EX-99.1 11 actg-20241231xex991.htm EX-99.1
February 21, 2025 Mr. Kirk Goehring CEO Benchmark Energy 3800 North Lamar Blvd, Suite 200 Austin, TX 78756 Re: Evaluation Summary – SEC Price Benchmark Energy II, LLC Interests Proved Developed Reserves Certain Properties in Oklahoma and Texas As of December 31, 2024 Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue Dear Mr. Goehring: As requested, this report was completed on February 21, 2025 for Benchmark Energy II, LLC (“Benchmark”), for the purpose of public disclosure by Benchmark 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 the Oklahoma and Texas proved developed reserves, as per information from Benchmark. This evaluation utilized an effective date of 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 SEC. The results of this evaluation are presented in the composite summary below: Proved Proved Proved Developed Developed Developed Proved Producing Non-Producing Behind Pipe Developed Net Reserves Oil - Mbbl 5,134.1 135.2 45.7 5,314.9 Gas - MMcf 66,173.1 1,298.6 638.6 68,110.3 NGL - Mbbl 8,373.3 191.8 47.9 8,612.9 Net Revenue Oil - M$ 369,681.9 9,685.3 3,332.8 382,699.9 Gas - M$ 56,864.1 1,115.9 548.8 58,528.8 NGL - M$ 210,648.2 4,824.1 1,204.9 216,677.2 Severance Taxes - M$ 39,556.3 945.9 284.8 40,787.1 Ad Valorem Taxes - M$ 12,787.6 351.4 142.5 13,281.4 Future Production Costs - M$ 272,666.9 9,090.5 1,551.4 283,308.8 Future Development Costs - M$ 0.0 1,755.0 310.5 2,065.5 Abandonment Costs - M$ 20,737.9 1,250.4 331.2 22,319.4 Net Operating Income (BFIT) - M$ 291,445.4 2,232.1 2,466.2 296,143.8 Discounted @ 10% - M$ 164,573.7 1,130.0 1,882.5 167,586.3 EXHIBIT 99.1

Benchmark Energy II, LLC Interests February 21, 2025 Page 2 Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow (net operating income) is after deducting these taxes, future development 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. Proved Developed reserves are the summation of the Proved Developed Producing, Proved Developed Non-Producing and Proved Developed Behind Pipe reserve estimates. Hydrocarbon Pricing The base SEC oil and gas prices calculated for December 31, 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 prices (EIA) during 2024 and the base gas price is based upon Henry Hub spot prices (Platts Gas Daily) during 2024. Furthermore, NGL prices were adjusted on a summary level and averaged 34.9% of the net oil price on a composite basis. The base prices 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 developed properties was estimated to be $72.005 per barrel for oil, $0.859 per MCF for natural gas and $25.157 per barrel for NGL. 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, oil and gas severance taxes, future production costs (lease operating expenses) and future development costs (capital investments) were calculated and prepared by Benchmark and reviewed by us at a summary level using historical lease operating statement data. All economic parameters, including lease operating expenses (LOE) and investments, were held constant (not escalated) throughout the life of these properties in accordance with SEC guidelines. LOE includes fixed and variable components. The fixed LOE costs represent all costs not tied to produced volumes. The variable costs consist of fees for water disposal, gas compression, processing and transportation, and other variable expenses. SEC Conformance and Regulations The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined on pages one (1) and two (2) of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes, and royalties currently in effect except as noted herein. Benchmark’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and

Benchmark Energy II, LLC Interests February 21, 2025 Page 3 policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities. This evaluation includes 32 PDNP and seven (7) PDBP locations which are targeting various reservoirs in Oklahoma and Texas. The PDNP locations represent 29 workover cases and three (3) wells that are awaiting plug and abandonment. The PDBP locations represent behind pipe cases for other zones. The drilling schedule was provided by Benchmark based upon their go forward plan and was accepted by CG&A as furnished. In our opinion, Benchmark has indicated they have every intent to complete this development plan as scheduled. Furthermore, Benchmark has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this development plan will be fully executed. Reserve Estimation Methods Reserves assigned to each producing well (PDP) were based on a combination of forecasting methods including decline curve analysis (DCA), regional type curve analysis and analogy to offset production. 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. Non-producing and behind pipe reserve estimates were forecast using either production performance, volumetric or analogy methods, or a combination of each. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved developed behind pipe reserves due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report. General Discussion The estimates and forecasts were based upon interpretations of data furnished by Benchmark and available from our files. 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. Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Moreover, estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom, and the actual costs related thereto, 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 considered in this evaluation as directed.

Benchmark Energy II, LLC Interests February 21, 2025 Page 4 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 Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or Benchmark Energy II, LLC and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office. Yours very truly, CAWLEY, GILLESPIE & ASSOCIATES, INC. TEXAS REGISTERED ENGINEERING FIRM F-693 W. Todd Brooker, P. E. President Thomas M. Barr Sr. Reservoir Engineer

Appendix Cawley, Gillespie & Associates, Inc. Page 1 APPENDIX 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. "(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.

Appendix Cawley, Gillespie & Associates, Inc. Page 2 "(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. “(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).”