EDGAR 10-K Filing

Company CIK: 315131
Filing Year: 2025
Filename: 315131_10-K_2025_0000950170-25-037978.json

---

ITEM 1. BUSINESS
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:
oIncreasing 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;
oUtilizing in-house geology and engineering expertise as a competitive advantage;
oProactively leasing or monetizing our unleased mineral holdings; and
oHigh-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:
oMaintaining a conservative amount of debt outstanding with ample liquidity to ensure our ability to successfully operate in all business and commodity environments; and
oHedging a portion of our future natural gas and oil prices to manage commodity price risk and protect our cash flow.
Our Business Strengths
We believe the following attributes position us to achieve our objectives:
•Focusing on Perpetual Mineral Fee Ownership. Our strategic decision to focus on mineral ownership provides us with the perpetual option to benefit from future development and technology. We are focused on generating meaningful revenues through lease bonuses and royalty interests, and our royalty revenue as a percentage of total revenue continues to increase. As of December 31, 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.
Year Ended December 31,
Company A
%
%
Company B
%
%
Company C
%
%
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
ITEM 1A. Risk Factors
In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. If any of the following risk factors should occur, our financial condition could be materially impacted, and the holders of our securities could lose part or all of their investment in the Company. As the owner of mineral fee interests and non-operating working interests, we do not operate any natural gas and oil properties, and we do not have any employees or contractors in the field. As such, the risks associated with natural gas and oil operations affect us indirectly and typically through our non-operating working interests as we proportionately share in the costs of operating such wells. The risk factors described below are not exhaustive, and investors are encouraged to perform their own investigation with respect to our Company and our business. Investors should also read the other information in this Form 10-K, including the financial statements and related notes.
Risks Related to our Business
The volatility of natural gas and oil prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.
The supply of and demand for natural gas, oil and NGL impact the revenues we realize in connection with the sale of these commodities and, in turn, materially affect our financial results. Our revenues, operating results, cash available for distribution and the carrying value of our natural gas and oil properties depend significantly upon the prevailing prices for natural gas, oil and NGL. Natural gas, oil and NGL prices have historically been, and will likely continue to be, volatile. The prices for natural gas, oil and NGL are subject to wide fluctuation in response to a number of factors beyond our control, including:
•domestic and worldwide economic conditions;
•economic, political, regulatory and tax developments;
•market uncertainty;
•changes in the supply of and demand for natural gas, oil and NGL, both domestically and abroad;
•the impacts and effects of public health crises, pandemics and epidemics;
•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:
•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:
•unexpected drilling conditions;
•title problems;
•pressure or irregularities in formations;
•equipment failures or accidents;
•fires, explosions, blowouts and surface cratering;
•lack of availability to market production via pipelines or other transportation;
•adverse weather conditions;
•environmental hazards or liabilities;
•lack of water disposal facilities;
•governmental regulations;
•cost and availability of drilling rigs, equipment and services; and
•expected sales price to be received for natural gas, oil or NGL produced from the wells.
Competition for acquisitions of mineral interests may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold properties, which could result in unforeseen operating difficulties. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business or assets into our existing operations. The process of integrating acquired businesses or assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.
No assurance can be given that we will be able to identify suitable mineral interest acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and cash available for distribution. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for distribution.
Any acquisition of additional mineral and royalty interests that we complete will be subject to substantial risks.
Any acquisition involves potential risks, including, among other things:
•the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses and costs;
•a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
•a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
•the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
•mistaken assumptions about the overall cost of equity or debt;
•our ability to obtain satisfactory title to the assets we acquire;
•an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and
•the occurrence of other significant changes, such as impairment of natural gas and oil properties, goodwill or other intangible assets, asset devaluation or restructuring charges.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.
It is not possible to measure underground accumulations of natural gas, oil and NGL with precision. Natural gas, oil and NGL reserve engineering requires subjective estimates of underground accumulations of natural gas, oil and NGL using assumptions concerning future prices of these commodities, future production levels and operating and development costs. In estimating our reserves, we and our Independent Consulting Petroleum Engineer must make various assumptions with respect to many matters that may prove to be incorrect, including:
•future natural gas, oil and NGL prices;
•unexpected complications from offset well development;
•production rates;
•reservoir pressures, decline rates, drainage areas and reservoir limits;
•interpretation of subsurface conditions including geological and geophysical data;
•potential for water encroachment or mechanical failures;
•levels and timing of capital expenditures, lease operating expenses, production taxes and income taxes, and availability of funds for such expenditures; and
•effects of government regulation.
If any of these assumptions prove to be incorrect, our estimates of reserves, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.
Our standardized measure of oil and natural gas reserves is calculated using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-month period prior to fiscal year end. These prices and the operating costs in effect as of the date of estimation are held flat over the life of the properties. Production and income tax expenses are deducted from this calculation of future estimated development, with the result
discounted at 10% per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.
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:
•cash flows from operating activities required to service indebtedness may not be available for other purposes;
•covenants contained in the Credit Agreement may limit our ability to borrow additional funds, pay dividends and make certain investments;
•any limitation on the borrowing of additional funds may affect our ability to fund capital projects and may also affect how we will be able to react to economic and industry changes;
•a significant increase in the interest rate under the Credit Facility will limit funds available for other purposes; and
•changes in prevailing interest rates may affect our capability to meet our interest payments, as the Credit Facility bears interest at floating rates.
The borrowing base of our Credit Facility is subject to periodic redetermination and is based in part on natural gas, oil and NGL prices. A lowering of our borrowing base because of lower natural gas, oil or NGL prices, or for other reasons, could require us to repay indebtedness in excess of the established borrowing base, or we might need to further secure the debt with additional collateral. Our ability to meet any debt obligations depends on our future performance. General business, economic, financial and
product pricing conditions, along with other factors, affect our future performance, and many of these factors are beyond our control. In addition, our failure to comply with the restrictive covenants relating to our Credit Facility could result in a default, which might adversely affect our business, financial condition, results of operations and cash flows.
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:
•our return on capital used in drilling or property acquisition;
•our production and reserve growth rates;
•capital required to workover or recomplete wells;
•success and timing of drilling, development and exploitation activities on our properties;
•compliance with environmental, safety and other regulations;
•lease operating expenses; and
•plugging and abandonment costs, including well-site restorations.
Dependency on each operator’s judgment, expertise and financial resources could result in unexpected future costs, lost revenues and/or capital restrictions, to the extent they would cumulatively have a material adverse effect on our financial position and results of operations.
The natural gas and oil drilling and producing operations of our third-party operators involve various risks.
Because we do not operate our properties, our business relies heavily upon our third-party operators and their operational effectiveness. Through our third-party operators, we are subject to all the risks normally incident to the operation and development of natural gas and oil properties, including:
•well blowouts, cratering, explosions and human related accidents;
•mechanical, equipment and pipe failures;
•adverse weather conditions, earthquakes and other natural disasters;
•civil disturbances and terrorist activities;
•natural gas, oil and NGL price reductions;
•environmental risks stemming from the use, production, handling and disposal of water, waste materials, hydrocarbons and other substances into the air, soil or water;
•title problems;
•limited availability of financing;
•marketing related infrastructure, transportation and processing limitations; and
•regulatory compliance issues.
As a non-operator, we are also dependent on third-party operators and the contractors they hire for operational safety, environmental safety and compliance with regulations of governmental authorities.
We maintain insurance against many potential losses or liabilities arising from well operations in accordance with customary industry practices and in amounts believed by management to be prudent. However, this insurance does not protect us against all risks. For example, we do not maintain insurance for business interruption, acts of war or terrorism. Additionally, pollution and environmental risks generally are not fully insurable. These risks could give rise to significant uninsured costs that might have a material adverse effect on our business condition and financial results.
We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.
A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell natural gas or oil at the same price as the operator it replaced.
Shortages of oilfield equipment, services, qualified personnel and resulting cost increases could adversely affect results of operations.
The demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas, oil and NGL prices, resulting in periodic shortages. When demand for rigs and equipment increases due to an increase in the number of wells being drilled, there have been shortages of drilling rigs, hydraulic fracturing equipment and personnel and other oilfield equipment. Higher natural gas, oil and NGL prices generally stimulate increased demand for, and result in increased prices of, drilling rigs, crews and associated supplies, equipment and services. These shortages or price increases could negatively affect the ability to drill wells and conduct ordinary operations by the operators of our wells, resulting in an adverse effect on our financial condition, cash flow and operating results.
The marketability of natural gas and oil production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.
The marketability of our or our operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, the shipment of our or our operators’ natural gas and oil on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations and cash distributions to stockholders. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation-including regulation of oil production, transportation and pipeline safety-as well as by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.
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. UNRESOLVED STAFF COMMENTS
ITEM 1B. Staff Comments
None

---

ITEM 2. PROPERTIES
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
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. In recent years, a few insignificant challenges have been made against our fee title to our acreage.
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
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
Net Acres
Held by
Production
Oklahoma
10,025
-
-
-
-
-
10,025
Texas
-
-
-
-
-
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
Net Acres
Held by
Production
Louisiana
-
-
-
-
-
Oklahoma
1,509
-
-
-
-
-
1,509
Texas
-
-
-
-
-
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
2.03
10.61
4,407
28.38
4,738
Oil
1.28
2.25
2,122
10.85
2,220
Total
3.31
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
-
-
0.35
Oil
-
-
0.25
Total
-
-
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
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 DISCLOSURE
ITEM 4. Mine Safety Disclosures
Not applicable.
PART II

---

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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. SELECTED FINANCIAL DATA
ITEM 6. Reserved

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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
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
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
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,
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
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
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
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
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
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
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
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
Incr. or (Decr.)
Provision for income taxes
$
827,187
$
4,735,460
(83%)
Effective tax rate
%
%
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:
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
$2.5 million
Haynesville
September 30, 2024
$3.0 million
Haynesville / SCOOP
June 30, 2024
$0.9 million
Haynesville / SCOOP
March 31, 2024
$1.4 million
SCOOP
December 31, 2023
$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.
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%. 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:
Payments due by period
Contractual Obligations
Less than
More than
and Commitments
Total
1 Year
1-3 Years
3-5 Years
5 Years
Long-term debt obligations
$
29,500,000
$
-
$
-
$
29,500,000
$
-
Building lease
$
734,572
$
270,845
$
463,727
$
-
$
-
Our building leases are accounted for as operating leases, and a related operating lease right-of-use (”ROU”) asset and operating lease liability has been recognized on our balance sheets.
At December 31, 2024, our derivative contracts were in a net liability position of $714,408. The ultimate settlement amounts of the derivative contracts are unknown because they are subject to continuing market risk. Please read Item 7A - “Quantitative and Qualitative Disclosures about Market Risk” and Note 12 to the financial statements included in Item 8 - “Financial Statements and Supplementary Data” for additional information regarding our derivative contracts.
As of December 31, 2024, our estimate for asset retirement obligations was $1,097,750. Asset retirement obligations represent our share of the future expenditures to plug and abandon the wells in which we own a working interest at the end of their economic lives. These amounts were not included in the schedule above due to the uncertainty of timing of the obligations. Please read Note 11 to the financial statements included in Item 8 - “Financial Statements and Supplementary Data” for additional information regarding our asset retirement obligations.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements during 2024 and 2023, and we currently do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future effect on our financial condition, or result in changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
CRITICAL ACCOUNTING POLICIES
Preparation of financial statements in conformity with GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change our reported cash flows or liquidity. Existing rules must be interpreted, and judgments made on how the specifics of a given rule apply to the Company.
The more significant reporting areas impacted by management’s judgments and estimates include: natural gas, crude oil and NGL reserve estimation; derivative contracts; impairment of assets; natural gas, oil and NGL sales revenue accruals; and provision for income taxes. Management’s judgments and estimates are based on information available from both internal and external sources, including engineers, geologists, consultants and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. The natural gas, oil and NGL sales revenue accrual is particularly subject to estimate inaccuracies due to our status as a non-operator on all of our properties. As such, production and price information obtained from well operators is substantially delayed. This causes the estimation of recent production and prices used in the natural gas, oil and NGL revenue accrual to be subject to future change.
Natural Gas, Oil and NGL Reserves
Management considers the estimation of our natural gas, crude oil and NGL reserves to be the most significant of our judgments and estimates. These estimates affect the unaudited standardized measure disclosures included in Supplementary Information to the financial statements in Item 8 - “Financial Statements and Supplementary Data” as well as DD&A and impairment calculations for working interest properties. Changes in natural gas, crude oil and NGL reserve estimates affect our calculation of DD&A, asset retirement obligations and assessment of the need for asset impairments. Our Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares our estimates of natural gas, crude oil and NGL reserves on an annual basis. These estimates are based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, we update the reserve calculations utilizing prices which are updated through the current period. In accordance with SEC rules, our reserve estimates were based on average individual product prices during the 12-month period prior to December 31 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. Based on our 2024 DD&A, a 10% change in the DD&A rate per Mcfe would result in a corresponding $960,644 annual change in DD&A expense. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future natural gas, crude oil and NGL pricing assumptions are used by management to prepare estimates of natural gas, crude oil and NGL reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.
Successful Efforts Method of Accounting
We have elected to utilize the successful efforts method of accounting for our natural gas and oil exploration and development activities. This means exploration expenses, including geological and geophysical costs, non-producing lease
impairment, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by property using the unit-of-production method for working interest wells (the ratio of natural gas, oil and NGL volumes produced to total proved or proved developed reserves is used to amortize the remaining asset basis on each producing property) as natural gas, oil and NGL is produced. Our exploratory wells are all onshore in the continental United States and primarily located in the Mid-Continent area. Expenditures on exploratory wells comprise less than 5% of our total expenditures for natural gas and oil properties. This accounting method may yield significantly different operating results than the full cost method.
Derivative Contracts
We have entered into costless collar contracts and fixed swap contracts. These instruments are intended to reduce our exposure to fluctuations in the price of natural gas and oil. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide for payments to the Company if the index price is below the fixed price or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of our natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in prices. Our derivative contracts are with BP Energy Company and are secured under our Credit Facility.
We are required to recognize all derivative instruments as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. At December 31, 2024, we had no derivative contracts designated as cash flow hedges, and therefore, changes in the fair value of derivatives are reflected in earnings.
Impairment of Assets
All long-lived assets, principally natural gas and oil properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than our estimated future net cash flows. The evaluations involve significant judgment, since the results are based on estimated future events, such as: inflation rates; future sales prices for natural gas, oil and NGL; future production costs; estimates of future natural gas, oil and NGL reserves to be recovered and the timing thereof; economic and regulatory climates and other factors. We estimate future net cash flows on our natural gas and oil properties utilizing differentially adjusted forward pricing curves for natural gas, oil and NGL and a discount rate in line with the discount rate we believe is most commonly used by market participants (10% for all periods presented). The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to natural gas, oil and NGL reserves. A further reduction in natural gas, oil and NGL prices (which are reviewed quarterly) or a decline in reserve volumes (which are re-evaluated semi-annually) would likely lead to impairment that may be material to the Company. The decision to not participate in future development on our leasehold acreage can trigger a test for impairment. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.
Natural Gas, Oil and NGL Sales Revenue Accrual
We do not operate our natural gas and oil properties and, therefore, receive actual natural gas, oil and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, as well as public and private sources, and natural gas, oil and NGL index prices are used to estimate the accrual of revenue on these wells. Obtaining timely production data on all other wells from the operators is not feasible; therefore, we utilize past production receipts and estimated sales price information to estimate our accrual of revenue on all other wells each quarter. The natural gas, oil and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL sales at the end of any particular quarter. Based on past history, our estimated accruals have been materially accurate.
Income Taxes
The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of our percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at the end of each fiscal year. During interim periods, an estimate is made which takes into account historical data and current pricing. We have
certain state and may have federal net operating loss carry forwards (NOLs) that are recognized as tax assets when assessed as more likely than not to be utilized before their expiration dates. Criteria such as expiration dates, future excess state depletion and reversing taxable temporary differences are evaluated to determine whether the NOLs are more likely than not to be utilized before they expire. If any NOLs are no longer determined to be more likely than not to be utilized, then a valuation allowance is recognized to reduce the tax benefit of such NOLs.
The above description of our critical accounting policies is not intended to be an all-inclusive discussion of the uncertainties considered and estimates made by management in applying GAAP. Results may vary significantly if different policies were used or required and if new or different information becomes known to management.

---

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Natural gas, oil and NGL prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of natural gas, oil and NGL price trends, and there remains a wide divergence in the opinions held in the industry. We can be significantly impacted by changes in natural gas and oil prices. The market price of natural gas, oil and NGL in 2025 will impact the amount of cash generated from operating activities, which will in turn impact the level of our capital expenditures for acquisitions and production. Excluding the impact of our 2025 derivative contracts (see below), the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $796,995 for operating revenue based on our prior year natural gas volumes. The price sensitivity in 2025 for each $1.00 per barrel change in wellhead oil is approximately $178,357 for operating revenue based on our prior year oil volumes.
Financial Market Risk
Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to our Credit Facility. Interest under our Credit Facility is calculated based on either (a) SOFR plus an applicable margin ranging from 2.750% to 3.750% per annum based on our Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the US Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on our Borrowing Base Utilization. Under the terms of the Credit Agreement, a 5% interest penalty may apply to any outstanding amount not paid when due or that remains outstanding while an event of default exists. At December 31, 2024, we had $29,500,000 outstanding under this facility and the effective interest rate was 7.88%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of $295,000 for the year ended December 31, 2024, assuming that our indebtedness remained constant throughout the period. At this point, we do not believe that our liquidity has been materially affected by the debt market uncertainties noted in the last few years, and we do not believe that our liquidity will be significantly impacted in the near future. All capitalized terms in this description of the interest rate under the Credit Facility that are not otherwise defined in this Annual Report have the meaning assigned to them in the Credit Agreement.

