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 quarterly period ended ~~June~~September 30, 2024

☐ 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~~November 1, 2024: 37,~~497~~480,~~978~~790 shares.

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements		1
		Condensed Balance Sheets – June 30, 2024 and December 31, 2023		1
		Condensed Balance Sheets – September 30, 2024 and December 31, 2023		1
		Condensed Statements of Income – Three and six months ended June 30, 2024 and 2023		2
		Condensed Statements of Income – Three and nine months ended September 30, 2024 and 2023		2
		Statements of Stockholders’ Equity – Six months ended June 30, 2024 and 2023		3
		Statements of Stockholders’ Equity – Nine months ended September 30, 2024 and 2023		3
		Condensed Statements of Cash Flows – Six months ended June 30, 2024 and 2023		5
		Condensed Statements of Cash Flows – Nine months ended September 30, 2024 and 2023		5
		Notes to Condensed Financial Statements		6
	Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations		1516
	Item 3	Quantitative and Qualitative Disclosures about Market Risk		2627
	Item 4	Controls and Procedures		2627
Part II	Other Information
	Item 1	Legal Proceedings		2728
	Item 1A	Risk Factors		2728
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		2728
	Item 6	Exhibits		2728
	Signatures		2829

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 or pandemics, 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 December 31, 2023 (“Annual Report”), and any quarterly 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, 2024			December 31, 2023
	September 30, 2024			December 31, 2023
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	2,~~271~~601,~~544~~681		$	806,254
Natural gas, oil, and NGL sales receivables (net of $0 allowance for uncollectable accounts)		54,~~071~~080,~~590~~560			4,900,126
Refundable income taxes		~~372~~343,~~963~~814			455,931
Derivative contracts, net		~~877~~761,~~538~~527			3,120,607
Other		~~703~~417,~~210~~929			878,659
Total current assets		98,~~296~~205,~~845~~511			10,161,577
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		~~216~~219,~~696~~958,~~381~~671			209,082,847
Non-producing natural gas and oil properties		52,~~997~~503,~~639~~370			58,820,445
Other		1,361,064			1,360,614
		271,055,084			269,263,906
		273,823,105			269,263,906
Less accumulated depreciation, depletion and amortization		(~~118~~120,~~186~~301,~~569~~196	)		(114,139,423	)
Net properties and equipment		~~152~~153,~~868~~521,~~515~~909			155,124,483
Derivative contracts, net		-33,726			162,980
Operating lease right-of-use assets		~~502~~466,~~194~~135			572,610
Other, net		~~640~~596,~~573~~830			486,630
Total assets	$	~~163~~162,~~308~~824,~~127~~111		$	166,508,280
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	~~636~~512,~~327~~936		$	562,607
Current portion of operating lease liability		~~239~~243,~~571~~184			233,390
Accrued liabilities and other		1,~~457~~815,~~285~~758			1,215,275
Total current liabilities		2,~~333~~571,~~183~~878			2,011,272
Long-term debt		2827,750,000			32,750,000
Deferred income taxes, net		67,~~829~~289,~~023~~591			6,757,637
Asset retirement obligations		1,~~083~~087,~~947~~416			1,062,139
Derivative contracts, net		239,372			-
Operating lease liability, net of current portion		512,357			695,818
Operating lease liability, net of current portion		574,598			695,818
Total liabilities		39,211,242			43,276,866
Total liabilities		39,810,123			43,276,866
Stockholders' equity:
Common Stock, $0.01666 par value; 75,000,000 shares authorized and 36,121,723 issued at June 30, 2024; 54,000,500 shares authorized and 36,121,723 issued at December 31, 2023		601,788			601,788
Common Stock, $0.01666 par value; 75,000,000 shares authorized and 36,121,723 issued at September 30, 2024; 54,000,500 shares authorized and 36,121,723 issued at December 31, 2023		601,788			601,788
Capital in excess of par value		43,~~054~~526,~~447~~595			41,676,417
Deferred directors' compensation		1,~~471~~276,~~052~~295			1,487,590
Retained earnings		78,~~891~~492,~~082~~889			80,022,839
		124,018,369			123,788,634
		123,897,567			123,788,634
Less treasury stock, at cost; 122,785 shares at June 30, 2024, and 131,477 shares at December 31, 2023		(520,365	)		(557,220	)
Less treasury stock, at cost; 67,203 shares at September 30, 2024, and 131,477 shares at December 31, 2023		(284,698	)		(557,220	)
Total stockholders' equity		123,~~498~~612,~~004~~869			123,231,414
Total liabilities and stockholders' equity	$	~~163~~162,~~308~~824,~~127~~111		$	166,508,280

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

(1)

PHX MINERALS INC.

CONDENSED STATEMENTS OF INCOME

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

2024

2023

2024

2023

Revenues:

(unaudited)

Natural gas, oil and NGL sales

97,~~826~~888,~~006~~516

78,~~231~~899,~~164~~091

1624,~~916~~804,~~214~~730

1927,~~088~~987,~~411~~502

Lease bonuses and rental income

~~134~~159,~~226~~271

~~111~~620,~~991~~101

~~285~~445,~~944~~215

~~425~~1,~~141~~045,242

Gains (losses) on derivative contracts

~~(418~~1,~~997~~089,242

)

~~183~~(337,~~006~~647

)

~~208~~1,~~495~~297,737

3,~~985~~648,~~826~~179

9,~~541~~137,~~235~~029

79,~~526~~181,~~161~~545

1726,~~410~~547,~~653~~682

2332,~~499~~680,~~378~~923

Costs and expenses:

Lease operating expenses

294,~~354~~720

~~341~~363,~~463~~426

~~626~~921,~~763~~483

~~916~~1,~~405~~279,831

Transportation, gathering and marketing

1,~~540~~111,~~396~~980

~~906~~693,~~373~~915

23,~~383~~495,~~900~~880

2,~~035~~729,~~129~~044

Production and ad valorem taxes

~~597~~428,~~995~~577

~~434~~437,~~580~~841

~~990~~1,~~322~~418,899

~~986~~1,~~838~~424,679

Depreciation, depletion and amortization

2,~~268~~376,~~284~~025

2,~~210~~022,~~332~~709

47,~~624~~000,~~610~~635

46,~~100~~123,~~322~~031

Provision for impairment

-36,460

238,~~073~~533

Interest expense

~~651~~622,~~982~~480

~~524~~556,~~294~~941

1,~~366~~989,~~868~~348

1,~~081~~638,~~767~~708

General and administrative

2,~~734~~683,~~628~~434

32,~~177~~760,~~103~~342

68,~~081~~765,~~665~~099

68,~~159~~919,~~012~~354

Losses (gains) on asset sales and other

~~(197~~62,~~326~~248

)

~~139~~(174,~~307~~492

)

(~~173~~110,~~114~~866

)

(4,~~195~~369,~~121~~613

)

Total costs and expenses

7,~~890~~579,~~313~~464

76,~~733~~697,~~452~~142

1523,~~901~~480,~~014~~478

1117,~~086~~783,~~425~~567

Income (loss) before provision for income taxes

1,~~650~~557,~~922~~565

~~(207~~2,~~291~~484,403

)

13,~~509~~067,~~639~~204

1214,~~412~~897,~~953~~356

Provision for income taxes

~~355~~457,~~151~~255

~~(166~~589,000

)

~~397~~854,~~483~~738

23,~~901~~490,000

Net income (loss)

1,~~295~~100,~~771~~310

~~(41~~1,~~291~~895,403

)

12,~~112~~212,~~156~~466

911,~~511~~407,~~953~~356

Basic and diluted earnings (loss) per common share (Note 4)

0.04

(0.00

)

0.03

0.26

Basic earnings (loss) per common share (Note 4)

0.03

0.05

0.06

0.32

Diluted earnings (loss) per common share (Note 4)

0.03

0.05

0.06

0.31

Weighted average shares outstanding:

Basic

36,~~308~~316,~~224~~742

35,~~965~~983,~~281~~116

36,~~301~~306,~~540~~593

35,~~950~~961,~~615~~570

Diluted

36,~~379~~983,~~653~~669

3536,~~965~~656,~~281~~272

36,~~301~~731,~~540~~643

36,~~034~~670,~~438~~494

Dividends per share of common stock paid in period

0.~~0300~~0400

0.0225

0.~~0600~~1000

0.~~045~~0675

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

(2)

PHX MINERALS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

~~Six~~Nine Months Ended ~~June~~September 30, 2024

					Capital in		Deferred
	Common Stock				Excess of		Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value		Compensation			Earnings			Shares			Stock			Total
Balances at December 31, 2023		36,121,723	$	601,788	$	41,676,417	$	1,487,590		$	80,022,839			(131,477	)	$	(557,220	)	$	123,231,414
Net income (loss)		-		-		-		-			(183,615	)		-			-			(183,615	)
Restricted stock award expense		-		-		656,656		-						-			-			656,656
Dividends declared		-		-		-		-			(1,121,314	)		-			-			(1,121,314	)
Distribution of deferred directors' compensation		-		-		70,344		(107,199	)		-			8,692			36,855			-
Increase in deferred directors' compensation charged to expense		-		-		-		45,132			-			-			-			45,132
Balances at March 31, 2024		36,121,723	$	601,788	$	42,403,417	$	1,425,523		$	78,717,910			(122,785	)	$	(520,365	)	$	122,628,273
(unaudited)
Net income (loss)		-		-		-		-			1,295,771			-			-			1,295,771
Restricted stock award expense		-		-		651,030		-			-			-			-			651,030
Dividends declared		-		-		-		-			(1,122,599	)		-			-			(1,122,599	)
Increase in deferred directors' compensation charged to expense		-		-		-		45,529			-			-			-			45,529
Balances at June 30, 2024		36,121,723	$	601,788	$	43,054,447	$	1,471,052		$	78,891,082			(122,785	)	$	(520,365	)	$	123,498,004
(unaudited)
Net income (loss)		-		-		-		-			1,100,310			-			-			1,100,310
Restricted stock award expense		-		-		466,103		-			-			-			-			466,103
Dividends declared		-		-		-		-			(1,498,503	)		-			-			(1,498,503	)
Distribution of deferred directors' compensation		-		-		6,045		(241,712	)		-			55,582			235,667			-
Increase in deferred directors' compensation charged to expense		-		-		-		46,955			-			-			-			46,955
Balances at September 30, 2024		36,121,723	$	601,788	$	43,526,595	$	1,276,295		$	78,492,889			(67,203	)	$	(284,698	)	$	123,612,869
(unaudited)

(3)

~~Six~~Nine Months Ended ~~June~~September 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 declared		-		-		-			-			(50,034	)		-			-			(50,034	)
Distribution of restricted stock to officers 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 award expense		-		-		647,873			-			-			-			-			647,873
Dividends declared		-		-		-			-			(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)
Net income (loss)		-		-		-			-			1,895,403			-			-			1,895,403
Restricted stock award expense		-		-		466,766			-			-			-			-			466,766
Dividends declared		-		-		-			-			(832,508	)		-			-			(832,508	)
Increase in deferred directors' compensation charged to expense		-		-		-			56,199			-			-			-			56,199
Balances at September 30, 2023		35,938,900	$	598,742	$	44,249,366		$	1,425,155		$	78,618,090			(225,723	)	$	(3,235,361	)	$	121,655,992
(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,
	Nine Months Ended September 30,
	2024			2023
Operating Activities	(unaudited)
Net income (loss)	$	12,~~112~~212,~~156~~466		$	911,~~511~~407,~~953~~356
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		47,~~624~~000,~~610~~635			46,~~100~~123,~~322~~031
Impairment of producing properties		-			238,~~073~~533
Provision for deferred income taxes		71531,~~386~~954			23,~~679~~256,000
Gain from leasing fee mineral acreage		(~~285~~445,~~944~~215	)		(~~425~~1,~~141~~045,242	)
Proceeds from leasing fee mineral acreage		~~292~~451,~~350~~616			~~488~~1,~~173~~108,909
Net (gain) loss on sales of assets		(~~511~~518,~~684~~816	)		(4,~~428~~671,~~212~~253	)
Directors' deferred compensation expense		90137,~~661~~617			~~109~~165,~~383~~582
Total (gain) loss on derivative contracts		(~~208~~1,~~495~~297,737	)		(3,~~985~~648,~~826~~179	)
Cash receipts (payments) on settled derivative contracts		23,~~853~~786,~~916~~071			12,~~865~~468,~~779~~724
Restricted stock award expense		1,~~307~~773,~~686~~789			1,~~228~~695,~~871~~637
Other		5576,~~059~~375			70105,~~526~~604
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables		~~(171~~819,~~464~~566	)		34,~~944~~369,~~092~~921
Other current assets		~~131~~430,~~854~~119			~~405~~408,~~055~~533
Accounts payable		73(68,~~810~~183	)		(~~228~~107,~~305~~796	)
Income taxes receivable		82112,~~968~~117			(~~675~~712,~~268~~475	)
Other non-current assets		(~~138~~81,~~508~~037	)		95150,~~283~~515
Income taxes payable		-			(576,427	)
Accrued liabilities		42286,~~994~~515			~~(332~~272,~~066~~711	)
Total adjustments		812,~~311~~995,~~199~~386			49,~~337~~402,~~312~~328
Net cash provided by operating activities		915,~~423~~207,~~355~~852			1320,~~849~~809,~~265~~684
Investing Activities
Capital expenditures		(3564,~~726~~628	)		(~~275~~321,~~419~~396	)
Acquisition of minerals and overriding royalty interests		(25,~~278~~272,~~178~~847	)		(1125,~~914~~383,~~003~~759	)
Net proceeds from sales of assets		~~515~~527,~~775~~167			9,~~223~~556,~~405~~666
Net cash provided by (used in) investing activities		(14,~~798~~810,~~129~~308	)		(216,~~966~~148,~~017~~489	)
Financing Activities
Borrowings under Credit Facility		1,000,000			616,000,000
Payments of loan principal		(56,000,000	)		(1518,550,000	)
Payments on off-market derivative contracts		-			(560,162	)
Purchases of treasury stock		-			(669	)
Payments of dividends		(23,~~159~~602,~~936~~117	)		(12,~~620~~430,~~442~~823	)
Net cash provided by (used in) financing activities		(68,~~159~~602,~~936~~117	)		(115,~~731~~541,~~273~~654	)
Increase (decrease) in cash and cash equivalents		1,~~465~~795,~~290~~427			(~~848~~880,~~025~~459	)
Cash and cash equivalents at beginning of period		806,254			2,115,652
Cash and cash equivalents at end of period	$	2,~~271~~601,~~544~~681		$	1,~~267~~235,~~627~~193
Supplemental Disclosures of Cash Flow Information:
Interest paid (net of capitalized interest)	$	12,~~409~~041,~~711~~252		$	1,~~155~~652,~~637~~872
Income taxes paid (net of refunds received)	$	~~243~~210,~~130~~668		$	1,~~473~~522,~~696~~904
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid	$	83140,~~977~~300		$	7294,~~460~~587
Gross additions to properties and equipment	$	25,~~357~~386,~~409~~597		$	1226,~~952~~392,~~046~~844
Net increase (decrease) in accounts receivable for properties and equipment additions		(4349,~~505~~122	)		(~~762~~687,~~624~~689	)
Capital expenditures and acquisitions	$	25,~~313~~337,~~904~~475		$	1225,~~189~~705,~~422~~155

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

(5)

PHX MINERALS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Basis of Presentation and Accounting Principles

Basis of Presentation

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

Certain reclassifications have been made to prior period financials to conform to the current year presentation. These reclassifications have no impact on previous reported total assets, total liabilities, net income (loss), stockholders’ equity, or operating cash flows.

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 December 31, 2023. 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~~nine months ended ~~June~~September 30, 2024 and 2023:

	Three Months Ended June 30, 2024						Six Months Ended June 30, 2024
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	4,682,626	$	373,024	$	5,055,650	$	7,884,523	$	736,800	$	8,621,323
Oil revenue		3,643,875		366,482		4,010,357		6,162,196		680,357		6,842,553
NGL revenue		492,463		267,536		759,999		948,520		503,818		1,452,338
Natural gas, oil and NGL sales	$	8,818,964	$	1,007,042	$	9,826,006	$	14,995,239	$	1,920,975	$	16,916,214
	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

Prior-period performance obligations and contract balances

(6)

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, 2024 and 2023, revenue recognized during the reporting period related to performance obligations satisfied in prior reporting periods for existing wells was considered a change in estimate.


