EX-10.6



 Exhibit 10.6 (1 of 2) 

DEGOLYER AND MACNAUGHTON 

5001 SPRING VALLEY ROAD 

SUITE 800 EAST 

DALLAS, TEXAS 75244 
  

 
  
  

This is a digital representation of a DeGolyer and MacNaughton report. 

This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same
conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information. 

 
  
  

 
 



 







 


      

  





       

DEGOLYER AND MACNAUGHTON 

5001 SPRING VALLEY ROAD 

SUITE 800 EAST 

DALLAS, TEXAS 75244 

April 29, 2016 
  

Mr. J. Javier Hinojosa Puebla 

Director Ejecutivo 

PEMEX Exploración y Producción 

Avenida Marina Nacional No. 329 

Torre Ejecutiva 

Colonia Verónica Anzures 

11300 Ciudad de México, México 

Dear Mr. Hinojosa Puebla: 

Pursuant to your request, we have conducted a reserves audit of the net proved oil, gas, condensate, and oil
equivalent reserves, as of January 1, 2016, of certain properties that PEMEX Exploración y Producción (PEP) has represented are owned by the United Mexican States in the Burgos area of Mexico. This audit was completed on
April 29, 2016. PEP has represented that these properties account for 2.2 percent on a net oil equivalent barrel basis of the net proved reserves assigned to PEP, as of January 1, 2016, and that the net proved reserves estimates have been
prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. At the request of PEP, we have also included in this report
estimates prepared by PEP of its natural gas liquids (NGL) reserves; however, PEP has represented that PEP’s management of the properties stops at the inlet of the gas processing plants. PEP has represented that all subsurface hydrocarbons
belong to the United Mexican States, and has further represented that PEP has received a 100-percent assignment in these properties by the United Mexican States; therefore, gross reserves are equal to net reserves and are defined as the total
estimated petroleum to be produced from these properties after December 31, 2015. We have reviewed information provided to us by PEP that it represents to be PEP’s estimates of the net reserves, as of January 1, 2016, for the same
properties as those which we audited. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by PEP.


 








 


      

  







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 Based on Mexico’s Energy Reform of 2014, PEP has
represented that its estimates of the net proved reserves assigned to PEP presented in this report correspond to 92.3 percent of the total net proved reserves of the Burgos area assigned to PEP, on an oil equivalent basis. 

Reserves estimates included herein are expressed as net reserves as represented by PEP. Gross reserves are
defined as the total estimated petroleum to be produced from these properties after December 31, 2015. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by the United Mexican States after
deducting all interests owned by others. 
 Estimates of oil, gas, condensate, NGL, and oil equivalent
reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates
are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. 

Data used in this audit were obtained from reviews with PEP personnel, from PEP files, from records on file
with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by PEP with respect to property interests, production from such
properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field
examination of the properties was not considered necessary for the purposes of this report. 
 Methodology and Procedures 

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation
principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing
of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and
completeness of basic data, and production history. 

 








 


      

  







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 Based on the current stage of field development, production
performance, the development plans provided by PEP, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. 

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

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery
factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering
methods were used to estimate recovery factors. In such cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. 

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate
trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of
economic production or to the limit of the production licenses as appropriate. 
 Gas quantities estimated
herein are expressed as marketable gas and sales gas at a temperature base of 20 degrees Celsius (°C) and at a pressure base of 1 atmosphere. Marketable gas is defined as the total gas in the reservoirs to be produced after shrinkage
resulting from field separation and flare. Marketable gas includes fuel. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for injection, fuel usage, flare, and shrinkage
resulting from field separation and plant processing. Oil, condensate, and NGL reserves estimated herein are expressed in terms of 42 United States gallons per barrel. Oil and condensate reserves estimated herein are to be recovered by


 








 


      

  







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 normal field separation. PEP has represented that its NGL reserves have been
estimated on the basis of the quantities of liquids recovered from gas delivered to a gas plant for processing, and can include propane, butane, and C5+ fractions. 

Definition of Reserves 

Petroleum reserves estimated by PEP included in this report are classified as proved. Only proved reserves
have been evaluated for this report. Reserves classifications used by PEP in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be
economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of
production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration
of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: 

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and
government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the
estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. 

(i) The area of the reservoir considered as proved includes: 

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent
undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.


 








 


      

  







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 (ii) In the absence of data on fluid contacts, proved
quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and
the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with
reasonable certainty. 
 (iv) Reserves which can be produced economically through application of improved
recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable
than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or
program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir
is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month
within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 

 








 


      

  







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 Developed oil and gas reserves – Developed oil and
gas reserves are reserves of any category that can be expected to be recovered: 
 (i) Through existing
wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves
estimate if the extraction is by means not involving a well. 
 Undeveloped oil and gas reserves
– Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas
that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has
been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for
which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10
(a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. 

