PHX PHX Minerals Inc

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

 

FORM 8-K

 

CURRENT REPORT

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

Date of Report (Date of earliest event reported): November 06, 2024

 

 

PHX MINERALS INC.

(Exact name of Registrant as Specified in Its Charter)

 

 

Delaware			001-31759	73-1055775
(State or Other Jurisdiction of Incorporation)			(Commission File Number)	(IRS Employer Identification No.)
1320 South University Drive Suite 720
Fort Worth, Texas				76107
(Address of Principal Executive Offices)				(Zip Code)

 

Registrant’s Telephone Number, Including Area Code: (405) 948-1560

 

(Former Name or Former Address, if Changed Since Last Report)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

Securities registered pursuant to 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 is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).

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. ☐

 

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Item 2.02	Results of Operations and Financial Condition.

On November 6, 2024, PHX Minerals Inc. (the “Company”) issued a press release providing information regarding the Company’s quarter ended September 30, 2024 financial and operating results. The press release is furnished as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated by reference herein.

Item 7.01	Regulation FD Disclosure.

The information set forth under Item 2.02 of this Current Report on Form 8-K is hereby incorporated in this Item 7.01 by reference.

 

On November 6, 2024, the Company posted an updated investor presentation to its website. A copy of the presentation is furnished as Exhibit 99.2 to this Current Report on Form 8-K.

 

The information in Item 2.02 and Item 7.01 of this Current Report on Form 8-K, including the attached Exhibit 99.1 and 99.2, is being furnished pursuant to Item 2.02 and Item 7.01 and shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, and shall not be deemed to be incorporated by reference into any of the Company’s filings under the Securities Act of 1933, as amended, or the Exchange Act, whether made before or after the date hereof and regardless of any general incorporation language in such filings, except to the extent expressly set forth by specific reference in such a filing.

 

Item 9.01	Financial Statements and Exhibits

	(d)	Exhibits.

Exhibit No.	Title of Document
99.1	Press Release, dated November 6, 2024
99.2	Corporate Presentation
104	Cover Page Interactive Data File (embedded within the Inline XBRL document).

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SIGNATURES

 

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

 

PHX MINERALS INC.

 

		By:	/s/ Chad L. Stephens
			Chad L. Stephens
			Chief Executive Officer
DATE:	November 6, 2024

 

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PHX Minerals Reports Results for the Quarter Ended Sept. 30, 2024

 

FORT WORTH, Texas, Nov. 6, 2024 – PHX MINERALS INC., “PHX” or the “Company” (NYSE: PHX), today reported financial and operating results for the quarter ended Sept. 30, 2024.

 

Summary of Results for the Quarter Ended Sept. 30, 2024

 

 

Subsequent Events

 

Chad L. Stephens, President and CEO, commented, “PHX generated our second-highest quarter for royalty volumes in our history, validating the quality of our asset base even amidst continued volatility in commodity pricing. We remain positive on natural gas prices as we move into a seasonal stronger period and are seeing sequential increased rig activities on and around our mineral acreage, further bolstering our longer-term outlook.

“During the quarter, we saw a growing pipeline of attractive M&A opportunities,” continued Mr. Stephens. “We purchased 325 net royalty acres for $3.0 million and replaced 100% of the wells in progress that converted to production. We also reduced our debt by $1.0 million sequentially with cashflow generated from our production. With a strong balance sheet, and a proven track record of acquiring attractive mineral assets that produce cash flow even during challenging pricing, we are well-positioned for continued success.

“Our risk-mitigated business is built for resilient and sustainable profitability even during challenging pricing environments, and our strategic advantages are evident through commodity price cycles,” concluded Mr. Stephens.

 

 

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Financial Highlights

 

		Three Months Ended				Three Months Ended				Nine Months Ended				Nine Months Ended
		Sept. 30, 2024				Sept. 30, 2023				Sept. 30, 2024				Sept. 30, 2023
Royalty Interest Sales		$	6,982,112			$	7,873,297			$	21,977,351			$	24,214,701
Working Interest Sales		$	906,404			$	1,025,794			$	2,827,379			$	3,772,801
Natural Gas, Oil and NGL Sales		$	7,888,516			$	8,899,091			$	24,804,730			$	27,987,502
Gains (Losses) on Derivative Contracts		$	1,089,242			$	(337,647	)		$	1,297,737			$	3,648,179
Lease Bonuses and Rental Income		$	159,271			$	620,101			$	445,215			$	1,045,242
Total Revenue		$	9,137,029			$	9,181,545			$	26,547,682			$	32,680,923
Lease Operating Expense
per Working Interest Mcfe		$	1.05			$	1.32			$	1.15			$	1.34
Transportation, Gathering and
Marketing per Mcfe		$	0.47			$	0.30			$	0.47			$	0.38
Production and Ad Valorem Tax
per Mcfe		$	0.18			$	0.19			$	0.19			$	0.20
G&A Expense per Mcfe		$	1.13			$	1.18			$	1.17			$	1.25
Cash G&A Expense per Mcfe (1)		$	0.91			$	0.95			$	0.92			$	0.99
Interest Expense per Mcfe		$	0.26			$	0.24			$	0.27			$	0.23
DD&A per Mcfe		$	1.00			$	0.86			$	0.94			$	0.86
Total Expense per Mcfe		$	3.16			$	2.92			$	3.16			$	3.10
Net Income (Loss)		$	1,100,310			$	1,895,403			$	2,212,466			$	11,407,356
Adjusted EBITDA (2)		$	4,905,335			$	6,321,029			$	15,938,535			$	18,147,976
Cash Flow from Operations (3)		$	5,784,497			$	6,960,419			$	15,207,852			$	20,809,684
CapEx (4)		$	28,902			$	45,977			$	64,628			$	321,396
CapEx - Mineral Acquisitions		$	2,994,669			$	13,469,756			$	5,272,847			$	25,383,759
Borrowing Base										$	50,000,000			$	45,000,000
Debt										$	27,750,000			$	30,750,000
Debt-to-Adjusted EBITDA (TTM) (2)											1.36				1.31

 

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Operating Highlights

 

	Three Months Ended				Three Months Ended				Nine Months Ended				Nine Months Ended
	Sept. 30, 2024				Sept. 30, 2023				Sept. 30, 2024				Sept. 30, 2023
Gas Mcf Sold		1,898,442				1,868,012				6,063,397				5,681,508
Average Sales Price per Mcf before the
effects of settled derivative contracts	$	2.00			$	2.40			$	2.05			$	2.63
Average Sales Price per Mcf after the
effects of settled derivative contracts	$	2.54			$	2.72			$	2.70			$	3.03
% of sales subject to hedges		48	%			46	%			48	%			46	%
Oil Barrels Sold		45,698				48,032				134,786				143,148
Average Sales Price per Bbl before the
effects of settled derivative contracts	$	74.83			$	78.48			$	76.14			$	76.23
Average Sales Price per Bbl after the
effects of settled derivative contracts	$	72.95			$	78.44			$	74.78			$	73.88
% of sales subject to hedges		31	%			35	%			31	%			44	%
NGL Barrels Sold		34,332				32,029				98,511				99,063
Average Sales Price per Bbl(1)	$	19.60			$	20.35			$	21.57			$	21.48
Mcfe Sold		2,378,622				2,348,378				7,463,177				7,134,770
Natural gas, oil and NGL sales before the
effects of settled derivative contracts	$	7,888,516			$	8,899,091			$	24,804,730			$	27,987,502
Natural gas, oil and NGL sales after the
effects of settled derivative contracts	$	8,820,672			$	9,502,036			$	28,590,801			$	29,896,064
(1) There were no NGL settled derivative contracts during the 2024 and 2023 periods.

Total Production for the last four 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

 

The percentage of total production volumes attributable to natural gas was 80% for the quarter ended Sept. 30, 2024.