---

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 42)
Balance Sheets As of December 31, 2024 and December 31, 2023
Statements of Income for the Years Ended December 31, 2024 and 2023
Statements of Stockholders’ Equity for the Years Ended December 31, 2024 and 2023
Statements of Cash Flows for the Years Ended December 31, 2024 and 2023
Notes to Financial Statements
Supplementary Information on Natural Gas, Oil, and NGL Reserves (Unaudited)
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of PHX Minerals Inc.
Opinion on the Financial Statements
We have audited the accompanying balance sheets of PHX Minerals Inc. (the Company) as of December 31, 2024 and 2023, the related statements of income, stockholders’ equity and cash flows for each of the two years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Depreciation, Depletion and Amortization of Producing Natural Gas and Oil Working Interest and Overriding Royalty Interest Properties
Description of the Matter
At December 31, 2024, the cost basis of the Company’s natural gas and oil properties was $274.9 million, and depreciation, depletion and amortization (“DD&A”) expense was $9.6 million for the year then ended. As discussed in Note 1, the Company follows the successful efforts method of accounting for its natural gas and oil producing activities. Depreciation, depletion and amortization of natural gas and oil properties is generally computed using the unit-of-production method primarily on an individual property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of natural gas, crude oil and NGL reserves using standard geological and engineering methods generally recognized in the petroleum industry based on evaluations of in-place hydrocarbon volumes using financial and non-financial inputs.
Subjective judgment is required by the Independent Consulting Petroleum Engineer in evaluating data used to estimate natural gas, oil and NGL reserves. Estimating reserves
requires the selection of inputs, including historical production, price assumptions, and future operating costs, among others. Auditing the Company’s working interest and overriding royalty interest properties unit-of-production DD&A calculations is subjective because of the use of the work of the Independent Consulting Petroleum Engineer and the determination of the inputs described above used by the engineers in estimating proved natural gas, oil and NGL reserves.
How We Addressed the Matter in Our Audit
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Independent Consulting Petroleum Engineer used to prepare the proved natural gas, oil and NGL reserve estimates. In assessing whether we can use the work of the Independent Consulting Petroleum Engineers, we evaluated the completeness and accuracy of the financial and non-financial data described above used by the engineers in estimating proved natural gas, oil and NGL reserves by agreeing them to source documentation. In addition, we assessed the inputs for reasonableness based on our review of corroborative evidence and consideration of any contrary evidence. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved natural gas, oil and NGL reserve amounts used in the calculations to the Company’s reserve report.
/s/ Ernst & Young LLP
We have served as the Company's auditor since 1989.
Oklahoma City, Oklahoma
March 12, 2025
PHX Minerals Inc.
Balance Sheets
December 31,
Assets
Current Assets:
Cash and cash equivalents
$
2,242,102
$
806,254
Natural gas, oil and NGL sales receivables (net of $0 allowance for uncollectable accounts)
6,128,954
4,900,126
Refundable income taxes
328,560
455,931
Derivative contracts, net
-
3,120,607
Other
857,317
878,659
Total current assets
9,556,933
10,161,577
Properties and equipment at cost, based on successful efforts accounting:
Producing natural gas and oil properties
223,043,942
209,082,847
Non-producing natural gas and oil properties
51,806,911
58,820,445
Other
1,361,064
1,360,614
276,211,917
269,263,906
Less accumulated depreciation, depletion and amortization
(122,835,668
)
(114,139,423
)
Net properties and equipment
153,376,249
155,124,483
Derivative contracts, net
-
162,980
Operating lease right-of-use assets
429,494
572,610
Other, net
553,090
486,630
Total assets
$
163,915,766
$
166,508,280
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable
$
804,693
$
562,607
Derivative contracts, net
316,336
-
Current portion of operating lease liability
247,786
233,390
Accrued liabilities and other
1,866,930
1,215,275
Total current liabilities
3,235,745
2,011,272
Long-term debt
29,500,000
32,750,000
Deferred income taxes
7,286,315
6,757,637
Asset retirement obligations
1,097,750
1,062,139
Derivative contracts, net
398,072
-
Operating lease liability, net of current portion
448,031
695,818
Total liabilities
41,965,913
43,276,866
Stockholders' equity:
Voting common stock, par value $0.01666 per share: 75,000,000 shares authorized and
36,796,496 shares issued and outstanding at December 31, 2024; 54,000,500 shares
authorized and 36,121,723 shares issued and outstanding at December 31, 2023
613,030
601,788
Capital in excess of par value
44,029,492
41,676,417
Deferred directors' compensation
1,323,760
1,487,590
Retained earnings
77,073,332
80,022,839
123,039,614
123,788,634
Treasury stock, at cost: 279,594 shares at December 31, 2024; 131,477 shares
at December 31, 2023
(1,089,761
)
(557,220
)
Total stockholders' equity
121,949,853
123,231,414
Total liabilities and stockholders' equity
$
163,915,766
$
166,508,280
See accompanying notes.
PHX Minerals Inc.
Statements of Income
Year Ended December 31,
Revenues:
Natural gas, oil and NGL sales
$
33,690,652
$
36,536,285
Lease bonuses and rental income
580,804
1,068,022
Gains (losses) on derivative contracts (Note 12)
299,608
6,859,589
34,571,064
44,463,896
Costs and expenses:
Lease operating expenses
1,228,813
1,598,944
Transportation, gathering and marketing
4,513,381
3,674,832
Production and ad valorem taxes
1,703,305
1,881,737
Depreciation, depletion and amortization
9,606,444
8,566,185
Provision for impairment
52,673
38,533
Interest expense
2,563,268
2,362,393
General and administrative
11,670,328
11,970,182
Losses (gains) on asset sales and other
83,799
(4,285,170
)
31,422,011
25,807,636
Income before provision for income
taxes
3,149,053
18,656,260
Provision for income taxes
827,187
4,735,460
Net income
$
2,321,866
$
13,920,800
Basic and diluted earnings (loss) per common share (Note 7)
$
0.06
$
0.39
Weighted average shares outstanding:
Basic
36,329,735
35,980,309
Diluted
36,412,270
35,980,309
Dividends per share of common stock paid in period
$
0.1400
$
0.0975
See accompanying notes.
PHX Minerals Inc.
Statements of Stockholders’ Equity
Voting
Capital in
Deferred
Common Stock
Excess of
Directors'
Retained
Treasury
Treasury
Shares
Amount
Par Value
Compensation
Earnings
Shares
Stock
Total
Balances at December 31, 2022
35,938,206
$
598,731
$
43,344,916
$
1,541,070
$
68,925,774
(300,272
)
$
(4,307,365
)
$
110,103,126
Net income (loss)
-
-
-
-
13,920,800
-
-
13,920,800
Purchase of treasury stock
-
-
-
-
-
(120,939
)
(402,704
)
(402,704
)
Restricted stock awards expense
-
-
2,205,910
-
-
-
-
2,205,910
Dividends declared
-
-
-
-
(2,823,735
)
-
-
(2,823,735
)
Distribution of restricted stock to
officers and directors
183,517
3,057
(3,850,079
)
-
-
268,422
3,847,022
-
Distribution of deferred directors'
compensation
-
-
(24,330
)
(281,497
)
-
21,312
305,827
-
Increase in deferred directors' compensation charged to expense
-
-
-
228,017
-
-
-
228,017
Balances at December 31, 2023
36,121,723
$
601,788
$
41,676,417
$
1,487,590
$
80,022,839
(131,477
)
$
(557,220
)
$
123,231,414
Net income (loss)
-
-
-
-
2,321,866
-
-
2,321,866
Purchase of treasury stock
-
-
-
-
-
(212,391
)
(805,063
)
(805,063
)
Restricted stock awards expense
-
-
2,287,927
-
-
-
-
2,287,927
Dividends declared
-
-
-
-
(5,271,373
)
-
-
(5,271,373
)
Distribution of restricted stock to
officers and directors
674,773
11,242
(11,242
)
-
-
-
-
-
Distribution of deferred directors'
compensation
-
-
76,390
(348,912
)
-
64,274
272,522
-
Increase in deferred directors' compensation charged to expense
-
-
-
185,082
-
-
-
185,082
Balances at December 31, 2024
36,796,496
$
613,030
$
44,029,492
$
1,323,760
$
77,073,332
(279,594
)
$
(1,089,761
)
$
121,949,853
See accompanying notes.
PHX Minerals Inc.
Statements of Cash Flows
Year Ended December 31,
Operating Activities
Net income
$
2,321,866
$
13,920,800
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization
9,606,444
8,566,185
Impairment of producing properties
52,673
38,533
Provision for deferred income taxes
528,678
4,303,731
Gain from leasing fee mineral acreage
(580,805
)
(1,067,992
)
Proceeds from leasing fee mineral acreage
597,389
1,213,913
Net (gain) loss on sales of assets
(518,816
)
(4,728,758
)
Directors' deferred compensation expense
185,082
228,017
Total (gain) loss on derivative contracts
(299,608
)
(6,859,589
)
Cash receipts (payments) on settled derivative contracts
4,297,603
2,743,475
Restricted stock award expense
2,287,927
2,205,910
Other
98,104
136,412
Cash provided (used) by changes in assets and
liabilities:
Natural gas, oil and NGL sales receivables
(1,228,828
)
4,883,870
Income taxes receivable
127,371
(455,931
)
Other current assets
(3,064
)
(45,869
)
Accounts payable
252,386
69,228
Other non-current assets
(22,985
)
206,292
Income taxes payable
-
(576,427
)
Accrued liabilities
376,436
(610,661
)
Total adjustments
15,755,987
10,250,339
Net cash provided by operating activities
18,077,853
24,171,139
Investing Activities
Capital expenditures
$
(87,579
)
$
(325,983
)
Acquisition of minerals and overriding royalty interests
(7,796,983
)
(29,735,516
)
Net proceeds from sales of assets
527,167
9,614,194
Net cash provided by (used in) investing activities
(7,357,395
)
(20,447,305
)
Financing Activities
Borrowings under Credit Facility
3,000,000
19,500,000
Payments of loan principal
(6,250,000
)
(20,050,000
)
Payments on off-market derivative contracts
-
(560,162
)
Purchases of treasury stock
(805,063
)
(402,704
)
Payments of dividends
(5,229,547
)
(3,520,366
)
Net cash provided by (used in) financing activities
(9,284,610
)
(5,033,232
)
Increase (decrease) in cash and cash equivalents
1,435,848
(1,309,398
)
Cash and cash equivalents at beginning of period
806,254
2,115,652
Cash and cash equivalents at end of period
$
2,242,102
$
806,254
Supplemental Disclosures of Cash Flow
Information
Interest paid (net of capitalized interest)
$
2,611,089
$
2,405,361
Income taxes paid (net of refunds received)
$
318,789
$
1,464,087
Supplemental schedule of noncash investing and
financing activities:
Dividends declared and unpaid
$
155,271
$
113,443
Gross additions to properties and equipment
$
7,893,036
$
30,761,578
Net (increase) decrease in accounts receivable for
properties and equipment additions
(8,474
)
(700,079
)
Capital expenditures and acquisitions
$
7,884,562
$
30,061,499
PHX Minerals Inc.
Notes to Financial Statements
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
The Company’s principal line of business is maximizing the value of its existing mineral and royalty assets through active management and expanding its asset base through acquisitions of additional mineral and royalty interests. The Company owns mineral and leasehold properties and other natural gas and oil interests, which are all located in the contiguous United States, primarily in Oklahoma, Texas, Louisiana, North Dakota and Arkansas, with properties located in several other states. The Company’s natural gas, oil and NGL production is from interests in 6,958 wells located principally in Oklahoma, Louisiana, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 52%, 39% and 9% of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in the year ended December 31, 2024. Approximately 81%, 11% and 8% of the Company’s total sales volumes in the year ended December 31, 2024 were derived from natural gas, oil and NGL, respectively. Substantially all the Company’s natural gas, oil and NGL production is sold through the operators of the wells.
Effective April 1, 2022, the Company changed its state of incorporation from Oklahoma to Delaware through a merger with a wholly owned subsidiary, which was conducted for such purpose (the “Reincorporation”). Other than the change in the state of incorporation, the Reincorporation did not result in any change in the business, physical location, management, or any change in the fair value of the assets and liabilities of PHX Minerals Inc. and its subsidiaries and no gain or loss was recognized in our consolidated financial statements (since the merger was between entities under common control both before and after the merger).
Use of Estimates
Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Of these estimates and assumptions, management considers the estimation of natural gas, crude oil and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. The Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of natural gas, crude oil and NGL reserves on an annual basis. These estimates are based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. For impairment purposes, projected future natural gas, crude oil and NGL prices as estimated by management are used. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Management uses projected future natural gas, crude oil and NGL pricing assumptions to prepare estimates of natural gas, crude oil and NGL reserves used in formulating management’s overall operating decisions.
As a non-operator of working, royalty and mineral interests, the Company receives actual natural gas, oil and NGL sales volumes and prices more than a month after the information is available to the operators of the wells. Because of the delay in information, the most current available production data is gathered from the appropriate operators, as well as public and private sources, and natural gas, oil and NGL index prices are used to estimate the accrual of revenue on these wells. If information is not available from an outside source, the Company utilizes past production receipts, production type curves, and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The natural gas, oil and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.
Basis of Presentation
Certain reclassifications have been made to prior period financials to conform to the current year presentation. These reclassifications have no impact on previous reported total assets, total liabilities, net income (loss), stockholders’ equity, or operating cash flows.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.
Natural Gas, Oil and NGL Sales
The Company sells natural gas, oil and NGL to various customers, recognizing revenues as natural gas, oil and NGL is produced and sold.
Accounts Receivable and Concentration of Credit Risk
Substantially all of the Company’s accounts receivable are due from purchasers (operators) of natural gas, oil and NGL. Natural gas, oil and NGL sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our natural gas, oil and NGL and the operators of the properties in which we have an interest may be similarly affected by changes in economic, industry or other conditions. During the years ended December 31, 2024, and 2023, the Company did not have any bad debt expense. The Company’s allowance for uncollectible accounts as of the balance sheet dates was not material.
Natural Gas and Oil Producing Activities
The Company follows the successful efforts method of accounting for natural gas and oil producing activities. For working interest properties, intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income, if and when the well does not reach commercial production levels. Natural gas and oil mineral and leasehold costs are capitalized when incurred.
Leasing of Mineral Rights
The Company generates lease bonuses by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as income. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rentals line item on the Company’s Statements of Income.
Derivatives
The Company utilizes derivative contracts to reduce its exposure to fluctuations in the price of natural gas and oil. These derivatives are recorded at fair value on the balance sheet. The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges.
Properties and Equipment
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of the costs of producing natural gas and oil properties are generally computed using the unit-of-production method primarily on an individual property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s capitalized costs of drilling and equipping all development wells, and those exploratory wells that have found proved reserves, are amortized on a unit-of-production basis over the remaining life of associated proved developed reserves. Leasehold costs for working interest and overriding royalty interest properties are amortized on a unit-of-production basis over the remaining life of associated total proved reserves. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.
Non-producing natural gas and oil properties include non-producing minerals, which had a net book value of $41,870,046 and $49,226,889 at December 31, 2024 and December 31, 2023, respectively, consisting of perpetual ownership of mineral interests in several states, with 57% of the acreage in Oklahoma, Texas, Louisiana, North Dakota and Arkansas. As mentioned, these mineral rights are perpetual and have been accumulated over the 98-year life of the Company. There are approximately 170,773 net acres of non-producing minerals in more than 5,603 tracts owned by the Company. An average tract contains approximately 30 acres. Since inception, the Company has continually generated an interest in several thousand natural gas and oil wells using its ownership of the fee mineral acres as an ownership basis. There continues to be drilling and leasing activity on these mineral interests each year. Non-producing minerals are considered a long-term investment by the Company, as they do not expire (unlike natural gas and oil leases) and based on past history and experience, management has concluded that a long-term straight-line amortization over 33 years is appropriate. Due to the fact that the Company’s mineral ownership consists of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis (by mineral deed).
When a new well is drilled on the Company’s mineral acreage, all of the non-producing mineral costs for the associated mineral tract are transferred to producing minerals and are amortized straight-line over a 20-year period (insignificant fields are amortized over a 10-year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on the Company’s minerals, and future development will deplete these assets over a long period. The straight-line amortization over a 20-year period is appropriate for producing minerals, because current and future development will deplete these assets over a lengthy period that represents the estimated economic life.
Capitalized Interest
During the years ended December 31, 2024 and 2023, no interest was capitalized. Interest of $2,563,268 and $2,362,393, respectively, was charged to expense during those periods.
Accrued Liabilities
The following table shows the balances for the years ended December 31, 2024 and December 31, 2023, relating to the Company’s accrued liabilities:
December 31,
December 31,
Accrued compensation
$
853,963
$
210,379
Revenues payable
624,837
529,025
Accrued ad valorem
81,422
39,591
Dividends
155,271
113,443
Other
151,437
322,837
Total accrued liabilities
$
1,866,930
$
1,215,275
The increase in accrued compensation in 2024 is due to timing of payment related to the short-term incentive compensation.
Asset Retirement Obligations
The Company owns interests in natural gas and oil properties, which may require expenditures to plug and abandon the wells upon the end of their economic lives. The fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties and equipment is depreciated over the useful life of the remaining asset. The Company does not have any assets restricted for the purpose of settling asset retirement obligations.
Environmental Costs
As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Company does not believe the existence of current environmental laws, or interpretations thereof, will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future effects on the Company of new laws or interpretations thereof. Since the Company does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Company being responsible for its proportionate share of the costs involved (on working interest wells only). The Company carries liability and pollution control insurance. However, all risks are not insured due to the availability and cost of insurance.
Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2024 and December 31, 2023, there were no such costs accrued and expenses were immaterial for both years.
Earnings (Loss) Per Share of Common Stock
Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period.
Share-based Compensation
The Company recognizes current compensation costs for its Deferred Compensation Plan for Non-Employee Directors (the “Plan”). Compensation cost is recognized for the requisite directors’ fees as earned and unissued stock is recorded to each director’s account based on the fair market value of the stock at the date earned. The Plan provides that only upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan may be issued to the director.