 








 


      

  







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 Primary Economic Assumptions 

The following economic assumptions were used for estimating existing and future prices and costs, expressed
in United States dollars (U.S.$): 
 Oil and Condensate Prices 

PEP has represented that the oil and condensate prices were based on a reference price, calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The average adjusted product price for all
fields was U.S.$45.48 per barrel, except for the Miahuapán field, which was U.S.$53.64 per barrel, and the prices were held constant thereafter. These prices were not escalated for inflation. 

Gas Prices 

PEP has represented that the gas prices were based on a 12 month average price, calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Each field’s calorific value, which
includes NGL, was used to determine each field’s gas price. The contract prices for the fields audited in this report varied between U.S.$2.36 and U.S.$4.87 per thousand cubic feet. These prices were not escalated for inflation. 

Operating Expenses, Capital Costs, and Abandonment Costs 

Operating expenses and capital costs, based on information provided by PEP, were used in estimating future
costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.
Abandonment costs were provided by PEP. 

 








 


      

  







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 While the oil and gas industry may be subject to regulatory
changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2016, estimated oil,
gas, condensate, and NGL reserves. 
 PEP has represented that its estimated net proved reserves
attributable to the reviewed properties are based on the definition of proved reserves of the SEC. PEP represents that its estimates of the net proved reserves attributable to these properties, which represent 2.2 percent of PEP’s reserves on a
net oil equivalent basis, are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe): 
  

																									
	 	 	Estimated by PEP
Net Proved Reserves
as of
January 1, 2016	 
	 	 	Oil
 (MMbbl) 	 	 	Marketable
Gas
(Bcf)	 	 	    Sales    
Gas
(Bcf)	 	 	Condensate
(MMbbl)	 	 	NGL
 (MMbbl) 	 	 	Oil
  Equivalent  
(MMboe)	 
	 Properties Reviewed by DeGolyer and MacNaughton
	 				 				 				 				 				 			
	 Burgos Area
	 				 				 				 				 				 			
							
	 Total Proved
	 	 	4.0	  	 	 	1,020.3	  	 	 	910.6	  	 	 	12.6	  	 	 	18.8	  	 	 	210.5	  

 Notes: 

1. Oil equivalent is calculated based on oil, marketable gas, and condensate quantities. 

2. Marketable gas is converted to oil equivalent on a field-by-field basis using an energy equivalent factor
reflecting the reservoir gas composition of each field. 
 In our opinion, the information relating to
estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update
932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and
Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning
of the year. 
 To the extent the above-enumerated rules, regulations, and statements require
determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.


 








 


      

  







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 In comparing the detailed net proved reserves estimates
prepared by us and by PEP, we have found differences, both positive and negative, resulting in an aggregate difference of 8.98 percent when compared on the basis of net oil equivalent barrels. It is our opinion that the net proved reserves estimates
prepared by PEP on the properties reviewed by us and referred to above, when compared on the basis of net oil equivalent barrels, in aggregate, are considered reasonable. 

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing
petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in PEP. Our fees were not contingent on the results of our evaluation. This letter report has
been prepared at the request of PEP. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. 

 

							
		 		 	Submitted,	 	
			
		 		 	




		 		 	DeGOLYER and MacNAUGHTON	 	
		 		 	Texas Registered Engineering Firm F-716	 	
			
	     




  
	 	 




	 	
		 		 	  
	 	
		 	     	 	Thomas C. Pence, P.E.	 	
		 		 	Senior Vice President	 	
		 		 	DeGolyer and MacNaughton	 	

 
 








 


      

  







       

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 CERTIFICATE of QUALIFICATION 

I, Thomas C. Pence, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800
East, Dallas, Texas, 75244 U.S.A., hereby certify: 
  

	 	1.	 That I am a Senior Vice President of DeGolyer and MacNaughton, which company did prepare the letter report
addressed to PEP dated April 29, 2016, and that I, as Senior Vice President, was responsible for the preparation of this letter report. 
	 

  

	 	2.	 That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum
Engineering in 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and that I have in excess of 33 years of experience in oil and gas reservoir studies and
reserves evaluations. 
	 