	Three Months Ended September 30, 2024						Nine Months Ended September 30, 2024
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	3,471,635	$	324,539	$	3,796,174	$	11,356,159	$	1,061,341	$	12,417,500
Oil revenue		3,092,025		327,419		3,419,444		9,254,221		1,007,775		10,261,996
NGL revenue		418,452		254,446		672,898		1,366,971		758,263		2,125,234
Natural gas, oil and NGL sales	$	6,982,112	$	906,404	$	7,888,516	$	21,977,351	$	2,827,379	$	24,804,730


	Three Months Ended September 30, 2023						Nine Months Ended September 30, 2023
	Royalty Interest		Working Interest		Total		Royalty Interest		Working Interest		Total
Natural gas revenue	$	4,046,566	$	431,075	$	4,477,641	$	13,404,030	$	1,543,985	$	14,948,015
Oil revenue		3,409,201		360,536		3,769,737		9,501,963		1,409,903		10,911,866
NGL revenue		417,530		234,183		651,713		1,308,708		818,913		2,127,621
Natural gas, oil and NGL sales	$	7,873,297	$	1,025,794	$	8,899,091	$	24,214,701	$	3,772,801	$	27,987,502

~~As noted above, as a non~~Prior-~~operator,~~period ~~there~~performance ~~are~~obligations ~~instances when the Company is limited by the information operators provide. Through cash received on new wells, in the quarters ended June 30, 2024~~ and ~~2023,~~contract the Company identified several producing properties on its minerals that had production dates prior to the quarters ended June 30, 2024 and 2023. 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 Income and on the Company’s Balance Sheets in natural gas, oil and NGL sales receivables. balances

InThe ~~connection~~Company ~~with~~records ~~obtaining~~revenue ~~more~~in ~~relevant~~the ~~information~~month onproduction ~~new~~is ~~wells~~delivered onto the purchaser. As a non-operator, the Company ~~acreage~~has ~~during~~limited visibility into the ~~quarters~~timing ~~ended~~of ~~June~~when ~~30,~~new ~~2024~~wells ~~and~~start ~~2023~~producing, ~~the~~and ~~Company~~production ~~recorded~~statements amay ~~change~~not inbe ~~estimate~~received for ~~new~~30 ~~wells~~ to ~~natural~~90 ~~gas,~~days ~~oil~~or ~~and~~more ~~NGL~~after ~~sales~~the ~~totaling~~date ~~$828,102~~production ofis ~~which~~delivered. $9As a result,~~175~~ ~~related~~the Company is required to estimate the ~~production~~amount ~~periods~~of ~~before~~production ~~January~~delivered 1,to ~~2024~~the purchaser and ~~$818,927~~the ~~related~~price tothat will be received for the ~~three~~sale ~~months~~of ~~ended~~the ~~March~~product. 31The expected sales volumes and prices for these properties are estimated and recorded within the natural gas, ~~2024;~~oil and NGL sales receivables line item on the Company’s ~~recorded~~balance asheets. ~~change~~The indifference ~~estimate~~between ~~for~~the ~~new~~Company's ~~wells~~estimates toand the actual amounts received for natural gas, oil and NGL sales ~~totaling~~is ~~$216,317~~recorded ofin ~~which~~the ~~$35,625~~quarter ~~related~~that topayment is received from the ~~production~~third ~~periods~~party. ~~before~~For ~~January~~the 1quarters ended September 30, ~~2023~~2024 and ~~$180~~2023,~~692~~ revenue recognized during the reporting period related to ~~the~~performance ~~three~~obligations ~~months~~satisfied ~~ended~~in ~~March~~prior ~~31,~~reporting ~~2023,~~periods ~~respectively~~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 September 30, 2024 and 2023, the Company identified several producing properties on its minerals that had production dates prior to the quarters ended September 30, 2024 and 2023. 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 Income 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 September 30, 2024 and 2023, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $819,342 for the quarter ended September 30, 2024, of which $38,308 related to the production periods before January 1, 2024 and $781,034 related to the six months ended June 30, 2024, and the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $570,630 for the quarter ended September 30, 2023, of which $8,625 related to the production periods before January 1, 2023 and $562,365 related to the six months ended June 30, 2023.

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 Income.

Natural gas and oil derivative contracts

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

(7)

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 Income.

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.

~~(7)~~As of September 30, 2024, 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 was required for certain state deferred tax assets and for the quarter ended September 30, 2024 the change in the Company’s valuation allowance from December 31, 2023 was an increase of $996 recorded in the income tax provision. The Company’s effective tax rate for the nine months ended September 30, 2024 was a 28% provision as compared to a 23% provision for the nine months ended September 30, 2023. The change in effective tax rate resulted from a decrease in net income and the discrete income tax expense for deferred directors' compensation benefit, changes in state tax rates, and prior year true-ups recorded in the nine months ended September 30, 2024.

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, 2024, 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, 2024, the change in the Company’s valuation allowance from December 31, 2023 is an increase of $1,023 recorded in the income tax provision. The Company’s effective tax rate for the six months ended June 30, 2024 was a 26% provision as compared to a 23% provision for the six months ended June 30, 2023. The change in effective tax rate resulted from a decrease in net income and the discrete income tax expense for deferred directors' compensation benefit and changes in state tax rates recorded in the six months ended June 30, 2024.

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~~September 30, 2024.

For the three and ~~six~~nine months ended ~~June~~September 30, 2024 and 2023, 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 ~~755~~577,~~491~~318 and ~~823~~815,~~359~~399, respectively, for the three and ~~six~~nine months ended ~~June~~September 30, 2024 and ~~692~~564,~~685~~578 and ~~556~~464,~~555~~151, respectively, for the three and ~~six~~nine months ended ~~June~~September 30, 2023.

(8)

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

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

2024

2023

2024

2023

Basic EPS

Numerator:

Basic net income (loss)

1,~~295~~100,~~771~~310

~~(41~~1,~~291~~895,403

)

12,~~112~~212,~~156~~466

911,~~511~~407,~~953~~356

Denominator:

Common Shares

3536,~~998~~049,~~938~~083

35,713,~~335~~177

3536,~~998~~015,~~795~~680

35,~~705~~708,~~890~~346

Unissued, directors' deferred compensation shares

~~309~~267,~~286~~659

~~251~~269,~~946~~939

~~302~~290,~~745~~913

~~244~~253,~~725~~224

Basic weighted average shares outstanding

36,~~308~~316,~~224~~742

35,~~965~~983,~~281~~116

36,~~301~~306,~~540~~593

35,~~950~~961,~~615~~570

Basic EPS

0.0403

(0.0005

)

0.0306

0.2632

Diluted EPS

Numerator:

Basic net income (loss)

1,~~295~~100,~~771~~310

~~(41~~1,~~291~~895,403

)

12,~~112~~212,~~156~~466

911,~~511~~407,~~953~~356

Diluted net income (loss)

1,~~295~~100,~~771~~310

~~(41~~1,~~291~~895,403

)

12,~~112~~212,~~156~~466

911,~~511~~407,~~953~~356

Denominator:

Basic weighted average shares outstanding

36,~~308~~316,~~224~~742

35,~~965~~983,~~281~~116

36,~~301~~306,~~540~~593

35,~~950~~961,~~615~~570

Effects of dilutive securities:

Unvested restricted stock

71666,~~429~~927

-673,156

-425,050

83708,~~823~~924

Diluted weighted average shares outstanding

36,~~379~~983,~~653~~669

3536,~~965~~656,~~281~~272

36,~~301~~731,~~540~~643

36,~~034~~670,~~438~~494

Diluted EPS

0.0403

(0.0005

)

0.0306

0.2631

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 $50,000,000 and a maturity date of September 1, 2028 as of ~~June~~September 30, 2024. OnThe ~~April~~Credit ~~18,~~Facility ~~2024,~~is secured by the ~~borrowing~~Company’s ~~base~~personal ~~was~~property ~~reaffirmed~~and at ~~$50,000,000,~~least in75% ~~connection~~of ~~with~~ the ~~regularly~~total ~~scheduled~~value ~~semi-annual~~of ~~redetermination~~the proved, developed and ~~the~~producing ~~maturity~~oil ~~date~~and ~~was~~gas ~~extended~~properties. ~~from~~The ~~September~~interest 1,rate ~~2025~~is tobased ~~September~~on 1,either ~~2028~~(a) SOFR plus an applicable margin ranging from 2.750% ~~The~~to ~~Credit~~3.750% ~~Facility~~per isannum ~~secured~~based byon the Company’s ~~personal~~Borrowing ~~property~~Base ~~and~~Utilization ator ~~least~~(b) ~~75%~~the greater of (1) the ~~total~~Prime ~~value~~Rate ofin ~~the~~effect ~~proved~~for such day, ~~developed~~or ~~and~~(2) ~~producing~~the ~~oil~~overnight ~~and~~cost ~~gas~~of ~~properties~~federal funds as announced by the U.S. ~~The~~Federal ~~interest~~Reserve ~~rate~~System isin ~~based~~effect on ~~either~~such day plus one-half of one percent (a0.50%), ~~SOFR~~ plus, in each case, an applicable margin ranging from 21.750% to 32.750% 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 September 30, 2024, the effective interest rate was 8.36%.

~~(8)~~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 September 30, 2024 was $347,547. The debt issuance cost is amortized over the life of the Credit Facility.

