Document:

EX-10.3

 Exhibit 10.3 

(Part 1 of 2) 
  

 
 April 28, 2020 

Ing. Octavio Romero Oropeza 
 Director General 

Petróleos Mexicanos 
 Avenida Marina Nacional No. 329

 Torre Ejecutiva, Piso 44 
 Colonia Verónica Anzures

 Alcaldía Miguel Hidalgo 
 11300 Ciudad de
México, México 
 Dear Ing. Octavio Romero Oropeza: 

We hereby consent to all references to our firm as set forth in the Annual Report on Form 20-F of Petróleos
Mexicanos (“Pemex”) for the year ending December 31, 2019 (the “Form 20-F”), under the headings “Presentation of Information Concerning Reserves”, “Item 4. Information
on the Company – Infrastructure of PEMEX – Exploration and Production – Reserves”, and “Item 19. Exhibits. Documents filed as exhibits to this Form 20-F”, and to the filing of our
audit letter dated April 15, 2020, as an exhibit to the Form 20-F. We have audited the estimates of Pemex’s proved oil, condensate, natural gas, and oil equivalent reserves, as of January 1,
2020, for 18 fields located in the Cantarell and Ku-Maloob-Zaap business units in the Marine regions of Mexico. These estimates were prepared by Pemex Exploración y Producción in accordance with the reserves definitions of Regulation S-X Rule 4-10(a) of the U.S. Securities and Exchange Commission. 
  

			
	Sincerely,
	
	NETHERLAND, SEWELL INTERNATIONAL, S. DE R.L. DE C.V.
		
	By:	 	

		 	Robert C. Barg, P.E.
		 	President

 RCB:LMS 
  

 

 Exhibit 10.3 

(Part 2 of 2) 
  

 
  
  

 April 28, 2020 

Ing. Octavio Romero Oropeza 
 Director General 

Petróleos Mexicanos 
 Avenida Marina Nacional No. 329

 Torre Ejecutiva, Piso 44 
 Colonia Verónica Anzures

 Alcaldía Miguel Hidalgo 
 11300 Ciudad de
México, México 
 Dear Ing. Octavio Romero Oropeza: 

We hereby consent to all references to our firm as set forth in the Annual Report on Form 20-F of Petróleos
Mexicanos (“Pemex”) for the year ending December 31, 2019 (the “Form 20-F”), under the headings “Presentation of Information Concerning Reserves”, “Item 4. Information
on the Company – Infrastructure of PEMEX – Exploration and Production – Reserves”, and “Item 19. Exhibits. Documents filed as exhibits to this Form 20-F”, and to the filing of our
audit letter dated April 15, 2020, as an exhibit to the Form 20-F. We have audited the estimates of Pemex’s proved oil, condensate, natural gas, and oil equivalent reserves, as of January 1,
2020, for 46 fields located in the Cinco Presidentes and Macuspana-Muspac business units in the Southern region of Mexico. These estimates were prepared by Pemex Exploración y Producción in accordance with the reserves definitions of
Regulation S-X Rule 4-10(a) of the U.S. Securities and Exchange Commission. 
  

			
	Sincerely,
	
	NETHERLAND, SEWELL INTERNATIONAL, S. DE R.L. DE C.V.
		
	By:	 	

		 	Robert C. Barg, P.E.
		 	President

 RCB:LMSEX-10.4

 Exhibit 10.4 

(Part 1 of 2) 
  

			
	

