Exhibit 99.1

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244

This is a digital representation of a DeGolyer and MacNaughton report.

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.

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD
SUITE 800 EAST

DALLAS, TEXAS 75244

March 19, 2018

Mesa Royalty Trust

919 Congress Avenue

Suite 500

Austin, Texas 78701

Ladies and Gentlemen:

Pursuant to your request, we have prepared estimates of the extent and value of the proved gas, condensate, and natural gas liquids (NGL) reserves, as of December 31, 2017, attributable to an overriding royalty interest (the ORRI) that the Mesa Royalty Trust (the Trust) has represented that it owns. 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 oil and gas 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 owned and/or administered by BP America Production Company (BP), ConocoPhillips (Conoco), and Linn Energy, LLC (Linn). BP, Conoco, and Linn 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 19, 2018. 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, 2017. 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) of the United States. 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 gas, condensate, and NGL to be produced

from, and net to, the Subject Interests (inclusive of the ORRI) after December 31, 2017. 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, there 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 report are to a large extent hypothetical and differ in significant respects from estimates of reserves attributable to a working interest.

Estimates of gas, condensate, and NGL reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue 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.

Data used in this evaluation were obtained from reviews with the trustee, from files provided by the trustee, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by IHS Markit Inc; Copyright 2017 IHS Markit Inc. In the preparation of this report we have relied, without independent verification, upon such information furnished by BP, Conoco, Linn, and the trustee with respect to property interests, 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.

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Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance 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.

All reserves estimated herein are considered proved developed producing.

For developed producing wells whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated using decline-curve analysis. For producing 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 based on existing economic conditions. No additional wells are planned, so there are no undeveloped reserves.

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 are expressed at a temperature base of 60 degrees Fahrenheit and at the pressure base of the state in which the reserves are located. Gas reserves included herein are expressed in thousands of cubic feet (Mcf). Condensate reserves estimated herein are those to be obtained by normal separator recovery. NGL reserves are those attributable to the leasehold interests according to processing agreements. Condensate and NGL reserves included in this report are expressed in barrels (bbl) 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

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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.

Definition of Reserves

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.

(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.

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(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.

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

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(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.

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 rates used for future gas, condensate, and NGL production were estimated to be within the capacity of a well or reservoir to produce. Data available from wells drilled on the evaluated properties through December 31, 2017, were used to prepare the estimates shown herein. Gross production estimated through December 31, 2017, was deducted from the gross ultimate recovery to arrive at

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estimates of gross reserves. This required that the production rates be estimated for up to 2 months, since production data were available only through October 2017.

Primary Economic Assumptions

Values associated with the ORRI and the Subject Interests are expressed in terms of estimated future net proceeds, future net revenue, and present worth. Future gross revenue is 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 tax expenses 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 of 10 percent 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.

Revenue values in this report were estimated for proved reserves using initial prices 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 assumptions were used for estimating future prices and costs:

Gas Prices

Gas prices were calculated using differentials furnished by the Lessees for their respective properties to a Henry Hub price of $3.02 per million British thermal units ($/MMBtu) and held constant thereafter. The Henry Hub price of $3.02 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. British thermal unit factors provided by Bank of New York were used to convert prices from $/MMBtu to dollars per thousand cubic feet ($/Mcf). The volume-weighted

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average price over the lives of the properties was $2.824 per thousand cubic feet of gas.

Condensate and NGL Prices

Condensate and NGL prices were calculated using differentials furnished by the Lessees for their respective properties to West Texas Intermediate (WTI) Cushing price of $51.34 per barrel and held constant thereafter. The WTI Cushing price of $51.34 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 $35.91 per barrel of condensate and $18.74 per barrel of NGL.

Production and Ad Valorem Taxes

Production and ad valorem taxes were provided by Bank of New York.

Operating Expenses, Capital Costs, and Abandonment Costs

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 were provided by Bank of New York for inclusion in this report.

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Estimates of the net proved reserves of the Trust’s ownership in the ORRI are summarized as follows, expressed in millions of cubic feet (MMcf) and in thousands of barrels (Mbbl):

The estimated future net revenue and present worth at 10 percent attributable to the Trust’s ownership of the ORRI, as of December 31, 2017, under the economic assumptions furnished by Bank of New York are summarized as follows, expressed in thousands of dollars (M$):

Note: Future income tax expenses were not taken into account in the preparation of these estimates.

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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, 2017, estimated reserves.

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 natural gas liquids, 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 Financial Accounting Standards Board 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 Securities and Exchange Commission; provided, however, (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.

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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 letter report has been prepared at the request of Bank of New York. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report.

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CERTIFICATE of QUALIFICATION

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

1.              That I am President of DeGolyer and MacNaughton, which company did prepare the letter report addressed to Mesa Royalty Trust dated March 19, 2018, and that I, as President, was responsible for the preparation of this letter report.

2.              That I attended Texas A&M University, and that I graduated with a degree in Civil Engineering in the year 1979; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations.