PHX MINERALS INC. 10-K

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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 the fiscal year ended DECEMBER 31, 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 Act). yes ☐ no ☒

The aggregate market value of the voting stock held by non-affiliates of the registrant, computed by using the $3.26 per share closing price of registrant's Common Stock, as reported by the New York Stock Exchange at June 30, 2024, the last day of the Registrant’s most recently completed second fiscal quarter, was $113,897,450.

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

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	20
Item 1C	Cybersecurity	20
Item 2	Properties	21
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	42
Item 8	Financial Statements and Supplementary Data	43
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	73
Item 9A	Controls and Procedures	73
Item 9B	Other Information	73
Item 9C	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	73

PART III
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	98
Item 16	Form 10-K Summary	100

Special Note Regarding Forward Looking Statements

This Annual Report on Form 10-K for the fiscal year ended December 31, 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.

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.
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.
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.


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.
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 unless the context requires otherwise.

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, 2024 and December 31, 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 provides 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, 2024, we owned approximately 239,909 perpetual mineral acres, as detailed in the table below:


Play	Net Acres		% Producing	% Leased But Not Producing	% Unleased
SCOOP		8,475	71%	7%	22%
STACK		5,828	91%	0%	9%
Arkoma Stack		9,794	76%	0%	24%
Haynesville		5,238	100%	0%	0%
Bakken /Three Forks		3,120	89%	0%	11%
Fayetteville		9,867	73%	0%	27%
Other		197,587	18%	0%	82%
Total:		239,909	29%	1%	70%

Approximately 30% of our net minerals are currently under lease with an operator of which 29% have a producing well. Additionally, approximately 70% 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 own working interests, royalty interests or both in 6,958 producing natural gas and oil wells and 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:

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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, 2024, we owned approximately 239,909 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 6,958 producing natural gas and oil wells and 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, 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 2024, production on our acreage averaged 26,890 Mcfed with approximately 81%, 11% 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 years ended December 31, 2024 and December 31, 2023.

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

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, 2024, we had 18 full-time employees, including our executive officers, and did not have any part-time employees.

Executive Officers and Key Management

Chad L. Stephens, age 69, 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 49, has served as our Chief Financial Officer and 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 39, 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 17 years of accounting experience.

Danielle D. Mezo, age 37, 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 15 years of experience in the oil and gas industry.

Kenna D. Clapp, age 38, 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 15 years of land experience across multiple basins including Haynesville, Eagleford, Mid-Continent and Barnett.

Taylor G. McClain, age 36, joined the Company as Vice President of Geology in February 2024. Prior to joining the Company, Mr. McClain served 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 11 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 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:

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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;

•

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 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:

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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

•

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. 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:

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unexpected drilling conditions;

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title problems;

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pressure or irregularities in formations;

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equipment failures or accidents;

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fires, explosions, blowouts and surface cratering;

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

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adverse weather conditions;

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environmental hazards or liabilities;

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lack of water disposal facilities;

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governmental regulations;

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

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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:

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

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

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

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

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mistaken assumptions about the overall cost of equity or debt;

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

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

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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:

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future natural gas, oil and NGL prices;

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unexpected complications from offset well development;

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production rates;

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

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interpretation of subsurface conditions including geological and geophysical data;

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potential for water encroachment or mechanical failures;

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

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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.

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, 2024, we had a balance of $29,500,000 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:

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

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

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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;

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

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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.

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, 2024 was a net liability of $714,408.

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 net income as determined 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 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.

Further revisions to U.S. tax law, such as any increase in corporate income tax 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.

The fluid produced from the fractured 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.

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.

The regulatory environment surrounding greenhouse gas emissions is evolving under the new administration. On January 20, 2025, President Trump issued the “Unleashing American Energy” executive Order (EO 3418), directing federal agencies to review and potentially revise or rescind regulations related to methane emissions and other climate policies affecting the oil and gas industry. This includes a review of the EPA Methane Rule that became effective on May 7, 2024. The EPA Methane Rule established new compliance requirements for emissions monitoring, equipment standards, and operational 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, participating countries signed a non-binding agreement calling for a transition away from fossil fuels, expansion of renewable energy capacity, and an acceleration of emissions reduction efforts.