~~(b)~~Determinations of the ~~greater~~borrowing ofbase ~~(1)~~under the ~~Prime~~Credit ~~Rate~~Facility inare ~~effect~~made ~~for~~semi-annually ~~such~~(usually ~~day,~~in orJune (2and December) or whenever the ~~overnight~~lending ~~cost~~banks, ofin ~~federal~~their ~~funds~~sole asdiscretion, ~~announced~~believe bythat ~~the~~there ~~U.S.~~has ~~Federal~~been ~~Reserve~~a ~~System~~material change in ~~effect~~the onvalue ~~such~~of ~~day~~the ~~plus~~Company’s ~~one-half~~natural ofgas ~~one~~and ~~percent~~oil (0properties.~~50%),~~ ~~plus,~~The inCredit ~~each~~Facility ~~case~~contains customary covenants which, anamong ~~applicable~~other ~~margin~~things, ~~ranging~~require ~~from~~periodic ~~1.750%~~financial toand ~~2.750%~~reserve ~~per~~reporting ~~annum~~and ~~based~~place certain restrictions on the Company’s ~~Borrowing~~ability ~~Base~~to ~~Utilization.~~incur ~~The~~debt, ~~election~~grant ofliens, ~~Independent~~make ~~Bank~~fundamental ~~prime~~changes orand ~~SOFR~~engage isin atcertain transactions with affiliates. The Credit Facility also restricts the Company’s ~~discretion.~~ability ~~The~~to ~~interest~~make ~~rate~~certain ~~spread~~restricted ~~from~~payments ~~Independent~~if ~~Bank~~before ~~prime~~ or ~~SOFR~~after ~~will~~the beRestricted ~~charged~~Payment ~~based~~(i) on the ~~ratio~~Available Commitment is less than ten percent (10%) of the ~~loan~~Borrowing ~~balance~~Base toor (ii) the ~~borrowing~~Leverage ~~base.~~Ratio ~~The~~on ~~interest~~a ~~rate~~pro ~~spread~~forma ~~from~~basis ~~SOFR~~is orgreater than 2.50 to 1.00. In addition, the ~~prime~~Company ~~rate~~is ~~increases~~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 ~~larger~~funded ~~percent~~debt to EBITDAX of ~~the~~no ~~borrowing~~more ~~base~~than is3.5 ~~advanced~~to 1.0 based on the trailing twelve months. At ~~June~~September 30, 2024, the ~~effective~~Company ~~interest~~was ~~rate~~in ~~was~~compliance 8with the covenants of the Credit Facility, had $27,750,000 in outstanding borrowings and had $22,250,000 available for borrowing under the Credit Facility.~~62%~~ 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.

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, 2024 was $369,877. The debt issuance cost is amortized over the life of the Credit Facility.(9)

Determinations of the borrowing base under the Credit Facility are made semi-annually (usually in 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 of no more than 3.5 to 1.0 based on the trailing twelve months. At June 30, 2024, the Company was in compliance with the covenants of the Credit Facility, had $28,750,000 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.

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

Compensation expense for 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~~nine months ended ~~June~~September 30, 2024 and 2023 related to the Company’s market-based and time-based restricted stock:

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2024

2023

2024

2023

Market-based, restricted stock

~~482~~310,~~912~~152

~~523~~324,~~408~~039

~~963~~1,~~588~~273,740

1,~~046~~370,~~818~~857

Time-based, restricted stock

~~168~~155,~~118~~951

~~124~~142,~~465~~727

~~344~~500,~~098~~049

~~182~~324,~~053~~780

Total compensation expense

~~651~~466,~~030~~103

~~647~~466,~~873~~766

1,~~307~~773,~~686~~789

1,~~228~~695,~~871~~637

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, 2024
	As of September 30, 2024
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	1,~~479~~168,~~064~~912		1.4830
Time-based, restricted stock		~~646~~505,~~735~~700		1.6446
Total	$	21,~~125~~674,~~799~~612

(9)

NOTE 8: Properties and Equipment

Acquisitions

The Company made the following property acquisitions during the ~~six~~nine-month periods ended ~~June~~September 30, 2024 and 2023.

Quarter Ended	Net royalty acres (1)(2)	~~Cash~~Total ~~Paid~~Purchase Price (1)	~~Total~~% ~~Purchase~~Proved ~~Price~~/ ~~(1)~~% Unproved	%Area ~~Proved~~of ~~/ % Unproved~~Interest	~~Area of Interest~~
June 30, 2024
September 30, 2024
	96	$0.9 million	$0.9 million	59% / 41%	Haynesville / SCOOP
	325	$3.0 million	78% / 22%	Haynesville / SCOOP
March 31, 2024
June 30, 2024
	146	$1.4 million	$1.4 million	5% / 95%	SCOOP
	96	$0.9 million	59% / 41%	Haynesville / SCOOP
June 30, 2023
March 31, 2024
	151	$1.8 million	$1.8 million	29% / 71%	Haynesville / SCOOP
	146	$1.4 million	5% / 95%	SCOOP
March 31, 2023
September 30, 2023
	912	$10.8 million	$10.8 million	44% / 56%	Haynesville / SCOOP
	974	$13.4 million	81% / 19%	Haynesville / SCOOP
June 30, 2023
	151	$1.8 million	29% / 71%	Haynesville / SCOOP
March 31, 2023
	912	$10.8 million	44% / 56%	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.

(10)

All purchases made in the 2024 and 2023 quarters were for mineral and royalty acreage and were accounted for as asset acquisitions.

Divestitures

The Company made the following property divestitures during the ~~six~~nine-month periods ended ~~June~~September 30, 2024 and 2023. 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
September 30, 2024
	No significant divestitures
June 30, 2024
	1,005 acres	$0.5 million	$0.4 million	TX
March 31, 2024
	No significant divestitures
September 30, 2023
	729 acres	$0.3 million	$0.2 million	OK
June 30, 2023
	No significant divestitures
March 31, 2023
	755 acres	$0.3 million	$0.3 million	OK / TX
	267 wellbores	$10.7 million	$4.1 million	OK / 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.

(10)

Natural Gas, Oil and NGL Reserves

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

Impairment

Company management monitors all long-lived assets, principally natural gas and oil properties, for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates; future drilling and completion costs; future sales prices for natural gas, oil and NGL; future production costs; estimates of future natural gas, oil and NGL reserves to be recovered and the timing thereof; the economic and regulatory climates; and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to natural gas, oil and NGL reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For the three and ~~six~~nine months ended ~~June~~September 30, 2024 and 2023, management’s assessment resulted in no impairment provisions on producing properties. The Company wrote off $238,~~073~~533 on wells assigned to the operator with zero consideration received during the ~~six~~nine months ended ~~June~~September 30, 2023.

(11)

NOTE 9: Derivatives

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

Derivative Contracts in Place as of ~~June~~September 30, 2024

Calendar Period	Contract total volume	Index	Contract average price
Natural gas costless collars
2024	~~430~~415,000 Mmbtu	NYMEX Henry Hub	$3.19 floor / $4.84 ceiling
2025	1,~~365~~440,000 Mmbtu	NYMEX Henry Hub	$3.2625 floor / $4.6659 ceiling
2026	570,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.82 ceiling
Natural gas fixed price swaps
2024	1470,~~262,500~~000 Mmbtu	NYMEX Henry Hub	$3.4155
2025	12,~~030~~150,000 Mmbtu	NYMEX Henry Hub	$3.4726
2026	150,000 Mmbtu	NYMEX Henry Hub	$3.10
Oil costless collars
2024	125,~~250~~300 Bbls	NYMEX WTI	$6566.7904 floor / $76.7679 ceiling
Oil fixed price swaps
2024	2117,~~500~~200 Bbls	NYMEX WTI	$68.6684
2025	4057,800 Bbls	NYMEX WTI	$69.5844
2026	412,~~500~~000 Bbls	NYMEX WTI	$7069.7453

~~(11)~~Derivative Settlements during the Three Months Ended September 30, 2024

Derivative Settlements during the Three Months Ended June 30, 2024


	Monthly			Settlement
Contract period (1)	Production volume	Index	Contract price	(paid) received
Natural gas costless collars
July - September 2024	30,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling	$	76,050
Natural gas fixed price swaps
July - September 2024	75,000 Mmbtu	NYMEX Henry Hub	$3.47	$	295,875
July - September 2024	25,000 Mmbtu	NYMEX Henry Hub	$3.47	$	98,625
July - September 2024	50,000 Mmbtu	NYMEX Henry Hub	$3.17	$	152,250
July 2024	127,500 Mmbtu	NYMEX Henry Hub	$3.24	$	78,030
August - September 2024	120,000 Mmbtu	NYMEX Henry Hub	$3.24	$	317,160
Oil costless collars
June - August 2024	500 Bbls	NYMEX WTI	$70.00 floor / $78.10 ceiling	$	(1,490	)
June 2024	1,650 Bbls	NYMEX WTI	$63.00 floor / $76.00 ceiling	$	(4,450	)
June 2024	500 Bbls	NYMEX WTI	$65.00 floor / $76.50 ceiling	$	(1,099	)
July - August 2024	1,650 Bbls	NYMEX WTI	$65.00 floor / $76.50 ceiling	$	(6,569	)
Oil fixed price swaps
June 2024	1,300 Bbls	NYMEX WTI	$70.59	$	(10,540	)
June - August 2024	1,000 Bbls	NYMEX WTI	$66.10	$	(36,313	)
July - August 2024	1,500 Bbls	NYMEX WTI	$69.50	$	(25,373	)
			Total (paid) received	$	932,156