 

Royalty Interest Production for the last four 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

 

The percentage of royalty production volumes attributable to natural gas was 82% for the quarter ended Sept. 30, 2024.

 

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Working Interest Production for the last four 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

 

Quarter Ended Sept. 30, 2024 Results

 

The Company recorded net income of $1.1 million, or $0.03 per diluted share, for the quarter ended Sept. 30, 2024, as compared to net income of $1.90 million, or $0.05 per diluted share, for the quarter ended Sept. 30, 2023. The change in net income was principally the result of a decrease in natural gas, oil and NGL sales, a decrease in lease bonuses, an increase in transportation, gathering and marketing expenses and an increase in depreciation, depletion and amortization expenses, partially offset by an increase in gains associated with our derivative contracts.

 

Natural gas, oil and NGL revenue decreased $1.0 million, or 11%, for the quarter ended Sept. 30, 2024, compared to the quarter ended Sept. 30, 2023, due to decreases in natural gas, oil, and NGL prices of 17%, 5%, and 4%, respectively, and a decrease in oil volumes of 5%, partially offset by increases in natural gas and NGL volumes of 2% and 7%, respectively.

The increase in royalty production volumes during the quarter ended Sept. 30, 2024, as compared to the quarter ended Sept. 30, 2023, resulted primarily from new wells being brought online in the Haynesville Shale and SCOOP plays.

The Company had a net gain on derivative contracts of $1.1 million for the quarter ended Sept. 30, 2024, comprised of a $0.9 million gain on settled derivatives and a $0.2 million non-cash gain on derivatives, as compared to a net loss of ($0.3) million for the quarter ended Sept. 30, 2023. The change in net gain on derivative contracts was due to the Company’s settlements of natural gas and oil collars and fixed price swaps and the change in valuation caused by the difference in Sept. 30, 2024 pricing relative to the strike price on open derivative contracts.

Nine Months Ended Sept. 30, 2024 Results

The Company recorded net income of $2.2 million, or $0.06 per diluted share, for the nine months ended Sept. 30, 2024, as compared to a net income of $11.4 million, or $0.31 per diluted share, for the nine months ended Sept. 30, 2023. The change in net income was principally the result of a decrease in natural gas, oil and NGL sales, a decrease in gains associated with our hedge contracts, a 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 a decrease in income tax provision.

Natural gas, oil and NGL revenue decreased $3.2 million, or 11%, for the nine months ended Sept. 30, 2024, compared to the nine months ended Sept. 30, 2023, due to a decrease in natural gas prices of 22% and decreases in oil and NGL volumes of 6% and 1%, respectively, partially offset by an increase in gas volumes of 7%.

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

The Company had a net gain on derivative contracts of $1.3 million for the nine months ended Sept. 30, 2024, comprised of a $3.8 million gain on settled derivatives and a $2.5 million non-cash loss on derivatives, as compared to a net gain of $3.6 million for the nine months ended Sept. 30, 2023. The change in net gain on derivative contracts was due to the Company’s settlements of natural gas and oil collars and fixed price swaps and the change in valuation caused by the difference in Sept. 30, 2024 pricing relative to the strike price on open derivative contracts.

Operations Update

 

During the quarter ended Sept. 30, 2024, the Company converted 46 gross (0.18 net) wells to producing status, including 12 gross (0.11 net) wells in the Haynesville and 18 gross (0.04 net) wells in the SCOOP, compared to 71 gross (0.16 net) wells converted in the quarter ended Sept. 30, 2023.

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At Sept. 30, 2024, the Company had a total of 278 gross (0.93 net) wells in progress and permits across its mineral positions, compared to 241 gross (0.93 net) wells in progress and permits at June 30, 2024. As of Sept. 30, 2024, 18 rigs were operating on the Company’s acreage and 70 rigs were operating within 2.5 miles of its acreage.

									Bakken/
									Three				Arkoma
	SCOOP				STACK				Forks				Stack				Haynesville				Other				Total
As of Sept. 30, 2024:
Gross Wells in Progress on PHX Acreage (1)		84				13				4				3				69				3				176
Net Wells in Progress on PHX Acreage (1)		0.351				0.021				0.001				0.015				0.240				0.030				0.658
Gross Active Permits on PHX Acreage		43				4				3				9				32				11				102
Net Active Permits on PHX Acreage		0.093				0.008				0.003				0.030				0.100				0.041				0.275
As of Sept. 30, 2024:
Rigs Present on PHX Acreage		9				2				1				-				4				2				18
Rigs Within 2.5 Miles of PHX Acreage		12				12				13				-				20				13				70

(1) Wells in progress includes drilling wells and drilled but uncompleted wells, or DUCs.

 

Leasing Activity

During the quarter ended Sept. 30, 2024, the Company leased 183 net mineral acres to third-party exploration and production companies for an average bonus payment of $688 per net mineral acre and an average royalty of 25%.

 

Acquisition and Divestiture Update

 

During the quarter ended Sept. 30, 2024, the Company purchased 325 net royalty acres for approximately $3.0 million and had no significant divestitures.

 

		Acquisitions
		SCOOP				Haynesville				Other		Total
During Three Months Ended Sept. 30, 2024:
Net Mineral Acres Purchased			20				181			-			201
Net Royalty Acres Purchased			40				285			-			325

Quarterly Conference Call

PHX will host a conference call to discuss the Company’s results for the quarter ended Sept. 30, 2024, at 12 p.m. EST on Nov. 7, 2024. Management’s discussion will be followed by a question-and-answer session with investors.

To participate on the conference call, please dial 877-407-3088 (toll-free domestic) or 201-389-0927. A replay of the call will be available for 14 days after the call. The number to access the replay of the conference call is 877-660-6853 and the PIN for the replay is 13748980.

A live audio webcast of the conference call will be accessible from the “Investors” section of PHX’s website at https://phxmin.com/events. The webcast will be archived for at least 90 days.

 

 

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FINANCIAL RESULTS

Statements of Income

	Three Months Ended Sept. 30,								Nine Months Ended Sept. 30,
	2024				2023				2024				2023
Revenues:
Natural gas, oil and NGL sales	$	7,888,516			$	8,899,091			$	24,804,730			$	27,987,502
Lease bonuses and rental income		159,271				620,101				445,215				1,045,242
Gains (losses) on derivative contracts		1,089,242				(337,647	)			1,297,737				3,648,179
		9,137,029				9,181,545				26,547,682				32,680,923
Costs and expenses:
Lease operating expenses		294,720				363,426				921,483				1,279,831
Transportation, gathering and marketing		1,111,980				693,915				3,495,880				2,729,044
Production and ad valorem taxes		428,577				437,841				1,418,899				1,424,679
Depreciation, depletion and amortization		2,376,025				2,022,709				7,000,635				6,123,031
Provision for impairment		-				36,460				-				38,533
Interest expense		622,480				556,941				1,989,348				1,638,708
General and administrative		2,683,434				2,760,342				8,765,099				8,919,354
Losses (gains) on asset sales and other		62,248				(174,492	)			(110,866	)			(4,369,613	)
Total costs and expenses		7,579,464				6,697,142				23,480,478				17,783,567
Income (loss) before provision for income taxes		1,557,565				2,484,403				3,067,204				14,897,356
Provision for income taxes		457,255				589,000				854,738				3,490,000
Net income (loss)	$	1,100,310			$	1,895,403			$	2,212,466			$	11,407,356
Basic earnings per common share	$	0.03			$	0.05			$	0.06			$	0.32
Diluted earnings per common share	$	0.03			$	0.05			$	0.06			$	0.31
Weighted average shares outstanding:
Basic		36,316,742				35,983,116				36,306,593				35,961,570
Diluted		36,983,669				36,656,272				36,731,643				36,670,494
Dividends per share of
common stock paid in period	$	0.0400			$	0.0225			$	0.1000			$	0.0675

