086,425			13,768,483
Income (loss) before provision (benefit) for income taxes		(207,291	)		9,565,010			12,412,953			5,577,555
Provision (benefit) for income taxes		(166,000	)		976,000			2,901,000			1,009,000
Net income (loss)	$	(41,291	)	$	8,589,010		$	9,511,953		$	4,568,555
Basic and diluted earnings (loss) per common share (Note 4)	$	(0.00	)	$	0.25		$	0.26		$	0.13
Weighted average shares outstanding:
Basic		35,965,281			34,652,155			35,950,615			34,473,247
Diluted		35,965,281			34,851,214			36,034,438			34,473,247
Dividends per share of common stock paid in period	$	0.0225		$	0.02		$	0.045		$	0.035

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

(2)

PHX MINERALS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Six Months Ended June 30, 2023

					Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total
Balances at December 31, 2022		35,938,206	$	598,731	$	43,344,916		$	1,541,070		$	68,925,774			(300,272	)	$	(4,307,365	)	$	110,103,126
Net income (loss)		-		-		-			-			9,553,244			-			-			9,553,244
Restricted stock award expense		-		-		580,998			-			-			-			-			580,998
Dividends		-		-		-			-			(50,034	)		-			-			(50,034	)
Distribution of restricted stock    to employees and directors		-		-		(766,846	)		-			-			53,476			766,846			-
Distribution of deferred    directors' compensation		-		-		(24,330	)		(281,497	)		-			21,312			305,827			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			53,589			-			-			-			53,589
Balances at March 31, 2023		35,938,206	$	598,731	$	43,134,738		$	1,313,162		$	78,428,984			(225,484	)	$	(3,234,692	)	$	120,240,923
(unaudited)
Net income (loss)												(41,291	)								(41,291	)
Purchase of treasury stock		-		-		-			-			-			(239	)		(669	)		(669	)
Restricted stock awards		-		-		647,873			-			-			-			-			647,873
Dividends		-		-		-			-			(832,498	)		-			-			(832,498	)
Distribution of restricted stock    to employees and directors		694		11		(11	)		-			-			-			-			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			55,794			-			-			-			55,794
Balances at June 30, 2023		35,938,900	$	598,742	$	43,782,600		$	1,368,956		$	77,555,195			(225,723	)	$	(3,235,361	)	$	120,070,132
(unaudited)

(3)

Six Months Ended June 30, 2022

					Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total
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
Net income (loss)		-		-		-			-			(4,020,455	)		-			-			(4,020,455	)
Cost of equity issuance		-		-		(48,166	)		-			-			-			-			(48,166	)
At-the-market offering		2,710		45		7,972			-			-			-			-			8,017
Restricted stock award expense		-		-		433,137			-			-			-			-			433,137
Distribution of deferred    directors' compensation		61,452		1,024		462,735			(463,759	)		-			-			-			-
Increase in deferred directors'    compensation charged to    expense		-		-		-			35,461			-			-			-			35,461
Balances at March 31, 2022		34,469,449	$	574,261	$	37,596,944		$	1,407,423		$	50,778,525			(377,232	)	$	(5,608,607	)	$	84,748,546
(unaudited)
Net income (loss)		-		-		-			-			8,589,010			-			-			8,589,010
At-the-market offering		1,211,521		20,184		4,722,585			-			-			-			-			4,742,769
Restricted stock awards		-		-		530,066			-			-			-			-			530,066
Dividends		-		-		-			-			(691,488	)		-			-			(691,488	)
Increase in deferred directors'    compensation charged to    expense		-		-		-			44,267			-			-			-			44,267
Balances at June 30, 2022		35,680,970	$	594,445	$	42,849,595		$	1,451,690		$	58,676,047			(377,232	)	$	(5,608,607	)	$	97,963,170
(unaudited)

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

(4)

PHX MINERALS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2023			2022
Operating Activities	(unaudited)
Net income (loss)	$	9,511,953		$	4,568,555
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		4,100,322			4,143,948
Impairment of producing properties		2,073			6,277
Provision for deferred income taxes		2,679,000			(159,000	)
Gain from leasing fee mineral acreage		(425,141	)		(370,131	)
Proceeds from leasing fee mineral acreage		488,173			450,881
Net (gain) loss on sales of assets		(4,428,212	)		(3,028,394	)
Directors' deferred compensation expense		109,383			79,728
Total (gain) loss on derivative contracts		(3,985,826	)		15,370,632
Cash receipts (payments) on settled derivative contracts		1,865,779			(1,215,245	)
Restricted stock award expense		1,228,871			963,203
Other		70,526			18,515
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables		3,944,092			(3,760,490	)
Other current assets		405,055			247,518
Accounts payable		(228,305	)		(155,410	)
Income taxes receivable		(675,268	)		(860,416	)
Other non-current assets		95,283			(403,745	)
Income taxes payable		(576,427	)		(499,939	)
Accrued liabilities		(332,066	)		304,497
Total adjustments		4,337,312			11,132,429
Net cash provided by operating activities		13,849,265			15,700,984
Investing Activities
Capital expenditures		(275,419	)		(158,847	)
Acquisition of minerals and overriding royalty interests		(11,914,003	)		(18,228,580	)
Net proceeds from sales of assets		9,223,405			3,265,897
Net cash provided (used) by investing activities		(2,966,017	)		(15,121,530	)
Financing Activities
Borrowings under Credit Facility		6,000,000			10,300,000
Payments of loan principal		(15,550,000	)		(2,000,000	)
Net proceeds from equity issuance		-			4,702,619
Cash receipts from (payments on) off-market derivative contracts		(560,162	)		(9,443,174	)
Purchases of treasury stock		(669	)		-
Payments of dividends		(1,620,442	)		(1,208,967	)
Net cash provided (used) by financing activities		(11,731,273	)		2,350,478
Increase (decrease) in cash and cash equivalents		(848,025	)		2,929,932
Cash and cash equivalents at beginning of period		2,115,652			1,559,350
Cash and cash equivalents at end of period	$	1,267,627		$	4,489,282
Supplemental Disclosures of Cash Flow Information:
Interest paid (net of capitalized interest)	$	1,155,637		$	487,487
Income taxes paid (net of refunds received)	$	1,473,696		$	2,528,356
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid	$	-		$	-
Gross additions to properties and equipment	$	12,952,046		$	18,248,046
Net increase (decrease) in accounts receivable for properties and equipment additions		(762,624	)		139,381
Capital expenditures and acquisitions	$	12,189,422		$	18,387,427

(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 a full fiscal year.