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.

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, 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 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:

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our return on capital used in drilling or property acquisition;

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our production and reserve growth rates;

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capital required to workover or recomplete wells;

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

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compliance with environmental, safety and other regulations;

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lease operating expenses; and

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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:

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well blowouts, cratering, explosions and human related accidents;

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mechanical, equipment and pipe failures;

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adverse weather conditions, earthquakes and other natural disasters;

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civil disturbances and terrorist activities;

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natural gas, oil and NGL price reductions;

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

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title problems;

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limited availability of financing;

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marketing related infrastructure, transportation and processing limitations; and

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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.

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.

As 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.

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 $0.04 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

Risk Management and Strategy

Cybersecurity 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.

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 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, 2024, our principal properties consisted of (i) perpetual ownership of 239,909 net mineral acres, held principally in Oklahoma, Texas, Louisiana, North Dakota and Arkansas; (ii) leases on 13,290 net acres primarily in Oklahoma; and (iii) working interests, royalty interests or both in 6,958 producing natural gas and oil wells and 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

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, 2024.


State	Net Acres		Gross Acres		Net Acres Producing (1)		Gross Acres Producing (1)		Net Acres Leased to Others (2)		Gross Acres Leased to Others (2)		Net Acres Unleased (3)		Gross Acres Unleased (3)
Oklahoma		106,409		1,042,744		48,913		455,866		1,530		11,801		55,966		575,077
Texas		30,395		252,419		5,154		78,704		277		2,240		24,964		171,475
Louisiana		3,971		40,426		3,971		40,426		-		-		-		-
North Dakota		14,316		90,357		2,786		26,744		-		-		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		-		-		71,988		249,885
Total		239,909		1,738,948		69,136		641,677		1,807		14,041		168,966		1,083,230

(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 2028, and net leased acres held by production related to leasehold as of December 31, 2024.


			Net Acres Expiring
State	Net Acres		2024		2025		2026		2027		2028		Net Acres Held by Production
Oklahoma		10,025		-		-		-		-		-		10,025
Texas		367		-		-		-		-		-		367
Other		1,084		-		-		-		-		-		1,084
Total		11,476		-		-		-		-		-		11,476

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


			Net Acres Expiring
State	Net Acres		2024		2025		2026		2027		2028		Net Acres Held by Production
Louisiana		274		-		-		-		-		-		274
Oklahoma		1,509		-		-		-		-		-		1,509
Texas		31		-		-		-		-		-		31
Total		1,814		-		-		-		-		-		1,814

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, 2024, compared to December 31, 2023, using prices and costs under existing economic conditions.

Proved reserves are located onshore within the contiguous United States and are principally made up of small interests in 6,958 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

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

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

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

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

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

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 year ended December 31, 2024, our net total proved reserves decreased by 7.5 Bcfe, as compared to December 31, 2023. The decrease in total proved reserves from December 31, 2023 to December 31, 2024 is attributable to a combination of the following factors:

•

Production of 9.8 Bcfe from our natural gas and oil properties.

•

Negative pricing revisions of 4.9 Bcfe primarily due to natural gas and oil wells reaching their economic limits earlier than was projected in 2023 due to lower commodity prices.

•

Negative performance revisions of 0.3 Bcfe principally due to a pad of working interest wells where production did not return to prior rates post workover.

•

Reserve 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

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 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 prior to December 31 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, 2024 and 2023 were as follows: $2.05 for natural gas, $73.48 for oil and $20.97 for NGL for the fiscal year ended December 31, 2024; and $2.67 for natural gas, $76.85 for oil and $21.98 for NGL for the fiscal year ended December 31, 2023. 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
	12/31/2024			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.

