UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

~~For~~for the fiscal year ended DECEMBER 31, ~~2023~~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, TX	76107
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (405) 948-1560

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or Section 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.

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the ~~Exchange~~ Act). yes ☐ no ☒

The aggregate market value of the voting stock held by non-affiliates of the registrant, computed by using the $3.1226 per share closing price of registrant's Common Stock, as reported by the New York Stock Exchange at June 30, ~~2023~~2024, the last day of the Registrant’s most recently completed second fiscal quarter, was $92113,~~484~~897,~~438~~450.

The number of shares of Registrant’s Common Stock outstanding as of March 5, ~~2024~~2025, was 37,~~438~~922,~~237~~368.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of PHX Minerals Inc. (to be filed no later than 120 days after December 31, 2023) relating to the Annual Meeting of Stockholders, to be held on May 16, 2024, are incorporated into Part III of this Form 10-K.

T A B L E O F C O N T E N T S

		Page
	Special Note Regarding Forward-Looking Statements
	Glossary of Certain Terms
PART I
Item 1	Business	1
Item 1A	Risk Factors	7
Item 1B	Staff Comments	1920
Item 1C	Cybersecurity	1920
Item 2	Properties	2021
Item 3	Legal Proceedings	28
Item 4	Mine Safety Disclosures	28
PART II
Item 5	Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6	Reserved	31
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	4442
Item 8	Financial Statements and Supplementary Data	4543
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	7673
Item 9A	Controls and Procedures	7673
Item 9B	Other Information	7673
Item 9C	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	7673
PART III
Item 10-14	Incorporated by Reference to Proxy Statement	77
Item 10	Directors, Executive Officers and Corporate Governance	74
Item 11	Executive Compensation	80
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	93
Item 13	Certain Relationships and Related Transactions, and Director Independence	95
Item 14	Principal Accountant Fees and Services	96
PART IV
Item 15	Exhibits and Financial Statement Schedules	7898
Item 16	Form 10-K Summary	80100

Special Note Regarding Forward Looking Statements

This Annual Report on Form 10-K for the fiscal year ended December 31, ~~2023~~2024 (this “Annual Report on Form 10-K”, this “Annual Report” or this “Form 10-K”) 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-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target,” “would,” “could,” “might,” or similar expressions.

All statements, other than statements of historical facts, included in this Annual Report on Form 10-K 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; 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-K 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 and oil. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K~~, and all quarterly reports on Form 10-Q filed subsequently thereto~~.

Should one or more of the risks or uncertainties described above or elsewhere in this Annual Report on Form 10-K 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 also 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, natural gas and oil industry and other defined terms used in this Annual Report:

ASC	Accounting Standards Codification.
ASU	Accounting Standards Update.
At-The-Market Offering	Our Common Stock offering arrangement by which we may offer and sell, from time to time through or to Stifel, up to 3,000,000 shares of our Common Stock pursuant to an At-The-Market Equity Offering Sales Agreement, as amended, with Stifel as sales agent and/or principal. The At-The-Market Offering was terminated in December 2022.
Bcf	Billion cubic feet.
Bcfe	Natural gas stated on a Bcf basis and crude oil and natural gas liquids converted to a billion cubic feet of natural gas equivalent by using the ratio of one million Bbl of crude oil or natural gas liquids to six Bcf of natural gas.
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 natural gas and/or crude oil.
conventional	An area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.
DD&A	Depreciation, depletion and amortization.
developed acreage	The number of acres allocated or assignable to productive wells or wells capable of production.
development well	A well drilled within the proved area of a natural gas or crude oil reservoir to the depth of a stratigraphic horizon known to be productive.
dry hole	Exploratory or development well that does not produce natural gas and/or crude oil in economically producible quantities.
EBITDA	Earnings before interest, taxes, depreciation and amortization (including impairment). EBITDA is a Non-GAAP measure.
exploratory well	A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or crude oil in another reservoir.
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.
formation	A layer of rock, which has distinct characteristics that differ from nearby rock.
G&A	General and administrative costs.
GAAP	United States generally accepted accounting principles.
gross acres or gross wells	The total acres or wells in which an interest is owned.
held by production or HBP	An oil and gas lease continued into effect into its secondary term for so long as a producing gas and/or oil well is located on any portion of the leased premises or lands pooled therewith.
horizontal drilling	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.
hydraulic fracturing	A process involving the high-pressure injection of water, sand and additives into rock formations to stimulate natural gas and crude oil production.
Independent Consulting Petroleum Engineer(s)	Cawley, Gillespie & Associates
LOE	Lease operating expense.
MCF	Thousand cubic feet.
MCFD	Thousand cubic feet per day.
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.
MCFED	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 per day.
Mmbtu	Million BTU.
MMCF	Million cubic feet.
MMCFE	Natural gas stated on an Mmcf basis and crude oil and natural gas liquids converted to a million cubic feet of natural gas equivalent by using the ratio of one thousand Bbl of crude oil or natural gas liquids to six Mmcf of natural gas.
minerals, mineral acres or mineral interests	Fee mineral acreage owned in perpetuity by the Company.
net acres or net wells	The sum of the fractional interests owned in gross acres or gross wells.
NGL	Natural gas liquids.

minerals, mineral acres or mineral interests	Fee mineral acreage owned in perpetuity by the Company.
net acres or net wells	The sum of the fractional interests owned in gross acres or gross wells.
NGL	Natural gas liquids.
NRI	Net revenue interest.
NYMEX	New York Mercantile Exchange.
OPEC	Organization of Petroleum Exporting Countries.
overriding royalty interest	An interest in the natural gas and oil produced under a lease, or the proceeds from the sale thereof, apportioned out of the working interest, to be received free and clear of all costs of development, operation or maintenance.
PDP	Proved developed producing.
play	Term applied to identified areas with potential natural gas and/or oil reserves.
production or produced	Volumes of natural gas, oil and NGL that have been both produced and sold.
proved reserves	The quantities of natural gas and crude oil, 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.
proved developed reserves	Reserves expected to be recovered through existing wells with existing equipment and operating methods.
proved undeveloped reserves or PUD	Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
PV-10	Estimated pre-tax present value of future net revenues discounted at 10% using SEC rules.
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.
Stifel	Stifel, Nicolaus & Company, Incorporated
unconventional	An area believed to be capable of producing natural gas and crude oil occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with gas and oil shale, tight oil and gas sands, and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.
undeveloped acreage	Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and/or crude oil.
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.

As used herein, the “Company,” “PHX,” “we,” “us” and “our” refer to PHX Minerals Inc., formerly known as Panhandle Oil and Gas Inc., and its predecessors ~~and subsidiaries~~ unless the context requires otherwise.

Fiscal year references

In December 2022, the Company changed its fiscal year end from September 30 to December 31. Accordingly, the Company reported a transition period that ran from October 1, 2022 through December 31, 2022, which we refer to as the “Transition Period”. All references to years or fiscal years in this Annual Report, unless otherwise noted, refer to the Company’s fiscal year ended December 31 with respect to 2023 and September 30 with respect to prior years. For example, references to 2023 mean the fiscal year ended December 31, 2023 and references to 2022 mean the fiscal year ended September 30, 2022.

References to natural gas and oil properties

References to natural gas and oil properties inherently include NGL associated with such properties.

PART I

ITEM 1. Business

Overview

PHX Minerals Inc., a Delaware corporation, is a Fort Worth-based company focused on perpetual natural gas and oil mineral ownership in resource plays in the United States. Prior to a strategy change in 2019, the Company participated with a working interest on some of its mineral and leasehold acreage and as a result still holds legacy interests in leasehold acreage and non-operated working interests in natural gas and oil properties. In this Annual Report, we generally refer to such working interests and the related wells as “legacy” interests and wells.

The Company was originally founded as a cooperative in 1926, and its shares became publicly traded in 1979. Effective April 1, 2022, the Company changed its state of incorporation from Oklahoma to Delaware through a merger with a wholly owned subsidiary, which was conducted for such purpose (the “Reincorporation”). Other than the change in the state of incorporation, the Reincorporation did not result in any change in the business, physical location, management, assets, liabilities or net worth of the Company, nor did it result in any change in location of the Company’s employees, including the Company’s management.

Strategic Focus on Mineral Ownership

During fiscal year 2019, we made the strategic decision to focus on perpetual natural gas and oil mineral ownership and growth by acquiring minerals in our core focus areas and by developing our significant mineral acreage inventory. In accordance with this strategy, we have ceased taking any working interest positions on our mineral and leasehold acreage. The legacy non-operated working interests require us to contribute our proportionate share of the costs incurred by the operator in the development of such minerals. During the two fiscal years ended December 31, ~~2023~~2024 and ~~September 30, 2022 and the Transition Period ended~~ December 31, ~~2022~~2023, we did not participate with a working interest in the drilling of any new wells. We believe that our strategy to focus on mineral ownership isprovides ~~the best path forward to provide~~ our stockholders the greatest risk-weighted returns on their investments. Our producing mineral and leasehold properties are located primarily in Oklahoma, Texas, Louisiana, North Dakota and Arkansas.

A “mineral fee” is an interest in real property in which the owner owns all of the rights to the minerals under the surface in perpetuity, as compared to a mineral lease in which the lessee’s rights end at the expiration of the lease term or after production in paying quantities ceases with respect to the lease or the lease otherwise terminates in accordance with its terms. Generally, the mineral interest owner of a mineral fee interest reserves a non-cost bearing royalty interest upon the lease of such gas, oil, and other minerals to a gas and oil exploration and development company. Such companies lease such mineral interests from the fee mineral owner for a term with the expectation of producing natural gas and oil, thereby generating free cash flow from bonuses and royalties to the mineral interest owner. The majority of our revenues is derived from royalties generated from the production and sale of natural gas, oil and NGL on our minerals and these royalties are tied to our perpetual ownership of mineral acreage. Royalties are due and payable whenever the operator of such interest produces and sells natural gas, oil or NGL from wells located on our mineral acreage.

As of December 31, ~~2023~~2024, we owned approximately ~~240~~239,~~651~~909 perpetual mineral acres, as detailed in the table below:

Play	Net Acres		% Producing	% Leased But Not Producing	% Unleased
SCOOP		8,~~307~~475	7071%	87%	22%
STACK		5,~~810~~828	9091%	40%	69%
Arkoma Stack		9,794	7576%	10%	24%
Haynesville		45,~~913~~238	100%	0%	0%
Bakken /Three Forks		3,~~123~~120	89%	0%	11%
Fayetteville		9,867	73%	0%	27%
Other		~~198~~197,~~837~~587	18%	20%	8082%
Total:		~~240~~239,~~651~~909	29%	21%	6970%

Approximately 3130% of our net minerals are currently under lease with an operator of which 29% have a producing well. Additionally, approximately 6970% of our net mineral position is currently unleased, providing the opportunity to generate additional cash flow from bonus payments and royalties without spending additional capital. We may also generate additional cash flows through opportunistically divesting unleased minerals. We ~~also~~ own working interests, royalty interests or both in 6,~~773~~958 producing natural gas and oil wells and ~~168~~150 wells in the process of being drilled or completed.

Exploration and development of our natural gas and oil properties are conducted by natural gas and oil exploration and production companies, which typically are larger, independent oil and gas operating companies. We do not operate any natural gas and oil properties. While we previously were an active working interest participant in wells drilled on our mineral and leasehold acreage, we now focus on growth through mineral acquisitions and through development of our significant mineral acreage inventory.

We intend to maximize stockholder value through the acquisition of mineral acreage in the core areas of resource plays with substantial undeveloped opportunities, proactive leasing of our mineral holdings, and divestiture of non-core minerals with limited optionality when the amount negotiated exceeds our projected total value.

Our Business Strategy

Our principal business objective is to maximize stockholder value. At the end of 2019, we made the strategic decision to cease taking working interest positions on our mineral and leasehold acreage. Our focus since then has been on growth through mineral acquisitions and by developing our significant mineral acreage inventory in our core focus areas under high quality operators. We believe this is the best path to provide our stockholders the greatest risk-weighted returns on their investment. We intend to accomplish this objective by executing the following corporate strategies:

•

Actively Manage Mineral and Leasehold Assets as a Portfolio to Maximize Value. We plan to manage our mineral and leasehold assets through the following:

Increasing our mineral fee holdings by acquiring mineral acreage in our core focus areas of natural gas and oil resource plays with substantial undeveloped opportunities that meet or exceed our minimum return threshold;

Utilizing in-house geology and engineering expertise as a competitive advantage;

Proactively leasing or monetizing our unleased mineral holdings; and

High-grading our asset base by: (a) selectively divesting non-core minerals when the anticipated sales price exceeds our projected total value, (b) optimizing our leasehold and working interest positions through strategic sales and farmouts of such assets, and (c) redeploying proceeds from sales into our core focus areas.

•

Maintain a Stable and Well Capitalized Balance Sheet. We plan to maintain a strong financial position through the following:

Maintaining a conservative amount of debt outstanding with ample liquidity to ensure our ability to successfully operate in all business and commodity environments; and

Hedging a portion of our future natural gas and oil prices to manage commodity price risk and protect our cash flow.

Our Business Strengths

We believe the following attributes position us to achieve our objectives:

•

Focusing on Perpetual Mineral Fee Ownership. Our strategic decision to focus on mineral ownership provides us with the perpetual option to benefit from future development and technology. We are focused on generating meaningful revenues through lease bonuses and royalty interests, and our royalty revenue as a percentage of total revenue continues to increase. As of December 31, ~~2023~~2024, we owned approximately ~~240~~239,~~651~~909 net mineral acres located primarily in Oklahoma, Texas, North Dakota, Louisiana and Arkansas. Subsequent to December 31, 2024, we sold 165,326 non-producing net mineral acres. We also own working interests, royalty interests or both in 6,~~773~~958 producing natural gas and oil wells and ~~168~~150 wells in the process of being drilled or completed.

•

Mineral and Leasehold Ownership in Multiple Top-Tier Resource Plays. We own mineral and leasehold interests in multiple top-tier resource plays in the United States, including positions in the Haynesville, SCOOP, STACK, Bakken/Three Forks, Arkoma Woodford, ~~Permian Basin~~ and Fayetteville plays. A significant portion of our revenues is derived from the production and sale of natural gas, oil and NGL from these positions. During fiscal year ~~2023~~2024, production on our acreage averaged 2526,~~697~~890 Mcfed with approximately 8081%, 1211% and 8% of such volumes derived from the production of natural gas, oil and NGL, respectively.

•

Material Undeveloped Mineral Position in Gas and Oil Producing Basins. Over 70% of our mineral fee position is currently unleased or not currently producing, providing us with the opportunity to generate additional cash flows from bonus payments and royalties without deploying additional capital. We may also generate additional cash flows through opportunistically divesting these unleased minerals.

•

Stable and Flexible Financial Position. We maintain a stable and flexible financial position by actively managing our debt, cash and working capital. We hedge a portion of our production to manage commodity price risk and to protect our balance sheet and cash flow.

•

Experienced Management and Technical Team. We have a management and technical team with extensive experience in the oil and gas industry. Our management and technical team members average over 20 years of industry experience in each applicable area of the Company, including accounting, land, geology, engineering and mergers and acquisitions.

Principal Products and Markets

We derive our revenue through bonus and royalty payments and from legacy working interests on our mineral and leasehold acreage. Our principal products from the production associated with our royalty and non-operated interests, in order of revenue generated, are natural gas, crude oil and NGL. These products are generally sold by well operators to various purchasers, including pipeline and marketing companies, which service the areas where the producing wells are located. Since we do not operate any of the wells in which we own an interest, we must rely on the operating expertise of numerous companies that operate the wells in which we own interests, including expertise in the drilling and completion of new wells, producing well operations and, in most cases, the marketing or purchasing of production from the wells. We receive payments from natural gas, oil and NGL sales from the well operator or the contracted purchaser.

Prices of natural gas, oil and NGL are dependent on numerous factors beyond our control, including supply and demand, competition, weather, international events and geopolitical circumstances, actions taken by OPEC and economic, political and regulatory developments. Since demand for natural gas is subject to weather conditions, prices received for our natural gas production may be subject to seasonal variations.

We enter into price risk management financial instruments (derivatives) to reduce our exposure to fluctuations in the price of natural gas and oil and to protect our return on investments. The derivative contracts apply only to a portion of our natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in natural gas and oil prices. Please see Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 12 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding the derivative contracts we enter into.

Competitive Business Conditions

The oil and natural gas industry is highly competitive, particularly with respect to attempting to acquire additional fee mineral interests and natural gas, oil and NGL reserves. Many factors beyond our control affect our competitive position. Some of these factors include: the quantity and price of foreign oil imports; domestic supply and deliverability of natural gas, oil and NGL; changes in prices received for natural gas, oil and NGL production; business and consumer demand for refined natural gas, oil products and NGL; and the effects of federal, state and local regulation of the exploration for, production of and sales of natural gas, oil and NGL (see Item 1A – “Risk Factors”). Many companies have substantially greater resources than we have, and such companies may have more resources to evaluate, bid for and purchase more mineral fee, royalty and similar interests than our financial or human resources permit.

We do not operate any of the wells in which we have an interest; rather, we rely on operating companies with greater resources, staff, equipment, research and experience for both drilling and production of gas and oil wells. Our business strategy is to use our stable and flexible financial position, coupled with our own geologic and economic evaluations, to acquire new mineral acreage and to lease or farmout our mineral and leasehold acreage interests. We believe this strategy allows us to compete effectively in a competitive mineral market; however, our ability to acquire additional mineral fee, royalty and similar interests in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Major Customers

Our natural gas, oil and NGL production is sold, in most cases, through our lessees or well operators to numerous different purchasers. The loss of certain major purchasers of natural gas, oil and NGL production could have a material adverse effect on our ability to produce and sell, through our lessees or well operators, natural gas, oil and NGL production. The following table shows sales to major purchasers, by percentage, through various operators/purchasers during the ~~year~~years ended December 31, ~~2023,~~2024 ~~the~~and ~~Transition Period consisting of the three months ended~~ December 31, ~~2022, and the year ended September 30, 2022~~2023.

	Year Ended			Three Months Ended			Year Ended
	Year Ended December 31,
	December 31, 2023			December 31, 2022			September 30, 2022
	2024			2023
Company A		1417	%		914	%		9	%
Company B		139	%		413	%		2	%
Company C		38	%		73	%		10	%

Regulation of the Natural Gas and Oil Industry

General

As the owner of mineral fee interests and non-operating working interests, we do not have any employees or contractors operating in the field, and we are not directly subject to many of the regulations of the oil and gas industry. The following disclosure describes regulations and environmental matters more directly associated with operators of natural gas and oil properties, including our current operators. Since we do not operate any wells in which we have interests, actual compliance with many laws and regulations is controlled by the well operators, and we are responsible only for our proportionate share of the costs, if any, involved on wells in which we own a working interest.

Natural gas and oil operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision. Some of these requirements carry substantial penalties for failure to comply.

Although we are generally not directly subject to many of the rules, regulations and limitations impacting the natural gas and oil exploration and production industry as a whole, companies that operate our interests may be impacted by such rules and regulations and we may be responsible for our proportionate share of costs for wells on which we own a working interest. While we may be partially insulated from compliance costs applicable to our operator-lessees, we may still be indirectly impacted by operator regulations because our revenue stream depends on operators complying with applicable laws and regulations that govern the production of natural gas, oil and NGL.

Regulation of Drilling and Production

The production of natural gas and oil is subject to regulation under federal, state and local statutes, rules, orders and regulations. These statutes and regulations require that operators obtain permits for drilling operations and drilling bonds, as well as provide for reporting requirements concerning operations. Additionally, the state regulatory agencies where we own mineral and leasehold interests have enacted regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, the regulation of well spacing and plugging and abandonment of wells. The effect of these regulations is to limit the amount of natural gas and oil that can be produced from wells and to limit the number of wells or the locations which can be drilled. Additionally, some states where we hold mineral or leasehold interests may impose a production or severance tax with respect to the production and sale of natural gas, oil and NGL within the applicable jurisdictions.

Regulation of Transportation of Oil

The sale and transportation of our crude oil is generally undertaken by the operators (or by third parties at the direction of the operators) of our properties. Sales of crude oil, condensate and NGL are not currently regulated and are made at negotiated prices; however, Congress has enacted price controls in the past and could reenact price controls in the future.

Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (the “FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given

~~pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject~~ to ~~regulation by state regulatory commissions. The basis for~~ intrastate oil pipeline ~~regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline~~ rates, varies from state to state. Interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs.

Regulation of Transportation and Sale of Natural Gas

The sale and transportation of our natural gas is generally undertaken by the operators (or by third parties at the direction of the operators) of our properties. Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

The FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state.

Environmental Compliance and Risks

Our operators and properties are impacted by extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment and relating to safety and health.

Natural gas and oil exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Historically, most of the environmental regulation of gas and oil production has been left to state regulatory boards or agencies in those jurisdictions where there is significant natural gas and oil production, with limited direct regulation by such federal agencies as the Environmental Protection Agency (the “EPA”). However, there are various regulations issued by the EPA and other governmental agencies that would govern significant spills, blow-outs or uncontrolled emissions.

Many states, including states where we own properties, have enacted natural gas and oil regulations that apply to the drilling, completion and operations of wells and the disposal of waste oil and salt water. The operators of our properties are subject to such regulations. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

At the federal level, among the more significant laws and regulations that may affect our business and the oil and natural gas industry are: The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund”; the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act, also known as “RCRA”; the Clean Air Act; Federal Water Pollution Control Act of 1972, or the Clean Water Act; and the Safe Drinking Water Act of 1974.

Since we do not operate any wells in which we own an interest, actual compliance with environmental laws is controlled by the well operators, and we are only responsible for our proportionate share of the costs for wells in which we own a working interest. As such, we have no knowledge of any instances of non-compliance with existing laws and regulations. We maintain insurance coverage at levels customary in the industry, but we are not fully insured against all environmental risks.

Taxes

Our natural gas and oil properties are subject to various taxes, such as gross production taxes and, in some cases, ad valorem taxes, which we pay on minerals we own.

Employees

At December 31, ~~2023~~2024, we had 2018 full-time employees, including our executive officers, and did not have any part-time employees.

Executive Officers and Key Management

Chad L. Stephens, age 6869, has served as our President and Chief Executive Officer since January 2020. Mr. Stephens served as Interim CEO from October 2019 to December 2019, and he has served as a Director of the Company since September 2017. Prior to joining the Company, Mr. Stephens held several positions at Range Resources Corporation from 1990 through his retirement in 2018, where he served as Senior Vice President – Corporate Development.

Ralph D’Amico, age 4849, has served as our Chief Financial Officer and ~~Senior~~Executive Vice President since March 2020 and served as Vice President – Business Development from January 2019 through February 2020. Prior to joining the Company, Mr. D’Amico served as a Managing Director focused on energy at Stifel Nicolaus & Company, Incorporated and Seaport Global Securities and held various other energy investment banking positions at Jefferies, Friedman Billings Ramsey and Salomon Smith Barney prior to then.

Chad D. True, age 3839, has served as our Senior Vice President of Accounting and Corporate Secretary since January 2024, Vice President of Accounting and Assistant Corporate Secretary from January 2022 through December 2023, and as Director of Accounting and Assistant Corporate Secretary from May 2020 through December 2021. Prior to joining the Company, he held various audit and accounting positions at Grant Thornton LLP and Wexford Capital LP and has more than 1617 years of accounting experience.

Danielle D. Mezo, age 3637, has served as our Vice President of Engineering since January 2022 and as Director of Engineering from November 2020 through December 2021. Prior to joining the Company, she held various reservoir engineering, reserves, acquisitions, corporate planning, and management positions at SandRidge Energy and has 1415 years of experience in the oil and gas industry.

Kenna D. Clapp, age 3738, has served as our Vice President of Land since January 2023 and as Director of Land from November 2020 through December 2022. Prior to joining the Company, she held various land positions at Chesapeake Energy and has more than 1415 years of land experience across multiple basins including Haynesville, Eagleford, Mid-Continent and Barnett.

Taylor G. McClain, age 3536, joined the Company as Vice President of Geology in February 2024. Prior to joining the Company, Mr. McClain served as as Managing Director of Geology at Redfield Energy Partners and Director of Geology at UBS Investment Bank. Prior to that, Mr. McClain held roles as an exploration and production Geologist with Range Resources, and has over 1011 years of experience across multiple basins including Appalachia, Haynesville, Permian and Mid-Continent.

Corporate Office

Our corporate headquarters are located at 1320 South University Drive, Suite 720, Fort Worth, TX 76107. All geology, engineering and accounting employees are located at 1601 NW Expressway, Suite 1100, Oklahoma City, OK 73118. Our telephone number is (405) 948-1560 and our website is www.phxmin.com.

Available Information

We make available free of charge on our website (www.phxmin.com) our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other filings pursuant to Section 13(a) or 15(d) of the Exchange Act, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC.

We also make available within the “Governance Library” section under the “Corporate Governance” section of our website our Code of Ethics & Business Practices, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines, and Audit Committee, Governance and Sustainability Committee and Compensation Committee Charters, each of which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Ethics & ~~Business Practices and Code of Ethics for Senior Financial Officers for our principal executive and senior financial officers. Copies of~~

Business Practices and Code of Ethics for Senior Financial Officers for our principal executive and senior financial officers. Copies of our Code of Ethics & Business Practices and Code of Ethics for Senior Financial Officers are available free of charge by writing us at: PHX Minerals Inc., Attn: Chad True, 1601 NW Expressway, Suite 1100, Oklahoma City, OK 73118.

ITEM 1A. Risk Factors

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. If any of the following risk factors should occur, our financial condition could be materially impacted, and the holders of our securities could lose part or all of their investment in the Company. As the owner of mineral fee interests and non-operating working interests, we do not operate any natural gas and oil properties, and we do not have any employees or contractors in the field. As such, the risks associated with natural gas and oil operations affect us indirectly and typically through our non-operating working interests as we proportionately share in the costs of operating such wells. The risk factors described below are not exhaustive, and investors are encouraged to perform their own investigation with respect to our Company and our business. Investors should also read the other information in this Form 10-K, including the financial statements and related notes.

Risks Related to our Business

The volatility of natural gas and oil prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

The supply of and demand for natural gas, oil and NGL impact the revenues we realize in connection with the sale of these commodities and, in turn, materially affect our financial results. Our revenues, operating results, cash available for distribution and the carrying value of our natural gas and oil properties depend significantly upon the prevailing prices for natural gas, oil and NGL. Natural gas, oil and NGL prices have historically been, and will likely continue to be, volatile. The prices for natural gas, oil and NGL are subject to wide fluctuation in response to a number of factors beyond our control, including:

•

domestic and worldwide economic conditions;

•

economic, political, regulatory and tax developments;

•

market uncertainty;

•

changes in the supply of and demand for natural gas, oil and NGL, both domestically and abroad;

•

the impacts and effects of public health crises, pandemics and epidemics~~, such as the COVID-19 pandemic~~;

•

availability and capacity of necessary transportation and processing facilities;

•

commodity futures trading;

•

regional price differentials;

•

differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);

•

differing quality and NGL content of natural gas produced;

•

conservation and environmental protection efforts;

•

the level of imports and exports of natural gas, oil and NGL;

•

political instability or armed conflicts in major natural gas and oil producing regions;

•

actions taken by OPEC or other major natural gas, oil and NGL producing or consuming countries;

•

technological advancements affecting energy consumption and energy supply;

•

the level of prices and expectations about future prices of natural gas and oil;

•

the level of global natural gas and oil exploration and production;

•

the cost of exploring for, developing, producing and delivering natural gas and oil;

•

the price and quantity of foreign imports;

•

political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

•

the ability of members of OPEC to agree to and maintain oil price and production controls;

•

speculative trading in natural gas and crude oil derivative contracts;

•

weather conditions and other natural disasters;

•

risks associated with operating drilling rigs;

•

the price and availability of, and competition from, alternative fuels;

•

domestic and foreign governmental regulations, taxes, duties and ~~taxes~~tariffs;

•

the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

•

social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the U.S., such as the conflicts between Ukraine and Russia and between Israel and Hamas;

•

the proximity, cost, availability and capacity of natural gas and oil pipelines and other transportation facilities; and

•

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty. If the prices of natural gas, oil and NGL decline, our operations, financial condition and level of expenditures for the development of our natural gas, oil and NGL reserves may be materially and adversely affected. Lower natural gas, oil and NGL prices may also result in a reduction in the borrowing base under our credit agreement, which may be determined at the discretion of our lenders.

