Exhibit 10.4 (1 of 3)

PRESIDENT - ROBERT C. BARG   VICE PRESIDENTS ALLEN E. EVANS, JR. RANDOLPH K. GREEN JOHN G. HATTNER C. H. (SCOTT) REES III DANNY D. SIMMONS DAN PAUL SMITH THOMAS M. SOUERS

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

México

Dear Ing. Hinojosa:

In accordance with your request, we have audited the estimates prepared by Pemex Exploración y Producción (PEP), as of January 1, 2017, of the gross (100 percent) proved reserves in 72 fields located in the Poza Rica-Altamira District, Mexico. PEP is a subsidiary entity of Petróleos Mexicanos. The scope of our work did not include auditing the future net revenue associated with these reserves. The Political Constitution of the United Mexican States provides that the Mexican nation owns all petroleum and other hydrocarbon reserves for these fields; however, these fields are currently operated by PEP. In accordance with the Energy Reform of 2014, the estimates in this report represent the gross (100 percent) proved reserves to be produced within the economic life of the properties. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, and economic producibility, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). Economic analysis was performed by PEP only to confirm economic producibility and determine economic limits for the properties. The estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on February 27, 2017. This report has been prepared for PEP’s and Petróleos Mexicanos’ use internally and in filings with the appropriate regulatory agencies. In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose; there is no guarantee or warranty, implied or expressed, by Netherland, Sewell International, S. de R.L. de C.V. (NSI) for any other use of this report.

The following table sets forth PEP’s estimates of the gross (100 percent) reserves, as of January 1, 2017, for the audited Poza Rica-Altamira District properties:

	Gross (100%) Reserves
Category	Oil(1) (MMBBL)		Condensate(2)   (MMBBL)		Plant Liquids   (MMBBL)		Dry Gas(3)     (MMBOE)		BOE  (MMBBL)
Proved Developed Producing		112.6		0.0		1.9		15.7		130.2
Proved Developed Non-Producing		26.9		0.0		0.6		3.3		30.8
Proved Undeveloped		87.6		0.0		1.7		11.4		100.7
Total Proved		227.1		0.0		4.2		30.4		261.7

⁽¹⁾  Oil reserves include oil plus liquids from the produced gas stream separated in the field.

⁽²⁾  Condensate reserves are the liquids volumes recovered from the produced gas stream during the compression and dehydration stages of processing.

⁽³⁾  Dry gas reserves are the dry, sweetened gas available for sale by Pemex Transformación Industrial at the tailgate of the processing plants.

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

Oil, condensate, plant liquids, and barrels of oil equivalent (BOE) volumes are expressed in millions of barrels (MMBBL); a barrel is equivalent to 42 United States gallons. Dry gas volumes are expressed in millions of barrels of oil equivalent (MMBOE), determined using dry gas conversion factors provided by PEP.

When compared on a field-by-field basis, some of the estimates of PEP are greater and some are less than the estimates of NSI. However, in our opinion the estimates of reserves prepared by PEP shown herein are reasonable when aggregated at the total proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by PEP in preparing the January 1, 2017, estimates of reserves, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by PEP.

The estimates shown herein are for proved reserves. PEP’s estimates do not include probable or possible reserves that exist for these properties. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves included herein have not been adjusted for risk.

Oil and gas prices were used only to confirm economic producibility and determine economic limits for the properties. It is our understanding that prices used by PEP are representative of the 12-month average for the period January through December 2016. NSI accepted the prices provided without independent review or verification. All prices are held constant throughout the lives of the properties.