	  	 PRESIDENT - ROBERT C. BARG

 
 VICE
PRESIDENTS
 RANDOLPH K. GREEN

JOHN G. HATTNER

MICHELLE F. HERRERA 

C. H. (SCOTT) REES III

DANNY D. SIMMONS

ERIC J. STEVENS

JOSEPH M. WOLFE

 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: 
 In accordance with your request, we have audited the estimates prepared by Pemex Exploración y Producción (PEP), as of
January 1, 2020, of the gross (100 percent) proved reserves and the net gas reserves in 18 fields located in Activo Integral de Producción Bloques (AIPB) AS01-01 (Cantarell) and AS01-02 (Ku-Maloob-Zaap), in Subdirección AS01 (Región Marina Noreste), located in the Bay of Campeche, offshore west of the Yucatan Peninsula of Mexico. PEP is
a subsidiary entity of Petróleos Mexicanos. The scope of our work did not include auditing the future net revenue associated with these reserves. The Political Constitution of the United Mexican States provides that the Mexican nation owns
all petroleum and other hydrocarbon reserves for these fields; however, these fields have been assigned to and are currently operated by PEP. In accordance with the Energy Reform of 2014, the estimates in this report represent the gross (100
percent) proved reserves to be produced within the economic life of the properties. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, and economic producibility, using the
definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). Economic analysis was performed by PEP only to confirm economic
producibility and determine economic limits for the properties. The estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC and conform to the FASB Accounting Standards Codification Topic 932,
Extractive Activities—Oil and Gas. We completed our audit on February 14, 2020. PEP has represented that these properties account for 54.2 percent on a net oil equivalent barrel basis of PEP’s net proved reserves as of
January 1, 2020. This report has been prepared for PEP’s and Petróleos Mexicanos’ use internally and in filings with the appropriate regulatory agencies. In our opinion the assumptions, data, methods, and procedures used in the
preparation of this report are appropriate for such purpose; there is no guarantee or warranty, implied or expressed, by Netherland, Sewell International, S. de R.L. de C.V. (NSI) for any other use of this report. 

  
 2100 Ross
AVENUE, SUITE 2200 • DALLAS, TEXAS 75201-2737 • PH: 214-969-5401 •
FAX: 214-969-5411 

 

 
  
 The following table sets forth PEP’s estimates
of the gross (100 percent) reserves and the net gas reserves to the combined interest of PEP, the Mexican State, and Pemex Transformación Industrial (PTRI), as of January 1, 2020, for the audited properties: 

 

																													
	 	  	Gross (100%) Reserves	 
	 	  	 	 	  	Liquid Components and Dry Gas	 	  	 	 	  	 	 	  	 	 
	 Category
	  	Wellhead
Oil(1)
(MMBBL)	 	  	Condensate(2)
(MMBBL)	 	  	Plant
Liquids(3)
(MMBBL)	 	  	Dry
Gas(4)
(MMBOE)	 	  	BOE(5)
(MMBBL)	 	  	Wellhead
Gas(6)
(BCF)	 	  	Net Gas(7)
(BCF)	 
	 Proved Developed Producing
	  	 	1,163.7	 	  	 	3.2	 	  	 	40.7	 	  	 	66.5	 	  	 	1,274.2	 	  	 	574.6	 	  	 	455.9	 
	 Proved Developed Non-Producing
	  	 	1,169.3	 	  	 	3.0	 	  	 	63.7	 	  	 	104.1	 	  	 	1,340.2	 	  	 	938.4	 	  	 	713.4	 
	 Proved Undeveloped
	  	 	1,231.3	 	  	 	1.8	 	  	 	18.0	 	  	 	29.5	 	  	 	1,280.6	 	  	 	257.2	 	  	 	202.0	 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Proved
	  	 	3,564.3	 	  	 	8.0	 	  	 	122.5	 	  	 	200.2	 	  	 	3,895.0	 	  	 	1,770.2	 	  	 	1,371.3	 

 Totals may not add because of rounding. 
  

	(1) 	 Oil reserves include oil plus liquids from the produced gas stream separated in the field.

	(2) 	 Condensate reserves are the liquids volumes recovered from the produced gas stream during the compression and
dehydration stages of processing. 

	(3) 	 Plant liquids reserves are the liquids volumes recovered from the gas stream through the processing plants.

	(4) 	 Dry gas reserves are the dry gas volumes available for sale by PTRI at the tailgate of the processing plants.

	(5) 	 BOE includes wellhead oil, condensate, plant liquids, and dry gas. 

	(6) 	 Gas reserves are the measured wellhead gas before shrinkage from fuel usage, flare, and processing.