Low natural gas, oil and NGL prices for a prolonged period of time would have a material adverse effect on the Company.

The volatility of the energy markets makes it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty. Natural gas, oil and NGL prices continued to fluctuate in fiscal year 2024, with realized sale prices of natural gas, oil and NGL declining in 2024 by 16%, 3% and 1%, respectively, compared to 2023 realized sale prices. Our financial position, results of operations, access to capital and the quantities of natural gas, oil and NGL that may be economically produced would be negatively impacted if natural gas, oil and NGL prices were low for an extended period of time. The ways in which low prices could have a material negative effect include the following:

•

significantly decrease the number of wells operators drill on our acreage, thereby reducing our production and cash flows;

•

cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves and maintain or increase production;

•

future undiscounted and discounted net cash flows from producing properties would decrease, possibly resulting in recognition of impairment expense;

•

certain reserves may no longer be economic to produce, leading to lower proved reserves, production and cash flow;

access to sources of capital, such as equity and debt markets, could be severely limited or unavailable; and

•

access to sources of capital, such as equity and debt markets, could be severely limited or unavailable; and

•

we may incur a reduction in the borrowing base on our credit facility.

There is no assurance that our evaluation of strategic alternatives will result in any particular outcome, and the process of reviewing strategic alternatives or the conclusion of the process could adversely affect our business and our stockholders.

On December 12, 2024, we announced that the Board agreed to initiate a process to evaluate certain strategic alternatives to maximize stockholder value, including a potential merger or sale of the Company. Our Board has not set a deadline or definitive timetable for the completion of this strategic alternatives process, nor have any definitive decisions been made relating to any strategic alternatives at this time. There can be no assurance that this process will result in the Company’s consummation of a merger, sale of the Company or any other strategic transaction or outcome. Any potential transaction may be dependent on a number of factors that are beyond our control, for example, market conditions, industry trends, the interest of third parties in a potential transaction with us and the availability of any necessary financing on reasonable terms. The process of exploring strategic alternatives could adversely impact our business, financial condition and results of operations. We could incur substantial expenses associated with identifying, evaluating and negotiating potential strategic alternatives, including those related to equity compensation, severance pay and legal, accounting and financial advisory fees. In addition, the process may be time consuming and disruptive to our business operations, could divert the attention of management and the Board from our business, could negatively impact our ability to attract, retain and motivate key employees, and could expose us to potential litigation in connection with this process or any resulting transaction. Further, speculation regarding any developments related to the review of strategic alternatives and perceived uncertainties related to the future of the Company could cause our stock price to fluctuate significantly.

The conflicts in Ukraine and Israel and related price volatility and geopolitical instability could negatively impact our business.

Global geopolitical tensions, including instability in the Middle East, and the conflicts between Russia and Ukraine and between Israel and Hamas, have caused, and could intensify, volatility in natural gas, oil and NGL prices, and the extent and duration of military actions, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time. Any such volatility and disruptions may also magnify the impact of other risks described in this “Risk Factors” section.

Lower natural gas, oil and NGL prices or negative adjustments to natural gas, oil and NGL reserves may result in significant impairment charges.

We have elected to utilize the successful efforts method of accounting for our natural gas and oil exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and development dry holes are capitalized and amortized by property using the unit-of-production method (the ratio of natural gas, oil and NGL volumes produced to total proved or proved developed reserves) as natural gas, oil and NGL are produced.

All long-lived assets, principally our natural gas and oil properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset on our books may be greater than our future net cash flows. The need to test a property for impairment may result from declines in natural gas, oil and NGL sales prices or unfavorable adjustments to natural gas, oil and NGL reserves. The decision to not participate in future development on our leasehold acreage can trigger a test for impairment. Also, once assets are classified as held for sale, they are reviewed for impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If an impairment charge is recognized, cash flow from operating activities is not impacted, but net income and, consequently, stockholders’ equity are reduced. In periods when impairment charges are incurred, it could have a material adverse effect on our results of operations. See Note 11 to the financial statements included in Item 8 – “Financial Statements and Supplemental Data” for further discussion on impairment under the heading “Impairment.”

Our future success depends on developing our existing inventory of mineral acreage and acquiring additional mineral interests. Failure to develop our existing inventory of mineral acreage and to acquire additional mineral interests will cause reserves and production to decline materially from their current levels.

The rate of production from natural gas and oil properties generally declines as reserves are depleted. Our proved reserves will decline materially as reserves are produced except to the extent that we acquire additional mineral interests on properties containing proved reserves and our lessees or well operators conduct additional successful exploration and development drilling, successfully apply new technologies or identify additional behind-pipe zones (different productive zones within existing producing ~~well bores) or secondary recovery reserves.~~

well bores) or secondary recovery reserves. Our proved reserves of natural gas have declined by approximately 12% from approximately 56.0 million Mcf at December 31, 2023 to approximately 49.3 million Mcf at December 31, 2024.

Drilling for natural gas and oil invariably involves unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient reserves to return a profit after deducting drilling, completion, operating and other costs. In addition, wells that are profitable may not achieve a targeted rate of return. We rely on third-party operators’ interpretation of seismic data and other advanced technologies in identifying prospects and in conducting exploration and development activities. Nevertheless, prior to drilling a well, the seismic data and other technologies used do not allow operators to know conclusively whether natural gas, oil or NGL is present in commercial quantities.

Cost factors can adversely affect the economics of any project, and the eventual cost of drilling, completing and operating a well is controlled by well operators and existing market conditions. Further, drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

•

unexpected drilling conditions;

•

title problems;

•

pressure or irregularities in formations;

•

equipment failures or accidents;

•

fires, explosions, blowouts and surface cratering;

•

lack of availability to market production via pipelines or other transportation;

•

adverse weather conditions;

•

environmental hazards or liabilities;

•

lack of water disposal facilities;

•

governmental regulations;

•

cost and availability of drilling rigs, equipment and services; and

•

expected sales price to be received for natural gas, oil or NGL produced from the wells.

Competition for acquisitions of mineral interests may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold properties, which could result in unforeseen operating difficulties. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business or assets into our existing operations. The process of integrating acquired businesses or assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

No assurance can be given that we will be able to identify suitable mineral interest acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and cash available for distribution. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for distribution.

Any acquisition of additional mineral and royalty interests that we complete will be subject to substantial risks.

Any acquisition involves potential risks, including, among other things:

•

the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses and costs;

•

a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;

•

a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

•

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

•

mistaken assumptions about the overall cost of equity or debt;

•

our ability to obtain satisfactory title to the assets we acquire;

•

an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

•

the occurrence of other significant changes, such as impairment of natural gas and oil properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of natural gas, oil and NGL with precision. Natural gas, oil and NGL reserve engineering requires subjective estimates of underground accumulations of natural gas, oil and NGL using assumptions concerning future prices of these commodities, future production levels and operating and development costs. In estimating our reserves, we and our Independent Consulting Petroleum Engineer must make various assumptions with respect to many matters that may prove to be incorrect, including:

•

future natural gas, oil and NGL prices;

•

unexpected complications from offset well development;

•

production rates;

•

reservoir pressures, decline rates, drainage areas and reservoir limits;

•

interpretation of subsurface conditions including geological and geophysical data;

•

potential for water encroachment or mechanical failures;

•

levels and timing of capital expenditures, lease operating expenses, production taxes and income taxes, and availability of funds for such expenditures; and

•

effects of government regulation.

If any of these assumptions prove to be incorrect, our estimates of reserves, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

Our standardized measure of oil and natural gas reserves is calculated using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-month period prior to fiscal year end. These prices and the operating costs in effect as of the date of estimation are held flat over the life of the properties. Production and income tax expenses are deducted from this calculation of future estimated development, with the result discounted at 10% per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.

discounted at 10% per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.

The reserve estimates made for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy records. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures. Further, our lack of knowledge of all individual well information known to the well operators such as incomplete well stimulation efforts, restricted production rates for various reasons and up-to-date well production data, etc. may cause differences in our reserve estimates.

Because PUD reserves, under SEC reporting rules, may only be recorded if the wells they relate to are scheduled to be drilled within five years of the date of recording, the removal of PUD reserves that are not developed within this five-year period may be required. Removals of this nature may significantly reduce the quantity and present value of our natural gas, oil and NGL reserves. Please read Item 2 – “Properties – Proved Reserves” and Supplementary Information to the financial statements included in Item 8 – “Financial Statements and Supplementary Data.”

Since forward-looking prices and costs are not used to estimate discounted future net cash flows from our estimated proved reserves, the standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved natural gas, oil and NGL reserves.

The timing of the development and production on our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor used when calculating discounted future net cash flows, in compliance with the FASB statement on oil and natural gas producing activities disclosures, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company, or the oil and natural gas industry in general.

Debt level and interest rates may adversely affect our business.

On September 1, 2021, we entered into a four-year Credit Agreement (as amended, the “Credit Agreement”) with certain lenders and Independent Bank, as Administrative Agent and Letter of Credit Issuer (as defined in the Credit Agreement). The Credit Agreement replaced our prior revolving credit facility set forth in the Amended and Restated Credit Agreement dated as of November 25, 2013, as amended, among the Company, each lender party thereto, and BOKF, NA dba Bank of Oklahoma, as administrative agent, which we repaid in full and terminated. As of December 31, ~~2023~~2024, we had a balance of $3229,~~750~~500,000 drawn on our credit facility set forth in the Credit Agreement (the “Credit Facility). The Credit Facility’s borrowing base is currently set at $50,000,000. All obligations under the Credit Agreement are secured, subject to permitted liens and other exceptions, by a first-priority security interest on substantially all of our personal property and at least 75% of the total value of the proved, developed and producing Oil and Gas Properties (as defined in the Credit Agreement) owned by the Company.

Should we incur additional indebtedness under the Credit Facility to fund capital projects or for other reasons, there is a risk this could adversely affect our business operations as follows:

•

cash flows from operating activities required to service indebtedness may not be available for other purposes;

•

covenants contained in the Credit Agreement may limit our ability to borrow additional funds, pay dividends and make certain investments;

•

any limitation on the borrowing of additional funds may affect our ability to fund capital projects and may also affect how we will be able to react to economic and industry changes;

•

a significant increase in the interest rate under the Credit Facility will limit funds available for other purposes; and

•

changes in prevailing interest rates may affect our capability to meet our interest payments, as the Credit Facility bears interest at floating rates.

The borrowing base of our Credit Facility is subject to periodic redetermination and is based in part on natural gas, oil and NGL prices. A lowering of our borrowing base because of lower natural gas, oil or NGL prices, or for other reasons, could require us to repay indebtedness in excess of the established borrowing base, or we might need to further secure the debt with additional collateral. Our ability to meet any debt obligations depends on our future performance. General business, economic, financial and product pricing conditions, along with other factors, affect our future performance, and many of these factors are beyond our control. In addition, our failure to comply with the restrictive covenants relating to our Credit Facility could result in a default, which might adversely affect our business, financial condition, results of operations and cash flows.

product pricing conditions, along with other factors, affect our future performance, and many of these factors are beyond our control. In addition, our failure to comply with the restrictive covenants relating to our Credit Facility could result in a default, which might adversely affect our business, financial condition, results of operations and cash flows.

We may incur losses as a result of title defects in the properties we own.

Consistent with industry practice, we do not have current abstracts or title opinions on all of our mineral acreage and, therefore, cannot be certain that we have unencumbered title to all of these properties. Our failure to cure any title defects that may exist may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we may suffer a financial loss.

Competition in the oil and natural gas industry is intense, and most of our competitors have greater financial and other resources than we do.

We compete in the highly competitive areas of natural gas and oil acquisition, development, exploration and production. We face intense competition from both major and independent oil and natural gas companies to acquire desirable producing properties, new properties for future exploration and human resource expertise necessary to effectively develop properties. We also face similar competition in obtaining sufficient capital to maintain or grow production.

We may be subject to information technology system failures, network disruptions, cyber-attacks or other breaches in data security.

The oil and natural gas industry in general has become increasingly dependent upon digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We use digital technology to estimate quantities of natural gas, oil and NGL reserves, process and record financial data and communicate with our employees and third parties. Power, telecommunication or other system failures due to hardware or software malfunctions, computer viruses, vandalism, terrorism, natural disasters, fire, human error or by other means could significantly affect our ability to conduct our business. Though we have implemented complex network security measures, stringent internal controls and maintain offsite backup of all crucial electronic data, there cannot be absolute assurance that a form of system failure or data security breach will not have a material adverse effect on our financial condition and operations results. For instance, unauthorized access to our reserves information or other proprietary or commercially sensitive information could lead to data corruption, communication interruption or other disruptions in our operations or planned business transactions, any of which could have a material adverse impact on our results of operations. We also face increased risk with the growing sophistication of generative artificial intelligence capabilities, which may improve or expand the existing capabilities of cybercriminals described above in a manner we cannot predict at this time. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

Our derivative activities may reduce the cash flow received for natural gas and oil sales.

In order to manage exposure to price volatility on our natural gas and oil production, we currently, and may in the future, enter into natural gas and oil derivative contracts for a portion of our expected production. Natural gas and oil price derivatives may limit the cash flow we actually realize and therefore reduce our ability to fund future projects. None of our natural gas and oil price derivative contracts are designated as hedges for accounting purposes; therefore, all changes in fair value of derivative contracts are reflected in earnings. Accordingly, these fair values may vary significantly from period to period, materially affecting reported earnings. In addition, this type of derivative contract can limit the benefit we would receive from increases in the prices for natural gas and oil. The fair value of our natural gas and oil derivative instruments outstanding as of December 31, ~~2023~~2024 was a net ~~asset~~liability of $3714,~~283,587~~408.

There is risk associated with our derivative contracts that involves the possibility that counterparties may be unable to satisfy contractual obligations to us. If any counterparty to our derivative instruments were to default or seek bankruptcy protection, it could subject a larger percentage of our future natural gas and oil production to commodity price changes, could adversely affect our cash flows and could have a negative effect on our ability to fund future acquisitions.

Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 and 12 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding derivative contracts.

There are inherent limitations in all control systems, and misstatements due to error or fraud could occur and not be detected.

The ongoing internal control provisions of Section 404 of the Sarbanes-Oxley Act of 2002 require us to identify material weaknesses in internal control over financial reporting, which is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with GAAP. Our management, including our principal executive officer and principal financial officer, does not expect that our internal controls and disclosure controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud in our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving our stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur in the future and not be detected.

In addition, discovery and disclosure of a material weakness, by definition, could have a material adverse impact on our financial statements. Such an occurrence could negatively affect our business and affect how our stock trades. This could, in turn, negatively affect our ability to access public equity or debt markets for capital.

Future legislative or regulatory changes may result in increased costs and decreased revenues, cash flows and liquidity.

Companies that operate wells in which we own a working interest are subject to extensive federal, state and local regulation. We, as a working interest owner, are therefore indirectly subject to these same regulations. New or changed laws and regulations such as those described below could have a material adverse effect on our business. In particular, changes in law or regulation related to hydraulic fracturing or greenhouse gases could potentially increase capital, compliance and operating costs significantly, as well as halt or delay the further development of oil and gas reserves on our properties.

Federal Income Taxation

We are subject to U.S. federal income tax, as well as income or capital-based taxes in various states, and our operating cash flow is sensitive to the amount of income taxes we must pay. Income taxes are assessed on our ~~revenue~~net ~~after~~income ~~consideration~~as ofdetermined ~~all~~for federal income tax purposes, considering allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of ~~costs~~items that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow.

Certain beneficial provisions within the Tax Cuts and Jobs Act passed in December 2017 began to be reduced beginning in 2023 and, without legislative action, will continue to be reduced. As a result, the percentage of immediate bonus depreciation available for qualified property placed into service in 2024 is set to be 60%, and shall be reduced by 20% each year until it reaches 0% in 2027.

The Inflation Reduction Act of 2022 (the “IRA”), which was signed into law in August 2022, includes several provisions that are specifically applicable to corporations. The IRA includes an annual 15% minimum tax on corporations that have “average annual adjusted financial statement income” in excess of $1 billion over a three-year period. The IRA also includes a 1% tax on publicly traded corporations on the fair market value of stock repurchased during any taxable year. Such tax applies to the extent such buybacks exceed $1 million during such year, which buyback value may be offset by other stock issuances.

~~Additionally,~~Further ~~further~~ revisions to U.S. tax law, such as aany ~~reversal~~increase ofin ~~the~~ corporate income tax ~~rate reduction~~rates, the repeal of the percentage depletion allowance, or the repeal of expensing for intangible drilling costs, could have a material adverse effect on our business. Moreover, the U.S. Department of Treasury has broad authority to issue regulations and interpretative guidance that may significantly impact how we apply U.S. tax law, with a corresponding impact on the results of our operations for the periods affected.

Oklahoma Taxation

Oklahoma imposes a gross production tax, or severance tax, on the value of natural gas, oil and NGL produced within the state. Under Oklahoma law, the gross production tax rate on the first three years of a horizontal well’s production is 5.2% and 7% thereafter. Future changes to Oklahoma production taxes could affect the profitability of wells producing natural gas, oil and NGL in Oklahoma.

Hydraulic Fracturing and Water Disposal

The vast majority of natural gas and oil wells drilled in recent years have been, and future wells are expected to be, hydraulically fractured as a part of the process of completing the wells and putting them on production. This is true of the wells drilled in which we own an interest. Hydraulic fracturing is a process that involves pumping water, sand and additives at high pressure into rock formations to stimulate natural gas and oil production. In developing plays where hydraulic fracturing, which requires large volumes of water, is necessary for successful development, the demand for water may exceed the supply. A lack of readily available water or a significant increase in the cost of water could cause delays or increased completion costs.

In addition to water, hydraulic fracturing fluid contains chemical additives designed to optimize production. Well operators are being required in certain states to disclose the components of these additives. Additional states and the federal government may follow with similar requirements or may restrict the use of certain additives. This could result in more costly or less effective development of wells.

~~Once~~The ~~a well has been hydraulically fractured, the~~ fluid produced from the fractured ~~wells~~formation must be either treated for reuse or disposed of by injecting the fluid into disposal wells. Injection well disposal processes have been, and continue to be, studied to determine the extent of correlation between injection well disposal and the occurrence of earthquakes. Certain studies have concluded there is a correlation, and this has resulted in the cessation of or the reduction of injection rates in certain water disposal wells, especially in northern Oklahoma.

studied to determine the extent of correlation between injection well disposal and the occurrence of earthquakes. Certain studies have concluded there is a correlation, and this has resulted in the cessation of or the reduction of injection rates in certain water disposal wells, especially in northern Oklahoma.

Efforts to regulate hydraulic fracturing and fluid disposal continue at the local, state and federal level. New regulations are being considered, including limiting water withdrawals and usage, limiting water disposition, restricting which additives may be used, implementing statewide hydraulic fracturing moratoriums and temporary or permanent bans in certain environmentally sensitive areas. Public sentiment against hydraulic fracturing and fluid disposal and shale production could result in more stringent permitting and compliance requirements. Consequences of these actions could potentially increase capital, compliance and operating costs significantly, as well as delay or halt the further development of gas and oil reserves on our properties. Though the Biden administration has not proposed the outright ban of hydraulic fracturing, the administration has proposed significant regulations regarding methane emissions that could potentially affect new and existing wells, including those that are hydraulically fractured. The proposed methane rule is discussed in more detail in the Climate Change section, below.

Any of the above factors could have a material adverse effect on our financial position, results of operations or cash flows.

Climate Change

Certain studies have suggested that emission of certain gases, commonly referred to as “greenhouse gases,” may be impacting the earth’s climate. Methane, the primary component of natural gas, and carbon dioxide, a byproduct of burning natural gas and oil, are examples of greenhouse gases. Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as gas and oil production equipment and operations.

~~Legislation~~The toregulatory ~~regulate~~environment surrounding greenhouse gas emissions ~~has~~is ~~periodically~~evolving ~~been~~under ~~introduced in~~ the Unew administration.S. ~~Congress,~~On ~~and~~January ~~such~~20, ~~legislation~~2025, ~~may~~President beTrump ~~proposed~~issued in the ~~future.~~“Unleashing InAmerican ~~December~~Energy” ~~2023,~~executive ~~the~~Order ~~EPA~~(EO ~~issued~~3418), adirecting ~~final~~federal ~~rule~~agencies to ~~regulate~~review ~~methane~~and ~~emissions~~potentially ~~from~~revise ~~the~~or ~~oil~~rescind ~~and~~regulations ~~gas~~related ~~industry. States have authority~~ to ~~incorporate~~methane ~~the~~emissions ~~emission~~and ~~guidelines~~other ~~proposed~~climate bypolicies affecting the ~~EPA~~oil orand togas ~~adopt~~industry. ~~their~~This ~~own~~includes ~~standards~~a ~~that~~review ~~achieve the same degree~~ of ~~emission limitations. The rule applies to~~ the ~~Crude~~EPA ~~Oil~~Methane ~~and~~Rule ~~Natural~~that ~~Gas~~became ~~source~~effective ~~category,~~on ~~including~~May ~~the production~~7, ~~processing, transmission, and storage segments~~2024. The ~~methane~~EPA ~~rule~~Methane ~~results~~Rule inestablished ~~additional~~new ~~operating~~compliance ~~costs,~~requirements ~~such~~for ~~as costs to purchase and operate~~ emissions ~~controls~~monitoring, ~~or lower emitting~~ equipment standards, and ~~costs~~operational ~~to implement monitoring requirements~~controls.

At the international level, the “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions every five years after 2020. President Biden recommitted the United States to the Paris Agreement and in April 2021 announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. At the 2023 United Nations Climate Change Conference (“COP28”) in December 2023, the parties signed onto an agreement to transition away from fossil fuels in energy systems and increase renewable energy capacity. While no firm commitment or timeline to phase out or phase down fossil fuels was made, and the agreement is non-binding, the agreements coming out of COP28 could result in increased pressure among financial institutions and various stakeholders to reduce or otherwise impose more stringent limitations on funding for and increase potential opposition to the production and use of fossil fuels. The full impact of these actions is uncertain at this time.15

There is a shift in federal climate policy under the Trump administration. The administration has prioritized domestic energy production and deregulation over climate change. The United States has initiated the process to withdraw from the Paris Agreement. On January 20, 2025, President Trump signed an executive order entitled “Putting America First in International Environmental Agreements” directing the immediate withdrawal from the Paris Agreement. Under the Paris Agreement, a request to withdraw becomes effective one year after receipt of notification. Although the United States remains a party to the Paris Agreement at this time, the administration has indicated its intent to reassess U.S. climate goals, regulatory policies and international commitments.

The COP28 agreement remains non-binding and does not impose any legal obligations on the United States. However, investors, financial institutions and other stakeholders could still impact access to capital and the cost of financing for fossil fuel projects. The extent to which global climate polices and market forces will affect the oil and gas industry is uncertain.

We will continue to monitor policy developments at the state, federal and international levels and assess their potential impacts on our business and operations.

Inflation Reduction Act of 2022

The Inflation Reduction Act of 2022 (IRA 2022) appropriates significant federal funding for renewable energy initiatives. These incentives could accelerate the transition of the U.S. economy towards lower- or zero-carbon emissions alternatives, which could decrease demand for oil and gas. Moreover, the IRA 2022 imposes a federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their greenhouse gas emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge could increase the operating costs of exploration and production operators.

On January 20, 2025, President Trump issued the “Unleashing American Energy” executive order (EO 3418), which directs federal agencies to suspend the disbursement of funds under IRA 2022, reassess existing energy policies, and streamline permitting processes for oil and gas development. If fully implemented, EO 3418 is expected to reduce compliance costs, expand development opportunities, and provide more investment certainty. However, while the executive order signals a shift in energy policy, certain provisions of the IRA were enacted through legislation that may require congressional action or judicial review before being fully repealed or modified. We will continue to monitor regulatory developments, potential legal challenges, and legislative actions that may affect the implementation of EO 3418. While the administration’s energy policies appear broadly supportive of the oil and gas industry, ongoing legal and political dynamics may impact the extent to which specific provisions are ultimately enforced or rescinded.

Seismic Activity

Earthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. Several states have imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation that could lead to operational delays, increase operating and compliance costs or otherwise adversely affect operations.

disposal wells in areas with increased instances of induced seismic events. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation that could lead to operational delays, increase operating and compliance costs or otherwise adversely affect operations.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on us and our ability to hedge risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (Dodd-Frank Act) required, in part, that the U.S. Commodity Futures Trading Commission (CFTC) and the SEC promulgate rules and regulations to establish federal oversight for the over-the-counter (OTC) derivatives markets and entities that participate in those markets. Among other things, the new rules and regulations impose (i) mandatory central clearing and exchange trading requirements on certain liquid, standardized swaps, (ii) initial and variation margin requirements on swaps that are not required to be centrally cleared, and (iii) position limits that cap the notional exposure market participants can have to certain physical commodity derivatives such as the energy-related swaps that we use to hedge risk. These new rules and regulations have impacted the cost and availability of derivative products and hedging and swap positions that our counterparties can make available to us. While the majority of Dodd-Frank Act rules and regulations have been promulgated and are already in effect, certain other rules and regulations remain to be finalized or effectuated and, therefore, the impact of those rules and regulations on us is uncertain at this time. Any further changes in the rules and regulations of derivative products, including swaps, may result in certain market participants deciding to curtail or cease their derivative activities with us altogether.

and variation margin requirements on swaps that are not required to be centrally cleared, and (iii) position limits that cap the notional exposure market participants can have to certain physical commodity derivatives such as the energy-related swaps that we use to hedge risk. These new rules and regulations have impacted the cost and availability of derivative products and hedging and swap positions that our counterparties can make available to us. While the majority of Dodd-Frank Act rules and regulations have been promulgated and are already in effect, any changes in the rules and regulations of derivative products, including swaps, may result in certain market participants deciding to curtail or cease their derivative activities with us altogether.

Risks Related to our Third-Party Operators

We ~~cannot~~do not control activities on our properties.

We do not operate any of the properties in which we have an interest and have very limited ability to exercise influence over the third-party operators of these properties. Our dependence on the third-party operators of our properties, and on the cooperation of other working interest owners in these properties, could negatively affect the following:

•

our return on capital used in drilling or property acquisition;

•

our production and reserve growth rates;

•

capital required to workover or recomplete wells;

•

success and timing of drilling, development and exploitation activities on our properties;

•

compliance with environmental, safety and other regulations;

•

lease operating expenses; and

•

plugging and abandonment costs, including well-site restorations.

Dependency on each operator’s judgment, expertise and financial resources could result in unexpected future costs, lost revenues and/or capital restrictions, to the extent they would cumulatively have a material adverse effect on our financial position and results of operations.

The natural gas and oil drilling and producing operations of our third-party operators involve various risks.

Because we do not operate our properties, our business relies heavily upon our third-party operators and their operational effectiveness. Through our third-party operators, we are subject to all the risks normally incident to the operation and development of natural gas and oil properties, including:

•

well blowouts, cratering, explosions and human related accidents;

•

mechanical, equipment and pipe failures;

•

adverse weather conditions, earthquakes and other natural disasters;

•

civil disturbances and terrorist activities;

•

natural gas, oil and NGL price reductions;

•

environmental risks stemming from the use, production, handling and disposal of water, waste materials, hydrocarbons and other substances into the air, soil or water;

•

title problems;

•

limited availability of financing;

•

marketing related infrastructure, transportation and processing limitations; and

•

regulatory compliance issues.

As a non-operator, we are also dependent on third-party operators and the contractors they hire for operational safety, environmental safety and compliance with regulations of governmental authorities.

