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Natural Gas Outlook

2016-2030

Mexico, 2016

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Secretariat of Energy Pedro Joaquín Coldwell Secretary of Energy Leonardo Beltrán Rodríguez Deputy Secretary of Planning and Energy Transition Cesar Emilio Hernández Ochoa Deputy Secretary of Electricity Aldo Flores Quiroga Deputy Secretary of Hydrocarbons Gloria Brasdefer Hernández Senior Officer Rafael Alexandri Rionda General Director of Planning and Energy Information Víctor Manuel Avilés Castro General Director of Communications

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Preparation and Review: Rafael Alexandri Rionda General Director of Planning and Energy Information (ralexandri@energia.gob.mx) Luis Gerardo Guerrero Gutiérrez Director for the Integration of the Sector Outlooks (lgguerrero@energia.gob.mx) Fabiola Rodríguez Bolaños Deputy Director for the Integration of Energy Policies (frodriguez@energia.gob.mx) Alain de los Ángeles Ubaldo Higuera Deputy Director of Energy Consumption (aubaldo@energia.gob.mx) Ana Lilia Ramos Bautista Department Head of Fuels Policies (aramos@energia.gob.mx) Cover: Administrative support: María de la Paz León Femat, Maricela de Guadalupe Novelo Manrique. 2016, Secretariat of Energy.

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Acknowledgments We owe a debt of gratitude to the following agencies, entities, organisms, and institution for the integration of this outlook:

Comisión Nacional de Hidrocarburos (National Hydrocarbons Commission)

Comisión Reguladora de Energía (Energy Regulatory Commission)

Centro Nacional de Control de Gas Natural (National Center for Natural Gas Control)

Comisión Federal de Electricidad (Federal Electricity Commission)

Comisión Nacional para el Uso Eficiente de la Energía (National Commission for the Efficient Use of Energy)

Subsecretaría de Hidrocarburos (Undersecretariat of Hydrocarbons)

Petróleos Mexicanos (Mexican Petroleums)

Instituto Mexicano del Petróleo (Mexican Petroleum Institute)

Energía Costa Azul

Gas del Litoral

Terminal KMS de GNL

Secretaría de Hacienda y Crédito Público (Secretariat of Finance and Public Credit)

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Index

Index .......................................................................................................................................................................................5

Index of Tables ...................................................................................................................................................................7

Index of Figures ..................................................................................................................................................................8

Presentation ..................................................................................................................................................................... 10

Introduction ...................................................................................................................................................................... 11

Executive Summary ........................................................................................................................................................ 12

1. Chapter One. Natural Gas Regulatory Frame............................................................................................ 15

1.1. Implementation of the Reform in Activities of the Natural-Gas Chain Value ....................... 15

1.1.1. Exploration and Extraction Activities of Natural Gas ........................................................................ 16

1.1.2. Natural Gas Processing ............................................................................................................................... 18

1.1.3. Storage ............................................................................................................................................................. 19

1.1.4. Transportation ............................................................................................................................................... 19

1.1.5. Distribution ...................................................................................................................................................... 20

1.1.6. Natural Gas Trading ..................................................................................................................................... 21

1.1.7. Other Regulating Instruments ................................................................................................................... 23

2. Chapter Two. Natural Gas Historic Market ............................................................................................... 26

2.1. Natural Gas Domestic Market ............................................................................................................. 26

2.1.1. Domestic Demand ........................................................................................................................................ 26

2.1.2. Natural Gas Demand by Sector ................................................................................................................ 26

2.1.3. Natural Gas Regional Demand .................................................................................................................. 31

2.1.4. Natural Gas Supply ....................................................................................................................................... 32

2.1.5. Natural Gas Infrastructure ......................................................................................................................... 35

2.1.6. Natural Gas Price ........................................................................................................................................... 40

2.1.7. Natural Gas Foreign Trade ......................................................................................................................... 41

2.1.8. Natural Gas Domestic Balance ................................................................................................................. 42

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3. Chapter Three. Prospective Natural Gas Market ..................................................................................... 44

3.1. Natural Gas Prospective ........................................................................................................................ 44

3.1.1. Natural Gas Demand .................................................................................................................................... 44

3.1.2. Sectoral Demand ........................................................................................................................................... 45

3.1.3. Natural-Gas Regional Demand ................................................................................................................. 51

3.1.4. Natural Gas Supply ....................................................................................................................................... 53

3.1.5. Infrastructure .................................................................................................................................................. 59

3.1.6. Foreign Trade .................................................................................................................................................. 60

3.1.7. National Balance 2015-2029.................................................................................................................... 61

4. Chapter four. Sensitivity Analysis ................................................................................................................. 63

Annexes ............................................................................................................................................................................. 67

Glossary ............................................................................................................................................................................. 81

Acronyms .......................................................................................................................................................................... 86

Conversion Factors ......................................................................................................................................................... 88

References......................................................................................................................................................................... 90

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Index of Tables

Table 2. 1 Natural Gas Total Remnant Reserves, 2004-2016* .............................................................................. 33

Table 2. 2 Natural Gas Extraction by Region, 2004-2014 ....................................................................................... 34

Table 2. 3 Natural Gas Open-Access Transportation Permits to December 2015. ......................................... 36

Table 2. 4 Quinquennial Data and Engagements of the Distribution Permit Holders, by the End of 2015 ...................................................................................................................................................................................................... 39

Table 2. 5 LNG Storage Permits, 2015............................................................................................................................ 40

Table 2. 6 Natural Gas Domestic Balance, 2005-2015 ............................................................................................. 43

Table 3. 1 Electricity Sector Fuel's Demand, 2015-2030. ......................................................................................... 46

Table 3. 2 Industrial Sector Domestic Demand for Fuels, 2015-2030. ................................................................ 46

Table 3. 3 Industrial Demand for Natural Gas by Projecting Component, 2016-2030. ................................. 47

Table 3. 4 Domestic Fuels Demand in the Oil Sector, 2015-2030. ........................................................................ 48

Table 3. 5 Fuels Consumption in the Residential Sector, 2015-2030. .................................................................. 49

Table 3. 6 Fuels Consumption in the Services Sector, 2015-2030. ....................................................................... 49

Table 3. 7 Motor-Carrier Sector Demand for Gasoline, Fuel Gas, Compressed Natural Gas, and Diesel, 2015-2030. .............................................................................................................................................................................. 51

Table 3. 8 Natural-Gas Regional Consumption by State, 2015-2030. ................................................................. 52

Table 3. 9 Infrastructure Projects Considered in the Quinquennial Plan, 2015-2019 ..................................... 59

Table 3. 10 Natural Gas Domestic Balance, 2015-2030. ......................................................................................... 62

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Index of Figures

Figure 1. 1 Natural Gas Supply Chain ....................................................................................................................... 15

Figure 1. 2 Instrumentos de regulación del mercado de gas natural .............................................................. 16

Figure 1. 3 Resolutions On transportation .............................................................................................................. 20

Figure 1. 4 Resolutions on Trading ............................................................................................................................ 21

Figure 1. 5 Actions for the implementation of the public policy ...................................................................... 23

Figure 1. 6 Schedule for the First Open Season ..................................................................................................... 25

Figure 2. 1 Domestic Demand for Fuels, 2015 ...................................................................................................... 26

Figure 2. 2 Natural Gas Domestic demand by sector, 2015 ............................................................................ 27

Figure 2. 3 Domestic Demand for Fuels in the Electricity Sector, 2015. ....................................................... 27

Figure 2. 4 Demand for Fuels in the Motor-Carrier Sector, 2015 ................................................................... 28

Figure 2. 5 Demand for Fuels in the Industrial Sector, 2015 ............................................................................. 29

Figure 2. 6 Domestic Demand for fuels in the Oil Sector, 2015 ...................................................................... 29

Figure 2. 7 Domestic demand for fuels in the residential sector, 2015 ........................................................ 30

Figure 2. 8 Domestic Demand for Fuels in the Services Sector, 2015 ........................................................... 31

Figure 2. 9 Natural Gas Regional Demand, 2015 ................................................................................................. 32

Figure 2. 10 Natural Gas Total Remnant Reserves by Category .................................................................... 33

Figure 2. 11 Production of Associated and Non-Associated Natural Gas, 2005-2015........................... 35

Figure 2. 12 Current Infrastucture of Natural Gas ............................................................................................... 38

Figure 2. 13 Natural Gas Benchmark (First-Hand Sales In Reynosa), 2010-2013 .................................... 41

Figure 2. 14 Natural Gas Import and Export Points Mexico-U.S ...................................................................... 42

Figure 3. 1 Natural Gas Domestic Demand, 2015-2030 ................................................................................... 44

Figure 3. 2 Natural-Gas Demand by Sector, 2015-2030. ................................................................................. 45

Figure 3. 3 Natural Gas Industrial Demand by Group of Branches, 2015-2030. ....................................... 47

Figure 3. 4 Natural-Gas Savings in the Residential and Services Sectors,2015-2030. ............................ 50

Figure 3. 5 Natural-Gas Savings in the Residential and Services Sectors, 2015-2030. ........................... 50

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Figure 3. 6 Natural-Gas Production*, Minimum and Maximum Scenarios. ................................................... 55

Figure 3. 7 Gas Production by Activity, Maximum Scenario 2016-2030 ..................................................... 56

Figure 3. 8 Gas Production by Activity, Minimum Scenario 2016-2030 ...................................................... 56

Figure 3. 9 Gas Production by Region, Maximum Scenario 2016-2030 ....................................................... 57

Figure 3. 10 Gas Production by Region, Minimum Scenario 2016-2030...................................................... 57

Figure 3. 11 Natural Gas Production by Origin, Maximum Scenario, 2016-2030. .................................... 58

Figure 3. 12 Natural-Gas Production by Origin, Maximum Scenario 2016-2030. .................................... 58

Figure 3. 13 Gas-Pipelines Network 2015-2030 ................................................................................................. 60

Figure 3. 14 Natural Gas Imports, 2015-2030. .................................................................................................... 61

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Presentation

A new model for natural gas was established to create a competitive and efficient market, one capable of attracting investments, ensuring the country's energy security, and which can offer a natural gas supply at a competitive price benefiting thus every sector, and which will allow the share of private companies within the value chain.

The implementation of the Energy Reform has been reflected in the share of private companies in the biddings for the allocation of fields for the exploration and extraction of hydrocarbons; in setting up a program for constructing gas pipelines; in issuing the "Public Policy for Implementing the Natural Gas Market"; and the open season process for any interested parties to reserve transport capacity within the network.

The bases have been founded for a dynamic and competitive natural gas market which fosters the growing availability of natural gas throughout the national territory; separates pipeline transportation from trading; establishes open-access and capacity-reserve principles for gas pipelines; sets asymmetric regulations when there are agents holding dominant positions within the sector; and which issues information about transactions, locations, discounts, and volumes for natural gas trade.

All these actions will be developed in the short, medium and long terms, will be reflected upon the market's behavior, and will set the basis for developing the Natural Gas Outlook document.

This document was prepared along with diverse entities within the energy sector, whose role have been of the highest importance on natural gas matters.

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Introduction

Natural gas is one of the main energy sources, and it is used by varied sectors such as the electricity, industrial and residential ones, since it is a low-cost and environmentally-friendly fuel compared to other fossil fuels like coal, diesel, or fuel oil. The energy transition going on in the country fosters the share of cleaner fuels for electricity generation.

Thereby, it is important to have an indicative planning which displays the natural gas market behavior and that will help the decision making of the different sectors. In this sense, the Secretariat of Energy issues every year the outlooks for the energy sector, in accordance with Article 24 of the Internal Regulation of the Secretariat of Energy.

The outlook document is formed by four chapters which explain the historic and prospective behavior of the natural gas market. The first chapter addresses the regulatory frame of the activities within the natural gas value chain, referring to the instruments issued starting from the Energy Reform.

The second chapter itemizes the national and regional markets' behavior of this fuel during the period 2005-2015 on subjects such as demand, production, prices, gas-pipelines infrastructure, trade, and balances.

The forecast for the natural gas market within the next 15 years is included in the third chapter. It addresses the demand and the production of natural gas according to the new methodology of the Hydrocarbons National Commission (CNH, for its Spanish acronym), the infrastructure of gas pipelines, gas trade, the national balance, and the regional balances.

Chapter four include the exercises on sensitivity analysis, taking into consideration three scenarios (base, high, and low) for the industrial, residential, and services sectors. Finally, this document presents the attachments with the information from chapters two and three.

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Executive Summary

Natural Gas Regulatory Frame

The Energy Reform led to a structural change that seeks to enable the potential of the energy sector and contribute thus to the country's development through the sustainable and efficient use of natural resources, and a new organization in the industry of exploration and extraction of hydrocarbons.

This change on the industrial organization of the natural gas sector was the result of the new legal and regulatory frame emanated from the Decree which amends and adds varied regulations of the Political Constitution of the United Mexican States, on energy matter, issued in the Official Journal of the Federation (DOF, for its Spanish acronym) on December 20, 2013, and made it necessary a new methodology of maximum prices for first-hand sales which considers the fundamental changes in the industry's structure, organization, and functioning.

The resolutions, agreements and decrees issued for each activity, serve as regulatory instruments. The greatest advances have occurred in the exploration and extraction of natural gas, like Round Zero, Round One, and Round Two, which have been carried out in order to receive incomes for the State that will contribute to the long-term development of the Nation.

As for the processing of natural gas, the General Administrative Provisions were issued to establish the formats and specifications for the requirements referred to in articles 50, 51, and 121 of the Hydrocarbons Law for granting the permits to treat and refine petroleum, and to process natural gas; likewise, the General Administrative Provisions which establish the models for the permit's titles in matter of the treatment and refining of petroleum, and for the processing of natural gas, were issued, and which intend to streamline and to make transparent the process for granting the permits, in compliance with what is established in the corresponding legal instruments, and with the Law's requirements.

For the transportation, storage, and trade of natural gas, varied agreements and resolutions have also been issued which will help to have a competitive and efficient market.

Historic Domestic Market

In 2015, the domestic demand for fossil fuels reached a volume of 17,115.0 million cubic feet per day of natural gas equivalent (MMCFDNGE), an increase of 1.7% regarding 2014. From this total demand, natural gas had a 43.8% share with a volume of 7,504.1 million cubic feet per day (MMCFD), followed by gasoline with a 22.3%; diesel, 12.7%; coal, 7.3%, LP gas ,6.3%; fuel oil, 4.9%, and finally petroleum coke with 2.6%.

The public electricity sector had the largest demand with a volume of 3,228.9 MMCFD of natural gas, seconded by the industrial sector with 1,375.9 MMCFD, and the private electricity one with 568.6 MMCFD. The residential, services, and motor-carrier sectors had the smallest share, 94.6 MMCFD, 33.7 MMCFD, and 2.4 MMCFD, respectively. It is important to mention that every sector displayed an increase in their demand, except for the oil sector which decreased by 3.3% regarding 2014.

The total remnant reserves by January 1st, 2016 reached a volume of 31,904.7 billion cubic feet BCF, a fall of 41.9% regarding 2015, due to the drop of crude oil prices and to budget cuts which put downward pressure on the development activities of Petroleos Mexicanos (Pemex), which resulted in the reallocation of resources to more profitable areas. From the total volume of gas reserves, 22,421.6 MMCFD corresponded to associated gas, and 9,483.1 MMCFD to non-associated gas.

Since 2015, the National Hydrocarbons Commission (CNH, for its Spanish acronym) is in charge of providing production data for the outlooks, and the previous classification used for delineating regions (Northeast

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Marine, Southwest Marine, South, and North) changes as follows: Chicontepec Paleochannel, Maritime areas with a water depth of more than 500 meters (Deep Water), Maritime areas with a water depth below 500 meters (Shallow Water), Onshore Areas and Non-Associated Gas. This classification is aligned with what is established in chapter V of the Agreement whereby are issued the general provisions for defining the methods to adjust the value of the hydrocarbons from the fees on hydrocarbons.

In 2015, the production of natural gas reached a volume of 6,40.0 MMCFD, a decrease of 2.0% regarding 2014. This production includes a volume of nitrogen of 896.7 MMCFD. The production of associated gas reached 4,825.7 MMCFD, a slight increase of 0.1% regarding 2014, and a share of 75.4%. The production of non-associated gas reached a volume of 1,573.3 MMFCD, a decrease of 8.0% regarding 2014.

By the end of 2015, the Energy Regulatory Commission (CRE, for its Spanish acronym) had 31 valid permits, from which 25 are currently operating, four under construction, and one about to be constructed. These permits represent a total length of 15,755.9 kilometers (km).

From the total authorized kilometers, 10,068.0 km belong to the National Comprehensive System for Transportation and Storage of Natural Gas (SISTRANGAS, for its Spanish acronym), and are operated and administrated by the National Center for Natural Gas Control (CENAGAS, for its Spanish acronym); and 5,687.9 km belong to private companies.

In 2015, the benchmark price for natural gas averaged 2.6 USD/MMBTU, 39.1% less than in 2014, due to an increase in the inventory of the United States of America (U.S).

By the end of 2015, imports reached a volume of 3,548.0 MMCFD, an increase of 24.0% regarding 2014. From the total volume, 2,910.3 MMCFD were imported through pipeline, and 637.7 MMCFD were liquefied natural gas. As for exports, these kept their 2014 levels, reaching 12.5 MMCFD. From this volume, 9.7 MMCFD were exported through Cd. Morelos in Baja California, and 2.8 through Reynosa, Tamaulipas.

Prospective National Market

In 2030, the demand for natural gas will increase by 20.3% regarding 2015, reaching a volume of 9,030.4 MMCFD. During the period 2015-2030, the demand for natural gas will display an average annual growth rate (AAGR) of 1.2%. This increase is the result of the construction and start-up of new gas pipelines which will enable the transportation of gas to areas which were inaccessible, and to an increase in the demand for natural gas of the electricity and industrial sectors. An increase in their demand is expected in almost every sector, except for the oil sector, which decreased by 34.0% regarding 2015. The electricity sector will remain as the largest consumer with a 58.7% share; seconded by the industrial sector with 23.2%; oil sector, 16.1%; residential and services sectors, 1.3% and 0.6%, respectively; and motor-carrier sector with 0.1%. As for the regional demand, the region with the largest demand for natural gas will be the Northeast one, with 33.0%, followed by the South-Southeast region with 21.6%, Central-Western with 20.6%, Central with 14.3%, and the Northwest with 10.4%. Regarding natural gas production, the CNH made an estimation for the next 15 years (maximum and minimum scenarios), detailed as to enable the analysis of the different kind of activities, regions and quality of hydrocarbons. Two main components were considered for estimating the production: extraction and exploration. For extraction, there have been considered those fields with discovered reserves, where there is certainty about the existence of the subsoil resources, but not about their amount. The exploration component includes information about the exploratory opportunities which could be discovered and developed. To define the production and investment profiles of the component, an estimation model was designed which incorporates all available information corresponding to exploratory opportunities and to the business reasoning of the potential firms to develop those opportunities.

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In the case of the minimum scenario, production is estimated to reach a volume of 2,691.8 MMCFD by 2030, a decrease of 51.1% regarding 2015. And for the maximum scenario, production is expected to reach a volume of 4,628.2 MMCFD by 2030, a decrease of 15.9% regarding 2015. As for infrastructure, on July 25, 2016, the first annual revision of the Quinquennial Plan for the Expansion of the SISTRANGAS 2015-2019 (Quinquennial Plan) was performed to verify the validity of the projects contained in the Quinquennial Plan published on October 14, 2015, according to the behavior of the natural gas market. By 2030, it is expected that natural gas imports will increase by 52.4% regarding 2015, reaching a volume of 5,406.9 MMCFD and an AAGR of 2.8% during 2015-2030. It has been considered that, from 2017 on, the total imports of gas will be performed through gas pipelines, due to the startup of the new gas-pipelines infrastructure in the coming years. For exports, these will reach a volume of 113.9 MMCFD by 2030, which will represent a 15.9% AAGR during 2015-2030.

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1. Chapter One. Natural Gas Regulatory Frame

1.1. Implementation of the Reform in Activities of the Natural-Gas Chain Value

The Energy Reform led to a structural change that seeks to enable the potential of the energy sector and contribute thus to the country's development through the sustainable and efficient use of natural resources, and a new organization in the industry of exploration and extraction of hydrocarbons.

This change on the industrial organization of the natural gas sector was the result of the new legal and regulatory frame emanated from the Decree which amends and adds varied regulations of the Political Constitution of the United Mexican States, on energy matter, issued in the Official Journal of the Federation (DOF, for its Spanish acronym) on December 20, 2013, and made it necessary a new methodology of maximum prices for first-hand sale1s (FHS) which considers the fundamental changes in the industry's structure, organization, and functioning.

The value chain involves different activities, like exploration, extraction, production, transportation, storage, distribution y trading to the end user.

FIGURE 1. 1 NATURAL GAS SUPPLY CHAIN

Source: SENER with information from the CRE and CENAGAS.

1 First-hand sales are understood as the first sales in national territory performed by Pemex, its subsidiary organisms or divisions, and any other state productive enterprise or private company which, on behalf or by request of the State, to a third party, or between them. Such sale shall be performed right after the product has been sent out from the processing plants, refineries, injection points for imported product, entry pipelines, or in the injection points of the hydrocarbons coming directly from the production fields.

PEMEX/Privateparties

Import (PEMEX/CFE)

PrivateImport

FHS

End users

Distribution

Trading

ElectricitySector

Low-consumptionend users*

Private Transportation

Cenagas Transportation

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To ensure the country's energy safety, the natural gas supply, its open access, the market's diversification, and the protection of low-consumption end users the CRE presented, by the end of 2015, the regulatory instruments for the natural gas industry (see Figure 1.2).

FIGURE 1. 2 REGULATING INSTRUMENTS FOR THE NATURAL GAS MARKET

Source: SENER with information from the CRE (New Regulatory Frame in Matter of Natural Gas)

1.1.1. Exploration and Extraction Activities of Natural Gas

These activities have undergone the biggest advances since the Energy Reform, such as Round Zero, Round One, and Round Two, which have been carried out for the State to receive the income which will contribute to the Nation's development in the long term.

As for Round Zero, the SENER granted PEMEX 489 allocations, from which 108 allow it to perform exploration activities; 286, extraction; and 95 correspond to production fields allocated for a two-year period or until the State puts them out for tender2.

Round One is formed by four international public tenders. The first tender for Share-Production Contracts for the Exploration and Extraction of Hydrocarbons was issued on December 11, 2014, and was formed by 14 areas located in shallow water of the Gulf of Mexico, within the oil provide Southeast Basins. This province is the most explored one and has the largest percentage of cumulated production of the country. On July 15, 2015, two out of the fourteen areas were allocated; and, finally, on September 4, 2015, the CNH made

2 Quinquennial Tender Plan for the Exploration and Extraction of Hydrocarbons 2015-2029, p. 9.

Permits for trading natural gas.

Applications and permits for the activities of storage, transportation, distribution, and retailing of oil, unprocessed natural gas, oil products, petrochemicals, and biofuels, as well as for the management of intregrated systems.