As previously disclosed, in December 2022, the Board approved a change in the Company’s fiscal year end from September 30 to December 31 to be in-line with our peer group. As a result, the Company’s current fiscal year runs from January 1, 2023 through December 31, 2023, and therefore references in this Form 10-Q to 2023 refer to the annual period from January 1, 2023 through December 31, 2023.

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, 2022. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “PHX” or the “Company” refer to PHX Minerals Inc.

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 Company’s financial statements upon adoption.

NOTE 2: Revenues

Revenues from contracts with customers

Natural gas, oil and NGL sales

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

Disaggregation of natural gas, oil and NGL revenues

The following table presents the disaggregation of the Company's natural gas, oil and NGL revenues for the three and six months ended June 30, 2023 and 2022:

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	Three Months Ended June 30, 2023						Six Months Ended June 30, 2023
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	3,171,443	$	388,160	$	3,559,603	$	9,357,464	$	1,112,910	$	10,470,374
Oil revenue		2,659,813		369,530		3,029,343		6,092,763		1,049,367		7,142,130
NGL revenue		386,407		255,811		642,218		891,177		584,730		1,475,907
Natural gas, oil and NGL sales	$	6,217,663	$	1,013,501	$	7,231,164	$	16,341,404	$	2,747,007	$	19,088,411
	Three Months Ended June 30, 2022						Six Months Ended June 30, 2022
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	8,457,521	$	4,494,665	$	12,952,186	$	14,078,545	$	7,409,634	$	21,488,179
Oil revenue		3,340,065		1,808,814		5,148,879		5,890,527		3,970,058		9,860,585
NGL revenue		675,829		784,674		1,460,503		1,383,337		1,613,332		2,996,669
Natural gas, oil and NGL sales	$	12,473,415	$	7,088,153	$	19,561,568	$	21,352,409	$	12,993,024	$	34,345,433

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 quarters ended June 30, 2023 and 2022, revenue recognized during the reporting period related to performance obligations satisfied in prior reporting periods for existing wells was 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. Through cash received on new wells, in the quarters ended June 30, 2023 and 2022, the Company identified several producing properties on its minerals that had production dates prior to the quarters ended June 30, 2023 and 2022. Estimates of the natural gas and oil sales related to those properties were made and are reflected in the 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 during the quarters ended June 30, 2023 and June 30, 2022, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $216,317 of which $35,625 related to the production periods before January 1, 2023 and $180,692 related to the three months ended March 31, 2023, and the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $894,099 of which $333,817 related to the production periods before January 1, 2022 and $560,282 related to the three months ended March 31, 2022, respectively.

Lease bonus revenue

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

Natural gas and oil derivative contracts

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

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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 June 30, 2023, the Company completed an evaluation of the expected realization of its gross deferred tax assets. As a result of its evaluation, the Company concluded a valuation allowance is required for certain state deferred tax assets and for the quarter ended June 30, 2023, the change in the Company’s valuation allowance from December 31, 2022 is a decrease of $7,000 recorded in the income tax provision. The Company’s effective tax rate for the six months ended June 30, 2023 was a 23% provision as compared to an 18% provision for the six months ended June 30, 2022.

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

Basic 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. 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 and any other potentially dilutive shares of Common Stock, during the period. Participating securities had no effect on basic and diluted EPS at June 30, 2023.

For the three and six months ended June 30, 2023 and 2022, the Company excluded restricted stock in the diluted EPS calculation that would have been antidilutive. The average shares outstanding of restricted stock excluded from the diluted EPS was 692,685 and 556,555, respectively, for the three and six months ended June 30, 2023, and 720,254 and 445,943, respectively, for the three and six months ended June 30, 2022.

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2023			2022		2023		2022
Basic EPS
Numerator:
Basic net income (loss)	$	(41,291	)	$	8,589,010	$	9,511,953	$	4,568,555
Denominator:
Common Shares		35,713,335			34,438,807		35,705,890		34,248,566
Unissued, directors' deferred compensation shares		251,946			213,348		244,725		224,681
Basic weighted average shares outstanding		35,965,281			34,652,155		35,950,615		34,473,247
Basic EPS	$	(0.00	)	$	0.25	$	0.26	$	0.13
Diluted EPS
Numerator:
Basic net income (loss)	$	(41,291	)	$	8,589,010	$	9,511,953	$	4,568,555
Diluted net income (loss)		(41,291	)		8,589,010		9,511,953		4,568,555
Denominator:
Basic weighted average shares outstanding		35,965,281			34,652,155		35,950,615		34,473,247
Effects of dilutive securities:
Unvested restricted stock		-			199,059		83,823		-
Diluted weighted average shares outstanding		35,965,281			34,851,214		36,034,438		34,473,247
Diluted EPS	$	(0.00	)	$	0.25	$	0.26	$	0.13

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 had a borrowing base of $45,000,000 as of June 30, 2023, and has a maturity date of September 1, 2025. The Credit Facility is secured by the Company’s personal property and at least 75% of the total value of the proved, developed and producing oil and gas properties. The interest rate is based on either (a) SOFR 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 SOFR is at the Company’s discretion. The interest rate spread from Independent Bank prime or SOFR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from SOFR or the prime rate increases as a larger percent of the borrowing base is advanced. At June 30, 2023, the effective interest rate was 8.45%.