	(7) 	 Net gas reserves are the volume of wet gas available for sale to PTRI at the inlet of the processing plants.

 Oil, condensate, plant liquids, and barrels of oil equivalent (BOE) volumes are expressed in millions of barrels (MMBBL); a barrel is
equivalent to 42 United States gallons. Dry gas volumes are expressed in millions of barrels of oil equivalent (MMBOE), determined using dry gas conversion factors provided by PEP. Gas volumes are expressed in billions of cubic feet (BCF) at
standard temperature and pressure bases. 
 When compared on a
field-by-field basis, some of the estimates of PEP are greater and some are less than the estimates of NSI. However, in our opinion the estimates of reserves prepared by
PEP shown herein are reasonable when aggregated at the total proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum
Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by PEP in preparing the January 1,
2020, estimates of reserves, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by PEP. 

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of
reserves included herein have not been adjusted for risk. PEP’s estimates do not include probable or possible reserves that exist for these properties. 

Oil and gas prices were used only to confirm economic producibility and determine economic limits for the properties. It is our understanding that prices used
by PEP are representative of the 12-month average for the period January through December 2019. NSI accepted the prices provided without independent review or verification. All prices are held constant
throughout the lives of the properties. 
 Costs were used only to confirm economic producibility and determine economic limits for the properties. It is
our understanding that operating costs used by PEP are representative of the 12-month average for the period January through December 2019. These costs include district and regional overhead expenses along
with costs to be incurred at the field level. Operating costs for certain non-producing or undeveloped fields are based on PEP’s analogy to a similar type of producing field. Operating costs have been
divided into field-level costs, per-well costs, and per-unit-of-production costs. No
headquarters general and administrative overhead expenses are included. Capital costs used by PEP are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new
development wells, pipelines, and production equipment. Abandonment costs used are PEP’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. NSI accepted the operating cost parameters and
the capital and abandonment costs provided without independent review or verification. Operating, capital, and abandonment costs are not escalated for inflation. 
  

 

 
  

 The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved
reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are
sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary
economic assumptions discussed herein, estimates of PEP and NSI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by PEP, that the
properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of PEP to produce and recover the reserves, and that projections of future production will prove
consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts used to confirm economic producibility and determine economic limits for the
properties. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

 It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily
of substantive testing, wherein we conducted a detailed review of all properties making up the total proved reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by
PEP with respect to oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. Our audit did not
include a review of PEP’s overall reserves management processes and practices. 
 We used standard engineering and geoscience methods, or a combination
of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there
are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. 

Supporting data documenting this audit, along with data provided by PEP, are on file in our office. The technical persons primarily responsible for conducting
this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Eric J. Stevens, a Licensed Professional Engineer in the State of Texas, has been practicing consulting
petroleum engineering at Netherland, Sewell & Associates, Inc. (NSAI), of which NSI is a subsidiary, since 2007 and has 5 years of prior industry experience. Ruurdjan (Rudi) de Zoeten, a Licensed Professional Geoscientist in the State of
Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has 18 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these
properties nor are we employed on a contingent basis. 

 

 
  

 
					
	Sincerely,	 	
		
	NETHERLAND, SEWELL INTERNATIONAL, S. DE R.L. DE C.V.	 	
			
	By:	 	

	 	        
		 	Robert C. Barg, P.E.	 	
		 	President	 	

  

													
	  
 By:
	 	 

 
	 	

	 	  
       By:
	 		 	 

	 	

		 	 Eric J. Stevens, P.E. 102415
 Vice
President
	 		 		 	 Ruurdjan (Rudi) de Zoeten, P.G. 3179

Geoscientist

				
	Date Signed: April 15, 2020	 		 	      Date Signed: April 15, 2020	 	
							
	EJS:LMS	 		 		 		 		 		 	

 Exhibit 10.4 

(Part 2 of 2) 
  

			
	 