Open access and service provision of transportation through pipeline and natural-gas storage.

Open access and service provision of distribution through pipeline of natural-gas.

FHS Asymmetric regulation (General Terms and Conditions Generales of First-Hand Sales) and trading of natural gas.

Methodology of FHS prices.

Protection to natural gas low-consumption users.

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public the official verdict with the winning bidders: Sierra Oil & Gas in consortium with Talos Energy, LLC and Premier Oil, PLC.

The second tender of Round One, carried out on February 27, 2015, was formed by five areas located in shallow water of the Gulf of Mexico, within the oil province Southeast Basins. The results of this tender were published on September 30, 2015, in which three areas with Share-Production contracts were allocated for extracting hydrocarbons. The first contract for the fields Amoca, Tecoalli, and Mizton was signed on November 30, 20153, while the contracts for the fields Hokchi, Pokoch, and Ichalkil were signed on January 7, 20164

The winning companies of the second tender were: Eni International BV, Pan American Energy LLC in consortium with E&P Hidrocarburos y Servicios SA de CV, and Fieldwood Energy in consortium with Petrobal SAPI de CV.

On May 12, 2015, the third call for tender of Round One was published, which included 25 contractual areas for offshore extraction under a Licensing modality. These 25 areas were grouped into three geographic areas identified as Burgos Fields, North Fields, and South Fields5. On December 15, 2015, the fields were completely allocated. The allocated contracts will require an associated investment of approximately $1,100 million USD during the next 25 years6. Finally, on May 10, 2016 the CNH signed, on behalf of the Mexican State, 19 out of the 25 licensing contracts for extracting hydrocarbons which will be in charge by twelve new contractors; the remaining six were signed on August 25, 20167.

The fourth tender of Round One was published on December 17, 2015. This stage comprises ten areas located in the Gulf of Mexico deep water, within the oil provinces Tampico-Misantla and Saline Basin8. According to the final version of the call for tender, published on August 31, 2015, the event for the submittal and opening of proposals, as well as the announcement of the winning bidders was held on December 5, 20169.

On July 19, 2016, the first call for tender of Round Two was published, comprising fifteen contractual areas located in Gulf of Mexico shallow water, within the oil provinces Tampico-Misantla, Veracruz, and Southeast Basins. According to the call, the event for the submittal and opening of proposals, and the announcement of the winning bidders will be held on March 22, 201710. Round 2.3 comprises fourteen contractual areas under the Licensing Contract modality. These contractual areas are in the oil provinces of Burgos, Tampico-Misantla, and Southeast Basins.

Finally, on August 23, 2016, the requirements for the second call for tender of Round Two were published, comprising twelve contractual areas under the Licensing-Contract modality. From these, nine are located in the Burgos Basin, two in Cinturon Plegado of Chiapas, and one in the Southeast Basins11. The event for the submittal and opening of proposals, as well as the announcement of the winning bidders will be held on April 5, 2017, according to the call for tender12.

As for the agreement and provisions for the exploration and extraction activities, the following have been published in the Official Journal of the Federation (DOF, for its Spanish acronym):

3 http://www.gob.mx/sener/presentacion-de-la-firma-del-primer-contrato-de-la-2a-licitacion-de-la-ronda-1. 4 http://www.gob.mx/sener/articulos/se-firman-los-contratos-de-la-2-licitacion-de-la-rondauno-area-contractual-2-hokchi-y-4-pokoch-e-ichalkil. 5 http://rondasmexico.gob.mx/l03-bloques/ 6 http://www.gob.mx/sener/prensa/resultados-de-la-tercera-convocatoria-de-la-ronda-uno. 7 http://www.gob.mx/cnh/acciones-y-programas/contratos-tercera-licitacion-de-la-ronda-1?idiom=es 8 http://rondasmexico.gob.mx/l04-ap-bloques/ 9 http://rondasmexico.gob.mx/wp-content/uploads/2016/08/20160831-9a-VERSION-FINAL-DE-BASES-limpia-aguas-profundas.pdf. pág. 19. 10 http://rondasmexico.gob.mx/wp-content/uploads/2016/07/Bases-Aguas-Someras-R02-L01_n.pdf pág.20. 11 http://rondasmexico.gob.mx/r02-licitaciones/ 12 http://rondasmexico.gob.mx/wp-content/uploads/2016/08/20160823-Proyecto-Bases-Terrestres-R02-L02.pdf pág.22

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• Agreement CNH.E.02.001/16 was published on February 11, 2015, whereby the CNH amends articles 43, section II, and 46, first paragraph, and adds the seventh transitory article to the technical Guidelines on hydrocarbons measuring, issued on September 29, 2015. This amendment was performed to grant legal certainty to the subject regulated according to the following:

I. Regarding articles 43 and 46, the references about articles 43 and 4 are modified in order to be able to comply with those articles, and,

II. Regarding the addition of the Transitory, to enable Pemex to measure the volume and quality of the hydrocarbons extracted from each allocation, by establishing different measuring points.

• On April 15, 2016, the Agreement CNH.E.09.002/16 was published, through which the CNH amends article 17 and adds the eighth transitory of the Guidelines which regulate the process of quantification and certification of the Nation's reserves, and the report of the related contingent resources. This amendment grants more legal certainty to the subjects regulated according to the following:

III. Article 17 of the Guidelines is amended so the oil operators may consider the extensions for allocations and contracts in the quantification and certification of hydrocarbons reserves, considering the methodology of the Petroleum Resources Management System (PRMS).

IV. The eighth transitory of the Guidelines is added, so during the first certification cycle, Pemex could be able to recognize or document the reserves' values based on the economic limit corresponding to the certified fields related to each allocation.

• The amendments and additions previously cited, derive from principles of certainty, legality, objectivity, and impartiality which rule the administrative procedures of the CNH, according to the Federal Law on Administrative Procedure and to the Law of the Coordinated Regulatory Organs for the Energy Matters.

• On April 24, 2016, the Agreement CNH.03.005/16 was published, through which the CNH carries out varied amendments and additions to the Guidelines which regulate the procedure for the submittal, approval, and supervision of the compliance with the exploring and development plans for the extraction of hydrocarbons, as well as for their amendments.

• These amendments provide legal certainty to the assignees and contractors regarding the payment to the administration for the exploitation in technical matters of the allocations and contracts for the exploration and extraction of Hydrocarbons by the Commission.

• Finally, on August 24, 2016, the Agreement CNH.E.29.002/16 was issued, by which the CNH amends articles 42 and 43 of the Technical Guidelines on Matters of Hydrocarbons' Measuring.

• Such amendments consist in, that as long as the regulated subjects implement mechanisms and measuring points according to the plans, the measuring points may be used when these are useful for measuring, defining, or assigning the volume, quality, and price of each kind of hydrocarbon.

1.1.2. Natural Gas Processing

According to article 48 section I, of the Hydrocarbons Law, which establishes that the permits to perform activities for treating and refining oil, to process natural gas, and to export and import hydrocarbons and oil products, shall be granted by the Secretariat of Energy. Likely, article 4 of the Regulations for the activities referred to in the Third Title of the Hydrocarbons Law, establishes SENER as the organ to regulate and supervise, as well as to grant, modify, and revoke permits for processing natural gas.

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On October 1st, 2015, the Administrative General Provisions which establish the formats and specifications of the requirements referred to in articles 50, 51, and 121 of the Hydrocarbons Law for the granting of permits on matters of oil treatment and refining, as well as of the processing of natural gas were published in the DOF; likewise, on November 19, 2015, the Administrative General Provisions which establish the models for the permits' titles on matters of oil treatment and refining, as well as of the processing of natural gas, provisions which intend to make the process for granting permits transparent and efficient, and comply with what is established in the applicable legal instruments.

In this sense, on February 27, 2015, Pemex requested SENER for permits to process natural gas for the Gas Processing Complex: Arenque, Burgos, Cactus, Ciudad Pemex, Coatzacoalcos, La Venta, Matapionche, Nuevo Pemex, and Poza Rica. Thus, SENER, through the General Director of Natural Gas and Petrochemicals, granted the permits for the nice Gas Processing Complexes on June 30, 2015.

1.1.3. Storage

For the storage activity, the CRE oversees and regulates, grants, modifies, and revokes permits for storing hydrocarbons as well as the storage related to pipelines, and the management of the Integrated Systems including SISTRANGAS13. On January 13, 2016, the Resolution by which the CRE issues the Administrative general provisions on open-access and transportation by pipeline servicing and natural-gas storage matters were published. This Resolution establishes the criteria to which the permit holders of natural-gas storage shall be subjected, in regards to the obligation and conditions to ensure open access, and not improperly discriminatory, to their facilities and services, the modalities of open seasons and the implementation of electronic bulletins. Besides, it foresees the modalities for hiring the services to use the systems' capacity; and define the criteria to which these facilities will be subjected so they can be considered as own uses, as well as the conditions under which the permit holders may use a part, or all their systems for storing natural gas in their property. According to this Resolution, the nature of the storage service comprises receiving the natural gas in one point of the system to deposit or guard it, measuring the quality and quantity of the received product, its eventual blending to bring it into specification, and every action or operation necessary for its subsequent delivery, in one or diverse acts, in a defined point of the same system, complying with what is established in the Terms and Conditions for the Provision of Services (TCPS). Warehousers will not be allowed to alienate the natural gas they store, unless it has been transported or stored for an emergency, fortuitous events, or force majeure, if they prove it was necessary for ensuring the integrity of the Systems and the continuity, uniformity, stability, and quality in the provision of services. The main business purpose of storage permittees will consist on providing the permitted services, as well as any related activity for achieving such purpose.

1.1.4. Transportation

The transportation activity comprises receiving natural gas in one point of the system, its conveyance through pipelines, the measuring of the quality and amount of the received product, and every action or operation necessary for delivering it in a different point of the same system, and which do not entail the alienation or trade of the transported product, in compliance with what is established in Part 1, Section A, point 4.1 of Resolution number RES/900/2015 published on January 13, 2016.

The transport permit holders will have as their main business purpose to provide their permitted service, as well as its related activities for achieving such purpose. Transporters may have, as part of their business

13 Article 5 of the Regulations for the Activities Referred to in Third Title of the Hydrocarbons Law.

20

purpose, the management of the integrated systems, for which they shall subject to the administrative provisions issued by the CRE for such effect.

About transportation, the resolutions and agreements that have been issued are used as regulatory instruments.

FIGURE 1. 3 RESOLUTIONS ON TRANSPORTATION

Source: SENER with information from resolutions RES/776/2015 and RES/900/2015, published in the DOF.

1.1.5. Distribution

According to the Regulation of the activities referred to in the Third Title of the Hydrocarbons Law, distribution comprises the activities of purchasing, receiving, keeping, and, if the case, convey natural gas and oil products for being supplied to the public or final consumption. Distribution can be carried out through pipeline, tank truck, delivery vehicles, portable container, pressurized portable containers, as well as any means established by the CRE in the Administrative general provisions, for its delivery to users or final users, in their facilities or utilization facilities, accordingly.

The distribution service through pipelines comprises the activities of receiving, conveying, and delivering natural gas and oil products through a network of pipelines and facilities to users or end users. Each distribution permit through other means different to pipelines shall be granted for a specific facility or group of facilities and a defined capacity.

The following agreements and resolutions have been issued about distribution, and are used as regulatory instruments:

• On February 15, 2016, it was published the Resolution by which the CRE issues the Administrative general provisions on matters of protection for the low-consumption end user of natural gas. Such provisions establish the guidelines to which the traders and distributors shall be subjected, when

•These provisions deal with the configuration of themeasurement systems used to define the amounts -whether volume or mass- of hydrocarbons, oil products,and petrochemicals conveyed through the pipelinetransportation systems of the country; likewise, theyseek to promote the efficient development of themarkets and the industry, protect the users' interests,and foster an appropriate national coverage.

Resolution whereby the Energy Regulatory Commission issues the general administrative provisions

in measurement matter applicable to the activity of transportation

through pipeline of hydrocarbons, oil products, and petrochemicals.

(December 17, 2015)

•These provisions expound the concepts, criteria, andguidelines to which, according to the Hydrocarbons Lawand the Regulation, shall be subjected the serviceprovision of Transportation through Pipeline and theNatural-Gas Storage, under effective open access andnot improperly discriminatory for the use of the capacityof the respective systems, and thereby, promote anefficient development of the markets and the industry,protect the users' interests, and foster an appropriatenational coverage of such services.

Resolution whereby the Energy Regulatory Commission issues the general administrative provisions

on open access, and service provision of transportation

through pipeline and natural-gas storage.

(January 13 , 2016)

21

offering trading services to low-consumption end users of natural gas, to avoid any abuse or improper exercise of power in detriment of those users.

• On November 27, 2015, it was the published the Agreement by which the CRE amends the previous decree which issues the requirements for the International Public Tender LIC-GAS-021-2012, which aims to grant the first permit for distributing natural gas in the Geographic Zone of Morelia. This agreement seeks to implement a Tender mechanism which enables, tenders to submit their technical and economic proposals, and the Commission to carry out the submittal and opening events for such proposals, as well as their assessment, in a more simple, agile, and transparent way.

1.1.6. Natural Gas Trading

According to the Regulations for the Activities Referred to in Third Title of the Hydrocarbons Law, trading is defined as the activity of "offering" users or end users, together or separately, one or more of the following services:

I. The buying and selling of hydrocarbons, oil products or petrochemicals;

II. The management or hiring of services for transportation, storage, or distribution of such products; and

III. The provision or intermediation of value-added services on behalf of users or end users for the activities referred to in the Regulations.

User and end user are defined as follows:

I. User: The permit holder which request or use other permit-holder's services.

II. End user: The individual who purchases for his/her own use hydrocarbons, oil products, or petrochemicals.

Article 5, fraction V, of the Regulations for the Activities Referred to in Third Title of the Hydrocarbons Law points out the CRE is in charge of regulating, supervising, granting, amending, and revoking permits for trading natural gas, oil products, and petrochemicals.

In this sense, the following resolutions and agreements were published in the DOF and which will be used as regulatory instruments (see Figure 1.4):

FIGURE 1. 4 RESOLUTIONS ON TRADING

•These provisions aim to establish the mechanisms to facilitate and speed up the issuing of permits to trade natural gas, oil products, and petrochemicals, and for the applicants, to afford the necessary tools to gather the required information and documentation to carry out the corresponding tramit.

Resolution whereby the Energy Regulatory Commission issues the general administrative provisions which establish the requirements to submit applications for permits to trade natural gas, oil products, and petrochemicals (09 / 06/15).

•This resolution enables the CRE to gather information about the prices, discounts, and volumes in trading matter; therefore, it is mandatory to issue the general administrative provisions which establish the formats for the submittal of information on the trading of hydrocarbons, oil products, and petrochemicals.

Resolution whereby the Energy Regulatory Commisision issues the general administrative provisions which establish the formats for the submittal of information of the permittees trading hydrocarbons, oil products, and petrochemicals. (06/01/16)

22

Source: SENER with information from the agreements and resolutions published on the DOF.

•This resolution on only applicable to Petróleos Mexicanos, its subsidiary organisms, its affiliates or divisions, without prejudice that the CRE approves and issues an metholodogy applicable to other State Productive Enterprises, or legal entity that on behalf of and ordered by the State performs FHS of natural gas.

Resolution whereby the Energy Regulatory Commission issues the methodology to define the maximum prices for natural gas subjected to first-hand sales (15/02/16).

•This resolution aims to limit the dominant power of Petróleos Mexicanos, by promoting a greater involvement of economic agents who will contribute to the efficient and competitive development of the markets.

•Thereby, it is hereby resolved the Petróleos Mexicanos, understood as the State Productive Enterprise, its subsidiary organisms, its affiliates or divisions, and any other entity controlled by them, shall instrument the Program for Contracts Transfer to transfer part of its portfolio contracts on natural gas trading in a term of maximum 4 years, a transfer equal to 70% of the trading volume currently carried out in the domestic market.

Resolution whereby the Energy Regulatory Commisision issues the general administrative provisions applicable to the trading of natural gas, on conditions of assymmetric regulation to Petróleos Mexicanos, its subsidiary organs, its affiliates and divisions, and any other entity controlled by such entities (15/02/16).

•The general terms and conditions for natural gas FHS are included in the asymmetric regulation which, under the terms of the Thirteenth Transitory of the Hydrocarbons Law, seeks to limit the dominant power of Petróleos Mexicanos, with the purpose that PetróleosMexicanos, its subsidiary organisms, divisions or affiliates, and any other State Productive Enterprise, or legal entity, that on behalf and ordered by the State, perform natural gas FHS in compliance with the applicable legal and regulatory provisions, without incurring in improperly discriminatory practices.

Resolution whereby the Energy Regulatory Commisision approves and issues the general terms and conditions for natural gas first-hand sales (19/02/16).

•This agreement establishes the procedure to be pursued by those entities in the event of cross-holding described in the sixteenth whereas of this agreement, ir order to obtain the authorizaation of such cross-holding by the CRE.

Agreement whereby the Energy Regulatory Commission interprets, for administrative purposes, the cross-holding referred to in the second paragraph of article 83 of the Hydrocarbons Law, and sets the procedure to authorize it (03/03/16).

•This resolution ameds the Resolution whereby the Energy Regulatory Commission issues the general administrative provisions whichestablish the requirements to submit applications for permits to trade natural gas, oil products, and petrochemicals, identified under the number RES/370/2015, in order to include the hydrocarbons in every reference related with the list of products to which such instrument is applicable, on the understanding that the references to natural gas shall be replaced with Hydrocarbons.

Resolution whereby the Energy Regulatory Commisision amends the previous resolution which issues the general administrative provisions establishing the requirements to submit applications for permits to trade natural gas, oil products, and petrochemicals, identified with the number RES/370/201, in order to include the hydrocarbons in the list of products subjected to a trading permit (11/03/16).

•The activity for trading hydrocarbons, oil products, or petrochemicals is understood to be performed within the national territory starting from the moment when it is offered to a user or end user, regardless of: i) the place where the offer is made, or ii) if the contracting of any of the services mentioned in the sections of article 19 of the Hydrocarbons Law comes to effect.

•The offer shall be binding, intended to contract any of the following services, individually or separately: i) sale and purchase of hydrocarbons, oil products, or petrochemicals; ii) management or contracting the services of transportation, storage, or distribution of such products; and iii) service provision or intemediation of aggregate-value services to benefit the user or end user; the latter, once the offers are addressed to Users or End Users located in the national territory and, in case of contracting the offered services, these will consequently will become effective in the national territory.

•Thereby, whoever performs the activities mentioned in the previous subsections, will require a permit granted by the Energy Regulatory Commission. The latter, pursuant to what is established in articles 49 of the Hydrocarbons Law, and 19 of the Regulataion of the activities referred to in the Third Title of the Hydrocarbons Law, and taking into consideration the extent of the definition of User and End User contained in sections XXII and XXIII of article 4 of that Regulation.

Agreement of the Energy Regulatory Commission which establishes the criterium thata shall prevail in the development of the activities for trading hydrocarbons, oil products, or petrochemicals (09 / 06/15).

23

1.1.7. Other Regulating Instruments

The "Public Policy for the Implementation of the Natural Gas Market" was issued to foster the development of new infrastructure and a larger natural-gas production, and establishes the necessary conditions to create a competitive natural-gas market and to ensure energy safety, under the principles of open access to infrastructure, high-quality information, and competitive tariffs.

This policy displays short, mid, and long-term actions, which will be gradually implemented to ensure a safe and efficient supply of hydrocarbons within the national territory (see Figure 1.5).

FIGURE 1. 5 ACTIONS TO IMPLEMENT PUBLIC POLICY

Source: SENER

As for implementing the Capacity Reserve and an effective open access in the country, on October 2016, the CENAGAS made available to the General Public the Available Capacity in the SISTRANGAS during the Open Season 2016.

The SISTRANGAS is a group of interconnected and integrated systems for natural gas transportation for tariff purposes. It is formed by the National Gas-Pipeline System (SNG, for its Spanish acronym) and six peripheral systems which bring technical and economic benefits such as: redundancy, operating efficiency, guarantee of supply, and competitive tariffs.

The SISTRANGAS has a 10,068-km length, including the pipeline Jaltipan-Salina Cruz. It runs across the country and reaches twenty (20) Federal Entities. It has a total transportation capacity of about 6,196 million cubic feet per day; 24 injection points; and 112 extraction points. The CRE assigned to the State Productive Enterprises (EPE's, for its Spanish acronym) the indispensable capacity to perform their activities, while the remaining transportation capacity will be made available to the general public, prioritizing those interested who have Acquired Rights.

SISTRANGAS available capacity will be assigned under the principles of Open Access and Not Improperly Discriminatory Treatment, to increase the number of users of the transportation service through pipeline.

Short term

(2016)Capacity reserve and effective open access

Report of commercial transactions

Definition of the Program for the Gradual Transfer of Pemex Contracts

Medium Term

(2017)Management of the capacity reserve and the effective open access

Partial liberation of the natural gas price

Long Term

(2018)Total liberation of the natural gas price

SISTRANGAS tariff reconfiguration

24

On December 20, 2016, the CRE approved the amendment and rescheduling of the first Open-Season Procedure to reserve firm capacity in the National Integrated Transportation and Storage System of Natural Gas (Procedure).

With this, more reasonable terms are given, and it sums up activities to the Procedure to match with the release and auction of Entry Pipelines capacity, and with the Program to Transfer the Trading Contracts of Pemex.

Likewise, to ensure the access to timely, relevant, and thorough information, CENAGAS will upload in its website http://www.gob.mx/cenagas, a Data Room with information booths on the respective consumption history, allocations to the EPE, and to the Independent Energy Producers, in-transit and congestion volumes, and the current conditions of pressure (flow diagram).

Interested parties may submit a Service Request proposing a first additional unit cost (ß) whose average result by route and group (General Public and Acquired Rights) will be published by the end of the period for receiving the first proposals and to overcome deficiencies. The period for receiving requests will end on February 10.

After the ß averages are published, those interested will have 10 working days for send a counterproposal for ß which will be evaluated by CENAGAS. From those results, which will be notified during the second half of April 2017, the EPE will release capacity from the Entry Pipelines which CENAGAS will put up for auction through an Electronic Bulletin.

When the Entry Pipeline's allocation procedure is finished, the SISTRANGAS users may negotiate (among them) capacities and interchange routes.

Due to the latter, the contracts for firm capacity will be signed starting on May 22, 2017, considering that, for purposes of contracting, the users will pay ß according to a second-price auction criteria. Users with saturated routes will not pay ß.

Lastly, CENAGAS will offer SISTRANGAS users a training on nomination and programming which will include training on the computing system to be used.

Thus, and under more certain conditions, access to information and transparency, on July 1, 2017, the contracts for firm capacity reserve will become effective with a one-year validity14.

