EX-99.1 23 exhibit991-202210xk.htm EX-99.1
Exhibit 99.1

APPRAISAL OF CERTAIN
OIL AND NATURAL GAS INTERESTS OWNED BY
CATAPULT MINERAL PARTNERS
A NAACO INDUSTRIES, INC. COMPANY
LOCATED IN
VARIOUS COUNTIES IN ALABAMA, LOUISIANA, NEW MEXICO, OHIO, PENNSYLVANIA, TEXAS, AND WYOMING
AS OF JANUARY 1, 2023
PREPARED FOR CATAPULT MINERAL PARTNERS
Haas Petroleum Engineering Services, Inc. F-0002950
/s/Franklin W. Stagg, P.E.
Franklin W. Stagg, P.E.
March 6, 2023

750 N. St. Paul Street
Suite 1750
Dallas, Texas 75201
Phone (214) 754-7090
March 6, 2023
Mr. Brian Larson
Catapult Mineral Partners, LLC.
A NACCO Natural Resources Company
5340 Legacy Drive, Suite 300
Plano, TX 75024
Mr. Larson:
As requested, Haas Petroleum Engineering Services, Inc. (hereinafter referred to as “Haas Engineering”) has prepared an estimate of certain hydrocarbon Proved Reserves owned by Catapult Mineral Partners, LLC. (hereinafter referred to as “Catapult”), a wholly owned subsidiary of NACCO Industries, Inc. (“NACCO”). The properties evaluated in this report are primarily located in Alabama, Louisiana, New Mexico, Ohio, Pennsylvania, Texas, and Wyoming. This estimate of Reserves was completed on or about the above date of this letter. This report was prepared for NACCO’s inclusion as an exhibit in their filing with the United States Securities and Exchange Commission (“SEC”), and it is our understanding that it contains approximately 100 percent of Catapult’s Proved Reserves. With the exception of the exclusion of future income taxes, this evaluation conforms to the FASB Accounting Standards Codification Topic
932, Extractive Industries - Oil and Gas. It is Haas Engineering’s opinion that the assumptions, data,
methods, and procedures used in the preparation of this report are appropriate for this purpose.
Production data was generally available through June 30, 2022, with many properties updated through November 30, 2022. As of January 01, 2023, Catapult’s net Reserves, future net income (“FNI”), and net present worth discounted at 10 percent per annum (“NPV”) have been estimated to be as follows:
FNI is after deducting estimated operating and future development costs, severance and ad valorem taxes, but before Federal income taxes. Total net Proved Reserves are defined as those natural gas and hydrocarbon liquid Reserves to Catapult interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. All Reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC. All hydrocarbon liquid Reserves are expressed in United States barrels (“bbl”) of 42 gallons.

