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Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

This report presents estimates, as of December 31, 2022, of the extent and value of the proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which Viper Energy Partners LP (Viper) has represented that GRP Energy Capital (GRP) holds an interest. The properties evaluated herein consist of royalty interests located in Colorado, Montana, New Mexico, North Dakota, Oklahoma, Pennsylvania, Texas, and Wyoming. A list of the properties evaluated in this report is shown in the appendix to this report under the Lease Totals – Reserves and Revenue tab.

Estimates of reserves presented in this report have been prepared in compliance with the regulations promulgated by the United States Securities and Exchange Commission (SEC). These reserves definitions are discussed in detail in the Definition of Reserves section of this report.

Reserves estimated in this report are expressed as gross reserves and net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2022. Net reserves are defined as that portion of the gross reserves attributable to the interests held by GRP after deducting all interests held by others.

This report presents values for proved reserves that were estimated using prices, expenses, and costs provided by Viper. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). A detailed explanation of the future price, expense, and cost assumptions is included in the Valuation of Reserves section of this report.

Values for proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad valorem taxes, and gathering, processing, and transportation (GP&T) expenses from future gross revenue. At the request of Viper, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold. In this report, present worth values using a discount rate of 10 percent are reported in detail and values using discount rates of 5, 8, 12, 15, 17.5, 20, and 25 percent are reported as totals in the appendix to this report.

Estimates of reserves and revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

This report was prepared in October 2023; therefore, certain events that may have occurred before the preparation of this report but after the “as-of” date of December 31, 2022, which might have affected the reserves, prices, costs, and values used in the estimates presented herein, were not taken into account.

Information used in the preparation of this report was obtained from Viper and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Viper with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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.

(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.

(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.

(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.

(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.

(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 (iii) of the proved oil and gas reserves definition, 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.

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 [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. No probable or possible reserves have been evaluated for this report.

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 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.

Viper was unable to provide actual plans for the future development of the properties evaluated herein. Therefore, for the purposes of this report, the timing for the development of undeveloped reserves estimates presented herein was derived based on data provided by Viper. 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 identified to Viper its intention to drill.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. 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.

Data provided by Viper from wells drilled through December 31, 2022, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available through December 31, 2022. Cumulative production, as of December 31, 2022, was deducted from the estimated gross ultimate recovery to estimate gross reserves.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in the appendix to this report are expressed in barrels (bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (◦F) and at the legal pressure base of the state in which the quantities are located. Gas quantities included in the appendix to this report are expressed in thousands of cubic feet (Mcf).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.


	Gross Reserves			Net Reserves
	Oil and		Sales	Oil and		Sales
	Condensate	NGL	Gas	Condensate	NGL	Gas
	(Mbbl)	(Mbbl)	(MMcf)	(Mbbl)	(Mbbl)	(MMcf)
Proved
Developed Producing	1,074,894	778,278	5,578,336	7,126	4,961	35,007
Developed Non-Producing	0	0	0	0	0	0

Total Proved Developed	1,074,894	778,278	5,578,336	7,126	4,961	35,007
Undeveloped	747,214	431,343	2,788,132	5,495	3,660	22,635

Total Proved	1,822,108	1,209,621	8,366,468	12,621	8,621	57,642

Viper has represented that the oil, condensate, and NGL prices were based on a reference 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, unless prices are defined by contractual agreements. Viper supplied differentials to a West Texas Intermediate (WTI) reference price of $93.67 per barrel and these prices were held constant thereafter. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were $94.02 per barrel of oil and condensate and $33.24 per barrel of NGL.

Viper has represented that the gas prices were based on a reference 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, unless prices are defined by contractual agreements. Viper supplied differentials to a Henry Hub reference price of $6.36 per million Btu and the prices were held constant thereafter. Btu factors provided by Viper were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $5.634 per thousand cubic feet of gas.

Production taxes were calculated using the tax rates for each state in which the reserves are located, including, where appropriate, abatements for enhanced recovery programs. Ad valorem taxes were calculated using rates provided by Viper based on recent payments.

The properties evaluated are royalties. Therefore, no operating expenses, capital costs, or abandonment costs are incurred. Estimates of operating expenses, provided by Viper and based on current expenses, were used to determine the economic life of each property. Viper was unable to provide actual capital costs or abandonment costs for the properties evaluated herein. Therefore, for the purposes of this report, typical capital costs and abandonment costs were estimated based on our knowledge of the areas and/or field operations. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2022, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):


	Proved	Proved	Total
	Developed	Developed	Proved	Proved	Total
	Producing	Non-Producing	Developed	Undeveloped	Proved
	(M$)	(M$)	(M$)	(M$)	(M$)

Future Gross Revenue	1,035,370	0	1,035,370	762,551	1,797,921
Production and Ad Valorem Taxes	60,469	0	60,469	37,000	97,469
GP&T Expenses	38,787	0	38,787	19,227	58,014
Future Net Revenue	936,114	0	936,114	706,324	1,642,438
Present Worth at 10 Percent	470,511	0	470,511	389,182	859,693

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8)(i), (ii), and (v)–(x), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year. This report does not include certain disclosures required by Item 1202 (a)(8) of Regulation S–K and is thus not to be used for inclusion in certain SEC filings.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

The appendix bound with this report includes (i) summary projections of proved reserves and revenue sorted by reserves category, (ii) summary projections of proved reserves and revenue sorted by basin and reserves category, and (iii) tabulations of proved reserves and revenue sorted by basin, reserves category, and lease.

Viper has represented that GRP holds an interest in certain properties located in Colorado, Montana, New Mexico, North Dakota, Oklahoma, Pennsylvania, Texas, and Wyoming evaluated herein. The estimated net proved reserves, as of December 31, 2022, of the properties evaluated herein are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):


	Net Reserves
	Oil and		Sales
	Condensate	NGL	Gas
	(Mbbl)	(Mbbl)	(MMcf)

Proved
Developed Producing	7,126	4,961	35,007
Developed Non-Producing	0	0	0

Total Proved Developed	7,126	4,961	35,007

Undeveloped	5,495	3,660	22,635

Total Proved	12,621	8,621	57,642

The estimated future revenue attributable to GRP’s interest in the proved reserves, as of December 31, 2022, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):


	Proved Developed Producing	Proved Developed Non-Producing	Total Proved Developed	Proved Undeveloped	Total Proved
	(M$)	(M$)	(M$)	(M$)	(M$)

Future Gross Revenue	1,035,370	0	1,035,370	762,511	1,797,921
Future Net Revenue	936,114	0	936,114	706,324	1,642,438
Present Worth at 10 Percent	470,511	0	470,511	389,182	859,693

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2022, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Viper. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report.


		Page
FOREWORD		1
	Scope of Investigation	1
	Authority	2
	Source of Information	3
DEFINITION of RESERVES		4
ESTIMATION of RESERVES		8
VALUATION of RESERVES		11
SUMMARY and CONCLUSIONS		14
APPENDIX - Bound with Report


Dilhan Ilk, P.E.
Executive Vice President
DeGolyer and MacNaughton