 

 

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Balance Sheets

 

	Sept. 30, 2024				Dec. 31, 2023
Assets
Current assets:
Cash and cash equivalents	$	2,601,681			$	806,254
Natural gas, oil, and NGL sales receivables (net of $0		4,080,560				4,900,126
allowance for uncollectable accounts)
Refundable income taxes		343,814				455,931
Derivative contracts, net		761,527				3,120,607
Other		417,929				878,659
Total current assets		8,205,511				10,161,577
Properties and equipment at cost, based on
successful efforts accounting:
Producing natural gas and oil properties		219,958,671				209,082,847
Non-producing natural gas and oil properties		52,503,370				58,820,445
Other		1,361,064				1,360,614
		273,823,105				269,263,906
Less accumulated depreciation, depletion and amortization		(120,301,196	)			(114,139,423	)
Net properties and equipment		153,521,909				155,124,483
Derivative contracts, net		33,726				162,980
Operating lease right-of-use assets		466,135				572,610
Other, net		596,830				486,630
Total assets	$	162,824,111			$	166,508,280
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	512,936			$	562,607
Current portion of operating lease liability		243,184				233,390
Accrued liabilities and other		1,815,758				1,215,275
Total current liabilities		2,571,878				2,011,272
Long-term debt		27,750,000				32,750,000
Deferred income taxes, net		7,289,591				6,757,637
Asset retirement obligations		1,087,416				1,062,139
Operating lease liability, net of current portion		512,357				695,818
Total liabilities		39,211,242				43,276,866
Stockholders' equity:
Common Stock, $0.01666 par value; 75,000,000 shares authorized and
36,121,723 issued at Sept. 30, 2024; 54,000,500 shares authorized
and 36,121,723 issued at Dec. 31, 2023		601,788				601,788
Capital in excess of par value		43,526,595				41,676,417
Deferred directors' compensation		1,276,295				1,487,590
Retained earnings		78,492,889				80,022,839
		123,897,567				123,788,634
Less treasury stock, at cost; 67,203 shares at Sept. 30,
2024, and 131,477 shares at Dec. 31, 2023		(284,698	)			(557,220	)
Total stockholders' equity		123,612,869				123,231,414
Total liabilities and stockholders' equity	$	162,824,111			$	166,508,280

 

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Condensed Statements of Cash Flows

 

	Nine Months Ended
	Sept. 30, 2024				Sept. 30, 2023
Operating Activities
Net income (loss)	$	2,212,466			$	11,407,356
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depreciation, depletion and amortization		7,000,635				6,123,031
Impairment of producing properties		-				38,533
Provision for deferred income taxes		531,954				3,256,000
Gain from leasing fee mineral acreage		(445,215	)			(1,045,242	)
Proceeds from leasing fee mineral acreage		451,616				1,108,909
Net (gain) loss on sales of assets		(518,816	)			(4,671,253	)
Directors' deferred compensation expense		137,617				165,582
Total (gain) loss on derivative contracts		(1,297,737	)			(3,648,179	)
Cash receipts (payments) on settled derivative contracts		3,786,071				2,468,724
Restricted stock award expense		1,773,789				1,695,637
Other		76,375				105,604
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables		819,566				4,369,921
Income taxes receivable		112,117				(712,475	)
Other current assets		430,119				408,533
Accounts payable		(68,183	)			(107,796	)
Other non-current assets		(81,037	)			150,515
Income taxes payable		-				(576,427	)
Accrued liabilities		286,515				272,711
Total adjustments		12,995,386				9,402,328
Net cash provided by operating activities		15,207,852				20,809,684
Investing Activities
Capital expenditures		(64,628	)			(321,396	)
Acquisition of minerals and overriding royalty interests		(5,272,847	)			(25,383,759	)
Net proceeds from sales of assets		527,167				9,556,666
Net cash provided by (used in) investing activities		(4,810,308	)			(16,148,489	)
Financing Activities
Borrowings under credit facility		1,000,000				16,000,000
Payments of loan principal		(6,000,000	)			(18,550,000	)
Payments on off-market derivative contracts		-				(560,162	)
Purchases of treasury stock		-				(669	)
Payments of dividends		(3,602,117	)			(2,430,823	)
Net cash provided by (used in) financing activities		(8,602,117	)			(5,541,654	)
Increase (decrease) in cash and cash equivalents		1,795,427				(880,459	)
Cash and cash equivalents at beginning of period		806,254				2,115,652
Cash and cash equivalents at end of period	$	2,601,681			$	1,235,193
Supplemental Disclosures of Cash Flow Information:
Interest paid (net of capitalized interest)	$	2,041,252			$	1,652,872
Income taxes paid (net of refunds received)	$	210,668			$	1,522,904
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid	$	140,300			$	94,587
Gross additions to properties and equipment	$	5,386,597			$	26,392,844
Net increase (decrease) in accounts receivable for properties
and equipment additions		(49,122	)			(687,689	)
Capital expenditures and acquisitions	$	5,337,475			$	25,705,155

 

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Derivative Contracts as of Sept. 30, 2024

		Production volume
Contract period		covered per month		Index		Contract price
Natural gas costless collars
October 2024 - June 2025		30,000 Mmbtu		NYMEX Henry Hub		$3.00 floor / $5.00 ceiling
November 2024 - March 2025		90,000 Mmbtu		NYMEX Henry Hub		$3.25 floor / $5.25 ceiling
November - December 2024		35,000 Mmbtu		NYMEX Henry Hub		$3.50 floor / $5.15 ceiling
December 2024		75,000 Mmbtu		NYMEX Henry Hub		$3.00 floor / $3.37 ceiling
January - March 2025		25,000 Mmbtu		NYMEX Henry Hub		$3.00 floor / $3.37 ceiling
January - March 2025		30,000 Mmbtu		NYMEX Henry Hub		$3.50 floor / $5.15 ceiling
January 2025		55,000 Mmbtu		NYMEX Henry Hub		$3.50 floor / $4.40 ceiling
February 2025		25,000 Mmbtu		NYMEX Henry Hub		$3.50 floor / $4.40 ceiling
March 2025		35,000 Mmbtu		NYMEX Henry Hub		$3.50 floor / $4.40 ceiling
April 2025 - September 2025		55,000 Mmbtu		NYMEX Henry Hub		$3.00 floor / $3.75 ceiling
November 2025 - March 2026		100,000 Mmbtu		NYMEX Henry Hub		$3.50 floor / $4.85 ceiling
November 2025 - March 2026		75,000 Mmbtu		NYMEX Henry Hub		$3.50 floor / $4.72 ceiling
November 2025 - March 2026		15,000 Mmbtu		NYMEX Henry Hub		$3.50 floor / $5.15 ceiling
Natural gas fixed price swaps
October 2024		50,000 Mmbtu		NYMEX Henry Hub		$3.17
October 2024		75,000 Mmbtu		NYMEX Henry Hub		$3.47
October 2024		25,000 Mmbtu		NYMEX Henry Hub		$3.47
October 2024		105,000 Mmbtu		NYMEX Henry Hub		$3.24
November 2024		25,000 Mmbtu		NYMEX Henry Hub		$2.80
November - December 2024		70,000 Mmbtu		NYMEX Henry Hub		$4.16
December 2024		50,000 Mmbtu		NYMEX Henry Hub		$3.39
January - March 2025		60,000 Mmbtu		NYMEX Henry Hub		$4.16
January - March 2025		50,000 Mmbtu		NYMEX Henry Hub		$3.51
April - May 2025		25,000 Mmbtu		NYMEX Henry Hub		$3.23
April - August 2025		125,000 Mmbtu		NYMEX Henry Hub		$3.01
April - October 2025		100,000 Mmbtu		NYMEX Henry Hub		$3.28
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 - October 2025		100,000 Mmbtu		NYMEX Henry Hub		$3.01
October 2025		100,000 Mmbtu		NYMEX Henry Hub		$3.23
April - June 2026		50,000 Mmbtu		NYMEX Henry Hub		$3.10
Oil costless collars
September 2024		500 Bbls		NYMEX WTI		$70.00 floor / $78.10 ceiling
September - October 2024		1,650 Bbls		NYMEX WTI		$65.00 floor / $76.50 ceiling
October - December 2024		500 Bbls		NYMEX WTI		$67.00 floor / $77.00 ceiling
Oil fixed price swaps
September - October 2024		1,000 Bbls		NYMEX WTI		$66.10
September - October 2024		1,500 Bbls		NYMEX WTI		$69.50
September 2024		500 Bbls		NYMEX WTI		$76.46
October 2024		500 Bbls		NYMEX WTI		$76.12
October 2024 - August 2025		1,000 Bbls		NYMEX WTI		$68.80
November 2024		500 Bbls		NYMEX WTI		$75.49
November - December 2024		2,000 Bbls		NYMEX WTI		$69.50
November 2024 - March 2025		1,600 Bbls		NYMEX WTI		$64.80
December 2024		500 Bbls		NYMEX WTI		$74.94
January 2025		500 Bbls		NYMEX WTI		$74.48
January - March 2025		500 Bbls		NYMEX WTI		$69.50
January - June 2025		2,000 Bbls		NYMEX WTI		$70.90
February 2025		500 Bbls		NYMEX WTI		$74.10