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 June 30, 2023 was $240,533. 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 June 30, 2023, the Company was in compliance with the covenants of the Credit Facility, had $23,750,000 in outstanding borrowings and had $21,250,000 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 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: Long Term Incentive Plan

On January 31, 2023, the Company granted shares of Common Stock in the form of time-based and market-based restricted stock to the employees and officers of the Company. Officers were awarded 299,900 market-based shares with a fair value on their award date of $1,541,893. Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 97,053 time-based shares with a fair value on the award date of $350,362. The shares issued to employees time-vest ratably over a three-year period ending in December of 2025, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December of 2025. All shares granted on January 31, 2023 have voting rights during the vesting period.

On April 20, 2023, the Company granted 92,544 shares of Common Stock in the form of time-based restricted stock to the non-employee directors of the Company, which had a fair value of $243,390. The shares of restricted stock fully vest in December 2023 and have voting rights during the vesting period.

Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized at the time of forfeiture. The following table summarizes the Company’s pre-tax compensation expense for the three and six months ended June 30, 2023 and 2022 related to the Company’s market-based, time-based and performance-based restricted stock:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
Market-based, restricted stock	$	523,408	$	313,728	$	1,046,818	$	627,600
Time-based, restricted stock		124,465		216,338		182,053		335,603
Total compensation expense	$	647,873	$	530,066	$	1,228,871	$	963,203

A summary of the Company’s unrecognized compensation cost for its unvested market-based and time-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, 2023
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	1,491,657		1.46
Time-based, restricted stock		615,489		1.66
Total	$	2,107,146

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NOTE 8: Properties and Equipment

Acquisitions

The Company made the following property acquisitions during the six-month periods ended June 30, 2023 and 2022.

Quarter Ended	Net royalty acres (1)(2)	Cash Paid	Total Purchase Price (1)	Area of Interest
June 30, 2023
	151	$1.8 million	$1.8 million	Haynesville / SCOOP
March 31, 2023
	913	$10.8 million	$10.8 million	Haynesville / SCOOP
June 30, 2022
	938	$9.1 million	$9.1 million	Haynesville / SCOOP
March 31, 2022
	825	$9.3 million	$9.3 million	Haynesville / SCOOP

(1) Excludes subsequent closing adjustments and insignificant acquisitions.

(2) An estimated net royalty equivalent was used for the unleased minerals included in the net royalty acres.

All purchases made in 2023 and 2022 were for mineral and royalty acreage and were accounted for as asset acquisitions.

Divestitures

The Company made the following property divestitures during the six-month periods ended June 30, 2023 and 2022. Revenue and expenses recognized between the effective date and close date of divestitures is recorded in the Operating Activities section in the Statements of Cash Flows.

Quarter Ended	Net mineral acres(1)/ Wellbores(2)	Sale Price (3)	Gain/(Loss) (3)	Location
June 30, 2023
	No significant divestitures
March 31, 2023
	757 acres	$0.3 million	$0.3 million	OK / TX
	268 wellbores	$10.7 million	$4.1 million (4)	OK / TX
June 30, 2022
	2,381 acres	$0.5 million	$0.5 million	AR / OK / TX
	27 wellbores	$0.5 million	$0.2 million	OK
March 31, 2022
	7,201 acres	$2.1 million	$2.1 million	NM / TX

(1) Number of net mineral acres sold.

(2) Number of gross wellbores associated with working interests sold.

(3) Excludes subsequent closing adjustments and insignificant divestitures.

(4) Excludes $6.1 million loss recognized as an impairment in the quarter ended December 31, 2022 related to assets and liabilities held for sale as of December 31, 2022.

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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.

Assets and liabilities held for sale

In the quarter ended December 31, 2022, the Company entered into two agreements to sell working interest in the Arkoma Basin and the Eagle Ford Play, and the Company recorded an impairment of $6.1 million to reduce the net book value of the working interest in the Arkoma Basin to fair value less cost to sell. As of December 31, 2022, the Arkoma Basin and Eagle Ford Play working interests had a net carrying value of approximately $5.5 million and were considered held for sale, resulting in the reclassification of $6.4 million of properties, plants and equipment (PP&E) to “Held for sale assets” and $0.9 million of asset retirement obligations, to “Held for sale liabilities” on the balance sheet. The Company received $0.8 million in deposits related to the held for sale assets recorded in “Accrued liabilities and other” on the balance sheet during the quarter ended December 31, 2022. These two divestitures closed in January 2023.

Impairment

Company management monitors all long-lived assets, principally natural gas and oil properties, for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates; future drilling and completion costs; future sales prices for natural gas, oil and NGL; future production costs; estimates of future natural gas, oil and NGL reserves to be recovered and the timing thereof; the economic and regulatory climates; and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to natural gas, oil and NGL reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For the three and six months ended June 30, 2023 and 2022, management’s assessment resulted in no impairment provisions on producing properties. The Company wrote off $2,073 and $6,277 on wells assigned to the operator with zero consideration received during the six months ended June 30, 2023 and 2022, 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 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:

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Derivative Contracts in Place as of June 30, 2023

Calendar Period	Contract total volume	Index	Contract average price
Natural gas costless collars
2023	480,000 Mmbtu	NYMEX Henry Hub	$3.34 floor / $6.21 ceiling
2024	1,025,000 Mmbtu	NYMEX Henry Hub	$3.77 floor / $6.18 ceiling
2025	270,000 Mmbtu	NYMEX Henry Hub	$3.25 floor / $5.25 ceiling
Natural gas fixed price swaps
2023	1,000,000 Mmbtu	NYMEX Henry Hub	$3.24
2024	780,000 Mmbtu	NYMEX Henry Hub	$3.33
Oil costless collars
2023	2,500 Bbls	NYMEX WTI	$75.00 floor / $96.00 ceiling
2024	23,450 Bbls	NYMEX WTI	$64.11 floor / $76.28 ceiling
Oil fixed price swaps
2023	33,250 Bbls	NYMEX WTI	$74.91
2024	10,200 Bbls	NYMEX WTI	$65.69
2025	4,800 Bbls	NYMEX WTI	$64.80