  
  

							
	   




  
	 	



	 	
		 		 	  
	 	
		 		 	Thomas C. Pence, P.E.	 	
		 		 	Senior Vice President	 	
		 		 	DeGolyer and MacNaughton	 	

 
 








 Exhibit 10.6 (2 of 2) 

 
 DEGOLYER AND
MACNAUGHTON 
 5001 SPRING VALLEY ROAD 

SUITE 800 EAST 

DALLAS, TEXAS 75244 
  

 
  
  

This is a digital representation of a DeGolyer and MacNaughton report. 

This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same
conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information. 

 
  
  

 
 



 







 


      

  





  

DEGOLYER AND MACNAUGHTON 

5001 SPRING VALLEY ROAD 

SUITE 800 EAST 

DALLAS, TEXAS 75244 

April 29, 2016 

Mr. J. Javier Hinojosa Puebla 

Director Ejecutivo 

PEMEX Exploración y Producción 

Avenida Marina Nacional No. 329 

Torre Ejecutiva 

Colonia Verónica Anzures 

11300 Ciudad de México, México 

Dear Mr. Hinojosa Puebla: 

Pursuant to your request, we have conducted a reserves audit of the net proved oil, gas, condensate, and oil
equivalent reserves, as of January 1, 2016, of certain properties that PEMEX Exploración y Producción (PEP) has represented are owned by the United Mexican States in the Veracruz area of Mexico. This audit was completed on
April 29, 2016. PEP has represented that these properties account for 1.6 percent on a net oil equivalent barrel basis of the net proved reserves assigned to PEP, as of January 1, 2016, and that the net proved reserves estimates have been
prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. At the request of PEP, we have also included in this report
estimates prepared by PEP of its natural gas liquids (NGL) reserves; however, PEP has represented that PEP’s management of the properties stops at the inlet of the gas processing plants. PEP has represented that all subsurface hydrocarbons
belong to the United Mexican States, and has further represented that PEP has received a 100-percent assignment in these properties by the United Mexican States; therefore, gross reserves are equal to net reserves and are defined as the total
estimated petroleum to be produced from these properties after December 31, 2015. We have reviewed information provided to us by PEP that it represents to be PEP’s estimates of the net reserves, as of January 1, 2016, for the same
properties as those which we audited. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by PEP.


 








 


      

  







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 Based on Mexico’s Energy Reform of 2014, PEP has
represented that its estimates of the net proved reserves assigned to PEP presented in this report correspond to 96.4 percent of the total net proved reserves of the Veracruz area assigned to PEP, on an oil equivalent basis. 

Reserves estimates included herein are expressed as net reserves as represented by PEP. Gross reserves are
defined as the total estimated petroleum to be produced from these properties after December 31, 2015. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by the United Mexican States after
deducting all interests owned by others. 
 Estimates of oil, gas, condensate, NGL, and oil equivalent
reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates
are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. 

Data used in this audit were obtained from reviews with PEP personnel, from PEP files, from records on file
with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by PEP with respect to property interests, production from such
properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field
examination of the properties was not considered necessary for the purposes of this report. 
 Methodology and Procedures 

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation
principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing
of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and
completeness of basic data, and production history. 

 








 


      

  







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 Based on the current stage of field development, production
performance, the development plans provided by PEP, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. 

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

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery
factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering
methods were used to estimate recovery factors. In such cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. 

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate
trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of
economic production or to the limit of the production licenses as appropriate. 
 Gas quantities estimated
herein are expressed as marketable gas and sales gas at a temperature base of 20 degrees Celsius (°C) and at a pressure base of 1 atmosphere. Marketable gas is defined as the total gas in the reservoirs to be produced after shrinkage
resulting from field separation and flare. Marketable gas includes fuel. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for injection, fuel usage, flare, and shrinkage
resulting from field separation and plant processing. Oil, condensate, and NGL reserves estimated herein are expressed in terms of 42 United States gallons per barrel. Oil and condensate reserves estimated herein are to be recovered by


 








 


      

  







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 normal field separation. PEP has represented that its NGL reserves have been
estimated on the basis of the quantities of liquids recovered from gas delivered to a gas plant for processing, and can include propane, butane, and C5+ fractions. 
 Definition of Reserves 

Petroleum reserves estimated by PEP included in this report are classified as proved. Only proved reserves
have been evaluated for this report. Reserves classifications used by PEP in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be
economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of
production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration
of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: 

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and
government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the
estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. 

(i) The area of the reservoir considered as proved includes: 

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent
undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.


 








 


      

  







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 (ii) In the absence of data on fluid contacts, proved
quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and
the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with
reasonable certainty. 
 (iv) Reserves which can be produced economically through application of improved
recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable
than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or
program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir
is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month
within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 

 








 


      

  







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 Developed oil and gas reserves – Developed oil and
gas reserves are reserves of any category that can be expected to be recovered: 
 (i) Through existing
wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves
estimate if the extraction is by means not involving a well. 
 Undeveloped oil and gas reserves
– Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas
that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has
been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for
which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10
(a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. 