We maintain insurance against many potential losses or liabilities arising from well operations in accordance with customary industry practices and in amounts believed by management to be prudent. However, this insurance does not protect us against all risks. For example, we do not maintain insurance for business interruption, acts of war or terrorism. Additionally, pollution and environmental risks generally are not fully insurable. These risks could give rise to significant uninsured costs that might have a material adverse effect on our business condition and financial results.

We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.

A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell natural gas or oil at the same price as the operator it replaced.

Shortages of oilfield equipment, services, qualified personnel and resulting cost increases could adversely affect results of operations.

The demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas, oil and NGL prices, resulting in periodic shortages. When demand for rigs and equipment increases due to an increase in the number of wells being drilled, there have been shortages of drilling rigs, hydraulic fracturing equipment and personnel and other oilfield equipment. Higher natural gas, oil and NGL prices generally stimulate increased demand for, and result in increased prices of, drilling rigs, crews and associated supplies, equipment and services. These shortages or price increases could negatively affect the ability to drill wells and conduct ordinary operations by the operators of our wells, resulting in an adverse effect on our financial condition, cash flow and operating results.

The marketability of natural gas and oil production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.

The marketability of our or our operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, the shipment of our or our operators’ natural gas and oil on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations and cash distributions to stockholders. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil production, transportation and pipeline safety—as well as by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

1718

unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, the shipment of our or our operators’ natural gas and oil on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations and cash distributions to stockholders. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil production, transportation and pipeline safety—as well as by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

We may be negatively impacted by inflation.

Increases in inflation could have an adverse effect on us. Current and future inflationary effects may be driven by, among other things, supply chain disruptions and governmental stimulus or fiscal policies, and geopolitical instability, including the ongoing conflicts between Ukraine and Russia and between Israel and Hamas. Continuing increases in inflation could increase our costs of labor and other costs related to our business, which could have an adverse impact on our business, financial position, results of operations and cash flows. Inflation has also resulted in higher interest rates in the U.S., which could increase our cost of debt borrowing in the future.

Risks Related to the Oil and Gas Industry

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, financial condition and cash available for distribution.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit in the European, Asian and U.S. markets contribute to economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of natural gas, oil and NGL, volatility in consumer confidence and job markets, may result in an economic slowdown or recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which natural gas, oil and NGL from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.

Conservation measures and technological advances could reduce demand for natural gas and oil.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas and oil. The impact of the changing demand for natural gas and oil services and products may have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Risks Related to an Investment in our Common Stock

The issuance of additional shares of our Common Stock could cause the market price of our Common Stock to decline and may result in dilution to our existing stockholders.

We have in the past issued, and may in the future from time to time issue, additional shares of Common Stock in public offerings pursuant to registration statements filed with the SEC. We also issue shares of our Common Stock in private transactions from time to time. For example, in the past we have issued shares of Common Stock in private transactions as consideration for the acquisition of mineral and royalty assets, and we have registered the resale of such shares through the filing of registration statements on Form S-3. We may also, in the future, issue securities other than Common Stock in public offerings or private transactions.

We cannot predict the effect, if any, that market sales of our securities or the availability of our securities will have on the prevailing market price of our Common Stock from time to time. Substantial sales of shares of our Common Stock or other securities in the public market, or the perception that those sales could occur, may cause the market price of our Common Stock to decline. Such a decrease in our share price could in turn impair our ability to raise capital through the sale of additional equity securities. In addition, any such decline may make it more difficult for stockholders to sell shares of our Common Stock at prices they deem acceptable.

18As of December 31, 2024, we were authorized to issue an aggregate of 75,010,000 shares of capital stock, consisting of 75,000,000 shares of Common Stock and 10,000 shares of preferred stock, par value $0.01666 per share (“Preferred Stock”), of which 37,922,368 shares of Common Stock and no shares of Preferred Stock were issued and outstanding on March 5, 2025. Future issuances of our Common Stock or Preferred Stock, or other securities convertible into our Common Stock or Preferred Stock, may result in significant dilution to our existing stockholders. Significant dilution would reduce the proportionate ownership and voting power held by our existing stockholders.

a decrease in our share price could in turn impair our ability to raise capital through the sale of additional equity securities. In addition, any such decline may make it more difficult for stockholders to sell shares of our Common Stock at prices they deem acceptable.

As of December 31, 2023, we were authorized to issue an aggregate of 54,010,500 shares of capital stock, consisting of 54,000,500 shares of Common Stock and 10,000 shares of preferred stock, par value $0.01666 per share (“Preferred Stock”), of which 37,438,237 shares of Common Stock and no shares of Preferred Stock were issued and outstanding on March 5, 2024. Future issuances of our Common Stock or Preferred Stock, or other securities convertible into our Common Stock or Preferred Stock, may result in significant dilution to our existing stockholders. Significant dilution would reduce the proportionate ownership and voting power held by our existing stockholders.

We may reduce or suspend our dividend in the future.

We have paid a quarterly dividend for many years. Our most recent quarterly dividend was $0.03 per share, and we have paid a quarterly dividend ranging from $0.01 per share or $0.03 per share for the past three years. In the future our Board may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position us for long‑term success. The declaration and amount of future dividends is at the discretion of our Board and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness. In addition, our ability to pay dividends may be limited by agreements governing our indebtedness now or in the future. Although we do not currently have plans to reduce or suspend our dividend, there can be no assurance that we will not reduce our dividend or that we will continue to pay a dividend in the future.19

We have paid a quarterly dividend for many years. Our most recent quarterly dividend was $0.04 per share, and we have paid a quarterly dividend ranging from $0.015 per share or $0.04 per share for the past three years. In the future our Board may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position us for long‑term success. The declaration and amount of future dividends is at the discretion of our Board and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness. In addition, our ability to pay dividends may be limited by agreements governing our indebtedness now or in the future. For example, our Credit Agreement sets limits on dividend payments and stock repurchases if those payments would cause the Leverage Ratio (as defined in the Credit Agreement) to go above 2.50 to 1.0 or the Available Commitment (as defined in the Credit Agreement) to go below ten percent of the Borrowing Base (as defined in the Credit Agreement). Although we do not currently have plans to reduce or suspend our dividend, there can be no assurance that we will not reduce our dividend or that we will continue to pay a dividend in the future.

If we cannot meet the NYSE continued listing requirements, the NYSE may delist our Common Stock.

Our Common Stock is currently listed on the NYSE. In the future, if we are unable to meet the continued listing requirements of the NYSE, including, among other things, (i) the requirement of maintaining a minimum average closing price of $1.00 per share over a consecutive 30 trading-day period and (ii) the requirement of maintaining an average market capitalization of not less than $50 million over a 30 trading-day period with, at the same time, stockholders’ equity not less than $50 million, we would fall below compliance standards and risk having our Common Stock delisted. In addition, in the event of an abnormally low share price of our Common Stock and/or we fail to maintain an average market capitalization of at least $15 million over a 30-trading day period, we would be subject to immediate delisting under the NYSE’s rules without any opportunity to cure. A delisting of our Common Stock could negatively impact us by, among other things, the following:

•

causing our shares to be transferred to a more limited market than the NYSE, which could affect the market price, trading volume, liquidity and resale price of such shares;

•

reducing the number of investors, including institutional investors, willing to hold or acquire our Common Stock, which could negatively impact our ability to raise equity;

•

decreasing the amount of news and analyst coverage relating to us;

•

limiting our ability to issue additional securities, obtain additional financing or pursue strategic restructuring, refinancing or other transactions; and

•

impacting our reputation and, as a consequence, our business.

ITEM 1B. Staff Comments

None

ITEM 1C. Cybersecurity

~~Cybersecurity~~Risk ~~risk~~Management ~~management is part of the Company’s overall enterprise risk management program. Our cybersecurity risk management program is designed to provide a framework for handling cybersecurity threats~~ and incidents, including threats and incidents associated with the use of services provided by third-party service providers, and facilitate coordination across different departments of our company. This framework includes steps for assessing the severity of a cybersecurity threat, identifying the source of a cybersecurity threat including whether the cybersecurity threat is associated with a third-party service provider, implementing cybersecurity countermeasures and mitigation strategies and informing management and our Board of material cybersecurity threats Strategy

19Cybersecurity risk management is part of the Company’s overall enterprise risk management program. Our cybersecurity risk management program is designed to provide a framework for handling cybersecurity threats and incidents, including threats and incidents associated with the use of services provided by third-party service providers, and facilitate coordination across different departments of our company. This framework includes steps for assessing the severity of a cybersecurity threat, identifying the source of a cybersecurity threat including whether the cybersecurity threat is associated with a third-party service provider, implementing cybersecurity countermeasures and mitigation strategies and informing management and our Board of material cybersecurity threats and incidents. We engage with third party service providers to perform penetration tests and to inform us of possible vulnerabilities. In addition, cybersecurity training is provided to all employees on a regular basis and at least annually.

and incidents. We engage with third party service providers to perform penetration tests and to inform us of possible vulnerabilities. In addition, cybersecurity training is provided to all employees on a regular basis but at least annually.Governance

Our Board has overall oversight responsibility for our risk management, including the cybersecurity risk management program. Management is responsible for identifying, considering and assessing material cybersecurity risks on an ongoing basis, establishing processes to ensure that such potential cybersecurity risk exposures are monitored, putting in place appropriate mitigation measures and maintaining cybersecurity programs. Our cybersecurity programs are under the direction of our Principal Accounting Officer, who receives reports from our cybersecurity consultants and monitors the prevention, detection, mitigation, and remediation of cybersecurity incidents. Any significant cybersecurity incidents are reported to the audit committee, which is 100% independent, and ultimately to our Board. There were no such cybersecurity incidents in fiscal 2023, 2022, or 2021. Management presents an assessment of our cybersecurity processes, procedures, and results of testing to the Audit Committee at least annually.

establishing processes to ensure that such potential cybersecurity risk exposures are monitored, putting in place appropriate mitigation measures and maintaining cybersecurity programs. Our cybersecurity programs are under the direction of our Principal Accounting Officer, who receives reports from our cybersecurity consultants and monitors the prevention, detection, mitigation, and remediation of cybersecurity incidents. Any significant cybersecurity incidents are reported to the Audit Committee, which consists of 100% independent directors, and ultimately to our Board. Management presents an assessment of our cybersecurity processes, procedures, and results of testing to the Audit Committee at least annually.

Despite our efforts, we cannot eliminate all risks from cybersecurity threats, or provide assurances that we have not experienced an undetected cybersecurity incident. For more information about these risks, please see “Risk Factors – We may be subject to information technology system failures, network disruptions, cyber-attacks or other breaches in data security.” in this Form 10-K.

ITEM 2. Properties

General Background

We are focused on perpetual natural gas and oil mineral ownership in resource plays in the United States. As part of our evolution as a company, we also own interests in leasehold acreage and non-operated working interests in natural gas and oil properties.

At December 31, ~~2023~~2024, our principal properties consisted of (i) perpetual ownership of ~~240~~239,~~651~~909 net mineral acres, held principally in Oklahoma, Texas, Louisiana, North Dakota and Arkansas; (ii) leases on 13,~~293~~290 net acres primarily in Oklahoma; and (iii) working interests, royalty interests or both in 6,~~773~~958 producing natural gas and oil wells and ~~168~~150 wells in the process of being drilled or completed.

Management’s Business Strategy Related to Properties

Our primary focus continues to be on perpetual natural gas and oil mineral ownership and growth through mineral acquisitions and the development of our significant mineral acreage inventory in our core focus areas. In accordance with this strategy, we no longer participate in new development on our mineral or leasehold acreage with a cost-bearing working interest. We believe that our strategy to focus on mineral ownership is the best path to giving our stockholders the greatest risk-weighted returns on their investments.

Our goal is to increase stockholder value through the active management of our fee mineral and leasehold assets. We continue to grow our mineral fee holdings by acquiring mineral acreage, in the core areas of resource plays with substantial undeveloped opportunities, that meets or exceeds our corporate return threshold. We have an active program in place focused on leasing open acreage to generate additional lease bonus revenue and future royalty revenue. We also generate additional cash flows through opportunistically divesting unleased minerals.

Title to Properties

2021

Acreage

Mineral Interests Owned

The following table of mineral interests owned reflects, in each respective state, the number of (i) net and gross acres owned by the Company, (ii) net and gross producing acres owned by the Company, (iii) net and gross acres leased to others by the Company and (iv) net and gross acres open (unleased) as of December 31, ~~2023~~2024.

State

Net Acres

Gross Acres

Net Acres Producing(1)

GrossAcresProducing(1)

Net AcresLeased toOthers (2)

GrossAcresLeased toOthers (2)

Net AcresUnleased(3)

Gross AcresUnleased(3)

Oklahoma

106,~~151~~409

1,~~040~~042,~~241~~744

48,~~501~~913

~~450~~455,~~414~~866

31,~~827~~530

3011,~~949~~801

5355,~~823~~966

~~558~~575,~~878~~077

Texas

3130,~~653~~395

~~262~~252,~~193~~419

5,~~249~~154

7978,~~510~~704

~~2,053~~277

122,~~411~~240

24,~~351~~964

~~170~~171,~~272~~475

Louisiana

3,~~711~~971

3940,~~143~~426

3,~~710~~971

3940,~~138~~426

North Dakota

14,~~318~~316

90,~~358~~357

2,~~788~~786

26,~~745~~744

11,530

63,613

Arkansas

11,754

55,417

7,236

32,237

4,518

23,180

Other

73,064

257,585

1,076

7,700

68-

~~400~~-

71,~~920~~988

249,~~485~~885

Total

~~240~~239,~~651~~909

1,~~744~~738,~~937~~948

6869,~~560~~136

~~635~~641,~~744~~677

51,~~949~~807

4314,~~765~~041

~~166~~168,~~142~~966

1,~~065~~083,~~428~~230

(1)

“Producing” represents the mineral acres in which PHX owns a royalty or working interest in a producing well.

(2)

“Leased” represents the mineral acres owned by PHX that are leased to third parties but not producing.

(3)

“Unleased” represents mineral acres owned by PHX that are not leased or in production.

Leases

The following table reflects our net mineral acres leased from others, lease expiration dates through ~~2027~~2028, and net leased acres held by production related to leasehold as of December 31, ~~2023~~2024.

Net Acres Expiring

State

NetAcres

~~2023~~2024

~~2024~~2025

~~2025~~2026

~~2026~~2027

~~2027~~2028

Net AcresHeld byProduction

Oklahoma

10,~~115~~025

Texas

~~368~~367

Other

1,~~083~~084

Total

11,~~566~~476

The following table reflects our net mineral acres leased from others, lease expiration dates through ~~2027~~2028, and net leased acres held by production related to our overriding royalty interests as of December 31, ~~2023~~2024.

			Net Acres Expiring
State	NetAcres		~~2023~~2024		~~2024~~2025		~~2025~~2026		~~2026~~2027		~~2027~~2028		Net AcresHeld byProduction
Louisiana		~~185~~274		-		-		-		-		-		~~185~~274
Oklahoma		1,~~511~~509		-		-		-		-		-		1,~~511~~509
Texas		31		-		-		-		-		-		31
Total		1,~~727~~814		-		-		-		-		-		1,~~727~~814

Proved Reserves

Summary of Proved Reserves

The following tables summarize estimates of total and royalty only proved reserves of natural gas, oil and NGL held by the Company as of December 31, ~~2023~~2024, compared to December 31, ~~2022 and September 30~~2023, ~~2022,~~ using prices and costs under existing economic conditions.

2122

~~economic conditions.~~ Proved reserves are located onshore within the contiguous United States and are principally made up of small interests in 6,~~773~~958 wells, which are predominately located in the Mid-Continent region. Other than this Annual Report, our reserve estimates are not filed with any federal agency.

Summary of Proved Natural Gas and Oil Reserves

	Natural Gas		Oil		NGL		Total Proved
	(Mcf)		(Bbl)		(Bbl)		(Mcfe)
Net Proved Developed Reserves
December 31, 2024		42,549,110		948,078		1,322,146		56,170,454
December 31, 2023		44,479,988		937,465		1,362,944		58,282,442
December 31, 2022		48,596,944		1,253,838		1,660,439		66,082,606
September 30, 2022		50,304,185		1,275,853		1,698,046		68,147,579
Net Proved Undeveloped Reserves
December 31, 2024		6,757,726		98,825		25,951		7,506,382
December 31, 2023		11,508,969		134,497		99,712		12,914,223
December 31, 2022		12,608,549		118,168		48,136		13,606,373
September 30, 2022		11,933,021		106,924		64,637		12,962,387
Net Total Proved Reserves
December 31, 2024		49,306,836		1,046,903		1,348,097		63,676,836
December 31, 2023		55,988,957		1,071,962		1,462,656		71,196,665
December 31, 2022		61,205,493		1,372,006		1,708,575		79,688,979
September 30, 2022		62,237,206		1,382,777		1,762,683		81,109,966

Summary of Proved Natural Gas and Oil Royalty Reserves

	Natural Gas		Oil		NGL		Total Proved
	(Mcf)		(Bbl)		(Bbl)		(Mcfe)
Net Proved Developed Royalty Interest Reserves
December 31, 2024		35,404,847		800,965		796,840		44,991,676
December 31, 2023		36,156,363		731,527		715,683		44,839,623
December 31, 2022		31,467,785		628,289		712,342		39,511,571
September 30, 2022		32,055,133		607,727		685,166		39,812,491
Net Proved Undeveloped Royalty Interest Reserves
December 31, 2024		6,757,726		98,825		25,951		7,506,382
December 31, 2023		11,508,969		134,497		99,712		12,914,223
December 31, 2022		12,608,549		118,168		48,136		13,606,373
September 30, 2022		11,933,021		106,924		64,637		12,962,387
Net Total Proved Royalty Interest Reserves
December 31, 2024		42,162,573		899,790		822,791		52,498,058
December 31, 2023		47,665,332		866,024		815,395		57,753,846
December 31, 2022		44,076,334		746,457		760,478		53,117,944
September 30, 2022		43,988,154		714,651		749,803		52,774,878

Exploration and development of our natural gas and oil properties is conducted by 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.

For the ~~three~~year ~~months~~ ended December 31, ~~2022~~2024, our ~~total~~ net total proved reserves decreased by 17.45 Bcfe, as compared to ~~September~~December 3031, ~~2022~~2023. The decrease in total proved reserves from ~~September~~December 3031, ~~2022~~2023 to December 31, ~~2022~~2024 is attributable to a combination of the following factors:

•

Production of 29.28 Bcfe from our natural gas and oil properties.

•

Negative ~~performance~~pricing revisions of 24.19 Bcfe ~~principally~~primarily due to ~~the~~natural ~~shut~~gas ~~in of a significant working interest well in the SCOOP play in the Ardmore basin of Oklahoma,~~ and ~~(i)~~oil wells ~~located~~reaching intheir aneconomic ~~area~~limits ~~with~~earlier ~~gas~~than ~~takeaway~~was ~~constraints~~projected ~~located~~ in ~~the~~2023 ~~Haynesville~~due ~~Shale~~to ~~play~~lower ofcommodity ~~Louisiana and (ii) wells drilled in the last two years in the Haynesville play of Texas~~prices.

•

Negative ~~pricing~~performance revisions of 10.43 Bcfe principally due to a ~~four well~~ pad ~~that~~of ~~did~~working ~~not reach the permitted lateral length when drilled in the Haynesville Shale, therefore reducing royalty~~ interest inwells ~~each~~where ~~well,~~production ~~and~~did ~~permit~~not ~~expirations,~~return asto ~~our~~prior ~~PUD~~rates ~~reserves~~post ~~consist only of wells that are permitted, drilling, or waiting on completion~~workover.

•

22Reserve extensions, discoveries and other additions of 5.0 Bcfe (comprised of 2.0 Bcfe proved developed reserves and 3.0 Bcfe proved undeveloped reserves) principally resulting from: (i) our royalty interest ownership in the ongoing development of unconventional natural gas, utilizing horizontal drilling, in the Haynesville Shale play of East Texas and Western Louisiana; and (ii) our royalty interest ownership in the ongoing development of unconventional natural gas, oil

The sale of 0.2 Bcfe proved developed reserves, consisting predominately of working interest properties in the Arkoma Stack play in Oklahoma.

Reserve extensions, discoveries and other additions of 3.0 Bcfe (comprised of 0.3 Bcfe proved developed reserves and 2.7 Bcfe proved undeveloped reserves) principally resulting from:(i) our royalty interest ownership in the ongoing development of unconventional natural gas, utilizing horizontal drilling, in the Haynesville Shale play of East Texas and Western Louisiana; and (ii) our royalty interest ownership in the ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma.

The acquisition of 1.5 Bcfe, predominately of royalty interest properties in the active drilling programs of the Haynesville Shale play in east Texas and western Louisiana and the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma, of which 0.5 Bcfe were proved developed and 1.0 Bcfe were proved undeveloped.

For the year ended December 31, 2023, our net total proved reserves decreased by 8.5 Bcfe, as compared to December 31, 2022. The decrease in total proved reserves from December 31, 2022 to December 31, 2023 is attributable to a combination of the following factors:

The sale of 10.2 Bcfe proved developed reserves, consisting predominately of working interest properties in the Eagle Ford Shale play in Texas and the Arkoma Stack play and Western Anadarko Basin in Oklahoma.

Production of 9.4 Bcfe from our natural gas and oil properties.

Negative pricing revisions of 4.8 Bcfe due to natural gas and oil wells reaching their economic limits earlier than was projected in 2022 due to lower commodity prices.

Negative performance revisions of 0.5 Bcfe principally due to steeper decline and lower than expected volumes in wells located in an area with gas takeaway constraints located in the Haynesville Shale.

Reserve extensions, discoveries and other additions of 8.8 Bcfe (comprised of 1.0 Bcfe proved developed reserves and 7.8 Bcfe proved undeveloped reserves) principally resulting from: (i) our royalty interest ownership in the ongoing development of unconventional natural gas, utilizing horizontal drilling, in the Haynesville Shale play of East Texas and Western Louisiana; and (ii) our royalty interest ownership in the ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma.

The acquisition of 7.7 Bcfe, predominately of royalty interest properties in the active drilling programs of the Haynesville Shale play in east Texas and western Louisiana and the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma, of which 3.4 Bcfe were proved developed and 4.3 Bcfe were proved undeveloped.

Proved Undeveloped Reserves

The following details the changes in proved undeveloped reserves for fiscal year 2023 (Mcfe):

Beginning proved undeveloped reserves	13,606,373
Proved undeveloped reserves transferred to proved developed	(12,328,750	)
Revisions	(471,393	)
Extensions and discoveries	7,819,628
Sales	-
Purchases	4,288,365
Ending proved undeveloped reserves	12,914,223

During fiscal year 2023, total net PUD reserves decreased by 0.7 Bcfe. In fiscal year 2023, a total of 12.3 Bcfe (91% of the beginning balance) was transferred to proved developed. The remaining balance of approximately 11.6 Bcfe (86% of the beginning balance) of positive revisions to PUD reserves consist of acquisitions of 4.3 Bcfe in the Haynesville Shale in Texas and Louisiana and Meramec and Woodford SCOOP play in Oklahoma, additions and extensions of 7.8 Bcfe within the active drilling program areas of (i) the Haynesville Shale in Texas and Louisiana, (ii) the SCOOP Meramec and Woodford in Oklahoma, (iii) the STACK Meramec

and ~~Woodford~~NGL inutilizing ~~Oklahoma~~horizontal ~~and~~drilling ~~(iv)~~in the ~~Bakken~~Mississippi ~~in North Dakota,~~ and ~~negative~~Woodford ~~revisions~~Shale ofintervals ~~0.5~~in ~~Bcfe~~the ~~primarily~~SCOOP ~~due~~play toin ~~permit~~the ~~expirations,~~Ardmore asbasin ~~our PUD reserves consist only~~ of ~~wells that are permitted, drilling, or waiting on completion~~Oklahoma.

•

The acquisition of 2.5 Bcfe, predominately of royalty interest properties in the active drilling programs of the Haynesville Shale play in east Texas and western Louisiana and the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma, of which 1.2 Bcfe were proved developed and 1.3 Bcfe were proved undeveloped.

Proved Undeveloped Reserves

The following details the changes in proved undeveloped reserves for fiscal year 2024 (Mcfe):


Beginning proved undeveloped reserves	12,914,223
Proved undeveloped reserves transferred to proved developed	(8,501,982	)
Revisions	(1,152,401	)
Extensions and discoveries	2,985,546
Sales	-
Purchases	1,260,996
Ending proved undeveloped reserves	7,506,382

During fiscal year 2024, total net PUD reserves decreased by 5.4 Bcfe. In fiscal year 2024, a total of 8.5 Bcfe (66% of the beginning balance) was transferred to proved developed. This decrease was partially offset by 3.1 Bcfe (24% of the beginning balance) of positive changes to PUD reserves consisting of acquisitions of 1.3 Bcfe in the Haynesville Shale in Texas and Louisiana and Meramec and Woodford SCOOP play in Oklahoma, additions and extensions of 3.0 Bcfe within the active drilling program areas of (i) the Haynesville Shale in Texas and Louisiana, (ii) the SCOOP Mississippi and Woodford in Oklahoma, (iii) the STACK Meramec and Woodford in Oklahoma, (iv) the Arkoma Woodford in Oklahoma and (v) the Bakken in North Dakota, and negative revisions of 1.2 Bcfe primarily due to permit expirations, as our PUD reserves consist only of wells that are permitted, drilling, or waiting on completion.

We anticipate that all our current PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves, which are no longer projected to be drilled within five years from the date they were added to PUD reserves, will be removed as revisions at the time that determination is made. In the event that there are undrilled PUD locations at the end of the five-year period, we will remove the reserves associated with those locations from our proved reserves as revisions.

Estimated Future Net Cash Flows

Set forth below are estimated future net cash flows with respect to our net proved reserves (based on the estimated units set forth above in Proved Reserves) for each of the periods indicated, and the present value of such estimated future net cash flows, computed by applying a 10% discount factor as required by SEC rules and regulations. We follow the SEC rule, Modernization of Oil and Gas Reporting Requirements. In accordance with the SEC rule, the estimated future net cash flows were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-month period ~~(or three-month period for the Transition Period)~~ prior to ~~September 30 or~~ December 31, ~~as applicable,~~ held flat over the life of the properties and applied to future production of proved reserves less estimated future development and production expenditures for these reserves. The amounts presented are net of operating costs and production taxes levied by the respective states. Prices used for determining future cash flows from natural gas, oil and NGL as of December 31, ~~2023,~~2024 ~~December 31, 2022,~~ and ~~September~~2023 ~~30, 2022,~~ were as follows: $2.6705 for natural gas, $7673.8548 for oil and $2120.9897 for NGL for the ~~12-month~~fiscal ~~period~~year ended December 31, ~~2023~~2024; and $62.5267 for natural gas, $9276.7485 for oil and $3921.1898 for NGL for the ~~three-month~~fiscal ~~Transition~~year ~~Period~~ ended December 31, ~~2022; and $6~~2023.41 ~~for natural gas, $90.33 for oil and $38.09 for NGL for the 12-month period ended September 30, 2022.~~ These future net cash flows based on SEC pricing rules should not be construed as the fair market value of our reserves. A market value determination would need to include many additional factors, including anticipated natural gas, oil and NGL price and production cost increases or decreases, which could affect the economic life of the properties.

