Exhibit 99.2

Cawley, Gillespie & Associates, Inc.

PETROLEUM CONSULTANTS

April 1, 2025

Mr. Chris Hammack, Co-CEO
Mr. William Ulrich, Co-CEO
Presidio Holding Company, LLC
500 West 7^th Street, Suite 803
Fort Worth, TX 76102

Ladies & Gentlemen:

As requested by Presidio Holding Company, LLC (“Company”), this report was prepared for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the Presidio Investment Holdings, LLC (“Pres-Inv”) ownership interests. We evaluated 100% of the Company reserves in the interest group noted above, which are made up of oil and gas properties located in Kansas, Oklahoma and Texas. This evaluation, effective December 31, 2024, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). This report has been prepared for use in filings with the SEC. In our opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

A composite summary of the total proved reserves are presented below:

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Future revenue was calculated prior to deducting state production taxes and ad valorem taxes; however, future net cash flow was calculated after deducting these taxes, future development costs, and future production costs, but before federal income taxes. Future net cash flow has been discounted at an annual rate of ten (10) percent, in accordance with SEC guidelines, to determine net present worth. Present worth indicates the time value of money and should not be construed as being fair market value.

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. Barrels of oil equivalent (“BOE”) is expressed as oil and NGL volumes in barrels plus gas volumes in Mcf divided by six (6) to convert to barrels. Our estimates include proved reserves only. Neither probable or possible reserves, nor interest in acreage beyond the location of proven reserves have been estimated.

Proved Developed reserves are the summation of the Proved Developed Producing and Proved Developed Non-Producing reserve estimates. Proved Developed reserves were estimated at 14,143.7 Mbbl oil, 301,317.6 MMcf gas and 27,111.5 Mbbl NGLs (or 91,474.8 MBOE). Of the Proved Developed reserves, 89,599.4 MBOE were attributed to producing zones in existing wells and 1,875.5 MBOE were attributed to zones in existing wells not producing.

Presentation

The report is divided into six (6) reserve category sections: Total Proved (“TP”), Proved Developed (“PD”), Proved Developed Producing (“PDP”), Proved Developed Non-Producing (“PDNP”), Proved Developed Shut-In (“PDSI”), and Proved Undeveloped (“PUD”).

Hydrocarbon Pricing

The base SEC oil and gas prices calculated for year end 2024 were $75.48/bbl and $2.130/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 market prices during 2024, and the base gas price is based upon Henry Hub spot market prices during 2024.

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Adjustments to oil and gas prices were provided by the Company based on the historical average and audited by us at a summary level. The differential calculations appear to be reasonable and appropriate for this evaluation and were accepted as furnished. Adjustments may include basis differentials, treating costs, transportation charges and/or crude quality and gravity corrections. Gas shrinkage factors were applied to each property against gross gas volumes to account for line losses and plant processing. NGL prices were applied to certain properties as provided at a percentage of WTI Cushing crude oil price. As provided by the Company, the liquids yield (NGL/Gas), residue gas BTU (heating value), and gas shrinkage were modeled using well-level historical averages and based on election type.

After these adjustments, the net realized prices over the life of the proved properties was estimated to be $73.86 per BBL for oil, $1.975 per MCF for gas and $22.64 per BBL for NGLs. All economic factors were held constant in accordance with SEC guidelines.

Expenses, Investments and Taxes

Lease operating expenses (Future Production Costs) and investments (Future Development Costs) were provided by the Company based on historical expenses and current contracts. These inputs were applied at the well level and audited by us at a detailed level. Our audit determined that the commercial parameters being applied were reasonable and appropriate, and in-line with historical averages. Therefore, no changes were made to cost parameters. Workover costs were included to account for the recurring workover costs required on rod pump wells. Gas and/or liquids gathering, and transportation are included as variable expenses. 3rd Party COPAS was included and represents overhead expenses incurred on certain non-operated properties. Compression costs were applied as provided by the Company, which includes a cost reduction in June 2025 based on the downsizing of compressors used for operated wells. Abandonment costs for all proved developed properties were scheduled independently for operated and non-operated properties. All expenses applied herein have been reviewed by CGA for accuracy and completeness and were applied as provided by the Company. Costs were not escalated in this report, in accordance with SEC guidelines.