 








 


      

  







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 Primary Economic Assumptions 

The following economic assumptions were used for estimating existing and future prices and costs, expressed
in United States dollars (U.S.$): 
 Oil and Condensate Prices 

PEP has represented that the oil and condensate prices were based on a reference price, calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The average adjusted product prices were
U.S.$45.66 per barrel for oil and U.S.$45.02 per barrel for condensate, and the prices were held constant thereafter. These prices were not escalated for inflation. 

Gas Prices 

PEP has represented that the gas prices were based on a 12 month average price, calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Each field’s calorific value, which
includes NGL, was used to determine each field’s gas price. The contract prices for the fields audited in this report varied between U.S.$2.49 and U.S.$3.99 per thousand cubic feet. These prices were not escalated for inflation. 

Operating Expenses, Capital Costs, and Abandonment Costs 

Operating expenses and capital costs, based on information provided by PEP, were used in estimating future
costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.
Abandonment costs were provided by PEP. 

 








 


      

  







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 While the oil and gas industry may be subject to regulatory
changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2016, estimated oil,
gas, condensate, and NGL reserves. 
 PEP has represented that its estimated net proved reserves
attributable to the reviewed properties are based on the definition of proved reserves of the SEC. PEP represents that its estimates of the net proved reserves attributable to these properties, which represent 1.6 percent of PEP’s reserves on a
net oil equivalent basis, are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe): 
  

																									
	 	 	Estimated by PEP
Net Proved Reserves
as of
January 1, 2016	 
	 	 	Oil
(MMbbl)	 	 	Marketable
Gas
(Bcf)	 	 	Sales
Gas
(Bcf)	 	 	Condensate
(MMbbl)	 	 	NGL
(MMbbl)	 	 	Oil
Equivalent
(MMboe)	 
							
	 Properties Reviewed by DeGolyer and MacNaughton
	 				 				 				 				 				 			
	 Veracruz Area
	 				 				 				 				 				 			
							
	 Total Proved
	 	 	51.8	  	 	 	493.3	  	 	 	474.6	  	 	 	1.1	  	 	 	5.7	  	 	 	149.8	  

 Notes: 

1. Oil equivalent is calculated based on oil, marketable gas, and condensate quantities. 

2. Marketable gas is converted to oil equivalent on a field-by-field basis using an energy equivalent factor
reflecting the reservoir gas composition of each field. 
 In our opinion, the information relating to
estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update
932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and
Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning
of the year. 
 To the extent the above-enumerated rules, regulations, and statements require
determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.


 








 


      

  







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 In comparing the detailed net proved reserves estimates
prepared by us and by PEP, we have found differences, both positive and negative, resulting in an aggregate difference of 3.34 percent when compared on the basis of net oil equivalent barrels. It is our opinion that the net proved reserves estimates
prepared by PEP on the properties reviewed by us and referred to above, when compared on the basis of net oil equivalent barrels, in aggregate, do not differ materially from those prepared by us. 

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing
petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in PEP. Our fees were not contingent on the results of our evaluation. This letter report has
been prepared at the request of PEP. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. 

 

			
		  	Submitted,
		
		  	




		  	DeGOLYER and MacNAUGHTON
		  	Texas Registered Engineering Firm F-716

  
  
  

											
		  	



	  		 	



	 	
		  		  		 		 	  
	 	
		  		  		 		 	Thomas C. Pence, P.E.	 	
		  		  		 		 	Senior Vice President	 	
		  		  		 		 	DeGolyer and MacNaughton	 	

 
 








 


       

     

  







      

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 CERTIFICATE of QUALIFICATION 

 I, Thomas C. Pence, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite
800 East, Dallas, Texas, 75244 U.S.A., hereby certify: 
  

	 	1.	 That I am a Senior Vice President of DeGolyer and MacNaughton, which company did prepare the letter report
addressed to PEP dated April 29, 2016, and that I, as Senior Vice President, was responsible for the preparation of this letter report. 
	 

  

	 	2.	 That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum
Engineering in 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and that I have in excess of 33 years of experience in oil and gas reservoir studies and
reserves evaluations. 
	 

  
  

											
		  	 




  
  
	  		 	



	  	
		  	  	 		 	  
	  
		  	  	 		 	 Thomas C. Pence, P.E.
 Senior Vice
President
 DeGolyer and MacNaughton