EX-10.6

Michael J. Callahan, P.E.

Vice President

DeGolyer and MacNaughton

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 17, 2017

Ing. J. Javier Hinojosa Puebla

Director General Pemex Exploración y Producción

Avenida Marina Nacional 329

Torre Ejecutiva, Piso 41

Col. Verónica Anzures, C.P. 11300

Del. Miguel Hidalgo, Ciudad de México

Dear Ing. Hinojosa,

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, 2017, 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 February 27, 2017. PEP has represented that these properties account for 2.1 percent on a net oil equivalent barrel basis of the net proved reserves assigned to PEP, as of January 1, 2017, 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, 2016. 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, 2017, 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 its estimates of the net proved reserves assigned to PEP presented in this report correspond to 99.6 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, 2016. 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.

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.

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 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.

(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

(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.

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.$37.44 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 audited was U.S.$36.19 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 audited was U.S.$2.41 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.

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, 2017, 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 2.1 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, 2017

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

0.000

877.298

788.111

15.395

16.283

178.020

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.

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 8.6 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



				Michael J. Callahan, P.E.
				Vice President
				DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

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

That I am a Vice President of DeGolyer and MacNaughton, which company did prepare the letter report addressed to PEP dated April 17, 2017, and that I, as Vice President, was responsible for the preparation of this letter report.

That I attended the University of Missouri at Rolla, and that I graduated with a degree in Petroleum Engineering in the year 1978; 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 36 years of experience in the oil and gas reservoir studies and reserves evaluations.

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

April 17, 2017

Ing. J. Javier Hinojosa Puebla

Director General Pemex Exploración y Producción

Avenida Marina Nacional 329

Torre Ejecutiva, Piso 41

Col. Verónica Anzures, C.P. 11300

Del. Miguel Hidalgo, Ciudad de México

Dear Ing. Hinojosa,

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, 2017, of certain properties that PEMEX Exploracion y Produccion (PEP) has represented are owned by the United Mexican States in the Veracruz area of Mexico. This audit was completed on February 27, 2017. PEP has represented that these properties account for 1.5 percent on a net oil equivalent barrel basis of the net proved reserves assigned to PEP, as of January 1, 2017, 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, 2016. 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, 2017, 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 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.

Methodology and Procedures

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–l0(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:

(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:

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.

(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. 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.$37.44 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 audited were U.S.$34.43 per barrel for oil and U.S.$36.19 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 audited was U.S.$2.85 per thousand cubic feet. These prices were not escalated for inflation.

Operating Expenses, Capital Costs, and Abandonment Costs

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 1.5 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, 2017

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

47.985

424.212

415.631

0.496

0.767

128.856

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 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 6.9 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.


		Submitted,


		DeGOLYER and MacNAUGHTON
		Texas Registered Engineering Firm F-716




								Michael J. Callahan, P.E.
								Vice President
								DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

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




								Michael J. Callahan, P.E. Vice President DeGolyer and MacNaughton