14 Secretariat of Energy, https://www.gob.mx/sener/prensa/modificación-y-recalendarizacion-de-la-primer-temporada-abierta-para-reservar-capacidad

25

FIGURE 1. 6 SCHEDULE FOR THE FIRST OPEN SEASON

_/1. Send to the E-mail: temporada-abierta2016@cenagas.gob.mx _/2. In the office of CENAGAS: Insurgentes Sur 388, piso 12, Col. Del Valle, Del. Benito Juárez, C.P. 03100, Monday to Friday from 9:00-15:00 h and from 16:00-18:00 h. _/3. Contracts signed between May 22 and June 2nd. _/4. Contracts signed between June 5 and 16. Schedule based on the terms established in provisions 17.2 and 17.3 of the open-access DAGS. Holidays considered in the Federal Labor Law. Source: CENAGAS

26

2. Chapter Two. Natural Gas Historic Market

2.1. Natural Gas Domestic Market

This section shows the behavior of the natural gas market, for its supply and demand, starting from the current infrastructure, natural gas prices, domestic balance, and by region.

2.1.1. Domestic Demand

In 2015, the domestic demand for fossil fuels reached a volume of 17,115.0 MMCFDNGE, an increase of 1.7% regarding 2014. From this demand, natural gas had a share of 43.8% with a volume of 7,504.1 MMCFD, seconded by gasoline with a 22.3% share, diesel with 12.7%, coal with 7.3%, LP gas with 6.3%, fuel oil with 4.9%, and petroleum coke with a 2.6%.

FIGURE 2. 1 DOMESTIC DEMAND FOR FUELS, 2015

(million cubic feet per day de gas natural equivalent)

Source: SENER based on information from IMP

2.1.2. Natural Gas Demand by Sector

In 2015, the domestic demand for natural gas increased by 4.1% regarding 2014. The electricity sector had the largest demand with a volume of 3,228.9 MMCFD, followed by the oil sector with 2,200.0 MMCFD, the industrial with 1,375.8 MMCFD, and the private electricity sector with a demand of 568.8 MMCFD. The sectors with the smallest demand were the residential one, with 94.6 MMCFD; services, 33.7 MMCFD; and motor-carrier, 2.4 MMCFD. Every sector increased their demand, except for the oil sector, which decreased by 3.3% regarding 2014.

Natural gas7,504.1

Gasoline3,816.2

Diesel2,177.4

Fuel oil836.9

LP gas1,082.9

Coal1,257.6

Petroleum coke439.8

27

FIGURE 2. 2 NATURAL GAS DOMESTIC DEMAND BY SECTOR, 2015 (percentage share)

Source: SENER based on information from IMP

Electricity Sector

In 2015, the electricity sector demanded a total volume of fuels of 5,494.4 MMCFDNGE, an increase of 4.9% regarding 2014. From this volume, natural gas had a share of 69.1%, seconded by coal with 16.5%, fuel oil with 11.6%, and petroleum coke and coal with 1.8% and 1.0%, respectively.

As for natural gas, its demand increased by 8.5% regarding 2014, reaching a volume of 3,797.6 MMCFD. In 2015, the Federal Electricity Commission (CFE, for its Spanish acronym) used more than 2,200 MMCFD of natural gas to operate its power stations; the latter, due to the high availability of gas, which helped reducing the consumption of more expensive and polluting fuels like fuel oil and diesel. To expand the natural gas offer within the country, CFE fosters the development of projects to transport natural gas for conveying this fuel from where it is produces up to where it is consumed15.

This sector decreased its consumption of fuel oil, diesel, and petroleum coke, but increased its consumption of natural gas and coal. The following figure shows the fuels' demand by the end of 2015.

FIGURE 2. 3 DOMESTIC DEMAND FOR FUELS IN THE ELECTRICITY SECTOR, 2015. (MMCFDNGE)

Source: SENER based on information from IMP.

15 Annual Report 2015, CFE, p. 20.

Oil29.3%

Industrial18.3%

Public electricity43.0%

Private electricity7.6%

Residential 1.3% Services

0.4% Motor carrier0.03%

Natural gas3,797.6

Fuel oil637.5

Diesel54.0

Coal904.7

Petroleum coke100.7 TOTAL DEMAND

5,494.4 MMCFDNGE

28

Motor-Carrier Sector

In 2015, the total demand for fuels in the motor-carrier sector reached 5,783.7 MMCFDNGE, an increase of 0.7% regarding 2014. In this sector, gasoline was the most demanded fuel with a volume of 3,807.7 MMCFDNGE, a share of 65.8%; followed by diesel with 1,836.8 MMCFDNGE, LP gas with 136.9 MMCFDNGE; and natural gas with 2.4 MMCFDNGE.

As for natural gas, it increased by 2.5% regarding 2014, mainly due to an increase of the vehicles using this fuel; on the contrary, the vehicle fleet using diesel and LP gas decreased (see Annex Table A.1).

FIGURE 2. 4 DEMAND FOR FUELS IN THE MOTOR-CARRIER SECTOR, 2015 (percentage share)

Source: SENER based on information from IMP.

Industrial Sector

In 2015, the demand for fuels reached a volume of 2,410.7 MMCFDNGE, an increase of 3.6% regarding 2014. Natural gas was the most used fuel in this sector, with a demand of 1,375.8 MMCFD and an increase of 4.7% regarding the previous year, which can be explained to a larger availability of natural gas from the new gas-pipelines projects in areas where there was not access before.

The branches in the industrial sector which consumed the largest volume were: basic metals with 347.4 MMCFD, seconded by the chemical branch with 339.1 MMCFDNGE, diesel with 171.8 MMCFDNGE, LP gas with 113.3 MMCFDNGE, and fuel oil with 57.8 MMCFDNGE.

As for the other fuels, coal was second in use, with a volume of 352.9 MMCFDNGE; it was followed by petroleum coke with 339.1 MMCFDNGE; LP gas with 113.3 MMCFDNGE; and fuel oil with 57.8 MMCFDNGE.

LP gas2.4%

Compressed natural gas

0.04%

Gasoline65.8%

Diesel31.8%

29

FIGURE 2. 5 DEMAND FOR FUELS IN THE INDUSTRIAL SECTOR, 2015 (percentage share)

Source: SENER based on information from IMP.

Oil Sector

In 2015, the oil sector's demand decreased by 3.7% regarding 2014, reaching a volume of 2,481.4 MMCFDNGE. Natural gas is the most used fuel in this sector, even if it decreased by 3.3% regarding the previous year, followed -far below- fuel oil with a volume of 141.6 MMCFDNGE, diesel with 114.9 MMCFD, LP gas with 16.3 MMCFD, and gasoline with 8.6 MMCFDNGE.

The exploration and production activities demanded 1,254.4 MMCFD; refining, 385.3 MMCFD; petrochemistry, 236.1 MMCFD; gas and basic petrochemistry, 182.1 MMCFD; cogeneration Nuevo Pemex, 87.6 MMCFD; and Corporate, 0.3 MMCFD (see Annex Table A.3).

FIGURE 2. 6 DOMESTIC DEMAND FOR FUELS IN THE OIL SECTOR, 2015 (Percentage share)

Source: SENER based on information from IMP.

Natural gas 57.1%

Fuel oil 2.4%

Diesel 7.1%

LP gas 4.7%

Petroleum coke 14.1%

Coal 14.6%

Natural gas88.7%

Fuel oil5.7%

Diesel4.6%

LP gas0.7%

Gasoline0.3%

30

Residential Sector

In 2015, the residential sector's demand decreased by 0.9% regarding 2014, reaching, 1,187.4 MMCFDNGE. LP gas was the most used fuel in this sector, reaching 653.5 MMCFDNGE; seconded by firewood with 439.4 MMCFDNGE; and natural gas with 94.6 MMCFD. Though natural was the least used fuel, it increased by 7.8% regarding 2014.

It is important to point out that the use of firewood has decreased since 2011, according to the updated information from the National Institute of Statistics and Geography (INEGI, for its Spanish acronym) (see Annex Table A.4).

FIGURE 2. 7 DOMESTIC DEMAND FOR FUELS IN THE RESIDENTIAL SECTOR, 2015 (Percentage share)

Source: SENER, based on information from IMP.

Services Sector

In 2015, the demand for fuels in the services sector increased by 8.0% regarding 2014. LP gas was the most demanded fuel with a volume of 162.9 MMCFDNGE, seconded by firewood with 70.3 MMCFDNGE and natural gas with 33.7 MMCFD. Like in the residential sector, natural gas increased by 12.9% regarding 2014, with a AAGR of 12.6% during 2005-2015, while the AAGR for LP gas and firewood were of 0.5% and -1.1%, respectively.

The historic data for this sector were updated since 2011 with information from INEGI and show a decrease in the use of firewood (see Annex Table A.5).

Natural gas8.0%

LP gas54.8%

Firewood37.2%

31

FIGURE 2. 8 DOMESTIC DEMAND FOR FUELS IN THE SERVICES SECTOR, 2015 (Percentage share)

Source: SENER, based on information from IMP.

2.1.3. Natural Gas Regional Demand

The country is divided in five regions to enable the analysis of the natural gas demand, namely: Northwest, Northeast, Central-Eastern, Central, and South-Southeast.

In 2015, almost every region increased their demand regarding 2014, except for the South-Southeast region, which decreased by 6.4%.

In the Northwest region, the demand was of 606.2 MMCFD, an increase of 22.1% regarding 2014; nonetheless, it had the smallest share in the total demand with 8.1% from the domestic total. Within the region, the state of Baja California demanded 349.4 MMCFD and Sonora, 256.8 MMCFD.

The Northeast region had the largest demand at domestic level with 2,464.2 MMCFD, 32.8% from the domestic total. This level of demand was 4.9% higher than the one of 2014. In this region, Tamaulipas and Nuevo León had the largest demands, with 956.1 MMCFD and 724.4 MMCFD, respectively, and followed by Chihuahua with 347.6 MMCFD, Coahuila with 235.5 MMCFD, and Durango with 200.5 MMCFD.

The Central-Eastern region increased by 7.7% regarding 2014, raising from 1,053.6 MMCFD to 1,134.6 MMCFD, equivalent to 15.1% of the domestic total. In this region, Guanajuato and Colima had the largest demands, of 257.4 MMCFD and 31.1 MMCFD, respectively. The states of Jalisco and Aguascalientes had the smallest demands, with 75.1 MMCFD and 31.1 MMCFD, respectively; even if Aguascalientes had the smallest demand, it increased by 63.2% regarding 2014.

The Central region demanded 919.4 MCFD, an increase of almost 20% regarding 2014, and a share of 12.3% from the domestic total. The states with the largest demands were Estado de México with 361.5 MMCFD and Hidalgo with 269.3 MMCFD. The states with the smallest demand were Mexico City and Morelos, with 69.6 MMCFD and 12.5 MMCFD, respectively.

Finally, the South-Southeast region had a decrease of 6.4% in its demand, falling from 2,541.9 MMCFD to 2,379.7 MMCFD in 2015. This region was second in demanding natural gas with a share of 31.7% from the domestic total. Veracruz was the state with the largest demand with a volume of 862.7 MMCFD, a decrease of 9.7% regarding 2014. On the other hand, Oaxaca had the smallest demand with a volume of 0.1 MMCFD (see Annex Table A.6).

Natural gas

12.6%

LP gas61.0%

Firewood26.3%

32

FIGURE 2. 9 NATURAL GAS REGIONAL DEMAND, 2015 (million cubic feet per day)

Source: SENER, based on information from IMP.

2.1.4. Natural Gas Supply

Gas Remnant Reserves

The total Remnant reserves by January 1st, 2016 reached a volume of 31,904.7 billion cubic feet (BCF), a fall of 41.9% regarding 2015, due to the drop of crude oil prices and to budget cuts which put downward pressure on the development activities of Petroleos Mexicanos (Pemex), and which resulted in the reallocation of resources to more profitable areas. From the total volume of gas reserves, 22,421.6 MMCFD corresponded to associated gas, and 9,483.1 MMCFD to non-associated gas.

Northwest Region: 606.2 MMCFDBaja CaliforniaBaja California SurSonoraSinaloa

Northeast Region: 2,464.2 MMCFD

CoahuilaChihuahuaDurangoNuevo León Tamalipas

Central-Eastern Region: 1,134.6 MMCFDAguascalientesColimaGuanajuatoJaliscoMichoacán NayaritQuerétaroSan Luis Potosí Zacatecas

Central Region: 919.4 MMCFDDistrito Federal HidalgoEstado de MéxicoMorelosPueblaTlaxcala

South-Southeast Region: 2,379.7 MMCFDCampecheChiapasGuerreroOaxacaQuintana RooTabascoVeracruzYucatán

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TABLE 2. 1 NATURAL GAS TOTAL REMNANT RESERVES, 2004-2016* (billion cubic feet)

* Figures by January 1st of each year. Source: CNH.

The proven reserves by January 1st, 2016, were of 12,651.4 MMCFD, whose largest volume was located in offshore areas with a volume of 6, 501.2 MMCFD, followed by shallow water with 5,631.6 MMCFD and deep water with 518.7 MMCFD.

Probable reserves reached a volume of 10,271.7 MMCFD, and were mainly located in offshore areas with 6,876.4 MMCFD, 1,697.5 MMCFD located in shallow water, and 407.7 MMCFD in deep water.

By January 1st, 2016, there was a volume of 10,271.7 MMCFD of possible reserves, from which 7,126.2 MMCFD were located offshore, 2,939.5 MMCFD in shallow water, and the rest in deep water.

FIGURE 2. 10 NATURAL GAS TOTAL REMNANT RESERVES BY CATEGORY (billion cubic feet)

*Figures to January 1st, of each year. Source: CNH

Associated Non-associated

2004 50,412.8 13,480.0

2005 49,431.5 14,447.3

2006 48,183.0 14,171.8

2007 47,403.0 15,642.1

2008 46,067.0 15,291.6

2009 44,710.0 15,664.3

2010 44,046.7 17,189.4

2011 43,294.9 17,980.0

2012 43,710.4 17,930.5

2013 44,402.5 18,826.9

2014 41,768.0 17,896.7

2015 37,313.0 17,576.5

2016 22,421.6 9,483.1

Type of gasYear*

12,651.4

8,981.6 21,633.1

10,271.7 31,904.7

Proven Probable 2P Possible 3P

34

Natural Gas Production

Since 2015, the National Hydrocarbons Commission (CNH, for its Spanish acronym) is in charge of providing production data for the outlooks, and the previous classification used for delineating regions (Northeast Marine, Southwest Marine, South, and North) changes as follows: Chicontepec Paleochannel, Maritime areas with a water depth of more than 500 meters (Deep Water), Maritime areas with a water depth below 500 meters (Shallow Water), Offshore Areas and Non-Associated Gas. This classification is aligned with what is established in chapter V of the Agreement whereby are issued the general provisions for defining the methods to adjust the value of the hydrocarbons from the fees on hydrocarbons.

In 2015, the natural gas production reached a volume of 6,401.0 MMCFD, a decrease of 2.0% regarding 2014; this production includes a volume of 896.7 MMCFD of nitrogen.

By classification, the production of associated gas -which includes shallow water and offshore production- reached a volume of 4,825.7 MMCFD, a slight increase of 0.1% regarding 2014, and a share of 75.4%. The production from shallow water reached 3,283.0 MMCFD, an increase of 6.3% regarding 2014, and a share of 51.3% from the total production; from this volume, 776.9 MMCFD corresponded to nitrogen. On the other hand, offshore production decreased by 10.9% regarding 2014, falling from 1,732.0 MMCFD to 1,542.7 MMCFD, a volume which represented a share of 24.1% from the total production and a content of nitrogen of 119.7 MMCFD.

Finally, the production of non-associated gas reached a volume of 1,573.3 MMCFD, a decrease of 8.0% regarding 2014, and a share of 24.6% regarding the previous year.

TABLE 2. 2 NATURAL GAS EXTRACTION BY REGION, 2004-2014 (million cubic feet per day)

Source: CNH.

Region 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Domestic total 4,818.0 5,356.1 6,058.5 6,918.6 7,030.7 7,020.0 6,594.1 6,384.7 6,370.3 6,531.9 6,401.0 2.9

Deep water 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 n.a.

Shallow water 1,582.5 1,776.4 2,149.7 2,924.2 2,894.0 2,755.4 2,613.9 2,593.1 2,739.2 3,087.9 3,283.0 7.6

Onshore 1,371.6 1,313.6 1,295.7 1,395.6 1,586.3 1,806.5 1,809.2 1,881.8 1,868.5 1,732.0 1,542.7 1.2

Non-associated gas 1,863.9 2,266.1 2,613.0 2,598.8 2,550.3 2,458.1 2,171.0 1,909.8 1,762.6 1,712.0 1,575.3 -1.7

Total extraction 4,818.0 5,356.1 5,915.3 6,289.3 6,534.4 6,337.0 5,913.4 5,676.3 5,678.9 5,757.8 5,504.4 1.3

Deep water 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 n.a.

Shallow water 1,582.5 1,776.4 2,006.6 2,294.8 2,397.7 2,178.2 2,029.3 1,991.6 2,136.1 2,424.8 2,506.1 4.7

Onshore 1,371.6 1,313.6 1,295.7 1,395.6 1,586.3 1,700.6 1,713.2 1,774.8 1,780.2 1,621.0 1,423.0 0.4

Non-associated gas 1,863.9 2,266.1 2,613.0 2,598.8 2,550.3 2,458.1 2,171.0 1,909.8 1,762.6 1,712.0 1,575.3 -1.7

AAGR2005-2015Nitrogen gas production

Production of fuel gas without nitrogen

35

FIGURE 2. 11 PRODUCTION OF ASSOCIATED AND NON-ASSOCIATED NATURAL GAS, 2005-2015

(million cubic feet per day)

Source: CNH.

2.1.5. Natural Gas Infrastructure

One of the Energy Reform advances during 2015 was the transfer of the assets of the National Gas Pipeline Systems (SNG) and Naco-Hermosillo from Pemex to CENAGAS. In this way, PEMEX transferred to CENAGAS nearly nine thousand kilometers of pipelines, with a capacity of more than 5,000 MMCFD of natural gas.

In such way, CENAGAS, as an independent manager of SISTRANGAS, will ensure efficient and equitable competitive conditions for the market which conveys and stores the largest amount of natural gas in the country, and will foster third-parties' share. Thereby, CENAGAS, as a Natural-Gas transportation permit holder (Transporter) shall be in charge of managing the operation and maintenance of the infrastructure transferred band PEMEX. to this Center.

By the end of 2015, the CRE had 31 current open-access permits, from which 28 are operating, one under construction, one about to be constructed, and another one about to start up; these permits represent a total length of 15,755.9 kilometers.

From the total authorized kilometers, 10,068.0 km belong to SISTRANGAS, and are operated and managed by CENAGAS; and 5,687.9 km belong to private companies.

2,954.1 3,090.03,445.4

4,319.8 4,480.3 4,561.9 4,423.1 4,474.9 4,607.7 4,819.9 4,825.7

1,863.92,266.1

2,613.0

2,598.8 2,550.3 2,458.12,171.0 1,909.8 1,762.6

1,712.0 1,575.3

4,818.0

5,356.1

6,058.5

6,918.6 7,030.7 7,020.0

6,594.16,384.7 6,370.3

6,531.96,401.0

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Associated gas Non-associated gas

36

TABLE 2. 3 NATURAL GAS OPEN-ACCESS TRANSPORTATION PERMITS TO DECEMBER 2015.

(*) Startup date of the project's first stage. N/A Not applicable with the permit's status. Source: CRE and CENAGAS

Location StartupLength

(km)

Average volumeMMCFD

Investment(million dollars)

Status

1 GasoPipelines de Chihuahua San Isidro - Samalayuca Dec-97 37.9 322.0 18.2 Operating

2 Igasamex San José Iturbide Huimilpan - San Luis Potosí Mar-98 3.0 13.4 0.4 Operating

3 FINSA Energéticos Matamoros, Tamaulipas Jan-99 7.9 6.1 0.2 Operating

4 Pemex Gas and Basic Petrochemistry Naco - Hermosillo, Son. Mar-99 339.0 109.9 22.1 Operating

5 Pemex Gas and Basic Petrochemistry Sectores Cárdenas, Minatitlán, Veracruz, Cd.Mendoza, Tlaxcala, V. de Carpio, Salamanca, Guadalajara, Madero, Reynosa, Monterrey, Torreon

Jun-99 8,704.0 5,107.0 436.5 Operating

6 Energía Mayakan Tabasco, chiapas, Campeche, Valladolid, Yucatán Sep-99 786.9 300.0 276.9 Operating

7Transportadora de GN de Baja California

Otay, San Diego -Rosarito, Baja California Jun-00 48.0 988.0 28.2 Operating

8 GasoPipelines del Bajío Valtierrilla - Aguascalientes Apr-01 204.2 94.7 56.5 Operating

9 GasoPipeline Rosarito Los Algodones - Tijuana (Baja California) Sep-02 302.4 1,434.0 124.6 Operating

10 GasoPipeline Agua Prieta Frontera México - EUA - Naco, Sonora Dec-02 12.5 210.2 6.6 Operating

11 Tejas de Gas de Toluca Palmillas - Toluca, Edo de México Feb-03 175.3 119.0 31.0 Operating

12 Kinder Morgan Cd. Mier, Tamaulipas - Huinalá, Nuevo León Mar-03 138.6 700.0 82.0 Operating

13 GasoPipelines del RíoFrontera México - EUA-CCC Rio Bravo II, III y IV y Portes Gil, Tamaulipas

Aug-03 57.9 410.0 39.3 Operating

14 GasoPipelines de Tamaulipas Reynosa - San Fernando Nov-03 114.2 1,460.0 238.7 Operating

15 Concepts Energéticos Mexicanos Cerretera Federal Mexicali-Tijuana Dec-03 1.6 9.9 0.8 Operating

16Transportadora de Natural gas de la Huasteca

Naranjos Veracruz-Tamazunchale, S.L.P. Dec-14 356.3 966.2 167.9 Operating

17Energía Occidente de México, S. de R. L. de C. V.

Manzanillo-Colima- Guadalajara, Jalisco Jun-11 310.5 821.0 413.0 Operating

18Tarahumara Pipeline, S. de R. L. de C. V.

Cd. Juárez-Chihuahua Aug-08 383.9 893.4 368.8 Operating

19 GasoPipeline del Northeast, S. de R.L. de C.V, Frontera- Aguascalientes Dec-14 116.4 1,001.7 486.8 Operating

20 GasoPipeline de AguaprietaSasabe-Puerto LibertadPuerto Libertad-GuaymasGuaymas-El Oro

Dec-14 842.6 872.4 922.9 Operating

21 Natural gas del Northwest, S.A. de C.V. Aguascalientes-Calera, Zacatecas Aug-14 174.9 38.1 53.0 Operating

22 GasoPipeline de Morelos Tlaxcala, Puebla y Morelos N/A 172.2 354.2 228.8 Operating

23 TAG Pipelines North, S. de R. L. de C. V. Tamaulipas, Nuevo León, San Luis Potosí N/A 451.6 1,432.7 1,065.5 Operating

24Transportadora de Natural gas del Northwest, S. de R.L. de C.V.