	Monthly			Settlement
Contract period (1)	Production volume	Index	Contract price	(paid) received
Natural gas costless collars
April - June 2024	30,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling	$	99,540
April 2024	90,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.70 ceiling	$	173,250
May 2024	95,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.70 ceiling	$	179,170
June 2024	90,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.70 ceiling	$	90,630
Natural gas fixed price swaps
April - June 2024	10,000 Mmbtu	NYMEX Henry Hub	$3.21	$	39,480
April - June 2024	50,000 Mmbtu	NYMEX Henry Hub	$3.17	$	191,400
April - June 2024	127,500 Mmbtu	NYMEX Henry Hub	$3.24	$	514,845
Oil costless collars
March 2024	1,650 Bbls	NYMEX WTI	$65.00 floor / $76.50 ceiling	$	(6,443	)
April - May 2024	500 Bbls	NYMEX WTI	$65.00 floor / $76.50 ceiling	$	(5,008	)
March 2024	1,750 Bbls	NYMEX WTI	$63.00 floor / $76.00 ceiling	$	(7,708	)
April 2024	1,700 Bbls	NYMEX WTI	$63.00 floor / $76.00 ceiling	$	(14,270	)
May 2024	1,750 Bbls	NYMEX WTI	$63.00 floor / $76.00 ceiling	$	(4,587	)
Oil fixed price swaps
March 2024	750 Bbls	NYMEX WTI	$71.75	$	(6,491	)
April - May 2024	1,000 Bbls	NYMEX WTI	$66.10	$	(30,815	)
April - May 2024	1,300 Bbls	NYMEX WTI	$70.59	$	(28,386	)
			Total (paid) received	$	1,184,607

(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 $~~638~~795,~~166~~253 as of ~~June~~September 30, 2024, and a net asset of $3,283,587 as of December 31, 2023. Cash receipts or payments in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2024			2023			2024			2023
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	542,590		$	475,320		$	1,650,165		$	1,190,910
Natural gas fixed price swaps(1)		745,725			576,490			1,300,973			659,590
Oil costless collars		(38,016	)		12,515			(39,235	)		12,515
Oil fixed price swaps(1)		(65,692	)		(15,384	)		(57,987	)		(183,653	)
Cash received (paid) on derivative contracts, net	$	1,184,607		$	1,048,941		$	2,853,916		$	1,679,362
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(633,105	)	$	(488,755	)	$	(1,392,373	)	$	94,846
Natural gas fixed price swaps		(1,050,328	)		(521,078	)		(852,312	)		1,652,299
Oil costless collars		60,234			29,131			(34,664	)		51,394
Oil fixed price swaps		19,595			114,767			(366,072	)		507,925
Non-cash gain (loss) on derivative contracts, net	$	(1,603,604	)	$	(865,935	)	$	(2,645,421	)	$	2,306,464
Gains (losses) on derivative contracts, net	$	(418,997	)	$	183,006		$	208,495		$	3,985,826

(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 Income. Total cash paid related to off-market derivatives was $560,162 for the six months ended June 30, 2023 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.

(12)

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, 2024 and December 31, 2023. The Company has offset all amounts subject to master netting agreements in the Company's balance sheets at June 30, 2024 and December 31, 2023.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2024			2023			2024			2023
Cash received (paid) on derivative contracts:
Natural gas costless collars	$	76,050		$	240,655		$	1,726,215		$	1,431,565
Natural gas fixed price swaps(1)		941,940			364,310			2,242,912			1,023,900
Oil costless collars		(13,608	)		11,815			(52,843	)		24,330
Oil fixed price swaps(1)		(72,226	)		(13,835	)		(130,213	)		(197,488	)
Cash received (paid) on derivative contracts, net	$	932,156		$	602,945		$	3,786,071		$	2,282,307
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	125,098		$	(146,476	)	$	(1,267,275	)	$	(51,630	)
Natural gas fixed price swaps		(655,239	)		76,754			(1,507,551	)		1,729,053
Oil costless collars		53,427			(225,028	)		18,763			(173,634	)
Oil fixed price swaps		633,800			(645,842	)		267,729			(137,917	)
Non-cash gain (loss) on derivative contracts, net	$	157,086		$	(940,592	)	$	(2,488,334	)	$	1,365,872
Gains (losses) on derivative contracts, net	$	1,089,242		$	(337,647	)	$	1,297,737		$	3,648,179

	June 30, 2024												December 31, 2023
	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	$	1,554,997		$	677,459		$	465,630		$	705,002		$	3,318,046		$	197,439		$	344,614		$	181,634
Offsetting adjustments		(677,459	)		(677,459	)		(465,630	)		(465,630	)		(197,439	)		(197,439	)		(181,634	)		(181,634	)
Net presentation on condensed balance sheets	$	877,538		$	-		$	-		$	239,372		$	3,120,607		$	-		$	162,980		$	-

(1) For the nine months ended September 30, 2023, excludes $373,745 of cash paid to settle off-market derivative contracts that are not reflected on the Condensed Statements of Income. Total cash paid related to off-market derivatives was $560,162 for the nine months ended September 30, 2023 and is reflected in the Financing Activities section of the Condensed Statements of Cash Flows.

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 September 30, 2024 and December 31, 2023. The Company has offset all amounts subject to master netting agreements in the Company's balance sheets at September 30, 2024 and December 31, 2023.


	September 30, 2024												December 31, 2023
	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	$	1,207,702		$	446,175		$	512,160		$	478,434		$	3,318,046		$	197,439		$	344,614		$	181,634
Offsetting adjustments		(446,175	)		(446,175	)		(478,434	)		(478,434	)		(197,439	)		(197,439	)		(181,634	)		(181,634	)
Net presentation on condensed balance sheets	$	761,527		$	-		$	33,726		$	-		$	3,120,607		$	-		$	162,980		$	-

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

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

NOTE 10: Fair Value Measurements

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

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis at June 30, 2024:

	Fair Value Measurement at June 30, 2024
	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	$	-	$	487,658	$	-	$	487,658
Derivative Contracts - Collars	$	-	$	150,508	$	-	$	150,508

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, 2024 and December 31, 2023, 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.

(13)

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 September 30, 2024:


	Fair Value Measurement at September 30, 2024
	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	$	-	$	466,220	$	-	$	466,220
Derivative Contracts - Collars	$	-	$	329,033	$	-	$	329,033

At September 30, 2024 and December 31, 2023, 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~~Debt ~~to June 30, 2024, the Company entered into new derivative contracts as summarized in the table below:~~Redetermination

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas fixed price swaps
November 2024	25,000 Mmbtu	NYMEX Henry Hub	$2.80
April 2025 - May 2025	25,000 Mmbtu	NYMEX Henry Hub	$3.23
April 2025 - August 2025	125,000 Mmbtu	NYMEX Henry Hub	$3.01
June 2025	10,000 Mmbtu	NYMEX Henry Hub	$3.23
July 2025	45,000 Mmbtu	NYMEX Henry Hub	$3.23
August 2025	40,000 Mmbtu	NYMEX Henry Hub	$3.23
September 2025	50,000 Mmbtu	NYMEX Henry Hub	$3.23
September 2025 - October 2025	100,000 Mmbtu	NYMEX Henry Hub	$3.01
October 2025	100,000 Mmbtu	NYMEX Henry Hub	$3.23
Oil fixed price swaps
July 2025 - August 2025	1,250 Bbls	NYMEX WTI	$70.81

Subsequent to September 30, 2024, the Company's borrowing base under the Credit Facility was reaffirmed at $50 million, which constitutes the periodic redetermination of the borrowing base for December 1, 2024 and is not deemed an unscheduled redetermination.

(14)

Derivative Contracts

Subsequent to September 30, 2024, 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
November 2025 - March 2026	50,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.87 ceiling
April 2026 - June 2026	75,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling
July 2026 - September 2026	100,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling
Oil fixed price swaps
April 2026 - June 2026	1,000 Bbls	NYMEX WTI	$65.80

(15)

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

BUSINESS OVERVIEW

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

We also currently own interests in leasehold acreage and non-operated working interests in natural gas and oil properties. Exploration and development of our natural gas and oil properties is conducted by third-party natural gas and oil exploration and production companies (primarily larger independent operating companies). We do not operate any of our natural gas and oil properties. While we previously were an active working interest participant in wells drilled on our mineral and leasehold acreage, our current 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.

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~~SEPTEMBER 30, 2024 COMPARED TO QUARTER ENDED ~~JUNE~~SEPTEMBER 30, 2023

Overview:

We recorded net income of $1,~~295~~100,~~771~~310, or $0.0403 per diluted share, for the quarter ended ~~June~~September 30, 2024 compared to net ~~loss~~income of $411,~~291~~895,403, or $0.0005 per diluted share, for the quarter ended ~~June~~September 30, 2023. The change in net income was principally the result of ~~increased~~a decrease in natural gas, oil and NGL sales, ~~decreased~~a ~~general~~decrease in lease bonuses, an increase in transportation, gathering and ~~administrative~~marketing expenses, and ~~increased~~an ~~gains~~increase onin ~~asset~~depreciation, ~~sales~~depletion and amortization expenses, partially offset by ~~increased~~an ~~losses~~increase in gains associated with our derivative contracts ~~and increased income tax provision~~. These items are further discussed below.