Costs were used only to confirm economic producibility and determine economic limits for the properties. It is our understanding that operating costs used by PEP are representative of the 12-month average for the period January through December 2016. These costs include district and regional overhead expenses along with costs to be incurred at the field level. Operating costs for certain undeveloped fields are based on PEP’s analogy to a similar type of producing field. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. No headquarters general and administrative overhead expenses are included. Capital costs used by PEP are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Abandonment costs used are PEP’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. NSI accepted the operating cost parameters and the capital and abandonment costs provided without independent review or verification. Operating, capital, and abandonment costs are not escalated for inflation.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of PEP and NSI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by PEP, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of PEP to produce and recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts used to confirm economic producibility and determine economic limits for the properties. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties making up the total proved reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by PEP with respect to oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. Our audit did not include a review of PEP’s overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by PEP, are on file in our office. The technical persons primarily responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Eric J. Stevens, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Netherland, Sewell & Associates, Inc. (NSAI), of which NSI is a subsidiary, since 2007 and has 5 years of prior industry experience. Michelle F. Herrera, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2013 and has 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL INTERNATIONAL, S. DE R.L. DE C.V.
By:
	Robert C. Barg, P.E.
	President

Exhibit 10.4 (2 of 3)

PRESIDENT - ROBERT C. BARG   VICE PRESIDENTS ALLEN E. EVANS, JR. RANDOLPH K. GREEN JOHN G. HATTNER C. H. (SCOTT) REES III DANNY D. SIMMONS DAN PAUL SMITH THOMAS M. SOUERS

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

México

Dear Ing. Hinojosa:

In accordance with your request, we have audited the estimates prepared by Pemex Exploración y Producción (PEP), as of January 1, 2017, of the gross (100 percent) proved reserves in 26 fields located in the Litoral de Tabasco District, Mexico. PEP is a subsidiary entity of Petróleos Mexicanos. The scope of our work did not include auditing the future net revenue associated with these reserves. The Political Constitution of the United Mexican States provides that the Mexican nation owns all petroleum and other hydrocarbon reserves for these fields; however, these fields are currently operated by PEP. In accordance with the Energy Reform of 2014, the estimates in this report represent the gross (100 percent) proved reserves to be produced within the economic life of the properties. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, and economic producibility, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). Economic analysis was performed by PEP only to confirm economic producibility and determine economic limits for the properties. The estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on February 27, 2017. This report has been prepared for PEP’s and Petróleos Mexicanos’ use internally and in filings with the appropriate regulatory agencies. In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose; there is no guarantee or warranty, implied or expressed, by Netherland, Sewell International, S. de R.L. de C.V. (NSI) for any other use of this report.

The following table sets forth PEP’s estimates of the gross (100 percent) reserves, as of January 1, 2017, for the audited Litoral de Tabasco District properties:

	Gross (100%) Reserves
Category	Oil(1)  (MMBBL)		Condensate(2)   (MMBBL)		Plant Liquids   (MMBBL)		Dry Gas(3)     (MMBOE)		BOE  (MMBBL)
Proved Developed Producing		214.3		10.6		56.4		93.2		374.5
Proved Developed Non-Producing		14.6		0.2		2.0		3.3		20.1
Proved Undeveloped		282.3		4.6		16.2		88.9		392.0
Total Proved		511.2		15.5		74.6		185.4		786.6

Totals may not add because of rounding.

⁽¹⁾  Oil reserves include oil plus liquids from the produced gas stream separated in the field.

⁽²⁾  Condensate reserves are the liquids volumes recovered from the produced gas stream during the compression and dehydration stages of processing.

⁽³⁾  Dry gas reserves are the dry, sweetened gas available for sale by Pemex Transformación Industrial at the tailgate of the processing plants.

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

Oil, condensate, plant liquids, and barrels of oil equivalent (BOE) volumes are expressed in millions of barrels (MMBBL); a barrel is equivalent to 42 United States gallons. Dry gas volumes are expressed in millions of barrels of oil equivalent (MMBOE), determined using dry gas conversion factors provided by PEP.

When compared on a field-by-field basis, some of the estimates of PEP are greater and some are less than the estimates of NSI. However, in our opinion the estimates of reserves prepared by PEP shown herein are reasonable when aggregated at the total proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by PEP in preparing the January 1, 2017, estimates of reserves, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by PEP.

The estimates shown herein are for proved reserves. PEP’s estimates do not include probable or possible reserves that exist for these properties. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves included herein have not been adjusted for risk.