El Encino, Chiahuahua - Mazatlán, Sinaloa N/A 950.6 947.1 896.7 Under

construction

25 TAG Pipelines Sur, S. de R.L. de C.V. San Luis Potosí, Guanajuato, Querétaro N/A 291.5 1,422.2 728.0 Operating

26 Argüelles Pipeline, S. de R. L. de C. V. Tamaulipas Oct-15 2.9 231.2 130.0 Operating

27 ATCO Pipelines, S. A. de C. V. Hidalgo N/A 14.8 530.8 N/A Por iniciar obra

28 Pemex Exploration y Production (Santuario) Tabasco Dec-83 19.0 78.0 N/A Operating

29 Pemex Exploration y Production (Misión) Tamaulipas y Nuevo León Dec-59 701.0 1.2 N/A Operating

30 Pemex Exploration y Production (Altamira) Tamaulipas Dec-09 29.3 2.0 N/A Operating

31Natural gas del Northwest, S. A. de C. V. (Proyecto Linares)

Nuevo León N/A 5.1 16.8 N/A About to start up

15,755.9 20,893.3 6,823.4 Domestic total

Permittee

37

As for the 2015 advances, the Midstream Gas Pipeline (Nueva Era) was developed, according with the agreement signed on August 2015 between Howard Midstream Energy Partners and CFE for conveying 500 MMCFD of natural gas, through a new import point which will be in Colombia, Nuevo León. This gas pipeline is estimated to start up on June 201716.

The CFE presented, in its annual report, the advances of the gas-pipeline infrastructure; likely, to increase the country’s natural gas supply, 26 tenders were fostered along with the private sector. By the end of 2015, 4 of these projects were already operating, 13 under construction, and the remaining 9, under tender process.

The gas pipelines of Sasabe-Guaymas and the one of Morelos are among the gas projects completed in 2015 by CFE.

The gas pipeline of Sasabe-Guaymas, started up trading on August 2015, with a transportation capacity of 770 MMCFD, a diameter of 36 in, a length of 515 km, and an investment of over 470 million USD. This gas pipeline conveys natural gas from the reception point in the interconnection with the gas pipeline Tucson-Sasabe, in the border of Mexico-USA, up to the delivery points defined as Measuring, Regulating, and Control Station (EMRyC, for its Spanish acronym) Puerto Libertad and EMRyC Guaymas17.

Additionally, the gas pipeline Morelos also started up, whose route goes across the states of Tlaxcala, Puebla, and Morelos. Phase I of this gas pipeline runs from the interconnection with the gas pipeline Esperanza-Venta de Carpio, located in the north of Puebla, and owned by CENAGAS, up the CC Centro in Morelos. Phases II runs from the interconnection with the high-pressure gas pipeline Cempoala-Santa Ana, located in Tlaxco, Tlaxcala, and owned by up to Phase 1 of the gas pipeline Morelos.

The first phase of this gas pipeline started up on June 2015, and phase II was completed on December 2015. Besides, from January-March 2016, with the interconnection works with the pipeline Cempoala-Santa Ana, the construction of the gas pipeline Morelos was completed. This pipeline has a transportation capacity of up to 320 MMCFD, a 30-in diameter, a 172-km length, and an investment of over 246 million dollars18.

In 2015, CFE put out to tender and allocated a total of six gas pipelines: Waha-Presidio, Waha-San Elizario, San Isidro-Samalayuca, Ramal Villa de Reyes, Samalayuca-Sasabe, and Tuxpan-Tula.

During 2016, CFE allocated the following gas pipelines: (i) Villa de Reyes-Aguascalientes-Guadalajara, (ii) South of Texas-Tuxpan (Marine), (iii) Ramal Centrales Empalme, (iv) Nueces-Brownsville (USA), and (v) La Laguna-Aguascalientes.

16 First annual review of the Quinquennial Plan to Expand the SISTRANGAS 2015-2019, p. 9. 17 CFE Annual Report 2015, p. 20-21. 18 CFE Annual Report 2015, p. 21.

38

FIGURE 2. 12 CURRENT INFRASTUCTURE OF NATURAL GAS

Source: SENER with information from CENAGAS.

As for the distribution through pipelines, the CRE seeks to foster investments in the retail market and to protect end users by enabling a trade which results attractive for it is not exclusive in the Geographic Zones19.

For distribution permits, CRE had 23 permits recorded by the end of 2015, with an accumulated length of 51,347.4 km and a coverage of 3.2 million users distributed along several states.

In this sense, the region with the largest number of permits is the Northeast one, with eleven, which represents an approximate length of 32,699.1 km and a converge of 1.4 million users; it is seconded by the Central region with seven permits and a length of 10,851.3 km; Central-Eastern with three permits and a length of 6,840.0 km; and, finally, the Northwest region with two permits and a length of 956.5 km.

19 Report 2015: http://www.cre.gob.mx/articulo.aspx?id=671

Pipelines operated by CENAGASPipelines operated by private partiesCENAGAS compression stationsPrivate compression stations

Los Algodones

San Luis Río Colorado

Escobedo

SamalayucaSan Isidro

PuertoLibertad

Sásabe

El EncinoGuaymas

La Laguna

Cd. Mier

Durango

Zacatecas

Aguascalientes

Guadalajara

San Luis Potosí

V. Reyes

Toluca

Los Naranjos

Tamazunchale

Huexca (Morelos)

Nativitas (Puebl)a

Lázaro Cárdenas

Salina Cruz

Merida

Tijuana

Ensenada

Pedro Escobedo

Camargo

Matamoros

ALTAMIRA

SANTA CATARINA LOS RAMONES

CEMPOALA

CHINAMECA

EMILIANO VALTIERRILLA

CÁRDENAS

GLORIA A DIOS

ESTACIÓN 19

EL CARACOL

LOS INDIOS

LERDO

CHÁVEZ

NACO

EL SUECO

JALTIPAN

EL SAUZ

DR. ARROYOVILLAGRAN

SAN ISIDRO

SOTO LA MARINA

39

TABLE 2. 4 QUINQUENNIAL DATA AND ENGAGEMENTS OF THE DISTRIBUTION PERMIT HOLDERS, BY THE END OF 2015

1/ Exchange rate by December 31st, 2015. 2/ Data at the permit's granting. Q3/ Companies in their third five-year period. Q4/ Companies in their fourth five-year period. Source: SENER based on information from the CRE.

Regarding liquefied natural gas (LNG) storage permits, by the end of 2015, there were four permits, from which three are currently operating with a storage capacity of 920,000m3 and an investment of 3,054 million dollars; and a storage project in Tuzandepetl, Veracruz, with an investment of approximately 200 million dollars.

By the end of its quinquennium

LocationLength(km)

Average volume MMCFD

Users' coverage

Investment (thousand dollars)1

Users' coverage

Conveyed Natural Gas

MMCFD

Accummulated network length

(km)

66,128.6 1,146 3,273,679 507,964 2,362,996 978 51,347.4

35,052 485 1,541,392 119,221 1,419,140 476 32,699.1

1 Cía. Nacional de Gas Q4/ Piedras Negras 723 10 12,719 - 12,491 11 728

2Ecogas México (antes DGN de Chihuahua) Q4/

Chihuahua 2,354 31 72,619 22,637 64,156 29 2,088

3 Natural gas de México (Saltillo) Q4/ Saltillo-Ramos Arispe-

Arteaga2,644 27 101,397 - 80,224 27 2,587

4 Cía. Mexicana de Gas Q4/ Monterrey 3,797 66 170,862 13,552 126,760 53 2,892

5 Natural gas de México (Nvo. Laredo) Q4/ Nuevo Laredo, Tamaulipas 1,153 4 34,155 2,795 31,414 3 1,176

6 Natural gas de Juárez Q4/ Ciudad Juárez 5,166 6 269,336 31,858 242,912 24 4,722

7 Tractebel GNP Q3/ Río Pánuco 917 25 44,583 896 41,181 27 818

8 Natural gas del Northwest (DGNN) 2/ Río Pánuco 302 39 10,062 25,468 5 37 26

9 Tamauligas Q4/ North de Tamaulipas 1,049 11 24,114 3,077 20,004 10 1,003

10 Natural gas México (Monterrey) Q4/ Monterrey 15,874 255 770,252 8,921 771,664 244 15,687

11Ecogas México (DGN La Laguna Durango) Q4/

Torreón-Gómez Palacio-Ciudad Lerdo-Durango

1,074 11 31,293 10,016 28,329 10 972

Total Central Region 20,068 431 1,311,704 301,852 708,977 295 10,851.3

12 Natural gas México (Toluca) Q4/ Toluca 1,098 41 47,461 4,833 31,278 36 881

13 Comercializadora Metrogas Q4/ Distrito Federal 7,475 112 730,197 119,819 411,068 57 3,899

14 Consorcio Mexi-Gas Q3/Valle Cuautitlán-Texcoco-

Hidalgo4,758 138 260,793 44,487 182,981 128 4,191

15 Natural gas del Northwest (DGNM) Q3/Valle Cuautitlán-Texcoco-

Hidalgo472 4 17,294 37,750 939 7 162

16 Natgasmex Q3/ Puebla-Tlaxcala 2,390 48 93,307 4,415 82,660 56 1,634

17 Natural gas del Northwest Morelos 2/ Morelos 221 59 26,806 21,492 18 3 5

18 Natural gas del Northwest Veracruz 2/ Veracruz 3,654 29 135,846 69,056 33 6 81

Total Central-Eastern Region 9,207 203 381,387 53,360 207,946 182 6,840.4

19 Tractebel Digaqro Q3/ Querétaro 1,766 60 73,119 32,468 65,122 62 1,570

20 Natural gas México (Bajío) Q4/Zona Bajío North, Silao-León-

Irapuato6,065 90 253,877 8,326 112,109 65 3,543

21 Tractebel DGJ Q3/ Guadalajara 1,376 53 54,391 12,566 30,715 55 1,727

Total Northwest Region 1,801 27 39,196 33,531 26,933 25 956.5

22 Ecogas México (DGN de Mexicali) Q4/ Mexicali 622 19 14,288 12,058 13,736 22 520

23 Natural gas del Northwest Sonora Q3/ Hermosillo 1,179 8 24,908 21,473 13,197 3 436

Northeast Region Total

Domestic total

By the end of 2015

40

TABLE 2. 5 LNG STORAGE PERMITS, 2015

Source: CRE.

2.1.6. Natural Gas Price

As for the maximum price for natural-gas first-hand sales, it includes the referencing prices of the USA, transportation costs between the border zone in Reynosa and the pipelines from south Texas, and the transportation costs in Mexico. The CRE will use as its international reference markets the Houston Ship Channel (HSC), Henry Hub (HH), and South of Texas (ST), as for the price adjustments for transportation in Mexico, tariffs authorized by SISTRANGAS. The transportation costs between the border in Reynosa and the pipelines from south Texas are added as part of the foreign-trade balance of natural gas, relevant to set the opportunity cost of the natural gas FHS.

In 2015, the natural gas benchmark averaged 2.6 USD/MMBTU, 39.1% less than in 2014 (4.3 USD/MMBTU) due to an increase on the USA inventories.

Regarding the price for the residential-sector end users, by December 2015, it averaged 9.7 USD/MMBTU. Within this sector, Ciudad Juarez had the lowest price, 6.0 USD/MMBTU, since the transportation costs and distribution tariff were the lowest regarding other zones. On the contrary, the zone of La Laguna-Durango had the highest price, with 15.7 USD/MMBTU, give its distribution tariff was the highest, reaching 12.8 USD/MMBTU.

For the services sector, the final price to end users averaged 5.3 USD/MMBTU, being the zone Puebla-Tlaxcala the one with the lowest price, 3.6 USD/MMBTU, since its distribution tariff was the lowest compared with other zones (0.9 USD/MMBTU). In contrast, the zone of Rio Panuco had the highest price, 7.1 USD/MMBTU.

The industrial sector had an average price of 4.0 USD/MMBTU, with Monterrey having the lowest price, 3.0 USD/MMBTU, and Rio Panuco having the highest price, 6.8 USD/MMBTU, due to its high distribution tariff, 4.3 USD/MMBTU.

The natural-gas prices to end users in the main distribution zones are displayed in Table A.7 of the Annex.

Under project

Altamira's LNG Terminal

Energía Costa AzulKMS's LNG Terminal

Almacenamiento Subterraneo del

Istmo, S. A. de C. V.

LocationAltamira

TamaulipasEnsenada

Baja CaliforniaManzanillo

ColimaTuzandépetl

Veracruz

Gasification capacity(MMCFD)

670-1119 1000-1300 500 N/A

Terminal's storage capacity (m3) 300,000 320,000 300,000 N/A

Investment (million dollars) $396.0 $1,875.0 $783.0 $200.0

Startup date 30-sep-06 14-may-08 17-ago-12 N/A

Company´s name

Under operation

41

FIGURE 2. 13 NATURAL GAS BENCHMARK (FIRST-HAND SALES IN REYNOSA), 2010-2013 (dollar per million BTU)

Source: CRE.

2.1.7. Natural Gas Foreign Trade

By the end of 2015, imports reached a volume of 3,548.0 MMCFD, an increase of 24.0% regarding 2014. From the total, 2,910.3 MMCFD (82.0%) were imported through pipeline. LNG imports had a 18.0% share, a volume of 637.7 MMCFD, which was a decrease of 25.5% regarding 2014; these imports came mainly from Peru, Nigeria, and Trinidad and Tobago.

Pemex imported a volume of 1,418.4 MMCFD, 40.0% of the total imported volume, which represented an increase of 4.5% regarding 2014, due to a lesser production of natural gas, and to a larger volume of gas conveyed through the Gas Pipeline Ramones I (Camargo-Ramones).

In 2015, private imports summed up a volume of 2,129.7 MMCFD, 60% of the total imports. This volume represented an increase of 41.7% regarding 2014. CFE’s imports, included in the private ones, had an increase due to the conversion to natural gas of Units 1, 2, and 4 of the CT Puerto Libertad; Unit 3 of the CT Emilio Portes Gil, and Units 9, 10, 11, and 12 of the CT Manzanillo.

As for natural-gas exports, these kept the same levels of 2014, reaching 12.5 MMCFD. From this volume, 9.7 MMCFD were exported through Cd. Morelos in Baja California, and 2.8 MMCFD through Reynosa, Tamaulipas (see Annex Table A.8).

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

2010 2011 2012 2013 2014 2015 2016

First-hand sales in Reynosa Henry hub

42

FIGURE 2. 14 NATURAL GAS IMPORT AND EXPORT POINTS MEXICO-USA

Source: CENAGAS

2.1.8. Natural Gas Domestic Balance

In the balance of dry natural gas, it can be observed a decrease of 7.4% regarding 2014, falling from 4,392.8 MMCFD to 4,066.8 MMCFD in 2015. In order to cover the gas demand (7,504.1 MMCFD), a volume of 3,548.0 MMCFD were needed for imports.

Regarding regional balances, the Northwest region had a demand of 606.2 MMCFD, an increase of 22.1%. This region imported a total of 637.3 MMCFD, and exported 9.7 MMCFD (see Table 2.11).

The Northeast region produced 957.5 MMCFD, a decrease of 16.3% regarding 2014, and an imported volume of 2,534.2 MMCFD. As for its demand, it reached 2,464.2 MMCFD; its dry gas exports were of 2.8 MMCFD, and the volume of gas exported to other regions was of 972.4 MMCFD.

The Central Eastern region had a 1,134.6 MMCFD demand, 7.7% more than in 2014; an imported volume of 376.5 MMCFD; and 746.7 MMCFD to exports. Though, this region had a deficit of 11.4 MMCFD.

The Central Region had a supply of 919.4 MMCFD, 152.3 MMCFD more than in 2014. To cover this demand, the region received a total 919.4 MMCFD from other regions.

Finally, the South-Southeast region decreased by 4.3% its dry-gas production, reaching a volume of 3,109.3 MMCFD, while its demand was of 2,379.7 MMCFD; the surplus was sent to other regions. The balances for gas by regions are showed in the Annex Tables A.9-A.13.

Interconexiones de gas natural por ducto México Estados UnidosOtay

Mexicali

Los Algodones

Sásabe Nogales

Naco

Agua Prieta

Ciudad Juárez

San Isidro

San Agustín

Acuña

Piedras Negras

Ciudad Mier

Camargo

Argüelles

Reynosa (3)

Río Bravo

Puntos asociados a gasoductos de transporte

Puntos asociados a actividades de distribución

Puntos asociados a actividades de autoabastecimiento

Puntos asociados a actividades de recolección

Hidalgo

Sistema Nacional de Gasoductos (CENAGAS)

Sistemas de transporte privados (en operación)

Sistemas de transporte en construcción

Puntos con capacidad de importación

Puntos con capacidad de exportación

Puntos con capacidad de importación y exportación

Ciudad MorelosSan Jerónimo

43

TABLE 2.6 NATURAL GAS DOMESTIC BALANCE, 2005-2015 (million cubic feet per day)

* Includes continuous own-uses. Source: IMP.

Concept 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015AAGR

2005-2015

Origin 5,149.2 5,703.4 6,070.6 6,256.1 6,228.7 6,462.9 6,562.1 6,732.9 7,009.0 7,253.9 7,614.8 4.0

Domestic production 4,243.7 4,685.0 4,967.0 4,919.9 4,971.0 5,004.0 4,812.7 4,603.1 4,492.4 4,392.8 4,066.8 -0.4

Production from plants 3,146.9 3,444.5 3,546.4 3,461.3 3,572.1 3,618.2 3,691.6 3,628.3 3,693.4 3,639.9 3,397.5 0.8

Direct from fields 997.8 1,152.2 1,333.6 1,382.3 1,325.3 1,311.8 1,045.3 911.1 737.5 694.2 612.4 -4.8

Ethane injected to pipelines 94.0 87.4 87.0 76.4 73.7 74.0 75.8 63.7 61.6 58.8 56.8 -4.9

Other currents 4.9 0.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 n.a.

Import 905.5 1,018.4 1,103.6 1,336.1 1,257.7 1,458.9 1,749.4 2,129.8 2,516.6 2,861.1 3,548.0 14.6

PGPB 480.4 450.9 385.6 450.4 422.0 535.7 790.8 1,089.0 1,289.7 1,357.8 1,418.4 11.4

Private 425.1 567.5 718.0 885.7 835.6 923.2 958.6 1,040.8 1,226.9 1,503.3 2,129.7 17.5

Destination 5,111.5 5,705.7 6,064.6 6,217.2 6,170.6 6,424.2 6,536.4 6,686.2 6,964.8 7,221.8 7,516.6 3.9

Domestic demand 5,087.6 5,672.9 5,925.9 6,109.9 6,104.0 6,340.9 6,512.2 6,678.4 6,952.4 7,209.3 7,504.1 4.0

Oil sector 2,030.0 2,159.6 2,125.4 2,174.9 2,149.4 2,236.6 2,186.2 2,273.1 2,272.2 2,275.6 2,200.0 0.8

Industrial sector 935.2 1,014.0 1,040.1 1,026.6 912.8 1,054.3 1,129.2 1,181.1 1,239.9 1,313.5 1,375.8 3.9

Electricity sector* 2,013.3 2,389.6 2,645.9 2,794.0 2,932.8 2,936.3 3,088.4 3,111.5 3,322.7 3,500.3 3,797.6 6.6

Residential sector 86.6 84.5 88.5 87.4 82.9 85.7 81.7 84.1 86.7 87.8 94.6 0.9

Services sector 20.5 23.3 24.2 25.3 24.5 26.6 25.2 27.0 28.5 29.9 33.7 5.1

Motor-carrier sector 1.9 2.0 1.9 1.7 1.5 1.4 1.5 1.8 2.4 2.3 2.4 2.1

Export 23.9 32.7 138.7 107.4 66.5 83.3 24.2 7.8 12.4 12.5 12.5 -6.3

Inventories variation and differences 37.7 -2.3 6.0 38.8 58.2 38.7 25.7 46.7 44.3 32.1 98.2 10.0

44

3. Chapter Three. Prospective Natural Gas Market

3.1. Natural Gas Prospective

Derived from the Energy Reform, the natural-gas market has undergone several changes; Extraction and exploration fields have been allocated to Pemex and to private companies through public, competitive tenders, opened nationally and internationally, carried out following the highest transparency standards and which are broadcasted in real time.

Additionally, gas pipelines have been constructed to expand coverage into places where this fuel was not accessible; they also improved the safety, continuity, quality and efficiency of the transportation and storage service of natural gas.

3.1.1. Natural Gas Demand

Worldwide, the total consumption of natural gas during 2015 reached a volume of 335,600.5 MMCFD. By sector, international trends expect that the electricity sector will increase its demand by 24.4%, reaching a 32,677.6 MMCFD volume between 2015 and 2040. The industrial sector will reach a 26,229.5 MMCFD volume, an increase of 27.6%; the services sector will increase by 14.6% with 10,082.0 MMCFD; and the residential sector will have a decrease of 7.7% with a 12,513.7 MMCFD volume.

In Mexico, it is expected that by 2030, the natural-gas demand will increase 20.3% regarding 2015, reaching a volume of 9,030.4 MMCFD. During 2015-2030, the gas demand will have a 1.2% AAGR. This increase is the result of the construction and startup of the new gas pipelines, which will enable the conveyance of natural gas to zone which did not have access to it, and of the increase on the demand for natural gas in the electricity and industrial sector (see Figure 3.1).

FIGURE 3. 1 NATURAL GAS DOMESTIC DEMAND, 2015-2030 (MMCFD)

Source: SENER based on information from IMP.

0

1,000

2,000

3,000

4,000

5,000

6,000

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08

20

09

20

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45

3.1.2. Sectoral Demand

In 2030, almost every sector will increase its demand, except for the oil one, which decrease by 34.0% regarding 2015. The electricity sector will consume 58.7%, a volume of 5,301.2 MMCFD, becoming the largest consumer of natural gas. It was followed by the industrial sector, with 23.2%; the oil sector, 16.1%; residential and services, 1.3% and 0.6%, respectively; and the motor-sector services with 0.1% (see Figure 3.2).

FIGURE 3. 2 NATURAL-GAS DEMAND BY SECTOR, 2015-2030. (MMCFD)

Note: Proyecto Etileno XXI is included in the industrial sector. Source: SENER with information from IMP.

Electricity Sector

In 2030, the electricity sector will demand fossil fuels for 5,447.0 MMCFD, a decrease of 0.9% regarding 2015 and an AAGR of -0.1%. This fall is mainly due to the energy transition of the country, and which has led to developing new projects to generate clean energy. In this sense, the fuel-oil demand is expected to decrease 98.6%, dropping from 637.5 MMCFDNGE to 8.8 MMCFDNGE; coal will decrease 97.5%, and diesel, 83.6% regarding 2015. On the contrary, petroleum coke will increase 4.9%, reaching a volume of 105.7 MMCFDNGE, and the natural gas demand will increase 39.6%.