Revenue:

Natural Gas, Oil and NGL Sales:

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	97,~~826~~888,~~006~~516	$	78,~~231~~899,~~164~~091	36(11%)

For the quarter ended ~~June~~September 30, 2024, the ~~increase~~decrease in natural gas, oil and NGL sales was primarily due to ~~increases~~decreases in natural gas, oil and ~~oil~~NGL ~~volumes~~prices of 3317%, 5%, and 264%, respectively, and ~~increases~~a decrease in ~~natural gas,~~ oil, ~~and~~volumes ~~NGL prices~~ of ~~7%,~~ 5%, ~~and 25%, respectively,~~ partially offset by aincreases ~~decrease~~ in natural gas and NGL volumes of 62% and 7%, respectively. The following table outlines our production and average sales prices for natural gas, oil and NGL for the quarters ended ~~June~~September 30, 2024 and ~~June~~September 30, 2023:

	MCF		Average		Oil Bbls		Average		NGL Bbls		Average		MCFE		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
6/30/2024		2,464,846	$	2.05		51,828	$	77.38		31,994	$	23.75		2,967,779	$	3.31
9/30/2024		1,898,442	$	2.00		45,698	$	74.83		34,332	$	19.60		2,378,622	$	3.32
6/30/2023		1,854,485	$	1.92		41,009	$	73.87		33,929	$	18.93		2,304,113	$	3.14
9/30/2023		1,868,012	$	2.40		48,032	$	78.48		32,029	$	20.35		2,348,378	$	3.79

(1516)

Total production for the last five quarters was as follows:

Quarter ended	MCF Sold		Oil Bbls Sold		NGL Bbls Sold		MCFE Sold
9/30/2024		1,898,442		45,698		34,332		2,378,622
6/30/2024		2,464,846		51,828		31,994		2,967,779
3/31/2024		1,700,108		37,260		32,184		2,116,776
12/31/2023		1,775,577		39,768		38,422		2,244,717
9/30/2023		1,868,012		48,032		32,029		2,348,378
6/30/2023		1,854,485		41,009		33,929		2,304,113

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

Quarter ended	MCF Sold		Oil Bbls Sold		NGL Bbls Sold		MCFE Sold
9/30/2024		1,724,635		41,170		21,011		2,097,722
6/30/2024		2,304,176		47,024		20,461		2,709,090
3/31/2024		1,533,580		33,083		20,844		1,857,147
12/31/2023		1,590,301		35,547		23,769		1,946,196
9/30/2023		1,689,396		43,575		20,416		2,073,342
6/30/2023		1,673,346		35,599		20,516		2,010,036

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

Quarter ended	MCF Sold		Oil Bbls Sold		NGL Bbls Sold		MCFE Sold
9/30/2024		173,807		4,528		13,321		280,900
6/30/2024		160,670		4,804		11,533		258,689
3/31/2024		166,528		4,177		11,340		259,629
12/31/2023		185,276		4,221		14,653		298,521
9/30/2023		178,616		4,457		11,613		275,036
6/30/2023		181,139		5,410		13,413		294,077

The production increase in royalty volumes during the quarter ended ~~June~~September 30, 2024, as compared to the quarter ended ~~June~~September 30, 2023, resulted primarily from new wells being brought online in the Haynesville Shale. ~~The~~and ~~production~~SCOOP ~~decrease in working interest volumes during the quarter ended June 30, 2024, as compared to the quarter ended June 30, 2023, resulted from natural production decline~~plays.

Lease Bonuses and Rental Income:

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Lease bonuses and rental income	$	~~134~~159,~~226~~271	$	~~111~~620,~~991~~101	20(74%)

When we lease our mineral interests, we generally receive an upfront cash payment, or lease bonus. Lease bonuses and rental income ~~increased~~decreased $22460,~~235~~830 in the quarter ended ~~June~~September 30, 2024 compared to the quarter ended ~~June~~September 30, 2023, primarily as the result of ~~increased~~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)

(1617)

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,
	For the Three Months Ended September 30,
							Percent
	2024			2023			Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net	$	1932,~~184,607~~156		$	1602,~~048,941~~945		1355%
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(1157,~~603,604~~086	)	$	(~~865~~940,~~935~~592	)	~~(85~~117%)
Gains (losses) on derivative contracts, net	$	~~(418~~1,~~997~~089,242	)	$	~~183~~(337,~~006~~647	)	~~(329~~423%)
	As of June 30,
	As of September 30,
	2024			2023
Fair value of derivative contracts
Net asset (net liability)	$	~~638~~795,~~166~~253		$	1346,~~287,520~~928		~~(50~~129%)

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~~September 30, 2024 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~~September 30, 2024 had expiration dates through ~~March~~June 2026. We utilize derivative contracts for the purpose of protecting our cash flow and reducing our exposure to short-term fluctuations in the price of natural gas and oil.

Costs and Expenses:

Lease Operating Expenses (LOE):

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Lease operating expenses	$	294,~~354~~720	$	~~341~~363,~~463~~426	(1419%)
Lease operating expenses per working interest MCFE	$	1.1405	$	1.1632	(220%)
Lease operating expenses per total MCFE	$	0.1012	$	0.15	(3320%)

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 $4768,~~109~~706, or 1419%, in the quarter ended ~~June~~September 30, 2024 compared to the quarter ended ~~June~~September 30, 2023. The decrease in LOE was principally the result of a decrease in workover expenses.

Transportation, Gathering and Marketing:

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Transportation, gathering and marketing	$	1,~~540~~111,~~396~~980	$	~~906~~693,~~373~~915	7060%
Transportation, gathering and marketing per MCFE	$	0.5247	$	0.3930	3357%

Transportation, gathering and marketing costs increased $~~634~~418,~~023~~065, or 7060%, in the quarter ended ~~June~~September 30, 2024 compared to the quarter ended ~~June~~September 30, 2023. This increase was primarily driven by the increase in production. Natural gas sales bear the large majority of our transportation, gathering and marketing fees, and the increase in production occurred in an area of the Louisiana Haynesville with higher transportation, gathering and marketing rates.

Production and Ad Valorem Taxes:

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
							Percent
	2024			2023			Incr. or (Decr.)
Production and ad valorem taxes	$	~~597~~428,~~995~~577		$	~~434~~437,~~580~~841		38(2%)
Production and ad valorem taxes as % of sales		65.14	%		64.09	%	210%

(1718)

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 ~~increased~~remained ~~$163,415,~~relatively orflat ~~38%,~~ in the quarter ended ~~June~~September 30, 2024 as compared to the quarter ended ~~June~~September 30, 2023. ~~The increase in amount was primarily the result of the increase in sales in the quarter ended June 30, 2024.~~

Depreciation, Depletion and Amortization (DD&A):

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Depreciation, depletion and amortization	$	2,~~268~~376,~~284~~025	$	2,~~210~~022,~~332~~709	317%
Depreciation, depletion and amortization per MCFE	$	01.7600	$	0.9686	~~(21~~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 $57353,~~952~~316, or 317%, in the quarter ended ~~June~~September 30, 2024 compared to the quarter ended ~~June~~September 30, 2023, which was attributable to a $~~637~~26,~~118~~004 increase resulting from production increasing 291%, ~~offset~~and by a $~~579~~327,~~166~~312 ~~decrease~~increase due to a $0.2014 ~~decrease~~increase in the DD&A rate per MCFE.

Provision for Impairment:

During the ~~quarters~~quarter ended ~~June~~September 30, ~~2024 and~~ 2023, ~~there~~impairment of $36,460 was norelated ~~impairment~~to ~~recognized~~working interest wells in which we assigned our interests to the operator.

Interest expense:

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Interest expense	$	~~651~~622,~~982~~480	$	~~524~~556,~~294~~941	2412%
Weighted average debt outstanding	$	2928,~~755~~309,~~495~~783	$	25,~~093~~152,~~407~~174	1913%

The increase in interest expense is due to a higher average ~~interest rate and higher average~~ debt balance in the quarter ended ~~June~~September 30, 2024 compared to the quarter ended ~~June~~September 30, 2023.

Income Tax Expense:

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
						Percent
	2024		2023			Incr. or (Decr.)
Provision for income taxes	$	~~355~~457,~~151~~255	$	~~(166~~589,000	)	~~314~~(22%)

Income taxes ~~increased~~decreased $~~521~~131,~~151~~745, from a $~~166~~589,000 ~~benefit~~provision in the quarter ended ~~June~~September 30, 2023 to a $~~355~~457,~~151~~255 provision in the quarter ended ~~June~~September 30, 2024. The change in income taxes resulted primarily from the ~~change~~decrease ~~from~~in pre-tax net ~~loss~~income recorded for the quarter ended ~~June~~September 30, ~~2023~~2024 compared to ~~pre-tax~~the ~~net~~quarter ~~income~~ended ~~for~~September 30, 2023, partially offset by discrete prior year true-ups recorded during the quarter ended ~~June~~September 30, 2024.