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, 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

Average Sales Prices and Production Costs

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


	Year Ended		Year Ended
Average Sales Price	12/31/2024		12/31/2023
Per Mcf, Natural Gas	$	2.19	$	2.61
Per Bbl, Oil	$	74.59	$	76.76
Per Bbl, NGL	$	21.95	$	22.18
Per Mcfe	$	3.42	$	3.90


	Year Ended		Year Ended
Average Production (lifting) Costs	12/31/2024		12/31/2023
(Per Total Mcfe)
Well Operating Costs (1)	$	0.58	$	0.56
Production Taxes (2)		0.17		0.20
	$	0.75	$	0.76

(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, 2024, approximately 89% 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, 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		50		2.03		281		10.61		4,407		28.38		4,738
Oil		20		1.28		78		2.25		2,122		10.85		2,220
Total		70		3.31		359		12.86		6,529		39.23		6,958

Our average interest in royalty interest only wells is 0.601%. Our average interest in working interest wells is 3.226% working interest and 3.7699% 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, 2024, we owned 641,677 gross (69,136 net) developed mineral acres and leased 189,106 gross (13,290 net) developed acres.

Undeveloped Acreage

As of December 31, 2024, we owned 1,097,271 gross and 170,773 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 Interest Wells		Royalty Interest Wells		Working Interest Wells
Development Wells
Years ended:
December 31, 2024		-		1.110635		-
December 31, 2023		-		0.995776		-

Exploratory Wells
Years ended:
December 31, 2024		-		-		-
December 31, 2023		-		-		-

Purchased Wells
Years ended:
December 31, 2024		-		0.223966		-
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, 2024, in which we own either a working interest, a royalty interest or both. These wells were not producing at December 31, 2024.


	Gross Working Interest Wells		Net Working Interest Wells		Gross Royalty Only Wells		Total Net Royalty Interest Wells
Natural Gas		-		-		76		0.35
Oil		-		-		74		0.25
Total		-		-		150		0.60

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, 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, 2024, we were authorized to issue an aggregate of 75,000,000 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, 2019, and the relative performance of such investment is tracked through and including December 31, 2024. This table is not intended to forecast future performance of our Common Stock.

Record Holders

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

Dividends

During 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.

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, 2024, we repurchased 212,391 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, 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	212,391(1)	$3.79	–	$	1,500,000
Total	212,391	$3.79	–	$	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 2024 and 2023 items and year-to-year comparisons between December 31, 2024 and December 31, 2023. Discussions of 2023 items and year-to-year comparisons between fiscal year 2023 and 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 December 31, 2023.

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 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 2024 decreased 2% and 3%, respectively, from that of fiscal year 2023. The 2024 fiscal year’s lower natural gas, oil and NGL prices (as discussed below) and the overall production changes noted above resulted in a 8% decrease in revenues from the sale of natural gas, oil and NGL in fiscal 2024.

Our proved natural gas, oil and NGL reserves decreased to 63.7 Bcfe in 2024, compared to 71.2 Bcfe in 2023, a decrease of approximately 7.5 Bcfe, or 11%. The decrease was primarily due to pricing revisions and production, which was not entirely offset by additions due to reduced permitting activity in the Haynesville shale as a result of lower gas prices, and to a far lesser extent, performance revisions. This was partially offset by the extensions of 5.0 Bcfe and acquisitions 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.

As of December 31, 2024, we owned an average 0.4% net revenue interest, consisting of all royalty interest, in 150 wells that were being drilled or awaiting completion.

Results of Operations

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


	For the Year Ended December 31,
			Percent
	2024	2023	Incr. or (Decr.)
Production:
Natural Gas (Mcf)	7,969,948	7,457,084	7%
Oil (Bbls)	178,357	182,916	(2%)
NGL (Bbls)	133,609	137,484	(3%)
Mcfe	9,841,746	9,379,484	5%
Average Sales Price:
Natural Gas (per Mcf)	$2.19	$2.61	(16%)
Oil (per Bbl)	$74.59	$76.76	(3%)
NGL (per Bbl)	$21.95	$22.18	(1%)
Mcfe	$3.42	$3.90	(12%)

Production by quarter for the years ended December 31, 2024 and 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

Fiscal Year 2024 Compared to Fiscal Year 2023

Overview

Revenues decreased in fiscal 2024 primarily due to lower natural gas, oil and NGL sales and a decrease in gains on derivative contracts. We recorded net income of $2,321,866, or $0.06 per diluted share, in fiscal 2024, compared to net income of $13,920,800, or $0.39 per diluted share, in fiscal 2023 . Expenses increased in fiscal 2024, primarily the result of increases in DD&A, transportation, gathering and marketing expenses, and interest expense, partially offset by decreases in LOE, production taxes, and G&A.

