EX-10.4



 Exhibit 10.4 (1 of 2) 

 

			
	



		 PRESIDENT - ROBERT C. BARG

 
 VICE
PRESIDENTS
 ALLEN E. EVANS, JR.

RANDOLPH K. GREEN

JOHN G. HATTNER

C. H. (SCOTT) REES III

DANNY S. SIMMONS

DAN PAUL SMITH

THOMAS M. SOUERS


 April 7, 2015 

Ing. Gustavo Hernández García 
 Director de
Pemex-Exploración y Producción 
 Pemex-Exploración y Producción 

Avenida Marina Nacional 329 
 Torre Ejecutiva, Piso 41 

Col. Petróleos Mexicanos, C.P. 11311 
 Del. Miguel Hidalgo,
México, D.F. 
 México 
 Dear Ing.
Hernández: 
 In accordance with your request, we have audited the estimates prepared February 19, 2015, by Pemex-Exploración y
Producción (PEP), as of January 1, 2015, of the gross (100 percent) proved reserves in 29 fields of the Northeastern Marine Region located in the Bay of Campeche, offshore west of the Yucatan Peninsula of Mexico. As a result of Round
Zero during 2014, 11 fields moved from control of PEP to the control of the Mexican State; however, all fields are currently operated by PEP. Based on the Energy Reform of 2014, PEP has represented that it controls 94 percent of the proved reserves
covered by this report in the Northeastern Marine Region, which represents 46 percent of PEP’s total proved reserves in the country. Economic analysis was performed by PEP only to confirm economic producibility and determine economic limits for
the properties. We have examined the estimates with respect to reserves quantities, reserves categorization, and future producing rates, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a).
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 or
about the date of this letter. This report has been prepared for Petróleos Mexicanos’ use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for
such purpose. 
 The following table sets forth PEP’s estimates of the gross (100 percent) reserves, as of January 1, 2015, for the audited
properties: 
  

																					
	 Category
		Gross (100%) Reserves	 
		Crude Oil
(MMBBL)	 		Condensate
(MMBBL)	 		Plant Liquids
(MMBBL)	 		Dry Gas(1)
(MMBOE)	 		BOE
(MMBBL)	 
	 Proved Developed Producing
		 	3,042.8	  		 	33.7	  		 	94.7	  		 	190.8	  		 	3,362.1	  
	 Proved Developed Non-Producing
		 	1,199.5	  		 	14.5	  		 	49.6	  		 	99.9	  		 	1,363.4	  
	 Proved Undeveloped
		 	1,233.0	  		 	5.4	  		 	15.0	  		 	33.0	  		 	1,286.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Proved
		 	5,475.3	  		 	53.6	  		 	159.3	  		 	323.7	  		 	6,011.9	  

  

	(1) 	Dry gas reserves are the dry, sweetened gas available for sale by Pemex-Gas y Petroquímica Básica at the tailgate of the processing plants. 


Crude 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. 
  

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








 



 
  
 When compared on a field-by-field basis, some of the
estimates of PEP are greater and some are less than the estimates of Netherland, Sewell International, S. de R.L. de C.V. (NSI). However, in our opinion the estimates of gross (100 percent) proved reserves prepared by PEP shown herein are, in the
aggregate, reasonable 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, 2015, 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 may 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 based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014.
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. Operating costs used by PEP are based on historical operating expense records. These costs include district and regional overhead expenses along with costs incurred at the field level. Operating costs have been divided into
per-well costs, per-unit-of-production costs, and field-level costs. No headquarters general and administrative overhead expenses of PEP or Petróleos Mexicanos 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; these estimates do not include any salvage value for the lease and well equipment. 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 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 Northeastern Marine Region. 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. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily
resolved our questions relating thereto or had independently verified such information or data. 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. Randolph K. Green, a Licensed Professional Engineer in the State of Texas, has been practicing consulting
petroleum engineering at NSAI since 1983. John G. Hattner, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has 11 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 2) 

 

			
	



		 PRESIDENT - ROBERT C. BARG

 
 VICE
PRESIDENTS
 ALLEN E. EVANS, JR.

RANDOLPH K. GREEN

JOHN G. HATTNER

C. H. (SCOTT) REES III

DANNY S. SIMMONS

DAN PAUL SMITH

THOMAS M. SOUERS


 April 2, 2015 

Ing. Gustavo Hernández García 
 Director de
Pemex-Exploración y Producción 
 Pemex-Exploración y Producción 

Avenida Marina Nacional 329 
 Torre Ejecutiva, Piso 41 

Col. Petróleos Mexicanos, C.P. 11311 
 Del. Miguel Hidalgo,
México, D.F. 
 México 
 Dear Ing.
Hernández: 
 In accordance with your request, we have audited the estimates prepared February 26, 2015, by Pemex-Exploración y
Producción (PEP), as of January 1, 2015, of the gross (100 percent) proved reserves in 110 fields of the Southern Region located in the states of Chiapas, Tabasco, and Veracruz, Mexico. As a result of Round Zero during 2014, 68 fields
moved from control of PEP to the control of the Mexican State; however, all fields are currently operated by PEP. Based on the Energy Reform of 2014, PEP has represented that it controls 99 percent of the proved reserves covered by this report in
the Southern Region, which represents 26 percent of PEP’s total proved reserves in the country. Economic analysis was performed by PEP only to confirm economic producibility and determine economic limits for the properties. We have examined the
estimates with respect to reserves quantities, reserves categorization, and future producing rates, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). 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 or about the date of this letter. This
report has been prepared for Petróleos Mexicanos’ use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. 

The following table sets forth PEP’s estimates of the gross (100 percent) reserves, as of January 1, 2015, for the audited properties: 

 

																					
	 Category
		Gross (100%) Reserves	 
		Crude Oil
(MMBBL)	 		Condensate
(MMBBL)	 		Plant Liquids
(MMBBL)	 		Dry Gas(1)
(MMBOE)	 		BOE
(MMBBL)	 
	 Proved Developed Producing
		 	493.1	  		 	21.5	  		 	180.8	  		 	309.3	  		 	1,004.7	  
	 Proved Developed Non-Producing
		 	568.9	  		 	14.8	  		 	95.9	  		 	167.3	  		 	847.0	  
	 Proved Undeveloped
		 	871.0	  		 	35.0	  		 	186.3	  		 	314.0	  		 	1,406.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Proved
		 	1,933.0	  		 	71.3	  		 	463.1	  		 	790.7	  		 	3,258.0	  

 Totals may not add because of rounding. 
  

	(1) 	Dry gas reserves are the dry, sweetened gas available for sale by Pemex-Gas y Petroquímica Básica at the tailgate of the processing plants. 


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







 



 
  
 Crude 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
Netherland, Sewell International, S. de R.L. de C.V. (NSI). However, in our opinion the estimates of gross (100 percent) proved reserves prepared by PEP shown herein are, in the aggregate, reasonable 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, 2015, 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 may 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 based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. 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. Operating costs used by PEP are
based on historical operating expense records. These costs include district and regional overhead expenses along with costs incurred at the field level. Operating costs have been divided into per-well costs, per-unit-of-production costs, and
field-level costs. No headquarters general and administrative overhead expenses of PEP or Petróleos Mexicanos 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. Operating costs and capital costs are not escalated for inflation. Estimates do not include any salvage value for the lease and well equipment or the cost
of abandoning the properties. 
 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 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 major properties making up approximately 89 percent of the company’s total proved reserves in the Southern Region. 







 



 
  
 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. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not
rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. 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.
Thomas M. Souers, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1991 and has over 14 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 over 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