Estimated Future Net Cash Flows
	12/31/2023			12/31/2022			9/30/2022
Proved Developed	$	160,071,971		$	372,320,970		$	374,063,580
Proved Undeveloped		34,828,229			89,814,060			83,098,064
Income Tax Expense		(18,437,730	)		(82,500,751	)		(107,209,614	)
Total Proved	$	176,462,470		$	379,634,279		$	349,952,030
10% Discounted Present Value of Estimated Future Net Cash Flows
	12/31/2023			12/31/2022			9/30/2022
Proved Developed	$	86,694,012		$	185,018,066		$	184,948,239
Proved Undeveloped		23,325,572			56,306,773			52,978,389
Income Tax Expense		(9,628,198	)		(43,835,204	)		(55,357,247	)
Total Proved	$	100,391,386		$	197,489,635		$	182,569,381


Estimated Future Net Cash Flows
	12/31/2024			12/31/2023
Proved Developed	$	126,968,957		$	160,071,971
Proved Undeveloped		17,418,289			34,828,229
Income Tax Expense		(7,979,227	)		(18,437,730	)
Total Proved	$	136,408,019		$	176,462,470

10% Discounted Present Value of Estimated Future Net Cash Flows
	12/31/2024			12/31/2023
Proved Developed	$	68,623,088		$	86,694,012
Proved Undeveloped		11,018,931			23,325,572
Income Tax Expense		(3,387,131	)		(9,628,198	)
Total Proved	$	76,254,888		$	100,391,386

Evaluation and Review of Reserves

The determination of reserve estimates is a function of testing and evaluating the production and development of natural gas and oil reservoirs in order to establish a production decline curve. The established production decline curves, in conjunction with natural gas and oil prices, development costs, production taxes and operating expenses, are used to estimate natural gas and oil reserve quantities and associated future net cash flows. As information is processed regarding the development of individual reservoirs, and as market conditions change, estimated reserve quantities and future net cash flows will change over time as well. Estimated reserve quantities and future net cash flows are affected by changes in product prices. These prices have varied substantially in recent years and are expected to vary substantially from current pricing in the future.

We follow the SEC’s modernized oil and natural gas reporting rules, which were effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. See Supplementary Information to the financial statements in Item 8 – “Financial Statements and Supplementary Data” for disclosures regarding our natural gas and oil reserves.

Under the SEC rules, oil and natural gas reserves are those quantities of 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 that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with the reservoir and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves, that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with the reservoir and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves, that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor, compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserve estimate, if the extraction is by means not involving a well.

Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

The independent consulting petroleum engineering firm of Cawley, Gillespie and Associates, Inc. (“CG&A”) of Fort Worth, Texas, prepared our natural gas, oil and NGL reserves estimates as of December 31, 2023, December 31, 2022, and September 30, 2022. Within CG&A, the technical person primarily responsible for preparing the estimates set forth in the Report of CG&A dated January 23, 2024, filed as Exhibit 99.1 to this Annual Report on Form 10-K, was W. Todd Brooker. Mr. Brooker has been a Petroleum Consultant for CG&A since 1992 and became President in 2017. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures, and his experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Prior to CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. He is a registered professional engineer in Texas, No. 83462, a member of the Society of Petroleum Engineers (SPE) and a member of the Society of Petroleum Evaluation Engineers (SPEE). Mr. Brooker meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

~~gas,~~Undeveloped oil and ~~NGL~~natural gas reserves ~~(including~~are ~~certain~~reserves ~~undeveloped~~of ~~reserves~~any ~~described~~category ~~above)~~that are ~~located~~expected ~~onshore~~to inbe ~~the~~recovered ~~contiguous~~from ~~United~~new ~~States.~~wells ~~All~~on ~~studies~~undrilled ~~have~~acreage ~~been~~or ~~prepared~~from inexisting ~~accordance~~wells ~~with~~where ~~regulations~~a ~~prescribed~~relatively bymajor ~~the~~expenditure ~~SEC~~is required for recompletion. ~~The~~Reserves ~~reserve~~on ~~estimates~~undrilled ~~were~~acreage ~~based~~are onlimited ~~economic~~to ~~and~~those ~~operating~~directly ~~conditions~~offsetting ~~existing~~development atspacing ~~December~~areas ~~31,~~that ~~2023,~~are ~~December~~reasonably ~~31,~~certain ~~2022~~of ~~and~~production ~~September~~when 30drilled, ~~2022.~~unless ~~Since~~evidence ~~the~~using ~~determination~~reliable ~~and~~technology ~~valuation~~exists that establishes reasonable certainty of ~~proved~~economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves isonly if a ~~function~~development ofplan ~~testing~~has ~~and~~been ~~estimation~~adopted indicating that they are scheduled to be drilled within five years, unless the ~~reserves~~specific ~~presented~~circumstances ~~are~~justify ~~expected~~a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to ~~change~~any asacreage ~~future~~for ~~information~~which ~~becomes~~an ~~available~~application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

The independent consulting petroleum engineering firm of Cawley, Gillespie and Associates, Inc. (“CG&A”) of Fort Worth, Texas, prepared our natural gas, oil and NGL reserves estimates as of December 31, 2024 and December 31, 2023. Within CG&A, the technical person primarily responsible for preparing the estimates set forth in the Report of CG&A dated January 13, 2025, filed as Exhibit 99.1 to this Annual Report on Form 10-K, was W. Todd Brooker. Mr. Brooker has been a Petroleum Consultant for CG&A since 1992 and became President in 2017. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures, and his experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Prior to CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. He is a registered professional engineer in Texas, No. 83462, a member of the Society of Petroleum Engineers (SPE) and a member of the Society of Petroleum Evaluation Engineers (SPEE). Mr. Brooker meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

All of the reserve estimates are reviewed and approved by our Vice President of Engineering. Our Vice President of Engineering and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information (such as ownership interest, gas and oil production, well test data, commodity prices, operating costs, handling fees, and development costs) for all properties to our Independent Consulting Petroleum Engineers. Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions. Our net proved natural gas, oil and NGL reserves (including certain undeveloped reserves described above) are located onshore in the contiguous United States. All studies have been prepared in accordance with regulations prescribed by the SEC. The reserve estimates were based on economic and operating conditions existing at December 31, 2024 and 2023. Since the determination and valuation of proved reserves is a function of testing and estimation, the reserves presented are expected to change as future information becomes available.

Natural Gas, Oil and NGL Production

The following table sets forth our net production of natural gas, oil and NGL for the fiscal periods indicated.


	Year Ended
	12/31/2024
	Royalty Interest		Working Interest		Total
Mcf - Natural Gas		7,290,616		679,332		7,969,948
Bbls - Oil		160,869		17,488		178,357
Bbls - NGL		84,094		49,515		133,609
Mcfe		8,760,394		1,081,352		9,841,746


	Year Ended
	12/31/2023
	Royalty Interest		Working Interest		Total
Mcf - Natural Gas		6,654,017		803,067		7,457,084
Bbls - Oil		160,116		22,800		182,916
Bbls - NGL		84,764		52,720		137,484
Mcfe		8,123,296		1,256,188		9,379,484

	Three Months Ended
	12/31/2022
	Royalty Interest		Working Interest		Total
Mcf - Natural Gas		1,303,825		365,495		1,669,320
Bbls - Oil		33,691		18,715		52,406
Bbls - NGL		20,353		18,258		38,611
Mcfe		1,628,089		587,330		2,215,419

	Year Ended
	9/30/2022
	Royalty Interest		Working Interest		Total
Mcf - Natural Gas		5,020,572		2,407,136		7,427,708
Bbls - Oil		119,518		79,017		198,535
Bbls - NGL		78,662		86,458		165,120
Mcfe		6,209,654		3,399,984		9,609,638

Average Sales Prices and Production Costs

The following tables set forth unit price and cost data for the periods indicated.

	Year Ended		~~Three~~Year ~~Months~~ Ended		~~Year Ended~~		~~Year Ended~~
Average Sales Price	12/31/~~2023~~2024		12/31/~~2022~~2023		~~9/30/2022~~		~~9/30/2021~~
Per Mcf, Natural Gas	$	2.6119	$	52.6661	$	~~6.16~~	$	~~3.13~~
Per Bbl, Oil	$	7674.7659	$	8276.5276	$	~~91.32~~	$	~~56.58~~
Per Bbl, NGL	$	2221.1895	$	2822.7718	$	~~36.11~~	$	~~23.80~~
Per Mcfe	$	3.9042	$	63.7290	$	~~7.27~~	$	~~4.16~~

	Year Ended		~~Three~~Year ~~Months~~ Ended		~~Year Ended~~		~~Year Ended~~
Average Production (lifting) Costs	12/31/~~2023~~2024		12/31/~~2022~~2023		~~9/30/2022~~		~~9/30/2021~~
(Per Total Mcfe)
Well Operating Costs (1)	$	0.5658	$	10.1056	$	~~1.02~~	$	~~1.08~~
Production Taxes (2)		0.2017		0.3020		~~0.35~~		~~0.24~~
	$	0.7675	$	10.4076	$	~~1.37~~	$	~~1.32~~

(1)

Includes actual well operating costs, compression, handling and marketing fees paid on natural gas sales and other minor expenses associated with well operations.

(2)

Includes production and ad valorem taxes.

In fiscal year ended December 31, ~~2023~~2024, approximately 8689% of our natural gas, oil and NGL revenue was generated from royalty payments received on our mineral acreage. Royalty interests bear no share of the field operating costs on those producing wells but do bear a share of the handling fees (primarily gathering and transportation).

Gross and Net Productive Wells and Developed Acres

The following table sets forth our gross and net productive natural gas and oil wells as of December 31, ~~2023~~2024. We own either working interests, royalty interests or both in these wells. We do not operate any wells.

	Gross Working Interest Only Wells		Net Working Interest Only Wells		Gross Working Interest and Royalty Interest Wells		Net Working Interest and Royalty Interest Wells		Gross Royalty Only Wells		Net Royalty Only Wells		Total Gross Wells
Natural Gas		5550		2.1503		~~294~~281		1110.0961		4,~~303~~407		28.2938		4,~~652~~738
Oil		2220		1.4328		7978		2.3325		2,~~020~~122		1110.1485		2,~~121~~220
Total		7770		3.5831		~~373~~359		1312.4286		6,~~323~~529		39.4323		6,~~773~~958

Our average interest in royalty interest only wells is 0.62601%. Our average interest in working interest wells is 3.75226% working interest and 3.787699% net revenue interest.

Information on multiple completions is not available from our records, but the number is not believed to be significant. With regard to Gross Royalty Only Wells, some of these wells are in multi-well unitized fields. In such cases, our ownership in each unitized field is counted as one gross well, as we do not have access to the actual well count in all of these unitized fields.

As of December 31, ~~2023~~2024, we owned ~~635~~641,~~744~~677 gross (6869,~~560~~136 net) developed mineral acres and leased ~~167~~189,~~768~~106 gross (13,~~293~~290 net) developed acres.

Undeveloped Acreage

As of December 31, ~~2023~~2024, we owned 1,~~109~~097,~~193~~271 gross and ~~172~~170,~~091~~773 net undeveloped mineral acres. All of our leases are held by production (“HBP”), and we do not have any leases on undeveloped acres.

Drilling Activity

The following table sets forth our net productive development, exploratory and purchased wells and net dry development, exploratory and purchased wells in which we had either a working interest, a royalty interest or both were drilled and completed during the periods indicated.

	Net Productive		Net Productive		Net Dry
	Working InterestWells		Royalty InterestWells		Working InterestWells
Development Wells
Year ended December 31, 2023		-		0.995776		-
Years ended:
Three months ended December 31, 2022		-		0.232461		-
December 31, 2024		-		1.110635		-
Year ended September 30, 2022		-		0.986062		-
December 31, 2023		-		0.995776		-
Exploratory Wells
Year ended December 31, 2023		-		-		-
Years ended:
Three months ended December 31, 2022		-		-		-
December 31, 2024		-		-		-
Year ended September 30, 2022		-		-		-
December 31, 2023		-		-		-
Purchased Wells
Year ended December 31, 2023		-		1.255061		-
Years ended:
Three months ended December 31, 2022		-		0.310160		-
December 31, 2024		-		0.223966		-
Year ended September 30, 2022		-		1.108386		-
December 31, 2023		-		1.255061		-

Present Activities

The following table sets forth our gross and net natural gas and oil wells being drilled or waiting on completion as of December 31, ~~2023~~2024, in which we own either a working interest, a royalty interest or both. These wells were not producing at December 31, ~~2023~~2024.

	Gross Working Interest Wells		Net Working Interest Wells		Gross Royalty Only Wells		Total Net Royalty Interest Wells
Natural Gas		-		-		7176		0.2635
Oil		-		-		9774		0.5925
Total		-		-		~~168~~150		0.8560

Other Facilities

We have an office lease on 8,776 square feet of office space in Oklahoma City, Oklahoma, which is scheduled to expire on August 31, 2027, and an office lease on 3,164 square feet of office space in Fort Worth, Texas, which is scheduled to expire on August 31, 2027.

ITEM 3. Legal Proceedings

In the ordinary course of business, we may be, from time to time, a claimant or a defendant in various legal proceedings. There were no material pending legal proceedings involving the Company on December 31, ~~2023~~2024, or at the date of this Annual Report.

ITEM 4. Mine Safety Disclosures

Not applicable.

PART II

ITEM 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for our Common Stock

Our Common Stock is listed on the New York Stock Exchange (NYSE) under the trading symbol “PHX.”

As of December 31, ~~2023~~2024, we were authorized to issue an aggregate of 5475,000,~~500~~000 shares of Common Stock.

Performance Graph

The following graph compares the 5-year cumulative total return provided stockholders on our Common Stock relative to the cumulative total returns of the S&P Smallcap 600 Index and the S&P Oil & Gas Exploration & Production Index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our Common Stock and in each of the indexes on December 31, ~~2018~~2019, and the relative performance of such investment is tracked through and including December 31, ~~2023~~2024. This table is not intended to forecast future performance of our Common Stock.

Record Holders

At March 5, 2024, there were 1,~~273~~238 holders of record of our Common Stock and approximately 6,~~357~~062 beneficial owners.

Dividends

29During the past three years, we have paid quarterly dividends ranging from $0.015 per share to $0.04 per share on our Common Stock. Approval by our Board is required before the declaration and payment of any dividends.

During the past three years, we have paid quarterly dividends ranging from $0.01 per share to $0.03 per share on our Common Stock. Approval by our Board is required before the declaration and payment of any dividends.

Historically, we have paid dividends to our stockholders on a quarterly basis. While we anticipate we will continue to pay dividends on our Common Stock, the payment and amount of future cash dividends will depend upon, among other things, financial condition, funds from operations, the level of capital and development expenditures, future business prospects, contractual restrictions and any other factors considered relevant by the Board. Our Credit Agreement sets limits on dividend payments and stock repurchases if those payments would cause the Leverage Ratio (as defined in the Credit Agreement) to go above 2.50 to 1.0 or the Available Commitment (as defined in the Credit Agreement) to go below ten percent of the Borrowing Base (as defined in the Credit Agreement).

Purchases of Equity Securities by the Company

Following approval by our stockholders of our 2010 Restricted Stock Plan (“2010 Stock Plan”) in March 2010, as amended in May 2018, our Board approved our repurchase program which, as amended, authorizes management to repurchase up to $1.5 million of our Common Stock at our discretion. The repurchase program has an evergreen provision which authorizes the repurchase of an additional $1.5 million of our Common Stock when the previous amount is utilized. As part of the amendment, the number of shares allowed to be purchased by us under the repurchase program is no longer capped at an amount equal to the aggregate number of shares of Common Stock (i) awarded pursuant to our 2010 Stock Plan, as amended, (ii) contributed by us to the PHX Minerals Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan (the “ESOP”), and (iii) credited to the accounts of directors pursuant to our Deferred Compensation Plan for Non-Employee Directors.

During the quarter ended December 31, ~~2023~~2024, we repurchased ~~120~~212,~~700~~391 shares of our Common Stock. The table below sets forth the information with respect to repurchase of our Common Stock during the quarter ended December 31, ~~2023~~2024.

Period	Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet be Purchased Under the Repurchase Program
October 1 – October 31	-	N/A	–	$	1,500,000
November 1 – November 30	-	N/A		$	1,500,000
December 1 – December 31	~~120~~212,~~700~~391(1)	$3.3379	–	$	1,500,000
Total	~~120~~212,~~939~~391	$3.3379	–	$	1,500,000

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

ITEM 6. Reserved

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this Annual Report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report. The following discussion and analysis generally discuss fiscal year ~~2023~~2024 and ~~the~~2023 ~~year ended December 31, 2022,~~ items and year-to-year comparisons between December 31, ~~2023~~2024 and December 31, ~~2022~~2023. Discussions of ~~2022~~2023 items and year-to-year comparisons between fiscal year ~~2022~~2023 and ~~2021~~2022 that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended ~~September 30, 2022. Discussions of period-to-period comparisons between the three-month periods ended~~ December 31, 2022 and 2021 that are not included in this Form 10-K can be found in Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Transition Report on Form 10-Q for the period ended December 31, 2022, which is incorporated herein by reference2023.

Business Overview

We are focused on perpetual natural gas and oil mineral ownership in resource plays in the United States. Prior to a strategy change in 2019, we participated with a working interest on some of our mineral and leasehold acreage and as a result, we still have legacy interests in leasehold acreage and non-operated interests in natural gas and oil properties. Effective October 8, 2020, our corporate name was changed to PHX Minerals Inc. to more accurately reflect our business strategy.

Our results of operations are dependent primarily upon the Company’s: existing reserve quantities; costs associated with acquiring, exploring for and developing new reserves; production quantities and related production costs; and natural gas, oil and NGL sales prices. The majority of our revenues is derived from royalties granted from the production and sale of natural gas, oil and NGL, and the remaining portion of our revenues is primarily derived from the production and sale of natural gas, oil and NGL on our working interests.

Strategic Focus on Mineral Ownership

During fiscal year 2019, we made the strategic decision to focus on perpetual natural gas and oil mineral ownership and growth through mineral acquisitions and the development of our significant mineral acreage inventory in our core focus areas. In accordance with this decision, we ceased taking working interest positions on our mineral and leasehold acreage going forward. During 2020 through ~~2023~~2024, we did not participate with a working interest in the drilling of any new wells. We believe that our strategy to focus on mineral ownership is the best path to giving our stockholders the greatest risk-weighted returns on their investments.

Market Conditions and Commodity Prices

Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our production volumes or revenues.

Our working interest and royalty revenues may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our operators.

Production and Operational Update

Our natural gas production for the fiscal year 2024 increased 7%, while oil, and NGL production for the fiscal year ~~2023~~2024 decreased 12%, ~~10%,~~ and 143%, respectively, from that of ~~the~~fiscal year ~~ended December 31, 2022~~2023. The ~~2023~~2024 fiscal year’s lower natural gas, oil and NGL prices (as discussed below) and the overall production changes noted above resulted in a 498% decrease in revenues from the sale of natural gas, oil and NGL in fiscal ~~2023~~2024.

Our proved natural gas, oil and NGL reserves decreased to 7163.27 Bcfe in ~~2023~~2024, compared to 7971.72 Bcfe in ~~the year ended December 31~~2023, ~~2022,~~ a decrease of approximately 87.5 Bcfe, or 11%. The decrease was primarily due to ~~the~~pricing ~~sale~~revisions ofand ~~10.2 Bcfe proved developed~~production, ~~consisting~~which ~~predominately~~was ofnot ~~working~~entirely ~~interest~~offset ~~properties~~by inadditions ~~the~~due ~~Eagle~~to ~~Ford~~reduced ~~Shale~~permitting ~~play~~activity in ~~Texas and~~ the ~~Arkoma~~Haynesville ~~Stack~~shale ~~play~~as ~~and~~a ~~Western~~result ~~Anadarko~~of ~~Basin~~lower ingas ~~Oklahoma~~prices, ~~coupled with production, pricing revisions,~~ and, to a far lesser extent, performance revisions. This was partially offset by the extensions of 85.80 Bcfe and acquisitions of 72.75 Bcfe, predominately of royalty interest properties in the active drilling programs of the Haynesville Shale play in east Texas and western Louisiana and the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma.

~~active~~As ~~drilling programs~~ of ~~the~~December ~~Haynesville~~31, ~~Shale~~2024, ~~play~~we inowned ~~east~~an ~~Texas~~average ~~and~~0.4% ~~western~~net ~~Louisiana~~revenue ~~and~~interest, ~~the~~consisting ~~Mississippi~~of ~~and~~all ~~Woodford~~royalty ~~Shale~~interest, ~~intervals~~ in ~~the~~150 ~~SCOOP~~wells ~~play~~that inwere ~~the~~being ~~Ardmore~~drilled ~~basin~~or ofawaiting ~~Oklahoma~~completion.

As of December 31, 2023, we owned an average 0.5% net revenue interest, consisting of all royalty interest, in 168 wells that were being drilled or awaiting completion.

Results of Operations

The following table reflects certain operating data for fiscal ~~2023~~2024 and the year ended December 31, ~~2022~~2023:

	For the Year Ended
	For the Year Ended December 31,
	December 31,	December 31,	Percent
			Percent
	2023	2022	Incr. or (Decr.)
	2024	2023	Incr. or (Decr.)
Production:
Natural Gas (Mcf)	7,~~457~~969,~~084~~948	7,~~522~~457,~~763~~084	(17%)
Oil (Bbls)	~~182~~178,~~916~~357	~~202~~182,~~867~~916	(102%)
NGL (Bbls)	~~137~~133,~~484~~609	~~159~~137,~~475~~484	(143%)
Mcfe	9,~~379~~841,~~484~~746	9,~~696~~379,~~809~~484	(35%)
Average Sales Price:
Natural Gas (per Mcf)	$2.6119	$62.1961	(5816%)
Oil (per Bbl)	$7674.7659	$9376.0676	(183%)
NGL (per Bbl)	$2221.1895	$3522.4418	(371%)
Mcfe	$3.9042	$73.3390	(4712%)

Production by quarter for the years ended December 31, ~~2023~~2024 and ~~2022~~2023 was as follows (Mcfe):


	For the Year Ended December 31, 2024
	Royalty Interest		Working Interest		Total
First quarter		1,857,147		259,629		2,116,776
Second quarter		2,709,090		258,689		2,967,779
Third quarter		2,097,722		280,900		2,378,622
Fourth quarter		2,096,435		282,134		2,378,569
Total		8,760,394		1,081,352		9,841,746


	For the Year Ended December 31, 2023
	Royalty Interest		Working Interest		Total
First quarter		2,093,722		388,554		2,482,276
Second quarter		2,010,036		294,077		2,304,113
Third quarter		2,073,342		275,036		2,348,378
Fourth quarter		1,946,196		298,521		2,244,717
Total		8,123,296		1,256,188		9,379,484

	For the Year Ended December 31, 2022
	Royalty Interest		Working Interest		Total
First quarter		1,547,609		912,433		2,460,042
Second quarter		1,595,323		834,437		2,429,760
Third quarter		1,841,502		750,086		2,591,588
Fourth quarter		1,628,089		587,330		2,215,419
Total		6,612,523		3,084,286		9,696,809

Fiscal Year 2024 Compared to Fiscal Year 2023

Fiscal Year 2023 Compared to Year Ended December 31, 2022

Change in Fiscal Year End

On December 9, 2022, the Company’s Board approved a change in fiscal year from the twelve months beginning October 1st and ending September 30th to the twelve months beginning January 1st and ending December 31st. Accordingly, the Company reported a transition period that ran from October 1, 2022 through December 31, 2022. We have presented unaudited pro-forma statements of income for the year ended December 31, 2022 (“Calendar 2022”). We have presented Calendar 2022 as a comparison to our results for fiscal 2023 as we believe this comparison is more meaningful to a reader’s understanding of our fiscal 2023 results of operations than a comparison to fiscal 2022. The pro-forma statements of income was derived as follows (in millions):

				Plus: Three			Less: Three
				Months Ended			Months Ended
	Fiscal 2022			December 31, 2022(1)			December 31, 2021(2)		Calendar 2022
							(Unaudited)		(Unaudited)
Revenues:
Natural gas, oil and NGL sales	$	69,860,631		$	14,888,674		$	13,687,164	$	71,062,141
Lease bonuses and rental income		467,502			34,482			78,915	$	423,069
Gains (losses) on derivative contracts		(16,833,078	)		3,347,002			2,836,168	$	(16,322,244	)
		53,495,055			18,270,158			16,602,247		55,162,966
Costs and expenses:
Lease operating expenses		3,945,706			977,165			1,196,836		3,726,035
Transportation, gathering and marketing		5,890,390			1,455,260			1,213,604		6,132,046
Production and ad valorem taxes		3,332,581			656,764			738,122		3,251,223
Depreciation, depletion and amortization		7,278,118			1,802,114			1,583,760		7,496,472
Provision for impairment		14,565			6,100,696			5,585		6,109,676
Interest expense		1,164,992			637,698			176,719		1,625,971
General and administrative		11,500,594			3,137,401			2,095,557		12,542,438
Losses (gains) on asset sales and other		(4,243,163	)		(824,073	)		2,147,815		(7,215,051	)
		28,883,783			13,943,025			9,157,998		33,668,810
Income before provision (benefit) for income taxes		24,611,272			4,327,133			7,444,249		21,494,156
Provision for income taxes		4,202,000			981,000			762,000		4,421,000
Net income	$	20,409,272		$	3,346,133		$	6,682,249	$	17,073,156

(1) As set forth in our Transition Report on Form 10-QT for the three-month period ended December 31, 2022. Certain prior period amounts have been reclassified to conform to current period presentation.

(2) As set forth in our Quarterly Report on Form 10-Q for the three-month period ended December 31, 2021. Certain prior period amounts have been reclassified to conform to current period presentation.

Overview

Revenues decreased in fiscal ~~2023~~2024 primarily due to lower natural gas, oil and NGL sales, ~~partially~~and ~~offset~~a bydecrease ~~an increase~~ in gains on derivative contracts. We recorded net income of $132,~~920~~321,~~800~~866, or $0.3906 per diluted share, in fiscal ~~2023~~2024, compared to net income of $1713,~~073~~920,~~156~~800, or $0.4839 per diluted share, in ~~Calendar~~fiscal ~~2022~~2023 . Expenses ~~decreased~~increased in fiscal ~~2023~~2024, primarily the result of ~~decreases~~increases in ~~impairment~~DD&A, ~~LOE, production taxes,~~ transportation, gathering and marketing expenses, and ~~G&A~~interest expense, partially offset by ~~increases~~decreases in ~~DD&A~~LOE, ~~and~~production ~~interest~~taxes, ~~expense~~and G&A.

Natural Gas, Oil and NGL Sales

	For the Year Ended December 31,
					Percent
	2023		2022		Incr. or (Decr.)
	2024		2023		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	3633,~~536~~690,~~285~~652	$	7136,~~062~~536,~~141~~285	(498%)

~~The decrease was due to decreased natural gas, oil and NGL prices of 58%, 18% and 37%, respectively, combined with lower natural gas, oil and NGL volumes of 1%, 10% and 14%, respectively.~~ 33

The decrease ~~in natural gas production~~ was ~~primarily~~ due to ~~divestiture~~decreased ofnatural ~~working~~gas, ~~interest~~oil ~~assets in the Fayetteville Shale during 2022~~ and ~~Arkoma~~NGL ~~Stack~~prices ~~during~~of ~~2023~~16%, ~~slightly~~3% ~~offset by acquisitions~~ and ~~new~~1%, ~~drilling~~respectively, incombined ~~the~~with ~~Haynesville~~lower ~~Shale. The decrease in~~ oil ~~production was a result of divestiture of working interest assets in the Eagle Ford Shale, partially offset by new drilling~~ and ~~acquisitions in the SCOOP and Bakken Shale. The decrease in~~ NGL ~~production~~volumes ~~is primarily attributable to the divestiture~~ of ~~working~~2% ~~interest assets in the Eagle Ford Shale~~ and ~~Arkoma~~3%, ~~Stack as well as natural decline in high interest~~respectively, ~~liquids rich wells in the STACK. This was~~ partially offset by ~~new~~higher ~~wells~~natural ingas ~~the~~volumes ~~Bakken~~of ~~Shale~~7%.

The increase in natural gas production was primarily due from new wells in the Haynesville Shale and SCOOP plays coming online. The decrease in oil production was a result of fewer new wells coming online in the Bakken compared to 2023 and the divestiture of working interest assets in the Eagle Ford Shale at the beginning of 2023. The decrease in NGL production is primarily attributable to the natural decline in high interest, liquids rich wells in the STACK.