In this sector, natural gas will remain as the most demanded fuel, with a 97.3% share. This fuel's demand will increase from 3,797.3 MMCFD in 2015 to 5,301.2 MMCFD in 2030. This increase is the result of the development for the transportation of natural gas, and of the conversion of CFE's power stations to dual combustion, which will reduce the use of fuel oil, which has a higher price and high greenhouse emissions compared to other energy sources like natural gas; besides, it extends the power/stations' lifespan, diversifies the use of energy sources, and increases the possibility of generating a competitive market20. The demand for fuels in the electricity sector are displayed in the following table.

20 Annual Report 2015 CFE, p. 33.

Oil2.200,0

Electricity3.797,6

Industrial1,375.8

Residential94,6

Services33,7

Vehicle transportation

2,4

Oil1,451.1

Electricity5,301.2

Industrial2,097.3

Residential 120.4

Services50,9 Vehicle

transportation9.6

20302015

46

TABLE 3. 1 ELECTRICITY SECTOR FUEL'S DEMAND, 2015-2030. (MMCFDNGE)

Source: IMP, based on information from CFE, PEMEX, SENER and private companies.

Industrial Sector

It is expected that in 2030, the demand for fossil fuels will reach a volume of 3,166.3 MMCFDNGE, an increase of 31.3% regarding 2015. In this sector, all fuels will increase their demand, except for fuel oil, which will not be used after 2019. Natural gas will remain as the most used fuel with 66.2% from the sector's total demand; it will be followed by coal, with a 11.9% share; petroleum coke with 11.0%; diesel with 6.4%; and LP gas with 4.4%.

As for natural gas, its demand will rise from 1,375.8 MMCFD to 2,097.3 MMCFD, an increase of 52.4% by 2030, due to the incorporation of new gas pipelines and to the permits for distribution through pipeline, which will cover all industrial users; and to the replacement of fuel oil with cheaper sources, such as natural gas.

TABLE 3. 2 INDUSTRIAL SECTOR DOMESTIC DEMAND FOR FUELS, 2015-2030. (million cubic feet per day of natural gas equivalent)

MMCFDNGE: Million cubic feet per day of natural gas equivalent. Source: IMP, based on information from BANXICO, CNIAA, CONAGUA, CONUEE, CRE, EIA, EPA, IEA, INEGI, PEMEX, SE, SENER and private companies.

In 2030, it estimated that the chemical branch will demand most of the natural gas, with a 19.0% share, a demand of 398.6 MMCFD. It will be seconded by basic-metals industry with 358.3 MMCFD (see Annex Table A.14).

Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030AAGR

2015-2030Total 5,494.4 4,922.7 4,819.4 4,674.8 4,541.9 4,433.9 4,436.0 4,509.4 4,680.8 4,734.4 4,877.8 5,005.4 5,220.2 5,210.9 5,337.1 5,447.0 -0.1

Coal 904.7 991.0 986.4 769.6 191.9 6.1 2.1 6.1 2.1 4.0 5.5 3.8 34.0 6.2 19.0 22.4 -21.8

Fuel oil 637.5 24.6 23.6 22.0 10.9 9.8 9.5 9.5 10.3 11.1 10.8 10.2 55.3 8.4 8.5 8.8 -24.9

Diesel 54.0 8.5 10.0 4.5 1.9 1.8 1.8 1.8 2.2 2.7 5.0 3.7 3.8 5.0 6.8 8.9 -11.3

Petroleum coke 100.7 105.7 105.7 105.7 105.7 105.7 105.7 105.7 105.7 105.7 105.7 105.7 105.7 105.7 105.7 105.7 0.3

Natural gas 3,797.6 3,792.8 3,693.7 3,772.9 4,231.5 4,310.5 4,316.9 4,386.3 4,560.6 4,610.9 4,750.8 4,882.0 5,021.4 5,085.6 5,197.1 5,301.2 2.2

(MMCFD) (MMCFDNGE) (MMCFDNGE) (MMCFDNGE) (MMCFDNGE) (MMCFDNGE) (MMCFDNGE)2015 1,375.8 57.8 113.3 171.8 339.1 352.9 2,410.72016 1,435.4 26.9 114.0 169.7 332.3 350.8 2,429.12017 1,737.0 20.2 110.1 167.9 342.6 354.4 2,732.22018 1,905.3 13.5 107.5 170.2 367.0 357.4 2,920.92019 1,931.8 6.7 108.7 172.6 358.8 358.6 2,937.32020 1,960.3 0.0 110.1 175.3 360.4 359.7 2,965.92021 1,985.5 0.0 111.8 177.9 364.2 362.4 3,001.82022 2,011.1 0.0 113.7 180.7 367.8 364.2 3,037.42023 2,029.1 0.0 115.8 183.5 369.5 366.1 3,064.02024 2,042.8 0.0 118.3 186.3 368.3 366.7 3,082.32025 2,058.0 0.0 121.0 189.2 366.4 369.6 3,104.12026 2,071.3 0.0 124.0 192.1 366.9 371.2 3,125.52027 2,083.6 0.0 127.4 195.1 363.3 372.9 3,142.32028 2,092.1 0.0 131.2 198.0 357.8 373.6 3,152.82029 2,097.0 0.0 135.4 201.0 353.8 375.8 3,163.02030 2,097.3 0.0 140.2 203.9 348.1 376.8 3,166.3AAGR

2015-2030

Coal Total

2.9 n.a. 1.4 1.1 0.2 0.4 1.8

Petroleum cokeYear Natural gas Fuel oil LP gas Diesel

47

FIGURE 3. 3 NATURAL GAS INDUSTRIAL DEMAND BY GROUP OF BRANCHES, 2015-2030. (percentage share)

Source: SENER with information from IMP, BANXICO, CNIAA, CONAGUA, CONUEE, CRE, EIA, EPA, IEA, INEGI, PEMEX, SE, SENER and private companies.

Within the industrial sector demand, the trending demand (economic growth and fuels prices) and the non-trending demand (new projects using natural gas, new transportation infrastructure, and the consumption of compressed natural gas). The trending demand will reach a volume of 1,541,7 MMCFD in 2030, an increase of 11.6% regarding 2015, while the non-trending demand will rise from 53.7 MMCFD in 2015 to 555.6 MMCFD. The latter, mainly due to new industrial projects, new transportation infrastructure for natural gas, and distribution developments (see Table 3.3).

TABLE 3. 3 INDUSTRIAL DEMAND FOR NATURAL GAS BY PROJECTING COMPONENT, 2016-2030. (MMCFDNGE)

Source: SENER with information from IMP, BANXICO, CNIAA, CONAGUA, CONUEE, CRE, EIA, EPA, IEA, INEGI, PEMEX, SE, SENER and private companies.

Basic-metal industries25.3%

Chemistry14.6%

Metallic products, machinery and equipment

10.0%

Glass and glass products9.6%

Food, beverages and tobacco9.5%

Non-metallic mineral products6.3%

Paper and cardboard, printing houses and publishers

6.5%

Textiles, garments, and leather industry

3.0%

Mining1.0%

Beer and malt2.8%

Hydraulic cement1.0%

Remaining branches and unidentified

10.4%2015

Basic-metal industries

17.1%

Chemistry19.0%

Metallic products, machinery and equipment

7.9%

Glass and glass products7.0%

Food, beverages and tobacco7.7%

Non-metallic mineral products7.0%

Paper and cardboard, printing houses and publishers

4.0%

Textiles, garments, and leather industry

2.4%

Mining1.2%

Beer and malt1.8%

Hydraulic cement0.7%

Remaining branches and unidentified

24.2%

2030

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 AAGR2015-2030

Total 1,435.4 1,737.0 1,905.3 1,931.8 1,960.3 1,985.5 2,011.1 2,029.1 2,042.8 2,058.0 2,071.3 2,083.6 2,092.1 2,097.0 2,097.3 2.7

Demand trend 1,381.6 1,400.4 1,429.4 1,446.8 1,465.8 1,482.5 1,498.8 1,509.5 1,516.9 1,525.5 1,533.0 1,539.6 1,542.9 1,543.7 1,541.7 0.8

Nontrendy demand 53.7 336.6 476.0 485.1 494.6 503.0 512.3 519.5 525.9 532.5 538.3 544.0 549.2 553.3 555.6 18.2

Industrial projects 21.4 182.3 217.7 220.6 223.7 226.0 228.8 230.0 230.8 231.8 232.5 233.4 233.9 233.8 232.5 18.6

New transportation infrastructure

5.6 41.4 82.8 84.9 87.2 89.3 91.6 93.8 95.8 97.9 99.7 101.5 103.3 104.9 106.4 23.5

Compressed natural gas 4.4 22.2 32.1 32.8 33.4 34.0 34.6 35.1 35.5 35.9 36.3 36.6 36.8 37.1 37.2 16.4

Distribution developments 22.3 90.6 143.3 146.7 150.3 153.8 157.3 160.6 163.8 167.0 169.8 172.5 175.2 177.6 179.7 16.1

48

Oil Sector

In 2030, the oil sector's fuels demand will reach a volume of 1,728.5 MMCFDNGE, a decrease of 30.3% regarding 2015 and an AAGR of -2.4%. Natural gas will remain as the most demanded fuel in this sector, with an 84.0% share, seconded by fuel oil with 8.6%; diesel, 6.9%; gasoline, 0.3%; and LP gas, 0.2%. As for natural gas, it will decrease 34.0%, falling from 2,200 MMCFD to 1,451.1 MMCFD in 2030, with an AAGR of -2.7% during 2015-2030.

TABLE 3. 4 DOMESTIC FUELS DEMAND IN THE OIL SECTOR, 2015-2030. (MMCFDNGE)

Source: IMP with information from PEMEX.

Residential Sector

In 2030, the fuels demand in the residential sector will decrease by 14.5% regarding 2015, going from 1,187.4 MMCFDNGE to 1,015.1 MMCFDNGE in 2030, which is an AAGR of -1.0%. LP gas will remain as the most used fuel, with a 52.7% share (535.3 MMCFDNGE), but will decrease by 118.2 MMCFDNGE. Firewood will be second with a 359.4 MMCFDNGE volume (34.4%). Natural gas will have an 11.9% share, increasing its demand by 27.2%, from 94.6 MMCFD in 2015 to 120.4 MMCFD in 2030. This increase is the result of replacing LP gas and firewood with natural gas.

(MMCFD) (MMCFDNGE) (MMCFDNGE) (MMCFDNGE) (MMCFDNGE) (MMCFDNGE)

2015 2,200.0 141.6 114.9 16.3 8.6 2,481.42016 2,270.5 148.8 120.1 18.0 5.0 2,562.32017 2,270.5 148.8 120.1 18.0 5.3 2,562.52018 2,149.5 148.8 120.1 17.7 5.3 2,441.32019 2,104.2 148.8 120.1 16.5 5.3 2,394.82020 2,248.6 148.8 120.1 15.0 5.3 2,537.72021 2,388.1 148.8 120.1 15.0 5.3 2,677.12022 2,399.3 148.8 120.1 14.5 5.3 2,687.92023 2,201.1 148.8 120.1 8.4 5.3 2,483.62024 2,050.3 148.8 120.1 3.3 5.3 2,327.72025 1,877.7 148.8 120.1 6.4 5.3 2,158.12026 1,769.6 148.8 120.1 5.4 5.3 2,049.02027 1,689.0 148.8 120.1 4.8 5.3 1,967.92028 1,608.8 148.8 120.1 4.3 5.3 1,887.12029 1,520.1 148.8 120.1 3.8 5.3 1,798.02030 1,451.1 148.8 120.1 3.3 5.3 1,728.5

AAGR2015-2030

Total

-2.7 0.3 0.3 -10.1 -3.2 -2.4

Gasolines Year

Natural gas Fuel oil Diesel LP gas

49

TABLE 3. 5 FUELS CONSUMPTION IN THE RESIDENTIAL SECTOR, 2015-2030. (MMCFDNGE)

Source: IMP, based on information from CONAGUA, CONAPO, CONUEE, CRE, EIA, INEGI, Pemex, SENER and private companies.

Services Sector

The demand for fuels in the services sector will reach a volume of 290.1 MMCFDNGE, an increase of 8.7% regarding 2015, and an AAGR of 0.6% during the period. Like the residential sector, LP gas will be the most used fuel in the services sector, reaching a volume of 181.8 MMCFDNGE in 2030, which is an increase of 11.6% regarding 2015. Firewood will be second with a 19.8% share, but decreasing by 18.2%. Finally, natural gas will rise from 33.7 MMCFD to 50.9 MMCFD, an AAGR of 2.8% during 2015-2030.

TABLE 3. 6 FUELS CONSUMPTION IN THE SERVICES SECTOR, 2015-2030. (MMCFDNGE)

Source: IMP, based on information from CONAGUA, CONAPO, CONUEE, CRE, EIA, INEGI, PEMEX, SENER and private companies.

LP gas Firewood Natural gas Total(MMCFDNGE) (MMCFDNGE) (MMCFD) (MMCFDNGE)

2015 653.5 439.4 94.6 1,187.42016 645.5 436.9 98.5 1,180.82017 638.2 432.3 103.9 1,174.42018 632.3 427.0 108.6 1,167.92019 621.3 421.2 112.1 1,154.72020 612.3 414.6 115.5 1,142.42021 601.1 409.3 116.9 1,127.42022 590.8 403.9 118.2 1,113.02023 585.5 398.1 120.0 1,103.62024 576.6 391.6 120.7 1,088.82025 568.2 386.8 120.9 1,076.02026 560.3 381.5 121.0 1,062.82027 552.7 376.1 120.8 1,049.72028 549.4 370.3 121.4 1,041.22029 542.3 364.2 120.9 1,027.42030 535.3 359.4 120.4 1,015.1AAGR

2015-2030

Year

-1.3 -1.3 1.6 -1.0

LP gas Firewood Natural gas Total(MMCFDNGE) (MMCFDNGE) (MMCFD) (MMCFDNGE)

2015 162.9 70.3 33.7 266.92016 153.3 69.9 32.9 256.02017 153.5 69.2 33.8 256.42018 154.3 68.3 35.0 257.72019 154.6 67.4 36.3 258.32020 155.5 66.3 37.4 259.22021 156.7 65.5 38.7 260.92022 158.4 64.6 40.0 263.02023 160.3 63.7 41.4 265.42024 162.6 62.7 42.8 268.02025 165.2 61.9 44.1 271.22026 168.1 61.0 45.4 274.62027 171.2 60.2 46.7 278.12028 174.5 59.3 48.1 281.82029 178.0 58.3 49.5 285.72030 181.8 57.5 50.9 290.1AAGR

2015-2030

Year

0.7 -1.3 2.8 0.6

50

In 2030, there are expected natural gas savings for up to 13.0 MMCFD, as a result of an improvement of the efficiency of water heaters, electronic-ignition stoves, and microwave ovens. This will mean a 9.9 MMCFD volume additional to the volume recorded in 2015 regarding this concept.

Most savings are related to water-heater efficiency, reaching a volume of 11.2 MMCFD, an 85.9% from the total savings, followed by the savings from electronic-ignition stoves with a volume of 8.1 MMCFD and a 13.7% share, and by the savings from microwave ovens, with 0.06 MMCFD and a 0.4% share.

FIGURE 3. 4 NATURAL-GAS SAVINGS IN THE RESIDENTIAL AND SERVICES SECTORS,2015-2030. (MMCFD)

Source: IMP, based on information from CONAGUA, CONAPO, CONUEE, CRE, EIA, INEGI, Pemex, SENER and private companies.

Two scenarios are set according to the savings programs: the first one considers there are no energy savings for water-heaters efficiency, electronic-ignition stoves, and microwave ovens, and estimates a gas-natural demand of 184.2 MMCFD by 2030; the other, considers efficiency, and estimates a natural-gas demand of 171.2 MMCFD for that same year. In this sense, it is expected accumulated savings of 135.8 MMCFD by the end of the period (see Figure 3.4).

FIGURE 3. 5 NATURAL-GAS SAVINGS IN THE RESIDENTIAL AND SERVICES SECTORS, 2015-2030. (million cubic feet per day)

Source: IMP, based on information from Banxico, CONAGUA, CONAPO, CRE, INEGI, Pemex, SENER and private companies.

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Water boilers Stoves Microwave ovens Total

128.4 131.3 137.7

143.6 148.4

152.9 155.6 158.3 161.4 163.5 165.0 166.4 167.6 169.4 170.4 171.2

131.5 134.9 141.8

148.3 154.2

159.6 163.3 166.8 170.8 173.6 175.8 177.8 179.5 181.8 183.1 184.2

0

50

100

150

200

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

With improvements on efficiency

Without improvements on Saving

51

Motor-Carrier Sector

By 2030, the demand for fuels in the motor-carrier sector is expected to reach an 8,023.7 MMCFDNGE volume, an increase of 38.7% regarding 2015. Gasoline will remain the most used fuel with a volume of 5,020.4 MMCFDNGE, a share of 62.6% from the total demand; the latter will be seconded by diesel, with 35.6%, a volume of 2,854.6 MMCFD and, far below, by LP gas and natural gas with a share of 1.7% and 0.1%, respectively. All fuels will increase their demand since it is expected a growth in the vehicle fleet up to 44,390.4 thousand units by 2030 (see Annex Table 3.21).

TABLE 3. 7 MOTOR-CARRIER SECTOR DEMAND FOR GASOLINE, FUEL GAS, COMPRESSED NATURAL GAS, AND DIESEL, 2015-2030.

(MMCFDNGE)

Source: prepared by IMP, based on AMDA, AMIA, ANPACT, BANXICO, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INE, INEGI, PEMEX, SEMARNAT, SCT, SENER and private companies.

3.1.3. Natural-Gas Regional Demand

In 2030, the natural-gas demand will reach a volume of 9,031.3 MMCFD, an increase of 20.4% regarding 2015 and an AAGR of 1.2% during 2015-2030. The Northeast region will have the highest demand of natural gas, with a 33.0% share; it will be followed by the South-Southeast with 21.6%, the Central-Eastern, 20.6%; Central, 14.3%; and Northwest with 10.4%.

During 2015-2030, every region will increase their demand, especially the Central Eastern region, with an increase of 64.3%; it will be seconded by the Northwest which will rise by 55.4%, Central by 40.7%, Northeast by 21.0%, and South-Southeast by 6.4%.

By 2030, the natural-gas demand in the Northeast region is expected to reach a volume of 2,981.0 MMCFD, an AAGR of 1.3% during 2015-2030. From this region, Nuevo León will be the state with the largest demand, 1,170.5 MMCFD, followed by Tamaulipas with 935.3 MMCFD, Chihuahua with 453.9 MMCFD, Coahuila with 337.4 MMCFD, and Durango with 83.7 MMCFD. This rise in the demand will be the result of the startup of new gas pipelines in the region and of the power stations North III in Chihuahua and Northeast in Nuevo León21.

21 Annual Report 2015, CFE, p. 28.

Year Gasoline Diesel LP gasCompressed natural gas Total

2015 3,807.7 1,836.8 136.9 2.4 5,783.72016 3,820.8 1,890.3 134.0 2.9 5,848.02017 3,933.3 1,947.0 134.5 3.1 6,018.02018 4,013.3 2,003.2 133.4 3.4 6,153.42019 4,094.1 2,060.1 130.0 3.7 6,288.02020 4,175.5 2,132.4 132.8 4.3 6,445.12021 4,279.9 2,225.5 135.5 4.9 6,645.72022 4,381.5 2,312.7 137.7 5.4 6,837.32023 4,494.5 2,392.2 139.4 5.9 7,032.22024 4,569.6 2,461.7 140.7 6.4 7,178.42025 4,654.7 2,517.3 141.5 6.9 7,320.42026 4,770.4 2,602.5 142.1 7.4 7,522.52027 4,844.9 2,672.1 142.3 7.9 7,667.32028 4,883.4 2,732.1 142.1 8.4 7,765.92029 4,940.7 2,790.1 141.1 9.1 7,881.02030 5,020.4 2,854.6 139.1 9.6 8,023.7AAGR

2015-20301.9 3.0 0.1 9.8 2.2

52

The South-Southeast region will reach 1,951.0 MMCFD in 2030, an AAGR of 0.4% during 2015-2030. Veracruz will be the state with the largest demand with 867.3 MMCFD, and Quintana Roo the one with the lowest one with 0.9 MMCFD. Every state in the region will increase their demand, except for Tabasco. These increases will be mainly due to those projects considered in the Quinquennial Plan for the Expansion of SISTRANGAS for gas pipelines in Veracruz, Oaxaca, and Chiapas, which will contribute their gas requirements.

In 2030, the gas demand in the Central-Eastern region is foreseen to reach a volume of 1,863.6 MMCFD, an AAGR of 3.4% during 2015-2030. San Luis Potosí will have the largest demand, 629.0 MMCFD. On the contrary, Zacatecas will have the lowest demand, 6.6 MMCFD. This increase in the region is chiefly due to the new gas pipelines constructed in Aguascalientes, Jalisco, Michoacán, and Zacatecas.

The Central region’s demand will reach 1,293.5 MMCFD, an AAGR of 2.3% during 2015-2030. Hidalgo will be the state with the largest demand, with 494.3 MMCFD, and Tlaxcala will have the lowest one with 36.4 MMCFD. The new gas pipelines in Hidalgo, Estado de México, and Morelos are the main reason for this increase22.

The natural-gas demand in the Northwest region will be of 942.2 MMCFD, an AAGR of 3.0% during the same period. Sinaloa will have the largest demand, with 399.4 MMCFD, followed by Sonora with 375.5 MMCFD, Baja California with 114.4 MMCFD, and Baja California Sur with 52.9 MMCFD. This increase is due to the new power stations which started up in Baja California, Sonora, and Sinaloa23, which will be supplied through the gas pipelines fostered by CFE along with the private sector24.

TABLE 3. 8 NATURAL-GAS REGIONAL CONSUMPTION BY STATE, 2015-2030. (MMCFD)

Source: prepared by IMP, based on information from CONAGUA, CONAPO, CONUEE, CRE, EIA, INEGI, Pemex, SENER and private companies.