Derivative Settlements during the Three Months Ended June 30, 2023

				Settlement
Contract period (1)	Production volume	Index	Contract price	(paid) received
Natural gas costless collars
April - June 2023	20,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $4.70 ceiling	$	54,220
April - June 2023	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $7.00 ceiling	$	421,100
Natural gas fixed price swaps
April - June 2023	100,000 Mmbtu	NYMEX Henry Hub	$3.37	$	382,100
April - June 2023	20,000 Mmbtu	NYMEX Henry Hub	$3.57	$	88,420
April - June 2023	20,000 Mmbtu	NYMEX Henry Hub	$3.58	$	89,020
June 2023	50,000 Mmbtu	NYMEX Henry Hub	$2.52	$	16,950
Oil costless collars
March - May 2023	2,500 Bbls	NYMEX WTI	$75.00 floor / $96.00 ceiling	$	12,515
Oil fixed price swaps
March 2023	1,000 Bbls	NYMEX WTI	$64.00	$	(9,373	)
March - May 2023	1,500 Bbls	NYMEX WTI	$67.55	$	(32,673	)
March - May 2023	750 Bbls	NYMEX WTI	$70.05	$	(10,711	)
March - May 2023	1,500 Bbls	NYMEX WTI	$80.80	$	26,952
April - May 2023	1,000 Bbls	NYMEX WTI	$80.74	$	10,421
			Total (paid) received	$	1,048,941

(1) Natural gas derivatives settle at first of the month pricing and oil derivatives settle at a monthly daily average.

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 asset of $1,287,520 as of June 30, 2023, and a net liability of $1,392,689 as of December 31, 2022. 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						Six Months Ended
	June 30,						June 30,
	2023			2022			2023			2022
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	475,320		$	(653,495	)	$	1,190,910		$	(805,685	)
Natural gas fixed price swaps(1)		576,490			(3,562,961	)		659,590			(4,037,896	)
Oil costless collars		12,515			-			12,515			-
Oil fixed price swaps(1)		(15,384	)		(1,453,691	)		(183,653	)		(2,037,332	)
Cash received (paid) on derivative contracts, net	$	1,048,941		$	(5,670,147	)	$	1,679,362		$	(6,880,913	)
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(488,755	)	$	926,778		$	94,846		$	(538,825	)
Natural gas fixed price swaps		(521,078	)		1,853,506			1,652,299			(5,833,392	)
Oil costless collars		29,131			(38,910	)		51,394			(38,910	)
Oil fixed price swaps		114,767			541,547			507,925			(2,078,592	)
Non-cash gain (loss) on derivative contracts, net	$	(865,935	)	$	3,282,921		$	2,306,464		$	(8,489,719	)
Gains (losses) on derivative contracts, net	$	183,006		$	(2,387,226	)	$	3,985,826		$	(15,370,632	)

(1) For the six months ended June 30, 2023, excludes $373,745 of cash paid to settle off-market derivative contracts that are not reflected on the Condensed Statements of Operations. For the three and six months ended June 30, 2022, excludes $1,284,024 and $3,777,505, respectively, of cash paid to settle off-market derivative contracts that are not reflected on the Condensed Statements of Operations. Total cash paid related to off-market derivatives was $560,162 and $9,443,174, respectively, for the six months ended June 30, 2023 and 2022 and is reflected in the Financing Activities section of the Condensed Statements of Cash Flows.

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

The following table summarizes and reconciles the Company’s derivative contracts’ fair values at a gross level back to net fair value presentation on the Company’s balance sheets at June 30, 2023 and December 31, 2022. The Company has offset all amounts subject to master netting agreements in the Company's balance sheets at June 30, 2023 and December 31, 2022.

	June 30, 2023												December 31, 2022
	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 Assets			Non-Current Liabilities
Gross amounts recognized	$	1,724,913		$	353,536		$	253,874		$	337,731		$	908,001		$	2,442,035		$	627,664		$	486,319
Offsetting adjustments		(353,536	)		(353,536	)		(253,874	)		(253,874	)		(908,001	)		(908,001	)		(486,319	)		(486,319	)
Net presentation on condensed balance sheets	$	1,371,377		$	-		$	-		$	83,857		$	-		$	1,534,034		$	141,345		$	-

(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

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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, 2023:

	Fair Value Measurement at June 30, 2023
	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	$	-	$	420,708	$	-	$	420,708
Derivative Contracts - Collars	$	-	$	866,812	$	-	$	866,812

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

At June 30, 2023 and December 31, 2022, 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 the Company’s 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

Subsequent to June 30, 2023, the Company entered into new derivative contracts as summarized in the table below:

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
December 2023 - September 2024	30,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.60ceiling
October 2024 - June 2025	30,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$5.00ceiling
Oil fixed price swaps
December 2023 - March 2024	750 Bbls	NYMEX WTI	$	71.75
April - June 2024	1,300 Bbls	NYMEX WTI	$	70.59
April - June 2025	1,000 Bbls	NYMEX WTI	$	68.00

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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 opportunistic divestitures 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 business strategy is 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.

As previously disclosed, in December 2022, our Board approved a change in our fiscal year end from September 30 to December 31 to be in-line with our peer group. As a result, our current fiscal year runs from January 1, 2023 through December 31, 2023, and therefore references in this Form 10-Q to 2023 refer to the annual period from January 1, 2023 through December 31, 2023.

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 we still receive revenue from the production and sale of natural gas, oil and NGL on our working interests, the majority of our revenue is derived from royalties received from the production and sale of natural gas, oil and NGL.

QUARTER ENDED JUNE 30, 2023 COMPARED TO QUARTER ENDED JUNE 30, 2022

Overview:

We recorded net loss of $41,291, or $0.00 per share, for the quarter ended June 30, 2023 compared to net income of $8,589,010, or $0.25 per share, for the quarter ended June 30, 2022. The change in net income was principally the result of decreased natural gas, oil and NGL sales and decreased gains on asset sales, partially offset by increased gains associated with our hedge contracts and decreased income tax provision. These items are further discussed below.

