EX-10.6



 Exhibit 10.6 

DEGOLYER AND MACNAUGHTON 

5001 SPRING VALLEY ROAD 

SUITE 800 EAST 

DALLAS, TEXAS 75244 

April 15, 2020 
 Ing. Francisco Javier
Flamenco López 
 Subdirector Técnico de Exploración y Producción 

Suplente por Ausencia del Director General de 
 Pemex
Exploración y Producción en términos del 
 Artículo 127 del Estatuto Orgánico de Pemex Exploración y
Producción. 
 Pemex Exploración y Producción 

Avenida Marina Nacional No. 329 
 Torre Ejecutiva, Piso 41

 Colonia Verónica Anzures 
 Alcaldía Miguel
Hidalgo 
 11300 Ciudad de México, México 
 Dear
Ing. Flamenco López, 
 Pursuant to your request, this report of third party presents an independent evaluation, as of January 1,
2020, of the estimated net proved oil, condensate, gas, and oil equivalent reserves of certain properties that Pemex Exploración y Producción (PEP) has represented are owned by the United Mexican States. These properties are located in
the Activo Integral de Producción Bloque AS02-03 (Abkatún-Pol-Chuc),
AS02-04 (Litoral de Tabasco), and N02 (Poza Rica-Altamira), onshore and offshore Mexico. This evaluation was completed on April 15, 2020. PEP has represented that these properties account for
22.9 percent on a net oil equivalent barrel basis of PEP’s net proved reserves as of January 1, 2020, and that PEP’s net proved reserves estimates were 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. It is our opinion that the procedures and methodologies employed by PEP for the preparation of its proved reserves estimates as of
January 1, 2020, comply with the current requirements of the SEC. We have reviewed information provided by PEP that it represents to be PEP’s estimates of the net reserves, as of January 1, 2020, for the same properties as those which
we evaluated. 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 PEP. 









			
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 PEP has represented that all subsurface hydrocarbons belong to the United Mexican States as
stated in the Ley de Hidrocarburos (Hydrocarbons Law). At the request of PEP, this report also includes estimates prepared by PEP of its natural gas liquids (plant liquids) reserves; however, PEP has represented that PEP’s management of
the properties stops at the inlet of the gas processing plants; therefore, PEP has no right to those quantities presented herein. 

Reserves estimates included herein are expressed as net reserves as represented by PEP. Gross reserves are defined as the total estimated
petroleum remaining to be produced from these properties after December 31, 2019. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by the United Mexican States and held by PEP after deducting
all interests held by others, without consideration of royalties and other fiscal or contractual terms. 
 Estimates of reserves 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. 
 Information used in the preparation
of this report was obtained from PEP. In the preparation of this report we have relied, without independent verification, upon information furnished by PEP 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. 
 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: 









			
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 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. 









			
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 (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. 









			
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 (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. 

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 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.










			
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 Based on the current stage of field development, production performance, the development
plans provided by PEP, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The undeveloped reserves estimated herein were based on opportunities identified in the plan of development
provided by PEP. 
 PEP has represented that its senior management is committed to the development plan provided by PEP and that PEP has the
financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities. 

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps
were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electric logs, radioactive logs, core analyses, bottomhole pressure, and other available data were used to prepare maps as well as to estimate
representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance methods were used to estimate OOIP or OGIP. 

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were based on
consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to
estimate recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.  

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. 
 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). 









			
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 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. 

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data
were available. 
 In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for
which more complete historical performance data were available. 
 For cases where history-matched dynamic models were available and
applicable, model results were used to estimate recovery factors and reserves production forecasts. In certain cases, a simplified multi-cell, three-dimensional, black-oil simulation model was developed to
support the analyses of recovery factors and production forecasts. 
 Data provided by PEP from wells drilled through December 31,
2019, 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 2019. Cumulative production, as of
December 31, 2019, 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. Plant liquids reserves estimated herein include propane, butane, and pentanes and heavier fractions (C5+). Plant liquids reserves are the result of
low-temperature plant processing. Oil, condensate, and plant liquids reserves reported herein are expressed in millions of barrels (106bbl). In these estimates, 1 barrel equals 42 United States gallons. 

Gas quantities estimated herein are expressed as natural gas, sales gas, and dry gas. Natural gas is the total gas produced from the reservoir
prior to processing or separation and includes all nonhydrocarbon components. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the inlet to the processing plant, after reduction for injection, fuel usage, flare,
and shrinkage resulting from field separation. Dry gas is defined as the total gas to be produced from the reservoirs, measured at the tailgate of the processing plant, after reduction for injection, fuel usage, flare, and shrinkage resulting from
field separation and plant processing. Gas reserves estimated herein are reported as sales gas and dry gas. Gas quantities estimated herein are expressed at a temperature base of 20 degrees Celsius (°C) and at a pressure base of 1
atmosphere (atm). Gas quantities presented in this report are expressed in billions of cubic feet (109ft3). 









