January 29, 2026

Mr. Brent Clum

Chief Financial Officer

MorningStar Partners LP

400 West Seventh Street

Fort Worth, TX 76102

Re: Reserve Evaluation – SEC Pricing

TXO Partners, L.P. Interests

Total Proved Reserves

As of December 31, 2025

Pursuant to the Guidelines of

the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue

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Dear Mr. Clum:

As requested, this report was prepared January 29, 2026 for TXO Partners, L.P. (“TXO”) for the purpose of public disclosure by TXO in filings made with the Securities and Exchange Commission (“SEC”) in accordance with the disclosure requirements set forth in the SEC regulations. We evaluated 100% of TXO reserves, which are made up of oil and gas properties in various states. This report utilized an effective date of December 31, 2025, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the SEC. The results of this evaluation are presented in the accompanying tabulation, with a composite summary of the values presented below:

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future Net Cash Flow (Net Operating Income – BFIT) is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten (10) percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties by Cawley, Gillespie & Associates, Inc. (“CG&A”).

The oil reserves include oil and condensate. Oil and natural gas liquid (“NGL”) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base. Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated.

Hydrocarbon Pricing

The base SEC oil and gas prices calculated for December 31, 2025 were $65.34/bbl and $3.387/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2025 and the base gas price is based upon Henry Hub spot prices (Platts Gas Daily) during 2025. Furthermore, NGL prices were adjusted on a per-property basis and averaged 22.8% of the net oil price on a composite basis.

The base prices shown above were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $62.022 per barrel for oil, $2.108 per MCF for gas and $15.775 per barrel for NGLs. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, future production costs (lease operating expenses) and future development costs (capital investments) were forecast by TXO by field or by property using the latest historical data available. However, all commercial parameters appear to be reasonable and appropriate based on our review and were held constant (not escalated) throughout the life of the properties in accordance with SEC guidelines.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. Government policies and market conditions different from those employed in this report may cause (1) the total quantity of oil or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

CG&A evaluated 39 PDNP opportunities and 57 PUD locations, targeting various reservoirs in Montana, New Mexico and Texas. Non-producing and undeveloped reserves were assigned based on regional type curves and analogy to recent, modern completions. Furthermore, the development schedule and capital costs for drilling and completion were provided by TXO and accepted as provided. However, our review showed the development plan and related capital to be reasonable and appropriate for this evaluation. Each of these PUD drilling locations proposed as part of TXO’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, TXO has indicated they have every intent to complete this development plan in the next five (5) years. Furthermore, TXO has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five-year development plan will be fully executed.

Reserve Estimation Methods

CG&A evaluated 8,062 producing wells (some of which include multi-well leases or units) for this report, with production typically updated through October 2025 with monthly and/ or daily production data sourced from TXO, state repositories or subscription services. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends mainly on the amount of the reliable geologic and engineering data available at the time of the estimate and the interpretation of such data, as well as the inherent uncertainties attributable to variations in reservoir and rock quality, offset drainage, mechanical wellbore integrity among others. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. This report addresses only the proved reserves attributable to the properties evaluated herein.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

General Discussion

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by CG&A. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included as directed.