EX-10.6



 Exhibit 10.6 

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 

March 31, 2015 
 PEMEX Exploración y
Producción 
 Avenida Marina Nacional 
 Torre Ejecutiva

 Colonia Petróleos Mexicanos 
 C.P. 11311
México, D.F. 
 Gentlemen: 
 Pursuant
to your request, we have conducted a reserves audit of the net proved crude oil, condensate, natural gas liquids (NGL), and sales-gas reserves, as of January 1, 2015, of certain properties that PEMEX Exploración y Producción (PEP)
has represented are owned by the United Mexican States in the Región Marina Suroeste of Mexico. This audit was completed on March 31, 2015. PEP has represented that these properties account for 17.1 percent on a net total liquids
equivalent barrel basis of the net proved reserves of the United Mexican States, as of January 1, 2015, 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. 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, 2015, 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.

 Based on Mexico’s Energy Reform of 2014, PEP has represented that the proved reserves assigned to PEP presented in this report
correspond with 92 percent of the total proved reserves of the Región Marina Suroeste and with 16 percent of the total proved reserves assigned to PEP at the country level, on a net total liquids equivalent basis. 








			
	DEGOLYER AND MACNAUGHTON		2

  
 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, 2014. 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,
condensate, NGL and sales-gas 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. 
 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. 








			
	DEGOLYER AND MACNAUGHTON		3

  
 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
sales gas. Sales gas is defined as that portion of the total gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit
(°F) and a pressure base of 14.7 pounds per square inch absolute (psia). Oil and condensate reserves estimated herein are those to be recovered by conventional field operations. 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: 








			
	DEGOLYER AND MACNAUGHTON		4

  
 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.

 (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. 








			
	DEGOLYER AND MACNAUGHTON		5

  
 (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 
 (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. 








			
	DEGOLYER AND MACNAUGHTON		6

  
 (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. 

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. PEP provided these 12-month average prices by field for oil and condensate, each
including differentials to the Istmo and Olmeca export prices of U.S.$94.25 and U.S.$95.18, respectively, and the prices were held constant thereafter. The volume-weighted average adjusted oil price attributable to estimated proved reserves was
U.S.$98.22 per barrel. The volume-weighted average adjusted condensate price attributable to estimated proved reserves was U.S.$51.61 per barrel. 








			
	DEGOLYER AND MACNAUGHTON		7

  
 Natural Gas Prices 

PEP has represented that the plant-inlet natural gas prices were 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 gas reference prices per million British thermal units (MMBtu) provided by PEP varied between
U.S.$4.09 and U.S.$5.66, and the prices were held constant thereafter. These reference prices represent the two gas processing plants through which all of the gas is processed for all of the fields audited. Each field’s calorific value, which
includes NGL and varied between 0.932 and 1.668 MMBtu per thousand cubic feet (Mcf), was used to determine each field’s gas price. The volume-weighted average adjusted price attributable to estimated proved reserves was U.S.$6.29 per Mcf of
gas. 
 Operating Expenses and Capital 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. 

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, 2015, estimated oil, condensate, NGL, and sales-gas 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. 








			
	DEGOLYER AND MACNAUGHTON		8

  
 PEP represents that its estimates of the net proved
reserves attributable to these properties, which represent 17.1 percent of the United Mexican States’ reserves on a net total liquids equivalent basis, are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and
thousands of barrels of oil equivalent (Mboe): 
  

																	
	 		Estimated by PEP	 
	 		Net Proved Reserves	 
	 		as of	 
	 		January 1, 2015	 
	 		Oil and	 		 	 		Sales	 		Total Liquids	 
	 		Condensate	 		NGL	 		Gas	 		Equivalent	 
	 		(Mbbl)	 		(Mbbl)	 		(MMcf)	 		(Mboe)	 
	 Properties reviewed by DeGolyer and MacNaughton
																
	 Mexico
																
	 Proved Developed
		 	825,789	  		 	138,744	  		 	1,374,322	  		 	1,228,778	  
	 Proved Undeveloped
		 	634,603	  		 	89,706	  		 	1,426,336	  		 	998,556	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Proved
		 	1,460,392	  		 	228,450	  		 	2,800,658	  		 	2,227,334	  

 Notes: 
  

	1.	Sales gas is equivalent to PEP’s dry gas. 


	2.	Gas is converted to liquids equivalent using an energy equivalent factor of 5,200 cubic feet of gas per 1 barrel of liquids equivalent. 


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, 1202(a) (1), (2), (3), (4), (8), and 1203(a) 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. 








			
	DEGOLYER AND MACNAUGHTON	  	9

  
 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 9.1 percent when compared on the basis of net total liquids 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 total liquids 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
  

	



	  	 




  
 R. M. Shuck, P.E.

Senior Vice President
 DeGolyer and MacNaughton

	  	
	  
	  









			
	DEGOLYER AND MACNAUGHTON		

  
 CERTIFICATE of QUALIFICATION

  
 I, R. M. Shuck, 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 with DeGolyer and MacNaughton, which company did prepare the letter report addressed to PEP dated March 31, 2015, and that I, as Senior Vice President, was responsible for the
preparation of this letter report. 

  

	 	2.	That I attended the University of Houston, and that I graduated with a Bachelor of Science degree in Chemical Engineering in the year 1977; that I am a Registered Professional Engineer in the State of Texas; that I am a
member of the Society of Petroleum Engineers; and that I have in excess of 37 years of experience in oil and gas reservoir studies and evaluations. 

  

			
	



		 




  
 R. M. Shuck, P.E.

Senior Vice President
 DeGolyer and MacNaughton