General and Administrative Costs (G&A):

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
General and administrative	$	2,~~734~~683,~~628~~434	$	32,~~177~~760,~~103~~342	(143%)

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~~September 30, 2024 decreased $~~442~~76,~~475~~908 as compared to the quarter ended ~~June~~September 30, 2023. The decrease for the quarter ended ~~June~~September 30, 2024 was primarily due to a decrease in professional fees.

(1819)

Losses (Gains) on Asset Sales and Other:

	For the Three Months Ended June 30,
	For the Three Months Ended September 30,
							Percent
	2024			2023			Incr. or (Decr.)
Losses (gains) on asset sales and other	$	~~(197~~62,~~326~~248	)	$	~~139~~(174,~~307~~492	)	~~242~~136%

The increase in ~~gain on asset sales and other, from a~~ loss on asset sales and other, is primarily related to the gain recognized on divestitures during the quarter ended ~~June~~September 30, ~~2024~~2023, whereas there were no significant divestitures during the quarter ended ~~June~~September 30, ~~2023~~2024.

~~SIX~~NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2024 COMPARED TO ~~SIX~~NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2023

Overview:

We recorded net income of $12,~~112~~212,~~156~~466, or $0.0306 per diluted share, for the ~~six~~nine months ended ~~June~~September 30, 2024 compared to net income of $911,~~511~~407,~~953~~356, or $0.2631 per diluted share, for the ~~six~~nine months ended ~~June~~September 30, 2023. The change in net income was principally the result of ~~decreased~~a decrease in natural gas, oil and NGL sales, ~~decreased~~a decrease in gains associated with our hedge contracts, ~~and~~a ~~decreased~~decrease in gains on asset sales, an increase in transportation, gathering and marketing expenses and an increase in depreciation, depletion and amortization expenses, partially offset by ~~decreased~~a decrease in income tax provision. These items are further discussed below.

Revenue:

Natural Gas, Oil and NGL Sales:

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	1624,~~916~~804,~~214~~730	$	1927,~~088~~987,~~411~~502	(11%)

For the ~~six~~nine months ended ~~June~~September 30, 2024, the decrease in natural gas, oil and NGL sales was primarily due ~~to decreases in oil and NGL volumes of 6% and 4%, respectively, and~~ a decrease in natural gas prices of 2522%, ~~partially~~and ~~offset~~decreases ~~by increases~~ in oil and NGL ~~prices~~volumes of 26% and 31%, respectively, ~~and~~partially offset by an increase in ~~natural~~ gas volumes of 97%. The following table outlines our production and average sales prices for natural gas, oil and NGL for the ~~six~~nine-month periods ended ~~June~~September 30, 2024 and ~~June~~September 30, 2023:

	MCF		Average		Oil Bbls		Average		NGL Bbls		Average		MCFE		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Six months ended
Nine months ended
6/30/2024		4,164,955	$	2.07		89,088	$	76.81		64,179	$	22.63		5,084,557	$	3.33
9/30/2024		6,063,397	$	2.05		134,786	$	76.14		98,511	$	21.57		7,463,177	$	3.32
6/30/2023		3,813,496	$	2.75		95,116	$	75.09		67,033	$	22.02		4,786,390	$	3.99
9/30/2023		5,681,508	$	2.63		143,148	$	76.23		99,063	$	21.48		7,134,770	$	3.92

The production increase in royalty volumes during the ~~six~~nine months ended ~~June~~September 30, 2024, as compared to the ~~six~~nine months ended ~~June~~September 30, 2023, resulted primarily from new wells ~~being brought online~~ in the Haynesville Shale and SCOOP plays coming online. The production decrease in working interest volumes during the ~~six~~nine months ended ~~June~~September 30, 2024, as compared to the ~~six~~nine months ended ~~June~~September 30, 2023, resulted from natural production decline ~~and divestitures of working interest properties~~.

Lease Bonuses and Rental Income:

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Lease bonuses and rental income	$	~~285~~445,~~944~~215	$	~~425~~1,~~141~~045,242	(3357%)

When we lease our mineral interests, we generally receive an upfront cash payment, or lease bonus. Lease bonuses and rental income decreased $~~139~~600,~~197~~027 in the ~~six~~nine months ended ~~June~~September 30, 2024 period compared to the ~~six~~nine months ended ~~June~~September 30, 2023, primarily as the result of decreased leasing activity.

Gains (Losses) on Derivative Contracts:

(1920)

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
						Percent
	2024			2023		Incr. or (Decr.)
Cash received (paid) on derivative contracts:
Cash received (paid) on derivative contracts, net(1)	$	23,~~853~~786,~~916~~071		$	12,~~679~~282,~~362~~307	7066%
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(2,~~645~~488,~~421~~334	)	$	21,~~306~~365,~~464~~872	(~~215~~282%)
Gains (losses) on derivative contracts, net	$	~~208~~1,~~495~~297,737		$	3,~~985~~648,~~826~~179	(9564%)
	As of June 30,
	As of September 30,
	2024			2023
Fair value of derivative contracts
Net asset (net liability)	$	~~638~~795,~~166~~253		$	1346,~~287,520~~928	~~(50~~129%)

(1) Excludes $373,745 of cash paid to settle off-market derivative contracts that are not reflected on the Condensed Statements of Operations for the ~~six~~nine months ended ~~June~~September 30, 2023.

Costs and Expenses:

Lease Operating Expenses (LOE):

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Lease operating expenses	$	~~626~~921,~~763~~483	$	~~916~~1,~~405~~279,831	(3228%)
Lease operating expenses per working interest MCFE	$	1.2115	$	1.34	(1014%)
Lease operating expenses per MCFE	$	0.12	$	0.1918	(3733%)

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 $~~289~~358,~~642~~348, or 3228%, in the ~~six~~nine months ended ~~June~~September 30, 2024 compared to the ~~six~~nine months ended ~~June~~September 30, 2023. The decrease in LOE was principally the result of the divestiture of higher LOE working interest properties.

Transportation, Gathering and Marketing:

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Transportation, gathering and marketing	$	23,~~383~~495,~~900~~880	$	2,~~035~~729,~~129~~044	1728%
Transportation, gathering and marketing per MCFE	$	0.47	$	0.4338	924%

Transportation, gathering and marketing costs increased $~~348~~766,~~771~~836, or 1728%, in ~~six~~nine months ended ~~June~~September 30, 2024 compared to the ~~six~~nine months ended ~~June~~September 30, 2023. This increase was primarily driven by the increase in production. Natural gas sales bear the large majority of our transportation, gathering and marketing fees, and the increase in production occurred in an area of the Louisiana Haynesville with higher transportation, gathering and marketing rates.

(2021)

Production and Ad Valorem Taxes:

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
							Percent
	2024			2023			Incr. or (Decr.)
Production and ad valorem taxes	$	~~990~~1,~~322~~418,899		$	~~986~~1,~~838~~424,679		0(—%)
Production and ad valorem taxes as % of sales		5.97	%		5.21	%	1312%

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 remained relatively flat in the ~~six~~nine months ended ~~June~~September 30, 2024 as compared to the ~~six~~nine months ended ~~June~~September 30, 2023.

Depreciation, Depletion and Amortization (DD&A):

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Depreciation, depletion and amortization	$	47,~~624~~000,~~610~~635	$	46,~~100~~123,~~322~~031	1314%
Depreciation, depletion and amortization per MCFE	$	0.9194	$	0.86	69%

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 $~~524~~877,~~288~~604, or 1314%, in the ~~six~~nine months ended ~~June~~September 30, 2024 compared to the ~~six~~nine months ended ~~June~~September 30, 2023, of which $~~256~~282,~~429~~428 of the increase resulted from production increasing 65% and an increase of $~~267~~595,~~859~~176 resulted from a $0.0508 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~~nine months ended ~~June~~September 30, 2024, contributed to the increase in DD&A.

Provision for Impairment:

During the ~~six~~nine months ended ~~June~~September 30, 2024, there was no impairment recognized. During the ~~six~~nine months ended ~~June~~September 30, 2023, impairment of $238,~~073~~533 was related to working interest wells in which we assigned our interests to the operator.

Interest expense:

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Interest expense	$	1,~~366~~989,~~868~~348	$	1,~~081~~638,~~767~~708	2621%
Weighted average debt outstanding	$	3130,~~134~~186,~~615~~131	$	26,~~650~~145,~~829~~788	1715%

The increase in interest expense was due to a higher average debt balance and average interest rate in the ~~six~~nine months ended ~~June~~September 30, 2024 compared to the ~~six~~nine months ended ~~June~~September 30, 2023.