Given our strategic decision to cease participating with working interests, we plan to offset the natural decline of our existing production base by the development of our current inventory of mineral acreage and through acquisitions of additional mineral interests.

Gains (Losses) on Derivative Contracts

	For the Year Ended December 31,
							Percent
	2023			2022			Incr. or (Decr.)
	2024			2023			Incr. or (Decr.)
Cash received (paid) on settled derivative contracts:
Cash received (paid) on settled derivative contracts, net(1)	$	24,~~557~~297,~~058~~603		$	~~(15~~2,~~737~~557,~~268~~058	)	~~116~~68%
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	4(3,~~302~~997,~~531~~995	)	$	~~(584~~4,~~976~~302,531	)	~~836~~(193%)
Gains (losses) on derivative contracts, net	$	6299,~~859,589~~608		$	~~(16~~6,~~322~~859,~~244~~589	)	~~142~~(96%)
	As of December 31,
	2023			2022
	2024			2023
Fair value of derivative contracts
Net asset (net liability)	$	3(714,~~283,587~~408	)	$	(13,~~392~~283,~~689~~587	)	~~336~~(122%)

(1) Excludes $373,745 ~~and $5,738,164, respectively,~~ of cash paid to settle off-market derivative contracts that are not reflected on the Statements of Income for the ~~years~~year ended December 31, 2023 ~~and 2022~~. See Note 12 to the financial statements in Item 8 – “Financial Statements and Supplementary Data” for further explanation on off-market derivative contracts.

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 December 31, ~~2023~~2024 pricing relative to the strike price on open derivative contracts.

Our natural gas and oil fixed price swaps in place at December 31, ~~2023~~2024 had expiration dates through ~~June~~September ~~2025~~2026. We utilize derivative contracts for the purpose of protecting our cash flow and return on investments.

Lease Operating Expenses (LOE)

	For the Year Ended December 31,
					Percent
	2023		2022		Incr. or (Decr.)
	2024		2023		Incr. or (Decr.)
Lease operating expenses	$	1,~~598~~228,~~944~~813	$	31,~~726~~598,~~035~~944	(5723%)
Lease operating expenses per working interest MCFE	$	1.2714	$	1.2127	5(10%)
Lease operating expenses per total MCFE	$	0.1712	$	0.3817	(5529%)

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 $2370,~~127~~131,~~091,~~ or 5723%, in fiscal ~~2023~~2024 compared to ~~Calendar~~fiscal ~~2022~~2023. The decrease in LOE was principally the result of the divestiture of working interest properties, ~~partially~~in ~~offset~~January ~~by cost inflation associated with field operating activities~~2023.

Transportation, Gathering and Marketing

	For the Year Ended December 31,
					Percent
	2023		2022		Incr. or (Decr.)
Transportation, gathering and marketing	$	3,674,832	$	6,132,046	(40%)
Transportation, gathering and marketing per MCFE	$	0.39	$	0.63	(38%)

Transportation, gathering and marketing decreased $2,457,214, or 40%, in fiscal 2023 compared to Calendar 2022. This decrease in costs was partially due to decreased production in 2023. The decrease in rate per Mcfe was primarily due to the divestiture of assets with higher associated transportation, gathering and marketing rates and the increase in natural gas sales in fields with lower associated transportation, gathering and marketing rates. Natural gas sales bear the large majority of our transportation, gathering and marketing fees.


	For the Year Ended December 31,
					Percent
	2024		2023		Incr. or (Decr.)
Transportation, gathering and marketing	$	4,513,381	$	3,674,832	23%
Transportation, gathering and marketing per MCFE	$	0.46	$	0.39	18%

35Transportation, gathering and marketing increased $838,549, or 23%, in fiscal 2024 compared to fiscal 2023. This increase in costs was partially due to increased production in 2024, and specifically due to increases in natural gas wells with higher than average deduct rates in the Haynesville. Natural gas sales bear the large majority of our transportation, gathering and marketing fees.

Production Taxes

	For the Year Ended December 31,
							Percent
	2023			2022			Incr. or (Decr.)
	2024			2023			Incr. or (Decr.)
Production and ad valorem taxes	$	1,~~881~~703,~~737~~305		$	31,~~251~~881,~~223~~737		(429%)
Production and ad valorem taxes as % of sales		5.21	%		45.62	%	13(2%)

Production taxes are paid on produced natural gas and oil based on a percentage of revenues from products sold at both fixed and variable rates or a fixed rate per unit produced established by federal, state or local taxing authorities. Production taxes decreased $1178,~~369~~432,~~486,~~ or 429%, in fiscal ~~2023~~2024 compared to ~~Calendar~~fiscal ~~2022~~2023. The decrease in amount was primarily the result of ~~decreased~~an 8% decrease in natural gas, oil and NGL sales ~~of $34,525,856~~ during fiscal ~~2023~~2024.

Depreciation, Depletion and Amortization (DD&A)

	For the Year Ended December 31,
					Percent
	2023		2022		Incr. or (Decr.)
	2024		2023		Incr. or (Decr.)
Depreciation, depletion and amortization	$	89,~~566~~606,~~185~~444	$	78,~~496~~566,~~472~~185	1412%
Depreciation, depletion and amortization per MCFE	$	0.9198	$	0.7791	188%

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 $1,~~069~~040,~~713~~259, or 1412%, in fiscal ~~2023~~2024 compared to ~~Calendar~~fiscal ~~2022~~2023, of which $1619,~~314,059~~613 of the increase resulted from a $0.1407 increase in the DD&A rate per Mcfe, ~~partially~~and ~~offset~~$420,646 ~~by a decrease~~ of ~~$244,346~~the ~~resulting~~increase resulted from production ~~decreasing~~increasing 35% in fiscal ~~2023~~2024. The purchase of additional minerals, conversions of overriding royalty interest and a large transfer of non-producing minerals, which are amortized over 33 years, to producing minerals, which are amortized over 20 years, were the biggest contributions to the increase in fiscal ~~2023~~2024.

Provision for Impairment

During fiscal ~~2023~~2024 impairment of $3824,~~533~~061 was related to ~~working~~one ~~interest wells in which we assigned our interests to the operator~~field. ~~During~~These ~~Calendar~~assets ~~2022,~~were wewritten ~~wrote~~ down ~~certain~~to ~~held~~their ~~for~~fair ~~sale~~market ~~assets~~value ~~associated~~as ~~with~~required ~~the~~by ~~pending~~GAAP. ~~sale~~The ofremaining ~~non-operated~~$28,612 ~~working~~was ~~interest~~related ~~wellbores~~ to ~~their~~leasehold ~~fair~~that ~~value,~~expired. ~~recording~~During afiscal $62023,~~100,696~~ impairment ~~expense.~~of ~~The remaining~~ $838,~~980~~533 inwas ~~Calendar 2022~~ related to working interest wells in which we assigned our interests to the operator.

Interest Expense

	For the Year Ended December 31,
					Percent
	2023		2022		Incr. or (Decr.)
	2024		2023		Incr. or (Decr.)
Interest expense	$	2,~~362~~563,~~393~~268	$	12,~~625~~362,~~971~~393	459%
Weighted average debt outstanding	$	2729,~~754~~637,~~247~~295	$	2827,~~972~~754,~~877~~247	(47%)

The increase was due to a higher average debt balance and an increase in the average interest rate in fiscal ~~2023~~2024 compared to ~~Calendar~~fiscal ~~2022~~2023.

General and Administrative Costs (G&A)

	For the Year Ended December 31,
					Percent
	2023		2022		Incr. or (Decr.)
	2024		2023		Incr. or (Decr.)
General and administrative costs	$	11,~~970~~670,~~182~~328	$	1211,~~542~~970,~~438~~182	(53%)

36G&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 fiscal 2024 decreased $299,854 as compared to fiscal 2023. The decrease was primarily due to decreases in professional services, including legal, during the year.

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 fiscal 2023 decreased $572,256 as compared to Calendar 2022. The decrease was primarily due to decreases in professional services and restricted stock expense during the year.

Losses (Gains) on Asset Sales and Other

	For the Year Ended December 31,
							Percent
	2023			2022			Incr. or (Decr.)
	2024			2023			Incr. or (Decr.)
Losses (gains) on asset sales and other	$	(483,~~285,170~~799	)	$	(74,~~215~~285,~~051~~170	)	41102%

The decrease in gain on asset sales and other is primarily related to divestitures during ~~Calendar~~fiscal ~~2022~~2023 that did not occur in 2024.

Provision for Income Taxes

	For the Year Ended December 31,
							Percent
	2023			2022			Incr. or (Decr.)
	2024			2023			Incr. or (Decr.)
Provision for income taxes	$	4827,~~735,460~~187		$	4,~~421~~735,~~000~~460		7(83%)
Effective tax rate		2526	%		2125	%	194%

Provision for income taxes changed $~~314~~3,~~460~~908,273, from a $4,~~421~~735,~~000~~460 provision in ~~Calendar~~fiscal ~~2022~~2023 to a $4827,~~735,460~~187 provision in the year ended December 31, ~~2023~~2024. The change in provision for income taxes resulted primarily due to ana ~~increase~~decrease in ~~state income tax expense and non~~pre-~~deductible compensation. Due to the direct allocation of income required by Oklahoma and disallowance of net operating loss carryforward by Texas, there was an increase in the state income~~ tax ~~expense in comparison to prior year. Additionally, there was non-deductible compensation in the current year that caused an overall increase to~~ income ~~tax expense~~.

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

Liquidity and Capital Resources

We had positive working capital (current assets less current liabilities excluding current derivatives) of $56,~~029~~637,~~698~~524 at December 31, ~~2023~~2024, compared to positive working capital of $145,~~554~~029,~~429~~698 at December 31, ~~2022 and $14,533,225 at September 30, 2022, respectively~~2023.

Liquidity

Cash and cash equivalents were $~~806~~2,~~254~~242,102 as of December 31, ~~2023~~2024, compared to $2806,~~115,652~~254 at December 31, ~~2022~~2023, aan ~~decrease~~increase of $1,~~309~~435,~~398~~848. Cash flows for the years ended December 31, ~~2023~~2024 and December 31, ~~2022~~2023, are summarized as follows:

	For the Year Ended
	For the Year Ended December 31,
Net cash provided (used) by:	~~December 31,~~			~~December 31,~~
	2023			2022			Change
	2024			2023			Change
Operating activities	$	2418,~~171~~077,~~139~~853		$	3924,~~035~~171,~~474~~139		$	(146,~~864~~093,~~335~~286	)
Investing activities		(207,~~447~~357,~~305~~395	)		(3620,~~243~~447,~~406~~305	)		1513,~~796~~089,~~101~~910
Financing activities		(59,~~033~~284,~~232~~610	)		(25,~~235~~033,~~766~~232	)		(24,~~797~~251,~~466~~378	)
Increase (decrease) in cash and cash equivalents	$	(1,~~309~~435,~~398~~848	)	$	~~556~~(1,~~302~~309,398	)	$	(12,~~865~~745,~~700~~246	)

3736

Operating activities:

Net cash provided by operating activities decreased $146,~~864~~093,~~335~~286 during the year ended December 31, ~~2023~~2024, as compared to the year ended December 31, ~~2022~~2023, primarily as a result of the following:

•

receipts of natural gas, oil and NGL sales (net of production taxes and gathering, transportation and marketing costs) and other decreased $239,~~647~~292,~~052~~678;

•

increased payments for interest expense of $1205,~~014,896~~728; and

•

~~increased~~decreased ~~payments~~lease ~~for~~bonus ~~G&A~~receipts ~~and other expense~~ of $~~324~~616,~~188;~~524.

partially offset by:

•

increased net receipts on derivative contracts of $61,~~164~~740,~~147~~545;

•

decreased field operating expenses of $2321,~~268,135~~517;

•

decreased income tax payments of $1,~~136~~145,~~425~~298; and

•

~~increased~~decreased ~~lease~~payments ~~bonus~~for ~~receipts~~G&A and other expense of $~~553~~814,~~094~~284.

Investing activities:

Net cash used in investing activities decreased $1513,~~796~~089,~~101~~910 during the year ended December 31, ~~2023~~2024, as compared to December 31, ~~2022~~2023, primarily as a result of the following:

•

lower acquisition activity decreased our expenditures by $1621,~~644~~938,~~907~~533; and

•

lower workover activity during fiscal ~~2023~~2024 decreased our capital expenditures by $~~121~~238,~~082~~404;

partially offset by:

•

~~decreased~~lower ~~deposits~~proceeds onreceived ~~held~~from ~~for~~the sale of assets of $~~815~~9,~~000; and~~087,027.

lower proceeds received from the sale of assets of $154,888.

Financing activities:

Net cash used in financing activities increased $24,~~797~~251,~~466~~378 during the year ended December 31, ~~2023~~2024, as compared to December 31, ~~2022~~2023, primarily as a result of the following:

•

~~decreased~~increased net ~~borrowings~~payments on debt of $132,~~850~~700,000;

•

~~decreased~~increased ~~net~~dividend ~~proceeds~~payments ~~from~~by ~~equity issuance of~~ $51,~~039~~709,~~045~~181 during 2024; and

•

increased ~~dividend~~purchases ~~payments~~of treasury stock by $~~868~~402,~~213 during 2023~~359; ~~and~~

increased purchases of treasury stock by $348,389;

partially offset by:

•

decreased net cash payments on off-market derivative contracts of $17560,~~308,181~~162.

Capital Resources

We had no capital expenditures to drill and complete wells in the year ended December 31, ~~2023,~~2024 as a result of our strategy to cease participating in new wells with a working interest at the end of fiscal year 2019. We currently have no remaining commitments that would require significant capital to drill and complete wells.

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

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

Quarter Ended	Net royalty acres (1)(2)	~~Cash~~Total Purchase Price (1)	~~Total~~Area ~~Purchase~~of ~~Price (1)(3)~~Interest	~~Area of Interest~~
December 31, 2023
December 31, 2024
	325	$4.3 million	$4.3 million	Haynesville / SCOOP
	363	$2.5 million	Haynesville
September 30, 2023
September 30, 2024
	974	$13.4 million	$13.4 million	Haynesville / SCOOP
	325	$3.0 million	Haynesville / SCOOP
June 30, 2023
June 30, 2024
	151	$1.8 million	$1.8 million	Haynesville / SCOOP
	96	$0.9 million	Haynesville / SCOOP
March 31, 2023
March 31, 2024
	912	$10.8 million	$10.8 million	Haynesville / SCOOP
	146	$1.4 million	SCOOP
December 31, 2022
December 31, 2023
	1,256	$14.6 million	$14.6 million	Haynesville / SCOOP
	325	$4.3 million	Haynesville / SCOOP

(1) Excludes subsequent closing adjustments and insignificant acquisitions.

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

~~(3)~~We ~~Table~~received ~~excludes~~lease ~~transaction~~bonus ~~costs~~payments ofduring ~~$0.3~~fiscal ~~million~~2024 ~~and~~totaling approximately $0.16 million,. ~~respectively~~Looking forward, ~~that~~the ~~were~~cash ~~capitalized~~flow ~~during~~from bonus payments associated with the ~~year~~leasing ~~ended~~of ~~December~~drilling ~~31,~~rights ~~2023~~on our mineral acreage is difficult to project and ~~the~~management ~~three~~plans ~~months~~to ~~ended~~continue ~~December~~to ~~31,~~actively ~~2022~~pursue leasing opportunities.

We received lease bonus payments during fiscal 2023 totaling approximately $1.2 million. Looking forward, the cash flow from bonus payments associated with the leasing of drilling rights on our mineral acreage is difficult to project and 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 12 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for a complete list of our outstanding derivative contracts.

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

	Year ended
	December 31, 2023
	December 31, 2024
Cash provided by operating activities	$	2418,~~171~~077,~~139~~853
Cash provided (used) by:
Capital expenditures - acquisitions		(297,~~735~~796,~~516~~983	)
Capital expenditures - legacy working interest wells and furniture and fixtures		(~~325~~87,~~983~~579	)
Quarterly dividends		(35,~~520~~229,~~366~~547	)
Treasury stock purchases		(~~402~~805,~~704~~063	)
Net borrowings (payments) on credit facility		(~~550~~3,250,000	)
Net proceeds from sales of assets		9527,~~614,194~~167
Cash receipts from (payments on) off-market derivative contracts		(560,162	)
Net cash used		(16,642,005	)
Net cash used		(25,480,537	)
Net increase (decrease) in cash	$	1,435,848
Net increase (decrease) in cash	$	(1,309,398	)

Outstanding borrowings under our Credit Facility at December 31, ~~2023~~2024 were $3229,~~750~~500,000.

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. We had availability of $1720,~~250~~500,000 at December 31, ~~2023~~2024 under our Credit Facility and were in compliance with our debt covenants (current ratio, debt to trailing 12-month EBITDAX (as defined in the Credit Agreement) and restricted payments limited by leverage ratio). The debt covenants in the Credit Agreement limit the maximum ratio of our debt to EBITDAX to no more than 3.5:1.

We have our Credit Facility with certain lenders and Independent Bank, as Administrative Agent and Letter of Credit Issuer, which provides for up to $100 million in borrowings from time to time and is subject to an at least semi-annual borrowing base determination. The borrowing base at December 31, ~~2023,~~2024 was $50,000,000 and all obligations under the Credit Agreement are secured, subject to permitted liens and other exceptions, by a first-priority security interest on substantially all of our personal property and at least 75% of the total value of our proved, developed and producing Oil and Gas Properties. The revolving loan matures on September 1, 2025. Borrowings under the revolving loan are due at maturity. Interest on the Credit Agreement is calculated based on either (a) the Secured Overnight Financing Rate (“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. At December 31, 2023, the effective rate was 8.74%. 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 Annual Report 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, we believe we have sufficient liquidity to fund our ongoing operations.38

OnSeptember ~~August 25~~1, ~~2021,~~2028. weBorrowings ~~entered~~under ~~into~~the anrevolving ~~At-The-Market~~loan ~~Equity~~are ~~Offering~~due ~~Sales~~at maturity. Interest on the Credit Agreement 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 ~~“ATM~~greater ~~Agreement”~~of (1) ~~with~~the ~~Stifel,~~Prime ~~Nicolaus~~Rate &in ~~Company,~~effect ~~Incorporated~~for such day, or (2) the overnight cost of federal funds as ~~sales~~announced ~~agent~~by ~~and/or~~the ~~principal~~US Federal Reserve System in effect on such day plus one-half of one percent (~~“Stifel”~~0.50%), ~~pursuant~~plus, toin ~~which~~each wecase, ~~may~~an ~~offer~~applicable ~~and~~margin ~~sell,~~ranging from ~~time~~1.750% to ~~time~~2.750% ~~through~~per orannum tobased ~~Stifel~~on our Borrowing Base Utilization. Under the terms of the Credit Agreement, upa 5% interest penalty may apply to ~~3,000,000~~any ~~shares~~outstanding ofamount ~~our~~not ~~Common~~paid ~~Stock~~when due or that remains outstanding while an event of default exists. OnAt December 1231, ~~2022~~2024, wethe ~~voluntarily~~effective ~~terminated~~rate ~~our~~was ~~ATM~~7.88%. The Credit Agreement. ~~During~~contains ~~the~~financial ~~term~~and ofvarious ~~the~~other ~~ATM~~covenants ~~Agreement~~that are common in such agreements, weincluding ~~sold~~a (a) maximum ratio of consolidated Funded Indebtedness to consolidated pro forma EBITDAX of 3.50 to 1.00,~~531~~ calculated on a rolling four-quarter basis,~~013~~ ~~shares~~and (b) minimum ratio of ~~Common~~consolidated ~~Stock~~Current ~~pursuant~~Assets to ~~the~~consolidated ~~ATM~~Current ~~Agreement~~Liabilities ~~for~~(excluding ~~proceeds~~the Loan Balance) of ~~approximately~~1.00 $5to 1.900. ~~million~~Other negative covenants include restrictions on our ability to incur debt, ~~net~~grant ofliens, ~~commissions~~make ~~paid~~fundamental changes and engage in certain transactions with affiliates. The ~~ATM~~Credit Agreement ~~was~~also ~~terminable~~restricts atour ~~will~~ability byto usmake atcertain ~~any~~restricted ~~time~~payments ~~without~~if ~~penalty~~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 Annual Report have the meaning assigned to them in the Credit Agreement.

40Based on our expected capital expenditure levels, anticipated cash provided by operating activities for 2025, combined with availability under our Credit Facility and potential future sales of Common Stock, we believe we have sufficient liquidity to fund our ongoing operations.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

Determinations of the borrowing base are made at least semi-annually (on December 1 and June 1) or whenever the banks, in their discretion, believe that there has been a material change in the value of the natural gas and oil properties. 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 before or 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. At December 31, ~~2023~~2024, we were in compliance with the covenants of the Credit Facility, had $3229,~~750~~500,000 outstanding and had $1720,~~250~~500,000 of borrowing base availability under the Credit Facility.

The table below summarizes our contractual obligations and commitments as of December 31, ~~2023~~2024:

	Payments due by period
Contractual Obligations			Less than						More than
and Commitments	Total		1 Year		1-3 Years		3-5 Years		5 Years
Long-term debt obligations	$	3229,~~750~~500,000	$	-	$	~~32,750,000~~-	$	-29,500,000	$	-
Building lease	$	1734,~~000,439~~572	$	~~265~~270,~~867~~845	$	~~548~~463,~~568~~727	$	~~186,004~~-	$	-

Our building leases are accounted for as operating leases, and a related operating lease right-of-use (”ROU”) asset and operating lease liability has been recognized on our balance sheets.

At December 31, 2023, our derivative contracts were in a net asset position of $3,283,587. The ultimate settlement amounts of the derivative contracts are unknown because they are subject to continuing market risk. Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 12 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding our derivative contracts.39

AsAt of December 31, ~~2023~~2024, our ~~estimate~~derivative ~~for~~contracts ~~asset~~were ~~retirement~~in ~~obligations~~a ~~was~~net liability position of $1714,~~062,139~~408. ~~Asset~~The ~~retirement~~ultimate ~~obligations~~settlement ~~represent~~amounts ~~our share~~ of the ~~future~~derivative ~~expenditures~~contracts toare ~~plug~~unknown ~~and~~because ~~abandon~~they ~~the~~are ~~wells~~subject into ~~which~~continuing wemarket ~~own a working interest at the end of their economic lives~~risk. ~~These~~Please ~~amounts~~read ~~were~~Item ~~not~~7A ~~included~~– in“Quantitative ~~the~~and ~~schedule~~Qualitative ~~above~~Disclosures ~~due~~about toMarket ~~the~~Risk” ~~uncertainty~~and ~~of timing of the obligations. Please read~~ Note 1112 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding our ~~asset~~derivative ~~retirement obligations~~contracts.

41As of December 31, 2024, our estimate for asset retirement obligations was $1,097,750. Asset retirement obligations represent our share of the future expenditures to plug and abandon the wells in which we own a working interest at the end of their economic lives. These amounts were not included in the schedule above due to the uncertainty of timing of the obligations. Please read Note 11 to the financial statements included in Item 8 – “Financial Statements and Supplementary Data” for additional information regarding our asset retirement obligations.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements during ~~2023~~2024 and ~~2022~~2023, and we currently do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future effect on our financial condition, or result in changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

CRITICAL ACCOUNTING POLICIES

Preparation of financial statements in conformity with GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change our reported cash flows or liquidity. Existing rules must be interpreted, and judgments made on how the specifics of a given rule apply to the Company.

The more significant reporting areas impacted by management’s judgments and estimates include: natural gas, crude oil and NGL reserve estimation; derivative contracts; impairment of assets; natural gas, oil and NGL sales revenue accruals; and provision for income taxes. Management’s judgments and estimates are based on information available from both internal and external sources, including engineers, geologists, consultants and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. The natural gas, oil and NGL sales revenue accrual is particularly subject to estimate inaccuracies due to our status as a non-operator on all of our properties. As such, production and price information obtained from well operators is substantially delayed. This causes the estimation of recent production and prices used in the natural gas, oil and NGL revenue accrual to be subject to future change.

Natural Gas, Oil and NGL Reserves

Management considers the estimation of our natural gas, crude oil and NGL reserves to be the most significant of our judgments and estimates. These estimates affect the unaudited standardized measure disclosures included in Supplementary Information to the financial statements in Item 8 – “Financial Statements and Supplementary Data” as well as DD&A and impairment calculations for working interest properties. Changes in natural gas, crude oil and NGL reserve estimates affect our calculation of DD&A, asset retirement obligations and assessment of the need for asset impairments. Our Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares our estimates of natural gas, crude oil and NGL reserves on an annual basis~~, with a semi-annual update~~. These estimates are 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, geological and geophysical information. Between periods in which reserves would normally be calculated, we update the reserve calculations utilizing prices which are updated through the current period. In accordance with SEC rules, our reserve estimates were based on average individual product prices during the 12-month period prior to December 31 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. Based on our ~~2023~~2024 DD&A, a 10% change in the DD&A rate per Mcfe would result in a corresponding $~~856~~960,~~619~~644 annual change in DD&A expense. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future natural gas, crude oil and NGL pricing assumptions are used by management to prepare estimates of natural gas, crude oil and NGL reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.

Successful Efforts Method of Accounting

We have elected to utilize the successful efforts method of accounting for our natural gas and oil exploration and development activities. This means exploration expenses, including geological and geophysical costs, non-producing lease impairment, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by property using the unit-of-production method for working interest wells (the ratio of natural gas, oil and NGL volumes produced to total proved or proved developed reserves is used to amortize the remaining asset basis on each producing property) as natural gas, oil and NGL is produced. Our exploratory wells are all onshore in the continental United States and primarily located in the Mid-Continent area. Expenditures on exploratory wells comprise less than 5% of our total expenditures for natural gas and oil properties. This accounting method may yield significantly different operating results than the full cost method.

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impairment, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by property using the unit-of-production method for working interest wells (the ratio of natural gas, oil and NGL volumes produced to total proved or proved developed reserves is used to amortize the remaining asset basis on each producing property) as natural gas, oil and NGL is produced. Our exploratory wells are all onshore in the continental United States and primarily located in the Mid-Continent area. Expenditures on exploratory wells comprise less than 5% of our total expenditures for natural gas and oil properties. This accounting method may yield significantly different operating results than the full cost method.

Derivative Contracts

We have entered into costless collar contracts and fixed swap contracts. These instruments are intended to reduce our exposure to fluctuations in the price of natural gas and oil. 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. Fixed swap contracts set a fixed price and provide for 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. These contracts cover only a portion of our natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in prices. Our derivative contracts are with BP Energy Company and are secured under our Credit Facility.

We are required to recognize all derivative instruments as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. At December 31, ~~2023~~2024, we had no derivative contracts designated as cash flow hedges, and therefore, changes in the fair value of derivatives are reflected in earnings.

Impairment of Assets

All long-lived assets, principally natural gas and oil properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than our estimated future net cash flows. The evaluations involve significant judgment, since the results are based on estimated future events, such as: inflation rates; 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; economic and regulatory climates and other factors. We estimate future net cash flows on our natural gas and oil properties utilizing differentially adjusted forward pricing curves for natural gas, oil and NGL and a discount rate in line with the discount rate we believe is most commonly used by market participants (10% for all periods presented). 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. A further reduction in natural gas, oil and NGL prices (which are reviewed quarterly) or a decline in reserve volumes (which are re-evaluated semi-annually) would likely lead to impairment that may be material to the Company. The decision to not participate in future development on our leasehold acreage can trigger a test for impairment. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.

Natural Gas, Oil and NGL Sales Revenue Accrual

We do not operate our natural gas and oil properties and, therefore, receive actual natural gas, oil and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, as well as public and private sources, and natural gas, oil and NGL index prices ~~local to each well~~ are used to estimate the accrual of revenue on these wells. Obtaining timely production data on all other wells from the operators is not feasible; therefore, we utilize past production receipts and estimated sales price information to estimate our accrual of revenue on all other wells each quarter. The natural gas, oil and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL sales at the end of any particular quarter. Based on past history, our estimated accruals have been materially accurate.