Revenue:

Natural Gas, Oil and NGL Sales:

	For the Three Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	7,231,164	$	19,561,568	(63%)

For the quarter ended June 30, 2023, the decrease in natural gas, oil and NGL sales was primarily due to decreases in natural gas, oil and NGL prices of 72%, 30% and 49%, respectively, and decreases in natural gas, oil and NGL volumes of 2%, 16% and 15%, respectively. The following table outlines our production and average sales prices for natural gas, oil and NGL for the quarters ended June 30, 2023 and June 30, 2022:

	MCF		Average		Oil Bbls		Average		NGL Bbls		Average		MCFE		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
6/30/2023		1,854,485	$	1.92		41,009	$	73.87		33,929	$	18.93		2,304,113	$	3.14
6/30/2022		1,897,799	$	6.82		48,928	$	105.23		39,732	$	36.76		2,429,760	$	8.05

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Total production for the last six quarters was as follows:

Quarter ended	MCF Sold		Oil Bbls Sold		NGL Bbls Sold		MCFE Sold
6/30/2023		1,854,485		41,009		33,929		2,304,113
3/31/2023		1,959,010		54,107		33,104		2,482,276
12/31/2022		1,669,320		52,406		38,611		2,215,419
9/30/2022		2,047,614		49,902		40,761		2,591,588
6/30/2022		1,897,799		48,928		39,732		2,429,760
3/31/2022		1,908,030		51,631		40,371		2,460,042

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

Quarter ended	MCF Sold		Oil Bbls Sold		NGL Bbls Sold		MCFE Sold
6/30/2023		1,673,346		35,599		20,516		2,010,036
3/31/2023		1,700,974		45,395		20,063		2,093,722
12/31/2022		1,303,825		33,691		20,353		1,628,089
9/30/2022		1,525,363		32,202		20,488		1,841,502
6/30/2022		1,283,737		32,562		19,369		1,595,323
3/31/2022		1,261,949		28,758		18,852		1,547,609

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

Quarter ended	MCF Sold		Oil Bbls Sold		NGL Bbls Sold		MCFE Sold
6/30/2023		181,139		5,410		13,413		294,077
3/31/2023		258,036		8,712		13,041		388,554
12/31/2022		365,495		18,715		18,258		587,330
9/30/2022		522,251		17,700		20,273		750,086
6/30/2022		614,062		16,366		20,363		834,437
3/31/2022		646,081		22,873		21,519		912,433

The production increase in royalty volumes during the quarter ended June 30, 2023, as compared to the quarter ended June 30, 2022, resulted from new wells in the Haynesville Shale coming online.

Lease Bonuses and Rental Income:

	For the Three Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Lease bonuses and rental income	$	111,991	$	209,329	(47%)

When we lease our mineral interests, we generally receive an upfront cash payment, or lease bonus. Lease bonuses and rental income decreased $97,338 in the quarter ended June 30, 2023 compared to the quarter ended June 30, 2022, primarily as the result of decreased leasing activity.

Gains (Losses) on Derivative Contracts:

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. Gains (losses) on derivative contracts represent the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii)

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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
	2023			2022			Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net(1)	$	1,048,941		$	(5,670,147	)	118%
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(865,935	)	$	3,282,921		(126%)
Gains (losses) on derivative contracts, net	$	183,006		$	(2,387,226	)	108%
	As of June 30,
	2023			2022
Fair value of derivative contracts
Net asset (net liability)	$	1,287,520		$	(11,258,090	)	111%

(1) Excludes $1,284,024 of cash paid to settle off-market derivative contracts that are not reflected on the Condensed Statements of Operations for the quarter ended June 30, 2022.

The change in net (loss) gain on derivative contracts was due to the settlements of natural gas and oil collars and fixed price swaps and the change in valuation caused by the difference in June 30, 2023 pricing relative to the strike price on open derivative contracts.

Our natural gas and oil costless collar contracts and fixed price swaps in place at June 30, 2023 had expiration dates through March 2025. 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 June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Lease operating expenses	$	314,150	$	900,807	(65%)
Lease operating expenses per working interest MCFE	$	1.07	$	1.08	(1%)
Lease operating expenses per total MCFE	$	0.14	$	0.37	(62%)

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 $586,657, or 65%, in the quarter ended June 30, 2023 compared to the quarter ended June 30, 2022. The decrease in LOE was principally the result of the divestiture of working interest properties.

Transportation, Gathering and Marketing:

	For the Three Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Transportation, gathering and marketing	$	906,373	$	1,430,136	(37%)
Transportation, gathering and marketing per MCFE	$	0.39	$	0.59	(34%)

Transportation, gathering and marketing costs decreased $523,763, or 37%, in the quarter ended June 30, 2023 compared to the quarter ended June 30, 2022. This decrease was primarily driven by the divestiture of assets with higher associated transportation, gathering and marketing rates and the increase in natural gas sales in fields with lower associated transportation, gathering and marketing 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 June 30,
							Percent
	2023			2022			Incr. or (Decr.)
Production taxes	$	461,893		$	925,197		(50%)
Production taxes as % of sales		6.4	%		4.7	%	36%

Production taxes are paid on produced natural gas and oil based on either a percentage of revenues from products sold at both fixed and variable rates or a fixed rate per unit produced established by federal, state or local taxing authorities. Production taxes decreased $463,304, or 50%, in the quarter ended June 30, 2023 as compared to the quarter ended June 30, 2022. The decrease in amount was primarily the result of the decrease in sales in the quarter ended June 30, 2023.

Depreciation, Depletion and Amortization (DD&A):

	For the Three Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Depreciation, depletion and amortization	$	2,210,332	$	2,022,832	9%
Depreciation, depletion and amortization per MCFE	$	0.96	$	0.83	16%

DD&A is the amount of cost basis of natural gas and oil properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis for working interest, and on a straight-line basis for producing and non-producing minerals. Estimates of proved developed producing reserves are a major component of the calculation of depletion. DD&A increased $187,500, or 9%, in the quarter ended June 30, 2023 compared to the quarter ended June 30, 2022, of which $291,786 of the increase resulted from a $0.13 increase in the DD&A rate per MCFE, partially offset by an decrease of $104,286 resulting from production decreasing 5%. The purchase of additional minerals, conversions of overriding royalty interest and a large transfer of non-producing minerals, which are amortized over 33 years, to producing minerals, which are amortized over 20 years, were the biggest contributions to the increase in the quarter ended June 30, 2023.

