EX-10.4



 Exhibit 10.4 (1 of 3) 
  

			
	



	  	 PRESIDENT - ROBERT C. BARG

 
 VICE PRESIDENTS

ALLEN E. EVANS, JR. 

RANDOLPH K. GREEN 

JOHN G. HATTNER 
 C. H.
(SCOTT) REES III
 DANNY D. SIMMONS 

DAN PAUL SMITH 

THOMAS M. SOUERS


 April 17, 2017 
  

Ing. J. Javier Hinojosa Puebla 
 Director General 

Pemex Exploración y Producción 
 Avenida Marina Nacional 329 

Torre Ejecutiva, Piso 41 
 Col. Verónica Anzures, C.P. 11300 

Del. Miguel Hidalgo, Ciudad de México 
 México 

Dear Ing. Hinojosa: 
 In accordance with your
request, we have audited the estimates prepared by Pemex Exploración y Producción (PEP), as of January 1, 2017, of the gross (100 percent) proved reserves in 72 fields located in the Poza Rica-Altamira District, 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 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 27, 2017. 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. 

The following table sets forth PEP’s estimates of the gross (100 percent) reserves, as of January 1, 2017, for the audited Poza Rica-Altamira
District properties: 
  

																					
	 	 	Gross (100%) Reserves	 
	 Category
	 	Oil(1)
(MMBBL)	 	 	  Condensate(2)  
(MMBBL)	 	 	  Plant Liquids  
(MMBBL)	 	 	Dry Gas(3)
    (MMBOE)    	 	 	BOE
 (MMBBL) 	 
						
	 Proved Developed Producing
	 	 	112.6	 	 	 	0.0	 	 	 	1.9	 	 	 	15.7	 	 	 	130.2	 
	 Proved Developed Non-Producing
	 	 	26.9	 	 	 	0.0	 	 	 	0.6	 	 	 	3.3	 	 	 	30.8	 
	 Proved Undeveloped
	 	 	87.6	 	 	 	0.0	 	 	 	1.7	 	 	 	11.4	 	 	 	100.7	 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
						
	 Total Proved
	 	 	227.1	 	 	 	0.0	 	 	 	4.2	 	 	 	30.4	 	 	 	261.7	 

 
  

	(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) 	 Dry gas reserves are the dry, sweetened gas available for sale by Pemex Transformación Industrial at the tailgate
of the processing plants. 



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










			
	 




  
	  	
	  	

  

 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. 

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, 2017, 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. 
 The estimates shown herein are for proved reserves. PEP’s estimates do not include probable or possible
reserves that exist for these properties. 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. 
 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 2016. 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 2016. These costs include district and
regional overhead expenses along with costs to be incurred at the field level. Operating costs for certain 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, 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, 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. 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. Michelle F. Herrera, a Licensed Professional Geoscientist in the State
of Texas, has been practicing consulting petroleum geoscience at NSAI since 2013 and has 10 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

  
 



 







 Exhibit 10.4 (2 of 3) 
  

			
	



	  	 PRESIDENT - ROBERT C. BARG 

 
 VICE PRESIDENTS 

ALLEN E. EVANS, JR. 

RANDOLPH K. GREEN 

JOHN G. HATTNER 
 C. H.
(SCOTT) REES III
 DANNY D. SIMMONS 

DAN PAUL SMITH 

THOMAS M. SOUERS


 April 17, 2017 
  

Ing. J. Javier Hinojosa Puebla 
 Director General 

Pemex Exploración y Producción 
 Avenida Marina Nacional 329 

Torre Ejecutiva, Piso 41 
 Col. Verónica Anzures, C.P. 11300 

Del. Miguel Hidalgo, Ciudad de México 
 México 

Dear Ing. Hinojosa: 
 In accordance with your
request, we have audited the estimates prepared by Pemex Exploración y Producción (PEP), as of January 1, 2017, of the gross (100 percent) proved reserves in 26 fields located in the Litoral de Tabasco District, 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 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 27, 2017. 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. 

The following table sets forth PEP’s estimates of the gross (100 percent) reserves, as of January 1, 2017, for the audited Litoral de Tabasco
District properties: 
  

																					
	 	  	Gross (100%) Reserves	 
	 Category
	  	Oil(1)
 (MMBBL) 	 	  	  Condensate(2)  
(MMBBL)	 	  	  Plant Liquids  
(MMBBL)	 	  	    Dry Gas(3)    
(MMBOE)	 	  	BOE
 (MMBBL) 	 
						
	 Proved Developed Producing
	  	 	214.3	 	  	 	10.6	 	  	 	56.4	 	  	 	93.2	 	  	 	374.5	 
	 Proved Developed Non-Producing
	  	 	14.6	 	  	 	0.2	 	  	 	2.0	 	  	 	3.3	 	  	 	20.1	 
	 Proved Undeveloped
	  	 	282.3	 	  	 	4.6	 	  	 	16.2	 	  	 	88.9	 	  	 	392.0	 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
						
	 Total Proved
	  	 	511.2	 	  	 	15.5	 	  	 	74.6	 	  	 	185.4	 	  	 	786.6	 

 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) 	 Dry gas reserves are the dry, sweetened gas available for sale by Pemex Transformación Industrial at the tailgate
of the processing plants. 