Severance tax values were determined by applying normal state severance tax rates, with certain new wells receiving high-cost gas well tax incentives. Ad valorem tax rates were calculated by state, with effective ad valorem tax rates of 1.41%, 0.30%, and 2.91% of total revenues for Kansas, Oklahoma, and Texas, respectively. All severance and ad valorem taxes were applied as provided by the Company.

Certain PDP wells with expected non-recurring workovers planned have future development costs scheduled in 2025, as provided by the Company. For undeveloped properties, future production costs were scheduled based on the average lease operating expenses of producing properties, as provided by the Company. High-cost gas well tax reductions were applied to undeveloped properties based on state guidelines. Future development cost information was provided by the Company based upon their recent drilling and completion (“D&C”) estimates. The D&C costs were applied based on lateral length and reservoir for all locations. Based on farmout agreements with partnering operators, the Company did not realize D&C costs associated with some undeveloped wells. The drill schedule applied herein was provided by the Company and appears to be reasonable and appropriate for this evaluation.

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Reserves Estimation Methods

We evaluated 3,762 PDP properties for this report, which included two (2) separate cases representing abandonment costs for operated and non-operated properties. For most operated properties, daily and monthly production data was provided by the Company through 12/31/2024. For most non-operated properties, monthly data was provided by the Company through 12/31/2024. Reserves for PDP 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, type curves and analogy to similar production, all of which are considered to provide a relatively high degree of accuracy.

We evaluated 72 PDNP properties for this report, 57 of which are commercial. PDNP properties include tubing repairs, pump replacements, and other capitalized workover projects proposed on existing, non-producing wellbores. Future development costs and timing for these projects were applied as provided by the Company. 1,703 PDSI properties were included in this report and modeled at zero value. Abandonment costs for PDNP and PDSI properties have been included as described previously.

Undeveloped reserve estimates were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting undeveloped reserves for the Company’s properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. Regional type curves were developed based on area, reservoir, and geologic conditions with preference given to modern completions. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages 6-8 of this report letter. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This report includes four (4) commercial PUD locations in Lipscomb County, Texas targeting the Cleveland reservoir. All PUD drills were assumed to be horizontal wells offsetting production from horizontal producers. The drill schedules were determined based on a non-operated rig rate provided by the Company. All PUDs are drilled and completed within five (5) years. Furthermore, the Company and their operating partners have demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five-year development plan can be fully executed.

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General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. Ownership information and economic factors such as liquid and gas prices, price differentials and expenses were furnished by the Company. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom, and the actual cost incurred could be more or less than the estimated amounts.

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 Cawley, Gillespie & Associates, Inc. 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 been included as provided.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. This evaluation was supervised by W. Todd Brooker, President at CG&A and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties, Presidio Investment Holdings, LLC or Presidio Holding Company, LLC and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstance to prepare the report to comply with the requirements in Item 1202(a)(8)(viii) of Regulation S-K. Our work papers and related data are available for inspection and review by authorized, interested parties. This report, issued April 1, 2025, supersedes any prior CGA report issued for Presidio Investment Holdings, LLC with an effective date of December 31, 2024, and utilizing SEC pricing.

	Yours very truly,
	/s/ W. Todd Brooker
	W. Todd Brooker, P.E.
	President
	CAWLEY, GILLESPIE & ASSOCIATES, INC.
	TEXAS REGISTERED ENGINEERING FIRM F-693

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Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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.

“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data

“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated 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.

“(iv) 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: (A) 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 (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

“(v) 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.

“(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i) 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

“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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“(31) Undeveloped oil and gas reserves. Undeveloped oil and 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.

“(i) Reserves on undrilled acreage shall be 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.

“(ii) 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.

“(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

“(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

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“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”