22 Ibidem. 23 Ibidem. 24 Idem, p. 20.

State 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030AAGR

2015-2030

Domestic total 7.504,1 7.633,0 7.842,1 7.974,9 8.419,8 8.676,8 8.851,1 8.960,5 8.958,3 8.874,2 8.858,8 8.897,2 8.970,0 8.964,9 8.994,5 9.031,3 1,2Northwest 606,3 420,9 568,4 641,8 720,2 693,9 674,9 724,2 749,7 751,3 789,4 859,0 978,4 916,5 932,0 942,2 3,0

Baja California 349,4 181,4 175,8 144,3 104,5 94,1 102,9 106,9 109,7 106,7 107,1 107,9 115,8 110,9 111,5 114,4 -7,2Baja California Sur 0,0 0,0 0,0 7,8 27,0 25,5 25,0 25,3 28,6 31,4 34,2 37,5 50,8 46,6 50,5 52,9 n.a.Sinaloa 0,0 0,0 117,0 116,9 228,0 274,6 219,4 249,6 256,4 281,6 315,5 378,9 402,1 399,0 400,7 399,4 90,8Sonora 256,8 239,5 275,6 372,9 360,7 299,7 327,6 342,4 355,0 331,6 332,5 334,8 409,7 360,0 369,2 375,5 2,6

Northeast 2.464,2 2.521,8 2.570,6 2.592,1 2.734,5 2.673,2 2.611,4 2.657,4 2.812,9 2.820,8 2.881,4 2.897,6 2.850,7 2.933,7 2.963,0 2.981,0 1,3Chihuahua 347,6 326,8 337,9 401,4 368,6 350,0 358,8 356,3 444,0 449,4 453,9 455,1 459,2 464,2 452,5 453,9 1,8Coahuila 235,5 220,7 227,0 231,1 330,2 327,3 322,8 324,6 328,5 330,6 336,2 332,6 336,8 332,6 336,7 337,4 2,4Durango 200,5 215,5 203,1 169,9 135,0 81,1 74,2 70,2 70,3 68,3 73,8 75,4 83,0 77,4 79,9 83,7 -5,7Nuevo León 724,4 863,6 959,5 970,2 1.080,2 1.111,0 1.102,1 1.121,3 1.118,5 1.129,7 1.139,9 1.138,3 1.146,6 1.146,1 1.171,9 1.170,5 3,3Tamaulipas 956,1 895,1 843,1 819,6 820,5 803,8 753,5 785,0 851,6 842,9 877,6 896,2 825,0 913,3 922,0 935,3 -0,1

Central - Western 1.134,6 1.072,5 1.130,1 1.247,3 1.458,0 1.640,9 1.779,9 1.789,0 1.694,0 1.725,9 1.740,8 1.776,9 1.811,7 1.816,4 1.844,2 1.863,6 3,4Aguascalientes 31,1 33,1 35,7 37,8 39,0 40,3 41,6 43,0 44,3 45,4 46,7 47,8 48,9 50,0 51,0 52,0 3,5Colima 248,8 191,7 191,8 191,8 191,8 191,7 191,7 191,7 191,7 191,2 191,6 191,6 191,4 191,7 191,7 191,2 -1,7Guanajuato 257,4 260,6 256,9 302,4 305,4 305,7 345,4 349,8 353,8 357,3 361,1 364,7 433,8 372,3 376,8 379,4 2,6Jalisco 75,1 72,6 80,3 85,1 168,6 312,5 313,8 315,3 316,4 316,9 317,5 317,9 319,0 318,6 318,8 318,0 10,1Michoacán 127,7 124,1 129,5 133,0 132,5 132,4 132,3 132,2 132,1 131,9 131,7 131,5 131,3 131,1 130,8 130,5 0,1Querétaro 165,4 153,9 153,4 156,2 156,2 156,5 157,1 157,8 158,3 158,8 158,8 158,7 158,7 158,1 157,8 156,9 -0,3San Luis Potosí 220,0 230,5 276,3 334,7 458,0 495,2 591,3 592,5 490,7 517,6 526,7 557,9 521,9 588,0 610,6 629,0 7,3Zacatecas 9,2 6,0 6,1 6,3 6,4 6,5 6,6 6,7 6,8 6,8 6,8 6,8 6,8 6,7 6,7 6,6 -2,2

Central 919,4 1.030,5 979,0 978,0 988,7 1.076,5 1.093,3 1.098,3 1.048,7 1.006,3 1.007,2 1.010,4 1.026,4 1.128,9 1.210,5 1.293,5 2,3Ciudad de México 69,6 81,8 73,3 52,6 53,1 54,3 55,5 56,6 57,7 58,3 58,8 59,2 59,5 59,8 59,8 59,8 -1,0Hidalgo 269,3 264,5 268,7 237,3 259,6 336,7 349,7 350,6 358,2 358,1 358,2 358,3 358,5 479,7 495,5 494,3 4,1México 361,5 346,6 212,4 256,5 257,2 259,1 260,6 262,0 263,1 263,6 264,3 264,8 264,7 264,3 330,0 341,4 -0,4Morelos 12,5 119,2 206,6 221,0 203,2 222,3 222,4 222,7 159,5 114,9 115,0 115,2 115,2 115,3 115,3 188,3 19,8Puebla 172,7 180,3 179,2 170,7 175,0 171,7 172,1 172,8 176,2 177,0 175,8 177,4 183,8 173,7 173,7 173,2 0,0Tlaxcala 33,7 38,2 38,8 40,1 40,7 32,3 33,0 33,7 34,1 34,5 35,1 35,5 44,6 36,2 36,3 36,4 0,5

South-Southeast 1.834,3 2.587,2 2.594,0 2.515,6 2.518,4 2.592,2 2.691,5 2.691,6 2.653,0 2.569,8 2.440,0 2.353,2 2.302,9 2.169,4 2.044,9 1.951,0 0,4Campeche 112,4 344,9 344,8 293,5 341,0 375,1 419,0 437,2 411,6 428,0 377,0 344,8 317,8 290,3 256,5 238,1 5,1Chiapas 57,8 181,4 181,4 152,7 181,0 224,6 250,8 261,6 246,4 358,9 328,6 309,5 293,5 277,1 257,0 245,8 10,1Oaxaca 0,1 102,7 102,2 83,2 83,1 151,0 198,0 198,0 198,0 198,0 198,0 198,0 198,0 198,0 198,0 197,8 72,9Quintana Roo 0,0 0,0 0,0 0,0 0,0 0,1 0,1 0,1 0,2 0,3 0,3 0,4 0,5 0,6 0,7 0,9 n.a.Tabasco 694,4 818,4 846,6 854,5 778,0 657,9 657,9 641,7 641,0 525,7 457,1 407,8 376,3 279,1 238,9 203,0 -7,9Veracruz 862,7 946,2 964,9 979,6 983,2 981,5 947,1 980,2 1.000,7 936,2 949,1 957,5 953,1 941,3 902,1 867,3 0,0Yucatán 107,0 193,7 154,2 152,0 151,9 202,1 218,6 172,8 155,1 122,7 129,9 135,2 163,7 183,0 191,5 198,1 4,2

Territorial water 545,4 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 -48,7

53

3.1.4. Natural Gas Supply

According to the BP Statistical Review of World Energy, issued on June 201625, in 2015, the worldwide natural gas production reached a volume of 342,373.2 MMCFD. From the overall production, the U.S. contribute with 21.8% from the total. Based on the Annual Energy Outlook 2016, it is expected that by 2035, the U.S. natural-gas production will reach a volume of 109,071.0 MMCFD, which will be enough to meet the demand's increase, for domestic consumption, as well as for net exports. As for prices, the benchmark Henry Hub is estimated to remain low compared to other energy sources26.

The Energy Information Administration (EIA) expects that during 2015-2040, the production of dry gas will increase by 55%, due to a larger development of shale gas and to tight-oil plays. These sources' production will rise from 37,260.3 MMCFD in 2015 to 79,452.1 MMCFD in 204027.

Natural Gas Production Estimate

In Mexico, the CNH made an estimate on the natural gas production for the next 15 years (maximum and minimum scenarios), detailed enough to analyze the different types of activities, regions, and hydrocarbons quality. In this estimate, two main components were considered: extraction and exploration.

The extraction component includes fields with discovered reserves, where there is the certainty of subsoil resources, though its amount is uncertain. These fields are assigned profiles of production and investment for different certainty levels, profiles which are devised according to the volume of proven, probable, and possible reserves presented to CNH for each field.

The exploration component has information about exploratory opportunities that could be discovered and developed. These opportunities have a level of risk and of uncertainty associated, and therefore it is not possible to know beforehand if there are Hydrocarbons and, if the case, their volume.

In order to define the production and investment profiles of the component, it was designed an estimation model which incorporates the information available about exploratory opportunities and business reasoning of the companies which will potentially develop such opportunities. To carry out this estimate, the CNH used the following sources and information:

• Data about exploratory opportunities (BDOE, for its Spanish acronym) version 4-2014, devised by PEMEX.

• Databases of conventional and non-conventional plays, devised by PEMEX.

• Databases of prospected resources, devised by PEMEX.

• Databases of hydrocarbons reserves, devised by the Extraction Technical Unit from the Commission by January 1st, 2016.

• Quinquennial Plan on Biddings for the Exploration and Extraction of Hydrocarbons 2015-2019, prepared and updated by SENER to August 2016.

The methodology used to estimate production was based on the proposition that there are two kind of companies in the market: a company owned by the State and a private company. The first one is PEMEX, which has allocation areas granted by the State, according to an initial selection of exploratory opportunities made by the company. The State made the allocations on condition that the company will perform exploration and extraction activities in these areas within the first five years; after this period, the company

25 BP Statistical Review of World Energy. June 2016. 26 U.S. Energy Information Administration. Annual Energy Outlook 2016, p. 118. 27 Idem, p. 119.

54

will return those allocated areas which were not developed. PEMEX is regarded to have an initial restriction for investing on capital stronger than an international oil company.

The second company has private capital and can take part in the bidding rounds of the blocks offered every year by the State. During the bidding rounds, this company will be allocated with the blocks it wins. It is assumed that the private-capital company faces less capital restriction than a State-owned company, and keeps a higher incentive to make its offer competitive and obtain the allocation of the blocks it is interested in. The elements of the estimating model and the decision-making process of both companies are:

1. Devise of the rounds and blocks to put out to tender.

2. Selection of the best exploratory opportunities available.

3. Definition of developable opportunities within each block or allocation area.

4. Production simulation of each developable opportunity by block or allocation area.

5. Selection and allocation of the best blocks within each bidding round.

6. Accrual of the resulting production and investment profiles for the opportunities developed in the allocated blocks

Natural Gas Production

The results from the gas-production estimates for 2016-2030, for the minimum and maximum scenarios, are displayed according to the following classification:

• Minimum:

Extraction component: 2P reserves

Exploration component: medium

• Maximum:

Extraction component: 3P reserves

Exploration component: P10

The natural-gas production for the minimum scenario is projected to reach a volume of 2,691.8 MMCFD in 2030, which represents a decrease of 51.1% regarding 2015. In this scenario, it can be observed production suffers a fall during the first years, but becomes steady in 2024.

In the maximum scenario, production will decrease in the coming years, but in 2022 it will increase due to the production coming from the companies winning the tenders. The gas production is estimated to reach a 4,628 MMCFD volume by 2030, a decrease of 15.9% regarding 2015.

55

FIGURE 3. 6 NATURAL-GAS PRODUCTION*, MINIMUM AND MAXIMUM SCENARIOS. (MMCFD)

* Does not include Nitrogen. Source: SENER based on information from the CNH

The SENER, with the technical assistance of CNH, updated the original exploration blocks with big exploration areas, according with the most recent information about geological structures to make sure that the tendered areas have the necessary materiality and fostering thus, a high participation and competence in tenders.

Previously, the Quinquennial Plan on Biddings for the Exploration and Extraction of Hydrocarbons 2015-2019 and the Bidding Program estimated a 178,554.3 km2 surface for exploration and extraction, which was modified by 31.7% to be set in 235,070.0 km2. The CNH estimated the production of gas by type of activity based on information from the Quinquennial Plan and PEMEX.

As for extraction fields, it has been considered to put out for tender 237 fields for extracting hydrocarbons, from which 92 are protected allocations with a current production of hydrocarbons and a remnant volume of 27,759.5 million barrels of crude oil equivalent (MMBCOE). The remaining fields had an estimate remnant resource of 40,384.3 MMBCOE.

In the exploration of conventional hydrocarbons, 72 exploration areas are considered, from which 9 are located in the Province of Burgos, 14 in Tampico-Misantla, 10 in Veracruz, 2 in Macuspana, 1 in Pilar Reforma-Akal, one in Cinturon Plegado of Catemaco, 16 in Salina del Istmo, one in Yucatan Platform, 13 in Area Perdido, and 5 in Cordilleras Mexicanas.

As for the production related to extraction, for the maximum scenario, it is estimated to decrease 62.3% regarding 2016, reaching an 1,896 MMCFD volume in 2030. This decrease is due to the decline of the fields allocated to Pemex and which are currently producing.

The production related to the exploration activity will be reflected by 2019, when the fields allocated in the bidding rounds start up, reaching their maximum volume by 2027 with 2,847.8 MMCFD; their production by 2030 will be of 2,731.9 MMCFD.

0.0

1,000.0

2,000.0

3,000.0

4,000.0

5,000.0

6,000.0

7,000.0

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Minimum scenario Maximum scenario

56

FIGURE 3. 7 GAS PRODUCTION BY ACTIVITY, MAXIMUM SCENARIO 2016-2030 (MMCFD)

Source: SENER based on information from the CNH.

In the minimum scenario, the production from extraction activities is expected to decrease by 75.2% regarding 2016, reaching a volume of 1,246.4 MMCFD, given the investment on the extraction fields will be the smallest, and because it depends on the volume of hydrocarbons extracted from each field. The production related to exploration will reach a volume of 1,445.5 MMCFD in 2030, having its peak in 2027 with a 1,632.8 MMCFD volume.

FIGURE 3. 8 GAS PRODUCTION BY ACTIVITY, MINIMUM SCENARIO 2016-2030 (MMCFD)

Source: SENER based on information from the CNH.

0.0

1,000.0

2,000.0

3,000.0

4,000.0

5,000.0

6,000.0

7,000.0

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Extraction Exploration

0.0

1,000.0

2,000.0

3,000.0

4,000.0

5,000.0

6,000.0

7,000.0

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Extraction Exploration

57

In the maximum scenario, the gas production coming from offshore areas will increase 8.5% regarding 2016, reaching 2,621.7 MMCFD, 25.6% from the total production. On the other hand, the production from shallow water will reach a 1,935.7 MMCFD volume, and the one from deep water, 70.8 MMCFD.

FIGURE 3. 9 GAS PRODUCTION BY REGION, MAXIMUM SCENARIO 2016-2030 (MMCFD)

Source: SENER with information from the CNH.

As for the minimum scenario, the gas production from offshore areas will decrease 32.7% regarding 2016, reaching a volume of 1,615.6 MMCFD in 2030. The production from shallow water will decrease 60.3%, reaching a volume of 1,044.6 MMCFD during that same year. The production from deep water will reach a 31.6 MMCFD volume in 2030.

FIGURE 3. 10 GAS PRODUCTION BY REGION, MINIMUM SCENARIO 2016-2030. (MMCFD)

Source: SENER based on data from the CNH.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Deep marine areas Shallow marine areas Onshore areas

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Deep marine areas Shallow marine areas Onshore areas

58

It is projected that, by 2030, the production of associated gas will reach a volume of 2,303.4 MMCFD in the maximum scenario, a decrease of 43.1% regarding 2016. Associated gas will become relevant in 2022 due to the startup of offshore gas fields, reaching a volume of 2,324.8 MMCFD in 2030. It is important mentioning that, in 2030, associated and non-associated gas will have a share of about 50%.

FIGURE 3. 11 PRODUCTION OF NATURAL GAS BY ORIGIN, MAXIMUM SCENARIO, 2016-2030. (MMCFD)

Source: SENER based on data from the CNH.

In the minimum scenario, associated gas is estimated to reach a volume of 1,598.9 MMCFD in 2030, which will represent a share of 59.4% from a total production. As for non-associated gas, it will have a 40.6% share with a volume of 1,092.9 MMCFD.

FIGURE 3. 12 NATURAL-GAS PRODUCTION BY ORIGIN, MINIMUM SCENARIO 2016-2030. (MMCFD)

Source: SENER based on data from the CNH.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Associated Non associated

0

1,000

2,000

3,000

4,000

5,000

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7,000

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Associated Non associated

59

3.1.5. Infrastructure

On July 25, 2016, SENER published the first annual review the Quinquennial Plan for the Expansion of the SISTRANGAS 2015-2019 (Quinquennial Plan). This reviewing exercise was proposed by CENAGAS to verify the validity of the projects contained in the Quinquennial Plan issued on October 14, 2015, according to the behavior of the natural-gas market.

Based on this review, the projects currently valid in the Quinquennial Plan are: Gas pipeline San Isidro-Samalayuca, Gas pipeline Samalayuca-Sasabe, Gas pipeline Tuxpan-Tula, Gas pipeline Tula-Villa de Reyes, Gas pipeline Villa de Reyes-Guadalajara, Gas pipeline La Laguna-Aguascalientes, Gas pipeline South of Texas-Tuxpan, Jaltipan-Salina Cruz, Lazaro Cardenas-Acapulco, Nueva Era (Mexico Midstream), Salina Cruz-Tapachula, and Ramones-Cempoala. These projects' characteristics are displayed in the table below, 3.9, and the details of each one are contained in the document of the First Review of the Quinquennial Plan 2015-2019.

It is important to point out the projects of Lazaro Cardenas-Acapulco and Salina Cruz-Tapachula are considered in the Quinquennial Plan; though, these projects can be deferred or their route plot can be reconsidered, seeking for the best conditions, economic as well as of economic impact to the country.

TABLE 3. 9 INFRASTRUCTURE PROJECTS CONSIDERED IN THE QUINQUENNIAL PLAN, 2015-2019

* According to public information issued by CFE. ** Information originally considered in the Quinquennial Plan 2015-2019. *** Length declared by TAG Pipelines, S de RL de CV. ****According to what was published by Howard Energy (Midstream Mexico). Source: SENER with information from Quinquennial Plan.

#Projects awarded from the

Quinquennial Plan 2015-2019States benefited

Length* (kilometers)

Estimated investment (million

dollars)*Awarding date* Startup date*

1 Tuxpan -Tula Hidalgo, Puebla and Veracruz

283 458 2015 2017

2 La Laguna -Aguascalientes Aguascalientes, Durango and Zacatecas

600 473 2016 2018

3 Tula -Villa de Reandes Hidalgo and San Luis Potosí 420 554 2015 2018

4 Villa de Reandes - Guadalajara Aguascalientes, Jalisco and San Luis Potosí

305 294 2016 2018

5 San Isidros -Samalaanduca Chihuahua 23 109 2015 2017

6 Samalaanduca - Sásabe Chihuahua and Sonora 650 571 2015 2017

7 Sur de Texas-Tuxpan Tamaulipas and Veracruz 800 2.111 2016 2018

# Projects under evaluation States benefitedLength

(kilometers)

Estimated investment (million

dollars)***

Projected bidding date

Startup date

8 Jáltipan-Salina Cruz Oaxaca and Veracruz 247 643 2016-2017 2018-2019

9 Lázaro Cárdenas -Acapulco Guerrero and Michoacán 331 456 2016-2017 2018-2019

# Other projects States benefitedLength

(kilometers)

Estimated investment (million

dollars)*

Projected bidding date

Startup date

10 Nueva Era (Midstream México) Nuevo León 302**** n.d. Development at its own risk and expense 2017****

11Salina Cruz-Tapachula Chiapas and Oaxaca

400*** 442** Development at its own risk and expense 2019

12 Los Ramones-Cempoala Nuevo León and Veracruz 855** 1980** 2018 2020

60

The following map shows the projects on gas pipelines infrastructure during 2015-2030.

FIGURE 3. 13 GAS-PIPELINES NETWORK 2015-2030

Source: SENER, with information from CENAGAS y PRODESEN

3.1.6. Foreign Trade

Towards the future, the U.S. is expected to go from a net importer of natural gas (with 2,732.2 MMCFD by 2015, equivalent to 3% of that country's total supply), to becoming a net exporter in 2018. In 2040, net natural-gas exports to the U.S. will reach 20,547.9 MMCFD. The gas production levels and surpluses will enable the export of LNG. Most of the LNG export capacity is currently under construction. After 2021, net exports from the U.S. will grow at a 4% AAGR28. During 2020, Mexico will become a fast-growing market for American natural gas, while Canada will remain as a modest net exporter to the U.S.

By 2030, it is foreseen natural-gas production will reach a volume of 3,737.5 MMCFD; though, this production will not cover the total domestic demand, which is expected to reach 9,030.4 MMCFD, so it will be necessary to resort to imports.

In 2030, natural-gas imports will increase 52.4% regarding 2015, reaching a volume of 5,406.9 MMCFD and a AAGR of 2.8% during 2015-2030. It is expected that, from 2017 on, all the gas imports will be performed through pipelines, due to the startup of the new pipelines infrastructure within the coming years. As for exports, these will reach a 113.9 MMCFD volume in 2030, which represents a 15.9% AAGR during 2015-2030.

28 U.S. Energy Information Administration. Annual Energy Outlook 2016, p. 141.

Gas pipellines operated by CENAGASGas pipellines operated by private partiesGaspipelines under construction Gaspipelines considered in the Quinquennial Plan Other projects

Los Algodones

San Luis Río Colorado

Escobedo

Samalayuca

San Isidro

PuertoLibertad

Sásabe

El EncinoGuaymas

La Laguna

Cd. Mier

Durango

Zacatecas

Aguascalientes

Guadalajara

San Luis Potosí

V. Reyes

Toluca

Los Naranjos

Tamazunchale

Huexca (Morelos)

Nativitas (Puebl)a

Lázaro Cárdenas

Salina Cruz

Merida

Tijuana

Ensenada

Pedro Escobedo

Camargo

Matamoros

Ojinaga

El Oro

Topolobampo

Waha

Colombia

Brownsville

Nueces

Mazatlán

Acapulco

61

FIGURE 3. 14 NATURAL GAS IMPORTS, 2015-2030. (million cubic feet per day)

Source: IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, PEMEX, SENER and private companies.

3.1.7. National Balance 2015-2029

In 2030, the demand for dry natural gas will reach a 9,030.4 MMCFD volume, an AAGR of 1.2% during 2015-2030. As for production, the volume is expected to be of 3,737.5 MMCFD, 8.1% less regarding 2015, and with a -0.6% AAGR. On the other side, in 2030, imports will reach 5,406.9 MMCFD, and exports, 113.9 MMCFD.

In 2030, the Northeast region will present a demand of 2,981.0 MMCFD, an increase of 21.0% regarding 2015; and its production will be of 1,547.0 MMCFD. The latter will not be enough to meet the demand so there will be needed to resort to imports for 4,464.7 MMCFD; exports will be of 3,030.7 MMCFD.

The Northwest region will present a demand of 942.2 MMCFD, an increase of 55.4% regarding 2015, and will resort to imports for covering its demand, since the region does not produce dry gas.

The Central and Central-Eastern regions do not produce dry gas, and they shall resort to imports from other regions to cover their demands. The Central region will demand 1,293.5 MMCFD in 2030, and the Central-Eastern, 1,863.6 MMCFD.