Restricted stock awards to officers and employees provide for either cliff vesting at the end of three years from the date of the awards or time vesting ratably over a three-year period. These restricted stock awards can be granted based on service time only (time-based), subject to certain share price performance standards (market-based) or subject to company performance standards (performance-based). Restricted stock awards to the non-employee directors provide for annual vesting during the calendar year of the award. The fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance.
Income Taxes
The estimation of amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax regulations. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities.
The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis.
Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended December 31, 2024 was 26% as compared to 25% for the year ended December 31, 2023.
The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2021.
The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Income. For the fiscal years ended December 31, 2024 and 2023, the Company’s interest and penalties were not material. The Company does not believe it has any material uncertain tax positions.
Recent Accounting Pronouncements
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”), which requires public entities with a single reportable segment to provide all existing segment disclosures required by ASC 280 on an interim and annual basis, including the title and position of the Chief Operating Decision Maker (“CODM”), and primarily requires disclosing of significant segment expenses that are regularly provided to the CODM. ASU 2023-07 is effective for annual periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. We have adopted ASU 2023-07 for the fiscal year 2024 annual financial statements and interim condensed financial statements thereafter and have applied this standard retrospectively for all prior periods presented. Refer to Note 15 - Operating Segment of these financial statements.
Accounting Pronouncements Not Yet Adopted
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740) Improvements to Income Tax Disclosures. The guidance increases transparency in the income tax disclosure, primarily related to the rate reconciliation and income taxes paid information. The guidance is effective for fiscal years beginning after December 15, 2024, and early adoption is permitted. The Company is currently evaluating the impact this guidance will have on the income tax disclosures.
In November 2024, the FASB issued ASU 2024-03, Income Statement -Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”), which requires public entities to disclose additional information about certain expenses included in relevant expense captions on the income statement. ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and for interim periods beginning after December 15, 2027. Management is evaluating the impact of adoption of ASU 2024-03 on the Company’s financial statements and disclosures.
2. LEASES AND COMMITMENTS
Assessment of Leases
The Company determines if an arrangement is a lease at inception by considering whether (i) explicitly or implicitly identified assets have been deployed in the agreement and (ii) the Company obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. As of December 31, 2024, none of the Company’s leases were classified as financing leases. Operating lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company entered into a seven-year lease for office space during the quarter ended March 31, 2020, with a commencement date in August 2020. The associated lease liability and ROU asset at December 31, 2024, were $459,654 and $300,816, respectively. The Company has a lease incentive asset of $132,476, which is included in Other, net on the Company’s balance sheets. Additionally, the Company entered into a new five-year lease for office space
during the quarter ended March 31, 2022, with a commencement date in July 2022. The associated lease liability and ROU asset at December 31, 2024, were $236,163 and $128,678, respectively. The Company has a lease incentive asset of $95,397, which is included in Other, net on the Company’s balance sheets. Lease costs for the years ended December 31, 2024 and 2023 were $287,763 and $304,163, respectively.
ROU assets represent the Company’s right to use an underlying asset for the lease term, and operating lease liabilities represent the Company’s obligation to make payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs and prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Company uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments.
The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Company will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Company will exercise that option. Lease expense for lease payments will be recognized on a straight-line basis over the lease term. The Company made an accounting policy election to not recognize leases with terms, including applicable options, of less than twelve months on the Company’s balance sheets and recognize those lease payments in the Company’s Statements of Income on a straight-line basis over the lease term. In the event that the Company’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.
The following table represents the maturities of the operating lease liabilities as of December 31, 2024:
270,845
277,723
186,004
Thereafter
-
Total lease payments
$
734,572
Less: Imputed interest
(38,755
)
Total
$
695,817
3. REVENUES
Natural gas and oil derivative contracts
See Note 12 for discussion of the Company’s accounting for derivative contracts.
Revenues from Contracts with Customers
Natural gas, oil and NGL sales
Sales of natural gas, oil and NGL are recognized when production is sold to a purchaser and control has transferred. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation; however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate.
Disaggregation of natural gas, oil and NGL revenues
The following tables present the disaggregation of the Company’s natural gas, oil and NGL revenues for the years ended December 31, 2024 and 2023.
Year Ended December 31, 2024
Royalty Interest
Working Interest
Total
Natural gas revenue
$
15,958,989
$
1,494,732
$
17,453,721
Oil revenue
12,011,909
1,292,015
13,303,924
NGL revenue
1,880,830
1,052,177
2,933,007
Natural gas, oil and NGL sales
$
29,851,728
$
3,838,924
$
33,690,652
Year Ended December 31, 2023
Royalty Interest
Working Interest
Total
Natural gas revenue
$
17,420,360
$
2,025,900
$
19,446,260
Oil revenue
12,306,987
1,733,213
14,040,200
NGL revenue
1,866,004
1,183,821
3,049,825
Natural gas, oil and NGL sales
$
31,593,351
$
4,942,934
$
36,536,285
Performance obligations
The Company satisfies the performance obligations under its natural gas, oil and NGL sales contracts upon delivery of its production and related transfer of title to purchasers. Upon delivery of production, the Company has a right to receive consideration from its purchasers in amounts that correspond with the value of the production transferred.
Allocation of transaction price to remaining performance obligations
Natural gas, oil and NGL sales
As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606, which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment relate specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient.
Prior-period performance obligations and contract balances
The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into the timing of when new wells start producing, and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the natural gas, oil and NGL sales receivables line item on the Company’s balance sheets. The difference between the Company’s estimates and the actual amounts received for natural gas, oil and NGL sales is recorded in the quarter that payment is received from the third party. For the years ended December 31, 2024 and 2023, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was considered a change in estimate.
As noted above, as a non-operator, there are instances when the Company is limited by the information operators provide. Through cash received on new wells, in the years ended December 31, 2024 and 2023, the Company identified several producing properties on its minerals that had production dates prior to the years ended December 31, 2024 and 2023. Estimates of the natural gas and oil sales related to those properties were made and are reflected in the natural gas, oil and NGL sales on the Company’s Statements of Income and on the Company’s Balance Sheets in natural gas, oil and NGL sales receivables. In connection with obtaining more relevant information on new wells on Company acreage during the years ended December 31, 2024 and 2023, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling approximately $0.5 million for the year ended December 31, 2024 related to the production periods before January 1, 2024 and approximately $0.9 million for the year ended December 31, 2023 related to the production periods before January 1, 2023.
4. INCOME TAXES
The Company’s provision for income taxes is detailed as follows:
Year Ended December 31,
Current:
Federal
$
99,719
$
190,914
State
198,790
240,815
298,509
431,729
Deferred:
Federal
525,511
3,538,031
State
3,167
765,700
528,678
4,303,731
$
827,187
$
4,735,460
The difference between the provision for income taxes and the amount which would result from the application of the federal statutory rate to income before provision for income taxes is analyzed below:
Year Ended December 31,
Provision for income taxes at statutory rate
$
661,301
$
3,917,815
Change in valuation allowance
3,394
(8,067
)
Percentage depletion
(375,145
)
(408,729
)
State income taxes, net of federal provision
156,818
963,063
Restricted stock tax benefit
(59,943
)
10,664
Deferred directors' compensation benefit
28,230
42,018
Nondeductible compensation
359,545
122,204
Law change
-
-
Provision to return adjustments
40,670
190,914
Other
12,317
(94,422
)
$
827,187
$
4,735,460
Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax basis of assets and liabilities, consist of the following at December 31, 2024 and 2023:
December 31,
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible
drilling costs capitalized for financial purposes and
expensed for tax purposes
$
12,099,584
$
10,825,555
Derivative contracts
-
802,712
Total deferred tax liabilities
12,099,584
11,628,267
Deferred tax assets:
State net operating loss carry forwards
221,690
293,701
Federal net operating loss carry forwards
1,998,323
2,234,275
Statutory depletion carryover
239,294
417,090
Asset retirement obligations
220,560
210,447
Deferred directors' compensation
288,962
331,879
Restricted stock expense
482,607
653,959
Derivative contracts
172,930
-
Interest expense limitation/carryover
1,101,150
643,067
Other
96,809
91,874
Total deferred tax assets
4,822,325
4,876,292
State NOL valuation allowance
9,056
5,662
Net deferred tax liabilities
$
7,286,315
$
6,757,637
The federal net operating loss carry forwards can be carried forward indefinitely. Included in state net operating loss carry forwards at December 31, 2024, the Company had a deferred tax asset of $20,946 related to various state income tax net operating loss (“state NOL”) carry-forwards, which begin to expire as of December 31, 2024. The Company has a valuation allowance of $9,056 for the state NOLs, as it is more likely than not that it will not be fully utilized before expiration.
5. DEBT
On September 1, 2021, the Company entered into a $100,000,000 credit facility (the “Credit Facility”) with a group of banks headed by Independent Bank. The Credit Facility has a current borrowing base of $50,000,000 as of December 31, 2024, and a maturity date of September 1, 2028. The Credit Facility is secured by the Company’s personal property and at least 75% of the total value of the proved, developed and producing oil and gas properties. The interest rate is based on either (a) SOFR plus an applicable margin ranging from 2.750% to 3.750% per annum based on the Company’s Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the US Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on the Company’s Borrowing Base Utilization. The election of Independent Bank prime or SOFR is at the Company’s discretion. The interest rate spread from Independent Bank prime or SOFR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from SOFR or the prime rate increases as a larger percent of the borrowing base is advanced. At December 31, 2024, the effective interest rate was 7.88%.
The Company’s debt is recorded at the carrying amount on its balance sheets. The carrying amount of the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in Other, net on the Company’s balance sheets. Total debt issuance cost net of amortization as of December 31, 2024, was $325,218. The debt issuance cost is amortized over the life of the Credit Facility.
Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the banks, in their sole discretion, believe that there has been a material change in the value of the Company’s natural gas and oil properties. The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, make fundamental changes, and engage in certain transactions with affiliates. The Credit Agreement also restricts the Company’s ability to make certain restricted payments if before or after the Restricted Payment (i) the Available Commitment is less than ten percent (10%) of the Borrowing Base or (ii) the Leverage Ratio on a pro forma basis is greater than 2.50 to 1.00. In addition, the Company is required to maintain certain financial ratios, a current ratio (as described in the Credit Agreement) of no less than 1.0 to 1.0 and a funded debt to EBITDAX (as defined in the Credit Agreement) of
no more than 3.5 to 1.0 based on the trailing twelve months. At December 31, 2024, the Company was 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. All capitalized terms in this description of the Credit Facility that are not otherwise defined in this Annual Report have the meaning assigned to them in the Credit Agreement.
6. STOCKHOLDERS’ EQUITY
In May 2014, the Board adopted stock repurchase resolutions (the “Repurchase Program”) to allow management, at its discretion, to purchase the Company’s Common Stock as treasury shares up to an amount equal to the aggregate number of shares of Common Stock awarded pursuant to the 2010 Restricted Stock Plan (“2010 Stock Plan”), as amended, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.
Effective in May 2018, the Board approved an amendment to the Company’s existing stock Repurchase Program. As amended, the Repurchase Program continues to allow the Company to repurchase up to $1.5 million of the Company’s Common Stock at management’s discretion. The Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $1.5 million of the Company’s Common Stock is authorized and approved whenever the previous amount is utilized. In addition, the number of shares allowed to be purchased by the Company under the Repurchase Program is no longer capped at an amount equal to the aggregate number of shares of Common Stock (i) awarded pursuant to the 2010 Stock Plan, as amended, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.
7. EARNINGS PER SHARE (“EPS”)
Basic and diluted earnings per common share is calculated using net income divided by the weighted average number of shares of Common Stock outstanding, including unissued, vested directors’ deferred compensation shares of 288,262 and 261,320, respectively, during the years ended December 31, 2024 and 2023. As of December 31, 2024, there were no participating securities.
For the years ended December 31, 2024 and 2023, the Company excluded restricted stock in the diluted EPS calculation that would have been antidilutive. The average shares outstanding of restricted stock excluded from the diluted EPS was 1,088,269 and 753,336, respectively, for the years ended December 31, 2024 and 2023.
The following table sets forth the computation of earnings (loss) per share.
Year Ended December 31,
Basic EPS
Numerator:
Basic net income (loss)
$
2,321,866
$
13,920,800
Denominator:
Common Shares
36,041,473
35,718,989
Unissued, directors' deferred compensation shares
288,262
261,320
Basic weighted average shares outstanding
36,329,735
35,980,309
Basic EPS
$
0.06
$
0.39
Diluted EPS
Numerator:
Basic net income (loss)
$
2,321,866
$
13,920,800
Diluted net income (loss)
2,321,866
13,920,800
Denominator:
Basic weighted average shares outstanding
36,329,735
35,980,309
Effects of dilutive securities:
Unvested restricted stock
82,535
-
Diluted weighted average shares outstanding
36,412,270
35,980,309
Diluted EPS
$
0.06
$
0.39
8. 401K PLAN
Effective January 1, 2021, the Company established a defined contribution 401K plan. The Company began matching up to 5% of 401K contributions in cash starting January 1, 2021.
Contributions to the plan consisted of:
Year
Amount
$
166,954
$
150,843
9. DEFERRED COMPENSATION PLAN FOR DIRECTORS
Annually, independent directors may elect to be included in the Company’s Deferred Directors’ Compensation Plan for Non-Employee Directors (the “Plan”). The Plan provides that each independent director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of the annual retainers, and may elect to receive shares, when issued, over annual time periods up to ten years. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares at each quarter end. Only upon a director’s retirement, termination, death or a change-in-control of the Company will the shares recorded for such director under the Plan be issued to the director. The promise to issue such shares in the future is an unsecured obligation of the Company. As of December 31, 2024, there were 292,320 shares recorded under the Plan. The deferred balance outstanding at December 31, 2024, under the Plan was $1,323,760. Expenses totaling $185,082 and $228,017 were charged to the Company’s results of operations for the years ended December 31, 2024 and 2023, respectively, and are included in general and administrative expense in the accompanying Statements of Income.
10. LONG-TERM INCENTIVE PLAN
In March of 2021, stockholders approved the PHX Minerals Inc. 2021 Long-Term Incentive Plan (the “LTIP”). The LTIP expressly prohibits the payment of dividends or dividend equivalents on any award before the date on which the award vests. Awards under the LTIP will be subject to any clawback or recapture policy that the Company may adopt from time to time or any clawback or recapture provisions set forth in an award agreement.
The fair value of the restricted stock (time-based) was based on the closing price of the shares on their grant date and will be recognized as compensation expense ratably over the vesting period. The fair value of the performance shares (market-based) was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the historical volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Vesting of these performance shares is based on the performance of the market price of the Common Stock over the vesting period. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period regardless of whether performance shares are awarded at the end of the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury or the Company’s authorized but unissued shares. Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur.
On January 31, 2023, the Company granted shares of Common Stock in the form of time-based and market-based restricted stock to the employees and officers of the Company. Officers were awarded 299,900 market-based shares with a fair value on their award date of $1,541,893. Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 97,053 time-based shares with a fair value on the award date of $350,362. The shares issued to employees time-vest ratably over a three-year period ending in December of 2025, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December of 2025. All shares granted on January 31, 2023 have voting rights during the vesting period.
On April 20, 2023, the Company granted 92,544 shares of Common Stock in the form of time-based restricted stock to the non-employee directors of the Company, which had a fair value of $243,390. The shares of restricted stock fully vested in December 2023 and had voting rights during the vesting period.
On December 21, 2023, the Company granted 482,339 shares of Common Stock in the form of time-based and market-based restricted stock to the employees and officers of the Company. Officers were awarded 369,114 market-based shares with a fair value on their award date of $1,678,599. Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 113,225 time-based shares with a fair value on the award date of $381,571. The shares issued to employees time-vest ratably over a three-year period ending in December of 2026, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December of 2026. All shares granted on December 21, 2023 have voting rights during the vesting period.
On December 21, 2023, the Company granted 116,904 shares of Common Stock in the form of time-based restricted stock to the non-employee directors of the Company, which had a fair value of $393,967. The shares of restricted stock fully vested in December 2024 and had voting rights during the vesting period.
On December 16, 2024, the Company granted 465,649 shares of Common Stock in the form of time-based and market-based restricted stock to the employees and officers of the Company. Officers were awarded 347,818 market-based shares with a fair value on their award date of $1,786,802. Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 117,831 time-based shares with a fair value on the award date of $467,790. The shares issued to employees time-vest ratably over a three-year period ending in December of 2027, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December of 2027. All shares granted on December 16, 2024 have voting rights during the vesting period.