	 	 PRESIDENT - ROBERT C. BARG

 
 VICE
PRESIDENTS
 RANDOLPH K. GREEN

JOHN G. HATTNER

MICHELLE F. HERRERA

		 	C. H. (SCOTT) REES III
		 	DANNY D. SIMMONS
		 	ERIC J. STEVENS
		 	JOSEPH M. WOLFE

 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: 
 In accordance with your request, we have audited the estimates prepared by Pemex Exploración y Producción (PEP), as of
January 1, 2020, of the gross (100 percent) proved reserves and the net gas reserves in 46 fields located in Activo Integral de Producción Bloques (AIPB) S01 (Macuspana-Muspac) and S04 (Cinco Presidentes), in Subdirección de
Producción Bloques Sur, located in the states of Chiapas, Tabasco, and Veracruz in southern Mexico. PEP is a subsidiary entity of Petróleos Mexicanos. The scope of our work did not include auditing the future net revenue associated
with these reserves. The Political Constitution of the United Mexican States provides that the Mexican nation owns all petroleum and other hydrocarbon reserves for these fields; however, these fields have been assigned to and are currently operated
by PEP. In accordance with the Energy Reform of 2014, the estimates in this report represent the gross (100 percent) proved reserves to be produced within the economic life of the properties. We have examined the estimates with respect to reserves
quantities, reserves categorization, future producing rates, and economic producibility, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). Economic analysis was performed by PEP only to confirm economic producibility and determine economic limits for the properties. The estimates of reserves have been prepared in accordance with the
definitions and regulations of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on February 14, 2020. PEP has represented that these properties account
for 3.5 percent on a net oil equivalent barrel basis of PEP’s net proved reserves as of January 1, 2020. This report has been prepared for PEP’s and Petróleos Mexicanos’ use internally and in filings with the
appropriate regulatory agencies. In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose; there is no guarantee or warranty, implied or expressed, by Netherland, Sewell
International, S. de R.L. de C.V. (NSI) for any other use of this report. 

  
 2100 ROSS
AVENUE, SUITE 2200 • DALLAS, TEXAS 75201-2737 • PH: 214-969-5401 • FAX: 214-969-5411 

 

 
  
 The following table sets forth PEP’s estimates
of the gross (100 percent) reserves and the net gas reserves to the combined interest of PEP, the Mexican State, and Pemex Transformación Industrial (PTRI), as of January 1, 2020, for the audited properties: 

 

																													
	 Category
	  	Gross (100%) Reserves	 	  	Net Gas(7)
(BCF)	 
	  	Wellhead
Oil(1)
(MMBBL)	 	  	Liquid Components and Dry Gas	 	  	BOE(5)
(MMBBL)	 	  	Wellhead
Gas(6)
(BCF)	 
	  	Condensate(2)
(MMBBL)	 	  	Plant
Liquids(3)
(MMBBL)	 	  	Dry
Gas(4)
(MMBOE)	 
	 Proved Developed Producing
	  	 	60.9	 	  	 	0.8	 	  	 	25.4	 	  	 	56.1	 	  	 	143.2	 	  	 	387.4	 	  	 	292.0	 
	 Proved Developed Non-Producing
	  	 	41.7	 	  	 	0.3	 	  	 	7.4	 	  	 	16.4	 	  	 	65.8	 	  	 	142.8	 	  	 	85.1	 
	 Proved Undeveloped
	  	 	23.3	 	  	 	0.1	 	  	 	5.3	 	  	 	10.9	 	  	 	39.7	 	  	 	82.5	 	  	 	56.9	 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Proved
	  	 	125.9	 	  	 	1.2	 	  	 	38.2	 	  	 	83.4	 	  	 	248.7	 	  	 	612.7	 	  	 	433.9	 

 Totals may not add because of rounding. 
  

	(1) 	 Oil reserves include oil plus liquids from the produced gas stream separated in the field.

	(2) 	 Condensate reserves are the liquids volumes recovered from the produced gas stream during the compression and
dehydration stages of processing. 

	(3) 	 Plant liquids reserves are the liquids volumes recovered from the gas stream through the processing plants.

	(4) 	 Dry gas reserves are the dry gas volumes available for sale by PTRI at the tailgate of the processing plants.

