EX-10.4



 Exhibit 10.4 

(Part 1 of 3) 
  





 
 April 24, 2018 

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, 2018, of
the gross (100 percent) proved reserves in portions of 71 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 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. Without considering 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. We completed our audit on February 13, 2018. 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, 2018, 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
	  	 	104.6	 	  	 	0.0	 	  	 	3.5	 	  	 	13.2	 	  	 	121.2	 
	 Proved Developed Non-Producing
	  	 	31.6	 	  	 	0.0	 	  	 	1.4	 	  	 	5.4	 	  	 	38.4	 
	 Proved Undeveloped
	  	 	91.0	 	  	 	0.0	 	  	 	3.2	 	  	 	9.6	 	  	 	103.9	 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Proved
	  	 	227.2	 	  	 	0.0	 	  	 	8.1	 	  	 	28.2	 	  	 	263.5	 

  

	(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. 

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 and adhere to the SEC definitions, except that 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. We are satisfied with the methods and procedures used by PEP in preparing the January 1, 2018, 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 2017. 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 2017. 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
						
	By:	 	



	 		 		  	By:	 	




		 	 Eric J. Stevens, P.E. 102415

Vice President
	 	



	 		  		 	 Michelle F. Herrera, P.G. 11912

Geoscientist
	 	




	  
 Date Signed: April 24, 2018
	 	 		  	  
 Date Signed: April 24, 2018
	 
	  
 EJS:DSS
	 	 		  		 		 








 Exhibit 10.4 

(Part 2 of 3) 
  
 



 
 April 24, 2018 

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, 2018, of
the gross (100 percent) proved reserves in 30 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 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 13, 2018. 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, 2018, for the audited Litoral de Tabasco District properties: 
  

																					
	 	  	Gross (100%) Reserves	 
	 	  	Oil(1) 	 	  	Condensate(2)	 	  	Plant Liquids	 	  	Dry Gas(3) 	 	  	BOE	 
	 Category
	  	(MMBBL)	 	  	(MMBBL)	 	  	(MMBBL)	 	  	(MMBOE)	 	  	(MMBBL)	 
	 Proved Developed Producing
	  	 	205.4	 	  	 	7.9	 	  	 	50.4	 	  	 	79.2	 	  	 	343.0	 
	 Proved Developed Non-Producing
	  	 	4.2	 	  	 	0.0	 	  	 	0.1	 	  	 	0.1	 	  	 	4.4	 
	 Proved Undeveloped
	  	 	346.5	 	  	 	5.4	 	  	 	24.5	 	  	 	100.7	 	  	 	477.1	 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Proved
	  	 	556.1	 	  	 	13.3	 	  	 	75.0	 	  	 	180.0	 	  	 	824.5	 

  

	(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. 

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, 2018, 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 2017. 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 2017. 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	  	
				
	By:	  	



	  	By:	  	 





		  	 Andres F. Castaño, P.E. 121698

Petroleum Engineer
	  	



	  		  	 Allen E. Evans, Jr., P.G. 1286

Vice President
	  	




	Date Signed: April 24, 2018	  	  	Date Signed: April 24, 2018	  
	AFC:LMS	  	  		  		  








 Exhibit 10.4 

(Part 3 of 3) 
  
 



 
 April 24, 2018 

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, 2018, of
the gross (100 percent) proved reserves in portions of 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 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. 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 13, 2018. 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, 2018, for the audited Aceite Terciario del
Golfo District properties: 
  

																					
	 	  	Gross (100%) Reserves	 
	 	  	Oil(1) 	 	  	Condensate(2)	 	  	Plant Liquids	 	  	Dry Gas(3) 	 	  	BOE	 
	 Category
	  	(MMBBL)	 	  	(MMBBL)	 	  	(MMBBL)	 	  	(MMBOE)	 	  	(MMBBL)	 
	 Proved Developed Producing
	  	 	20.3	 	  	 	0.0	 	  	 	3.3	 	  	 	7.9	 	  	 	31.5	 
	 Proved Developed Non-Producing
	  	 	70.8	 	  	 	0.0	 	  	 	6.8	 	  	 	16.4	 	  	 	94.1	 
	 Proved Undeveloped
	  	 	350.7	 	  	 	0.0	 	  	 	41.9	 	  	 	102.0	 	  	 	494.6	 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Proved
	  	 	441.8	 	  	 	0.0	 	  	 	52.0	 	  	 	126.4	 	  	 	620.1	 

  

	(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: 214-963-5411 








 



 
  

 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 these estimates 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 wells; however, in recent years development has slowed, with approximately 100 wells drilled from 2015 through 2017. Based on discussions with PEP, its development plan
consists of drilling more than 33,000 wells over the next 35 years to develop the Chicontepec formation. PEP has indicated a commitment to develop the Aceite Terciario del Golfo District and plans to drill 33 proved undeveloped locations in 2018,
ramping up to a maximum of 999 proved undeveloped locations in 2021. 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, 2018, 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 2017. 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 2017. 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
				
	By:	  	



	  	By:	  	




		  	 Eric J. Stevens, P.E. 102415

Petroleum Engineer
	  	



	  		  	 Dana D. Coryell, P.G. 10566

Geoscientist
	  	




	Date Signed: April 24, 2018	  	  	Date Signed: April 24, 2018	  
	JMW:ARC