Oil and gas prices were used only to confirm economic producibility and determine economic limits for the properties. It is our understanding that prices used by PEP are representative of the 12-month average for the period January through December 2016. NSI accepted the prices provided without independent review or verification. All prices are held constant throughout the lives of the properties.

Costs were used only to confirm economic producibility and determine economic limits for the properties. It is our understanding that operating costs used by PEP are representative of the 12-month average for the period January through December 2016. These costs include district and regional overhead expenses along with costs to be incurred at the field level. Operating costs for certain undeveloped fields are based on PEP’s analogy to a similar type of producing field. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. No headquarters general and administrative overhead expenses are included. Capital costs used by PEP are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Abandonment costs used are PEP’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. NSI accepted the operating cost parameters and the capital and abandonment costs provided without independent review or verification. Operating, capital, and abandonment costs are not escalated for inflation.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of PEP and NSI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by PEP, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of PEP to produce and recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts used to confirm economic producibility and determine economic limits for the properties. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties making up the total proved reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by PEP with respect to oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. Our audit did not include a review of PEP’s overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by PEP, are on file in our office. The technical persons primarily responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Andres F. Castaño, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Netherland, Sewell & Associates, Inc. (NSAI), of which NSI is a subsidiary, since 2013 and has 8 years of prior industry experience. Allen E. Evans, Jr., a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1996 and has 13 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL INTERNATIONAL, S. DE R.L. DE C.V.
By:
	Robert C. Barg, P.E.
	President

Exhibit 10.4 (3.3)

PRESIDENT - ROBERT C. BARG   VICE PRESIDENTS ALLEN E. EVANS, JR. RANDOLPH K. GREEN JOHN G. HATTNER C.H. (SCOTT) REES III DANNY D. SIMMONS DAN PAUL SMITH THOMAS M. SOUERS

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

México

Dear Ing. Hinojosa:

In accordance with your request, we have audited the estimates prepared by Pemex Exploración y Producción (PEP), as of January 1, 2017, of the gross (100 percent) proved reserves in 27 fields located in the Aceite Terciario del Golfo District, Veracruz, Mexico. PEP is a subsidiary entity of Petróleos Mexicanos. The scope of our work did not include auditing the future net revenue associated with these reserves. The Political Constitution of the United Mexican States provides that the Mexican nation owns all petroleum and other hydrocarbon reserves for these fields; however, these fields are currently operated by PEP. In accordance with the Energy Reform of 2014, the estimates in this report represent the gross (100 percent) proved reserves to be produced within the economic life of the properties. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, and economic producibility, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). Economic analysis was performed by PEP only to confirm economic producibility and determine economic limits for the properties. Without considering (1) the accelerated development pace and (2) the inclusion of proved undeveloped locations drilled beyond 5 years of their original booking date, the estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. These considerations are discussed in a subsequent paragraph of this letter. We completed our audit on February 27, 2017. This report has been prepared for PEP’s and Petróleos Mexicanos’ use internally and in filings with the appropriate regulatory agencies. In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose; there is no guarantee or warranty, implied or expressed, by Netherland, Sewell International, S. de R.L. de C.V. (NSI) for any other use of this report.

The following table sets forth PEP’s estimates of the gross (100 percent) reserves, as of January 1, 2017, for the audited Aceite Terciario del Golfo District properties:

	Gross (100%) Reserves
Category	Oil(1)  (MMBBL)		Condensate(2)   (MMBBL)		Plant Liquids   (MMBBL)		Dry Gas(3)     (MMBOE)		BOE  (MMBBL)
Proved Developed Producing		26.2		0.0		4.0		9.6		39.7
Proved Developed Non-Producing		67.8		0.0		6.6		15.9		90.3
Proved Undeveloped		419.1		0.0		52.8		128.4		600.4
Total Proved		513.1		0.0		63.3		154.0		730.5

⁽¹⁾  Oil reserves include oil plus liquids from the produced gas stream separated in the field.

