DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244

March 29, 2019

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2018, of the extent and value of the estimated net proved gas, condensate, and natural gas liquids (NGL) reserves attributable to an overriding royalty interest (the ORRI) in which the Mesa Royalty Trust (the Trust) has represented it holds an interest. The ORRI was conveyed to the Trust pursuant to an Overriding Royalty Conveyance dated November 1, 1979 (the Conveyance), and is payable out of certain net proceeds attributable to the grantor's ownership of certain properties located in the San Juan Basin of Colorado and New Mexico and the Hugoton field in Kansas. The grantor's interests in the oil and gas properties (referred to as the Subject Interests in the Conveyance and evaluated in this report) are now held and/or administered by BP America Production Company (BP), Hilcorp Energy Company (Hilcorp), and Riviera Operating, LLC (Riviera). BP, Hilcorp, and Riviera are collectively referred to herein as the Lessees. This report was prepared at the request of The Bank of New York Trust Company, N.A. (Bank of New York), the trustee of the Trust. This evaluation was completed on March 29, 2019. The Trust has represented that these properties account for 100 percent on a net equivalent barrel basis of the Trust's net proved reserves as of December 31, 2018. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202(a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by the Trust.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from, and net to, the Subject Interests (inclusive of the ORRI) after December 31, 2018. Net reserves are defined as that portion of the gross reserves attributable to the Trust's ownership of the ORRI.

While estimates of reserves attributable to the Trust's ownership of the ORRI are shown in order to comply with requirements of the SEC, this is no precise method of allocating estimates of physical quantities of reserves between the working interest owners (the Lessees) and the Trust. The ORRI is not a working interest and the Trust does not own, and is not entitled to receive by virtue of its ownership of the ORRI, any specific quantity of reserves from these oil and gas properties. Reserves quantities in this report have been allocated based on the method referenced under the Methodology and Procedures heading of this report. The quantities of reserves attributable to the Trust's ORRI will be affected by future changes in various economic factors utilized in estimating future gross and net revenues from the Subject Interests. Therefore, the estimates of reserves set forth in this reserves report are to a large extent hypothetical and differ in significant respects from estimates of reserves attributable to a working interest.

Values associated with the ORRI and the Subject Interests are expressed in terms of estimated future gross revenue, future net proceeds, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue from the sale of gas, condensate, and NGL reserves net to the Subject Interests. Future net proceeds attributable to the Subject Interests are calculated by deducting production taxes and certain production costs from the estimated future gross revenue. The future net revenue attributable to the ORRI is calculated by multiplying the net proceeds attributable

to the Subject Interests by the Trust's ownership of the ORRI. The Trust's ownership of the ORRI is 11.4429 percent of 90 percent of the future net proceeds. Future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at the arbitrary nominal discount rate of 10 percent per year 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.

Estimates of reserves and revenue should be regarded only as estimates that may change as 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.

Information used in the preparation of this report was obtained from the Lessees, from files provided by the trustee, from reports on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by IHS Markit Inc; Copyright 2018 IHS Markit Inc. In the preparation of this report we have relied, without independent verification, upon information furnished by the Lessees and the trustee 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 of the properties 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.

Developed oil and gas reserves—Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

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.

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 (Revision as of February 19, 2007)." 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.

Based on the current stage of field development, production performance, the development plans provided by the Lessees, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. All reserves estimated herein are considered proved developed.

For wells whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated using decline-curve analysis. For wells whose performance was not yet established, reserves were estimated using type curves. The parameters needed to develop these type curves, such as initial decline rate, b factor, and final decline rate, were based on nearby wells producing from the same reservoir and of similar completion for which more data were available. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report. No additional wells are planned, so there are no undeveloped reserves.

Data provided by the Lessees from wells drilled through December 31, 2018, 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 for certain properties only through November 2018. Estimated cumulative production, as of December 31, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 1 month.

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. All gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state in which the reserves are located. Gas reserves included in this report are expressed in millions of cubic feet (MMcf).

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 are nonassociated gas.

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. NGL reserves are the result of low-temperature plant processing. Condensate and NGL reserves included in this report are expressed in thousands of barrels (Mbbl) representing 42 United States gallons per barrel.

Net reserves for the Trust's ownership of the ORRI were calculated at the aggregate level from the net revenue for each of the Lessees. To estimate net gas reserves, the total net revenue was divided by the net value of 1 Mcf of gas. The net value of 1 Mcf of gas is the gas price per Mcf, plus the condensate value per Mcf of gas, plus the NGL value per Mcf of gas. The net condensate and NGL reserves were calculated by multiplying their respective yields by the net gas reserves.

Revenue values in this report were estimated using initial price, expenses, and costs provided by Bank of New York on behalf of the Lessees for the properties administered by each. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:

Gas prices were calculated using differentials furnished by the Lessees for their respective properties to a Henry Hub price of $3.16 per million Btu and held constant thereafter. The Henry Hub price of $3.16 per million Btu is the 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. Btu factors provided by Bank of New York were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price over the lives of the properties was $2.043 per thousand cubic feet of gas.

Condensate and NGL prices were calculated using differentials furnished by the Lessees for their respective properties to West Texas Intermediate (WTI) Cushing price of $65.66 per barrel and held constant thereafter. The WTI Cushing price of $65.66 per barrel is the 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 volume-weighted average price over the lives of the properties was $33.93 per barrel of condensate and $16.56 per barrel of NGL.

Estimates of operating expenses based on current expenses were used for the life of each property with no increases in the future based on inflation. Neither capital costs nor abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Bank of New York for inclusion in this report.

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 gas, condensate, and NGL 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, and 1202(a) (1), (2), (3), (4), (8) 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.

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 estimated net proved reserves, as of December 31, 2018, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized by Lessee as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2018

	BP		Hilcorp		Riviera		Total
Proved Developed
Gas, MMcf		1,143		5,482		667		7,292
Condensate, Mbbl		0		10		0		10
NGL, Mbbl		0		398		35		433
Proved Undeveloped
Gas, MMcf		0		0		0		0
Condensate, Mbbl		0		0		0		0
NGL, Mbbl		0		0		0		0
Total Proved
Gas, MMcf		1,143		5,482		667		7,292
Condensate, Mbbl		0		10		0		10
NGL, Mbbl		0		398		35		433

The estimated future net revenue and present worth discounted at 10 percent to be derived from the production and the sale of the net proved reserves, as of December 31, 2018, of the properties evaluated using the guidelines established by the SEC are summarized as follows, expressed in thousands of dollars (M$):

	Future Net Revenue (M$)

	BP		Hilcorp		Riviera		Total
Proved Developed		1,371		16,284		3,228		20,883
Proved Undeveloped		0		0		0		0

Total Proved		1,371		16,284		3,228		20,883

	Present Worth at 10 Percent (M$)

	BP		Hilcorp		Riviera		Total
Proved Developed		821		7,606		2,213		10,640
Proved Undeveloped		0		0		0		0

Total Proved		821		7,606		2,213		10,640

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, 2018, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and

MacNaughton does not have any financial interest, including stock ownership, in the Trust. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of the Trust. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report.


		Submitted,
		/s/ DeGolyer and MacNaughton
		DeGOLYER and MacNAUGHTON
		Texas Registered Engineering Firm F-716

I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:


		/s/ GREGORY K. GRAVES Gregory K. Graves, P.E. Senior Vice President DeGolyer and MacNaughton