Income Taxes

The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of our percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at the end of each fiscal year. During interim periods, an estimate is made which takes into account historical data and current pricing. We have certain state and may have federal net operating loss carry forwards (NOLs) that are recognized as tax assets when assessed as more likely than not to be utilized before their expiration dates. Criteria such as expiration dates, future excess state depletion and reversing taxable temporary differences are evaluated to determine whether the NOLs are more likely than not to be utilized before they expire. If any NOLs are no longer determined to be more likely than not to be utilized, then a valuation allowance is recognized to reduce the tax benefit of such NOLs.

4341

certain state and may have federal net operating loss carry forwards (NOLs) that are recognized as tax assets when assessed as more likely than not to be utilized before their expiration dates. Criteria such as expiration dates, future excess state depletion and reversing taxable temporary differences are evaluated to determine whether the NOLs are more likely than not to be utilized before they expire. If any NOLs are no longer determined to be more likely than not to be utilized, then a valuation allowance is recognized to reduce the tax benefit of such NOLs.

The above description of our critical accounting policies is not intended to be an all-inclusive discussion of the uncertainties considered and estimates made by management in applying GAAP. Results may vary significantly if different policies were used or required and if new or different information becomes known to management.

ITEM 7A. 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~~2025 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~~2025 derivative contracts (see below), the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $~~745~~796,~~708~~995 for operating revenue based on our prior year natural gas volumes. The price sensitivity in ~~2024~~2025 for each $1.00 per barrel change in wellhead oil is approximately $~~182~~178,~~916~~357 for operating revenue based on our prior year oil volumes.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to our Credit Facility. Interest under our Credit Facility is calculated based on either (a) 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. At December 31, ~~2023~~2024, we had $3229,~~750~~500,000 outstanding under this facility and the effective interest rate was 87.7488%. 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 $~~327~~295,~~500~~000 for the year ended December 31, ~~2023~~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 noted in the last few years, and we do not believe that our liquidity will be significantly impacted in the near future. All capitalized terms in this description of the interest rate under the Credit Facility that are not otherwise defined in this Annual Report have the meaning assigned to them in the Credit Agreement.

4442

ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 42)		4644
Balance Sheets As of December 31, 2023 and September 30, 2022		48
Balance Sheets As of December 31, 2024 and December 31, 2023		46
Statements of Income for the Year Ended December 31, 2023, Three Months Ended December 31, 2022, and Year Ended September 30, 2022		49
Statements of Income for the Years Ended December 31, 2024 and 2023		47
Statements of Stockholders’ Equity for the Year Ended December 31, 2023, Three Months Ended December 31, 2022, and Year Ended September 30, 2022		50
Statements of Stockholders’ Equity for the Years Ended December 31, 2024 and 2023		48
Statements of Cash Flows for the Year Ended December 31, 2023, Three Months Ended December 31,2022, and Year Ended September 30, 2022		51
Statements of Cash Flows for the Years Ended December 31, 2024 and 2023		49
Notes to Financial Statements		5250
Supplementary Information on Natural Gas, Oil, and NGL Reserves (Unaudited)		7068

4543

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of PHX Minerals Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of PHX Minerals Inc. (the Company) as of December 31, ~~2023~~2024 and ~~September 30~~2023, ~~2022,~~ the related statements of income, stockholders’ equity and cash flows for ~~the~~each ~~year~~of ~~ended~~the ~~December~~two ~~31,~~years ~~2023,~~in the ~~three~~period ~~months~~ ended December 31, ~~2022~~2024, and the ~~year ended September 30, 2022, and the~~ related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, ~~2023~~2024 and ~~September 30~~2023, ~~2022,~~ and the results of its operations and its cash flows for ~~the~~each ~~year~~of ~~ended~~the ~~December~~two ~~31,~~years ~~2023,~~in the ~~three~~period ~~months~~ ended December 31, ~~2022~~2024, ~~and the year ended September 30, 2022,~~ in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Depreciation, Depletion and Amortization of Producing Natural Gas and Oil Working Interest and Overriding Royalty Interest Properties Description of the Matter At December 31, ~~2023~~2024, the cost basis of the Company’s natural gas and oil properties was $~~267~~274.9 million, and depreciation, depletion and amortization (“DD&A”) expense was $89.6 million for the year then ended. As discussed in Note 1, the Company follows the successful efforts method of accounting for its natural gas and oil producing activities. Depreciation, depletion and amortization of natural gas and oil properties is generally computed using the unit-of-production method primarily on an individual property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of natural gas, crude oil and NGL reserves using standard geological and engineering methods generally recognized in the petroleum industry based on evaluations of in-place hydrocarbon volumes using financial and non-financial inputs. ~~For~~Subjective ~~DD&A~~judgment ~~purposes,~~is required by the ~~reserve~~Independent ~~estimates~~Consulting ~~are~~Petroleum Engineer in evaluating data used to estimate natural gas, oil and NGL reserves. Estimating reserves

4644

based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. Natural gas, oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Significant judgment is required by the Independent Consulting Petroleum Engineer in evaluating geological and engineering data used to estimate natural gas, oil and NGL reserves. Estimating reserves requires the selection of inputs, including ~~natural~~historical ~~gas~~production, ~~oil and NGL~~ price assumptions, ~~historical~~and ~~production,~~future operating ~~and capital~~ costs ~~assumptions and tax rates by jurisdiction~~, among others. Auditing the Company’s working interest and overriding royalty interest properties ~~units~~unit-of-production DD&A calculations is ~~especially~~subjective ~~complex~~ because of the use of the work of the Independent Consulting Petroleum Engineer and the ~~evaluation of management’s~~ determination of the inputs described above used by the engineers in estimating proved ~~developed~~ natural gas, oil and NGL reserves. How We Addressed the Matter in Our Audit Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Independent Consulting Petroleum Engineer used to prepare the proved natural gas, oil and NGL reserve estimates. In ~~addition, in~~ assessing whether we can use the work of the Independent Consulting Petroleum Engineers, we evaluated the completeness and accuracy of the financial and non-financial data ~~and inputs~~ described above used by the engineers in estimating proved natural gas, oil and NGL reserves by agreeing them to source documentation. ~~and~~In addition, we ~~identified~~assessed ~~and~~the ~~evaluated~~inputs for reasonableness based on our review of corroborative evidence and consideration of any contrary evidence. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved ~~developed~~ natural gas, oil and NGL reserve amounts used in the calculations to the Company’s reserve report.

/s/ Ernst & Young LLP

We have served as the Company's auditor since 1989.

Oklahoma City, Oklahoma

March 12, ~~2024~~2025

4745

PHX Minerals Inc.

Balance Sheets

	December 31,			~~September 30,~~
	2023			2022
	2024			2023
Assets
Current Assets:
Cash and cash equivalents	$	~~806~~2,~~254~~242,102		$	3806,~~396,809~~254
Natural gas, oil and NGL sales receivables (net of $0 allowance for uncollectable accounts)		46,~~900~~128,~~126~~954			134,~~152~~900,~~274~~126
Refundable income taxes		~~455~~328,~~931~~560			-455,931
Derivative contracts, net		~~3,120,607~~-			-3,120,607
Other		~~878~~857,~~659~~317			1878,~~372,847~~659
Total current assets		109,~~161~~556,~~577~~933			1710,~~921~~161,~~930~~577
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties		~~209~~223,~~082~~043,~~847~~942			~~248~~209,~~978~~082,~~928~~847
Non-producing natural gas and oil properties		5851,~~820~~806,~~445~~911			5158,~~779~~820,~~336~~445
Other		1,~~360~~361,~~614~~064			1,~~085~~360,~~056~~614
		269,263,906			301,843,320
		276,211,917			269,263,906
Less accumulated depreciation, depletion and amortization		(~~114~~122,~~139~~835,~~423~~668	)		(~~168~~114,~~759~~139,~~385~~423	)
Net properties and equipment		~~155~~153,~~124~~376,~~483~~249			~~133~~155,~~083~~124,~~935~~483
Derivative contracts, net		~~162,980~~-			-162,980
Operating lease right-of-use assets		~~572~~429,~~610~~494			~~739~~572,~~131~~610
Other, net		~~486~~553,~~630~~090			~~757~~486,~~116~~630
Total assets	$	~~166~~163,~~508~~915,~~280~~766		$	~~152~~166,~~502~~508,~~112~~280
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable	$	~~562~~804,~~607~~693		$	~~647~~562,~~217~~607
Derivative contracts, net		-316,336			~~7,873,979~~-
Current portion of operating lease liability		~~233~~247,~~390~~786			~~213~~233,~~355~~390
Income taxes payable		-			495,858
Accrued liabilities and other		1,866,930			1,215,275
Accrued liabilities and other		1,215,275			2,032,275
Total current liabilities		3,235,745			2,011,272
Total current liabilities		2,011,272			11,262,684
Long-term debt		29,500,000			32,750,000
Long-term debt		32,750,000			28,300,000
Deferred income taxes		7,286,315			6,757,637
Deferred income taxes		6,757,637			1,585,906
Asset retirement obligations		1,097,750			1,062,139
Asset retirement obligations		1,062,139			1,901,904
Derivative contracts, net		398,072			-
Derivative contracts, net		-			687,212
Operating lease liability, net of current portion		448,031			695,818
Operating lease liability, net of current portion		695,818			985,887
Total liabilities		41,965,913			43,276,866
Total liabilities		43,276,866			44,723,593
Stockholders' equity:
Voting common stock, par value $0.01666 per share: 54,000,500 shares authorized and 36,121,723 shares issued and outstanding at December 31, 2023; 54,000,500 shares authorized and 35,776,752 shares issued and outstanding at September 30, 2022		601,788			596,041
Voting common stock, par value $0.01666 per share: 75,000,000 shares authorized and 36,796,496 shares issued and outstanding at December 31, 2024; 54,000,500 shares authorized and 36,121,723 shares issued and outstanding at December 31, 2023		613,030			601,788
Capital in excess of par value		4144,~~676~~029,~~417~~492			4441,~~177~~676,~~051~~417
Deferred directors' compensation		1,~~487~~323,~~590~~760			1,~~496~~487,~~243~~590
Retained earnings		8077,~~022~~073,~~839~~332			6780,~~117~~022,~~791~~839
		123,788,634			113,387,126
		123,039,614			123,788,634
Treasury stock, at cost: 131,477 shares at December 31, 2023; 377,232 shares at September 30, 2022		(557,220	)		(5,608,607	)
Treasury stock, at cost: 279,594 shares at December 31, 2024; 131,477 shares at December 31, 2023		(1,089,761	)		(557,220	)
Total stockholders' equity		~~123~~121,~~231~~949,~~414~~853			~~107~~123,~~778~~231,~~519~~414
Total liabilities and stockholders' equity	$	~~166~~163,~~508~~915,~~280~~766		$	~~152~~166,~~502~~508,~~112~~280

See accompanying notes.

4846

PHX Minerals Inc.

Statements of Income

Year Ended

Three Months Ended

Year Ended

Year Ended December 31,

December 31, 2023

December 31, 2022

September 30, 2022

2024

2023

Revenues:

Natural gas, oil and NGL sales

3633,~~536~~690,~~285~~652

1436,~~888~~536,~~674~~285

~~69,860,631~~

Lease bonuses and rental income

1580,~~068,022~~804

341,~~482~~068,022

~~467,502~~

Gains (losses) on derivative contracts (Note 12)

6299,~~859,589~~608

36,~~347~~859,~~002~~589

~~(16,833,078~~

)

44,463,896

18,270,158

53,495,055

34,571,064

44,463,896

Costs and expenses:

Lease operating expenses

1,~~598~~228,~~944~~813

~~977~~1,~~165~~598,944

~~3,945,706~~

Transportation, gathering and marketing

34,~~674~~513,~~832~~381

13,~~455~~674,~~260~~832

~~5,890,390~~

Production and ad valorem taxes

1,~~881~~703,~~737~~305

~~656~~1,~~764~~881,737

~~3,332,581~~

Depreciation, depletion and amortization

89,~~566~~606,~~185~~444

18,~~802~~566,~~114~~185

~~7,278,118~~

Provision for impairment

3852,~~533~~673

638,~~100,696~~533

~~14,565~~

Interest expense

2,~~362~~563,~~393~~268

~~637~~2,~~698~~362,393

~~1,164,992~~

General and administrative

11,~~970~~670,~~182~~328

311,~~137~~970,~~401~~182

~~11,500,594~~

Losses (gains) on asset sales and other

(483,~~285,170~~799

)

(~~824~~4,~~073~~285,170

)

~~(4,243,163~~

)

25,807,636

13,943,025

28,883,783

31,422,011

25,807,636

Income before provision (benefit) for income taxes

18,656,260

4,327,133

24,611,272

Income before provision for income taxes

3,149,053

18,656,260

Provision for income taxes

4827,~~735,460~~187

~~981~~4,~~000~~735,460

~~4,202,000~~

Net income

132,~~920~~321,~~800~~866

313,~~346~~920,~~133~~800

~~20,409,272~~

Basic and diluted earnings (loss) per common share (Note 7)

0.3906

0.0939

~~0.59~~

Weighted average shares outstanding:

Basic

3536,~~980~~329,~~309~~735

35,~~679~~980,~~740~~309

~~34,403,498~~

Diluted

3536,~~980~~412,~~309~~270

3635,~~489~~980,~~353~~309

~~34,560,310~~

Dividends declared per share of common stock and paid in period

0.0975

0.0200

0.0650

Dividends per share of common stock paid in period

0.1400

0.0975

See accompanying notes.

4947

PHX Minerals Inc.

Statements of Stockholders’ Equity

	Voting				Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total
Balances at September 30, 2021		32,770,433	$	545,956	$	33,213,645		$	1,768,151		$	48,966,420			(388,545	)	$	(5,785,433	)	$	78,708,739
Net income (loss)		-		-		-			-			20,409,272			-			-			20,409,272
Purchase of treasury stock		-		-		-			-			-			(700	)		(1,855	)		(1,855	)
Restricted stock awards expense		-		-		2,211,673			-			-			-			-			2,211,673
Dividends declared		-		-		-			-			(2,257,901	)		-			-			(2,257,901	)
Distribution of restricted stock to officers and directors		115,373		1,922		(178,481	)		-			-			12,013			178,681			2,122
Distribution of deferred directors' compensation		61,452		1,024		462,736			(463,760	)		-			-			-			-
Increase in deferred directors' compensation charged to expense		-		-		-			191,852			-			-			-			191,852
Equity issued to acquire assets		1,519,481		25,315		3,484,686			-			-			-			-			3,510,001
At-The-Market Offering		1,310,013		21,824		4,982,792			-			-			-			-			5,004,616
Balances at September 30, 2022		35,776,752	$	596,041	$	44,177,051		$	1,496,243		$	67,117,791			(377,232	)	$	(5,608,607	)	$	107,778,519
Net income (loss)		-		-		-			-			3,346,133			-			-			3,346,133
Purchase of treasury stock		-		-		-			-			-			(14,442	)		(52,460	)		(52,460	)
Restricted stock awards expense		-		-		524,257			-			-			-			-			524,257
Dividends declared		-		-		-			-			(1,538,150	)		-			-			(1,538,150	)
Distribution of restricted stock to officers and directors		161,454		2,690		(1,356,392	)		-			-			91,402			1,353,702			-
Increase in deferred directors' compensation charged to expense		-		-		-			44,827			-			-			-			44,827
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)		-		-		-			-			13,920,800			-			-			13,920,800
Purchase of treasury stock		-		-		-			-			-			(120,939	)		(402,704	)		(402,704	)
Restricted stock awards expense		-		-		2,205,910			-			-			-			-			2,205,910
Dividends declared		-		-		-			-			(2,823,735	)		-			-			(2,823,735	)
Distribution of restricted stock to officers and directors		183,517		3,057		(3,850,079	)		-			-			268,422			3,847,022			-
Distribution of deferred directors' compensation		-		-		(24,330	)		(281,497	)		-			21,312			305,827			-
Increase in deferred directors' compensation charged to expense		-		-		-			228,017			-			-			-			228,017
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)		-		-		-			-			2,321,866			-			-			2,321,866
Purchase of treasury stock		-		-		-			-			-			(212,391	)		(805,063	)		(805,063	)
Restricted stock awards expense		-		-		2,287,927			-			-			-			-			2,287,927
Dividends declared		-		-		-			-			(5,271,373	)		-			-			(5,271,373	)
Distribution of restricted stock to officers and directors		674,773		11,242		(11,242	)		-			-			-			-			-
Distribution of deferred directors' compensation		-		-		76,390			(348,912	)		-			64,274			272,522			-
Increase in deferred directors' compensation charged to expense		-		-		-			185,082			-			-			-			185,082
Balances at December 31, 2024		36,796,496	$	613,030	$	44,029,492		$	1,323,760		$	77,073,332			(279,594	)	$	(1,089,761	)	$	121,949,853

See accompanying notes.

5048

PHX Minerals Inc.

Statements of Cash Flows

	Year Ended			Three Months Ended			Year Ended
	Year Ended December 31,
	December 31, 2023			December 31, 2022			September 30, 2022
		2024			2023
Operating Activities
Net income	$	132,~~920~~321,~~800~~866		$	313,~~346~~920,~~133~~800		$	~~20,409,272~~
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		89,~~566~~606,~~185~~444			18,~~802~~566,~~114~~185			~~7,278,118~~
Impairment of producing properties		3852,~~533~~673			638,~~100,696~~533			~~14,565~~
Provision for deferred income taxes		4528,~~303,731~~678			~~868~~4,~~000~~303,731			~~1,242,000~~
Gain from leasing fee mineral acreage		(1580,~~067,992~~805	)		(341,~~371~~067,992	)		~~(466,341~~	)
Proceeds from leasing fee mineral acreage		1597,~~213,913~~389			671,~~651~~213,913			~~688,207~~
Net (gain) loss on sales of assets		(4518,~~728,758~~816	)		(~~934~~4,~~207~~728,758	)		~~(4,423,646~~	)
Directors' deferred compensation expense		~~228~~185,~~017~~082			44228,~~827~~017			~~191,852~~
Total (gain) loss on derivative contracts		(6299,~~859,589~~608	)		(36,~~347~~859,~~002~~589	)		~~16,833,078~~
Cash receipts (payments) on settled derivative contracts		24,~~743~~297,~~475~~603			~~(810~~2,~~839~~743,475	)		~~(2,796,250~~	)
Restricted stock award expense		2,~~205~~287,~~910~~927			~~524~~2,~~257~~205,910			~~2,211,673~~
Other		~~136~~98,~~412~~104			30136,~~157~~412			~~87,353~~
Cash provided (used) by changes in assets and liabilities:
Natural gas, oil and NGL sales receivables		4(1,~~883~~228,~~870~~828	)		34,~~368~~883,~~278~~870			~~(6,723,292~~	)
Income taxes receivable		~~(455~~127,~~931~~371	)		-(455,931	)		~~2,413,942~~
Other current assets		(453,~~869~~064	)		(~~309~~45,~~051~~869	)		~~250,568~~
Accounts payable		69252,~~228~~386			~~(129~~69,~~304~~228	)		~~(10,305~~	)
Other non-current assets		~~206~~(22,~~292~~985	)		63206,~~723~~292			~~(380,964~~	)
Income taxes payable		~~(576,427~~-	)		80(576,~~569~~427	)		~~161,808~~
Accrued liabilities		~~(610~~376,~~661~~436	)		(~~589~~610,~~817~~661	)		~~550,012~~
Total adjustments		1015,~~250~~755,~~339~~987			610,~~795~~250,~~681~~339			~~17,122,378~~
Net cash provided by operating activities		2418,~~171~~077,~~139~~853			1024,~~141~~171,~~814~~139			~~37,531,650~~
Investing Activities
Capital expenditures	$	(~~325~~87,~~983~~579	)	$	(87325,~~104~~983	)	$	~~(552,638~~	)
Acquisition of minerals and overriding royalty interests		(297,~~735~~796,~~516~~983	)		(1429,~~499~~735,~~014~~516	)		~~(43,525,236~~	)
Net proceeds from sales of assets		9527,~~614,194~~167			19,~~137~~614,~~730~~194			~~13,217,844~~
Deposits received on held for sale assets		-			815,000			-
Net cash provided by (used in) investing activities		(7,357,395	)		(20,447,305	)
Net cash provided (used) by investing activities		(20,447,305	)		(12,633,388	)		(30,860,030	)
Financing Activities
Financing Activities
Borrowings under Credit Facility		3,000,000			19,500,000
Borrowings under Credit Facility		19,500,000			10,000,000			21,300,000
Payments of loan principal		(6,250,000	)		(20,050,000	)
Payments of loan principal		(20,050,000	)		(5,000,000	)		(10,500,000	)
Payments on off-market derivative contracts		-			(560,162	)
Net proceeds from equity issuance		-			-			5,006,538
Purchases of treasury stock		(805,063	)		(402,704	)
Cash receipts from (payments on) off-market derivative contracts		(560,162	)		(3,010,661	)		(19,260,104	)
Payments of dividends		(5,229,547	)		(3,520,366	)
Purchases of treasury stock		(402,704	)		(52,460	)		(1,855	)
Net cash provided by (used in) financing activities		(9,284,610	)		(5,033,232	)
Payments of dividends		(3,520,366	)		(726,462	)		(2,257,901	)
Increase (decrease) in cash and cash equivalents		1,435,848			(1,309,398	)
Net cash provided (used) by financing activities		(5,033,232	)		1,210,417			(5,713,322	)
Cash and cash equivalents at beginning of period		806,254			2,115,652
Increase (decrease) in cash and cash equivalents		(1,309,398	)		(1,281,157	)		958,298
Cash and cash equivalents at end of period	$	2,242,102		$	806,254
Cash and cash equivalents at beginning of period		2,115,652			3,396,809			2,438,511
Supplemental Disclosures of Cash Flow Information
Cash and cash equivalents at end of period	$	806,254		$	2,115,652		$	3,396,809
Interest paid (net of capitalized interest)	$	2,611,089		$	2,405,361
Supplemental Disclosures of Cash Flow Information
Income taxes paid (net of refunds received)	$	318,789		$	1,464,087
Interest paid (net of capitalized interest)	$	2,405,361		$	581,142		$	997,085
Supplemental schedule of noncash investing and financing activities:
Income taxes paid (net of refunds received)	$	1,464,087		$	32,431		$	384,249
Dividends declared and unpaid	$	155,271		$	113,443
Supplemental schedule of noncash investing and financing activities:
Gross additions to properties and equipment	$	7,893,036		$	30,761,578
Dividends declared and unpaid	$	113,443		$	811,688		$	-
Net (increase) decrease in accounts receivable for properties and equipment additions		(8,474	)		(700,079	)
Gross additions to properties and equipment	$	30,761,578		$	14,710,613		$	46,791,346
Capital expenditures and acquisitions	$	7,884,562		$	30,061,499
Value of shares used for acquisitions		-			-			(3,510,001	)
Net (increase) decrease in accounts receivable for properties and equipment additions		(700,079	)		(124,495	)		796,529
Capital expenditures and acquisitions	$	30,061,499		$	14,586,118		$	44,077,874

5149

PHX Minerals Inc.

Notes to Financial Statements

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

The Company’s principal line of business is maximizing the value of its existing mineral and royalty assets through active management and expanding its asset base through acquisitions of additional mineral and royalty interests. The Company owns mineral and leasehold properties and other natural gas and oil interests, which are all located in the contiguous United States, primarily in Oklahoma, Texas, Louisiana, North Dakota and Arkansas, with properties located in several other states. The Company’s natural gas, oil and NGL production is from interests in 6,~~773~~958 wells located principally in Oklahoma, Louisiana, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 5352%, 3839% and 9% of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in the year ended December 31, ~~2023~~2024. Approximately 8081%, 1211% and 8% of the Company’s total sales volumes in the year ended December 31, ~~2023~~2024 were derived from natural gas, oil and NGL, respectively. Substantially all the Company’s natural gas, oil and NGL production is sold through the operators of the wells.

Effective April 1, 2022, the Company changed its state of incorporation from Oklahoma to Delaware through a merger with a wholly owned subsidiary, which was conducted for such purpose (the “Reincorporation”). Other than the change in the state of incorporation, the Reincorporation did not result in any change in the business, physical location, management, or any change in the fair value of the assets and liabilities of PHX Minerals Inc. and its subsidiaries and no gain or loss was recognized in our consolidated financial statements (since the merger was between entities under common control both before and after the merger).

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of natural gas, crude oil and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. The Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of natural gas, crude oil and NGL reserves on an annual basis~~, with a semi-annual update~~. These estimates are 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, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. For impairment purposes, projected future natural gas, crude oil and NGL prices as estimated by management are used. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Management uses projected future natural gas, crude oil and NGL pricing assumptions to prepare estimates of natural gas, crude oil and NGL reserves used in formulating management’s overall operating decisions.

As a non-operator of working, royalty and mineral interests, the Company receives actual natural gas, oil and NGL sales volumes and prices more than a month after the information is available to the operators of the wells. Because of the delay in information, the most current available production data is gathered from the appropriate operators, as well as public and private sources, and natural gas, oil and NGL index prices are used to estimate the accrual of revenue on these wells. If information is not available from an outside source, the Company utilizes past production receipts, production type curves, and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The natural gas, oil and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.

5250

Basis of Presentation

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.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.

Natural Gas, Oil and NGL Sales

The Company sells natural gas, oil and NGL to various customers, recognizing revenues as natural gas, oil and NGL is produced and sold.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers (operators) of natural gas, oil and NGL. Natural gas, oil and NGL sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our natural gas, oil and NGL and the operators of the properties in which we have an interest may be similarly affected by changes in economic, industry or other conditions. During the ~~year~~years ended December 31, ~~2023~~2024, ~~the Transition Period consisting of the three months ended December 31, 2022,~~ and ~~the year ended September 30~~2023, ~~2022,~~ the Company did not have any bad debt expense. The Company’s allowance for uncollectible accounts as of the balance sheet dates was not material.

Natural Gas and Oil Producing Activities

The Company follows the successful efforts method of accounting for natural gas and oil producing activities. For working interest properties, intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income, if and when the well does not reach commercial production levels. Natural gas and oil mineral and leasehold costs are capitalized when incurred.

Leasing of Mineral Rights

The Company generates lease bonuses 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, and it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as income. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rentals line item on the Company’s Statements of Income.

Derivatives

The Company utilizes derivative contracts to reduce its exposure to fluctuations in the price of natural gas and oil. These derivatives are recorded at fair value on the balance sheet. The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges.

5351

Properties and Equipment

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization of the costs of producing natural gas and oil properties are generally computed using the unit-of-production method primarily on an individual property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s capitalized costs of drilling and equipping all development wells, and those exploratory wells that have found proved reserves, are amortized on a unit-of-production basis over the remaining life of associated proved developed reserves. Leasehold costs for working interest and overriding royalty interest properties are amortized on a unit-of-production basis over the remaining life of associated total proved reserves. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.

Non-producing natural gas and oil properties include non-producing minerals, which had a net book value of $4941,~~226~~870,~~889~~046 and $4349,~~223~~226,~~165~~889 at December 31, ~~2023~~2024 and ~~September~~December 3031, ~~2022~~2023, respectively, consisting of perpetual ownership of mineral interests in several states, with 5857% of the acreage in Oklahoma, Texas, Louisiana, North Dakota and Arkansas. As mentioned, these mineral rights are perpetual and have been accumulated over the 9798-year life of the Company. There are approximately ~~172~~170,~~091~~773 net acres of non-producing minerals in more than 5,~~659~~603 tracts owned by the Company. An average tract contains approximately 30 acres. Since inception, the Company has continually generated an interest in several thousand natural gas and oil wells using its ownership of the fee mineral acres as an ownership basis. There continues to be drilling and leasing activity on these mineral interests each year. Non-producing minerals are considered a long-term investment by the Company, as they do not expire (unlike natural gas and oil leases) and based on past history and experience, management has concluded that a long-term straight-line amortization over 33 years is appropriate. Due to the fact that the Company’s mineral ownership consists of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis (by mineral deed).