Provision for Impairment:

During the quarter ended June 30, 2022, impairment of $6,277 was related to working interest wells in which we assigned our interests to the operator.

Interest expense:

	For the Three Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Interest expense	$	524,294	$	286,345	83%
Weighted average debt outstanding	$	25,093,407	$	26,976,923	(7%)

The increase in interest expense is due to a higher average interest rate in the quarter ended June 30, 2023 compared to the quarter ended June 30, 2022.

Income Tax Expense:

	For the Three Months Ended June 30,
						Percent
	2023			2022		Incr. or (Decr.)
Provision (benefit) for income taxes	$	(166,000	)	$	976,000	(117%)

Income taxes decreased $1,142,000, from a $976,000 provision in the quarter ended June 30, 2022 to a $166,000 benefit in the quarter ended June 30, 2023. The change in income taxes resulted from net loss recorded in the quarter ended June 30, 2023.

General and Administrative Costs (G&A):

	For the Three Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
General and administrative	$	3,177,103	$	2,877,614	10%

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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 quarter ended June 30, 2023 increased $299,489 as compared to the quarter ended June 30, 2022. The increase for the quarter ended June 30, 2023 was primarily due to an increase in restricted stock expense and fees for professional services.

Losses (Gains) on Asset Sales and Other:

	For the Three Months Ended June 30,
						Percent
	2023		2022			Incr. or (Decr.)
Losses (gains) on asset sales and other	$	139,307	$	(630,547	)	(122%)

The decrease from the gain to the loss on asset sales and other is primarily related to the gain recognized on divestitures during the quarter ended June 30, 2022.

SIX MONTHS ENDED JUNE 30, 2023 COMPARED TO SIX MONTHS ENDED JUNE 30, 2022

Overview:

We recorded net income of $9,511,953, or $0.26 per share, for the six months ended June 30, 2023 compared to net income of $4,568,555, or $0.13 per share, for the six months ended June 30, 2022. The change in net income was principally the result of increased gains associated with our hedge contracts and increased gains on asset sales, partially offset by decreased natural gas, oil and NGL sales and increased income tax provision. These items are further discussed below.

Revenue:

Natural Gas, Oil and NGL Sales:

	For the Six Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	19,088,411	$	34,345,433	(44%)

For the six months ended June 30, 2023 and 2022, the decrease in natural gas, oil and NGL sales was primarily due to decreases in natural gas, oil and NGL prices of 51%, 23% and 41%, respectively, and decreases in oil and NGL volumes of 5% and 16%, respectively. The following table outlines our production and average sales prices for natural gas, oil and NGL for the six-month periods ended June 30, 2023 and June 30, 2022:

	MCF		Average		Oil Bbls		Average		NGL Bbls		Average		MCFE		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Six months ended
6/30/2023		3,813,496	$	2.75		95,116	$	75.09		67,033	$	22.02		4,786,390	$	3.99
6/30/2022		3,805,829	$	5.65		100,559	$	98.06		80,103	$	37.41		4,889,802	$	7.02

The production increase in royalty volumes during the six months ended June 30, 2023, as compared to the six months ended June 30, 2022, resulted from new wells in the Haynesville Shale coming online.

Lease Bonuses and Rental Income:

	For the Six Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Lease bonuses and rental income	$	425,141	$	371,237	15%

When we lease our mineral interests, we generally receive an upfront cash payment, or lease bonus. Lease bonuses and rental income increased $53,904 in the six months ended June 30, 2023 period compared to the six months ended June 30, 2022, primarily as the result of increased leasing activity.

Gains (Losses) on Derivative Contracts:

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. Gains (losses) on derivative contracts represent the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii)

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gains (losses) on settlements of derivative contracts for positions that have settled within the period. The net gain (loss) on derivative instruments for the periods indicated includes the following:

	For the Six Months Ended June 30,
						Percent
	2023		2022			Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net(1)	$	1,679,362	$	(6,880,913	)	124%
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	2,306,464	$	(8,489,719	)	127%
Gains (losses) on derivative contracts, net	$	3,985,826	$	(15,370,632	)	126%
	As of June 30,
	2023		2022
Fair value of derivative contracts
Net asset (net liability)	$	1,287,520	$	(11,258,090	)	111%

(1) Excludes $373,745 and $3,777,505, respectively, of cash paid to settle off-market derivative contracts that are not reflected on the Condensed Statements of Operations for the six months ended June 30, 2023 and 2022.

The change in net (loss) gain on derivative contracts was due to the settlements of natural gas and oil collars and fixed price swaps and the change in valuation caused by the difference in June 30, 2023 pricing relative to the strike price on open derivative contracts.

Our natural gas and oil costless collar contracts and fixed price swaps in place at June 30, 2023 had expiration dates through March 2025. 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 Six Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Lease operating expenses	$	859,917	$	1,830,261	(53%)
Lease operating expenses per working interest MCFE	$	1.26	$	1.05	20%
Lease operating expenses per MCFE	$	0.18	$	0.37	(51%)

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 $970,344, or 53%, in the six months ended June 30, 2023 compared to the six months ended June 30, 2022. The decrease in LOE was principally the result of the divestiture of higher LOE working interest properties, partially offset by cost inflation associated with field operating activities.

Transportation, Gathering and Marketing:

	For the Six Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Transportation, gathering and marketing	$	2,035,129	$	2,918,654	(30%)
Transportation, gathering and marketing per MCFE	$	0.43	$	0.60	(28%)

Transportation, gathering and marketing costs decreased $883,525, or 30%, in the six months ended June 30, 2023 compared to the six months ended June 30, 2022. This decrease was primarily driven by the divestiture of assets with higher associated transportation, gathering and marketing rates and the increase in natural gas sales in fields with lower associated transportation, gathering and marketing rates. Natural gas sales bear the large majority of our transportation, gathering and marketing fees.