On December 16, 2024, the Company granted 82,695 shares of Common Stock in the form of time-based restricted stock to the non-employee directors of the Company, which had a fair value of $328,300. The shares of restricted stock fully vest in December 2025 and have voting rights during the vesting period.
The following table summarizes the Company’s pre-tax compensation expense for the years ended December 31, 2024 and 2023 related to the Company’s market-based, time-based and performance-based restricted stock:
Year Ended December 31,
Market-based, restricted stock
$
1,624,134
$
1,722,814
Time-based, restricted stock
663,793
483,096
Total compensation expense
$
2,287,927
$
2,205,910
A summary of the Company’s unrecognized compensation cost for its unvested market-based and time-based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table:
Unrecognized
Compensation
Cost
Weighted Average Period
(in years)
Market-based, restricted stock
$
2,605,320
1.75
Time-based, restricted stock
1,080,882
2.02
Total
$
3,686,202
Upon vesting, shares are expected to be issued out of shares held in treasury or authorized but unissued shares.
A summary of the status of, and changes in, unvested shares of restricted stock awards is presented below:
Market-Based
Unvested
Restricted
Awards
Weighted
Average
Grant-Date
Fair Value
Time-Based Unvested
Restricted
Awards
Weighted
Average
Grant-Date
Fair Value
Unvested shares as of December 31,
705,835
$
3.55
153,224
$
5.09
Granted
669,014
4.81
419,726
3.26
Vested
(303,750
)
2.72
(147,495
)
5.17
Forfeited
-
-
(7,919
)
3.41
Unvested shares as of December 31,
1,071,099
$
4.57
417,536
$
3.26
Granted
458,465
4.89
210,651
3.92
Vested
(502,608
)
4.18
(172,165
)
3.15
Forfeited
(21,962
)
4.81
(60,658
)
3.36
Unvested shares as of December 31, 2024
1,004,994
$
4.91
395,364
$
3.64
The fair value of the vested shares for the years ended December 31, 2024 and 2023 was $2,558,348 and $1,539,424, respectively.
11. PROPERTIES AND EQUIPMENT
Impairment
During the year ended December 31, 2024, the Company recorded impairment of $24,061 related to one field. These assets were written down to their fair market value. The remaining $28,612 of impairment expense was related to leasehold that expired.
During the year ended December 31, 2023, the Company recorded no impairment provisions on producing properties and $38,533 on wells that were assigned back to the operator and the Company wrote off.
A further reduction in natural gas, oil and NGL prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.
Acquisitions
Quarter Ended
Net royalty acres (1)(2)
Total Purchase Price (1)(3)
% Proved / % Unproved
Area of Interest
December 31, 2024
$2.5 million
85% / 15%
Haynesville
September 30, 2024
$3.0 million
78% / 22%
Haynesville / SCOOP
June 30, 2024
$0.9 million
59% / 41%
Haynesville / SCOOP
March 31, 2024
$1.4 million
5% / 95%
SCOOP
December 31, 2023
$4.3 million
72% / 28%
Haynesville / SCOOP
September 30, 2023
$13.4 million
81% / 19%
Haynesville / SCOOP
June 30, 2023
$1.8 million
29% / 71%
Haynesville / SCOOP
March 31, 2023
$10.8 million
44% / 56%
Haynesville / SCOOP
(1) Excludes subsequent closing adjustments and insignificant acquisitions.
(2) An estimated net royalty equivalent was used for the unleased minerals included in the net royalty acres.
(3) Table excludes transaction costs of $0.1 million and $0.3 million, respectively, that were capitalized during the years ended December 31, 2024 and 2023.
All purchases made in fiscal years 2023 and 2024 were of mineral and royalty acreage and were accounted for as asset acquisitions.
Divestitures
Quarter Ended
Net mineral acres(1)/ Wellbores(2)
Sale Price (3)
Gain/(Loss) (3)
Location
December 31, 2024
No significant divestitures
September 30, 2024
No significant divestitures
June 30, 2024
1,005 acres
$0.5 million
$0.4 million
TX
March 31, 2024
No significant divestitures
December 31, 2023
No significant divestitures
September 30, 2023
729 acres
$0.3 million
$0.2 million
OK
June 30, 2023
No significant divestitures
March 31, 2023
755 acres
$0.3 million
$0.3 million
OK / TX
267 wellbores
$10.7 million
$4.1 million
OK / TX
(1) Number of net mineral acres sold.
(2) Number of gross wellbores associated with working interests sold.
(3) Excludes subsequent closing adjustments and immaterial divestitures.
Asset Retirement Obligations
The following table shows the activity for the years ended December 31, 2024 and 2023, relating to the Company’s asset retirement obligations:
Year Ended December 31,
Asset retirement obligations as of beginning of the period
$
1,062,139
$
1,916,932
Wells acquired or drilled
-
-
Wells sold or plugged
(8,214
)
(898,231
)
Accretion of discount
43,825
43,438
Asset retirement obligations as of end of the period
$
1,097,750
$
1,062,139
As a non-operator, the Company does not control the plugging of wells in which it has a working interest and is not involved in the negotiation of the terms of the plugging contracts. This estimate relies on information gathered from outside sources as well as relevant information received directly from operators.
12. DERIVATIVES
The Company has entered into fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to fluctuations in the price of natural gas and oil. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in prices.
On September 2, 2021, the Company settled all of its derivative contracts consisting of both swaps and costless collars with BOKF, NA dba Bank of Oklahoma (“BOKF”) by paying $8.8 million. On September 3, 2021, the Company entered into new derivative contracts with BP Energy Company (“BP”) that had similar terms to the contracts settled with BOKF and received a payment of $8.8 million from BP. The new derivative contracts consisted of all fixed swap contracts and are secured under the Company’s Credit Facility with Independent Bank. Management concluded that the financing element of the new derivative contracts with BP was other than insignificant due to the off-market terms of the fixed swap price. Due to the financing element, the Company is required to report all cash flows associated with these derivative contracts as “cash flows from financing activities” in the statement of cash flows. This requirement relates to all cash flows from these derivatives and not just the portion of the cash flows relating to the financing element of the derivative. All of these derivatives with a financing element settled in 2023. The Company’s derivative contracts that were in place and unsettled as of December 31, 2024 will settle based on the terms below.
Derivative contracts in place as of December 31, 2024
Fiscal period
Contract total volume
Index
Contract average price
Natural gas costless collars
1,540,000 Mmbtu
NYMEX Henry Hub
$3.27floor/$4.54ceiling
1,245,000 Mmbtu
NYMEX Henry Hub
$3.29floor/$4.19ceiling
Natural gas fixed price swaps
2,200,000 Mmbtu
NYMEX Henry Hub
$3.28
215,000 Mmbtu
NYMEX Henry Hub
$3.44
Oil Costless Collars
Remaining unsettled from 2024
500 Bbls
NYMEX WTI
$67.00floor/$77.00ceiling
Oil fixed price swaps
Remaining unsettled from 2024
5,100 Bbls
NYMEX WTI
$68.42
57,800 Bbls
NYMEX WTI
$69.44
15,000 Bbls
NYMEX WTI
$68.78
The Company’s fair value of derivative contracts was a net liability of $714,408 as of December 31, 2024, and a net asset of $3,283,587 as of December 31, 2023. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Income. Cash receipts in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods.
For the Year Ended December 31,
Cash received (paid) on settled derivative contracts:
Natural gas costless collars
$
1,877,875
$
1,516,535
Natural gas fixed price swaps(1)
2,616,497
1,344,580
Oil costless collars
(52,530
)
24,330
Oil fixed price swaps(1)
(144,239
)
(328,387
)
Cash received (paid) on settled derivative contracts, net
$
4,297,603
$
2,557,058
Non-cash gain (loss) on derivative contracts:
Natural gas costless collars
$
(1,940,316
)
$
857,675
Natural gas fixed price swaps
(2,138,259
)
3,119,388
Oil costless collars
14,577
(702
)
Oil fixed price swaps
66,003
326,170
Non-cash gain (loss) on derivative contracts, net
$
(3,997,995
)
$
4,302,531
Gains (losses) on derivative contracts, net
$
299,608
$
6,859,589
(1) For the year ended December 31, 2023, excludes $373,745 of cash paid to settle off-market derivative contracts that are not reflected on the Statements of Income. Total cash paid related to off-market derivatives was $560,162 for the year ended December 31, 2023 and is reflected in the Financing Activities section of the Statements of Cash Flows. Cash (paid) or received not related to off-market derivatives is reflected in the Operating Activities section of the Statements of Cash Flows.
The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on, or termination of, any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability on the balance sheets. The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's balance sheets at December 31, 2024, and December 31, 2023. The Company has offset all amounts subject to master netting agreements on the Company's balance sheets at December 31, 2024 and December 31, 2023.
12/31/2024
12/31/2023
Fair Value
Fair Value
Commodity Contracts
Commodity Contracts
Current Assets
Current Liabilities
Non-Current
Assets
Non-Current
Liabilities
Current Assets
Current Liabilities
Non-Current
Assets
Non-Current
Liabilities
Gross amounts recognized
$
596,514
$
912,850
$
398,894
$
796,966
$
3,318,046
$
197,439
$
344,614
$
181,634
Offsetting adjustments
(596,514
)
(596,514
)
(398,894
)
(398,894
)
(197,439
)
(197,439
)
(181,634
)
(181,634
)
Net presentation on Balance Sheets
$
-
$
316,336
$
-
$
398,072
$
3,120,607
$
-
$
162,980
$
-
The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented.
13. FAIR VALUE MEASUREMENTS
Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels.
Level 1:	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2:	Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and commodity options (i.e. price collars).
The Company uses an option pricing valuation model for option derivative contracts that considers various inputs including: future prices, time value, volatility factors, counterparty credit risk and current market and contractual prices for the underlying instruments. The values calculated are then compared to the values given by counterparties for reasonableness.
Level 3:	Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and unobservable (or less observable) from objective sources (supported by little or no market activity).
The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis.
Fair Value Measurement at December 31, 2024
Quoted
Prices in
Active
Markets
Significant
Other Observable Inputs
Significant Unobservable Inputs
Total Fair
(Level 1)
(Level 2)
(Level 3)
Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps
$
-
$
(366,215
)
$
-
$
(366,215
)
Derivative Contracts - Collars
$
-
$
(348,193
)
$
-
$
(348,193
)
Fair Value Measurement at December 31, 2023
Quoted
Prices in
Active
Markets
Significant
Other
Observable Inputs
Significant Unobservable Inputs
Total Fair
(Level 1)
(Level 2)
(Level 3)
Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps
$
-
$
1,706,042
$
-
$
1,706,042
Derivative Contracts - Collars
$
-
$
1,577,545
$
-
$
1,577,545
The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
Year Ended December 31,
Fair Value
Impairment
Fair Value
Impairment
Producing Properties (a)
$
-
$
24,061
$
-
$
-
(a)At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment if indicators of impairment existed at such time. If indicators of impairment exist, the Company utilizes estimates of future cash flows of proved properties or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future natural gas, oil and NGL prices using a
forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off in the amount of $28,612 and $38,533 for the years ended December 31, 2024 and 2023, respectively.
At December 31, 2024 and December 31, 2023, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments. Financial instruments include debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.
14. INFORMATION ON NATURAL GAS AND OIL PRODUCING ACTIVITIES
The natural gas and oil producing activities of the Company are conducted within the contiguous United States (principally in Oklahoma, Texas, Louisiana, Arkansas and North Dakota) and represent substantially all of the business activities of the Company.
The following table shows sales to major purchasers, by percentage, through various operators/purchasers during the years ended December 31, 2024 and 2023.
Year Ended December 31,
Company A
%
%
Company B
%
%
Company C
%
%
The loss of any of these major purchasers of natural gas, oil and NGL production could have a material adverse effect on the ability of the Company to produce and sell its natural gas, oil and NGL production.
15. OPERATING SEGMENT
An operating segment is defined as a component of a public entity that engages in business activities and for which discrete financial information and operating results are available and regularly reviewed by the CODM in deciding how to allocate resources and assess performance. The Company’s Chief Executive Officer has been determined to be its CODM. The CODM manages the Company’s business activities in a single operating and reportable segment focused on managing the Company’s mineral portfolio and growing its mineral positions in its core focus areas. The financial information and operating results, including net income and total assets, used by the CODM to allocate resources, assess performance, and make key operating decisions are the same as that which is reported by the Company on the Income Statement and Balance Sheet, and the CODM does not use further disaggregated expenses or assets in deciding how to allocate resources and assess performance.
16. SUBSEQUENT EVENTS
Subsequent to December 31, 2024, the Company closed on the divestiture of 165,326 net mineral acres for approximately $8.0 million and paid down an additional $9.8 million in debt. Additionally, the Company announced a $0.04 per share quarterly dividend, payable on March 28, 2025, to stockholders of record on March 17, 2025.
PHX Minerals Inc.
Supplementary Information
SUPPLEMENTARY INFORMATION ON NATURAL GAS, OIL AND NGL RESERVES (UNAUDITED)
Aggregate Capitalized Costs
The aggregate amount of capitalized costs of natural gas and oil properties and related accumulated depreciation, depletion and amortization as of December 31, 2024 and December 31, 2023 is as follows:
December 31,
December 31,
Producing properties
$
223,043,942
$
209,082,847
Non-producing minerals
50,156,199
56,670,341
Non-producing leasehold
1,650,712
2,150,104
274,850,853
267,903,292
Accumulated depreciation, depletion and amortization
(122,030,459
)
(113,506,928
)
Net capitalized costs
$
152,820,394
$
154,396,364
Costs Incurred
For the years ended December 31, 2024 and 2023, the Company incurred the following costs in natural gas and oil producing activities:
Year Ended December 31,
Property acquisition costs
$
7,834,849
$
30,435,595
Development costs
94,022
113,967
$
7,928,871
$
30,549,562
Estimated Quantities of Proved Natural Gas, Oil and NGL Reserves
The following unaudited information regarding the Company’s natural gas, oil and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.
Proved natural gas and oil reserves are those quantities of natural gas and oil which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the 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.
The independent consulting petroleum engineering firm of Cawley, Gillespie and Associates, Inc. (CG&A) of Fort Worth, Texas, prepared the Company’s natural gas, oil and NGL reserves estimates as of December 31, 2024 and December 31, 2023.
The Company’s net proved natural gas, oil and NGL reserves, which are located in the contiguous United States, as of December 31, 2024 and December 31, 2023, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.
All of the reserve estimates are reviewed and approved by the Company’s Vice President of Engineering. The Vice President of Engineering, and internal staff work closely with the Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. The Company provides 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 the Independent Consulting Petroleum Engineers. Throughout the year, the Vice President of Engineering and internal staff meet regularly with representatives of the Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions.
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers (SPE) entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, development plans and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The proved undeveloped reserves were estimated for locations that have been permitted, are currently drilling, are drilled but not yet completed, or locations where the operator has indicated to the Company its intention to drill.
For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas). Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.
Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available.
Net quantities of proved, developed and undeveloped natural gas, oil and NGL reserves are summarized as follows:
Proved Reserves
Natural Gas
Oil
NGL
Total
(Mcf)
(Barrels)
(Barrels)
Bcfe
December 31, 2022
61,205,493
1,372,006
1,708,575
79.7
Revisions of previous estimates
(4,997,247
)
29,514
(86,414
)
(5.3
)
Acquisitions
7,322,724
35,228
20,361
7.7
Divestitures
(7,296,462
)
(340,265
)
(145,231
)
(10.2
)
Extensions, discoveries and other additions
7,211,533
158,395
102,849
8.8
Production
(7,457,084
)
(182,916
)
(137,484
)
(9.4
)
December 31, 2023
55,988,957
1,071,962
1,462,656
71.2
Revisions of previous estimates
(4,947,215
)
10,432
(45,846
)
(5.2
)
Acquisitions
2,366,885
13,425
8,531
2.5
Divestitures
(4,594
)
(2,276
)
-
(0.0
)
Extensions, discoveries and other additions
3,872,751
131,717
56,365
5.0
Production
(7,969,948
)
(178,357
)
(133,609
)
(9.8
)
December 31, 2024
49,306,836
1,046,903
1,348,097
63.7
The prices used to calculate reserves and future cash flows from reserves for natural gas, oil and NGL, respectively, were as follows: December 31, 2024 - $2.05/Mcf, $73.48/Bbl, $20.97/Bbl; December 31, 2023 - $2.67/Mcf, $76.85/Bbl, $21.98/Bbl.
The changes in reserves at December 31, 2024, as compared to December 31, 2023, are attributable to:
Revisions of previous estimates from December 31, 2023 to December 31, 2024 that were primarily the result of
•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.
Acquisitions and divestitures were the result of
•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.
Extensions, discoveries and other additions from December 31, 2023 to December 31, 2024 that are principally attributable to
•Reserve extensions, discoveries and other additions of 5.0 Bcfe (comprised of 2.0 Bcfe proved developed and 3.0 Bcfe proved undeveloped reserves) principally resulting from:
a)The Company’s 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.
b)The Company’s 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.
And production of 9.8 Bcfe from the Company’s natural gas and oil properties.
Proved Developed Reserves
Proved Undeveloped Reserves
Natural Gas
Oil
NGL
Natural Gas
Oil
NGL
(Mcf)
(Barrels)
(Barrels)
(Mcf)
(Barrels)
(Barrels)
December 31, 2023
44,479,988
937,465
1,362,944
11,508,969
134,497
99,712
December 31, 2024
42,549,110
948,078
1,322,146
6,757,726
98,825
25,951
The following details the changes in proved undeveloped reserves for 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.
The Company anticipates that all 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, the Company will remove the reserves associated with those locations from proved reserves as revisions.
Standardized Measure of Discounted Future Net Cash Flows
Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.
Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of natural gas, oil and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced, based on continuation of the economic conditions applied for such year.
Estimated future income taxes are computed using current statutory income tax rates, including consideration for the current tax basis of the properties and related carry forwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Company’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.
Year Ended December 31,
Future cash inflows
$
206,317,618
$
264,083,714
Future production costs
(60,622,892
)
(67,959,181
)
Future development and asset retirement costs
(1,307,480
)
(1,224,333
)
Future income tax expense
(7,979,227
)
(18,437,730
)
Future net cash flows
136,408,019
176,462,470
10% annual discount
(60,153,131
)
(76,071,084
)
Standardized measure of discounted future net
cash flows
$
76,254,888
$
100,391,386
Changes in the standardized measure of discounted future net cash flows are as follows:
Year Ended December 31,
Beginning of year
$
100,391,386
$
197,489,635
Changes resulting from:
Sales of natural gas, oil and NGL, net of
production costs
(26,245,153
)
(29,380,772
)
Net change in sales prices and production costs
(16,835,611
)
(112,688,455
)
Net change in future development and asset
retirement costs
(41,631
)
171,076
Extensions and discoveries
9,694,126
13,586,306
Revisions of quantity estimates
(8,661,885
)
(16,554,366
)
Acquisitions (divestitures) of reserves-in-place
2,540,234
(19,144,486
)
Accretion of discount
11,001,794
24,132,484
Net change in income taxes
6,239,421
34,208,654
Change in timing and other, net
(1,827,793
)
8,571,310
Net change
(24,136,498
)
(97,098,249
)
End of year
$
76,254,888
$
100,391,386