⁽²⁾  Condensate reserves are the liquids volumes recovered from the produced gas stream during the compression and dehydration stages of processing.

⁽³⁾  Dry gas reserves are the dry, sweetened gas available for sale by Pemex Transformación Industrial at the tailgate of the processing plants.

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

Oil, condensate, plant liquids, and barrels of oil equivalent (BOE) volumes are expressed in millions of barrels (MMBBL); a barrel is equivalent to 42 United States gallons. Dry gas volumes are expressed in millions of barrels of oil equivalent (MMBOE), determined using dry gas conversion factors provided by PEP.

In our opinion, the estimates of proved reserves shown herein have been prepared in accordance with generally accepted petroleum engineering and evaluation principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards) and, aside from the following considerations, adhere to the SEC definitions. First, the development plan incorporated in this report represents a more accelerated drilling pace than the recent development drilling. Focused development of the Chicontepec formation began in 2007, and to date, over 4,500 wells have been drilled. Development drilling peaked in 2009 with the drilling of 794 locations; however, in recent years development has slowed, with fewer than 100 wells drilled in 2015 and 2016 combined. Based on discussions with PEP, its development plan consists of drilling more than 30,000 wells over the next 36 years to develop the Chicontepec formation. PEP has indicated a commitment to develop the Aceite Terciario del Golfo District and plans to drill 500 wells in 2017, ramping up to a maximum of 1,000 wells per year by 2019. The time period for development of proved reserves locations is restricted to 5 years. Second, it is our understanding that a significant portion of the proved undeveloped reserves are associated with locations that have been categorized as proved undeveloped for longer than 5 years.

When compared on a field-by-field basis, some of the estimates of PEP are greater and some are less than the estimates of NSI. However, in our opinion the estimates of reserves prepared by PEP shown herein are reasonable when aggregated at the total proved level and have been prepared in accordance with the SPE Standards. Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by PEP in preparing the January 1, 2017, estimates of reserves, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by PEP.

The estimates shown herein are for proved reserves. PEP’s estimates do not include probable or possible reserves that exist for these properties. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves included herein have not been adjusted for risk.

Oil and gas prices were used only to confirm economic producibility and determine economic limits for the properties. It is our understanding that prices used by PEP are representative of the 12-month average for the period January through December 2016. NSI accepted the prices provided without independent review or verification. All prices are held constant throughout the lives of the properties.

Costs were used only to confirm economic producibility and determine economic limits for the properties. It is our understanding that operating costs used by PEP are representative of the 12-month average for the period January through December 2016. These costs include district and regional overhead expenses along with costs to be incurred at the field level. Operating costs for certain undeveloped fields are based on PEP’s analogy to a similar type of producing field. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. No headquarters general and administrative overhead expenses are included. Capital costs used by PEP are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Abandonment costs used are PEP’s estimates of the costs to abandon the wells and production facilities, net of any salvage value. NSI accepted the operating cost parameters and the capital and abandonment costs provided without independent review or verification. Operating, capital, and abandonment costs are not escalated for inflation.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of PEP and NSI are based on certain assumptions including, but not limited to, that the properties will be developed consistent

with current development plans as provided to us by PEP, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of PEP to produce and recover the reserves, and that projections of future production will prove consistent with actual performance. A portion of these reserves are for properties operated by service contractors that are involved with the investment, planning, and development in accordance with their agreements with PEP. The development plan incorporated in this report was provided by PEP; this development plan may differ from development plans of individual service contract operators. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts used to confirm economic producibility and determine economic limits for the properties. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties making up the total proved reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by PEP with respect to oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. Our audit did not include a review of PEP’s overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by PEP, are on file in our office. The technical persons primarily responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Eric J. Stevens, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Netherland, Sewell & Associates, Inc. (NSAI), of which NSI is a subsidiary, since 2007 and has 5 years of prior industry experience. Dana D. Coryell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1999 and has 15 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL INTERNATIONAL, S. DE R.L. DE C.V.
By:
	Robert C. Barg, P.E.
	President