Document:

EX-10.5

 Exhibit 10.5 

(Part 1 of 2) 

DEGOLYER AND MACNAUGHTON 

5001 SPRING VALLEY ROAD 

SUITE 800 EAST 

DALLAS, TEXAS 75244 

April 26, 2018 
 Ing. Carlos Alberto
Treviño Medina 
 Director General 
 Petróleos
Mexicanos 
 Avenida Marina Nacional No. 329 
 Torre
Ejecutiva, Piso 44 
 Colonia Verónica Anzures 
 11300
Ciudad de México, México 
 Dear Ing. Treviño Medina: 

We hereby consent to the references to DeGolyer and MacNaughton as set forth under the headings “Presentation of Information Concerning
Reserves,” “Item 4. Information on the Company – Business Overview – Exploration and Production – Reserves,” and “Item 19. Exhibits. Documents filed as exhibits to this Form
20-F” in the Annual Report on Form 20-F of Petróleos Mexicanos (PEMEX) for the year ended December 31, 2017 (the Form
20-F), and to the filing as Exhibit 10.6 to the Form 20-F of our report of third party dated April 20, 2018, describing our independent reserves evaluation of the
estimated proved oil, marketable gas, sales gas, condensate, natural gas liquids (NGL), and oil equivalent reserves that PEMEX has represented are owned by the United Mexican States (México) as of January 1, 2018, for certain fields
located in the Burgos area of México, which include reserves that PEMEX has represented that it has the right to extract and sell. These estimates were prepared ‘in accordance with the reseres definitions of Rules 4-10(a) (1)-(32) of Regulation s-x of the United States Securities and Exchange Commission. 

 

	
	Very truly yours,
	
	

	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716

 Exhibit 10.5 

(Part 2 of 2) 

DEGOLYER AND MACNAUGHTON 

5001 SPRING VALLEY ROAD 

SUITE 800 EAST 

DALLAS, TEXAS 75244 

April 26, 2018 
 Ing. Carlos Alberto
Treviño Medina 
 Director General 
 Petróleos
Mexicanos 
 Avenida Marina Nacional No. 329 
 Torre
Ejecutiva, Piso 44 
 Colonia Verónica Anzures 
 11300
Ciudad de México, México 
 Dear Ing. Treviño Medina: 

We hereby consent to the references to DeGolyer and MacNaughton as set forth under the headings “Presentation of Information Concerning
Reserves,” “Item 4. Information on the Company – Business Overview – Exploration and Production – Reserves,” and “Item 19. Exhibits. Documents filed as exhibits to this Form
20-F” in the Annual Report on Form 20-F of Petróleos Mexicanos (PEMEX) for the year ended December 31, 2017 (the Form
20-F), and to the filing as Exhibit 10.6 to the Form 20-F of our report of third party dated April 20, 2018, describing our independent reserves evaluation of the
estimated proved oil, marketable gas, sales gas, condensate, natural gas liquids (NGL), and oil equivalent reserves that PEMEX has represented are owned by the United Mexican States (México) as of January 1, 2018, for certain fields
located in the Veracruz area of México, which include reserves that PEMEX has represented that it has the right to extract and sell. These estimates were prepared in accordance with the reserves definitions of Rules 4-10(a) (l)-(32) of Regulation S-X of the United States Securities and Exchange Commission. 

 

	
	Very truly yours,
	
	

	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716EX-10.6

 Exhibit 10.6 

(Part 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 20, 2018 
 Ing. J. Javier Hinojosa Puebla

 Director General de Pemex Exploración y Producción 

Avenida Marina Nacional 329 
 Torre Ejecutiva, Piso 41 

Col. Verónica Anzures, C.P. 11300 
 Del. Miguel Hidalgo,
Ciudad de México 
 Dear Ing. Hinojosa, 

Pursuant to your request, DeGolyer and MacNaughton has conducted an independent reserves evaluation of the net proved oil, gas, condensate,
and oil equivalent reserves, as of January 1, 2018, 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 evaluation was completed on
February 15, 2018. PEP has represented that these properties account for 2.4 percent on a net oil equivalent barrel basis of the net proved reserves assigned to PEP, as of January 1, 2018, 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, this report also includes 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, 2017. We have reviewed information provided to us by PEP that it represents to be PEP’s estimates of the net proved reserves, as of January 1, 2018, for the same properties as those which we
evaluated. 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. 

 2 

DEGOLYER AND MACNAUGHTON 

 

 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 99.8 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, 2017. 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 evaluation 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. 

 3 

DEGOLYER AND MACNAUGHTON 

 

 Based on the current stage of field development, production performance, the development
plans provided by PEP, and 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 based on
existing economic conditions. 
 Gas quantities estimated herein are expressed as marketable gas and sales gas at a temperature base of 20
degrees Celsius 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 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. 

 4 

DEGOLYER AND MACNAUGHTON 

 

 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. 

 5 

DEGOLYER AND MACNAUGHTON 

 

 (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. 

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 

 6 

DEGOLYER AND MACNAUGHTON 

 

 (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. 

 7 

DEGOLYER AND MACNAUGHTON 

 

 Primary Economic Assumptions 

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

 Condensate Prices 

PEP has represented that the 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. As represented by PEP, the reference price utilized is the Mexican Mix reference price, which is
composed of the Istmo, Maya, and Olmeca reference prices and is calculated based on a formula that includes the West Texas Sour, Light Louisiana Sweet, Brent, Oman, and Dubai reference prices. PEP supplied differentials by field to an average
Mexican Mix reference price of U.S.$52.32 per barrel and the prices were held constant thereafter. The volume-weighted average adjusted price attributable to estimated proved reserves for the fields that were evaluated was U.S.$48.34 per barrel for
condensate. 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 volume-weighted average adjusted price for the fields that were evaluated was U.S.$3.79 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.