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Production Taxes:

	For the Six Months Ended June 30,
							Percent
	2023			2022			Incr. or (Decr.)
Production taxes	$	1,043,326		$	1,622,590		(36%)
Production taxes as % of sales		5.5	%		4.7	%	17%

Production taxes are paid on produced natural gas and oil based on either a percentage of revenues from products sold at both fixed and variable rates or a fixed rate per unit produced established by federal, state or local taxing authorities. Production taxes decreased $579,264, or 36%, in the six months ended June 30, 2023 as compared to the six months ended June 30, 2022. The decrease in amount was primarily the result of the decrease in sales in the six months ended June 30, 2023.

Depreciation, Depletion and Amortization (DD&A):

	For the Six Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Depreciation, depletion and amortization	$	4,100,322	$	4,143,948	(1%)
Depreciation, depletion and amortization per MCFE	$	0.86	$	0.85	1%

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 $43,626, or 1%, in the six months ended June 30, 2023 compared to the six months ended June 30, 2022, of which $87,899 of the decrease resulted from production decreasing 2%, partially offset by an increase of $44,273 resulted from a $0.01 increase in the DD&A rate per MCFE. The purchase of additional minerals, conversions of overriding royalty interest and a large transfer of non-producing minerals, which are amortized over 33 years, to producing minerals, which are amortized over 20 years, in the six months ended June 30, 2023, partially offset the decrease in DD&A.

Provision for Impairment:

During the six months ended June 30, 2023 and 2022, impairment of $2,073 and $6,277, respectively, was related to working interest wells in which we assigned our interests to the operator.

Interest expense:

	For the Six Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Interest expense	$	1,081,767	$	516,557	109%
Weighted average debt outstanding	$	26,650,829	$	24,734,254	8%

The increase in interest expense is due to a higher average debt balance and average interest rate in the six months ended June 30, 2023 compared to the six months ended June 30, 2022.

Income Tax Expense:

	For the Six Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
Provision (benefit) for income taxes	$	2,901,000	$	1,009,000	188%

Income taxes increased $1,892,000, from $1,009,000 in the six months ended June 30, 2022 to $2,901,000 in the six months ended June 30, 2023. The change in income taxes resulted from an increase in deferred tax expense due to the recognition of deferred tax assets generated from the divestiture of working interests partially offset by the net operating loss generated from the divestiture of those working interests, as well as an increase in value of the derivatives for the six months ended June 30, 2023 compared to the six months ended June 30, 2022.

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General and Administrative Costs (G&A):

	For the Six Months Ended June 30,
					Percent
	2023		2022		Incr. or (Decr.)
General and administrative	$	6,159,012	$	5,621,878	10%

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 six months ended June 30, 2023 increased $537,134 as compared to the six months ended June 30, 2022. The increase for the six months ended June 30, 2023 was primarily due to an increase in restricted stock expense and fees for professional services.

Losses (Gains) on Asset Sales and Other:

	For the Six Months Ended June 30,
							Percent
	2023			2022			Incr. or (Decr.)
Losses (gains) on asset sales and other	$	(4,195,121	)	$	(2,891,682	)	45%

The increase in gain on asset sales and other is primarily related to the gain recognized on divestitures during the six months ended June 30, 2023.

LIQUIDITY AND CAPITAL RESOURCES

We had positive working capital (current assets less current liabilities excluding current derivatives) of $6,313,731 at June 30, 2023, compared to positive working capital of $14,554,429 at December 31, 2022.

Liquidity:

Cash and cash equivalents were $1,267,627 as of June 30, 2023, compared to $2,115,652 at December 31, 2022, a decrease of $848,025. The decrease in cash is primarily associated with our mineral and royalty acquisition program and paydown of debt. Cash flows for the six months ended June 30, 2023 and 2022 are summarized as follows:

Net cash provided (used) by:	For the Six Months Ended June 30,
	2023			2022			Change
Operating activities	$	13,849,265		$	15,700,984		$	(1,851,719	)
Investing activities		(2,966,017	)		(15,121,530	)		12,155,513
Financing activities		(11,731,273	)		2,350,478			(14,081,751	)
Increase (decrease) in cash and cash equivalents	$	(848,025	)	$	2,929,932		$	(3,777,957	)

Operating activities:

Net cash provided by operating activities decreased $1,851,719 during the six months ended June 30, 2023, as compared to the six months ended June 30, 2022, 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 decreasing by $6,050,326;

•increased payments for G&A and other expense of $676,900; and

•increased interest payments of $668,150;

partially offset by:

•increased net receipts on derivative contracts of $3,081,024;

•decreased field operating expenses of $1,370,791;

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•decreased income tax payments of $1,054,660; and

•increased lease bonus receipts of $37,182.

Investing activities:

Net cash used by investing activities decreased $12,155,513 during the six months ended June 30, 2023, as compared to the six months ended June 30, 2023, primarily due to lower acquisition costs of $6,314,577 and higher net proceeds from the sale of assets of $5,957,508, partially offset by higher payments of $116,572 for capital expenditures on legacy working interest wells and furniture and fixtures.

Financing activities:

Net cash used by financing activities increased $14,081,751 during the six months ended June 30, 2023, as compared to the six months ended June 30, 2022, primarily due to net payments on long-term debt of $9,550,000 in the six months ended June 30, 2023 compared to net borrowings of $8,300,000 in the six months ended June 30, 2022, a decrease in net proceeds from equity issuances of $4,702,619, and an increase of $411,475 in dividend payments, partially offset by decreased cash payments on off-market derivative contracts of $8,883,012.

Capital Resources:

We had no capital expenditures to drill and complete new wells in the six months ended June 30, 2023 and 2022 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, as the expenditures will be limited to capital workovers to enhance existing wells.