 

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March 2025		500 Bbls		NYMEX WTI		$73.71
April 2025		500 Bbls		NYMEX WTI		$73.30
April - June 2025		750 Bbls		NYMEX WTI		$69.50
April - June 2025		1,000 Bbls		NYMEX WTI		$68.00
May 2025		500 Bbls		NYMEX WTI		$72.92
June 2025		500 Bbls		NYMEX WTI		$72.58
July 2025		500 Bbls		NYMEX WTI		$72.24
July - August 2025		1,250 Bbls		NYMEX WTI		$70.81
July - September 2025		500 Bbls		NYMEX WTI		$69.50
July - December 2025		1,500 Bbls		NYMEX WTI		$68.90
August 2025		500 Bbls		NYMEX WTI		$71.88
September 2025		500 Bbls		NYMEX WTI		$71.60
September 2025		1,500 Bbls		NYMEX WTI		$68.80
October 2025		750 Bbls		NYMEX WTI		$71.12
October 2025		2,000 Bbls		NYMEX WTI		$68.80
November 2025		750 Bbls		NYMEX WTI		$70.99
November 2025 - March 2026		1,500 Bbls		NYMEX WTI		$68.80
December 2025		750 Bbls		NYMEX WTI		$70.66
January 2026		1,500 Bbls		NYMEX WTI		$70.53
February 2026		1,500 Bbls		NYMEX WTI		$71.28
March 2026		1,500 Bbls		NYMEX WTI		$70.42
April - June 2026		1,000 Bbls		NYMEX WTI		$68.80

Non-GAAP Reconciliation

This press release includes certain “non-GAAP financial measures” as defined under the rules and regulations of the U.S. Securities and Exchange Commission, or the SEC, including Regulation G. These non-GAAP financial measures are calculated using GAAP amounts in the Company’s financial statements. These measures, detailed below, are provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in the Company’s financial statements prepared in accordance with GAAP (including the notes thereto), included in the Company’s SEC filings and posted on its website.

Adjusted EBITDA Reconciliation

The Company defines “adjusted EBITDA” as earnings before interest, taxes, depreciation and amortization, or EBITDA, excluding non-cash gains (losses) on derivatives and gains (losses) on asset sales and including cash receipts from (payments on) off-market derivatives and restricted stock and deferred directors’ expense. The Company has included a presentation of adjusted EBITDA because it recognizes that certain investors consider this amount to be a useful means of measuring the Company’s ability to meet its debt service obligations and evaluating its financial performance. Adjusted EBITDA has limitations and should not be considered in isolation or as a substitute for net income, operating income, cash flow from operations or other consolidated income or cash flow data prepared in accordance with GAAP. Because not all companies use identical calculations, this presentation of adjusted EBITDA may

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not be comparable to a similarly titled measure of other companies. The following table provides a reconciliation of net income (loss) to adjusted EBITDA for the quarters indicated:

	Three Months Ended				Three Months Ended				Nine Months Ended				Nine Months Ended				Three Months Ended
	Sept. 30, 2024				Sept. 30, 2023				Sept. 30, 2024				Sept. 30, 2023				June 30, 2024
Net Income	$	1,100,310			$	1,895,403			$	2,212,466			$	11,407,356			$	1,295,771
Plus:
Income tax expense		457,255				589,000				854,738				3,490,000				355,151
Interest expense		622,480				556,941				1,989,348				1,638,708				651,982
DD&A		2,376,025				2,022,709				7,000,635				6,123,031				2,268,284
Impairment expense		-				36,460				-				38,533				-
Less:
Non-cash gains (losses)
on derivatives		157,086				(940,592	)			(2,488,334	)			1,365,872				(1,603,604	)
Gains (losses) on asset sales		6,708				243,041				518,391				4,671,254				445,184
Plus:
Cash payments on off-market derivative
contracts		-				-				-				(373,745	)			-
Restricted stock and deferred
director's expense		513,059				522,965				1,911,405				1,861,219				696,559
Adjusted EBITDA	$	4,905,335			$	6,321,029			$	15,938,535			$	18,147,976			$	6,426,167

 

Debt-to-Adjusted EBITDA (TTM) Reconciliation

 

“Debt-to-adjusted EBITDA (TTM)” is defined as the ratio of long-term debt to adjusted EBITDA on a trailing 12-month (TTM) basis. The Company has included a presentation of debt-to-adjusted EBITDA (TTM) because it recognizes that certain investors consider such ratios to be a useful means of measuring the Company’s ability to meet its debt service obligations and for evaluating its financial performance. The debt-to-adjusted EBITDA (TTM) ratio has limitations and should not be considered in isolation or as a substitute for net income, operating income, cash flow from operations or other consolidated income or cash flow data prepared in accordance with GAAP. Because not all companies use identical calculations, this presentation of debt-to-adjusted EBITDA (TTM) may not be comparable to a similarly titled measure of other companies. The following table provides a reconciliation of net income (loss) to adjusted EBITDA on a TTM basis and of the resulting debt-to-adjusted EBITDA (TTM) ratio:

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	TTM Ended				TTM Ended
	Sept. 30, 2024				Sept. 30, 2023
Net Income	$	4,725,910			$	14,753,489
Plus:
Income tax expense		2,100,198				4,471,000
Interest expense		2,713,033				2,276,406
DD&A		9,443,789				7,925,145
Impairment expense		-				6,139,229
Less:
Non-cash gains (losses)
on derivatives		448,324				7,630,914
Gains (losses) on asset sales		575,897				5,605,461
Plus:
Cash payments on off-market derivative
contracts		-				(1,277,206	)
Restricted stock and deferred
director's expense		2,484,115				2,430,303
Adjusted EBITDA	$	20,442,824			$	23,481,991
Debt	$	27,750,000			$	30,750,000
Debt-to-Adjusted EBITDA (TTM)		1.36				1.31

 

PHX Minerals Inc. Fort Worth-based, PHX Minerals Inc. is a natural gas and oil mineral company with a strategy to proactively grow its mineral position in its core focus areas. PHX owns mineral acreage principally located in Oklahoma, Texas, Louisiana, North Dakota and Arkansas. Additional information about the Company can be found at www.phxmin.com.