Natural Gas, Oil and NGL Sales


	For the Year Ended December 31,
					Percent
	2024		2023		Incr. or (Decr.)
Natural gas, oil and NGL sales	$	33,690,652	$	36,536,285	(8%)

The decrease was due to decreased natural gas, oil and NGL prices of 16%, 3% and 1%, respectively, combined with lower oil and NGL volumes of 2% and 3%, respectively, partially offset by higher natural gas volumes of 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
	2024			2023		Incr. or (Decr.)
Cash received (paid) on settled derivative contracts:
Cash received (paid) on settled derivative contracts, net(1)	$	4,297,603		$	2,557,058	68%
Non-cash gain (loss) on derivative contracts:
Non-cash gain (loss) on derivative contracts, net	$	(3,997,995	)	$	4,302,531	(193%)
Gains (losses) on derivative contracts, net	$	299,608		$	6,859,589	(96%)

	As of December 31,
	2024			2023
Fair value of derivative contracts
Net asset (net liability)	$	(714,408	)	$	3,283,587	(122%)

(1) Excludes $373,745 of cash paid to settle off-market derivative contracts that are not reflected on the Statements of Income for the year ended December 31, 2023. 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, 2024 pricing relative to the strike price on open derivative contracts.

Our natural gas and oil fixed price swaps in place at December 31, 2024 had expiration dates through September 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
	2024		2023		Incr. or (Decr.)
Lease operating expenses	$	1,228,813	$	1,598,944	(23%)
Lease operating expenses per working interest MCFE	$	1.14	$	1.27	(10%)
Lease operating expenses per total MCFE	$	0.12	$	0.17	(29%)

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 $370,131, or 23%, in fiscal 2024 compared to fiscal 2023. The decrease in LOE was principally the result of the divestiture of working interest properties in January 2023.

Transportation, Gathering and Marketing


	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%

Transportation, 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
	2024			2023			Incr. or (Decr.)
Production and ad valorem taxes	$	1,703,305		$	1,881,737		(9%)
Production and ad valorem taxes as % of sales		5.1	%		5.2	%	(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 $178,432, or 9%, in fiscal 2024 compared to fiscal 2023. The decrease in amount was primarily the result of an 8% decrease in natural gas, oil and NGL sales during fiscal 2024.

Depreciation, Depletion and Amortization (DD&A)


	For the Year Ended December 31,
					Percent
	2024		2023		Incr. or (Decr.)
Depreciation, depletion and amortization	$	9,606,444	$	8,566,185	12%
Depreciation, depletion and amortization per MCFE	$	0.98	$	0.91	8%

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 $1,040,259, or 12%, in fiscal 2024 compared to fiscal 2023, of which $619,613 of the increase resulted from a $0.07 increase in the DD&A rate per Mcfe and $420,646 of the increase resulted from production increasing 5% in fiscal 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 2024.

Provision for Impairment

During fiscal 2024 impairment of $24,061 was related to one field. These assets were written down to their fair market value as required by GAAP. The remaining $28,612 was related to leasehold that expired. During fiscal 2023, impairment of $38,533 was related to working interest wells in which we assigned our interests to the operator.

Interest Expense


	For the Year Ended December 31,
					Percent
	2024		2023		Incr. or (Decr.)
Interest expense	$	2,563,268	$	2,362,393	9%
Weighted average debt outstanding	$	29,637,295	$	27,754,247	7%

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

General and Administrative Costs (G&A)


	For the Year Ended December 31,
					Percent
	2024		2023		Incr. or (Decr.)
General and administrative costs	$	11,670,328	$	11,970,182	(3%)

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

Losses (Gains) on Asset Sales and Other


	For the Year Ended December 31,
						Percent
	2024		2023			Incr. or (Decr.)
Losses (gains) on asset sales and other	$	83,799	$	(4,285,170	)	102%

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

Provision for Income Taxes


	For the Year Ended December 31,
							Percent
	2024			2023			Incr. or (Decr.)

