EX-99.1 4 a2208206zex-99_1.htm EX-99.1
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Exhibit 99.1

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

February 29, 2012

Mesa Royalty Trust
919 Congress Avenue
Suite 500
Austin, Texas 78701

Gentlemen:

Pursuant to your request, we have prepared estimates of the extent and value of the proved developed natural gas reserves and associated condensate and natural gas liquids (NGL) attributable to an overriding royalty interest (the ORRI) owned by the Mesa Royalty Trust (the Trust), as of December 31, 2011. 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), ConocoPhilips (Conoco), Red Willow Production Company (Red Willow), XTO Energy Inc. (XTO), and Pioneer Natural Resources (Pioneer). BP, Conoco, Red Willow, XTO, and Pioneer are collectively referred to 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 and is to be used for inclusion in certain filings with the Securities and Exchange Commission (SEC) of the United States. This evaluation was completed on February 29, 2012. 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, 2011. The net proved reserves estimates prepared by us have been prepared in accordance with the reserves definitions of Rules 4-10(a) (1)–(32) of Regulation S-X of the SEC.

Estimates of proved reserves presented in this report have been prepared in compliance with the regulations promulgated by the SEC. These reserves definitions are discussed in detail under the Definition of Reserves heading of this letter.

Reserves estimated in this report are expressed as gross and 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, 2011. 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 letter 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 shown herein are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. 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 compounded monthly over the expected period of realization.

This report presents values that 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. A detailed explanation of the price and cost assumptions used herein is included in the "Valuation of Reserves" section of this report.

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 that revenue which will accrue from the sale of gas, oil and natural gas 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.

Estimates of oil, condensate, NGL, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves 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 audit were obtained from reviews with the trustee, 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 Global Inc; Copyright 2011 IHS Global Inc. In the preparation of this report we have relied, without independent verification, upon such information furnished by 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.

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.

For developed producing wells whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were determined using decline-curve analysis. For producing wells whose performance was not yet established and for undeveloped well locations, 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.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

The rates used for future condensate, NGL, and gas production are estimated to be within the capacity of a well or reservoir to produce. Data available from wells drilled on the appraised properties through December 31, 2011, were used to prepare the estimates shown herein. Gross production through December 31, 2011, was deducted from the gross ultimate recovery to arrive at estimates of gross reserves.

Gas quantities estimated herein are expressed as sales gas at a temperature base of 60 degrees Fahrenheit (°F) and a pressure base of the state in which the reserves are located. 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. Condensate reserves estimated herein are those to be obtained by normal separator recovery.

Net reserves for the Trust's ownership of the ORRI are calculated at the aggregate level from the net revenue for each of the Lessees. To estimate net gas reserves, the total net revenue is 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 are 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.

(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:

(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.

Primary Economic Assumptions

This report has been prepared using initial prices and costs provided by or on behalf of Bank of New York. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). In this report, values for proved reserves were based on projections of estimated future production and revenue prepared for these properties.

Revenue values in this report are estimated using the prices discussed herein. The following assumptions were used for estimating future prices and costs:

Condensate and NGL Prices

Initial condensate prices were calculated using differentials furnished by the Lessees for their respective properties to WTI Cushing price of $96.23 per barrel and held constant thereafter. The WTI cushing price of $96.23 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 weighted average price over the lives of the properties was $81.31 per barrel for condensate and $47.45 per barrel for NGL.

Natural Gas Prices

Initial natural gas prices were calculated using differentials furnished by the Lessees for their respective properties to a Henry Hub price of $4.12 per million British thermal units (MMbtu) and held constant thereafter. The Henry Hub price of $4.12 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 weighted average price over the lives of the properties was $3.52 per Mcf.

Operating Expenses and Capital 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.

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 oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2011, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

Estimates of the gross and net proved reserves, as of December 31, 2011, of the Trust's ownership in the ORRI are presented as follows. Condensate and NGL reserves are expressed in thousands of barrels (Mbbl) and gas reserves are expressed in thousands of cubic feet (MMcf).

	Net Reserves

	BP		Conoco		Pioneer		Red Willow		XTO		Total
Proved Developed
Condensate, Mbbl		0		11		0		0		0		11
Gas, MMcf		629		4,570		2,002		132		11		7,344
NGL, Mbbl		0		410		114		0		1		525
Proved Undeveloped
Condensate, Mbbl		0		0		0		0		0		0
Gas, MMcf		0		0		651		0		0		651
NGL, Mbbl		0		0		37		0		0		37
Total Proved
Condensate, Mbbl		0		11		0		0		0		11
Gas, MMcf		629		4,570		2,653		132		11		7,995
NGL, Mbbl		0		410		151		0		1		562

The estimated future net revenue and present worth at 10 percent attributable to the Trust's ownership of the ORRI, as of December 31, 2011, under the economic assumptions furnished by Bank of New York is summarized as follows, expressed in thousands of dollars (M$):

	Future Net Revenue (M$)

	BP		Conoco		Pioneer		Red Willow		XTO		Total
Proved Developed		1,727		33,031		14,485		419		72		49,734
Proved Undeveloped		0		0		4,692		0		0		4,692

Total Proved		1,727		33,031		19,177		419		72		54,426
	Present Worth at 10 Percent (M$)
	BP		Conoco		Pioneer		Red Willow		XTO		Total
Proved Developed		1,056		17,190		9,348		231		51		27,876
Proved Undeveloped		0		0		2,061		0		0		2,061

Total Proved		1,056		17,190		11,409		231		51		29,937

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

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, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-6 through 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, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.

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.

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.


		Submitted,
		/s/ DEGOLYER AND MACNAUGHTON DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716

[SEAL]		/s/ PAUL J. SZATKOWSKI, P.E. Paul J. Szatkowski, P.E. Senior Vice President

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, 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 a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Mesa dated February 29, 2012, and that I, as Senior Vice President, was responsible for the preparation of this report.
2.: That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 37 years of experience in oil and gas reservoir studies and reserves evaluations.


[SEAL]		/s/ PAUL J. SZATKOWSKI, P.E. Paul J. Szatkowski, P.E. Senior Vice President

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Exhibit 99.1