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None

---

ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The Company maintains “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognizes that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Based on their evaluation, with reasonable assurance, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2024.
(b) MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s management is responsible for establishing and maintaining adequate “internal control over financial reporting,” as such term is defined in Exchange Act Rule 13a-15(f). The Company’s internal control structure is designed to provide reasonable assurance to its management and Board regarding the reliability of financial reporting and the preparation and fair presentation of its financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on their evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that the Company’s internal control over financial reporting was effective as of December 31, 2024.
(c) CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter ended December 31, 2024.

---

ITEM 9B. OTHER INFORMATION
ITEM 9B OTHER INFORMATION
None.

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. Directors, Executive Officers and Corporate Governance
Directors
The following table sets forth the directors of the Company and their Board Committee memberships as of March 5, 2025:
Positions/Offices Presently
Served As
Present
Name
Age
Held with the Company
Director Since
Term Ends
Mark T. Behrman (1)(2)
Director, Non-Executive Chairman of the Board
Glen A. Brown (1)(2)
Director
Lee M. Canaan (1)(3)
Director
Steven L. Packebush (1)(3)
Director
John H. Pinkerton (2)(3)
Director
Chad L. Stephens
Director, Chief Executive Officer
1)Member of the Audit Committee.
2)Member of the Compensation Committee.
3)Member of the Governance and Sustainability Committee.
Our Bylaws state that the Board shall be comprised of not less than five members with the exact number of members to be determined by resolution of the Board adopted by a vote of two-thirds (2/3) of the Board or at an annual or special meeting of the stockholders by the affirmative vote of sixty-six and two-thirds percent (66-2/3%) of the shares of outstanding Common Stock entitled to vote. The size of the Board is currently fixed at six members.
The Board is divided into three classes. At each annual stockholders’ meeting, the term of one class expires. Directors in each class ordinarily serve three-year terms, or until the director’s retirement or until his or her successor is elected and qualified. The Board believes it is in the Company’s best interest to continue to have a classified board structure, with three-year terms for its directors, due to the uniqueness of the Company’s assets and strategies. The Company’s focus on ownership of perpetual fee mineral acres requires business strategies that are more long-term oriented as compared to more traditional oil and gas exploration and production companies. We believe that this requires the Company’s directors to have a long-term outlook and understanding rather than a focus on short-term results. We believe this focus on long-term results will serve the Company well and create value for our stockholders.
Biographical Information of Directors
Below is information about the members of our Board. The biographical information reflects the particular experience, qualifications, attributes and skills that led the Board to conclude that each director is qualified to serve on our Board.
Directors Whose Terms End at the 2025 Annual Meeting
Mark T. Behrman, 62, has been with LSB Industries, Inc. (“LSB”), Oklahoma City, (a publicly traded manufacturer and marketer of chemical products for the agricultural, mining and industrial markets) since 2014. Mr. Behrman currently serves as LSB’s Chairman and Chief Executive Officer, a position he has held since December 30, 2018. Mr. Behrman joined LSB as Senior Vice President of Corporate Development and served in that capacity until June 2015 and served as Executive Vice President - Chief Financial Officer from June 2015 through December 2018. Prior to LSB, Mr. Behrman was Managing Director, Head of Investment Banking and Head of the Industrial and Energy Practices of Sterne Agee, Inc. from 2007 to 2014. Mr. Behrman has over 35 years of operational, financial, executive management, and investment banking experience.
Mr. Behrman has served on the Board since 2017, as its Chairman since 2019 and as Audit Committee Chairman from 2018 to 2022. He also has served on the Board of Directors of LSB since 2018 and on the Board of Directors of The Fertilizer Institute since 2019. Mr. Behrman previously has served on the board of directors of the following publicly held companies: Noble International Ltd. (a supplier to the automotive industry), from 1998 to 2007, where he also served as Audit Committee Chairman from 1998 to 2003; Oakmont Acquisition Corporation (a special purpose acquisition corporation), from 2005 to 2007; and Robocom Systems International (a developer and marketer of advanced warehouse management software solutions), from 1998 to 2000.
Mr. Behrman holds an MBA in Finance from Hofstra University and a Bachelor of Science in Accounting, Minor in Finance from Binghamton University.
Mr. Behrman’s qualifications to serve on the Board include his executive management and operational experience, his extensive investment banking experience, his experience in accounting and finance, including as former Chief Financial Officer of LSB Industries, his co-founding and management of several diverse businesses and his previous experience as a director of several public companies.
John H. Pinkerton, 71, has served on the Board since February 1, 2021. Mr. Pinkerton has had a long and distinguished career in the oil and gas industry, including serving at Range Resources Corporation (NYSE: RRC), a petroleum and natural gas exploration and production company, as President in 1990 and as Chief Executive Officer from 1992 until 2012. During his 27-year tenure, Range Resources grew from its small cap origins to be a $13 billion enterprise with a preeminent position in the Marcellus Shale. As CEO of Range Resources, Mr. Pinkerton established the technical expertise to enable a drilling-led strategy complemented by bolt-on acquisitions where synergies would enhance growth. Prior to joining Range Resources, Mr. Pinkerton served in various capacities at Snyder Oil Corporation for 12 years, including the position of Senior Vice President.
Mr. Pinkerton began serving as a director of Range Resources in 1988 and was Chairman of its board of directors from 2008 until his retirement as a director in January 2015. Since 2017, Mr. Pinkerton has served as Executive Chairman and is Chairman of the Board of Directors of Encino Energy, LLC, a Houston-based private oil and gas company. Mr. Pinkerton is also a director of EP Energy Corporation where he has served since October 2020. Mr. Pinkerton received his Bachelor of Arts degree in Business Administration from Texas Christian University, where he now serves on the board of trustees, and a Master’s degree from the University of Texas at Arlington. He has represented the energy industry in policy matters, serving on the executive committee of America’s Natural Gas Alliance.
Mr. Pinkerton’s qualifications to serve on the Board include his widespread skills in the management, acquisition and divestiture of oil and gas properties, including related corporate financing activities, hedging, risk analysis and the evaluation of drilling programs.
Directors Whose Terms End at the 2026 Annual Meeting
Steven L. Packebush, 60, is a founder and partner in Elevar Partners, LLC, a company providing advisory services and capital solutions for companies in the agriculture and energy markets. Prior to Elevar Partners, Mr. Packebush worked at Koch Industries, Inc. for over 30 years, retiring in March 2018. Until his retirement, he was the President of Koch Ag & Energy Solutions (“KAES”). Under his leadership, KAES grew to be one of world’s largest fertilizer companies. Mr. Packebush also oversaw the expansion of KAES, which included the addition of three start-up businesses: Koch Energy Services became one of the largest natural gas marketing companies in North America; Koch Methanol supplied methanol to global customers in the plywood, carpet, fuels, and plastics markets; and Koch Agronomic Services became a global leader in enhanced-efficiency fertilizer production and marketing. Mr. Packebush currently serves on the LSB Industries, Inc. board of directors. He is a graduate of Kansas State University with a bachelor’s degree in agricultural economics. Mr. Packebush was appointed to the Board effective April 2022.
Mr. Packebush’s qualifications to serve on the Board include his extensive management and operational experience and his management of a natural gas marketing company, which provide him with a broad knowledge of the energy market.
Chad L. Stephens, 69, was appointed Chief Executive Officer of the Company on January 16, 2020. Prior to his appointment as Chief Executive Officer, Mr. Stephens served as the Interim Chief Executive Officer of the Company, a position to which he was appointed in August 2019. Mr. Stephens previously served as Senior Vice President - Corporate Development of Range Resources Corporation (“Range”), a position he held from 2002 until his retirement effective December 31, 2018. Mr. Stephens joined Range in 1990 as Senior Vice President - Southwest. While at Range, he was responsible for the origination, valuation and acquisition or divestiture of over $6.0 billion of oil and gas producing properties. Mr. Stephens served on Range’s internal hedging committee and was responsible for the oversight of all gas, oil and NGL marketing and sales. Mr. Stephens holds a Bachelor of Arts degree in Finance and Land Management from the University of Texas. He was appointed to the Board in 2017 and previously served as its Lead Independent Director.
Mr. Stephens’ qualifications to serve on the Board include his 41 years of oil and gas experience, having served 29 years in various senior management roles with Range, including significant experience with mergers and acquisitions, land and risk management, midstream logistics and commodity sales.
Directors Whose Terms End at the 2027 Annual Meeting
Lee M. Canaan, 68, is the founder and portfolio manager of Braeburn Capital Partners, LLC (a private investment management firm), established in 2003 in Bloomfield Hills, MI. Ms. Canaan has over 35 years of oil and gas and investment management experience, starting her career as an Exploration Geophysicist at Amoco Production Company, then ARCO, and AIM/Invesco. She was elected to the Board in 2015.
Ms. Canaan currently serves on the board of EQT Corporation (a natural gas production company operating exclusively in the Appalachian Basin of the U.S.), ROC Energy Acquisition Corporation (a special purpose acquisition corporation looking to acquire non-operated exploration and production working interest properties) and Aethon Energy, LLC (a private exploration and production company with main operations in East Texas and western Louisiana). She has also served on the board of directors of the following publicly held companies: Noble International Ltd. (a supplier to the automotive industry), from 2000 to 2004, where she served as the Compensation Committee Chairman from 2002 to 2004; Oakmont Acquisition Corporation (a special purpose acquisition corporation), from 2005 to 2007; Equal Energy Ltd. (an oil and gas exploration and production company), from 2013 until its sale in 2014; and Rock Creek Pharmaceuticals (a pharmaceutical research and development company), from 2014 to 2016, where she also served as the chairman of the Audit and Nominating and Corporate Governance committees. She also served on the board of Philadelphia Energy Solutions, LLC (a private downstream energy company and the largest crude oil refining complex on the East Coast of the U.S.), from 2018 to 2020. She holds a bachelor’s degree in Geological Sciences from the University of Southern California, a master’s degree in Geophysics from the University of Texas at Austin, and an MBA degree in Finance from The Wharton School of the University of Pennsylvania. She is also a Chartered Financial Analyst.
Ms. Canaan’s qualifications to serve on the Board include her corporate finance, capital markets and merger and acquisition experience; her scientific background in geology and geophysics; her oil and gas exploration knowledge of North American basins; and her experience serving as a director of several public and private companies.
Glen A. Brown, 68, has broad oil and gas experience both as a senior executive and as an independent explorationist. Mr. Brown served as the Senior Vice President of Exploration for Continental Resources (“Continental”) from 2015 to 2017. He joined Continental in 2012 as Manager of New Ventures and in 2013 was named Vice President of Geology. During his career at Continental, he managed annual budgets of $2 to $4 billion with active leasing, drilling and completion programs. Prior to joining Continental, he was an independent owner of NE LLC from 2003 to 2012, which developed projects that resulted in over 200 wells being drilled and completed with 12 different operators. From 1991 to 2003, he served as an Exploration Manager for EOG Resources--Midcontinent Division where he was responsible for various drilling programs and numerous field discoveries. From 1985 to 1991, Mr. Brown held middle management positions with TXO Production Company. Mr. Brown began his career in 1982 as an Exploration Geologist with Marshall R. Young Oil Company where he worked until 1985. He holds a bachelor’s degree in Geology from State University of New York at Plattsburgh and a master’s degree in Geology from New Mexico State University in Las Cruces. Mr. Brown was elected to the Board in 2021.
Mr. Brown’s qualifications to serve on the Board include his 43 years of oil and gas experience identifying acquisition and divestiture targets and assessing risks of projects, his extensive knowledge of prospect economics and of horizontal drilling and completions in unconventional resource plays, and his 34 years in various management roles.
CORPORATE GOVERNANCE AND OUR BOARD
Our Board
Board Leadership Structure and Non-Executive Chairman of the Board
The Company established the position of Non-Executive Chairman of the Board effective August 3, 2021, which replaced the role of Lead Independent Director. It is the policy of the Company that a Non-Executive Chairman of the Board shall be elected annually to preside over meetings of the Board and executive sessions of the Company’s independent directors, to facilitate information flow and communication between the directors and the Chief Executive Officer and to perform such other duties specified by the Board and outlined in the Non-Executive Chairman of the Board Guidelines, which can be viewed on our website: www.phxmin.com under the “Governance Library” section of the “Corporate Governance” tab. The Non-Executive Chairman of the Board determines the agenda and presides over all Board meetings and all executive sessions of non-employee directors. The Non-Executive Chairman of the Board also performs other duties that the Board may from time-to-time delegate to assist the Board in the fulfillment of its responsibilities.
Effective August 26, 2019, Mark T. Behrman was named Lead Independent Director by the Board and was reaffirmed as the Non-Executive Chairman of the Board at the March 4, 2024 Governance and Sustainability Committee meeting.
Meetings and Committees of the Board of Directors
During the fiscal year ended December 31, 2024, the Board held eight meetings. At each meeting, a quorum of directors was present. The non-employee directors held executive sessions at each regularly scheduled Board meeting without management present.
Our Corporate Governance Guidelines provides that all of our directors are expected to attend regularly scheduled Board and committee meetings and the annual meeting of stockholders. During 2024, each director attended at least 75% of the meetings of the Board and each of the Board committees on which he or she served. All of the directors attended the Company’s 2024 annual meeting.
Each year, the Board conducts a formal evaluation of its performance. Additionally, each Board committee conducts a formal evaluation of such committee’s performance. The Board and Board committee evaluations address, among other matters, the qualifications and performance of individual directors, overall Board or committee dynamics, the quality of information received from management, the appropriateness of matters reviewed and the quality of Board or committee deliberations. The results of these evaluations are discussed with the chairs of the relevant committees, the Non-Executive Chairman of the Board, or the full Board in executive session, as appropriate.
Board Committees
The independent members of the Board are elected to serve on various Board committees. The Board presently has three standing committees: the Audit Committee, the Compensation Committee, and the Governance and Sustainability Committee. Each committee operates under a charter that has been approved by the Board, and the chair of each committee reports to the Board on actions taken at each committee meeting.
Audit Committee
The Audit Committee is currently comprised of Mark T. Behrman, Glen A. Brown, Lee M. Canaan (Chair) and Steven L. Packebush. The Board has determined that each member of the Audit Committee during 2024 met all applicable independence requirements during such member’s service on the committee and the financial literacy requirements of the SEC and the NYSE. Mark T. Behrman and Lee M. Canaan have been determined by the Board to each meet the “audit committee financial expert” requirements of the SEC. For purposes of complying with NYSE rules, the Board has determined that none of the Committee members currently serves on the audit committees of more than three public companies.
The purpose of the Audit Committee is to provide assistance to the Board in fulfilling its oversight responsibility to the Company’s stockholders, potential stockholders, the investment community and others, relating to: the integrity of the Company’s financial statements; the financial reporting process; the systems of internal accounting and financial controls; the performance of the Company’s internal audit function and independent auditors; the independent auditors’ qualifications and independence; cybersecurity risk, and the Company’s compliance with ethics policies and legal and regulatory requirements. The primary responsibility of the Audit Committee is to oversee the Company’s financial reporting process on behalf of the Board and report the results of the Audit Committee’s activities to the Board. While the Audit Committee has the responsibilities and powers set forth in the Audit Committee Charter, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company’s financial statements are complete and accurate and are in accordance with generally accepted accounting principles. Management is responsible for the preparation, presentation and integrity of the Company’s financial statements and for the appropriateness of the accounting principles and reporting policies that are used by the Company. The independent auditors are responsible for auditing the Company’s financial statements and for reviewing the Company’s unaudited interim financial statements.
The Audit Committee met four times during 2024. The Audit Committee Charter is available on our website: www.phxmin.com under the “Governance Library” section of the “Corporate Governance” tab.
Compensation Committee
The Compensation Committee is currently comprised of Mark T. Behrman, Glen A. Brown (Chair) and John H. Pinkerton. During 2024, each member of the Compensation Committee met the applicable independence requirements during his service on the Compensation Committee, including the enhanced independence standards of the NYSE, and qualifies as a “Non-Employee Director” under Rule 16b-3 of the Exchange Act.
The purpose of the Compensation Committee is to discharge the Board’s responsibilities relating to compensation, employee benefits and incentive programs of the Company. The Compensation Committee has the overall responsibility of approving and evaluating executive officer compensation, retirement plans, policies and programs of the Company, and the compensation of directors. The Compensation Committee’s function includes reviewing officer performance and recommending to the Board compensation amounts for executive officers and directors. The Compensation Committee also oversees the administration of the Company’s 401(k) Plan. For additional information regarding the Compensation Committee, please see the Compensation Committee Charter and the “Compensation Discussion and Analysis” section of this Form 10-K.
The Compensation Committee met three times during 2024. The Compensation Committee Charter is available on our website: www.phxmin.com under the “Governance Library” section of the “Corporate Governance” tab.
Governance and Sustainability Committee
The Governance and Sustainability Committee is currently comprised of Lee M. Canaan, Steven L. Packebush and John H. Pinkerton (chair). The Board determined that each member of the Governance and Sustainability Committee during 2024 met the applicable independence requirements.
The purpose of the Governance and Sustainability Committee is to assist the Board with the management of its corporate governance, nominating and sustainability duties and responsibilities. Functions of the Governance and Sustainability Committee include: searching for, identifying and screening individuals qualified to become members of the Board; recommending to the Board when new members should be added to the Board; recommending to the Board individuals to fill vacant Board positions; recommending to the Board nominees for election as directors at each annual meeting; and recommending the committee structure of the Board and the directors who will serve as members and chairs of each committee. If a vacancy on the Board exists that will not be filled by an incumbent director, the Governance and Sustainability Committee identifies prospective nominees from several sources, including through the Board’s and management’s business and industry contacts and through stockholder recommendations. Currently, the Company does not pay a fee to any third party to identify or evaluate, or assist in identifying or evaluating, potential nominees.
The Governance and Sustainability Committee is also responsible for overseeing and evaluating compliance by the Board and management with the Company’s corporate governance principles and its Code of Ethics and Business Practices. The Governance and Sustainability Committee reviews periodically the corporate governance policies and principles of the Company and oversees the creation and implementation of policies and procedures appropriate for the Company related to the environment, sustainable development, and corporate responsibility.
Diversity
Although the Governance and Sustainability Committee does not have a formal policy with respect to diversity when considering potential nominees for Board membership, the Governance and Sustainability Committee seeks individuals with backgrounds and qualities that, when combined with those of the Company’s existing directors, provide a blend of skills and experience that will further enhance the Board’s effectiveness at the time the consideration is made. When considering potential nominees for Board membership, the Governance and Sustainability Committee considers, among other things, the candidate’s character, wisdom, judgment, acumen, diversity, skills, financial literacy, experience and understanding of and involvement in the oil and gas industry. The committee also considers a potential nominee’s availability to devote the time and effort necessary to fulfill his or her responsibilities in the context of the needs of the Company and the Board. Our Bylaws generally provide that a person may not stand for election or re-election as a director after attaining the age of 75, provided that, in the sole discretion of the Board, a director who is over 75 years of age may be re-elected for one additional term of one year.
Stockholder Nominees
The Governance and Sustainability Committee will consider nominees proposed by stockholders of the Company if the requirements set forth in the Company’s Bylaws are satisfied. Nominations from our stockholders must include sufficient biographical information for the Governance and Sustainability Committee to appropriately assess the proposed nominee’s background and qualifications. To propose a prospective nominee for consideration by the Governance and Sustainability Committee, stockholders must submit the proposal in writing to PHX Minerals Inc., Attention: Secretary, 1320 S. University Dr., Suite 720, Fort Worth, Texas 76107. Any such submission must be accompanied by the proposed nominee’s written consent to being named as a nominee and to serve as a director, if elected. Whether recommended by a stockholder or through the activities of the Governance and Sustainability Committee, the Governance and Sustainability Committee seeks to select candidates who have distinguished records and who will make significant contributions to the Board and the Company. There are no differences in the manner in which the Governance and Sustainability Committee evaluates nominees for director based on whether a nominee was recommended by the incumbent directors or by a stockholder.
The Governance and Sustainability Committee met three times during 2024. The Governance and Sustainability Committee Charter and the Code of Ethics and Business Practices are available on our website: www.phxmin.com under the “Governance Library” section of the “Corporate Governance” tab.
Board Role in Risk Oversight
Management is responsible for day-to-day risk assessment and mitigation activities. The Board is responsible for risk oversight, focusing on the Company’s overall risk management strategy, its degree of tolerance for risk, and oversight of the steps management is taking to manage the Company’s risk. This process is designed to provide the Board timely visibility needed for the identification, assessment and management of critical risks. The Audit Committee assists the Board by annually reviewing and
discussing with management this process and its functionality. The areas of critical risk for the Company include information technology, strategic, operational, compliance, environmental and financial risks. The Board (or the Audit Committee) receives information regarding areas of risk and potential risk exposure through updates from the appropriate members of management to enable the Board to understand and monitor our risk management process. Information brought to the attention of the Audit Committee is appropriately shared with the Board.
The Board has oversight responsibility for our 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 and ultimately to the Board. There were no such cybersecurity incidents in 2024, 2023, or 2022. Management presents an assessment of our cybersecurity processes, procedures, and results of testing to the Audit Committee at least annually.
Code of Ethics
The Board has adopted a Code of Ethics and Business Practices applicable to all of our directors, officers and employees. Each director, officer and employee annually submits a signed statement that he or she is in compliance with the Company’s Code of Ethics and Business Practices. In addition, the Board has adopted a Code of Ethics for Senior Financial Officers. Our Chief Executive Officer and Chief Financial Officer are held to the standards outlined in the Code of Ethics for Senior Financial Officers and are required to annually acknowledge compliance with this code. Copies of both the Code of Ethics and Business Practices and Code of Ethics for Senior Financial Officers are available on our website: www.phxmin.com under the “Governance Library” section of the “Corporate Governance” tab.
Communications with the Board of Directors
We provide a process for stockholders and other interested parties to send communications to the Board. Stockholders or other interested parties who wish to contact the Non-Executive Chairman of the Board, the non-employee directors as a group, or any of our individual Board members may do so by writing: Board of Directors, PHX Minerals Inc., Attention: Mark Behrman, 1320 South University Drive, Suite 720, Fort Worth, TX 76107. Correspondence directed to any individual Board member is referred, unopened, to that member. Correspondence not directed to a particular Board member is referred, unopened, to the Non-Executive Chairman of the Board.
Executive Officers
Our executive officers who served the Company during 2024 are listed below. Based on an examination of the roles and functions of each of the Company’s officers, including any policy-making functions, the Board determined that only Chad L. Stephens, the Company’s President and Chief Executive Officer, and Ralph D’Amico, the Company’s Executive Vice President and Chief Financial Officer, qualified as executive officers, as defined in Rule 3b-7 under the Exchange Act, during 2024. All officers hold office at the discretion of the Board and may be removed from office, with or without cause, at any time by the Board.
Positions and Offices
Officer
Name
Age
Presently Held With the Company
Since
Chad L. Stephens (1)
President and Chief Executive Officer
Ralph D’Amico
Executive Vice President and Chief Financial Officer
(1)Biographical information for Mr. Stephens is set forth above under “Biographical Information of Directors -Directors Whose Terms End at the 2026 Annual Meeting.”
Ralph D’Amico has served as our Executive Vice President and Chief Financial Officer since March 9, 2020. Mr. D’Amico joined the Company on January 2, 2019 and served as Vice President of Business Development and Investor Relations from that date through March 9, 2020. Mr. D’Amico previously served as Managing Director in the energy investment banking group at Stifel, Nicolaus & Company, Incorporated and at Seaport Global Securities and previously held positions within the investment banking practices of Jefferies, Friedman Billings Ramsey, and Salomon Smith Barney. Mr. D’Amico holds a bachelor’s degree in finance from the University of Maryland and an MBA from The George Washington University.
Delinquent Section 16(a) Reports
Section 16(a) of the Exchange Act requires directors and officers and persons who own more than ten percent of the Company’s Common Stock to file with the SEC initial reports of ownership and reports of changes in ownership of the Common Stock, and to furnish the Company with copies of such reports. During the fourth quarter of 2024, the Company determined that the shares of Common Stock credited to a director’s deferred compensation account pursuant to the Directors’ Deferred Compensation Plan (“Deferred Stock Units”), which includes shares credited in lieu of cash fees and shares credited as a result of the reinvestment of dividends on previously issued Deferred Stock Units, should be reported on Form 4 at the time such Deferred Stock Units are credited to the director’s account. Prior to such determination, directors did not report Deferred Stock Units on a Form 4. As result of this determination, the following directors reported previously unreported Deferred Stock Units as follows: (i) on January 2, 2025, Mr. Packebush filed a Form 4 reporting Deferred Stock Units granted on December 31, 2024 (such Deferred Stock Units granted on December 31, 2024 were timely reported) and in the footnotes reported an additional 43,655 previously unreported Deferred Stock Units that had been credited to Mr. Packebush since he became a director in 2022; (ii) on January 2, 2025, Mr. Behrman filed a Form 4 reporting Deferred Stock Units granted on December 31, 2024 (such Deferred Stock Units granted on December 31, 2024 were timely reported) and in the footnotes reported an additional 146,187 previously unreported Deferred Stock Units that had been credited to Mr. Behrman since he became a director in 2017; (iii) on February 3, 2025, Ms. Canaan filed a Form 5 reporting 7,782 previously unreported Deferred Stock Units that had been credited to Ms. Canaan since she became a director in 2015; (iv) on February 3, 2025, Mr. Brown filed a Form 5 reporting 51,326 previously unreported Deferred Stock Units that had been credited to Mr. Brown since he became a director in 2021; and (v) on February 3, 2025, Mr. Pinkerton filed a Form 5 reporting 15,982 previously unreported Deferred Stock Units that had been credited to Mr. Pinkerton since he became a director in 2021. Additionally, on December 20, 2024, each of Mr. Stephens, Mr. D’Amico and Mr. True were granted shares of Common Stock (“Additional Performance Shares”) pursuant to the terms of a Restricted Stock Award Agreement (“Award Agreement”) each individual had entered into with the Company, with such grants being the result of achieving 125% of the target performance goals under the Award Agreement. On January 16, 2025, each of Mr. Stephens, Mr. D’Amico and Mr. True filed a Form 4 Amendment reporting the grant of the Additional Performance Shares as an additional line item on the Form 4 filing each had originally filed on December 23, 2024 to report the withholding of shares of Common Stock to cover payroll tax liability on the vesting of previously issued shares of restricted Common Stock and on the grant of the Additional Performance Shares. Other than the late Form 4 filings related to the previously unreported Deferred Stock Units and the grant of Additional Performance Shares, based on a review of the filings with the SEC and representations that no other reports were filed, the Company believes that during 2024 all directors and officers and persons who own more than ten percent of the Company’s Common Stock complied with the reporting requirements of Section 16(a) of the Exchange Act.
Family Relationships
There are no family relationship between any of the Company’s directors or executive officers.
Director or Officer Involvement in Certain Prior Legal Proceedings
The Company’s directors and executive officers were not involved in any legal proceedings as described in Item 401(f) of Regulation S-K in the past ten years.
Material Changes to Stockholder Nomination Procedure
There has been no material change to the procedures by which stockholders may recommend nominees to the Company’s Board since our last public disclosure.
Insider Trading Policy
We have adopted a formal Insider Trading Policy that applies to all directors, officers and employees. The policy provides guidelines with respect to transactions in securities of the Company and the handling of confidential information about the Company and the companies with which we do business. The policy was adopted to promote compliance with federal, state and foreign securities laws that prohibit certain persons who are aware of material nonpublic information about a company from trading in securities of that company or providing material nonpublic information to other persons who may trade on the basis of that information. A copy of our Insider Trading Policy is filed as Exhibit 19.1 to this Form 10-K.

---

ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. Executive Compensation
Compensation Discussion and Analysis
This Compensation Discussion and Analysis (CD&A) describes the Company’s compensation objectives and philosophy, the material elements of our executive compensation program for our named executive officers, recent compensation decisions and the factors the Compensation Committee considered in making such decisions.
This CD&A focuses on compensation earned during 2024 by our Chief Executive Officer and Chief Financial Officer. As determined by the Board, the only two officers who qualified as named executive officers (collectively, “named executive officers” or “NEOs”) during 2024 were as follows:
NEO
Position
Chad L. Stephens
President and Chief Executive Officer
Ralph D’Amico
Executive Vice President and Chief Financial Officer
Executive Compensation Overview
Our executive compensation program includes a mix of compensation components in furtherance of our pay-for-performance philosophy, while also providing a competitive level of overall compensation to our executive officers. The program is designed to reward our leadership team for operating and financial results for the year and over the long term, building per share value for our stockholders.
During fiscal 2020, the Board made the decision to focus on perpetual oil and natural gas mineral ownership and growth through mineral acquisitions and the development of its mineral acreage inventory in its core areas of focus. In accordance with this strategy, beginning in January 2020 we ceased taking any working interest positions on our mineral and leasehold acreage. The Company believes that its strategy to focus on mineral ownership is the best path forward to providing our stockholders the highest risk-weighted returns on their investments. The Compensation Committee has aligned short-term incentive metrics to align with our business strategy in 2024.
The short-term incentive plan objective performance metrics are focused on financial performance of the Company utilizing operating cash flow and expense management metrics and growth in royalty production volumes. This structure is aligned with our stated strategy of divesting working interests and growing royalty minerals rights. Our compensation philosophy is (i) to be stockholder aligned by heavily weighting equity performance-based compensation tied to goals that builds long-term value for stockholders; (ii) to be competitive with the market allowing the Company to attract and retain talent; (iii) to motivate and reward for individual performance; and (iv) to be transparent utilizing measurable metrics and clearly articulated objectives. Furthermore, the Company believes in policies that promote stock ownership among our executives and directors.
Summary of Current Compensation Program
Our current executive compensation structure is comprised of a mix of compensation elements intended to support the Company’s operating, financial and strategic goals and objectives in both the short-term and long-term. Each component of our compensation program is summarized below:
Component
Form of Payout
Objectives
How Values are Determined
Base Salary
Cash
•Compensate our executive officers for their experience and expertise
•Compete for talent with comparable companies in the oil and gas industry
Base salaries are evaluated and determined annually based on Company and individual results, overall responsibilities of each officer, expertise required in execution of the position and comparable peer company ranges.
Annual Bonuses
Cash
•Motivate our executive officers to achieve short-term business goals and objectives
•Reward achievement of operational performance metrics aligned with long-term business objectives
•Reward our officers for individual executive performance that demonstrates the application of targeted competencies
Cash bonus payments are a variable component of our compensation that is at-risk. The performance metrics associated with cash bonus payments are aligned with our annual performance goals and objectives.
The Compensation Committee annually evaluates and determines the annual operational performance metrics that align with long-term value creation. Subjective job responsibility performance goals of each officer are reviewed to ensure achievement of targeted competencies is rewarded.
Overall bonus levels are based on a comparable peer group.
Long-Term Incentive (LTI) Awards
Restricted Stock Awards
•Motivate achievement of long-term goals
•Retain and attract key officers who perform over the longer time period
•Encourage our executive officers to create long-term value for our stockholders
•Promote pay-for-performance by aligning our executive officers with stockholders through meaningful ownership interests in the Company
LTI restricted equity-based compensation includes restricted (time-based) and performance shares that vest based on the market price performance of our Common Stock.
LTI performance metrics are evaluated annually to determine alignment with business strategy and stockholder value creation.
LTI ultimate realization is based on employment metrics and performance metrics over the vesting period of the restricted stock grants. The CEO’s LTI is 100% performance-based.
Compensation Philosophy and Objectives
The Compensation Committee strives to maintain a compensation program that will attract, retain and motivate key executive officers by providing incentives to reward the officers for performance efforts that support our short-term and long-term strategic objectives and is competitive with industry practice. The key objectives of the Company’s compensation program are to:
•Align the interests of our executives with those of our stockholders through long-term share ownership - The Company uses restricted stock awards under the LTIP to align the financial interests of our executives with those of our stockholders and to provide a longer-term incentive form of compensation, with vesting provisions relating to continuous length of service to the Company and market price performance of our Common Stock.
•Attract, retain and incentivize key executives, who are necessary to continue execution of our business strategies principally involving growth in value through divestiture of our low-margin working interests, acquisition of higher-margin mineral interests and active management of our extensive mineral acreage position - Reward executives who contribute to our success and motivate the officers to develop and execute short-, medium-, and long-term business strategies as well as meet annual goals approved by the Board.
•Provide transparency regarding our compensation program for the benefit of executives and stockholders- Use measurable metrics such as the financial and operating performance of the Company and the market price performance of our Common Stock as key factors in determining compensation.
•Motivate and reward individual performance that contributes meaningfully to Company performance - Evaluation of the individual performance of each executive officer affects most aspects of the executive’s compensation. Market data, individual performance and level of responsibility are considered in determining an executive’s annual salary and are important factors in deciding discretionary cash bonuses.
Risk Considerations Relating to Compensation
Our compensation program is designed to focus on meeting the Company’s objectives and goals while discouraging management from undue risk-taking. When establishing and reviewing our executive compensation program, the Compensation Committee has considered whether the program encourages unnecessary or excessive risk taking and has concluded that it does not. While behavior that may result in inappropriate risk taking cannot necessarily be prevented by the structure of compensation practices, we believe that our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on the Company.
Our compensation program is comprised of both fixed and variable incentive-based elements. The fixed component of our compensation program is base salary. A fixed base salary provides reliable, foreseeable income that mitigates the focus of our employees on our immediate financial performance or our stock price, encouraging employees to make decisions in the Company’s best long-term interests. The variable incentive components are designed to be sensitive to our goals and objectives, performance and stock price. In combination, we believe that our compensation structure does not encourage our officers and employees to take unnecessary or excessive risks in performing their duties.
Moreover, with limited exceptions, the Compensation Committee retains discretion to impose additional conditions and adjust compensation pursuant to our clawback policy as well as for quality of performance and adherence to Company values. The restricted stock that the Company has granted to its executive officers generally has a three-year vesting period, which further mitigates compensation risk because an executive officer who resigns (other than as a result of retirement) or is terminated prior to the end of the vesting period will forfeit his or her unvested restricted stock.
Role of the Compensation Committee and the Board
The Compensation Committee is responsible for establishing, implementing and monitoring all facets of the compensation of our executive officers. In particular, the Compensation Committee’s role is to recommend to the Board for final approval, the compensation, benefit plans and policies, and, in addition, to review, approve and recommend to the Board annually all compensation decisions relating to the Chief Executive Officer and the other executive officers of the Company. The Compensation Committee reviews the executive compensation program and recommends compensation levels, performance metrics, executive bonus distributions and restricted stock awards.
For 2024, the Compensation Committee and the Board, with advice from its compensation consultant, Meridian Compensation Partners (“Meridian”), made all compensation decisions for the executive officers as described in more detail below in “Role of the Compensation Consultant”. The Compensation Committee and the Board reviewed the performance of Mr. Stephens, who serves as our Chief Executive Officer, and set his compensation. Mr. Stephens was not present during these discussions. Mr. Stephens made compensation recommendations to the Compensation Committee with respect to Mr. D’Amico. Mr. D’Amico was not present during these discussions. The Board made the final decisions and approved the compensation of the Company’s executive officers.
Role of the Compensation Consultant
In an effort to align our executives’ compensation competitively with the market, the Compensation Committee engaged an outside, independent compensation consultant, Meridian, to review levels and incentive components of the NEO’s compensation for 2024, including base salaries, the design of our incentive programs and executive compensation levels.
The Compensation Committee, with the assistance of Meridian, selected a group of “peer companies” for comparison purposes in determining compensation for 2024, which selected peer group is provided below.
The Compensation Committee uses the peer group to estimate the market compensation for talent. The Compensation Committee selects reference companies preferably in the minerals business with similar market capitalizations and operating models. The Compensation Committee supplements this very limited list with smaller energy companies under the belief that the management teams of small energy companies possess similar experience, training, and knowledge. The Compensation Committee recognizes the Company’s small market capitalization versus the reference peer group and therefore targets total compensation below the 50th percentile of such group. For 2024 and 2023, the Compensation Committee used the following companies as the Company’s peer
group. In the event a member of the peer group is acquired or no longer publicly traded, the Compensation Committee will remove that company from the peer group without replacement.
2024 Reference Peer Group
Amplify Energy Corp.
Riley Exploration Permian, Inc.
Empire Petroleum Corporation
Ring Energy, Inc.
Epsilon Energy Ltd.
SandRidge Energy, Inc.
Evolution Petroleum Corporation
SilverBow Resources, Inc.
Granite Ridge Resources, Inc.
U.S. Energy Corp
Kimbell Royalty Partners, LP
VAALCO Energy, Inc.
PrimeEnergy Resource Corporation
2023 Reference Peer Group
Amplify Energy Corp.
Riley Exploration Permian, Inc.
Battalion Oil Corporation
Ring Energy, Inc.
Empire Petroleum Corporation
SandRidge Energy, Inc.
Epsilon Energy Ltd.
SilverBow Resources, Inc.
Evolution Petroleum Corporation
U.S. Energy Corp
Kimbell Royalty Partners, LP
VAALCO Energy, Inc.
PrimeEnergy Resource Corporation
The Compensation Committee has sole authority to retain and terminate independent compensation consultants and to determine the terms of their retention. In 2024 and 2023, Meridian received appropriate information from the Compensation Committee, reported directly to the Compensation Committee and did not provide any other services to the Company. Management does not direct or oversee the retention or activities of Meridian with respect to the Company’s executive compensation program.
Role of Stockholder Say-On-Pay Vote
We have historically received very strong stockholder support for our executive compensation practices. At the 2024 annual meeting of stockholders, approximately 80% of the shares cast were voted in support of the Company’s compensation program for the named executive officers. In consideration of these results, the Compensation Committee has acknowledged the support received from our stockholders and views these results as an affirmation of our existing executive compensation policies and continued efforts to enhance our pay-for-performance practices. The Say-On-Pay vote serves as an additional tool to guide the Board and the Compensation Committee in ensuring alignment of our executive compensation program with the interests of our stockholders. The Compensation Committee will carefully consider the outcome of this year’s Say-On-Pay vote when considering future executive compensation arrangements. We currently intend to continue to hold this vote annually.
Elements of 2024 Compensation Program
The principal elements of our executive compensation program are (i) an annual base salary, (ii) an annual cash bonus, (iii) restricted stock awards, and (iv) matching cash contributions to our 401(k) Plan. Awards of restricted stock pursuant to the PHX Minerals Inc. LTIP are an integral part of the Company’s compensation program as a retention and long-term incentive form of compensation.
Base Salaries
The base salaries of our executive officers are reviewed annually by the Compensation Committee, and the Compensation Committee recommends future salary adjustments, if any, to the Board for final approval. The Compensation Committee and the Board consider various factors, including:
•overall responsibilities of the executive officers;
•scope, level of experience and expertise required to successfully execute the executive officer’s position with the Company;
•demonstrated individual performance of the executive officer;
•recommendation of the Chief Executive Officer with respect to other executive officers; and
•the current level of base salaries for executive officers compared to similar positions in our industry.
Base salaries are based on the individual’s responsibilities and experience, taking into account, among other factors, the individual’s initiative, contribution to overall performance, handling of projects during the year, and yearly financial and operating results of the Company. Salaries for the named executive officers in 2024 are set forth in the “Summary Compensation Table” below and were reviewed by the Compensation Committee and approved by the Board based on the considerations described above.
Annual Cash Bonuses
Annual cash bonuses are largely determined by the preceding fiscal year’s operational and financial performance. Annual cash bonuses are targeted as a percentage of each executive officer’s base salary, determined by the weighting of objective performance metrics and subjective performance goals applicable to each executive officer. During the annual goal-setting process, the Compensation Committee and the Board approve objective performance metrics and subjective or discretionary performance goals that focus on the manner in which the Company’s business is managed.
The Compensation Committee believes that the cash bonuses for executive officers should principally reflect how well the officers achieved both objective and subjective performance metrics determined by the Compensation Committee and outlined below. The executive officers’ target cash bonuses as a percentage of base salary and weighting between objective and subjective metrics is:
Company
Title
% of Salary
Objective Performance Metrics(1)
Subjective
Discretionary
Metrics(1)
Maximum Bonus Achievable as % of Salary
Chief Executive Officer
100%
70%
30%
150%
Chief Financial Officer
80%
70%
30%
120%
(1) These percentages represent the target payout, based upon percentage of annual salary. However, executive officers can earn up to 150% of the objective and subjective metrics as further described below.
Objective Performance Metrics
The Compensation Committee and the Board approved the use of the following categories of objective performance metrics in determining annual cash bonus amounts for the year ended December 31, 2024 in January 2024:
•Operating cash flow per share as compared to a budgeted amount;
•2024 royalty production growth compared to 2023 actual; and
•Cash general and administrative expense (“G&A”) per MCFE produced as compared to a budgeted amount.
For the year ended December 31, 2024, the Compensation Committee approved Threshold (Minimum), Target and Maximum levels for the objective performance metrics (as set forth in the tables below). In any objective performance metric category, if the Threshold is achieved, 50% of weighting is earned. If the Target is achieved, 100% of weighting is earned. If the Maximum is achieved, 150% of weighting is earned. Achievement between the Threshold and the Target results in earning between 50% and 100% of weighting. Achievement between the Target and the Maximum results in earning between 100% and 150% of weighting. If the Threshold is not achieved in an objective performance metric category, no credit is earned.
The following tables set forth the Company’s performance metrics as established by the Compensation Committee.
For the Year Ended December 31, 2024
Metric Category
Threshold
Target
Maximum
Weighting
Actual Results
Operating cash flow per share(1)
$0.50
$0.54
$0.58
35%
$0.53
Royalty production growth (mcfe)(2)
9,065,607
9,301,183
9,536,759
25%
8,760,394
Cash G&A per mcfe(3)
$1.00
$0.96
$0.92
10%
$0.94
Discretionary
n/a
n/a
n/a
30%
33%
(1) Operating cash flow is defined as: (a) oil and gas sales plus (b) lease bonus and rental revenues plus (c) realized cash portion of hedges minus (d) lease operating expense (“LOE”) (e) minus transportation, gathering and marketing minus (f) production tax minus (g) cash G&A (as defined below) minus (h) interest expense divided by the average of basic shares outstanding. The target was set at the budgeted amount and for purposes of determining performance, the threshold, target, and maximum was adjusted to remove the remaining budgeted cash flow associated with working interest divestitures from the effective date of the sale, if any.
(2) Royalty production growth includes natural gas, oil and NGL royalty volumes recorded through the accounting process, and, for the year ended December 31, 2024, the Threshold, Target and Maximum represent growth rates of 11.6%, 14.5%, and 17.4%, respectively, compared to 2023 production volumes.
(3) Cash G&A is defined as the cash portion of G&A including the target short-term incentive (“STI”) amount for the applicable STI period, and excludes STI cash payments from prior periods, consulting and legal fees incurred by the Board, and expenses associated with business combinations, divided by total production for that period. The target was set at the budgeted amount and production was adjusted to remove budgeted production associated with working interest divestitures from the effective date of the sale, if any.
In setting the performance metrics for the year ended December 31, 2024, the Compensation Committee determined that the operating cash flow, cash G&A expense and discretionary metrics had the effect of discouraging excessive risk taking and controlling general and administrative costs. The Compensation Committee also determined that the royalty production growth metrics aligned management’s compensation with the Company’s strategy of focusing on mineral growth. The operating cash flow target for the fiscal year is heavily influenced by natural gas and oil strip prices at the time the target metrics are set. The Compensation Committee does not believe that these performance metrics reward executives for taking risks beyond those risks inherent in the oil and gas business.
The Compensation Committee has the discretion to modify the effect of any of the objective performance metrics if unforeseen or uncontrollable conditions result in any of the performance metrics not being relevant to the Company’s results for the fiscal year. No adjustments were made to the metrics for the year ended December 31, 2024.
Subjective Performance Goals
The Compensation Committee and the Board approved discretionary subjective performance goals that focus heavily on the manner in which our business is managed by the executive officers. The five subjective metrics are strategy execution, operations expense management, acquisition performance, investor relations, and valuation. An evaluation of the Chief Executive Officer is performed annually by the Compensation Committee. The Chief Executive Officer performs the evaluation of each of the other executive officers. In these evaluations, performances are evaluated on each of the detailed areas of responsibility.
Determination of Annual Cash Bonus Awards
The Compensation Committee reviewed the performance of the Company’s NEOs in meeting their objective performance metrics and subjective performance goals for the year ended December 31, 2024. The tables above set forth the actual results of the Company for each objective performance metric level to determine the objective portion of the cash bonuses.
During 2024, the Company did not meet the threshold for the royalty production growth metric. However, the Company met the threshold for the operating cash flow per share and the target for cash G&A per mcfe, resulting in a combined payout of 32% of the award for these objective performance metrics. The Compensation Committee determined that management’s performance in the five subjective areas that govern the discretionary portion of the annual bonus warranted an award of 33% of base salary. The total annual bonus percentage earned for the year ended December 31, 2024 was 65%. See “Executive Compensation - Summary Compensation Table” for the dollar amount of cash bonuses for 2024 and 2023.
Cash bonuses are generally paid in the first fiscal quarter of the following fiscal year based on the preceding fiscal year’s metric results. The cash bonus payments made to our NEOs are set forth below in the “Summary Compensation Table” under “Executive Compensation.”
Long-Term Equity-Based Restricted Stock Compensation
Our executive officers are eligible to receive stock-based awards under the LTIP. The objectives of the LTIP are to attract and retain key employees, align their interests with those of our stockholders, motivate our executive officers to achieve long-term goals, and reward individual performance. Because executives’ compensation from stock-based awards is tied to the Company’s stock price performance, the Compensation Committee believes stock-based awards create a strong incentive to improve long-term financial performance and increase stockholder value.
We enter into restricted stock agreements with our officers and directors when restricted stock awards are granted. These agreements include the terms and conditions of the restricted stock awards. Vesting provisions contained in the restricted stock
agreements are used by the Compensation Committee as a method to tie executive compensation both to continuing service by the executive to the Company and to growth in stockholder value, as measured by the market price of the Company’s shares. Under various circumstances, the restricted stock awards may vest completely, partially or not at all. The Compensation Committee believes a three-year vesting schedule for restricted stock awards enhances the retention value of these awards and positions the Company competitively from a market perspective.
A portion of the restricted stock awards vest if the executive officers remain Company employees for the entire vesting period (known as “non-performance shares”). These time-vested stock awards are forfeited if the officer does not remain continuously employed for the vesting period (typically three years). The remaining portion of the restricted stock awards vest based on the market price performance of the Common Stock (known as “performance shares”). See “Stock Vested in 2024” table below for shares that vested or were forfeited during 2024. Meridian reviewed the total direct compensation packages of our executives, including our stock-based award program and recommended that the Compensation Committee continue the use of restricted stock awards as the equity component of the compensation of our NEOs. The Compensation Committee relied upon market data, Company performance, and individual performance to determine the stock-based awards for our executive officers. For 2024, the Compensation Committee recommended and the Board approved the grant of the following restricted stock awards on December 16, 2024. It is the goal of the Compensation Committee to grant restricted stock awards for any given year in December of the preceding year. For additional information regarding the stock-based awards granted to our executive officers under the Restricted Stock Plan and Long-Term Incentive Plan, see the table entitled “Outstanding Restricted Stock Awards.”