Provision for income taxes	$	827,187		$	4,735,460		(83%)
Effective tax rate		26	%		25	%	4%

Provision for income taxes changed $3,908,273, from a $4,735,460 provision in fiscal 2023 to a $827,187 provision in the year ended December 31, 2024. The change in provision for income taxes resulted primarily due to a decrease in pre-tax income.

Liquidity and Capital Resources

We had positive working capital (current assets less current liabilities excluding current derivatives) of $6,637,524 at December 31, 2024, compared to positive working capital of $5,029,698 at December 31, 2023.

Liquidity

Cash and cash equivalents were $2,242,102 as of December 31, 2024, compared to $806,254 at December 31, 2023, an increase of $1,435,848. Cash flows for the years ended December 31, 2024 and December 31, 2023, are summarized as follows:


	For the Year Ended December 31,
Net cash provided (used) by:
	2024			2023			Change
Operating activities	$	18,077,853		$	24,171,139		$	(6,093,286	)
Investing activities		(7,357,395	)		(20,447,305	)		13,089,910
Financing activities		(9,284,610	)		(5,033,232	)		(4,251,378	)
Increase (decrease) in cash and cash equivalents	$	1,435,848		$	(1,309,398	)	$	2,745,246

Operating activities:

Net cash provided by operating activities decreased $6,093,286 during the year ended December 31, 2024, as compared to the year ended December 31, 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 $9,292,678;

•

increased payments for interest expense of $205,728; and

•

decreased lease bonus receipts of $616,524.

partially offset by:

•

increased net receipts on derivative contracts of $1,740,545;

•

decreased field operating expenses of $321,517;

•

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

•

decreased payments for G&A and other expense of $814,284.

Investing activities:

Net cash used in investing activities decreased $13,089,910 during the year ended December 31, 2024, as compared to December 31, 2023, primarily as a result of the following:

•

lower acquisition activity decreased our expenditures by $21,938,533; and

•

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

partially offset by:

•

lower proceeds received from the sale of assets of $9,087,027.

Financing activities:

Net cash used in financing activities increased $4,251,378 during the year ended December 31, 2024, as compared to December 31, 2023, primarily as a result of the following:

•

increased net payments on debt of $2,700,000;

•

increased dividend payments by $1,709,181 during 2024; and

•

increased purchases of treasury stock by $402,359;

partially offset by:

•

decreased net cash payments on off-market derivative contracts of $560,162.

Capital Resources

We had no capital expenditures to drill and complete wells in the year ended December 31, 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)	Total Purchase Price (1)	Area of Interest

December 31, 2024
	363	$2.5 million	Haynesville
September 30, 2024
	325	$3.0 million	Haynesville / SCOOP
June 30, 2024
	96	$0.9 million	Haynesville / SCOOP
March 31, 2024
	146	$1.4 million	SCOOP
December 31, 2023
	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.

We received lease bonus payments during fiscal 2024 totaling approximately $0.6 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, 2024
Cash provided by operating activities	$	18,077,853
Cash provided (used) by:

Capital expenditures - acquisitions		(7,796,983	)
Capital expenditures - legacy working interest wells and furniture and fixtures		(87,579	)
Quarterly dividends		(5,229,547	)
Treasury stock purchases		(805,063	)
Net borrowings (payments) on credit facility		(3,250,000	)
Net proceeds from sales of assets		527,167
Net cash used		(16,642,005	)
Net increase (decrease) in cash	$	1,435,848

Outstanding borrowings under our Credit Facility at December 31, 2024 were $29,500,000.

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 $20,500,000 at December 31, 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.

September 1, 2028. Borrowings under the revolving loan are due 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 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, 2024, the effective rate was 7.88%. 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 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

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, 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, 2028. Borrowings under the revolving loan are due 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 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, 2024, the effective rate was 7.88%. 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.

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, 2024, we were in compliance with the covenants of the Credit Facility, had $29,500,000 outstanding and had $20,500,000 of borrowing base availability under the Credit Facility.

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

Year Ended December 31,