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Cautionary Statement Regarding Forward-Looking Statements

 

This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Words such as “anticipates,” “plans,” “estimates,” “believes,” “expects,” “intends,” “will,” “should,” “may” and similar expressions may be used to identify forward-looking statements. Forward-looking statements are not statements of historical fact and reflect PHX’s current views about future events. Forward-looking statements may include, but are not limited to, statements relating to: the Company’s operational outlook; the Company’s ability to execute its business strategies; the volatility of realized natural gas and oil prices; the level of production on the Company’s properties; estimates of quantities of natural gas, oil and NGL reserves and their values; general economic or industry conditions; legislation or regulatory requirements; conditions of the securities markets; the Company’s 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 the Company invests; and other economic, competitive, governmental, regulatory or technical factors affecting properties, operations or prices. Although the Company believes expectations reflected in these and other forward-looking statements are reasonable, the Company can give no assurance such expectations will prove to be correct. Such forward-looking statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. These forward-looking statements involve certain risks and uncertainties that could cause results to differ materially from those expected by the Company’s management. Information concerning these risks and other factors can be found in the Company’s filings with the SEC, including its Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on the Company’s website or the SEC’s website at www.sec.gov.

Investors are cautioned that any such forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those projected. The forward-looking statements in this press release are made as of the date hereof, and the Company does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise.

 

Investor Contact:

Rob Fink / Stephen Lee

FNK IR

646.809.4048

PHX@fnkir.com

Corporate Contact:

405.948.1560

inquiry@phxmin.com

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Investor Presentation November 2024 Exhibit 99.2 NYSE: PHX

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This presentation does not constitute an offer to sell, a solicitation of an offer to buy, or a recommendation to purchase any security of PHX Minerals Inc. (“PHX” or the “Company”).  No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended, or an exemption therefrom.   Cautionary Statement Regarding Forward-Looking Statements  This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that the company expects, believes or anticipates will or may occur in the future are forward looking statements. The words “anticipates”, “plans”, “estimates”, “believes”, “expects”, “intends”, “will”, “should”, “may” and similar expressions may be used to identify 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; 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.  Although the Company believes the expectations reflected in these and other forward-looking statements are reasonable, the Company can give no assurance such statements will prove to be correct. Such forward-looking statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the Company’s management. Information concerning these risks and other factors can be found in the Company’s filings with the Securities and Exchange Commission, including its Annual Report on Form 10-K and Quarterly Reports on Form 10-Q, available on the Company's website or the SEC’s website at www.sec.gov.  Readers are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this presentation are made as of the date hereof, and the Company does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise. Use of Non-GAAP Financial Information This presentation includes certain non-GAAP financial measures. Adjusted EBITDA is a supplemental non-GAAP measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. PHX defines “Adjusted EBITDA” as earnings before interest, taxes, depreciation and amortization, or EBITDA, excluding unrealized gains (losses) on derivatives and gains (losses) on asset sales and including cash receipts from (payments on) off-market derivatives and restricted stock and deferred directors’ expense. PHX references Adjusted EBITDA in this presentation because it recognizes that certain investors consider Adjusted EBITDA a useful means of measuring our ability to meet our debt service obligations and evaluating our financial performance. Adjusted EBITDA has limitations and should not be considered in isolation or as a substitute for net income, operating income, cash flow from operations or other consolidated income or cash flow data prepared in accordance with GAAP. Because not all companies use identical calculations, the Company’s calculations of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.  Oil and Gas Reserves The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty  to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. The Company discloses only estimated proved reserves in its filings with the SEC. The Company’s  estimated  proved reserves as of December 31, 2023, referenced in this presentation were prepared by Cawley, Gillespie and Associates, Inc, an independent engineering firm, and comply with definitions promulgated by the SEC. Additional information on the Company’s estimated proved reserves is contained in the Company’s filings with the SEC. Cautionary Statement Regarding Forward-Looking Statements

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Source: Company information and Enverus 1 Based on $3.69 per share as of 10/25/2024 and 37.5 million shares outstanding on a fully diluted basis  as of 9/30/2024 2 Market Cap plus debt of $27.8 million minus cash on hand of $2.6 million as of 9/30/2024 3 Calculated as working capital (current assets less current liabilities excluding current derivatives) plus availability on the borrowing base.  See Non-GAAP reconciliation in Appendix 4 Based on $0.16 annualized Dividend per share  5 Total Debt / TTM Adjusted EBITDA; See Non-GAAP Reconciliation in Appendix 6 See Non-GAAP reconciliation in Appendix  7 3P Reserves per 12/31/2023 CGA report proforma acquisitions, divestitures, and activity as of 9/30/2024 at 9/30/2024 SEC price deck of $77.21 per bbl of oil, $21.97 per bbl of NGL, $2.13 per mcf of gas (proved volume weighted average price)  8 As of 9/30/2024; average royalty rate of ~16%; PHX also owns 169,056 unleased net mineral acres  9 At mid-point of production outlook (see page 10)   Company Snapshot Key Statistics Market Cap1 $138.3 Enterprise Value2 $163.5 Liquidity3 $27.1 Dividend Yield4 4.3% Leverage5 1.36x LTM Adjusted EBITDA6 $20.4 LTM Discretionary Cash Flow Yield6 ~13% LTM ROCE6 ~7% Percent of 3P Reserves – Natural Gas7 ~77% Net Leased Royalty Acres8 88,637 Sustainable Organic Royalty Production Growth MMCFE Outlook9 3 $ in millions CAGR: ~28%

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Strategy Execution Goals Set in early 2020 Achievements Through Sept. 30, 2024 High Grade Asset Base Grow royalty production Increase inventory of undeveloped locations Improve operating margins Exit working interest assets Royalty production volumes up ~278% 2P royalty reserves up ~151% Completed ~$137 million in mineral acquisitions Built a 10+ year inventory of mineral locations with line-of-sight to development and conversion to cash flow Increased discretionary cash flow margin from 36% to 56% Divested ownership in 1,380 working interest wellbores Build a strong and sustainable balance sheet Maintained leverage ratio between 1.0x and 1.5x compared to over 2.5x in 2020 Entered into a new and improved commercial bank relationship Become a consolidator in the mineral space Allocate capital to generate the best possible returns to shareholders Mineral acquisitions completed: 86 Focus on smaller acquisition in targeted areas: ~$1.6 million average deal size generates higher returns with less competition Generate return on capital employed (ROCE) Generated annual ROCE1 between 9% and 15% since 2021; up from ~0% in 2019 and 2020 Return profile driven by royalty volume growth associated with new wells converting from undeveloped locations Improve balance sheet designed to withstand commodity price volatility 1 See Non-GAAP reconciliation in Appendix

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Focused in SCOOP and Haynesville Key Operators of PHX Minerals Source: Company info and Enverus 1 Rig data from Enverus as of 9/30/2024 PHX targets areas in key plays with significant active operator development activity Provides line of sight to conversion of undeveloped locations to cash flow

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Per Share NAV Continues to Grow 6 Significant improvement in NAV both on an absolute and per share basis (published in every corporate presentation since early 2021) since royalty-only strategy effort began under new management team High grading assets with mineral acquisition program, despite divesting of non-operated working interest, has grown PV10 value and increased NAV per share since change in strategy Below reserve value independently verified by DeGolyer & MacNaughton (2021) and Cawley, Gillespie and Associates, Inc (2022-2024) Total 2P Reserve Value @ PV-10 ($ millions) NAV per Share Net of Debt Next Twelve-Month NYMEX strip for oil and natural gas as of date reserves analysis was compiled (1) Probable locations are currently being developed and converted to Producing (PDP) at an annual rate of approximately 300 gross wells per year (see slide 13, 14 and 15)   (1)