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










			
	 




  
	  	
	  	

  

 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. 

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, 2017, 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. 
 The estimates shown herein are for proved reserves. PEP’s estimates do not include probable or possible
reserves that exist for these properties. 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. 
 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 2016. 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 2016. These costs include district and
regional overhead expenses along with costs to be incurred at the field level. Operating costs for certain 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, 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. Andres F. Castaño, 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 8 years of prior industry experience. Allen E. Evans, Jr., a Licensed Professional Geoscientist in
the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1996 and has 13 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

  
 



 







 Exhibit 10.4 (3.3) 
  

			
	



	  	 PRESIDENT - ROBERT C. BARG

 
 VICE PRESIDENTS

ALLEN E. EVANS, JR.

RANDOLPH K. GREEN

JOHN G. HATTNER
 C.H.
(SCOTT) REES III
 DANNY D. SIMMONS

DAN PAUL SMITH

THOMAS M. SOUERS


 April 17, 2017 
  

Ing. J. Javier Hinojosa Puebla 
 Director General 

Pemex Exploración y Producción 
 Avenida Marina Nacional 329 

Torre Ejecutiva, Piso 41 
 Col. Verónica Anzures, C.P. 11300 

Del. Miguel Hidalgo, Ciudad de México 
 México 

Dear Ing. Hinojosa: 
 In accordance with your
request, we have audited the estimates prepared by Pemex Exploración y Producción (PEP), as of January 1, 2017, of the gross (100 percent) proved reserves in 27 fields located in the Aceite Terciario del Golfo District, Veracruz,
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 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. Without considering (1) the accelerated development pace and (2) the inclusion of proved undeveloped locations drilled beyond 5 years of their original booking date, 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. These considerations are discussed in a subsequent paragraph of this
letter. We completed our audit on February 27, 2017. 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.

 The following table sets forth PEP’s estimates of the gross (100 percent) reserves, as of January 1, 2017, for the audited Aceite
Terciario del Golfo District properties: 
  

																					
	 	  	Gross (100%) Reserves	 
	 Category
	  	 Oil(1) 
(MMBBL)	 	  	  Condensate(2)  

(MMBBL)	 	  	  Plant Liquids  
(MMBBL)	 	  	    Dry Gas(3)    
(MMBOE)	 	  	BOE
 (MMBBL) 	 
						
	 Proved Developed Producing
	  	 	26.2	 	  	 	0.0	 	  	 	4.0	 	  	 	9.6	 	  	 	39.7	 
	 Proved Developed Non-Producing
	  	 	67.8	 	  	 	0.0	 	  	 	6.6	 	  	 	15.9	 	  	 	90.3	 
	 Proved Undeveloped
	  	 	419.1	 	  	 	0.0	 	  	 	52.8	 	  	 	128.4	 	  	 	600.4	 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
						
	 Total Proved
	  	 	513.1	 	  	 	0.0	 	  	 	63.3	 	  	 	154.0	 	  	 	730.5	 

  

	(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) 	 Dry gas reserves are the dry, sweetened gas available for sale by Pemex Transformación Industrial at the tailgate
of the processing plants. 



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










			
	 




  
	  	
	  	

  

 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. 

In our opinion, the estimates of proved reserves shown herein have been prepared in accordance with generally accepted petroleum engineering and
evaluation principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards) and, aside from the following considerations, adhere to
the SEC definitions. First, the development plan incorporated in this report represents a more accelerated drilling pace than the recent development drilling. Focused development of the Chicontepec formation began in 2007, and to date, over 4,500
wells have been drilled. Development drilling peaked in 2009 with the drilling of 794 locations; however, in recent years development has slowed, with fewer than 100 wells drilled in 2015 and 2016 combined. Based on discussions with PEP, its
development plan consists of drilling more than 30,000 wells over the next 36 years to develop the Chicontepec formation. PEP has indicated a commitment to develop the Aceite Terciario del Golfo District and plans to drill 500 wells in 2017, ramping
up to a maximum of 1,000 wells per year by 2019. The time period for development of proved reserves locations is restricted to 5 years. Second, it is our understanding that a significant portion of the proved undeveloped reserves are associated with
locations that have been categorized as proved undeveloped for longer than 5 years. 
 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 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, 2017, 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. 

The estimates shown herein are for proved reserves. PEP’s estimates do not include probable or possible reserves that exist for these properties.
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. 

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 2016. 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 2016. These costs include district and regional overhead
expenses along with costs to be incurred at the field level. Operating costs for certain 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, 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. A portion of these reserves are for properties operated by service contractors that are involved
with the investment, planning, and development in accordance with their agreements with PEP. The development plan incorporated in this report was provided by PEP; this development plan may differ from development plans of individual service contract
operators. 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 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. 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. Dana D. Coryell, a Licensed Professional Geoscientist in the State of
Texas, has been practicing consulting petroleum geoscience at NSAI since 1999 and has 15 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