The South-Southeast region will demand a volume of 1,950.1 MMCFD, and will produce 2,190.5 MMCFD. From this production, it will export 126.4 MMCFD to other regions, and 113.9 MMCFD will be exported to Central America. The natural-gas regional balances are presented in Annex Table A.22-A.26.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Import Demand Production

62

TABLE 3. 10 NATURAL GAS DOMESTIC BALANCE, 2015-2030. (MMCFD)

Source: prepared by IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

Concept 2015 2016 2017 2018 2019 2020 2021 2022 AAGR 2015-2022

AAGR2015-2030

Origin 7,614.8 7,634.3 7,843.4 7,977.9 8,421.3 8,692.4 8,869.4 8,981.9 2.4 1.2

Domestic production 4,066.8 3,782.2 3,680.4 3,603.2 3,527.7 3,461.1 3,479.5 3,533.8 2.0- 0.6-

Production in plants 4,066.8 3,782.2 3,680.4 3,603.2 3,527.7 3,461.1 3,479.5 3,533.8 2.0- 0.6-

Import 3,548.0 3,852.1 4,163.0 4,374.7 4,893.6 5,231.3 5,389.9 5,448.1 6.3 2.8

Destination 7,516.6 7,634.3 7,843.4 7,977.9 8,421.3 8,692.4 8,869.4 8,981.9 2.6 1.3

Domestic demand 7,504.1 7,632.9 7,842.1 7,974.8 8,419.7 8,676.7 8,850.9 8,960.4 2.6 1.2

Oil sector 2,200.0 2,270.5 2,270.5 2,149.5 2,104.2 2,248.6 2,388.1 2,399.3 1.2 2.7-

Industrial sector 1,375.8 1,435.4 1,737.0 1,905.3 1,931.8 1,960.3 1,985.5 2,011.1 5.6 2.9

Electricity sector 3,797.6 3,792.8 3,693.7 3,772.9 4,231.5 4,310.5 4,316.9 4,386.3 2.1 2.2

Residential sector 94.6 98.5 103.9 108.6 112.1 115.5 116.9 118.2 3.2 1.6

Services sector 33.7 32.9 33.8 35.0 36.3 37.4 38.7 40.0 2.5 2.8

Motor-carrier sector 2.4 2.9 3.1 3.4 3.7 4.3 4.9 5.4 12.5 9.8

Export 12.5 1.3 1.3 3.1 1.5 15.7 18.5 21.6 8.1 15.9

Inventories variation and differences 98.2 - - - - - - - n.a. n.a.

Concept 2023 2024 2025 2026 2027 2028 2029 2030 AAGR 2023-2030

AAGR2015-2030

Origin 8,984.7 8,906.6 8,898.7 8,946.3 9,030.5 9,039.4 9,086.2 9,144.4 0.3 1.2

Domestic production 3,800.1 4,050.8 4,069.6 4,239.2 4,253.9 4,121.0 3,900.2 3,737.5 0.2- 0.6-

Production in plants 3,800.1 4,050.8 4,069.6 4,239.2 4,253.9 4,121.0 3,900.2 3,737.5 0.2- 0.6-

Import 5,184.6 4,855.8 4,829.1 4,707.0 4,776.6 4,918.4 5,186.1 5,406.9 0.6 2.8

Destination 8,984.7 8,906.6 8,898.7 8,946.3 9,030.5 9,039.4 9,086.2 9,144.4 0.3 1.3

Domestic demand 8,958.1 8,873.9 8,858.4 8,896.7 8,969.5 8,964.3 8,993.8 9,030.4 0.1 1.2

Oil sector 2,201.1 2,050.3 1,877.7 1,769.6 1,689.0 1,608.8 1,520.1 1,451.1 5.8- 2.7-

Industrial sector 2,029.1 2,042.8 2,058.0 2,071.3 2,083.6 2,092.1 2,097.0 2,097.3 0.5 2.9

Electricity sector 4,560.6 4,610.9 4,750.8 4,882.0 5,021.4 5,085.6 5,197.1 5,301.2 2.2 2.2

Residential sector 120.0 120.7 120.9 121.0 120.8 121.4 120.9 120.4 0.0 1.6

Services sector 41.4 42.8 44.1 45.4 46.7 48.1 49.5 50.9 3.0 2.8

Motor-carrier sector 5.9 6.4 6.9 7.4 7.9 8.4 9.1 9.6 7.1 9.8

Export 26.6 32.7 40.3 49.5 61.0 75.1 92.5 113.9 23.1 15.9

Inventories variation and differences - - - - - - - - n.a. n.a.

63

4. Chapter four. Sensitivity Analysis

For this outlook, the sensitivity analysis for the natural-gas demand was prepared considering three macroeconomic scenarios (base, high, and moderate). For the base scenario, the growth will be 2.9%, average, 3.6% for the high scenario, and 2.4% for the moderate one, during 2016-2030. It was also considered a low-savings scenario, related to the motor-carrier, industrial, residential, and services sectors.

The assumptions considered for the base scenario are the following:

• The standardization of the American monetary policy and the rise of its interest rates, generate uncertainty within the financial and exchange markets, strengthening the U.S. dollar and weakening other currencies.

• The exit of the United Kingdom from the European Union emphasizes the financial and currency uncertainty in the short term, and will weaken ever more the worldwide trade and economy in the medium and long terms.

• China's economy loss of dynamism affects international trade, particularly emerging economies.

• The dropping in the prices of raw materials and commodities, reduce the revenues of producing countries and limiting thus, their demand for goods and services.

• The industrial sector contraction in the United States as an impact on their economic activity.

• Budgetary cuts in 2016 and 2017 will narrow economic growth potential.

• Financial and Exchange markets turmoil

• Tightening of the monetary policy and rises on the interest rates.

• The domestic market and its determiners will lose dynamism

• The Energy Reform will foster the oil and the electricity-generation sectors.

For the moderate scenario (low) it was considered the following:

• Oil-supply worldwide surplus keeps oil prices below $100 per barrel at the medium term.

• The normalization of the American monetary policy has an effect over the financial and exchange markets of emerging countries.

• The United Kingdom's exit from the E.U., have an impact on important trade agreements and over the economic growth of the Eurozone.

• China's economic slowdown is deeper than expected.

• The prices' drop of raw materials and commodities, will continue reducing the revenues of producing countries limiting their demand for goods and services.

• The American economic growth is lower than expected.

64

• U.S. industrial crisis becomes more acute impacting Mexican industry and manufacturing sector.

• The exchange turmoil spreads and widens.

• The determiners of the domestic market are weakening, unable to counteract the negative effects from abroad.

Finally, for the high scenario, the assumptions are:

• Drop of the prices of raw materials and commodities.

• Discoordination of the monetary policies in advanced economies.

• Uncertainty in emerging economies.

• Less dynamism of the American economy.

• Normalization of the U.S. monetary policy.

• Turmoil in financial markets.

• Employment formalization, revenues from real salaries, and credit expansion, which foster consumption and investment.

• Family remittances go on in the medium and long term.

• The oil production platform recovers, thanks to the Energy Reform.

• The advances in infrastructure to transport hydrocarbons will reduce costs, and foster their consumption.

• The Financial Reform has generated the necessary means to have access to financing at lower rates and to higher credit amounts.

The results of the industrial, residential, and services sectors are shown according to the latter. The industrial sector's demand in the base scenario reaches a volume of 2,097.3 MMCFD, of 2,281.8 MMCFD in the high scenario, and of 1,979.3 MMCFD in the low scenario. In the low-savings scenario, derived from the efficiencies in each sector's branch, the demand will reach a volume of 2,397.4 MMCFD (see Figure 4.1).

65

FIGURE 4. 1 INDUSTRIAL SECTOR DEMAND, 2010-2030 (MMCFD)

Source: prepared by IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

For the residential sector, the three scenarios have a constant volume of 120.4 MMFCD in 2030; and in the low-savings scenario, its demand will reach a volume of 137.7 MMCFD (see Figure 4.2).

FIGURE 4. 2 RESIDENTIAL SECTOR DEMAND, 2010-2030 (MMCFD)

Source: prepared by IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

-

500.0

1,000.0

1,500.0

2,000.0

2,500.0

3,000.0

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Base scenario Base scenario-low saving Moderate scenario High scenario

50.0

60.0

70.0

80.0

90.0

100.0

110.0

120.0

130.0

140.0

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Base scenario Base scenario-low saving Moderate scenario High scenario

66

Finally, in the services sector, the difference between the demands of the different scenarios is not very significant: in the base scenario, the demand will reach a volume of 50.9 MMCFD; in the high scenario, 51.9 MMCFD; in the low scenario, 50.0 MMCFD; and in the low-savings’, 58.4 MMCFD.

FIGURE 4. 3 SERVICES SECTOR DEMAND, 2010-2030 (MMCFD)

Source: prepared by IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

20.0

25.0

30.0

35.0

40.0

45.0

50.0

55.0

60.0

65.0

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Base scenario Base scenario-low saving Moderate scenario High scenario

67

Annexes

TABLE A. 1 REGIONAL COMPOSITION OF THE VEHICLE FLEETBY FUEL, 2005-2015 ..................................... 68

TABLE A. 2 DOMESTIC DEMAND FOR FUELS IN THE RESIDENTIAL SECTOR, 2005-2015 ............................ 68

TABLE A. 3 NATURAL GAS CONSUMPTION IN THE OIL SECTOR, 2005-2015 ................................................ 68

TABLE A. 4 DOMESTIC DEMAND FOR FUELS IN THE RESIDENTIAL SECTOR, 2005-2015 ............................ 69

TABLE A. 5 DOMESTIC DEMAND FOR FUELS IN THE SERVICES SECTOR,............................................................ 69

TABLE A. 6 NATURAL GAS DEMAND BY REGION AND STATE, ............................................................................. 70

TABLE A. 7 NATURAL-GAS PRICES TO END USERS IN THE MAIN CITIES OF THE COUNTRY, FEBRUARY, 2016. .......................................................................................................................................................................................... 71

TABLE A. 8 NATURAL GAS FOREIGN TRADE BY INTERCONNECTION POINT, 2005-2015 ......................... 72

TABLE A. 9 NATURAL GAS BALANCE OF THE NORTHWEST REGION, 2005-2015 ........................................ 73

TABLE A. 10 NATURAL GAS BALANCE OF THE NORTHEAST REGION, ............................................................... 73

TABLE A. 11 NATURAL GAS BALANCE OF THE CENTRAL-EASTERN REGION, 2005-2015 ......................... 74

TABLE A. 12 NATURAL GAS BALANCE OF THE CENTRAL REGION, 2005-2015 ............................................. 74

TABLE A. 13 NATURAL GAS BALANCE OF THE SOUTH-SOUTHEAST REGION, 2005-2015 ...................... 75

TABLE A. 14 NATURAL GAS DEMAND BY GROUP OF BRANCHES, 2015-2030 ............................................... 75

TABLE A. 15 REGIONAL COMPOSITION OF THE VEHICLE FLEETBY FUEL, 2015-2030 .................................. 76

TABLE A. 16 NATURAL GAS BALANCE OF THE NORTHEAST REGION, 2015-2030 ...................................... 76

TABLE A. 17 NATURAL GAS BALANCE OF THE NORTHWEST REGION, 2015-2030 ..................................... 77

TABLE A. 18 NATURAL GAS BALANCE OF THE CENTRAL-EASTERN REGION, 2015-2030 ......................... 78

TABLE A. 19 NATURAL GAS BALANCE OF THE CENTRAL REGION, 2015-2030 ............................................. 79

TABLE A. 20 NATURAL GAS BALANCE OF THE SOUTH-SOUTHEAST REGION, 2015-2030 ...................... 80

68

TABLE A. 1 REGIONAL COMPOSITION OF THE VEHICLE FLEETBY FUEL, 2005-2015 (thousand units)

Source: IMP, based on information from private companies.

TABLE A. 2 DOMESTIC DEMAND FOR FUELS IN THE RESIDENTIAL SECTOR, 2005-2015

(MBDLPGE)

Source: IMP, based on information from CRE, PGPB and private companies.

TABLE A. 3 NATURAL GAS CONSUMPTION IN THE OIL SECTOR, 2005-2015 (million cubic feet per day)

¹ Includes the consumption of Cantarell’s Compañía Nitrógeno. Source: IMP, based on information from Pemex.

Fuel 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015AAGR

2005-2015

Compressed natural gas 2 3 3 3 2 1 2 2 4 3 3 5.0

Gasoline 16,667 19,199 21,182 23,147 24,160 25,241 26,802 28,369 30,100 30,747 32,338 6.9

LP gas 305 235 221 196 185 185 203 232 250 254 250 2.0-

Diesel 672 701 738 774 780 791 799 845 898 855 842 2.3 Total 17,646 20,137 22,144 24,120 25,127 26,219 27,805 29,448 31,252 31,858 33,434 6.6

Branch 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 AAGR2005-2015

Total 935.2 1,014.0 1,040.1 1,026.6 912.8 1,054.3 1,129.2 1,181.1 1,239.9 1,313.5 1,375.8 3.9

Food 89.1 92.3 95.9 96.0 102.9 111.5 122.8 132.6 125.7 132.0 130.0 3.9

Cellulose and paper 52.3 63.8 65.2 69.9 62.9 63.8 63.6 76.8 83.8 81.4 90.1 5.6

Cement 13.0 18.1 10.7 8.7 11.7 9.6 8.5 17.4 11.4 13.4 13.2 0.2

Beer and malt 15.3 18.9 16.6 17.7 15.8 16.2 18.6 22.0 39.1 34.9 38.3 9.6

Basic metals 279.5 293.6 305.6 299.3 223.4 287.5 301.4 299.2 326.1 340.4 347.4 2.2

Mining 23.8 23.8 22.4 20.3 17.5 21.4 21.6 23.1 23.8 17.2 14.2 -5.0

Non-metallic mineral products

63.9 68.3 69.4 66.2 58.2 74.2 80.9 82.6 83.1 80.1 86.6 3.1

Metallic products, eelectrical and transportation equipment

103.4 106.9 111.2 106.3 95.0 110.6 124.6 130.1 123.3 135.2 137.6 2.9

Chemistry 115.9 127.1 131.7 132.3 135.2 155.8 165.6 167.3 170.0 204.4 200.4 5.6

Rest 53.6 61.6 65.3 59.0 51.9 63.4 71.3 72.0 91.1 99.4 143.6 10.4

Textile 30.4 33.9 35.0 34.4 34.4 35.3 37.8 37.6 38.0 39.3 41.8 3.2

Glass 95.0 105.6 111.1 116.6 104.0 105.0 112.6 120.4 124.5 136.0 132.5 3.4

Concept 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 AAGR2005-2015

Total 2,030 2,160 2,125 2,175 2,149 2,237 2,186 2,273 2,272 2,276 2,200 0.8

Corporate 0.4 0.5 0.5 0.4 0.5 0.5 0.5 0.3 0.3 0.3 0.3 -3.0

Refining 274.9 279.5 282.4 306.0 299.3 337.8 332.9 343.5 348.8 375.7 385.3 3.4

Gas and Basic Petrochemistry 250.9 262.9 268.4 287.6 291.4 289.0 292.0 274.8 213.4 196.1 182.1 -3.2

Exploration and Production 1 1,240.2 1,324.8 1,251.2 1,236.4 1,239.8 1,289.4 1,240.9 1,313.8 1,288.8 1,285.4 1,254.7 0.1

PetroChemistry 263.5 292.0 322.9 344.5 318.4 319.9 320.0 340.6 349.1 332.0 236.1 -1.1

Cogeneration Nuevo Pemex - - - - - - - - 71.8 86.1 87.6 n.a.

Sales to PF 19.4 n.a.

Sales to PE 34.4 n.a.

69

TABLE A. 4 DOMESTIC DEMAND FOR FUELS IN THE RESIDENTIAL SECTOR, 2005-2015 (MMCFDNGE)

Source: IMP, based on information from SENER, PGPB and private companies

TABLE A. 5 DOMESTIC DEMAND FOR FUELS IN THE SERVICES SECTOR, 2005-2015 (MMCFDNGE)

Source IMP, based on information from SENER and PEMEX.

Natural gas LP gas FirewoodMMCFD MMCFDNGE MMCFDNGE MMCFDNGE

2005 86.6 776.7 492.3 1,355.6

2005 84.5 769.0 488.8 1,342.3

2006 88.5 760.8 485.9 1,335.1

2007 87.4 743.3 482.1 1,312.8

2008 82.9 712.3 481.1 1,276.3

2009 85.7 730.9 477.9 1,294.5

2010 81.7 709.8 471.2 1,262.7

2011 84.1 696.9 462.6 1,243.6

2012 86.7 663.5 456.1 1,206.3

2013 87.8 663.0 447.9 1,198.7

2015 94.6 653.5 439.4 1,187.4AAGR

2005-20150.9 -1.7 -1.1 -1.3

Year

Residential sector fuelsTotal

Natural gas LP gas FirewoodMMCFD MMCFDNGE MMCFDNGE MMCFDNGE

2005 20.5 171.0 78.8 270.3

2006 23.3 177.9 78.2 279.3

2007 24.2 164.8 77.7 266.8

2008 25.3 154.9 77.1 257.4

2009 24.5 153.9 77.0 255.4

2010 26.6 157.3 76.5 260.4

2011 25.2 162.7 75.4 263.4

2012 27.0 165.4 74.0 266.4

2013 28.5 168.3 73.0 269.7

2014 29.9 163.3 71.7 264.8

2015 33.7 162.9 70.3 266.9

AAGR2005-2015

5.1 -0.5 -1.1 -0.1

TotalServices sector fuels

Year

70

TABLE A. 6 NATURAL GAS DEMAND BY REGION AND STATE, 2005-2015 (million cubic feet per day)

Source: IMP with information from Pemex Gas and Basic Petrochemistry.

State 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015AAGR

2005-2015

Northwest 334.4 391.5 376.3 428.9 408.3 380.0 399.3 445.3 437.7 496.7 606.2 6.1

Baja California 248.1 282.8 265.8 303.2 289.2 255.6 276.2 317.6 306.1 334.2 349.4 3.5

Sonora 86.4 108.7 110.6 125.7 119.1 124.4 123.1 127.7 131.6 162.5 256.8 11.5

Northeast 1,418.7 1,634.1 1,785.8 1,807.9 1,834.0 1,965.6 2,219.3 2,217.0 2,263.2 2,350.1 2,464.2 5.7

Chihuahua 199.3 229.6 258.5 266.0 276.4 280.7 306.5 322.1 336.8 366.4 347.6 5.7

Coahuila 122.1 129.7 136.3 142.3 127.3 139.2 156.5 174.1 201.5 208.4 235.5 6.8

Durango 71.8 98.6 107.5 107.8 112.3 153.3 186.6 193.1 163.1 196.4 200.5 10.8

Nuevo León 554.6 607.0 604.1 617.4 591.2 633.4 667.7 672.4 675.8 687.4 724.4 2.7

Tamaulipas 470.9 569.2 679.3 674.3 726.8 759.0 902.0 855.4 886.0 891.5 956.1 7.3

Central-Eastern 518.0 564.8 637.3 705.0 666.2 703.4 728.9 789.4 880.3 1,053.6 1,134.6 8.2

Aguascalientes 10.7 12.6 12.4 12.8 13.2 16.9 19.2 20.9 21.3 19.1 31.1 11.2

Colima 53.6 125.9 216.7 248.8 n.a.

Guanajuato 194.8 217.7 219.6 220.4 201.0 211.2 217.0 226.4 245.3 259.1 257.4 2.8

Jalisco 45.6 48.0 47.2 50.0 50.4 54.2 57.1 59.4 59.2 68.4 75.1 5.1

Michoacán 125.9 134.5 139.7 131.6 65.9 111.2 119.9 114.3 124.1 131.9 127.7 0.1

Querétaro 114.7 121.2 111.6 118.1 157.4 138.4 127.0 143.5 128.6 160.0 165.4 3.7

San Luis Potosí 26.4 30.8 106.9 172.1 178.3 171.6 188.8 171.3 174.3 198.4 220.0 23.6

Zacatecas 1.6 9.2 n.a.

Central 604.0 642.7 639.1 655.8 672.9 712.1 752.4 754.1 818.0 767.1 919.4 4.3

Distrito Federal 56.6 55.6 50.9 48.6 50.2 64.1 70.1 74.5 71.4 59.1 69.6 2.1

Hidalgo 169.9 181.6 151.1 168.8 155.2 153.4 149.9 162.9 205.3 196.5 269.3 4.7

México 283.5 300.9 321.7 319.5 348.1 329.2 335.0 316.6 341.2 300.7 361.5 2.5

Morelos 1.2 8.4 9.8 12.5 n.a.

Puebla 78.3 87.8 98.4 102.1 97.7 141.4 172.3 170.3 162.1 170.6 172.7 8.2

Tlaxcala 15.7 16.8 17.0 16.9 21.7 24.0 25.1 28.6 29.6 30.4 33.7 7.9

South-Southeast 2,212.4 2,439.9 2,487.3 2,512.3 2,522.7 2,579.8 2,412.4 2,472.6 2,553.1 2,541.9 2,379.7 0.7

Campeche 108.5 116.5 135.4 740.2 89.3 124.1 105.3 120.0 121.7 118.9 112.4 0.4

Chiapas 384.3 419.0 450.8 542.8 577.1 561.4 76.6 76.6 67.9 62.7 57.8 17.3-

Oaxaca 0.0 1.4 3.0 4.1 4.0 0.0 0.0 0.0 0.0 0.0 0.1 11.4

Tabasco 151.5 147.0 152.9 174.7 182.3 191.3 663.0 651.8 702.2 696.1 694.4 16.4

Veracruz 735.8 843.9 904.0 882.4 900.6 917.2 844.9 866.7 951.9 955.4 862.7 1.6

Yucatán 83.9 108.7 151.4 168.1 168.7 151.8 122.5 114.7 113.2 119.6 107.0 2.5

Territorial water 748.4 803.4 689.8 600.7 634.0 600.1 642.8 596.1 589.1 545.4 3.1-

Domestic total 5,087.6 5,672.9 5,925.9 6,109.9 6,104.0 6,340.9 6,512.2 6,678.4 6,952.4 7,209.3 7,504.1 4.0

71

TABLE A. 7 NATURAL-GAS PRICES TO END USERS IN THE MAIN CITIES OF THE COUNTRY, FEBRUARY, 2016.

(dollars per million BTU)

* Includes differences, packaging, and ships in transit. Source: IMP, based on Pemex and SENER.