Income Tax Expense:

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
Provision (benefit) for income taxes	$	~~397~~854,~~483~~738	$	23,~~901~~490,000	(8676%)

Income taxes decreased $2,~~503~~635,~~517~~262, from $23,~~901~~490,000 in the ~~six~~nine months ended ~~June~~September 30, ~~2024~~2023 to $~~397~~854,~~483~~738 in the ~~six~~nine months ended ~~June~~September 30, ~~2023~~2024. The change in income taxes resulted from a decrease in net income and the discrete income tax expense for deferred directors' compensation benefit, ~~and~~ changes in state tax rates, and prior year true-ups recorded in the ~~six~~nine months ended ~~June~~September 30, 2024.

(22)

General and Administrative Costs (G&A):

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
					Percent
	2024		2023		Incr. or (Decr.)
General and administrative	$	68,~~081~~765,~~665~~099	$	68,~~159~~919,~~012~~354	(12%)

~~(21)~~G&A are costs not directly associated with the production of natural gas and oil and include the cost of employee salaries and related benefits, office expenses and fees for professional services. G&A for the nine months ended September 30, 2024 decreased $154,255 as compared to the nine months ended September 30, 2023.

Losses (Gains) on Asset Sales and Other:

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
							Percent
	2024			2023			Incr. or (Decr.)
Losses (gains) on asset sales and other	$	(~~173~~110,~~114~~866	)	$	(4,~~195~~369,~~121~~613	)	(9697%)

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

LIQUIDITY AND CAPITAL RESOURCES

We had positive working capital (current assets less current liabilities excluding current derivatives) of $64,~~086~~872,~~124~~106 at ~~June~~September 30, 2024, compared to positive working capital of $5,029,698 at December 31, 2023.

Liquidity:

Cash and cash equivalents were $2,~~271~~601,~~544~~681 as of ~~June~~September 30, 2024, compared to $806,254 at December 31, 2023, an increase of $1,~~465~~795,~~290~~427. Cash flows for the ~~six~~nine months ended ~~June~~September 30, 2024 and 2023 are summarized as follows:

Net cash provided (used) by:	For the ~~Six~~Nine Months Ended ~~June~~September 30,
	2024			2023			Change
Operating activities	$	915,~~423~~207,~~355~~852		$	1320,~~849~~809,~~265~~684		$	(45,~~425~~601,~~910~~832	)
Investing activities		(14,~~798~~810,~~129~~308	)		(216,~~966~~148,~~017~~489	)		111,~~167~~338,~~888~~181
Financing activities		(68,~~159~~602,~~936~~117	)		(115,~~731~~541,~~273~~654	)		5(3,~~571~~060,~~337~~463	)
Increase (decrease) in cash and cash equivalents	$	1,~~465~~795,~~290~~427		$	(~~848~~880,~~025~~459	)	$	2,~~313~~675,~~315~~886

Operating activities:

Net cash provided by operating activities decreased $45,~~425~~601,~~910~~832 during the ~~six~~nine months ended ~~June~~September 30, 2024, as compared to the ~~six~~nine months ended ~~June~~September 30, 2023, 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 $67,~~412~~793,~~665~~227;

•

decreased lease bonus receipts of $~~195~~657,~~713~~293; and

•

increased interest payments of $~~254~~388,~~074~~380;

partially offset by:

•

increased net receipts on derivative contracts of $~~988~~1,~~137~~503,764;

•

decreased payments for G&A and other expense of $65290,~~012~~133;

~~decreased field operating expenses of $152,827; and~~ (23)

•

decreased ~~income~~field ~~tax~~operating ~~payments~~expenses of $1130,~~230,566.~~935; and

•

~~(22)~~decreased income tax payments of $1,312,236.

Investing activities:

Net cash used in investing activities decreased $111,~~167~~338,~~888~~181 during the ~~six~~nine months ended ~~June~~September 30, 2024, as compared to the ~~six~~nine months ended ~~June~~September 30, 2023, primarily due to lower acquisition costs of $920,~~635~~110,~~825~~912 and lower payments of $~~239~~256,~~693~~768 for capital expenditures on legacy working interest wells and furniture and fixtures, partially offset by lower net proceeds from the sale of assets of $89,~~707~~029,~~630~~499.

Financing activities:

Net cash used in financing activities ~~decreased~~increased $53,~~571~~060,~~337~~463 during the ~~six~~nine months ended ~~June~~September 30, 2024, as compared to the ~~six~~nine months ended ~~June~~September 30, 2023, primarily due to net payments on long-term debt of $45,000,000 in the ~~six~~nine months ended ~~June~~September 30, 2024 compared to net payments of $92,550,000 in the ~~six~~nine months ended ~~June~~September 30, 2023 and an increase of $1,171,294 in dividend payments, partially offset by decreased cash payments on off-market derivative contracts of $560,162~~, partially offset by an increase of $539,494 in dividend payments~~.

Capital Resources:

We had no capital expenditures to drill and complete new wells in the ~~six~~nine months ended ~~June~~September 30, 2024 and 2023 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 working interests 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~~Total ~~Paid~~Purchase Price (1)	~~Total~~Area ~~Purchase~~of ~~Price (1)~~Interest	~~Area of Interest~~
June 30, 2024
September 30, 2024
	96	$0.9 million	$0.9 million	Haynesville / SCOOP
	325	$3.0 million	Haynesville / SCOOP
March 31, 2024
June 30, 2024
	146	$1.4 million	$1.4 million	SCOOP
	96	$0.9 million	Haynesville / SCOOP
December 31, 2023
March 31, 2024
	325	$4.3 million	$4.3 million	Haynesville / SCOOP
	146	$1.4 million	SCOOP
September 30, 2023
December 31, 2023
	974	$13.4 million	$13.4 million	Haynesville / SCOOP
	325	$4.3 million	Haynesville / SCOOP
June 30, 2023
September 30, 2023
	151	$1.8 million	$1.8 million	Haynesville / SCOOP
	974	$13.4 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~~nine months ended ~~June~~September 30, 2024 and 2023 totaling approximately $0.35 million and $01.51 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~~September 30, 2024.

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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
	Nine Months Ended
	June 30, 2024
	September 30, 2024
Cash provided by operating activities	$	915,~~423~~207,~~355~~852
Cash provided (used) by:
Capital expenditures - acquisitions		(25,~~278~~272,~~178~~847	)
Capital expenditures - legacy working interest wells and furniture and fixtures		(3564,~~726~~628	)
Quarterly dividends		(23,~~159~~602,~~936~~117	)
Net payments on credit facility		(45,000,000	)
Net proceeds from sale of assets		~~515~~527,~~775~~167
Net cash used		(713,~~958~~412,~~065~~425	)
Net increase in cash	$	1,~~465~~795,~~290~~427

Outstanding borrowings under our Credit Facility at ~~June~~September 30, 2024 were $2827,750,000.

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~~September 30, 2024, we had availability of $2122.3 million under our Credit Facility and were in compliance with all debt covenants (current ratio, debt to trailing 12-month EBITDAX, 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 $50,000,000 as of ~~June~~September 30, 2024, and a maturity date of September 1, 2028. 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 2024, 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 December 31, 2023.

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 December 31, 2023.

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 2024 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 2024 derivative contracts, the price sensitivity for each $0.10 per MCF change in wellhead natural gas price is approximately $745,708 for operating revenue based on our fiscal year ended December 31, 2023 natural gas volumes. The price sensitivity in 2024 for each $1.00 per barrel change in wellhead oil is approximately $182,916 for operating revenue based on our fiscal year ended December 31, 2023 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~~September 30, 2024, we had $2827,750,000 outstanding under the Credit Facility and the effective interest rate was 8.6236%. 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 $~~143~~208,~~750~~125 for the ~~six~~nine months ended ~~June~~September 30, 2024, 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.

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Changes in Internal Control over Financial Reporting.

There were no changes in our “internal control over financial reporting,” as such term is defined in Rule 13a-15(f) under the Exchange Act, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting made during the quarter ended ~~June~~September 30, 2024.

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 December 31, 2023 as well as the factors discussed elsewhere in this Form 10-Q. There have been no material changes to the risk factors contained in the Annual Report on Form 10-K for the fiscal year ended December 31, 2023. 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 made no repurchases of Common Stock under the Repurchase Program during the quarter ended ~~June~~September 30, 2024.

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.

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	Certificate of Amendment to Certificate of Incorporation of PHX Minerals Inc., as amended (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 20, 2024).
	3.3	Second Amended and Restated Bylaws of PHX Minerals Inc. (incorporated by reference to Exhibit 3.1 to Form 8‑K/A filed July 19, 2024).

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		10.1		Sixth Amendment to Credit Agreement dated as of April 18, 2024, 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 10.1 to Form 8-K filed April 18, 2024).
		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 7, 2024		/s/ Chad L. Stephens
November 6, 2024		/s/ Chad L. Stephens
Date		Chad L. Stephens, President,
		Chief Executive Officer
August 7, 2024		/s/ Ralph D’Amico
November 6, 2024		/s/ Ralph D’Amico
Date		Ralph D’Amico, Executive Vice President,
		Chief Financial Officer

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