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

Quarter Ended	Net royalty acres (1)(2)	Cash Paid	Total Purchase Price (1)	Area of Interest
June 30, 2023
	151	$1.8 million	$1.8 million	Haynesville / SCOOP
March 31, 2023
	913	$10.8 million	$10.8 million	Haynesville / SCOOP
December 31, 2022
	1,257	$14.6 million	$14.6 million	Haynesville / SCOOP
September 30, 2022
	924	$13.6 million	$13.6 million	Haynesville / SCOOP
June 30, 2022
	938	$9.1 million	$9.1 million	Haynesville / SCOOP

(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 six months ended June 30, 2023 and 2022 totaling approximately $0.5 million and $0.5 million, respectively. 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 June 30, 2023.

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

	Six Months Ended
	June 30, 2023
Cash provided by operating activities	$	13,849,265
Cash provided (used) by:
Capital expenditures - acquisitions		(11,914,003	)
Capital expenditures - legacy working interest wells and furniture and fixtures		(275,419	)
Quarterly dividends		(1,620,442	)
Treasury stock purchases		(669	)
Net borrowings (payments) on credit facility		(9,550,000	)
Net proceeds from sale of assets		9,223,405
Cash receipts from (payments on) off-market derivative contracts		(560,162	)
Net cash used		(14,697,290	)
Net increase (decrease) in cash	$	(848,025	)

Outstanding borrowings under our Credit Facility at June 30, 2023 were $23,750,000.

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 under our Credit Facility. At June 30, 2023, we had availability of $21.3 million under our Credit Facility and were in compliance with all debt covenants (current ratio, debt to trailing 12-month EBITDAX, as defined in the Credit Agreement, and restricted payments limited by leverage ratio). The debt covenants in our Credit Agreement limit the maximum ratio of our debt to EBITDAX to no more than 3.5:1.

Our $100,000,000 Credit Facility is with a group of banks led by Independent Bank pursuant to the Credit Agreement entered into in September 2021, as amended. The Credit Facility had a borrowing base of $45,000,000 as of June 30, 2023, and a maturity date of September 1, 2025. Interest on the Credit Facility will be calculated based on either (a) SOFR 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 Agreement, 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 Agreement 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 Agreement 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 have the meaning assigned to them in the Credit Agreement.

Based on our expected capital expenditure levels, anticipated cash provided by operating activities for 2023, combined with availability under our Credit Facility and potential future sales of Common Stock under our currently effective shelf registration statement, we expect to have sufficient liquidity to fund our ongoing operations.

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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, 2022.

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, 2022.

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 2023 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 2023 derivative contracts, the price sensitivity for each $0.10 per MCF change in wellhead natural gas price is approximately $742,771 for operating revenue based on our fiscal year ended September, 30, 2022 natural gas volumes. The price sensitivity in 2023 for each $1.00 per barrel change in wellhead oil is approximately $198,535 for operating revenue based on our fiscal year ended September 30, 2022 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) SOFR 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 Agreement, 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 June 30, 2023, we had $23,750,000 outstanding under the Credit Facility and the effective interest rate was 8.45%. 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 $118,750 for the six months ended June 30, 2023, 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 that have existed in recent 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

Evaluation of Disclosure 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 quarterly period covered by this Form 10-Q, our 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.

Changes in Internal Control over Financial Reporting.

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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 quarter ended June 30, 2023.

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, 2022 and Item 1A of our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2023. Except as set forth in Item 1A of our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2023, 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, 2022. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In May 2014, the Board adopted stock repurchase resolutions (the “Repurchase Program”) to allow management, at its discretion, to purchase our Common Stock as treasury shares. Effective in May 2018, the Board approved an amendment to the Repurchase Program, which continues to allow us to repurchase up to $1.5 million of our Common Stock at management’s discretion. Our Board added language to clarify that the Repurchase Program 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. The Repurchase Program, as amended, does not otherwise place a cap on the aggregate number of shares of Common Stock that may be repurchased pursuant to the Repurchase Program. We repurchased 239 shares of our Common Stock during the quarter ended June 30, 2023.

The table below sets forth the information with respect to repurchase of our Common Stock during the quarter ended June 30, 2023.

Period	Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet be Purchased Under the Repurchase Program
June 1 – June 30	239(1)	$2.80	–	$	1,500,000
Total	239	$2.80	–	$	1,500,000

(1) These shares represent vested restricted shares of Common Stock previously issued to employees of the Company pursuant to restricted stock awards, which the Company repurchased from such employees in connection with the satisfaction of tax withholding obligations upon the vesting of the restricted stock awards.

Restrictions upon the payment of dividends

The Credit Agreement 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)	Exhibit No.	Description
	2.1	Agreement and Plan of Merger, dated as of March 31, 2022, by and between PHX Minerals Inc., an Oklahoma corporation, and PHX Minerals (DE) Inc., a Delaware corporation (incorporated by reference to Exhibit 2.1 to Form 8-K12B filed April 5, 2022).
	3.1	Certificate of Incorporation of PHX Minerals Inc., as amended (incorporated by reference to Exhibit 3.1 to Form 8-K12B filed April 5, 2022).
	3.2	Amended and Restated Bylaws of PHX Minerals Inc. (incorporated by reference to Exhibit 3.2 to Form 10-K filed December 13, 2022).
	10.1	Fourth Amendment to Credit Agreement dated as of May 5, 2023, 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 10.4 to Form 10-Q filed May 9, 2023).
	31.1	Certification under Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Executive Officer
	31.2	Certification under Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Financial Officer
	32.1	Certification under Section 906 of the Sarbanes-Oxley Act of 2002 by Chief Executive Officer
	32.2	Certification under Section 906 of the Sarbanes-Oxley Act of 2002 by Chief Financial Officer
	101.INS	Inline XBRL Instance Document
	101.SCH	Inline XBRL Taxonomy Extension Schema Document
	101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
	101.LAB	Inline XBRL Taxonomy Extension Labels Linkbase Document
	101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
	101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
	104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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 8, 2023	/s/ Chad L. Stephens
Date	Chad L. Stephens, President,
	Chief Executive Officer
August 8, 2023	/s/ Ralph D’Amico
Date	Ralph D’Amico, Senior Vice President,
	Chief Financial Officer

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