When a new well is drilled on the Company’s mineral acreage, all of the non-producing mineral costs for the associated mineral tract are transferred to producing minerals and are amortized straight-line over a 20-year period (insignificant fields are amortized over a 10-year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on the Company’s minerals, and future development will deplete these assets over a long period. The straight-line amortization over a 20-year period is appropriate for producing minerals, because current and future development will deplete these assets over a lengthy period that represents the estimated economic life.

Capitalized Interest

During the ~~year~~years ended December 31, ~~2023,~~2024 ~~three months ended December 31, 2022,~~ and ~~year ended September 30~~2023, ~~2022,~~ no interest was capitalized. Interest of $2,~~362~~563,~~393,~~268 ~~$637,698,~~ and $12,~~164~~362,~~992~~393, respectively, was charged to expense during those periods.

Accrued Liabilities

The following table shows the balances for the years ended December 31, ~~2023~~2024 and ~~September~~December 3031, ~~2022~~2023, relating to the Company’s accrued liabilities:

	December 31,		~~September~~December 3031,
	2023		2022
	2024		2023
Accrued compensation	$	~~210~~853,~~379~~963	$	1210,~~296,471~~379
Revenues payable		~~529~~624,~~025~~837		~~263~~529,~~225~~025
Accrued ad valorem		3981,~~591~~422		~~190~~39,~~216~~591
Dividends		~~113~~155,~~443~~271		-113,443
Other		~~322~~151,~~837~~437		~~282~~322,~~363~~837
Total accrued liabilities	$	1,~~215~~866,~~275~~930	$	21,~~032~~215,275

The ~~decrease~~increase in accrued compensation in ~~2023~~2024 is ~~primarily~~ due to timing of payment related to the short-term incentive compensation.

5452

Asset Retirement Obligations

The Company owns interests in natural gas and oil properties, which may require expenditures to plug and abandon the wells upon the end of their economic lives. The fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties and equipment is depreciated over the useful life of the remaining asset. The Company does not have any assets restricted for the purpose of settling asset retirement obligations.

Environmental Costs

As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Company does not believe the existence of current environmental laws, or interpretations thereof, will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future effects on the Company of new laws or interpretations thereof. Since the Company does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Company being responsible for its proportionate share of the costs involved (on working interest wells only). The Company carries liability and pollution control insurance. However, all risks are not insured due to the availability and cost of insurance.

Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, ~~2023,~~2024 and December 31, ~~2022~~2023, ~~and September 30, 2022,~~ there were no such costs accrued and expenses were immaterial for both years.

Earnings (Loss) Per Share of Common Stock

Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period.

Share-based Compensation

The Company recognizes current compensation costs for its Deferred Compensation Plan for Non-Employee Directors (the “Plan”). Compensation cost is recognized for the requisite directors’ fees as earned and unissued stock is recorded to each director’s account based on the fair market value of the stock at the date earned. The Plan provides that only upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan may be issued to the director.

Restricted stock awards to officers and employees provide for either cliff vesting at the end of three years from the date of the awards or time vesting ratably over a three -year period. These restricted stock awards can be granted based on service time only (time-based), subject to certain share price performance standards (market-based) or subject to company performance standards (performance-based). Restricted stock awards to the non-employee directors provide for annual vesting during the calendar year of the award. The fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance.

Income Taxes

The estimation of amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax regulations. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities.

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis.

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 53

55Both 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. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended December 31, 2024 was 26% as compared to 25% for the year ended December 31, 2023.

~~estimated~~The ~~taxable~~threshold ~~loss projected~~ for ~~any~~recognizing ~~year.~~the ~~Federal~~financial ~~and~~statement ~~Oklahoma~~effect ~~excess~~of ~~percentage depletion, when~~ a ~~provision~~tax ~~for~~position ~~income~~is ~~taxes~~when it is ~~expected~~more ~~for~~likely ~~the~~than ~~year~~not, ~~decreases~~based on the ~~effective~~technical ~~tax rate~~merits, ~~while~~that the ~~effect~~position iswill tobe ~~increase~~sustained ~~the~~by ~~effective~~a ~~tax~~taxing ~~rate~~authority. ~~when~~Recognized atax ~~benefit~~positions ~~for~~are ~~income~~initially ~~taxes~~and issubsequently ~~expected~~measured ~~for~~as the ~~year.~~largest ~~The~~amount ~~benefits~~ of ~~federal and Oklahoma excess percentage depletion and excess~~ tax ~~benefits~~benefit ~~and~~that ~~deficiencies~~is ofmore ~~stock-based~~likely ~~compensation~~than ~~are~~ not ~~directly related~~ to ~~the~~be ~~amount~~realized ofupon ~~pre-tax~~ultimate ~~income~~settlement ~~(loss)~~with ~~recorded in~~ a ~~period~~taxing authority. ~~Accordingly,~~The inCompany ~~periods~~files ~~where~~income ~~a recorded pre-~~tax ~~income~~returns orin ~~loss is relatively small,~~ the ~~proportional~~U.S. ~~effect~~federal ofjurisdiction ~~these~~and ~~items~~various onstate ~~the~~jurisdictions. ~~effective~~Subject ~~tax~~to ~~rate~~statutory ~~may~~exceptions bethat ~~significant.~~allow ~~The~~for ~~effective~~a ~~tax~~possible ~~rate~~extension ~~for~~of the ~~year~~assessment ~~ended December 31~~period, ~~2023~~the ~~was~~Company ~~25%~~is asno ~~compared~~longer subject to ~~23%~~U.S. ~~for~~federal, ~~the~~state, ~~three~~and ~~months~~local ~~ended~~income ~~December~~tax ~~31,~~examinations ~~2022 and 17%~~ for ~~the~~fiscal ~~year~~years ~~ended~~prior ~~September~~to ~~30, 2022~~2021.

The ~~threshold~~Company ~~for~~includes ~~recognizing~~interest ~~the~~assessed ~~financial~~by ~~statement effect of a tax position is when it is more likely than not, based on~~ the ~~technical merits, that the position will be sustained by a~~ taxing ~~authority.~~authorities ~~Recognized~~in ~~tax~~interest ~~positions~~expense ~~are initially~~ and ~~subsequently~~penalties ~~measured~~related ~~as the largest amount of tax benefit that is more likely than not~~ to ~~be realized upon ultimate settlement with a taxing authority. The Company files~~ income ~~tax~~taxes ~~returns~~ in ~~the~~general ~~U.S. federal jurisdiction~~ and ~~various~~administrative ~~state~~expense ~~jurisdictions.~~on ~~Subject~~its toStatements ~~statutory~~of ~~exceptions~~Income. ~~that~~For ~~allow~~the ~~for~~fiscal ayears ~~possible~~ended ~~extension~~December of31, ~~the~~2024 ~~assessment~~and ~~period~~2023, the Company’s isinterest noand ~~longer~~penalties ~~subject~~were tonot Umaterial.S. ~~federal,~~The ~~state,~~Company ~~and~~does ~~local~~not ~~income~~believe ~~tax~~it ~~examinations~~has ~~for~~any ~~fiscal~~material ~~years~~uncertain ~~prior~~tax ~~to 2020~~positions.

The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Income. For the fiscal year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022, the Company’s interest and penalties were not material. The Company does not believe it has any material uncertain tax positions.

Recent Accounting Pronouncements

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable ~~Segments~~Segment Disclosures (~~Topic~~“ASU ~~280~~2023-07”), which ~~updates~~requires public entities with a single reportable segment ~~disclosure~~to ~~requirements,~~provide all existing segment disclosures required by ASC 280 on an interim and annual basis, including the ~~amendments~~title ~~provide~~and ~~new~~position ~~segment~~of ~~disclosure~~the ~~requirements~~Chief ~~for~~Operating ~~entities~~Decision ~~with~~Maker a(“CODM”), ~~single~~and ~~reportable~~primarily requires disclosing of significant segment. ~~The~~expenses ~~guidance~~that are regularly provided to the CODM. ASU 2023-07 is effective for ~~fiscal~~annual ~~years~~periods beginning after December 15, 2023, and for interim periods ~~within fiscal years~~ beginning after December 15, 2024. ~~The~~We ~~Company~~have ~~does~~adopted ~~not~~ASU ~~expect~~2023-07 for the ~~new~~fiscal ~~guidance~~year to2024 ~~have~~annual afinancial ~~material~~statements ~~impact~~and oninterim ~~its~~condensed financial statements thereafter and ~~related~~have ~~disclosures~~applied this standard retrospectively for all prior periods presented. Refer to Note 15 — Operating Segment of these financial statements.

~~Other~~Accounting ~~accounting~~Pronouncements ~~standards~~Not ~~that~~Yet ~~have~~Adopted been issued or proposed by the FASB, or other standards-setting bodies, and 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.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740) Improvements to Income Tax Disclosures. The guidance increases transparency in the income tax disclosure, primarily related to the rate reconciliation and income taxes paid information. The guidance is effective for fiscal years beginning after December 15, 2024, and early adoption is permitted. The Company is currently evaluating the impact this guidance will have on the income tax disclosures.

In November 2024, the FASB issued ASU 2024-03, Income Statement —Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”), which requires public entities to disclose additional information about certain expenses included in relevant expense captions on the income statement. ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and for interim periods beginning after December 15, 2027. Management is evaluating the impact of adoption of ASU 2024-03 on the Company’s financial statements and disclosures.

2. LEASES AND COMMITMENTS

Assessment of Leases

The Company determines if an arrangement is a lease at inception by considering whether (i) explicitly or implicitly identified assets have been deployed in the agreement and (ii) the Company obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. As of December 31, ~~2023~~2024, none of the Company’s leases were classified as financing leases. Operating lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company entered into a seven-year lease for office space during the quarter ended March 31, 2020, with a commencement date in August 2020. The associated lease liability and ROU asset at December 31, ~~2023~~2024, were $~~613~~459,~~436~~654 and $~~401~~300,~~615~~816, respectively. The Company has a lease incentive asset of $~~182~~132,~~155~~476, which is included in Other, net on the Company’s balance sheets. Additionally, the Company entered into a new five-year lease for office space during the quarter ended March 31, 2022, with a commencement date in July 2022. The associated lease liability and ROU asset at December 31, 2023, were $315,772 and $170,995, respectively. The Company has a lease incentive asset of $131,364, which is included in Other, net on the Company’s balance sheets. Lease costs for the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 were $304,163, $69,709, and $204,344, respectively.

during the quarter ended March 31, 2022, with a commencement date in July 2022. The associated lease liability and ROU asset at December 31, 2024, were $236,163 and $128,678, respectively. The Company has a lease incentive asset of $95,397, which is included in Other, net on the Company’s balance sheets. Lease costs for the years ended December 31, 2024 and 2023 were $287,763 and $304,163, respectively.

ROU assets represent the Company’s right to use an underlying asset for the lease term, and operating lease liabilities represent the Company’s obligation to make payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs and prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Company uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments.

The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Company will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Company will exercise that option. Lease expense for lease payments will be recognized on a straight-line basis over the lease term. The Company made an accounting policy election to not recognize leases with terms, including applicable options, of less than twelve months on the Company’s balance sheets and recognize those lease payments in the Company’s Statements of Income on a straight-line basis over the lease term. In the event that the Company’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.

56The following table represents the maturities of the operating lease liabilities as of December 31, 2024:

made an accounting policy election to not recognize leases with terms, including applicable options, of less than twelve months on the Company’s balance sheets and recognize those lease payments in the Company’s Statements of Income on a straight-line basis over the lease term. In the event that the Company’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.


2025		270,845
2026		277,723
2027		186,004
Thereafter		-
Total lease payments	$	734,572
Less: Imputed interest		(38,755	)
Total	$	695,817

The following table represents the maturities of the operating lease liabilities as of December 31, 2023:

2024	$	265,867
2025		270,845
2026		277,723
2027		186,004
Thereafter		-
Total lease payments	$	1,000,439
Less: Imputed interest		(71,231	)
Total	$	929,208

3. REVENUES

Natural gas and oil derivative contracts

See Note 12 for discussion of the Company’s accounting for derivative contracts.

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 has 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 tables present the disaggregation of the Company’s natural gas, oil and NGL revenues for the ~~year~~years ended December 31, ~~2023,~~2024 ~~the three months ended December 31, 2022,~~ and ~~the year ended September 30, 2022~~2023.


	Year Ended December 31, 2024
	Royalty Interest		Working Interest		Total
Natural gas revenue	$	15,958,989	$	1,494,732	$	17,453,721
Oil revenue		12,011,909		1,292,015		13,303,924
NGL revenue		1,880,830		1,052,177		2,933,007
Natural gas, oil and NGL sales	$	29,851,728	$	3,838,924	$	33,690,652


	Year Ended December 31, 2023
	Royalty Interest		Working Interest		Total
Natural gas revenue	$	17,420,360	$	2,025,900	$	19,446,260
Oil revenue		12,306,987		1,733,213		14,040,200
NGL revenue		1,866,004		1,183,821		3,049,825
Natural gas, oil and NGL sales	$	31,593,351	$	4,942,934	$	36,536,285

	Three Months Ended December 31, 2022
	Royalty Interest		Working Interest		Total
Natural gas revenue	$	7,209,757	$	2,243,736	$	9,453,493
Oil revenue		2,760,844		1,563,619		4,324,463
NGL revenue		601,103		509,615		1,110,718
Natural gas, oil and NGL sales	$	10,571,704	$	4,316,970	$	14,888,674

	Year Ended September 30, 2022
	Royalty Interest		Working Interest		Total
Natural gas revenue	$	30,837,464	$	14,930,201	$	45,767,665
Oil revenue		10,851,353		7,279,566		18,130,919
NGL revenue		2,795,655		3,166,392		5,962,047
Natural gas, oil and NGL sales	$	44,484,472	$	25,376,159	$	69,860,631

Performance obligations

The Company satisfies the performance obligations under its natural gas, oil and NGL sales contracts upon delivery of its production and related transfer of title to purchasers. Upon delivery of production, the Company has a right to receive consideration from its purchasers in amounts that correspond with the value of the production transferred.

Allocation of transaction price to remaining performance obligations

Natural gas, oil and NGL sales

As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606, which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment relate specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient.

Prior-period performance obligations and contract balances

The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into the timing of when new wells start producing, and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the natural gas, oil and NGL sales receivables line item on the Company’s balance sheets. The difference between the Company’s estimates and the actual amounts received for natural gas, oil and NGL sales is recorded in the quarter that payment is received from the third party. For the ~~year~~years ended December 31, ~~2023,~~2024 ~~three months ended December 31, 2022,~~ and ~~year ended September 30~~2023, ~~2022,~~ revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was considered a change in estimate.

As noted above, as a non-operator, there are instances when the Company is limited by the information operators provide. Through cash received on new wells, in the years ended December 31, 2024 and 2023, the Company identified several producing properties on its minerals that had production dates prior to the years ended December 31, 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 years ended December 31, 2024 and 2023, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling approximately $0.5 million for the year ended December 31, 2024 related to the production periods before January 1, 2024 and approximately $0.9 million for the year ended December 31, 2023 related to the production periods before January 1, 2023.

4. INCOME TAXES

The Company’s provision for income taxes is detailed as follows:

Year Ended

Three Months Ended

Year Ended

Year Ended December 31,

December 31, 2023

December 31, 2022

September 30, 2022

2024

2023

Current:

Federal

~~190~~99,~~914~~719

88190,~~000~~914

~~2,522,000~~

State

~~240~~198,~~815~~790

25240,~~000~~815

~~438,000~~

431,729

113,000

2,960,000

298,509

431,729

Deferred:

Federal

3525,~~538,031~~511

~~729~~3,~~000~~538,031

~~845,000~~

State

~~765~~3,~~700~~167

~~139~~765,~~000~~700

~~397,000~~

4,303,731

868,000

1,242,000

528,678

4,303,731

4827,~~735,460~~187

~~981~~4,~~000~~735,460

~~4,202,000~~

The difference between the provision for income taxes and the amount which would result from the application of the federal statutory rate to income before provision for income taxes is analyzed below:

	Year Ended			Three Months Ended			Year Ended
	Year Ended December 31,
	December 31, 2023			December 31, 2022			September 30, 2022
		2024			2023
Provision for income taxes at statutory rate	$	3661,~~917,815~~301		$	~~908~~3,~~698~~917,815		$	~~5,168,366~~
Change in valuation allowance		(83,~~067~~394	)		(~~953~~8,067	)		~~(1,313,271~~	)
Percentage depletion		(~~408~~375,~~729~~145	)		(~~150~~408,~~528~~729	)		~~(602,490~~	)
State income taxes, net of federal provision		~~963~~156,~~063~~818			~~138~~963,~~573~~063			~~863,042~~
Restricted stock tax benefit		10(59,~~664~~943	)		9310,~~000~~664			~~59,000~~
Deferred directors' compensation benefit		4228,~~018~~230			-42,018			~~64,000~~
Nondeductible compensation		~~122~~359,~~204~~545			-122,204			-
Law change		-			-			~~(56,094~~	)
Other		96,492			(7,790	)		19,447
Provision to return adjustments		40,670			190,914
	$	4,735,460		$	981,000		$	4,202,000
Other		12,317			(94,422	)
	$	827,187		$	4,735,460

Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax basis of assets and liabilities, consist of the following at December 31, 2023 and September 30, 2022: 57

	December 31,		September 30,
	2023		2022
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$	10,825,555	$	5,121,376
Derivative contracts		802,712		-
Total deferred tax liabilities		11,628,267		5,121,376
Deferred tax assets:
State net operating loss carry forwards		293,701		14,737
Federal net operating loss carry forwards		2,234,275		-
Statutory depletion carryover		417,090		-
Asset retirement obligations		210,447		337,247
Deferred directors' compensation		331,879		331,395
Restricted stock expense		653,959		705,195
Derivative contracts		-		2,072,530
Interest expense limitation/carryover		643,067		-
Other		91,874		88,095
Total deferred tax assets		4,876,292		3,549,199
State NOL valuation allowance		5,662		13,729
Net deferred tax liabilities	$	6,757,637	$	1,585,906

The federal net operating loss carry forwards can be carried forward indefinitely. Included in state net operating loss carry forwards at December 31, 2023, the Company had a deferred tax asset of $8,323 related to various state income tax net operating loss (“state NOL”) carry-forwards, which begin to expire in 2027. The Company has a valuation allowance of $5,662 for the state NOLs, as it is more likely than not that it will not be fully utilized before expiration.


	December 31,
	2024		2023
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$	12,099,584	$	10,825,555
Derivative contracts		-		802,712
Total deferred tax liabilities		12,099,584		11,628,267
Deferred tax assets:
State net operating loss carry forwards		221,690		293,701
Federal net operating loss carry forwards		1,998,323		2,234,275
Statutory depletion carryover		239,294		417,090
Asset retirement obligations		220,560		210,447
Deferred directors' compensation		288,962		331,879
Restricted stock expense		482,607		653,959
Derivative contracts		172,930		-
Interest expense limitation/carryover		1,101,150		643,067
Other		96,809		91,874
Total deferred tax assets		4,822,325		4,876,292
State NOL valuation allowance		9,056		5,662
Net deferred tax liabilities	$	7,286,315	$	6,757,637

The federal net operating loss carry forwards can be carried forward indefinitely. Included in state net operating loss carry forwards at December 31, 2024, the Company had a deferred tax asset of $20,946 related to various state income tax net operating loss (“state NOL”) carry-forwards, which begin to expire as of December 31, 2024. The Company has a valuation allowance of $9,056 for the state NOLs, as it is more likely than not that it will not be fully utilized before expiration.

5. DEBT

On September 1, 2021, the Company entered into a $100,000,000 credit facility (the “Credit Facility”) with a group of banks headed by Independent Bank. The Credit Facility has a current borrowing base of $50,000,000 as of December 31, ~~2023~~2024, and a maturity date of September 1, ~~2025~~2028. The Credit Facility is secured by the Company’s personal property and at least 75% of the total value of the proved, developed and producing oil and gas properties. The interest rate is based on either (a) ~~the Secured Overnight Financing Rate (“~~SOFR”) plus an applicable margin ranging from 2.750% to 3.750% per annum based on the Company’s Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the 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 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 December 31, 2024, the effective interest rate was 7.88%.

59The Company’s debt is recorded at the carrying amount on its balance sheets. The carrying amount of the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in Other, net on the Company’s balance sheets. Total debt issuance cost net of amortization as of December 31, 2024, was $325,218. The debt issuance cost is amortized over the life of the Credit Facility.

~~prime~~Determinations of the borrowing base are made semi-annually (usually June and December) or ~~SOFR~~whenever isthe atbanks, in their sole discretion, believe that there has been a material change in the value of the Company’s ~~discretion~~natural gas and oil properties. The ~~interest~~Credit ~~rate~~Facility ~~spread~~contains ~~from~~customary ~~Independent~~covenants ~~Bank~~which, ~~prime~~among orother ~~SOFR~~things, ~~will~~require beperiodic ~~charged~~financial ~~based~~and reserve reporting and place certain limits on the ~~ratio~~Company’s incurrence of ~~the~~indebtedness, ~~loan~~liens, ~~balance~~make tofundamental ~~the~~changes, ~~borrowing~~and ~~base~~engage in certain transactions with affiliates. The ~~interest~~Credit ~~rate~~Agreement ~~spread~~also ~~from~~restricts ~~SOFR~~the Company’s ability to make certain restricted payments if before or after the ~~prime~~Restricted ~~rate~~Payment ~~increases~~(i) asthe aAvailable ~~larger~~Commitment is less than ten percent (10%) of the ~~borrowing~~Borrowing ~~base~~Base or (ii) the Leverage Ratio on a pro forma basis is ~~advanced~~greater than 2.50 Atto ~~December~~1.00. 31In addition, ~~2023~~the Company is required to maintain certain financial ratios, a current ratio (as described in the ~~effective~~Credit ~~interest~~Agreement) ~~rate~~of ~~was~~no 8less than 1.~~74%~~0 to 1.0 and a funded debt to EBITDAX (as defined in the Credit Agreement) of

The Company’s debt is recorded at the carrying amount on its balance sheets. The carrying amount of the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in Other, net on the Company’s balance sheets. Total debt issuance cost net of amortization as of December 31, 2023, was $173,113. The debt issuance cost is amortized over the life of the Credit Facility.58

Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the 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 limits on the Company’s incurrence of indebtedness, liens, make fundamental changes, and engage in certain transactions with affiliates. The Credit Agreement 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 Agreement) of no ~~less than 1.0 to 1.0 and a funded debt to EBITDAX (as defined in the Credit Agreement) of no~~ more than 3.5 to 1.0 based on the trailing twelve months. At December 31, ~~2023~~2024, the Company was in compliance with the covenants of the Credit Facility, had $3229,~~750~~500,000 outstanding, and had $1720,~~250~~500,000 of borrowing base availability under the Credit Facility. All capitalized terms in this description of the Credit Facility that are not otherwise defined in this Annual Report have the meaning assigned to them in the Credit Agreement.

6. STOCKHOLDERS’ EQUITY

In May 2014, the Board adopted stock repurchase resolutions (the “Repurchase Program”) to allow management, at its discretion, to purchase the Company’s Common Stock as treasury shares up to an amount equal to the aggregate number of shares of Common Stock awarded pursuant to the 2010 Restricted Stock Plan (“2010 Stock Plan”), as amended, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

Effective in May 2018, the Board approved an amendment to the Company’s existing stock Repurchase Program. As amended, the Repurchase Program continues to allow the Company to repurchase up to $1.5 million of the Company’s Common Stock at management’s discretion. The Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $1.5 million of the Company’s Common Stock is authorized and approved whenever the previous amount is utilized. In addition, the number of shares allowed to be purchased by the Company under the Repurchase Program is no longer capped at an amount equal to the aggregate number of shares of Common Stock (i) awarded pursuant to the 2010 Stock Plan, as amended, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

On August 25, 2021, the Company entered into an At-The-Market Equity Offering Sales Agreement, pursuant to which the Company may offer and sell from time to time up to 3 million shares of Common Stock. On December 12, 2022, the Company voluntarily terminated the At-The-Market Equity Offering Sales Agreement.

The Company declared a $0.0225 dividend during the three months ended December 31, 2022 that was paid in March of 2023.

7. EARNINGS PER SHARE (“EPS”)

Basic and diluted earnings per common share is calculated using net income divided by the weighted average number of shares of Common Stock outstanding, including unissued, vested directors’ deferred compensation shares of ~~261~~288,~~320,~~262 ~~241,352,~~ and ~~219~~261,~~286~~320, respectively, during the ~~year~~years ended December 31, ~~2023,~~2024 ~~three months ended December 31, 2022,~~ and ~~year ended September 30, 2022~~2023. As of December 31, ~~2023~~2024, there were no participating securities.

For the ~~year~~years ended December 31, ~~2023,~~2024 ~~three months ended December 31, 2022,~~ and ~~year ended September 30~~2023, ~~2022,~~ the Company excluded restricted stock in the diluted EPS calculation that would have been antidilutive. The average shares outstanding of restricted stock excluded from the diluted EPS was ~~753~~1,~~336~~088,269 ~~401,273~~ and ~~460~~753,~~667~~336, respectively, for the ~~year~~years ended December 31, ~~2023,~~2024 ~~three months ended December 31, 2022,~~ and ~~year ended September 30, 2022~~2023.

The following table sets forth the computation of earnings (loss) per share.

	Year Ended		Three Months Ended		Year Ended
	Year Ended December 31,
	December 31, 2023		December 31, 2022		September 30, 2022
		2024		2023
Basic EPS
Numerator:
Basic net income (loss)	$	132,~~920~~321,~~800~~866	$	313,~~346~~920,~~133~~800	$	~~20,409,272~~
Denominator:
Common Shares		3536,~~718~~041,~~989~~473		35,~~438~~718,~~388~~989		~~34,184,212~~
Unissued, directors' deferred compensation shares		~~261~~288,~~320~~262		~~241~~261,~~352~~320		~~219,286~~
Basic weighted average shares outstanding		3536,~~980~~329,~~309~~735		35,~~679~~980,~~740~~309		~~34,403,498~~
Basic EPS	$	0.3906	$	0.0939	$	~~0.59~~
Diluted EPS
Numerator:
Basic net income (loss)	$	132,~~920~~321,~~800~~866	$	313,~~346~~920,~~133~~800	$	~~20,409,272~~
Diluted net income (loss)		132,~~920~~321,~~800~~866		313,~~346~~920,~~133~~800		~~20,409,272~~
Denominator:
Basic weighted average shares outstanding		3536,~~980~~329,~~309~~735		35,~~679~~980,~~740~~309		~~34,403,498~~
Effects of dilutive securities:
Unvested restricted stock		-82,535		~~809,613~~-		~~156,812~~
Diluted weighted average shares outstanding		3536,~~980~~412,~~309~~270		3635,~~489~~980,~~353~~309		~~34,560,310~~
Diluted EPS	$	0.3906	$	0.0939	$	~~0.59~~

8. 401K PLAN

Effective January 1, 2021, the Company established a defined contribution 401K ~~only~~ plan. The Company began matching up to 5% of 401K contributions in cash starting January 1, 2021.

Contributions to the ~~plans~~plan consisted of:

Year	Amount
Year Ended December 31, 2023	$	150,843
2024	$	166,954
Three Months Ended December 31, 2022	$	27,987
2023	$	150,843
Year Ended September 30, 2022	$	85,444

9. DEFERRED COMPENSATION PLAN FOR DIRECTORS

Annually, independent directors may elect to be included in the Company’s Deferred Directors’ Compensation Plan for Non-Employee Directors (the “Plan”). The Plan provides that each independent director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of the annual retainers, and may elect to receive shares, when issued, over annual time periods up to ten years. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares at each quarter end. Only upon a director’s retirement, termination, death or a change-in-control of the Company will the shares recorded for such director under the Plan be issued to the director. The promise to issue such shares in the future is an unsecured obligation of the Company. As of December 31, ~~2023~~2024, there were ~~304~~292,~~741~~320 shares recorded under the Plan. The deferred balance outstanding at December 31, ~~2023~~2024, under the Plan was $1,~~487~~323,~~590~~760. Expenses totaling $~~228~~185,~~017,~~082 ~~$44,827,~~ and $~~191~~228,~~852~~017 were charged to the Company’s results of operations for the ~~year~~years ended December 31, ~~2023,~~2024 ~~three months ended December 31, 2022,~~ and ~~year ended September 30~~2023, ~~2022,~~ respectively, and are included in general and administrative expense in the accompanying Statements of Income.