			
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 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 crude oil present in the reservoir. Associated gas includes both gas-cap gas and solution gas. Gas-cap
gas is gas at initial reservoir conditions and is in communication with an underlying crude oil zone. Solution gas is gas dissolved in crude oil at initial reservoir conditions. Gas quantities estimated herein include both associated and
nonassociated gas. 
 Condensate, sales gas, plant liquids, and dry gas reserves were estimated by applying yields and shrinkages, provided
by PEP, to estimates of natural gas quantities. 
 At the request of PEP, estimated dry gas quantities, defined as the total gas to be
produced from the reservoirs, measured at the tailgate of the processing plant, after reduction for injection, fuel usage, flare, and shrinkage resulting from field separation and plant processing, were converted to dry gas equivalent to liquids on
a field-by-field basis using an energy equivalent factor based on the dry gas composition of each field, as provided by PEP. In addition, natural gas quantities
estimated herein were converted to oil equivalent on a field-by-field basis using an energy equivalent factor reflecting the yields and shrinkages of each field, as
provided by PEP. 
 Primary Economic Assumptions 

This report has been prepared using initial prices, expenses, and costs provided by PEP in United States dollars (U.S.$). 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 reserves reported herein: 









			
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 Oil and Condensate Prices 

PEP has represented that the oil and condensate 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. As represented by PEP, the reference price utilized is the Mexican Mix reference price, which is composed of the Istmo, Maya, and Olmeca reference
prices and is calculated based on a formula that includes the West Texas Sour, Light Louisiana Sweet, Brent, Oman, and Dubai reference prices. PEP supplied differentials by field to an average Mexican Mix reference price of U.S.$60.81 per barrel and
the prices were held constant thereafter. The volume-weighted average adjusted prices attributable to estimated proved reserves for the fields that were evaluated were U.S.$61.85 per barrel for oil and U.S.$27.67 per barrel for condensate. These
prices were not escalated for inflation. 
 Gas Prices 

PEP has represented that the gas prices were based on a 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, unless prices are defined by contractual arrangements. Each field’s calorific value, which includes plant liquids, was used to determine each
field’s gas price. The volume-weighted average adjusted price for the fields that were evaluated was U.S.$3.91 per thousand cubic feet. These prices were not escalated for inflation. 

Operating Expenses, Capital Costs, and Abandonment Costs 

Operating expenses and capital costs were based on information provided by PEP and were used in estimating future costs required to operate the
properties and in estimating costs for future development. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation
that might result from inflation was applied. 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 PEP. Estimates of
operating expenses, capital costs, and abandonment costs were considered in determining the economic viability of the undeveloped reserves estimated herein. 









			
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 In our opinion, the information relating to estimated proved reserves of oil, condensate, 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, and 932-235-50-9 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), and 1203(a) of Regulation S–K of the SEC; provided, however, that estimates of 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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 Summary of Conclusions 

PEP has represented that its estimated net proved reserves attributable to the evaluated properties were based on the definition of proved
reserves of the SEC. PEP’s estimates of the net proved quantities and reserves, as of January 1, 2020, attributable to these properties, which represent 22.9 percent of PEP’s reserves on a net oil equivalent basis, are summarized
as follows, expressed in millions of barrels (106bbl), billions of cubic feet (109ft3),
and millions of barrels of oil equivalent (106boe): 
  

																																	
	 	  	Estimated by PEP as of January 1, 2020	 
	 	  	 	 	  	Net Proved Reserves	 
	 Properties Evaluated by

DeGolyer and

MacNaughton
	  	Net
Natural 
Gas
Quantities
(109ft3)	 	  	Oil
(106bbl)	 	  	Condensate
(106bbl)	 	  	Sales
Gas
(109ft3)	 	  	Plant
Liquids
(106bbl)	 	  	Dry Gas
(109ft3)	 	  	Dry Gas
Equivalent
to Liquids
(106boe)	 	  	Oil
Equivalent
(106boe)	 
	 Proved Developed
	  	 	1,057.67	 	  	 	485.54	 	  	 	5.00	 	  	 	765.13	 	  	 	50.00	 	  	 	642.53	 	  	 	123.54	 	  	 	664.09	 
	 Proved Undeveloped
	  	 	1,618.38	 	  	 	720.60	 	  	 	4.64	 	  	 	1,216.10	 	  	 	44.59	 	  	 	1,112.60	 	  	 	213.92	 	  	 	983.74	 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Proved
	  	 	2,676.05	 	  	 	1,206.14	 	  	 	9.64	 	  	 	1,981.23	 	  	 	94.59	 	  	 	1,755.13	 	  	 	337.46	 	  	 	1,647.83	 

 Notes: 
  

	1.	 Reserves were estimated to the economic limit and did not consider the expiration of the contracts.




	2.	 Dry gas equivalent to liquids was calculated based on dry gas reserves. 



	3.	 Dry gas reserves estimated herein were converted to dry gas equivalent to liquids on a field-by-field basis using an energy equivalent factor reflecting the dry gas composition of each field, as provided by PEP. 



	4.	 Oil equivalent was calculated based on oil reserves and natural gas quantities. 



	5.	 Natural gas quantities estimated herein were converted to oil equivalent on a field-by-field basis using an energy equivalent factor reflecting the yields and shrinkages of each field, as provided by PEP. 



In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by PEP, differences have been found, both
positive and negative, resulting in an aggregate difference of 7.5 percent when compared on the basis of net oil equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by PEP on the
properties evaluated and referred to above, when compared on the basis of net equivalent barrels, in aggregate, are reasonable. 
 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
January 1, 2020, estimated reserves. 









			
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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 PEP. Our fees were not contingent on the results of our evaluation. This
report has been prepared at the request of PEP. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. 

 

     




	
	Submitted,
	
	




	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716

 
 


 

 



 



	
	




	Federico Dordoni, P.E.
	Vice President
	DeGolyer and MacNaughton

 
 










			
	DEGOLYER AND MACNAUGHTON	  	

  

 CERTIFICATE of QUALIFICATION 

I, Federico Dordoni, 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 Vice President of DeGolyer and MacNaughton, which firm did prepare the report of third party
addressed to PEP dated April 15, 2020, and that I, as Vice President, was responsible for the preparation of this report of third party. 


  

	 	2.	 That I attended Buenos Aires Institute of Technology (ITBA) University, and that I graduated with a degree in
Petroleum Engineering in the year 2004; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 15 years of experience in oil and gas reservoir
studies and reserves evaluations. 



 

 



 



	
	




	Federico Dordoni, P.E.
	Vice President
	DeGolyer and MacNaughton