Officer
Grant Date
Vest Date
Non-Performance Shares
Performance Shares
Chad L. Stephens
Dec. 16, 2024
Dec. 16, 2027
-
216,285
Ralph D’Amico
Dec. 16, 2024
Dec. 16, 2027
22,322
66,966
Vesting of the performance shares of restricted stock awards granted as part of 2024 executive compensation is based on the market price performance of the Common Stock or total stockholder return “(TSR”) at the completion of the time-vesting period. The vesting of the performance shares will be 50% dependent on TSR as compared to a peer group and 50% dependent on the compounded annual growth rate (“CAGR”) of the stock price, as set forth in each restricted stock agreement.
If the Company’s stock TSR as compared to the peer group is between the prescribed threshold and maximum percentages, the restricted stock will partially vest on a pro rata basis.
Level
Percentile Rank as to Company TSR Versus Relative TSR
Percentage of Shares Vesting
Maximum
Above 75th Percentile
187.5%
Target
50th Percentile
100%
Threshold
25th Percentile
50%
Below Threshold
Below the 25th Percentile
0%
The performance shares granted on December 16, 2024 vest based on how the Company’s TSR ranks against the following peer group.
Amplify Energy Corp.
PrimeEnergy Resources Corporation
Black Stone Minerals, L.P.
Riley Exploration Permian, Inc.
Dorchester Minerals, L.P.
Ring Energy, Inc.
Epsilon Energy Ltd.
SandRidge Energy, Inc.
Evolution Petroleum Corporation
Sitio Royalties Corp.
Granite Ridge Resources, Inc.
VAALCO Energy, Inc.
Kimbell Royalty Partners, LP
Vitesse Energy, Inc.
Mach Natural Resources LP
If the Company’s CAGR of its stock price is between the prescribed threshold and maximum percentages, the restricted stock will partially vest on a pro rata basis.
Level
Three-Year CAGR
Percentage of Shares Vesting
Maximum
20% or Higher
187.5%
Target
10%
100%
Threshold
5%
50%
Below Threshold
Below 5%
0%
Clawback Policy
The Company has adopted a clawback policy to ensure that incentive compensation is paid based on accurate financial and operating data and the correct calculation of the Company’s performance against incentive targets. If there is a restatement of the financial and/or operating results of the Company due in whole or in part to the material noncompliance with any financial reporting requirement under applicable securities laws (which would exclude, for example, a restatement caused by a change in applicable accounting rules or interpretations), regardless of whether an officer’s misconduct was the cause for such restatement, and such restatement resulted in or contributed to any incentive compensation (as defined below) being granted, earned or vested to or by an officer that the officer would not otherwise have been granted, earned or vested if the correct financial and/or operating data had been used (“excess incentive compensation”), the Board shall require reimbursement or forfeiture of any such excess incentive compensation deemed to have been received by the officer during the three completed fiscal years immediately preceding the date on which the Company is required to prepare the accounting restatement. “Incentive compensation” means any (A) annual bonus or other short and long-term cash incentive that is earned and (B) equity award that is vested, in each case, based (in whole or in part) on the attainment of one or more “financial reporting measures.” For these purposes, “financial reporting measures” are any measures used in preparing the Company’s financial statements or terms of compensation awards (or results that are derived from such measures), including, without limitation, (i) revenue, (ii) net income, (iii) earnings before interest, tax, depreciation and amortization, (iv) return on equity, (v) cash flows, (vi) stock price, and (vii) measures of stockholder return, in each case, whether absolute or relative.
Other Compensation and Benefits
Qualified Defined Contribution Plan
The Company has a 401(k) Plan that allows for a Company match. The 401(k) Plan is a tax-qualified, defined contribution plan and serves as the Company’s only employee retirement plan. Contributions are made at the discretion of the Board and, to date, all contributions have been made in cash. A matching contribution up to 5% of an employee’s salary is made every pay period up to certain regulatory limits.
Participation in Employee Benefit Plans
We offer health and welfare benefits to all eligible employees. Our executive officers and management are eligible to participate on the same basis as other employees in all such benefit plans, which include medical, dental, vision, group life, long-term disability and accidental death and dismemberment insurance.
Perquisites
The Company provides no other perquisites or personal benefits to its executive officers.
Change in Control Executive Severance Agreements
Messrs. Stephens and D’Amico are each a party to a Change-in-Control Executive Severance Agreement (collectively, the “Change-in-Control Agreements”). The Board believes that, in the event of a change-in-control of the Company, the executives’ performance may become hampered by distraction, uncertainty or other activities, which might adversely affect stockholder value. To reduce these potential adverse effects and to encourage fair treatment of its executive officers in connection with any change-in-control event, the Company enters into Change-In-Control Agreements with its executive officers to provide for change-in-control protection. For additional information, see “Potential Payments Upon Termination or Change in Control” below.
Other than the Change in Control Agreements, the Company maintains no employment agreements with its executive officers.
Indemnification Agreements
The Company has entered into an indemnification agreement with each of its directors and executive officers. These agreements provide that the Company will indemnify such persons against certain liabilities that may arise by reason of their status or service as directors or officers, to advance their expenses incurred as a result of a proceeding as to which they may be indemnified and to cover such persons under any directors’ and officers’ liability insurance policy the Company chooses, in its discretion, to maintain. These indemnification agreements are intended to provide indemnification rights to the fullest extent permitted under Delaware law and are in addition to any other rights the indemnitee may have under the Company’s Certificate of Incorporation and Bylaws and under applicable law. We believe these indemnification agreements enhance the Company’s ability to attract and retain knowledgeable and experienced officers and directors.
Other Compensation Matters
In December 2019, the Compensation Committee adopted stock ownership requirements for management. The Company’s Code of Ethics and Business Practices provides that directors, officers and employees should not engage in speculative transactions involving the Company’s securities, such as exchange-traded options, short-sales or derivative instruments.
Section 162(m) of the Internal Revenue Code generally limits the deductibility of compensation in excess of $1,000,000 annually paid to any of our executive officers. The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017, made significant revisions to Section 162(m), including repeal of the performance-based exception, revising the definition of covered employees to include any individual who served as the chief executive officer or chief financial officer at any time during the taxable year, and providing that once an individual is considered a covered employee, he or she will be considered a covered employee for all future years, including following any termination of employment. As a result, compensation paid to covered employees in excess of $1,000,000 generally will not be deductible, regardless of whether it is salary or performance-based.
Report of the Compensation Committee
The Compensation Committee has reviewed and discussed with management the preceding Compensation Discussion and Analysis for the year ended December 31, 2024. Based on such review and discussions, the Compensation Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
Respectfully submitted,
Compensation Committee
Glen A. Brown, Chair
Mark T. Behrman
John H. Pinkerton
Executive Compensation
The table below sets forth information for the two most recently completed fiscal years concerning compensation paid to our named executive officers in those fiscal years for services in all capacities.
Summary Compensation Table
Name and Principal
Position
Fiscal
Year
Base
Salary
Cash
Bonus (1)
Stock
Awards (2)
All Other
Compensation (3)
Total
Chad L. Stephens, President
$412,000
$267,800
$1,111,098
$129,294(4)
$1,920,192
and Chief Executive Officer
$400,000
$212,525
$2,159,843
$44,137 (4)
$2,816,505
Ralph D’Amico, Executive Vice
$309,000
$160,680
$432,634
$58,173(5)
$960,487
President and Chief Financial Officer
$300,000
$126,994
$827,003
$23,138 (5)
$1,277,135
(1) See “Determination of Annual Cash Bonus Awards” in the CD&A section of this Form 10-K for a description of how cash bonuses are determined.
(2) In accordance with applicable accounting standards, these amounts represent the aggregate grant date fair value of the stock awards. The ultimate value realized by the executive officers on vesting of the awards may or may not equal the fair market value at the award date based on failure to achieve the specified vesting requirements. Under certain circumstances, the awards may wholly, partially or never vest. See footnotes to table entitled “Outstanding Restricted Stock Awards.” Performance restricted stock is valued assuming a target number of shares would be issued. Assuming that the highest level of performance conditions will be achieved would result in a performance award grant equal to 187.5%
of the target award, and therefore the grant date fair value of stock awards for 2024 and 2023, respectively, would have been as follows: Mr. Stephens $2,082,419 and $4,049,706; and Mr. D’Amico $733,375 and $1,550,630.
(3) Includes immaterial amounts for group life insurance premiums for 2024 and 2023.
(4) Includes dividends received from restricted stock awards of $106,484 and $21,927 for 2024 and 2023, respectively, and $20,600 and $20,000, in 401(k) matching contribution by the Company in 2024 and 2023, respectively.
(5) Includes dividends received from restricted stock awards of $42,273 and $7,688 for 2024 and 2023, respectively, and $15,450 and $15,000 in 401(k) matching contributions by the Company in 2024 and 2023, respectively.
Grants of Plan-Based Awards Table
The table below shows the plan-based awards granted by the Compensation Committee to the Company’s named executive officers in 2024:
Equity Incentive Plan Awards
Performance Shares
Name
Grant Date
Vest Date
Threshold(1)
Target(1)
Maximum(1)
Non- Performance Shares
Grant Date Fair Value of Stock Awards
Chad L. Stephens
12/16/2024
12/16/2027
108,143
216,285
405,534
-
$1,111,098
Ralph D’Amico
12/16/2024
12/16/2027
33,483
66,966
125,561
22,322
$432,634
(1) See “Long-Term Equity-Based Restricted Stock Compensation” in the CD&A section of this Form 10-K for a description of the vesting of performance shares.
Outstanding Equity Awards
The following table provides information on the holdings of restricted stock by the Company’s named executive officers at December 31, 2024:
Outstanding Restricted Stock Awards
Number of Shares of Restricted Stock That Have Not Vested
Company Common Stock Price at Dec. 31, 2024
Market Value of
Shares of
Restricted Stock That
Have Not Vested
Name
Grant Date
Performance
Non-Performance
Chad L. Stephens
January 31, 2023
201,613
-
$4.00
$806,452
December 21, 2023
247,002
-
$4.00
$988,088
December 16, 2024
216,285
-
$4.00
$865,140
Ralph D’Amico
January 31, 2023
62,044
20,681
$4.00
$330,900
December 21, 2023
76,416
25,472
$4.00
$407,522
December 16, 2024
66,966
22,322
$4.00
$357,152
Stock Vested in 2024
The following table summarizes, for the NEOs, the restricted stock awards that vested during 2024.
Officer
Grant Date
Vest Date
Non-Performance Shares Vested
Performance Shares Vested
Performance Shares Forfeited
Value Realized on Vesting
Chad L. Stephens
Mar. 2, 2024
Dec. 20, 2024
-
357,928(1)
-
$1,356,547
Ralph D’Amico
Mar. 2, 2024
Dec. 20, 2024
29,914
112,179(1)
-
$538,532
(1) 125% of the restricted stock awards vested based on market price performance.
Potential Payments Upon Termination or Change in Control
The following table and narratives disclose certain information with respect to compensation that would be payable to the Company’s NEOs upon termination or change in control as of December 31, 2024.
In 2024, Messrs. Stephens and D’Amico were each a party to a Change-in-Control Agreement. Under such Change-in-Control Agreements for Mr. Stephens and Mr. D’Amico, if, within two years following a change-in-control event, the Company terminates his employment without cause or he resigns for good reason as defined in the Change-in-Control Agreement, such executive would be entitled to a severance payment, payable in a lump sum, in cash, following his termination, in an amount equal to two times the average of the compensation paid to the executive during the two calendar years preceding the change-in-control event (or the annual average of any shorter period). Compensation for this purpose includes the sum of the executive’s base salary, cash bonuses and the Company’s contribution to the 401(k) Plan (restricted stock awards are excluded). Further, if the executive qualifies, and the Company is required to provide coverage under COBRA, the Company shall reimburse the executive the costs of purchasing continuing coverage under COBRA for the executive and his dependents as long as he qualifies for COBRA coverage. In fiscal 2021, the Change-of-Control Agreements were amended to reduce the Company’s reimbursement of COBRA coverage costs to a maximum of twelve months, and in 2023 the Change-in-Control Agreements were amended to be consistent with Delaware law (as a result of the Company’s reincorporation from Oklahoma to Delaware) and to make other immaterial modifications. The Company became subject to COBRA on January 1, 2014.
A change-in-control event generally means: (i) the acquisition of beneficial ownership of more than 50% of the Company’s Common Stock; (ii) during any period of twelve consecutive months, individuals who at the beginning of such period constitute the Board, and any new director, whose election by the Board or nomination for election by the Company’s stockholders was approved by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute a majority of the Board; (iii) approval by the Company’s stockholders, and consummation, of a merger or consolidation, other than a merger or consolidation which results in the Common Stock of the Company outstanding immediately prior thereto continuing to represent at least 70% of the total voting power of the Company (or the surviving entity, if not the Company) after such merger or consolidation; or (iv) any person or entity acquires (or has acquired during the twelve-month period ending on the date of the most recent acquisition) assets from the Company that have a total gross fair market value equal to or more than 50% of the total gross fair market value of all of the assets of the Company immediately before such acquisition(s).
Situations may arise where the potential to merge with or be acquired by another company may be in the best interest of our stockholders. Based on this potential, the Company believes that the “double trigger” requiring both (i) a change-in-control event and (ii) the termination of an executive’s employment without cause or his or her resignation for good reason after the event is appropriate to provide fair treatment of the executive officers, while allowing them to continue to concentrate on enhancing stockholder value during a change-in-control event, as they may take actions which ultimately may lead to termination of their employment after the change-in-control event.
Pursuant to the Change-in-Control Agreements, assuming that a change-in-control event took place on the last business day of 2024, and an executive’s employment was terminated without cause, or the executive terminated his or her employment for good reason, within two years following this assumed change-in-control event, the executives named below would receive the following severance payments:
Name
Salary
Bonus
401(k)
Total
Chad L. Stephens
$812,000
$480,325
$40,600
$1,332,925
Ralph D’Amico
$609,000
$287,674
$30,450
$927,124
Compensation of Directors
The compensation of our non-employee directors is reviewed by the Compensation Committee and is approved by the Board. We use a combination of cash and equity-based incentive compensation to attract and retain qualified candidates to serve on our
Board. We consider the responsibilities of our non-employee directors and the amount of time such directors spend fulfilling their responsibilities and duties as a director in determining Board and Board committee compensation.
The following summary includes information regarding the compensation earned by our non-employee directors during 2024 for service on our Board and Board committees.
Cash Annual Retainers
For 2024, each of our non-employee directors received an annual retainer of $60,000. We also reimburse our non-employee directors for out-of-pocket travel expenses incurred in connection with attending Board and committee meetings. The Non-Executive Chairman of the Board received an additional annual retainer of $25,000 for 2024, and the chairs of the Audit Committee, the Compensation Committee, and the Governance and Sustainability Committee received additional annual retainers of $13,000, $10,500, and $9,000, respectively. The annual retainers were paid in equal installments on March 31, June 30, September 30 and December 31 of 2024.
The Company’s retainer and fee structure for non-employee directors was guided by a study conducted by Meridian.
Equity Incentive Plans for Non-Employee Directors
The Company’s Deferred Compensation Plan for Non-Employee Directors (the “Directors’ Deferred Compensation Plan”) and the PHX Minerals Inc. 2021 Long-Term Incentive Plan (the “LTIP”) serve as the equity incentive plans for the Company’s non-employee directors.
Deferred Compensation Plan for Non-Employee Directors
Annually, non-employee directors may elect to be included in the Directors’ Deferred Compensation Plan. The Directors’ Deferred Compensation Plan provides that each non-employee director may individually elect to be credited with future unissued shares of Common Stock rather than cash for all or a portion of the director’s annual retainers, and may elect to receive shares, if and when issued, over annual time periods up to ten years. These unissued shares of Common Stock are recorded to each director’s deferred compensation account at the closing market price of the shares on the payment dates of the annual retainers. Dividends are credited to each deferred account on the record date of each declared dividend. Upon a director’s retirement, resignation, termination, death or a change-in-control of the Company, the unissued shares of Common Stock recorded for such director under the Directors’ Deferred Compensation Plan will be issued to the director. In the case of a change-in-control of the Company, all shares in the deferred accounts will be issued in a single lump sum to the appropriate directors at the closing of the event triggering such change-in-control. The promise to issue such shares in the future is an unsecured obligation of the Company.
Long-Term Incentive Plan
The Company’s independent directors are eligible to participate in the Company’s LTIP.
On December 16, 2024, the Compensation Committee recommended and the Board approved the granting of restricted stock awards to each director in an amount determined by dividing $65,000 by the Company’s average daily closing share price during the last five trading days ended December 13, 2024.
The shares issued on December 16, 2024 will vest in December 2025 or, if elected by the director, will vest upon retirement or annually in equal installments up to five years after the director’s retirement. For additional information regarding the grants of restricted stock to our non-employee directors, please see the “Non-Employee Directors Compensation for 2024” table below.
Director Compensation for 2024
The table below sets forth the total non-employee director compensation earned during 2024 for each person who served in such capacity at any time during 2024. The 2024 compensation of Chad L. Stephens, who served as a director and Chief Executive Officer, is disclosed under the caption “Executive Compensation - Summary Compensation Table” of this Form 10-K.
Non-Employee Directors Compensation for 2024
Name
Fees Paid in Cash or Deferred(1)(2)
All Other Compensation(3)(4)(5)
Total
Mark T. Behrman
$85,000
$87,289
$172,289
Glen A. Brown
$70,500
$75,400
$145,900
Lee M. Canaan
$73,000
$66,723
$139,723
Steven L. Packebush
$60,000
$73,514
$133,514
John H. Pinkerton
$69,000
$70,571
$139,571
1.The following non-employee directors deferred 100% of their retainers under the Directors’ Deferred Compensation Plan: Mark T. Behrman and Steven L. Packebush. John H. Pinkerton, Glen A. Brown, and Lee M. Canaan did not elect to participate in the Directors’ Deferred Compensation Plan and received cash payments for their retainers.
2.At the end of 2024, the following future share amounts had been recorded to each non-employee director’s account under the Directors’ Deferred Compensation Plan: Behrman- 151,500 shares; Brown- 51,326 shares; Canaan- 7,782 shares; Packebush- 47,405 shares; and Pinkerton- 15,982 shares.
3.Includes dividends accrued under the Directors’ Deferred Compensation Plan. Under the Director’s Deferred Compensation Plan, dividends paid on the Common Stock are recorded to each non-employee director’s account on the record date of the dividend in the form of unissued shares of Common Stock. The amount recorded is based on the number of future unissued shares in each non-employee director’s account and the closing market price of the Common Stock on each dividend payment date. These future share amounts have no voting authority and the non-employee directors have no investment authority with respect thereto.
4.Includes restricted stock awards granted in December 2024 for each non-employee director, which were valued in accordance with applicable accounting standards, based on the grant date fair value of the awards.
5.Includes dividends from non-participating restricted stock that vested during the period.
Share Ownership Guidelines for Directors
The Bylaws of the Company require non-employee directors to own shares of Common Stock in order to be a Board member. To align the interests of the directors with the Company’s stockholders, the Board has adopted a “Company Share Ownership” policy in the Corporate Governance Guidelines. The policy indicates that each director is expected to own a number of shares at the end of his or her fifth year of Board service equal to, on a cost basis, the aggregate amount of his or her first three years’ annual retainers for the regularly scheduled Board meetings held each year, plus the number of shares of restricted stock granted to such director under the Company’s LTIP, which are granted and vest during such three-year period. Future unissued shares that have been credited to the directors’ accounts under the Directors’ Deferred Compensation Plan may be used to satisfy this share ownership requirement.
Policies and Practices Related to the Grant of Certain Equity Awards Close in Time to the Release of Material Nonpublic Information
We do not grant stock options and therefore do not have any formal policies or practices regarding the timing of awards of stock options in relation to the disclosure of material nonpublic information. If we anticipate granting stock options in the future, we may determine to establish a policy regarding how the Board and/or the Compensation Committee determines when to grant such awards and how the Board and/or the Compensation Committee will take material nonpublic information into account when determining the timing and terms of such awards.
Compensation Committee Interlocks and Insider Participation
The functions and members of the Compensation Committee are set forth under “ITEM 10. Directors, Executive Officers and Corporate Governance - Board Committees” above. All Compensation Committee members are independent under the enhanced independence standards of the NYSE for compensation committee members of NYSE-listed companies.
None of the members of our Compensation Committee is or has been an officer or employee of the Company. In addition, during 2024, none of our executive officers served as a member of the board or the compensation committee (or other board committee performing similar functions or, in the absence of any such committee, the entire board) of any entity in which a member of the Company’s Board or Compensation Committee is an executive officer.

---

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Stock Ownership of Management and Certain Beneficial Owners
The information provided below summarizes the beneficial ownership of each named executive officer (NEO), each of our directors, all of our directors and executive officers as a group, and owners of more than five percent of our outstanding Common Stock. Generally, “beneficial ownership” includes those shares of Common Stock held by someone who has investment and/or voting
authority of such shares or has the right to acquire such Common Stock within 60 days. The ownership includes Common Stock that is held directly and also Common Stock held indirectly through a relationship, a position as a trustee, or under a contract or understanding.
Stock Ownership of Directors and Executive Officers
The following table sets forth information with respect to the outstanding shares of Common Stock beneficially owned by each current director and named executive officer, individually and all directors and executive officers as a group. The percent of Common Stock beneficially owned by each person is based on 37,922,368 shares of Common Stock issued and outstanding at March 5, 2025. Unless otherwise indicated, the address of the persons below is 1320 South University Drive, Suite 720, Fort Worth, TX 76107. None of the Common Stock beneficially owned as set forth below is pledged as security.
Amount of Shares
Percent of
Name of Beneficial Owner
Beneficially Owned(3)(4)(5)
Common Stock
Mark T. Behrman (1)(6)
190,243
*
Glen A. Brown (1)(6)
118,213
*
Lee M. Canaan (1)(7)
130,718
*
Ralph D’Amico (2)(6)
576,274
1.5%
Steven L. Packebush (1)(6)
172,184
*
John H. Pinkerton (1)(6)
110,025
*
Chad L. Stephens (1)(2)(6)
1,317,928
3.5%
All directors and executive officers
as a group (7 persons)
2,615,585
6.9%
* Less than 1% owned
(1) Director
(2) Executive Officer
(3) The number of shares shown includes shares that are individually or jointly owned, as well as shares over which the individual has either sole or shared investment or voting authority.
(4) The number of shares shown does not include future share amounts recorded to each non-employee director’s account under the Directors’ Deferred Compensation Plan. These future share amounts represent shares to be issued in the future and have no investment or voting authority. See “Compensation of Directors” - footnote (2) of table entitled “Non-Employee Directors Compensation for 2024.”
(5) The number of shares shown includes unvested shares of restricted stock awarded under the Company’s Long-Term Incentive Plan, over which they exercise voting authority.
(6) Owner has sole voting and investment power over all shares.
(7) Comprised of 129,641 shares held directly by Ms. Canaan and 1,077 shares held by the Canaan Family Trust. Ms. Canaan has sole voting and investment power over 61,447 shares and shared voting and investment power over the 69,271 shares held by the Canaan Family Trust and a Joint Account with her husband.
The Company knows of no arrangements which would result in a change in control of the Company at any future date.
Stock Ownership of Certain Beneficial Owners
Based on filings with the SEC and information supplied to us by the stockholders, we believe the following stockholders are beneficial owners of more than 5% of our outstanding shares of Common Stock based on 37,922,368 shares of Common Stock issued and outstanding as of March 5, 2025, listed in alphabetical order:
Name and Address
Amount of Shares
Percent of
of Beneficial Owner
Beneficially Owned
Common Stock
Edenbrook Capital, LLC (1)
3,396,023
9.0%
116 Radio Circle, Suite 202
Mount Kisco, NY 10549
Robert A. Hefner III (2)
3,165,570
8.3%
6305 Waterford Boulevard, Suite 470
Oklahoma City, OK 73118
Punch & Associates Investment Management, Inc. (3)
2,745,884
7.2%
7701 France Ave. So., Suite 300
Edina, MN 55435
SRP Capital Advisors, LLC (4)
3,057,036
8.1%
3811 Turtle Creek Blvd., Suite 1100
Dallas, TX 75219
(1) Based solely on a Schedule 13D filed with the SEC on November 14, 2024, Edenbrook Capital, LLC, the investment adviser to certain private investment funds that hold shares of the Company’s Common Stock, has shared voting power and shared dispositive power as to 3,396,023 shares, shared with Jonathan Brolin, the managing member of Edenbrook Capital, LLC.
(2) Based solely on a Schedule 13G/A (Amendment No. 2) filed with the SEC on September 1, 2022, Robert A. Hefner III has sole voting power and sole dispositive power as to 3,165,570 shares.
(3) Based solely on a Schedule 13G filed with the SEC on February 14, 2024, Punch & Associates Investment Management, Inc. has sole voting power and sole dispositive power as to 2,745,884 shares.
(4) Based solely on a Schedule 13G/A (Amendment No. 3) filed with the SEC on February 14, 2025, SRP Capital Advisors, LLC has shared voting power and shared dispositive power as to 3,057,036 shares, (i) shared with SRPO-II Manager, LP, Palmetto Investment Partners II, LLC, PIPII-SRPOII Investments, LLC and Ryan A. Turner as to all such shares, (ii) shared with SRP Opportunities II, LP and SRP Opportunities II GP, LP as to 1,888,169 shares and (iii) shared with SRPO-II Partners I, LP and SRPO-II Partners I GP, LP as to 1,168,867 shares.
Equity Compensation Plan Information
The following table gives aggregate information regarding grants under all of the Company’s equity compensation plans through December 31, 2024.
Plan Category
Number of securities to be issued upon exercise of outstanding options, warrants and rights
Weighted-average exercise price of outstanding options, warrants and rights
Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by stockholders
-
N/A
2,001,233
Equity compensation plans not approved by stockholders
-
N/A
-
Total
-
N/A
2,001,233

---

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. Certain Relationships and Related Transactions, and Director Independence
Related-Person Transactions
We review all transactions and relationships in which the Company and any of our directors, nominees for director, executive officers or any of their immediate family members may be participants to determine whether any of these individuals have a direct or indirect material interest in any such transaction. We have developed and implemented processes and controls to obtain information from the directors and executive officers about related-person transactions, and for determining, based on the facts and circumstances, whether a related person has a direct or indirect material interest in any such transaction. Transactions that are determined to be directly or indirectly material to a related person are disclosed in our proxy statement and our annual report on Form 10-K as applicable and as required by SEC rules.
Pursuant to the Company’s processes, all directors and executive officers annually complete, sign and submit questionnaires that are designed to identify actual and potential conflicts of interest, related persons and any related-person transactions. Additionally, we make appropriate inquiries as to the nature and extent of business that the Company may conduct with other companies for whom any of our directors or executive officers also serve as directors or executive officers. Under the Company’s Code of Ethics and Business Practices, if an actual or potential conflict of interest affects an executive officer or a director, he or she is required to immediately disclose all the relevant facts and circumstances to the Company’s President or the Governance and Sustainability Committee, as appropriate. If the Governance and Sustainability Committee determines that there is a conflict, it will refer the matter to the Board, which will review the matter to make a final determination as to whether a conflict exists, and, if so, how the conflict should be resolved. In addition, the Audit Committee reviews all reports and disclosures of actual and potential related-person transactions.
None of the current non-employee directors has ever been an officer or employee of the Company. Mr. Stephens serves as the Chief Executive Officer of the Company and is not considered independent. He is the only director who is also an officer or employee of the Company. Mr. Stephens does not currently serve on any Board committee.
None of the organizations where the Company’s directors and officers hold positions are parents, subsidiaries or affiliates of the Company, or conduct business with the Company. Since the beginning of 2024, we are not aware of any related-party transactions that require disclosure.
Board Independence
Our Board annually determines the independence of each director and nominee for election as a director based on a review of the information provided by the directors and nominees. The Board makes these determinations under the independence standards set forth in the NYSE Listed Company Manual, applicable SEC rules and our Corporate Governance Guidelines. A copy of our Corporate Governance Guidelines can be viewed on our website: www.phxmin.com under the “Governance Library” section of the “Corporate Governance” tab.
As a result of its annual evaluation, the Board affirmatively determined by resolution that each of the Company’s current non-employee directors is independent under the listing standards of the NYSE, the requirements of the SEC and our Corporate Governance Guidelines. The Board has determined that each of the following non-employee directors is independent and has no material relationship with the Company that could impair such director’s independence: Mark T. Behrman, Glen A. Brown, Lee M. Canaan, Steven L. Packebush, and John H. Pinkerton.
Chad L. Stephens is not independent based on his service as the Company’s President and Chief Executive Officer. Mr. Stephens is the only director who is an officer or employee of the Company, and he does not currently serve on any Board committee.

---

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. Principal Accountant Fees and Services
Independent Accountants’ Fees and Services
The following sets forth fees billed for audit and other services provided by Ernst & Young for the fiscal years ended December 31, 2024 and 2023:
Fee Category
Fiscal 2024 Fees
Fiscal 2023 Fees
Audit Fees (1)
$410,000
$405,000
Audit-Related Fees
$-
$-
Tax Fees
$-
$-
All Other Fees
$-
$-
(1)Includes fees for audit of financial statements, review of the related quarterly financial statements for those fiscal years, and services related to other SEC filings.
Audit Committee Pre-Approval Policies and Procedures
The Audit Committee’s pre-approval policy provides that the Audit Committee shall pre-approve all audit and non-audit services provided by the Company’s independent auditors and the fees to be paid for those services and shall not engage the independent auditors to perform any non-audit services prohibited by law or regulation. The Audit Committee delegates specific pre-approval authority with respect to audit and permitted non-audit services to the Chair of the Audit Committee, but only where pre-approval is required to be acted upon prior to the next Audit Committee meeting and where the aggregate audit and permitted non-audit services fees pre-approved under this policy since the last Audit Committee meeting are not more than $150,000. All services rendered by Ernst & Young were permissible under applicable laws and regulations and were pre-approved by the Audit Committee.
PART IV

---

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES
FINANCIAL STATEMENT SCHEDULES
The Company has omitted all schedules because the conditions requiring their filing do not exist or because the required information appears in the Company’s Financial Statements, including the notes to those statements.
EXHIBITS
(2.1)
Agreement and Plan of Merger, dated as of March 31, 2022, by and between PHX Minerals Inc., an Oklahoma corporation, and PHX Minerals (DE) Inc., a Delaware corporation (incorporated by reference to Exhibit 2.1 to Form 8-K12B filed April 5, 2022).
(3.1)
Certificate of Incorporation of PHX Minerals Inc., as amended (incorporated by reference to Exhibit 3.1 to Form 8-K12B filed April 5, 2022).
(3.2)
Certificate of Amendment to Certificate of Incorporation of PHX Minerals Inc., as amended (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 20, 2024).
(3.3)
Second Amended and Restated Bylaws of PHX Minerals Inc. (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed July 19, 2024).
(4.1)
Description of Capital Stock of PHX Minerals Inc. (incorporated by reference to Exhibit 99.1 to Form 8-K12B filed April 5, 2022).
(4.2)
Form of Senior Indenture (incorporated by reference to Exhibit 4.3 to Form S-3 filed March 12, 2024).
(4.3)
Form of Subordinated Indenture (incorporated by reference to Exhibit 4.5 to Form S-3 filed March 12, 2024).
*(10.1)
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to Form 8-K filed January 5, 2023).
*(10.2)
Amended and Restated Change-in-Control Executive Severance Agreement between PHX Minerals Inc. and Chad L. Stephens (incorporated by reference to Exhibit 10.2 to Form 10-K filed March 12, 2024).
*(10.3)
Amended and Restated Change-in-Control Executive Severance Agreement between PHX Minerals Inc. and Ralph D’Amico (incorporated by reference to Exhibit 10.3 to Form 10-K filed March 12, 2024).
*(10.4)
Form of Change-in-Control Executive Severance Agreement for Executive Officers other than Named Executive Officers (incorporated by reference to Exhibit 10.4 to Form 10-K filed March 12, 2024).
*(10.5)
PHX Minerals Inc. Amended 2010 Restricted Stock Plan (incorporated by reference to Exhibit 10.18 to Form 10-K filed December 10, 2020)
*(10.6)
PHX Minerals Inc. Amended and Restated 2021 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed March 8, 2023).
*(10.7)
Form of Restricted Stock Award Agreement with Performance and Non-Performance Shares.
*(10.8)
Form of Restricted Stock Award Agreement with Performance Shares Only.
*(10.9)
Form of Director Restricted Stock Award Agreement.
(10.10)
Credit Agreement dated as of September 1, 2021, among PHX Minerals Inc., each lender from time to time party thereto, and Independent Bank, as Administrative Agent and L/C Issuer (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 3, 2021)
(10.11)
First Amendment to Credit Agreement dated as of December 6, 2021, by and among PHX Minerals Inc., each lender party thereto, and Independent Bank, as Administrative Agent and L/C Issuer (incorporated by reference to Exhibit 10.3 to Form 8-K filed December 9, 2021).
(10.12)
Second Amendment to Credit Agreement dated as of May 18, 2022, by and among PHX Minerals Inc., each lender party thereto, and Independent Bank, as Administrative Agent and L/C Issuer (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 19, 2022).
(10.13)
Third Amendment to Credit Agreement dated as of December 7, 2022, by and among PHX Minerals Inc., each lender party thereto, and Independent Bank, as Administrative Agent and L/C Issuer (incorporated by reference to Exhibit 10.8 to Form 10-K filed December 13, 2022).
(10.14)
Fourth Amendment to Credit Agreement dated as of May 5, 2023, by and among PHX Minerals Inc., each lender party thereto, and Independent Bank, as Administrative Agent and L/C Issuer (incorporated by reference to Exhibit 10.4 to Form 10-Q filed May 9, 2023).
(10.15)
Fifth Amendment to Credit Agreement dated as of November 6, 2023, by and among PHX Minerals Inc., each lender party thereto, and Independent Bank, as Administrative Agent and L/C Issuer (incorporated by reference to Exhibit 10.1 to Form 10-Q filed November 8, 2023).
(10.16)
Sixth Amendment to Credit Agreement dated as of April 18, 2024, by and among PHX Minerals Inc., each lender party thereto, and Independent Bank, as Administrative Agent and L/C Issuer (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 18, 2024).
(19.1)
Insider Trading Policy
(23.1)
Consent of Ernst & Young LLP
(23.2)
Consent of Cawley, Gillespie and Associates, Inc., Independent Petroleum Engineering Consultants
(24.1)
Power of Attorney (see signature page)
(31.1)
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(31.2)
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(32.1)
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(32.2)
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(97.1)
PHX Minerals Inc. Clawback Policy (incorporated by reference to Exhibit 97.1 to Form 10-K filed March 12, 2024).
(97.2)
Form of PHX Minerals Inc. Executive Acknowledgement & Agreement Pertaining to Clawback Policy (incorporated by reference to Exhibit 97.2 to Form 10-K filed March 12, 2024).
(99.1)
Report of Cawley, Gillespie and Associates, Inc., Independent Petroleum Engineering Consultants, dated January 13, 2025
(101.INS)
Inline XBRL Instance Document
(101.SCH)
Inline XBRL Taxonomy Extension Schema Document
(101.CAL)
Inline XBRL Taxonomy Extension Calculation Linkbase Document
(101.LAB)
Inline XBRL Taxonomy Extension Labels Linkbase Document
(101.PRE)
Inline XBRL Taxonomy Extension Presentation Linkbase Document
(101.DEF)
Inline XBRL Taxonomy Extension Definition Linkbase Document
(104)
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*
Indicates management contract or compensatory plan or arrangement