10. ~~RESTRICTED STOCK PLAN AND~~ LONG-TERM INCENTIVE PLAN

In March of 2021, stockholders approved the PHX Minerals Inc. 2021 Long-Term Incentive Plan (the “LTIP”). The LTIP expressly prohibits the payment of dividends or dividend equivalents on any award before the date on which the award vests. Awards under the LTIP will be subject to any clawback or recapture policy that the Company may adopt from time to time or any clawback or recapture provisions set forth in an award agreement.

61 The fair value of the restricted stock (time-based) was based on the closing price of the shares on their grant date and will be recognized as compensation expense ratably over the vesting period. The fair value of the performance shares (market-based) was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the historical volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Vesting of these performance shares is based on the performance of the market price of the Common Stock over the vesting period. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period regardless of whether performance shares are awarded at the end of the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury or the Company’s authorized but unissued shares. Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur.

The fair value of the restricted stock (time-based) was based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over the vesting period. The fair value of the performance shares (market-based) was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Vesting of these performance shares is based on the performance of the market price of the Common Stock over the vesting period. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period regardless of whether performance shares are awarded at the end of the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury or the Company’s authorized but unissued shares. Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur.

On March 2, 2022, the Company awarded shares of Common Stock in the form of time-based and market-based restricted stock to the directors, employees and officers of the Company. Non-employee directors received 138,249 time-based shares with a fair value on the award date of $387,095. These shares vest in December 2022. Officers were awarded 402,086 market-based shares with a fair value on their award date of $1,679,757. Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 126,013 time-based shares with a fair value on the award date of $352,838. The shares issued to employees time-vest ratably over a three-year period ending in December 2024, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December 2024. All shares awarded on March 2, 2022, have voting rights during the vesting period and do not include the right to dividends prior to vesting.

On April 1, 2022, the Company awarded shares of common stock in the form of time-based restricted stock to a new director. The non-employee director received 20,737 time-based shares with a fair value on the award date of $62,004. These shares vest in December of 2022, contain voting rights during the vesting period, and do not include the right to dividends prior to vesting.

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

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

On December 21, 2023, the Company granted 482,339 shares of Common Stock in the form of time-based and market-based restricted stock to the employees and officers of the Company. Officers were awarded 369,114 market-based shares with a fair value on their award date of $1,678,599. Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 113,225 time-based shares with a fair value on the award date of $381,571. The shares issued to employees time-vest ratably over a three-year period ending in December of 2026, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December of 2026. All shares granted on December 21, 2023 have voting rights during the vesting period.

On December 21, 2023, the Company granted 116,904 shares of Common Stock in the form of time-based restricted stock to the non-employee directors of the Company, which had a fair value of $393,967. The shares of restricted stock fully ~~vest~~vested in December 2024 and ~~have~~had voting rights during the vesting period.

62On December 16, 2024, the Company granted 465,649 shares of Common Stock in the form of time-based and market-based restricted stock to the employees and officers of the Company. Officers were awarded 347,818 market-based shares with a fair value on their award date of $1,786,802. Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 117,831 time-based shares with a fair value on the award date of $467,790. The shares issued to employees time-vest ratably over a three-year period ending in December of 2027, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December of 2027. All shares granted on December 16, 2024 have voting rights during the vesting period.

~~The~~On ~~following~~December ~~table~~16, ~~summarizes~~2024, the Company’s ~~pre-tax~~granted ~~compensation~~82,695 ~~expense~~shares ~~for~~of Common Stock in the ~~year~~form ~~ended~~of ~~December~~time-based ~~31,~~restricted ~~2023,~~stock ~~three~~to ~~months~~the ~~ended~~non-employee ~~December~~directors ~~31,~~of ~~2022~~the Company, ~~and~~which ~~year~~had ~~ended~~a ~~September~~fair ~~30,~~value ~~2022~~of $328,300. ~~related~~The toshares ~~the~~of ~~Company’s~~restricted ~~market-based,~~stock ~~time-based~~fully vest in December 2025 and ~~performance-based~~have ~~restricted~~voting ~~stock:~~rights during the vesting period.

	Year Ended		Three Months Ended		Year Ended
	December 31, 2023		December 31, 2022		September 30, 2022
Market-based, restricted stock	$	1,722,814	$	311,548	$	1,018,136
Time-based, restricted stock		483,096		206,333		730,303
Performance-based, restricted stock		-		6,376		463,234
Total compensation expense	$	2,205,910	$	524,257	$	2,211,673

The following table summarizes the Company’s pre-tax compensation expense for the years ended December 31, 2024 and 2023 related to the Company’s market-based, time-based and performance-based restricted stock:


	Year Ended December 31,
	2024		2023
Market-based, restricted stock	$	1,624,134	$	1,722,814
Time-based, restricted stock		663,793		483,096
Total compensation expense	$	2,287,927	$	2,205,910

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 are shown in the following table:

	UnrecognizedCompensation Cost		Weighted Average Period (in years)
Market-based, restricted stock	$	2,~~494~~605,~~255~~320		1.7175
Time-based, restricted stock		1,~~089~~080,~~983~~882		12.8702
Total	$	3,~~584~~686,~~238~~202

Upon vesting, shares are expected to be issued out of shares held in treasury or authorized but unissued shares.

A summary of the status of, and changes in, unvested shares of restricted stock awards is presented below:

	Market-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		Time-Based Unvested Restricted Awards			Weighted Average Grant-Date Fair Value		~~Performance-Based Unvested Restricted Awards~~			~~Weighted Average Grant-Date Fair Value~~
Unvested shares as of September 30, 2021		356,149		$	3.56		203,100		$	5.33		34,814		$	8.99
Unvested shares as of December 31, 2022		705,835		$	3.55		153,224		$	5.09
Granted		~~402~~669,~~086~~014			4.1881		~~284~~419,~~999~~726			23.8126		-			-
Vested		-(303,750	)		-2.72		(~~127~~147,~~386~~495	)		35.4117		-			-
Forfeited		~~(17,585~~-	)		~~8.16~~-		(67,~~855~~919	)		63.9241		-			-
Unvested shares as of September 30, 2022		740,650		$	3.79		353,858		$	3.97		34,814		$	8.99
Unvested shares as of December 31, 2023		1,071,099		$	4.57		417,536		$	3.26
Granted		-458,465			-4.89		-210,651			-3.92		~~17,408~~			~~8.99~~
Vested		-(502,608	)		-4.18		(~~200~~172,~~634~~165	)		3.1115		~~(52,222~~	)		~~8.99~~
Forfeited		(3421,~~815~~962	)		84.5881		-(60,658	)		-3.36		-			-
Unvested shares as of December 31, 2022		705,835		$	3.55		153,224		$	5.09		-		$	-
Unvested shares as of December 31, 2024		1,004,994		$	4.91		395,364		$	3.64
Granted		669,014			4.81		419,726			3.26		-			-
Vested		(303,750	)		2.72		(147,495	)		5.17		-			-
Forfeited		-			-		(7,919	)		3.41		-			-
Unvested shares as of December 31, 2023		1,071,099			4.57		417,536			3.26		-			-

The fair value of the vested shares for the ~~year~~years ended December 31, ~~2023~~2024 and ~~three~~2023 ~~months ended December 31, 2022~~ was $12,~~539~~558,~~424~~348 and $~~948~~1,~~358~~539,424, respectively.

11. PROPERTIES AND EQUIPMENT

Assets and liabilities held for sale

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

Impairment

During the year ended December 31, 2024, the Company recorded impairment of $24,061 related to one field. These assets were written down to their fair market value. The remaining $28,612 of impairment expense was related to leasehold that expired.

During the year ended December 31, 2023, the Company recorded no impairment provisions on producing properties and $38,533 on wells that were assigned back to the operator and the Company wrote off.

During the three months ended December 31, 2022, the Company recorded no impairment provisions on producing properties, other than those held for sale discussed above.

During the year ended September 30, 2022, the Company recorded no impairment provisions on producing properties and $14,565 on wells that were assigned back to the operator and the Company wrote off.

A further reduction in natural gas, oil and NGL prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.

Acquisitions

Quarter Ended

Net royalty acres (1)(2)

~~Cash~~Total Purchase Price (1)(3)

~~Number~~% ofProved ~~shares~~/ ~~(3)~~% Unproved

~~Total~~Area ~~Purchase~~of ~~Price (1)(4)~~Interest

~~% Proved / % Unproved~~

~~Area of Interest~~

December 31, 2023

December 31, 2024

325

$4.3 million

72% / 28%

Haynesville / SCOOP

363

$2.5 million

85% / 15%

Haynesville

September 30, 2023

September 30, 2024

974

$13.4 million

81% / 19%

Haynesville / SCOOP

325

$3.0 million

78% / 22%

Haynesville / SCOOP

June 30, 2023

June 30, 2024

151

$1.8 million

29% / 71%

Haynesville / SCOOP

$0.9 million

59% / 41%

Haynesville / SCOOP

March 31, 2023

March 31, 2024

912

$10.8 million

44% / 56%

Haynesville / SCOOP

146

$1.4 million

5% / 95%

SCOOP

December 31, 2022

December 31, 2023

1,256

$14.6 million

32% / 68%

Haynesville / SCOOP

325

$4.3 million

72% / 28%

Haynesville / SCOOP

September 30, 2022

September 30, 2023

924

$13.6 million

73% / 27%

Haynesville / SCOOP

974

$13.4 million

81% / 19%

Haynesville / SCOOP

June 30, 2022

June 30, 2023

938

$9.1 million

58% / 42%

Haynesville / SCOOP

151

$1.8 million

29% / 71%

Haynesville / SCOOP

March 31, 2022

March 31, 2023

825

$9.3 million

63% / 37%

Haynesville / SCOOP

912

$10.8 million

44% / 56%

Haynesville / SCOOP

December 31, 2021

1,884

$11.3 million

1,519,481

$14.8 million

52% / 48%

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.

(3) ~~The~~Table ~~Company’s~~excludes ~~policy~~transaction iscosts toof ~~classify~~$0.1 ~~all~~million ~~costs~~and ~~associated~~$0.3 ~~with~~million, ~~equity~~respectively, ~~issuances~~that aswere ~~financial~~capitalized ~~costs~~during in the ~~Statements~~years ofended ~~Cash~~December ~~Flows~~31, 2024 and 2023.

~~(4)~~All ~~Table~~purchases ~~excludes~~made ~~transaction~~in ~~costs~~fiscal ofyears ~~$0.3~~2023 ~~million, $0.1 million,~~ and ~~$0.7~~2024 ~~million, respectively, that~~ were ~~capitalized~~of ~~during~~mineral ~~the~~and ~~year~~royalty ~~ended~~acreage ~~December 31, 2023, the three months ended December 31, 2022,~~ and ~~the~~were ~~year~~accounted ~~ended~~for ~~September~~as ~~30,~~asset ~~2022~~acquisitions.

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

Divestitures

Quarter Ended	Net mineral acres(1)/ Wellbores(2)	Sale Price (3)	Gain/(Loss) (3)	Location
December 31, 2024
	No significant divestitures
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
December 31, 2023
	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~~(4)~~	OK / TX
December 31, 2022
	4,743 acres	$1.0 million	$0.8 million	OK / TX
September 30, 2022
	87 acres	$0.1 million	$0.1 million	TX
	224 wellbores	$5.3 million	$3.6 million	OK / AR / ND
June 30, 2022
	2,381 acres	$0.5 million	$0.5 million	AR / OK / TX
	27 wellbores	$0.5 million	$0.2 million	OK
March 31, 2022
	7,201 acres	$2.1 million	$2.1 million	NM / TX
December 31, 2021
	692 wellbores	$4.6 million	($2.2) million	AR / 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 immaterial divestitures.

~~(4) Excludes $6.1 million loss recognized as an impairment in the quarter ended December 31, 2022 related to assets and liabilities held for sale as of December 31, 2022.~~63

Asset Retirement Obligations

The following table shows the activity for the ~~year~~years ended December 31, ~~2023,~~2024 ~~the three month period ended December 31, 2022,~~ and ~~the year ended September 30~~2023, ~~2022,~~ relating to the Company’s asset retirement obligations:

	Year Ended December 31,				~~Three Months Ended December 31,~~				~~Year Ended September 30,~~
	2023				2022				2022
	2024				2023
Asset retirement obligations as of beginning of the period	$	1,~~916~~062,~~932~~139		~~(1)~~	$	1,~~901~~916,~~904~~932			$	~~2,836,172~~
Wells acquired or drilled		-				-				-
Wells sold or plugged		(~~898~~8,~~231~~214	)			(5898,~~938~~231	)			~~(1,027,030~~	)
Accretion of discount		43,~~438~~825				2043,~~966~~438				~~92,762~~
Asset retirement obligations as of end of the period	$	1,~~062~~097,~~139~~750			$	1,~~916~~062,~~932~~139		~~(1)~~	$	~~1,901,904~~

(1) The December 31, 2022 balance includes $0.8 million related to the held for sale liabilities at December 31, 2022.

As a non-operator, the Company does not control the plugging of wells in which it has a working interest and is not involved in the negotiation of the terms of the plugging contracts. This estimate relies on information gathered from outside sources as well as relevant information received directly from operators.

12. DERIVATIVES

The Company has entered into fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to fluctuations in the price of natural gas and oil. 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. 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. These contracts cover only a portion of the Company’s natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in prices.

On September 2, 2021, the Company settled all of its derivative contracts consisting of both swaps and costless collars with BOKF, NA dba Bank of Oklahoma (“BOKF”) by paying $8.8 million. On September 3, 2021, the Company entered into new derivative contracts with BP Energy Company (“BP”) that had similar terms to the contracts settled with BOKF and received a payment of $8.8 million from BP. The new derivative contracts consisted of all fixed swap contracts and are secured under the Company’s Credit Facility with Independent Bank. Management concluded that the financing element of the new derivative contracts with BP was other than insignificant due to the off-market terms of the fixed swap price. Due to the financing element, the Company is required to report all cash flows associated with these derivative contracts as “cash flows from financing activities” in the statement of cash flows. This requirement relates to all cash flows from these derivatives and not just the portion of the cash flows relating to the financing element of the derivative. All of these derivatives with a financing element settled in 2023. The Company’s derivative ~~instruments~~contracts ~~have~~that ~~settled~~were orin place and unsettled as of December 31, 2024 will settle based on the terms below.

Derivative contracts in place as of December 31, ~~2023~~2024

Fiscal period	Contract total volume	Index	Contract average price
Natural gas costless collars
2024	1,455,000 Mmbtu	NYMEX Henry Hub	$3.57floor/$5.58ceiling
2025	1,540,000 Mmbtu	NYMEX Henry Hub	$3.27floor/$4.54ceiling
2025	540,000 Mmbtu	NYMEX Henry Hub	$3.21floor/$5.15ceiling
2026	1,245,000 Mmbtu	NYMEX Henry Hub	$3.29floor/$4.19ceiling
Natural gas fixed price swaps
2024	2,172,500 Mmbtu	NYMEX Henry Hub	$3.40
2025	2,200,000 Mmbtu	NYMEX Henry Hub	$3.28
2025	180,000 Mmbtu	NYMEX Henry Hub	$4.16
2026	215,000 Mmbtu	NYMEX Henry Hub	$3.44
Oil Costless Collars
2024	23,450 Bbls	NYMEX WTI	$64.11floor/$76.28ceiling
Remaining unsettled from 2024	500 Bbls	NYMEX WTI	$67.00floor/$77.00ceiling
Oil fixed price swaps
Remaining 2023	5,500 Bbls	NYMEX WTI	$74.48
Remaining unsettled from 2024	5,100 Bbls	NYMEX WTI	$68.42
2024	16,350 Bbls	NYMEX WTI	$67.69
2025	57,800 Bbls	NYMEX WTI	$69.44
2025	7,800 Bbls	NYMEX WTI	$66.03
2026	15,000 Bbls	NYMEX WTI	$68.78

The Company’s fair value of derivative contracts was a net asset of $3,283,587 as of December 31, 2023, and a net liability of $8,561,191 as of September 30, 2022. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Income. Cash receipts 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.64

	For the Year Ended			Three Months Ended			For the Year Ended
	December 31, 2023			December 31, 2022			September 30, 2022
Cash received (paid) on settled derivative contracts:
Natural gas costless collars	$	1,516,535		$	(455,040	)	$	(1,878,250	)
Natural gas fixed price swaps(1)		1,344,580			(1,896,872	)		(9,065,100	)
Oil costless collars		24,330			-			-
Oil fixed price swaps(1)		(328,387	)		(566,127	)		(3,590,210	)
Cash received (paid) on settled derivative contracts, net	$	2,557,058		$	(2,918,039	)	$	(14,533,560	)
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	857,675		$	1,779,405		$	(1,044,958	)
Natural gas fixed price swaps		3,119,388			4,557,865			(1,954,719	)
Oil costless collars		(702	)		(120,032	)		106,157
Oil fixed price swaps		326,170			47,803			594,002
Non-cash gain (loss) on derivative contracts, net	$	4,302,531		$	6,265,041		$	(2,299,518	)
Gains (losses) on derivative contracts, net	$	6,859,589		$	3,347,002		$	(16,833,078	)

The Company’s fair value of derivative contracts was a net liability of $714,408 as of December 31, 2024, and a net asset of $3,283,587 as of December 31, 2023. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Income. Cash receipts 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.


	For the Year Ended December 31,
	2024			2023
Cash received (paid) on settled derivative contracts:
Natural gas costless collars	$	1,877,875		$	1,516,535
Natural gas fixed price swaps(1)		2,616,497			1,344,580
Oil costless collars		(52,530	)		24,330
Oil fixed price swaps(1)		(144,239	)		(328,387	)
Cash received (paid) on settled derivative contracts, net	$	4,297,603		$	2,557,058
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars	$	(1,940,316	)	$	857,675
Natural gas fixed price swaps		(2,138,259	)		3,119,388
Oil costless collars		14,577			(702	)
Oil fixed price swaps		66,003			326,170
Non-cash gain (loss) on derivative contracts, net	$	(3,997,995	)	$	4,302,531
Gains (losses) on derivative contracts, net	$	299,608		$	6,859,589

(1) For the year ended December 31, 2023, ~~three months ended December 31, 2022, and the year ended September 30, 2022,~~ excludes $373,745, ~~$903,461, and $7,522,794, respectively,~~ of cash paid to settle off-market derivative contracts that are not reflected on the Statements of Income. Total cash paid related to off-market derivatives was $560,162, ~~$3,010,661, and $19,260,104, respectively,~~ for the year ended December 31, 2023, ~~three months ended December 31, 2022,~~ and ~~the year ended September 30, 2022 and~~ is reflected in the Financing Activities section of the Statements of Cash Flows. Cash (paid) or received not related to off-market derivatives is reflected in the Operating Activities section of the 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 to offset or not, 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 on the balance sheets. The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's balance sheets at December 31, ~~2023~~2024, and ~~September~~December 3031, ~~2022~~2023. The Company has offset all amounts subject to master netting agreements on the Company's balance sheets at December 31, ~~2023~~2024 and ~~September~~December 3031, ~~2022~~2023.

	12/31/2023												9/30/2022
	12/31/2024												12/31/2023
	Fair Value												Fair Value
	Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-CurrentAssets			Non-CurrentLiabilities			Current Assets			Current Liabilities			Non-CurrentAssets			Non-CurrentLiabilities
Gross amounts recognized	$	3596,~~318,046~~514		$	~~197~~912,~~439~~850		$	~~344~~398,~~614~~894		$	~~181~~796,~~634~~966		$	~~924~~3,~~258~~318,046		$	8197,~~798,237~~439		$	~~124~~344,~~983~~614		$	~~812~~181,~~195~~634
Offsetting adjustments		(~~197~~596,~~439~~514	)		(~~197~~596,~~439~~514	)		(~~181~~398,~~634~~894	)		(~~181~~398,~~634~~894	)		(~~924~~197,~~258~~439	)		(~~924~~197,~~258~~439	)		(~~124~~181,~~983~~634	)		(~~124~~181,~~983~~634	)
Net presentation on Balance Sheets	$	~~3,120,607~~-		$	-316,336		$	~~162,980~~-		$	-398,072		$	-3,120,607		$	~~7,873,979~~-		$	-162,980		$	~~687,212~~-

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.

13. 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: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and commodity options (i.e. price collars).

The Company uses an option pricing valuation model for option derivative contracts that considers various inputs including: future prices, time value, volatility factors, counterparty credit risk and current market and contractual prices for the underlying instruments. The values calculated are then compared to the values given by counterparties for reasonableness.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and unobservable (or less observable) from objective sources (supported by little or no market activity).

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis.


	Fair Value Measurement at December 31, 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	$	-	$	(366,215	)	$	-	$	(366,215	)
Derivative Contracts - Collars	$	-	$	(348,193	)	$	-	$	(348,193	)


	Fair Value Measurement at December 31, 2023
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	1,706,042	$	-	$	1,706,042
Derivative Contracts - Collars	$	-	$	1,577,545	$	-	$	1,577,545

	Fair Value Measurement at September 30, 2022
	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	$	-	$	(7,622,390	)	$	-	$	(7,622,390	)
Derivative Contracts - Collars	$	-	$	(938,801	)	$	-	$	(938,801	)

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

	Year Ended December 31,				~~Three Months Ended December 31,~~				~~Year Ended September 30,~~
	2023				2022				2022
	2024				2023
	Fair Value		Impairment		Fair Value		Impairment		~~Fair Value~~		~~Impairment~~
Producing Properties (a)	$	-	$	-24,061	$	-	$	-	$	-	$	-

(a)

At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment if indicators of impairment existed at such time. If indicators of impairment exist, the Company utilizes estimates of future cash flows of proved properties or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future natural gas, oil and NGL prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off in the amount of $38,533 and $14,565 for the year ended December 31, 2023 and year ended September 30, 2022, respectively. This table excludes impairments on held for sale assets associated with the sale of non-operated working interest wellbores to their fair value in the amount of $6,100,696 for the three months ended December 31, 2022.

At December 31, 2023 and September 30, 2022, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments. Financial instruments include debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving 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.66

68forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off in the amount of $28,612 and $38,533 for the years ended December 31, 2024 and 2023, respectively.

At December 31, 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 debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving 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.

14. INFORMATION ON NATURAL GAS AND OIL PRODUCING ACTIVITIES

The natural gas and oil producing activities of the Company are conducted within the contiguous United States (principally in Oklahoma, Texas, Louisiana, Arkansas and North Dakota) and represent substantially all of the business activities of the Company.

The following table shows sales to major purchasers, by percentage, through various operators/purchasers during the ~~year~~years ended December 31, ~~2023,~~2024 ~~three months ended December 31, 2022,~~ and ~~year ended September 30, 2022~~2023.

	Year Ended			Three Months Ended			Year Ended
	Year Ended December 31,
	December 31, 2023			December 31, 2022			September 30, 2022
	2024			2023
Company A		1417	%		914	%		9	%
Company B		139	%		413	%		2	%
Company C		38	%		73	%		10	%

The loss of any of these major purchasers of natural gas, oil and NGL production could have a material adverse effect on the ability of the Company to produce and sell its natural gas, oil and NGL production.

15. ~~SUBSEQUENT~~OPERATING ~~EVENTS~~SEGMENT

~~Subsequent~~An operating segment is defined as a component of a public entity that engages in business activities and for which discrete financial information and operating results are available and regularly reviewed by the CODM in deciding how to ~~December~~allocate 31resources and assess performance. The Company’s Chief Executive Officer has been determined to be its CODM. The CODM manages the Company’s business activities in a single operating and reportable segment focused on managing the Company’s mineral portfolio and growing its mineral positions in its core focus areas. The financial information and operating results, ~~2023~~including net income and total assets, used by the ~~Company~~CODM ~~entered~~to ~~into~~allocate ~~new~~resources, ~~derivative~~assess ~~contracts~~performance, and make key operating decisions are the same as ~~summarized~~that inwhich is reported by the ~~table~~Company ~~below:~~on the Income Statement and Balance Sheet, and the CODM does not use further disaggregated expenses or assets in deciding how to allocate resources and assess performance.

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - September 2025	55,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.75ceiling
November 2025 - March 2026	100,000 Mmbtu	NYMEX Henry Hub	$3.50floor/$4.85ceiling
Natural gas fixed price swaps
January - March 2025	50,000 Mmbtu	NYMEX Henry Hub	$3.51
April - October 2025	100,000 Mmbtu	NYMEX Henry Hub	$3.28
Oil costless collars
June - September 2024	500 Bbls	NYMEX WTI	$70.00floor/$78.10ceiling
October - December 2024	500 Bbls	NYMEX WTI	$67.00floor/$77.00ceiling
Oil fixed price swaps
July - October 2024	1,500 Bbls	NYMEX WTI	$69.50
November - December 2024	2,000 Bbls	NYMEX WTI	$69.50
January - March 2025	500 Bbls	NYMEX WTI	$69.50
January - June 2025	2,000 Bbls	NYMEX WTI	$70.90
April - June 2025	750 Bbls	NYMEX WTI	$69.50
July - September 2025	500 Bbls	NYMEX WTI	$69.50
July - December 2025	1,500 Bbls	NYMEX WTI	$68.90

16. SUBSEQUENT EVENTS

69Subsequent to December 31, 2024, the Company closed on the divestiture of 165,326 net mineral acres for approximately $8.0 million and paid down an additional $9.8 million in debt. Additionally, the Company announced a $0.04 per share quarterly dividend, payable on March 28, 2025, to stockholders of record on March 17, 2025.

PHX Minerals Inc.

Supplementary Information

SUPPLEMENTARY INFORMATION ON NATURAL GAS, OIL AND NGL RESERVES (UNAUDITED)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of natural gas and oil properties and related accumulated depreciation, depletion and amortization as of December 31, ~~2023~~2024 and ~~September~~December 3031, ~~2022~~2023 is as follows:

	December 31,			~~September~~December 3031,
	2023			2022
	2024			2023
Producing properties	$	~~209~~223,~~082~~043,~~847~~942		$	~~248~~209,~~978~~082,~~928~~847
Non-producing minerals		5650,~~670~~156,~~341~~199			5056,~~032~~670,~~539~~341
Non-producing leasehold		21,~~150~~650,~~104~~712			12,~~746~~150,~~797~~104
		267,903,292			300,758,264
		274,850,853			267,903,292
Accumulated depreciation, depletion and amortization		(~~113~~122,~~506~~030,~~928~~459	)		(~~168~~113,~~349~~506,~~542~~928	)
Net capitalized costs	$	~~154~~152,~~396~~820,~~364~~394		$	~~132~~154,~~408~~396,~~722~~364

Costs Incurred

For the ~~year~~years ended December 31, ~~2023,~~2024 ~~three months ended December 31, 2022,~~ and ~~year ended September 30~~2023, ~~2022,~~ the Company incurred the following costs in natural gas and oil producing activities:

Year Ended

Three Months Ended

Year Ended

Year Ended December 31,

December 31, 2023

December 31, 2022

September 30, 2022

2024

2023

Property acquisition costs

307,~~435~~834,~~595~~849

1430,~~637~~435,~~290~~595

~~46,224,928~~

Development costs

~~113~~94,~~967~~022

36113,~~801~~967

~~156,752~~

307,~~549~~928,~~562~~871

1430,~~674~~549,~~091~~562

~~46,381,680~~

7068

Estimated Quantities of Proved Natural Gas, Oil and NGL Reserves

The following unaudited information regarding the Company’s natural gas, oil and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved natural gas and oil reserves are those quantities of natural gas and oil 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 that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engin

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