Natural gas Reserves are expressed in thousand standard cubic feet (“Mcf”) at the contractual pressure and temperature bases and include shrinkage adjustment related to field and plant losses.
RESERVES ESTIMATE METHODOLOGY
The Reserves estimates contained in this report have been prepared using standard engineering practices generally accepted by the petroleum industry. Decline curve analysis was used to estimate the remaining Reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing Reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves in this report have been estimated using deterministic and probabilistic methods. The appropriate methodology was used, as deemed necessary, to estimate Reserves in conformance with SEC regulations. The maximum remaining Reserves life assigned to wells included in this report is 50 years. This report does not include any gas sales imbalances.
RESERVES CLASSIFICATION
The Reserves estimates contained in this report conform to guidelines specified by the SEC. For more information regarding Reserves classification definitions see Appendix A. A complete discussion of the Reserves classification definitions can be found on the United States Government Printing Office website (www.gpo.gov ).
As Catapult is a mineral and royalty company, there is some uncertainty in the timing of future completions and development. Haas Engineering has used professional judgment in forecasting such timing. For the purposes of this report, completed, non-producing and drilled, and uncompleted wells have been classified as Proved Behind Pipe, and locations with an active permit have been classified as Proved Undeveloped.
COMMODITY PRICES
Pursuant to SEC guidelines, the cash flow projections in this report utilize the unweighted 12 month arithmetic average of the first-day-of month benchmark prices for January through December 2022. The benchmark price for natural gas is taken to be the price received at Henry Hub and the benchmark price for hydrocarbon liquids is taken to be the price received for West Texas Intermediate (“WTI”) crude oil at the Cushing, OK sales point.
The unweighted arithmetic average cash market price for natural gas delivered at Henry Hub during this time period is $6.36 per MMBTU. The Henry Hub price was held constant throughout the life of the wells and is adjusted for BTU content and basis differentials resulting in a weighted average net price of $6.17 per Mcf.
The unweighted arithmetic average cash market price for WTI crude oil sold at Cushing, OK during this time period is $93.67 per bbl. For natural gas liquids (“NGL”), the WTI crude oil price was held constant throughout the life of the wells and is adjusted for BTU content and basis differentials, resulting in a weighted average net price of $39.95 per bbl. For crude oil, the WTI crude oil price was held constant throughout the life of the wells and is adjusted for crude quality, BS&W, purchaser bonuses and basis differentials, resulting in a weighted average net price of $93.02 per bbl.
Fees associated with gathering, marketing, processing, and transportation were applied as expenses in this report.
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Revenue accounting data for the period of July 1, 2021 to June 30, 2022 was used in this evaluation.
OPERATING EXPENSES
As Catapult is a mineral and royalty company, it is not burdened by operating expenses and capital costs. Therefore, Asset Retirement Obligations (“ARO”) have not been included in this evaluation. The lease operating costs used in this evaluation have been included to truncate the commercial life of the property and were estimated based on knowledge of analogous wells producing under similar conditions. The lease operating expenses in this report represent field level operating costs.
Operating expenses and capital costs were not escalated in this evaluation.
DISCLAIMERS
The Proved Reserves presented in this report are 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. Because of governmental policies and uncertainties of supply and demand, the product prices and the costs incurred in recovering these Reserves may vary from the price and cost assumptions in this report. Because these estimates are based on existing governmental regulations, changes could affect the ability to recover these Reserves. In any case, quantities of Reserves may increase or decrease as a result of future operations.
Reserves estimates for individual properties included in this report are only valid when considered within the context of the overall report and should not be considered independently. The future net income and net present value estimates contained in this report do not represent an estimate of fair market value.
All information pertaining to the operating expenses, prices, and the interests of Catapult in the properties appraised has been accepted as represented. It was not considered necessary to make a field examination of the appraised properties. Data used in performing this appraisal were obtained from Catapult, public sources, and our own files. Supporting work papers pertinent to the appraisal are retained in our files and are available to you or designated parties at your convenience.
It was beyond the scope of this Haas Engineering report to evaluate the potential environmental liability costs from the operation and abandonment of these properties. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the forecasts presented herein.
Nothing contained in this report is intended to create or confer, or shall be construed as having created or conferred, any rights in any third party, and all claims, rights, remedies, and obligations of Haas Engineering or Catapult, as the case may be, in connection with this report shall accrue or apply solely to Haas Engineering or Catapult. For all purposes of this paragraph, the term “third party” means any party other than Catapult or Haas Engineering, including without limitation Catapult’s owners, prospective investors, lenders or prospective lenders, partners or prospective partners, and vendors or other service providers. Without the express written consent of Haas Engineering, only Catapult is entitled to rely on this report and any information, conclusions, and/or opinions contained herein.
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Haas Engineering is independent with respect to Catapult, as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
The technical persons primarily responsible for conducting this Report meets the requirements regarding qualifications, independence, objectivity, and confidentiality, as defined by the SPE Standards. Franklin Stagg, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Haas Engineering since 2016 and has over 7 years of industry experience.
GENERAL INFORMATION
Attached are summary tables of economic analysis of predicted future performance. Other tables identify the properties appraised with summary Reserves and the economic factors applicable to each. A list of tables is included.
We appreciate this opportunity to have been of service and hope that this report will fulfill your requirements.
[Remainder of page intentionally left blank. Signature page follows.]
Catapult Mineral Partners, LLC | March 6, 2023| Page 4 of 5

Respectfully submitted,
Haas Petroleum Engineering Services, Inc. F-0002950
/s/Franklin W. Stagg, P.E.
Franklin W. Stagg, P.E. March 6, 2023
Catapult Mineral Partners, LLC | March 6, 2023| Page 5 of 5

Appendix

Appendix A
Definitions of Oil and Gas Reserves ‐ Securities and Exchange Commission
The list of definitions below were compiled by HPESI. They represent selected definitions from the Securities and Exchange Commission’s Rule 4‐10 document. This document was amended on January 14, 2009, and the definitions below reflect the changes resulting from the amendment. Comprehensive versions of Rule 4‐10 and the amendments to Rule 4‐10 can be obtained online at http://www.gpoaccess.gov/ .
(a) Definitions. The following definitions apply to the terms listed below as they are used in this section:
(1) 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.
(2) 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 (a)(22)(iii) of this section, 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.
(3) 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.

Appendix A
Definitions of Oil and Gas Reserves ‐ Securities and Exchange Commission
(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 (a)(17)(iv) and (a)(17)(vi) of this section.
(4) 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 the 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.
(5) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(6) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Appendix A
Definitions of Oil and Gas Reserves ‐ Securities and Exchange Commission
(7) 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 (a)(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).
(8) 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.
-SEE NACCO'S EXHIBIT 99.2 - SUPPLEMENTAL FIGURES ATTACHMENT