	(5) 	 BOE includes wellhead oil, condensate, plant liquids, and dry gas. 

	(6) 	 Gas reserves are the measured wellhead gas before shrinkage from fuel usage, flare, and processing.

	(7) 	 Net gas reserves are the volume of wet gas available for sale to PTRI at the inlet of the processing plants.

 Oil, condensate, plant liquids, and barrels of oil equivalent (BOE) volumes are expressed in millions of barrels (MMBBL); a barrel is
equivalent to 42 United States gallons. Dry gas volumes are expressed in millions of barrels of oil equivalent (MMBOE), determined using dry gas conversion factors provided by PEP. Gas volumes are expressed in billions of cubic feet (BCF) at
standard temperature and pressure bases. 
 When compared on a
field-by-field basis, some of the estimates of PEP are greater and some are less than the estimates of NSI. However, in our opinion the estimates of reserves prepared by
PEP shown herein are reasonable when aggregated at the total proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum
Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by PEP in preparing the January 1,
2020, estimates of reserves, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by PEP. 

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of
reserves included herein have not been adjusted for risk. PEP’s estimates do not include probable or possible reserves that exist for these properties. 

Oil and gas prices were used only to confirm economic producibility and determine economic limits for the properties. It is our understanding that prices used
by PEP are representative of the 12-month average for the period January through December 2019. NSI accepted the prices provided without independent review or verification. All prices are held constant
throughout the lives of the properties. 
 Costs were used only to confirm economic producibility and determine economic limits for the properties. It is
our understanding that operating costs used by PEP are representative of the 12-month average for the period January through December 2019. These costs include district and regional overhead expenses along
with costs to be incurred at the field level. Operating costs for certain non-producing or undeveloped fields are based on PEP’s analogy to a similar type of producing field. Operating costs have been
divided into field-level costs, per-well costs, and per-unit-of-production costs. No
headquarters general and administrative overhead expenses are included. Capital costs used by PEP are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new
development wells, pipelines, and production equipment. Abandonment costs used are PEP’s estimates of the costs to abandon the wells and production facilities, net of any salvage value. NSI accepted the operating cost parameters and the capital
and abandonment costs provided without independent review or verification. Operating, capital, and abandonment costs are not escalated for inflation. 
  

 

 
  

 The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved
reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are
sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary
economic assumptions discussed herein, estimates of PEP and NSI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by PEP, that the
properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of PEP to produce and recover the reserves, and that projections of future production will prove
consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts used to confirm economic producibility and determine economic limits for the
properties. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

 It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily
of substantive testing, wherein we conducted a detailed review of all properties making up the total proved reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by
PEP with respect to oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. Our audit did not
include a review of PEP’s overall reserves management processes and practices. 
 We used standard engineering and geoscience methods, or a combination
of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties
inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. 

Supporting data documenting this audit, along with data provided by PEP, are on file in our office. The technical persons primarily responsible for conducting
this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Joseph M. Wolfe, a Licensed Professional Engineer in the State of Texas, has been practicing consulting
petroleum engineering at Netherland, Sewell & Associates, Inc. (NSAI), of which NSI is a subsidiary, since 2013 and has 5 years of prior industry experience. Dana D. Coryell, a Licensed Professional Geoscientist in the State of Texas, has
been practicing consulting petroleum geoscience at NSAI since 1999 and has 12 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties
nor are we employed on a contingent basis. 
  

 

 
  

 
			
	Sincerely,
	
	 NETHERLAND, SEWELL INTERNATIONAL, S. DE R.L. DE C.V.

		
	By:	 	 

		 	Robert C. Barg, P.E.
		 	President

  

													
	  
 By:
	 	

	 	 

	 		 	  
       By:
	 	

	 	 

		 	 Joseph M. Wolfe, P.E. 116170

Vice President
	 		 		 	 Dana D. Coryell, P.G. 10566

Geoscientist

					
	Date Signed: April 15, 2020	 		 		 	      Date Signed: April 15, 2020	 	
							
	JMW:MR

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