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NAV Per Share Net of Debt SEC Pricing1 Strip Pricing2 $80/$5.00 Flat Pricing3 $248 $297 $436 1 3P Reserves per CGA Year End 2023 report proforma acquisitions, divestitures, and activity as of 9/30/2024 at 9/30/2024 SEC price deck of $77.21 per bbl of oil, $21.97 per bbl of NGL, $2.13 per mcf of gas (proved volume weighted average price)  2 3P Reserves per CGA Year End 2023 report proforma acquisitions, divestitures, and activity as of 9/30/2024 at 10/14/2024 STRIP price of WTI/HH 2024: $73.54/$2.71, 2025: $71.23/$3.16, 2026: $68.86/$3.56, 2027: $67.55/$3.61, 2028: $66.78/$3.56, 2029: $66.24/$3.49, 2030: $65.80/$3.42, 2031: $65.44/$3.28, 2032: $65.36/$3.14, 2033: $65.25/$3.06, 2034: $65.16/$3.07, 2035: $65.14/$3.03, 2036+: $65.14/$3.05. 3 3P Reserves per CGA Year End 2023 report proforma acquisitions, divestitures, and activity as of 9/30/2024 flat price deck of $80.00 WTI /$5.00 HH. 4 Technical PUDs, reviewed and approved by Cawley, Gillespie and Associates, Inc., share all technical merits of PUDs but development timing is uncertain, therefore Technical PUDs are not included in PHX’s SEC Proved Reserve Report. However, PHX Technical PUDs  may be PUDs in their respective operator’s reserve report. 5 Scheduled out approximately 10 years for PROB and 15 years for POSS. 6 Un-risked PV-10 less net debt of $25.1 MM as of 9/30/2024 divided by total shares outstanding as of 9/30/2024 Reserve Category PV-10 Value ($mm) SEC1 Strip2 $80 / $5.003 PDP $78.0 $98.3 $151.0 Wells in Progress $10.9 $13.8 $19.8 Permits $2.4 $3.8 $5.7 Total Proved Reserves $91.3 $115.8 $176.6 Technical PUDs4 $47.3 $60.7 $87.5 Adjusted Proved Reserves $138.6 $176.6 $264.1 PROB5 $84.6 $95.8 $136.5 POSS5 $25.2 $25.1 $35.8 Total 3P Reserves $248.4 $297.4 $436.4 NAV per Share Net of Debt Proved PV-10 Per Share6 $1.77 $2.42 $4.04 Adjusted Proved PV-10 Per Share6 $3.03 $4.04 $6.37 2P PV-10 Per Share6 $5.29 $6.59 $10.02 3P PV-10 Per Share6 $5.96 $7.26 $10.97

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Royalty Cash Flow Driving Shareholder Value Royalty Production and Realized Natural Gas Price Adjusted EBITDA1 Discretionary Cash Flow Margin2 Return on Capital Employed3 $ in millions Source: Company filings ; All quarters are in Calendar Year 1 Calculated as net income excluding non-cash gain/loss on derivatives, income tax expense, interest expense, DD&A, non-cash impairments, non-cash G&A, gain(losses) on asset sales and cash receipts from/payments on off-market derivatives; See Non-GAAP reconciliation in Appendix 2 Calculated as Adjusted EBITDA minus interest expense divided by total oil and gas sales 3 See Non-GAAP reconciliation in Appendix

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Stable Balance Sheet & Ample Liquidity Net Debt 1 Percentage Drawn on Credit Facility Advance Rate Debt / Adjusted EBITDA2 (TTM) Liquidity3 $ in millions $ in millions Source: Company filings ; All quarters are in Calendar Year 1 Total debt less cash 2 Total Debt / Adjusted EBITDA;  See Non-GAAP reconciliation in Appendix 3 Calculated as working capital (current assets less current liabilities excluding current derivatives) plus availability on the borrowing base; See Non-GAAP reconciliation in Appendix

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PHX Operational Outlook 1 See Non-GAAP reconciliation in Appendix Cal. Year 2022 Actual Cal. 2023 YTD Actual Sept. 30, 2024 YTD Actual  Cal. Year 2024 Outlook Mineral & Royalty Production (Mmcfe) 6,613 8,123 6,664 8,700 – 9,100 Working Interest Production (Mmcfe) 3,084 1,256 799 1,000 – 1,200 Total Production (Mmcfe) 9,697 9,379 7,463 9,700 – 10,300 Percentage Natural Gas 78% 80% 81% 79% - 82% Transportation, Gathering & Marketing (per mcfe) $0.63 $0.39 $0.47 $0.40 - $0.50 Production Tax (as % of pre-hedge sales) 4.50% 5.20% 5.70% 5.25% - 6.25% LOE Expenses (on an absolute basis in 000’s) $3,807 $1,599 $921 $1,100 - $1,300 Cash G&A(1) (on an absolute basis in 000’s) $9,900 $9,500 $6,854 $9,500 - $9,900  Calendar 2024 production derived from wells already on production and wells currently being drilled/completed by operators Total corporate volumes forecasted to increase for the first time since 2020 after completing our transition away from non-op working interest

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PHX Financial Outlook Note: 1 Assumes no additional sales of working interest wellbores 2 Calculated as EBITDA less interest and cash portion of income tax PHX’s growth strategy has the potential to significantly increase its operating cash flow to over $40 million annually by Fiscal Year 2026; representing a 100% increase from the current run rate Key Assumptions Between 250 / 300 gross  (1.1 / 1.3 net) wells converted to PDP annually in 2024 – 2026 PHX has an 8-year inventory of drilling locations Does not assume additional acquisitions Cash flow used to paydown debt; fully paid down in less than 18 months NYMEX Natural Gas ($/mcf) WTI ($/bbl)

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Royalty Reserve Growth Sustainable royalty reserve and production growth through conversion of existing mineral location inventory Royalty Reserves Royalty Production MMCFE CAGR: ~36% MMCFE CAGR: ~28% 1 At mid-point of production outlook (see page 10)  

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Yearly Conversions To Producing Wells Strong drilling activity on our mineral assets provides sustainable annual royalty production growth Gross Conversions Net Conversions 1 As of 9/30/2024 1 1

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Quarterly Near-Term Drilling Inventory Continuous conversion of undrilled location inventory will drive future royalty volume growth Gross Inventory Net Inventory

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Royalty Interest Inventory by Basin  Sub-region  Gross PDP Wells1  Net PDP Wells1,3  Undeveloped Locations1 Sub-region PDP Wells Average NRI1 Gross Wells In Progress2 Net Wells in Progress3 Gross Permits Net Permits3 Gross Technical PUDs4 Net Technical PUDs3,4,5 Gross PROB Net PROB3,5 Gross POSS Net POSS3,5 SCOOP 1,208 4.780 84 .351 43 .093 227 0.925 716 2.099 335 1.221 Haynesville 690 3.910 69 .240 32 .100 313 1.029 237 0.678 4 0.003 STACK 410 1.751 13 0.021 4 0.008 71 0.391 170 1.039 58 0.573 Bakken 634 1.860 4 0.001 3 0.003 65 0.233 132 0.826 9 0.146 Arkoma Stack 505 4.551 3 0.015 9 0.030 1 0.001 94 1.710 83 0.924 Fayetteville 1,068  6.420 0 0.000 0 0.000 0 0 0 0 0 0 Other 1,982 16.042 3 0.030 11 0.041 0 0 1 0.000 0 0 Total 6,497 39.314 176  0.658 102 0.275 677 2.579 1,349 6.353 489 2.867 Gross Undeveloped Locations 2,793 2,793 Note: 1 As of 9/30/2024 2 Wells in Progress includes wells currently being drilled and wells waiting on completion 3 Net interest on wells are internal estimates and subject to confirmation from operator 4 Technical PUDs, reviewed and approved by Cawley, Gillespie and Associates, Inc., share all technical merits of PUDs but development timing is uncertain. PHX Technical PUDs are most likely PUDs in their respective operator’s reserve report. 5 Technical PUDs, PROB, and POSS net wells assume 10,000 ft. laterals 2 Continuous conversion of undrilled location inventory will drive future royalty volume growth

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Analyst Coverage Firm Analyst Contact Johnson Rice Charles Meade cmeade@jrco.com Alliance Global Partners Jeff Grampp jgrampp@allianceg.com Northland Securities Donovan Schafer dschafer@northlandcapitalmarkets.com

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Appendix

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Company Leadership Management Team Title Years with Company Experience Chad Stephens President, CEO and Board Director 5 CEO for PHX since 2019 SVP –Corporate Development of Range Resources for 30 years until retiring in 2018 B.A. in Finance and Land Management from University of Texas Ralph D’Amico Executive Vice President, CFO 5 CFO for PHX since 2020 20 years of investment banking experience Bachelor’s in Finance from University of Maryland; MBA from George Washington University Chad True S.V.P. of Accounting 4 >16 years of accounting experience Audit and accounting positions with Grant Thornton LP, Tiptop Oil & Gas and Wexford Capital LP B.S. and Masters in Accounting from Oklahoma State University Danielle Mezo V.P. of Engineering 4 >15 years reservoir engineer experience Reservoir engineer, acquisitions, and corporate planning positions at SandRidge Energy B.S. in Petroleum Engineering from University of Oklahoma and licensed Professional Engineer Kenna Clapp V.P. of Land 4 >15 years of land experience Various land positions with Chesapeake Energy in Haynesville, Eagleford, Mid-Continent and Barnett shales B.S. in Accounting and Finance from Oklahoma State University; JD from Oklahoma City University Taylor McClain V.P. of Geology <1 >10 years of experience across multiple basins including Appalachia, Haynesville, Permian and Mid-Continent Various exploration and production Geologist positions with Range Resources, UBS and Redfield Energy B.S. in Geoscience from Pennsylvania State University and a Masters in Geology from West Virginia University Board of Directors Title Years with Company Experience Mark T. Behrman Chairman 7 CEO of LSB Industries, Inc. since 2018 Managing Director and Head of Investment Banking of the Industrial and Energy Practices of Sterne Agee from 2007 to 2014 MBA in Finance from Hofstra University and B.S. in Accounting, Minor in Finance from Binghamton University Glen A. Brown Director 3 SVP – Exploration for Continental Resources from 2015 through 2017 Exploration manager for EOG Resources Midcontinent from 1991 through 2003 Bachelor’s in Geology from State University of New York; Master’s in Geology from New Mexico State University in Las Cruces Lee M. Canaan Director 8 Founder and portfolio manager of Braeburn Capital Partners, LLC Board member for EQT Corporation and Aethon Energy, LLC Bachelor’s in Geological Sciences from USC, Master’s in Geophysics from UT-Austin, and MBA in Finance from Wharton Steven L. Packebush Director 2 Founder and partner in Elevar Partners, LLC President of Koch Ag & Energy Solutions upon his retirement in 2018 after 30 years with the company Bachelor’s in agricultural economics from Kansas State John H. Pinkerton Director 3 CEO of Range Resources Corporation from 1992 through 2012 Executive Chairman and Chairman of Board of Directors for Encino Energy from 2017 through 2022 B.A. in Business Administration from Texas Christian University; Master’s from the University of Texas at Arlington

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Scoop Haynesville Bakken Stack Arkoma Fayetteville Other Total Production Mix Net Production (MMcfe/d)1,3 4.43 12.97 1.08 2.86 1.08 0.90 2.53 25.85 Leased Net Royalty Acres1,2 9,604 8,623 4,026 6,691 9,839 8,394 41,460 88,637 Permits on File1 43 32 3 4 9 - 11 102 Rigs Running on PHX Acreage4 9 4 1 2 - - 2 18 Rigs Running Within 2.5 miles of  PHX Acreage4 12 20 13 12 - - 13 70 Key Operators 1 As of 9/30/2024 2 PHX average royalty rate of ~16%; PHX also owns 169,056 unleased net mineral acres 3 Includes both royalty and working interest production  4 Rig data from Enverus as of 9/30/2024 Portfolio Overview by Basin 29%

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TRINITY | BYRD 23-26-35 | 3 WELL AVG 1st Prod                3/2024                   PHX NRI 0.410% LL          10,450’    IP24hr  18.2 MMCFPD NRM PROP     4,200 #/FT IP30    12.5 MMCFPD CHESAPEAKE  |  ARK 9&16&21-15-16HC 001 1st Prod                1/2024                   PHX NRI 0.563% LL          12,500’    IP24hr  30.7 MMCFPD NRM PROP     3,900 #/FT IP30    25.9 MMCFPD Texas / Louisiana Haynesville Update Notable Well Results CHESAPEAKE | L 14-23-26-35 HC 001 1st Prod                3/2024                   PHX NRI 0.416% LL          10,450’    IP24hr  39.5 MMCFPD NRM PROP     4,200 #/FT IP30    32.2 MMCFPD AETHON  |  BURNS FOREST / MOJO MINERALS DSU | 5 WELL AVG 1st Prod                1/2024                   PHX NRI 4.667% LL          9,800’    IP24hr  21.8 MMCFPD NRM PROP     4,700 #/FT IP30    11.7 MMCFPD Source: Company info and Enverus 1 As of 9/30/2024 2 Wells in Progress includes wells currently being drilled and wells waiting on completion 3 Active natural gas and oil horizontal permits filed  4 Rig data from Enverus as of 9/30/2024 Operators are drilling 3-5 wells per unit, and a positive indication of near term volumes and cashflows Since 2019, core development areas have been extended as new completion designs have lowered breakevens Key Operators: Aethon, Trinity, Chesapeake, Silverhill, Blue Dome and Paloma PHX TX / LA AOI Haynesville Ownership1: 7,564 NRA (total PHX Haynesville ownership 8,623 NRA)  Gross Wells In Progress on PHX1,2: 54 (total PHX Haynesville gross active WIPs 69) Gross Active Permits on PHX1,3: 32 (total PHX Haynesville gross active permits 32) Total Active Rigs in TX / LA AOI4: 23 1 2 3 4 1 2 4 3

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AETHON |  ATTOYAC RIVER GAS UNIT | 4 WELL AVG 1st Prod                10/2023                   PHX NRI 0.286%5 LL          6,400’    IP24hr  21.1 MMCFPD NRM PROP     4,500 #/FT IP30    12.5 MMCFPD AETHON | ATTOYAC RIVER - SCOGGINS GAS UNIT | 3 WELL AVG 1st Prod                10/2023                   PHX NRI 0.184% LL          8,600’    IP24hr  22.8 MMCFPD NRM PROP     4,500 #/FT IP30    15.3 MMCFPD AETHON  | CLARK – ARMSTRONG UNIT | 5 WELL AVG 1st Prod                5/2024                   PHX NRI 0.138% LL          10,900’    IP24hr  16.8 MMCFPD NRM PROP     4,400 #/FT IP30    11.6 MMCFPD AETHON  |  SILVER HAMMER / PATZAKIS | 4 WELL AVG 1st Prod                6/2023                   PHX NRI 0.490% LL          8,200’    IP24hr  21.8 MMCFPD NRM PROP     4,800 #/FT IP30    15.6 MMCFPD South Texas Haynesville Update Notable Well Results Source: Company info and Enverus 1 As of 9/30/2024 2 Wells in Progress includes wells currently being drilled and wells waiting on completion 3 Active natural gas and oil horizontal permits filed  4 Rig data from Enverus as of 9/30/2024  5 NRIs are internal estimates and are subject to confirmation from operator Operators are drilling 3-5 wells per unit, and a positive indication of near term volumes and cashflows Since 2019, core development areas have been extended as new completion designs have lowered breakevens Key Operator is Aethon who has been the most active in the Shelby Trough PHX South Texas Haynesville Ownership1: 1,059 NRA (total PHX Haynesville ownership 8,623 NRA) Gross Wells In Progress on PHX1,2: 15 (total PHX Haynesville gross active WIPs 69) Gross Active Permits on PHX1,3: 0 (total PHX Haynesville gross active permits 32) Total Active Rigs in South Texas AOI4: 4 1 2 3 4 1 2 3 4