 8 

DEGOLYER AND MACNAUGHTON 

 

 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 reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2018, estimated reserves. 

PEP has represented that its estimated net proved reserves attributable to the reviewed properties were based on the definition of proved
reserves of the SEC. PEP has represented that its estimates of the net proved reserves attributable to these properties, which represent 2.4 percent of PEP’s reserves on a net oil equivalent basis, are summarized 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, 2018	 
	 Properties Reviewed by DeGolyer and
MacNaughton
	  	Oil
(MMbbl)	 	  	Marketable
Gas
(Bcf)	 	  	Sales
Gas
(Bcf)	 	  	Condensate
(MMbbl)	 	  	NGL
(MMbbl)	 	  	Oil
Equivalent
(MMboe)	 
	 Burgos Area
	  				  				  				  				  				  			
	 Total Proved
	  	 	0.00	 	  	 	971.81	 	  	 	818.52	 	  	 	14.18	 	  	 	15.10	 	  	 	182.22	 

 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. 

 9 

DEGOLYER AND MACNAUGHTON 

 

 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. 

In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by PEP, differences have been found, both
positive and negative, resulting in an aggregate difference of 5.7 percent when compared on the basis of net oil equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by PEP on the
properties reviewed and referred to above, when compared on the basis of net oil equivalent barrels, in aggregate, are considered reasonable. 

DeGolyer and MacNaughton 1s 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

 DEGOLYER AND MACNAUGHTON 

 

 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 20, 2018, 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 degree in Petroleum Engineering in the year 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 35 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 

(Part 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 20, 2018 
 Ing. J. Javier Hinojosa Puebla

 Director General de Pemex Exploración y Producción 

Avenida Marina Nacional 329 
 Torre Ejecutiva, Piso 41 

Col. Verónica Anzures, C.P. 11300 
 Del. Miguel Hidalgo,
Ciudad de México 
 Dear Ing. Hinojosa, 

Pursuant to your request, DeGolyer and MacNaughton has conducted an independent reserves evaluation of the net proved oil, gas, condensate,
and oil equivalent reserves, as of January 1, 2018, 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 evaluation was completed on
February 15, 2018. PEP has represented that these properties account for 2.3 percent on a net oil equivalent barrel basis of the net proved reserves assigned to PEP, as of January 1, 2018, 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, this report also includes 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, 2017. We have reviewed information provided to us by PEP that it represents to be PEP’s estimates of the net proved reserves, as of January 1, 2018, for the same properties as those which we
evaluated. 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. 

 2 

DEGOLYER AND MACNAUGHTON 

 

 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 100 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, 2017. 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 evaluation 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. 

 3 

DEGOLYER AND MACNAUGHTON 

 

 Based on the current stage of field development, production performance, the development
plans provided by PEP, and 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 based on
existing economic conditions. 
 Gas quantities estimated herein are expressed as marketable gas and sales gas at a temperature base of 20
degrees Celsius 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 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. 

 4 

DEGOLYER AND MACNAUGHTON 

 

 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. 

 5 

DEGOLYER AND MACNAUGHTON 

 

 (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. 

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 

 6 

DEGOLYER AND MACNAUGHTON 

 

 (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. 

 7 

DEGOLYER AND MACNAUGHTON 

 

 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. As represented by PEP, the reference price utilized is the Mexican Mix reference price, which is
composed of the Istmo, Maya, and Olmeca reference prices and is calculated based on a formula that includes the West Texas Sour, Light Louisiana Sweet, Brent, Oman, and Dubai reference prices. PEP supplied differentials by field to an average
Mexican Mix reference price of U.S.$52.32 per barrel and the prices were held constant thereafter. The volume-weighted average adjusted prices attributable to estimated proved reserves for the fields that were evaluated were U.S.$49.64 per barrel
for oil and U.S.$50.06 per barrel for condensate. 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 volume-weighted average adjusted price for the fields that were evaluated was U.S.$3.81 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.

 8 

DEGOLYER AND MACNAUGHTON 

 

 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 reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2018, estimated reserves. 

PEP has represented that its estimated net proved reserves attributable to the reviewed properties were based on the definition of proved
reserves of the SEC. PEP has represented that its estimates of the net proved reserves attributable to these properties, which represent 2.3 percent of PEP’s reserves on a net oil equivalent basis, are summarized 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, 2018	 
	 Properties Reviewed by DeGolyer and
MacNaughton
	  	Oil
(MMbbl)	 	  	Marketable
Gas
(Bcf)	 	  	Sales
Gas
(Bcf)	 	  	Condensate
(MMbbl)	 	  	NGL
(MMbbl)	 	  	Oil
Equivalent
(MMboe)	 
	 Veracruz Area
	  				  				  				  				  				  			
	 Total Proved
	  	 	71.34	 	  	 	597.49	 	  	 	561.65	 	  	 	0.35	 	  	 	0.63	 	  	 	180.04	 

 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. 

 9 

DEGOLYER AND MACNAUGHTON 

 

 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. 

In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by PEP, differences have been found, both
positive and negative, resulting in an aggregate difference of 3.8 percent when compared on the basis of net oil equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by PEP on the
properties reviewed and referred to above, when compared on the basis of net oil equivalent barrels, in aggregate, do not differ materially from those prepared 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

 DEGOLYER AND MACNAUGHTON 

 

 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 20, 2018, 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 degree in Petroleum Engineering in the year 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 35 years of experience in oil and gas reservoir studies and reserves evaluations. 
  
 

 

			
		 	

                                    
            
	 	 Thomas C. Pence, P.E.

	 	 Senior Vice President

	 	 DeGolyer and MacNaughton

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