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Springboard III Update Highest resource in-place per DSU in the midcontinent, co-developing the Mississippian Sycamore & Woodford Shale Operators starting to infill existing DSUs; Early results suggest very little to no Parent-Child degradation PHX Springboard III Ownership1: 4,129 NRA Gross Wells In Progress on PHX1,2: 35 Gross Active Permits on PHX1,3: 3 Gross Active Rigs in Springboard III4: 5 Notable Well Results Source: Company info and Enverus 1 As of 9/30/2024 2 Wells in Progress includes wells currently being drilled and wells waiting on completion 3 Active natural gas and oil horizontal permits filed  4 Rig data from Enverus as of 9/30/2024  CONTINENTAL  |  COURBET 7-22-9XHW | WOODFORD 1st Prod      03/2023 PHX NRI                 0.363%        10,700’ IP30 2,340 BOEPD NRM PROP        2,500 #/FT % OIL    52% CONTINENTAL  |  SUNDANCE KID 3-23-26-35XHM |  SYCAMORE  1st Prod      03/2024 PHX NRI              0.473% LL 12,400’ IP30 2,150 BOEPD NRM PROP        2’500 #/FT % OIL 79% CONTINENTAL  |  COURBET 16-15-9XHM |  SYCAMORE 1st Prod                03/2023 PHX NRI                 0.771% LL 11,200’ IP30 3,230 BOEPD NRM PROP       2,500 #/FT % OIL 78% CONTINENTAL  |  HONDO 3-22-15XHM |  SYCAMORE   1st Prod       02/2024 PHX NRI                 2.584% LL      9,900’ IP30 3,400 BOEPD  NRM PROP 2,500 #/FT % OIL 87% 1 2 3 4 1 2 3 4

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STACK MERGE SCOOP MERAMEC OSAGE/SYCAMORE WOODFORD SHALE STACK | MERGE | SCOOP The SCOOP is the premier play in Oklahoma with the highest resource in-place and most horizontal objectives The transition between the SCOOP and STACK is the MERGE where the thickness prevents stacked development The primary target in the STACK is the Meramec All 3 regions are sourced by the Woodford and feature >1,350 btu gas and minimal produced water 1 PHX internally plans all undrilled inventory on a section-by-section basis, the above is a representation of the regional estimate of wells per section, however locally some areas will differ MERGE SCOOP STACK A A’ WOODFORD SHALE OSAGE MERAMEC WOODFORD SHALE SYCAMORE MERAMEC STACK MERGE SCOOP A A’ BOOKED LOCATION UNBOOKED LOCATION

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Robust Acquisition Process 24 PHX believes that being the aggregator of choice in our core areas is a key component of our strategy Royalties, just like any other hydrocarbon asset class, are naturally depleting assets and reinvestment is required to maintain and grow cash flows over time We target minerals in our core areas (SCOOP and Haynesville) with full analysis of geology and established type curves in order to minimize execution risk Typical profile of acquisitions includes an already producing component as well as royalties that are either in the process of being developed (WIPs) or will be developed over time (locations) by reputable and creditworthy operators to minimize timing risk Focused on active operators in order to minimize development timing risk Our acquisition program targets returns well in excess of our cost of capital (see ROCE) to drive increasing shareholder value IRR Payback MOIC Commodity Pricing Geology Type Curves Title Review Takeaway Capacity Basin Differentials Development Timing Inputs Requirements PHX’s A&D Methodology

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Acquisition Summary Acquisitions by Basin by Year (in thousands) Focused on highest quality rock in the SCOOP and Haynesville plays Targeting a mix of production, near term development opportunities via wells in progress and additional upside potential under high quality operators $35.6M in acquisitions in SCOOP and $91.6M in Haynesville since Q1 of 2020 Positioned For Growth Through Acquisitions Total domestic US mineral market estimated at ~$0.5 - 1 trillion(2) Highly fragmented Predominantly owned by private individuals PHX well positioned to be one of the premier consolidators in our core areas Focus on smaller deals increases opportunity set and potential returns Market Opportunity Midpoint (1) : 97% 1 As of 9/30/2024 2 Midpoint of market size estimate range. Based on production data from EIA and spot price as of 03/31/2021. Assumes 20% of royalties are on Federal lands and there is an average royalty burden of 18.75%. Assumes a 10x multiple on cash flows to derive total market size. Excludes NGL value and overriding royalty interests 3 Enterprise values of PHX, DMCP, KRP, BSM, STR and VNOM as of 03/31/2023

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Acquisition History All acreage currently owned in the Haynesville and predominately all acreage currently owned in Springboard III area of interest was acquired under current management team’s guidance Source: Company information and Enverus; Map of active rigs as of 9/30/2024 1 As of 9/30/2024 1 1

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Natural Gas – Continued Demand Growth Natural Gas Electrical Generation1 Monthly Electrical Generation by Fuel Type1 Natural Gas Consumption1 1 Source: EIA Natural gas demand from power generation continues to increase and dominate the power stack; increase in solar and wind are coming at the expense of coal 20 additional gas fired power plants with total capacity of 7.7 GW expected to come online in 2024 – 2025 LNG export capacity expected to increase as projects under construction come online in second half of 2024 and in 2025

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Natural Gas – Surging LNG Demand Forecasted U.S. Export Annual Volume Growth1 Large Scale Approved Liquefaction Facilities 1 Current LNG export capacity is fully committed North America liquefied natural gas capacity is on track to more than double between 2024 and 2028 (US 9.7 Bcf/d, Canada 2.5 Bcf/d and Mexico 0.8 Bcf/d) US exported more LNG in 2023 than any other country; increasing exports 12% compared to 2022 Source: EIA. 1 Capacity based on baseload nameplate capacity 2 Expected online in 2H 2025 – 1H 2026 3 Expected online by end of 2024 4 Expected online in 2026 5 Expected online 2027 6 Expected online 2027 / 2028

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Current Hedge Position Mix of collars and swaps designed to provide upside exposure while protecting downside risk Note: Volumes hedged through 10/26/2024 Gas hedge prices are in $/Mcf and Oil hedge prices are in $/bbl

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Reconciliation of Non-GAAP Financial Measures Source: Company Filings

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Reconciliation of Non-GAAP Financial Measures

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Reconciliation of Non-GAAP Financial Measures Source: Company Filings

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Reconciliation of Non-GAAP Financial Measures

v3.24.3

Document And Entity Information	Nov. 06, 2024
Cover [Abstract]
Document Type	8-K
Amendment Flag	false
Document Period End Date	Nov. 06, 2024
Entity Registrant Name	PHX MINERALS INC.
Entity Central Index Key	0000315131
Entity Emerging Growth Company	false
Entity File Number	001-31759
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	73-1055775
Entity Address, Address Line One	1320 South University Drive
Entity Address, Address Line Two	Suite 720
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76107
City Area Code	(405)
Local Phone Number	948-1560
Written Communications	false
Soliciting Material	false
Pre-commencement Tender Offer	false
Pre-commencement Issuer Tender Offer	false
Title of 12(b) Security	Common Stock, $0.01666 par value
Trading Symbol	PHX
Security Exchange Name	NYSE

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