Molecule price

(USD/BTU)

Transportation

charges

Distribution tariff Retail price

Molecule price

(USD/BTU)

Transportation

charges

Distribution tariff Retail price

Molecule price

(USD/BTU)

Transportation

charges

Distribution tariff Retail price

Piedras Negras 2.1 1.2 7.3 10.6 2.1 1.2 2.6 5.9 2.1 1.2 0.2 3.5

Valle-Cuautitlan 2.0 0.7 3.4 6.1 2.0 0.7 1.4 4.2 2.0 0.7 0.8 3.5

Ciudad Juárez 2.0 0.2 3.7 6.0 2.0 0.2 3.2 5.5 2.0 0.2 1.1 3.4

Puebla-Tlaxcala 2.0 0.7 6.5 9.2 2.0 0.7 0.9 3.6 2.0 0.7 0.7 3.4

North de Tamaulipas 2.1 0.5 6.0 8.6 2.1 0.5 1.3 3.8 2.1 0.5 1.1 3.7

Chihuahua 2.1 0.7 8.1 10.9 2.1 0.7 1.6 4.4 2.1 0.7 0.7 3.5

La Laguna-Durango 2.1 0.7 12.8 15.7 2.1 0.7 3.9 6.7 2.1 0.7 2.1 4.9

Mexicali 2.3 0.2 6.9 9.4 2.3 0.2 3.2 5.7 2.3 0.2 1.6 4.1

Guadalajara 2.0 0.8 5.7 8.5 2.0 0.8 2.7 5.5 2.0 0.8 1.9 4.7

Rio Panuco 2.0 0.6 8.4 11.0 2.0 0.6 4.6 7.1 2.0 0.6 4.3 6.8

Queretaro 2.0 0.8 4.2 7.0 2.0 0.8 3.0 5.8 2.0 0.8 2.9 5.8

Toluca 2.0 1.4 7.1 10.4 2.0 1.4 2.2 5.5 2.0 1.4 0.4 3.7

Nuevo Laredo 2.1 0.5 10.4 13.0 2.1 0.5 3.0 5.6 2.1 0.5 0.8 3.4

Saltillo 2.1 0.5 7.7 10.3 2.1 0.5 1.8 4.4 2.1 0.5 0.5 3.1

Monterrey 1 2.1 0.5 7.9 10.5 2.1 0.5 2.2 4.8 2.1 0.5 0.4 3.0

El Bajio 2.0 0.8 6.4 9.2 2.0 0.8 2.0 4.8 2.0 0.8 0.7 3.5

Distrito Federal 2.0 0.8 6.7 9.5 2.0 0.8 2.0 4.7 2.0 0.8 0.6 3.4

Monterrey 2 2.1 0.5 4.0 6.6 2.1 0.5 2.7 5.2 2.1 0.5 0.8 3.4

Hermosillo 2.1 0.4 8.8 11.3 2.1 0.4 4.5 7.0 2.1 0.4 2.5 5.0

Valle Cuautitlán-Texcoco 2.0 0.7 8.1 10.8 2.0 0.7 3.8 6.5 2.0 0.7 1.7 4.5

Distribution zone

Residential Services Industrial

72

TABLE A. 8 NATURAL GAS FOREIGN TRADE BY INTERCONNECTION POINT, 2005-2015

(million cubic feet per day)

1 Includes CFE and IEP. 2 Includes imports from Cd. Juárez, San Agustín Valdivia, and San Isidro Source: Prepared by IMP, based on information from CRE, CFE, Pemex, SENER and private companies.

Interconnection point in Mexico Importers 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 AAGR2005-2015

Total Imports 905.5 1,018.4 1,103.6 1,336.1 1,257.6 1,458.9 1,749.4 2,129.8 2,516.6 2,851.0 3,548.0 14.6

Imports through pipeline 905.5 939.6 854.1 980.4 916.8 911.8 1,356.2 1,671.9 1,755.5 1,994.7 2,910.3 12.4

1. Mexicali, BC. Private 11.0 14.3 13.9 15.3 15.9 17.5 19.0 20.5 21.3 21.5 21.8 7.1

2. Los Algodones, BC. 237.0 268.4 251.8 277.5 257.0 111.9 250.4 274.4 255.2 295.0 333.8 3.5

PGPB 7.2 14.4 9.6 11.7 10.3 - - - - - - n.a.

Public electricity sector 1 112.7 118.6 119.2 119.2 110.4 33.6 43.0 48.7 42.9 46.6 155.0 3.2

Private 117.1 135.4 123.1 146.7 136.3 78.3 207.4 225.7 212.3 248.4 178.8 4.3

3. Nogales, Son. Private 0.3 0.4 0.5 0.6 0.7 0.8 0.9 0.9 1.0 n.a.

4. Naco, Son. 37.3 62.8 58.9 73.5 69.1 69.6 64.6 73.4 72.5 66.5 147.8 14.8

PGPB 9.0 31.0 34.0 38.1 32.4 33.6 30.7 34.8 33.9 34.0 6.9 -2.7

Public electricity sector 1 28.3 31.8 24.9 35.4 36.6 36.0 34.0 38.6 38.6 32.5 141.0 17.4

5. Naco, Son. Public electricity sector 1 38.4 36.2 37.3 40.1 38.5 41.8 44.9 39.5 44.6 51.6 42.8 1.1

6. Agua Prieta, Son. Private 10.2 10.3 11.3 9.7 8.9 9.0 10.1 11.2 11.4 43.1 65.2 20.4

7. Ciudad Juárez, Chih. 2 190.6 209.5 236.3 246.6 259.1 254.0 278.2 288.0 308.8 409.0 402.6 7.8

PGPB 169.7 184.2 206.7 211.2 224.9 216.2 236.4 248.9 264.5 258.6 46.9 -12.1

Public electricity sector 1 20.8 25.4 29.7 35.4 34.2 37.8 41.8 39.1 44.3 150.4 355.7 32.8

Private 0.0 0.01 0.02 0.02 n.a.

8. Ciudad Acuña, Coah. Private 0.9 1.0 0.9 1.0 0.8 1.1 1.2 1.1 1.0 n.a.

9. Piedras Negras, Coah. 6.3 5.6 5.9 5.0 3.9 4.8 8.4 16.8 19.1 19.7 20.5 12.5

PGPB - - - - - - - - - - - n.a.

Private 6.3 5.6 5.9 5.0 3.9 4.8 8.4 16.8 19.1 19.7 20.5 12.5

10. Ciudad Mier, Tamps. PGPB 102.2 55.5 62.3 67.6 54.6 100.3 175.5 357.0 370.5 412.8 450.1 16.0

11. Camargo, Tamps PGPB 10.1 808.4 n.a.

13. Argüelles, Tamps. (Kinder Morgan) 72.0 49.4 21.5 98.0 40.9 58.2 167.4 182.7 208.9 211.3 164.4 8.6

PGPB 72.0 49.4 11.8 46.2 29.1 55.0 145.5 182.4 208.9 211.3 164.4 8.6

Private 9.7 51.8 11.7 3.2 22.0 0.4 - - - n.a.

15. Reynosa, Tamps. (Tennessee Gas, PMX) PGPB 75.2 62.3 4.0 14.0 14.0 71.6 130.3 199.2 226.7 251.4 213.7 11.0

16. Reynosa, Tamps. (Tennessee Gas, RB)3 125.3 165.4 149.5 131.5 153.7 171.7 205.8 207.4 214.4 210.6 237.0 6.6

PGPB 45.0 54.2 57.2 61.5 56.7 59.1 72.4 66.7 70.9 72.1 18.3 -8.6

Public electricity sector 1 80.3 111.2 92.3 70.0 97.0 112.5 133.4 140.7 143.5 138.5 218.7 10.5

LNG Imports - 78.8 249.6 355.7 340.8 547.1 393.2 457.9 761.1 856.3 637.7 n.a.

16. Altamira, Tamps. Public electricity sector 1 - 78.8 249.6 330.6 334.0 351.0 368.6 329.4 356.8 382.3 236.4 n.a.

17. Ensenada, BC. Private - - - 25.1 6.8 196.1 24.6 33.3 34.0 33.6 24.9 n.a.

18. Manzanillo, Col. - - - - - - - 95.2 370.3 440.3 376.5 n.a.

PGPB 114.3 107.4 93.9 n.a.

Public electricity sector 1 95.2 256.0 332.9 282.6 n.a.

Total Exports 23.9 32.7 138.7 107.4 66.5 83.3 24.2 7.8 12.4 12.5 12.5 -6.3

Tijuana, BC. Private - - - - - 13.9 2.9 - - - - n.a.

Ensenada, BC. Private - - - - - - 8.5 - - - - n.a.

Los Algodones, BC. Private - - - - - 47.9 3.0 - - - - n.a.

Ciudad Morelos, BC. Private - - - - - 2.3 8.4 6.9 9.3 8.4 9.7 n.a.

Reynosa, Tamps. PGPB 23.9 32.7 138.7 107.4 66.5 19.3 1.3 0.9 3.1 4.1 2.8 -19.4

73

TABLE A. 9 NATURAL GAS BALANCE OF THE NORTHWEST REGION, 2005-2015

(million cubic feet per day)

* Includes continuous own-uses. Source: prepared by IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

TABLE A. 10 NATURAL GAS BALANCE OF THE NORTHEAST REGION,

2005-2015 (million cubic feet per day)

* Includes continuous own-uses. Source: prepared by IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

Concept 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 AAGR2005-2015

Origin 333.9 392.0 373.6 441.7 396.6 446.4 414.2 453.0 440.0 512.3 637.3 6.7

Regional production 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 n.a.

Import 333.9 392.0 373.6 441.7 396.6 446.4 414.2 453.0 440.0 512.3 637.3 6.7

From other regions 0.0 0.0 n.a.

Destination 334.4 391.5 376.3 428.9 408.3 444.0 422.2 452.1 447.0 505.0 616.0 6.3

Regional demand 334.4 391.5 376.3 428.9 408.3 380.0 399.3 445.3 437.7 496.7 606.2 6.1

Oil sector 0.4 0.9 0.7 0.9 0.9 0.9 0.9 1.0 0.9 0.9 1.0 8.8

Industrial sector 23.6 26.5 28.2 28.4 26.8 31.5 37.1 39.6 41.8 37.1 35.3 4.1

Electricity sector * 308.7 362.4 345.7 398.3 379.7 346.5 360.1 403.2 393.5 457.0 568.0 6.3

Residential sector 1.5 1.4 1.5 1.0 0.8 0.9 1.0 1.2 1.2 1.2 1.7 0.9

Services sector 0.2 0.3 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.4 0.3 3.1

Motor-carrier sector n.a.

Export 64.0 22.9 6.9 9.3 8.4 9.7 n.a.

To other regions 0.0 0.0 - - - - - - - - - n.a.

Inventories variation and differences -0.5 0.6 -2.7 12.8 -11.7 2.4 -7.9 0.9 -7.0 7.3 21.3 n.a.

Concept 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015AAGR

2005-2015

Origin 1,755.0 1,984.9 2,091.7 2,221.1 2,309.7 2,427.0 2,614.8 2,782.8 2,911.6 3,052.5 3,491.7 7.1

Regional production 1,183.5 1,358.5 1,361.4 1,326.7 1,448.6 1,414.6 1,279.6 1,201.2 1,205.3 1,144.1 957.5 -2.1

Import 571.6 626.4 730.0 894.4 861.1 1,012.5 1,335.2 1,581.6 1,706.3 1,908.4 2,534.2 16.1

From other regions 0.2 n.a.

Destination 1,755.0 1,975.6 2,098.0 2,210.6 2,300.4 2,424.3 2,616.0 2,784.1 2,913.5 3,051.3 3,439.3 7.0

Regional demand 1,418.7 1,634.1 1,785.8 1,807.9 1,834.0 1,965.6 2,219.3 2,217.0 2,263.2 2,350.1 2,464.2 5.7

Oil sector 125.3 131.3 150.8 141.9 130.3 148.9 181.2 191.4 185.2 217.4 234.0 6.4

Industrial sector 347.8 371.4 383.6 371.5 340.1 391.4 416.7 439.5 466.9 482.5 512.6 4.0

Electricity sector * 869.1 1,057.5 1,174.7 1,219.1 1,294.3 1,353.8 1,554.4 1,515.0 1,537.5 1,577.7 1,635.5 6.5

Residential sector 60.9 57.4 59.7 57.8 53.6 54.4 50.8 53.8 56.0 54.9 62.0 0.2

Services sector 15.5 16.4 16.9 17.3 15.6 17.1 16.1 17.4 17.6 17.5 20.0 2.6

Motor-carrier sector 0.1 0.2 0.1 0.1 0.1 0.1 0.1 0.0 0.1 0.1 0.1 -1.9

Export 23.9 32.7 138.7 107.4 66.5 19.3 1.3 0.9 3.1 4.1 2.8 -19.4

To other regions 312.4 308.8 173.5 295.4 399.9 439.5 395.38 566.10 647.2 697.0 972.4 12.0

Inventories variation and differences 0.0 9.4 -6.4 10.5 9.3 2.7 -1.2 -1.3 -1.9 1.2 52.4 n.a.

74

TABLE A. 11 NATURAL GAS BALANCE OF THE CENTRAL-EASTERN REGION, 2005-2015

(million cubic feet per day)

* Includes continuous own-uses. Source: prepared by IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

TABLE A. 12 NATURAL GAS BALANCE OF THE CENTRAL REGION, 2005-2015 (million cubic feet per day)

* Includes continuous own-uses. Source: prepared by IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

Concept 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015AAGR

2005-2015

Origin 518.0 564.8 637.3 705.0 666.2 703.4 730.1 803.5 897.4 1,057.2 1,123.2 8.0

Regional production 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 n.a.

Import 0.0 0.0 0.0 0.0 0.0 0.0 0.0 95.2 370.3 440.3 376.5 n.a.

From other regions 518.0 564.8 637.3 705.0 666.2 703.4 730.1 708.3 527.1 616.9 746.7 3.7

Destination 518.0 564.8 637.3 705.0 666.2 703.4 728.9 789.4 880.3 1,053.6 1,134.6 8.2

Regional demand 518.0 564.8 637.3 705.0 666.2 703.4 728.9 789.4 880.3 1,053.6 1,134.6 8.2

Oil sector 61.9 68.5 61.6 65.0 59.0 65.3 57.2 63.0 63.5 62.9 57.3 -0.8

Industrial sector 259.1 287.7 296.4 298.4 231.1 287.7 310.2 318.8 334.8 370.2 391.1 4.2

Electricity sector * 190.4 200.9 272.3 334.3 368.3 340.1 353.7 399.6 473.2 609.9 674.1 13.5

Residential sector 5.6 5.4 5.0 5.2 5.1 6.9 5.7 5.7 5.9 6.5 6.1 0.9

Services sector 1.1 2.2 2.1 2.1 2.7 3.4 2.0 2.2 2.8 3.8 5.7 17.9

Motor-carrier sector 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.3 0.3 n.a.

Export - - - - - - - - - - - n.a.

To other regions n.a.

Inventories variation and differences 0.0 0.0 0.0 0.0 0.0 0.0 1.2 14.1 17.1 3.6 -11.4 n.a.

Concept 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015AAGR

2005-2015

Origin 604.0 642.7 639.1 655.8 672.9 712.1 752.4 754.1 818.0 767.1 919.4 4.3

Regional production - - - - - - - - - - n.a.

Import - - - - - - - - - - n.a.

From other regions 604.0 642.7 639.1 655.8 672.9 712.1 752.4 754.1 818.0 767.1 919.4 4.3

Destination 604.0 642.7 639.1 655.8 672.9 712.1 752.4 754.1 818.0 767.1 919.4 4.3

Regional demand 604.0 642.7 639.1 655.8 672.9 712.1 752.4 754.1 818.0 767.1 919.4 4.3

Oil sector 68.8 72.9 63.0 92.6 94.0 87.8 103.8 103.1 104.3 108.8 114.8 5.3

Industrial sector 232.2 246.4 251.5 244.7 234.6 257.2 274.7 286.7 292.4 300.3 322.1 3.3

Electricity sector * 279.1 297.0 295.7 288.1 313.6 336.5 341.4 332.2 388.2 323.1 448.2 4.8

Residential sector 18.5 20.3 22.3 23.3 23.4 23.5 24.2 23.4 23.6 25.2 24.9 3.0

Services sector 3.6 4.2 4.8 5.6 5.9 5.8 6.8 7.0 7.4 7.6 7.5 7.7

Motor-carrier sector 1.8 1.9 1.8 1.5 1.4 1.3 1.4 1.8 2.2 1.9 2.0 1.0

Export - - - - - - - - - - - n.a.

To other regions - - - - - - - - - - - n.a.

Inventories variation and differences 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 n.a.

75

TABLE A. 13 NATURAL GAS BALANCE OF THE SOUTH-SOUTHEAST REGION, 2005-2015 (million cubic feet per day)

* Includes continuous own-uses. Source: prepared by IMP, based on information from BANXICO, CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

TABLE A. 14 NATURAL GAS DEMAND BY GROUP OF BRANCHES, 2015-2030 (million cubic feet per day)

Source: IMP, based on information from BANXICO, CNIAA, CONAGUA, CONUEE, CRE, EIA, EPA, IEA, INEGI, PEMEX, SE, SENER and private companies.

Concept 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015AAGR

2005-2015

Origin 3,060.3 3,326.4 3,605.6 3,593.3 3,522.4 3,589.4 3,533.1 3,401.8 3,287.1 3,248.8 3,109.3 0.2

Regional production 3,060.3 3,326.4 3,605.6 3,593.3 3,522.4 3,589.4 3,533.1 3,401.8 3,287.1 3,248.8 3,109.3 0.2

Import - - - - - - - - - - - n.a.

From other regions - - - - - - - - - - - n.a.

Destination 3,022.0 3,338.6 3,590.4 3,577.8 3,461.8 3,555.8 3,499.5 3,368.9 3,251.1 3,228.8 3,073.4 0.2

Regional demand 2,212.4 2,439.9 2,487.3 2,512.3 2,522.7 2,579.8 2,412.4 2,472.6 2,553.1 2,541.9 2,379.7 0.7

Oil sector 1,773.6 1,886.0 1,849.3 1,874.6 1,865.2 1,933.7 1,843.0 1,914.6 1,918.4 1,885.5 1,793.0 0.1

Industrial sector 72.6 82.1 80.4 83.5 80.3 86.5 90.5 96.5 104.0 123.3 114.6 4.7

Electricity sector * 366.0 471.7 557.4 554.1 577.0 559.4 478.7 461.4 530.2 532.6 471.8 2.6

Residential sector - - - - - - - - - - - n.a.

Services sector 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.5 0.5 0.3 5.7

Motor-carrier sector - - - - - - - - - - - n.a.

Export - - - - - - - - - - - n.a.

To other regions 809.6 898.8 1,103.1 1,065.5 939.2 976.0 ##### 896.3 698.0 686.9 693.7 -1.5

Inventories variation and differences 38.2 -12.2 15.1 15.5 60.6 33.6 33.7 32.9 36.1 20.0 35.9 -0.6

Group of Branches 2015 2016 2017 2018 2019 2020 2021 2022AAGR

2015-2022AAGR

2015-2030

Total 1,375.8 1,435.4 1,737.0 1,905.3 1,931.8 1,960.3 1,985.5 2,011.1 5.6 2.9

Basic-metal industries 347.4 343.3 344.7 346.7 348.1 349.6 350.9 352.2 0.2 0.2

Chemistry 200.4 210.1 349.9 372.3 376.2 381.6 385.3 390.1 10.0 4.7

Metallic products, machinery and equipment 137.6 141.0 150.0 157.6 160.6 163.3 165.8 167.8 2.9 1.3

Glass and glass products 132.5 134.5 136.9 140.2 141.8 143.4 144.8 146.2 1.4 0.6

Food, beverages and tobacco 130.0 134.9 147.0 155.4 157.5 159.5 161.2 162.8 3.3 1.4

Non-metallic mineral products 86.6 92.2 100.2 106.1 110.0 114.0 118.0 121.8 5.0 3.6

Paper and cardboard, printing houses and publishers 90.1 90.7 93.4 94.5 94.4 94.4 94.1 93.7 0.6 -0.4

Textiles, garments, and leather industry 41.8 42.9 43.9 45.2 46.1 46.9 47.7 48.4 2.1 1.2

Mining 14.2 14.5 18.9 22.4 22.6 23.2 23.7 24.2 7.9 4.2

Beer and malt 38.3 38.1 40.7 41.1 41.3 41.6 41.6 41.7 1.2 0.0

Hydraulic cement 13.2 13.2 13.4 17.2 17.0 16.8 16.6 16.5 3.2 0.6

Remaining branches 143.6 180.0 298.0 406.6 416.2 426.1 435.8 445.8 17.6 8.8

Group of Branches 2023 2024 2025 2026 2027 2028 2029 2030AAGR

2023-2030AAGR

2015-2030

Total 2,029.1 2,042.8 2,058.0 2,071.3 2,083.6 2,092.1 2,097.0 2,097.3 0.5 2.9

Basic-metal industries 353.3 354.0 355.0 355.8 356.6 357.3 357.9 358.3 0.2 0.2

Chemistry 392.8 394.8 396.4 397.8 399.2 400.0 400.0 398.6 0.2 4.7

Metallic products, machinery and equipment 168.0 167.9 168.5 168.8 169.6 169.1 167.8 166.1 -0.2 1.3

Glass and glass products 147.1 147.2 147.4 147.7 147.8 147.4 146.7 145.9 -0.1 0.6

Food, beverages and tobacco 163.7 163.8 164.1 164.1 163.9 163.4 162.5 161.1 -0.2 1.4

Non-metallic mineral products 124.8 127.8 131.3 134.9 138.1 141.2 144.1 146.4 2.3 3.6

Paper and cardboard, printing houses and publishers 93.0 92.0 90.9 89.9 88.7 87.3 85.8 84.2 -1.4 -0.4

Textiles, garments, and leather industry 48.9 49.2 49.5 49.8 50.0 50.1 50.2 50.0 0.3 1.2

Mining 24.6 25.0 25.4 25.7 26.1 26.2 26.2 26.2 0.9 4.2

Beer and malt 41.6 41.3 41.0 40.6 40.2 39.7 39.1 38.5 -1.1 0.0

Hydraulic cement 16.2 16.0 15.7 15.5 15.2 14.9 14.7 14.4 -1.7 0.6

Remaining branches 455.0 463.9 472.7 480.7 488.1 495.4 502.0 507.8 1.6 8.8

76

TABLE A. 15 REGIONAL COMPOSITION OF THE VEHICLE FLEETBY FUEL, 2015-2030 (thousand units)

Source: IMP based on information from private companies

TABLE A. 16 NATURAL GAS BALANCE OF THE NORTHEAST REGION, 2015-2030 (million cubic feet per day)

Source: prepared by IMP, based on information from CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Gasoline 32,338.2 33,184.6 33,626.7 33,846.7 34,422.3 34,909.1 35,922.9 36,938.1 37,925.8 38,645.1 39,396.3 40,317.3 41,082.0 41,557.6 42,105.8 42,620.9

Diesel 842.0 831.2 829.6 846.9 882.2 929.6 987.5 1,045.7 1,104.2 1,159.9 1,210.5 1,274.1 1,331.9 1,386.1 1,439.5 1,497.0

LP gas 250.3 240.6 242.3 230.5 223.5 223.5 225.5 228.3 232.0 236.3 240.2 246.6 252.9 259.3 265.5 265.7

GNC 3.1 3.8 4.0 4.3 4.5 4.8 5.1 5.3 5.5 5.7 5.9 6.0 6.1 6.3 6.7 6.8

Total 33,433.6 34,260.2 34,702.6 34,928.4 35,532.4 36,067.0 37,141.0 38,217.4 39,267.6 40,047.0 40,852.8 41,844.1 42,673.0 43,209.3 43,817.5 44,390.4

Concept 2015 2016 2017 2018 2019 2020 2021 2022 AAGR 2015-2022

AAGR2015-2030

Origin 3,491.7 3,704.4 3,736.6 4,220.0 4,720.8 5,123.9 5,308.8 5,300.8 6.1 2.4

Regional production 957.5 564.9 433.7 487.2 547.4 586.6 593.8 576.9 7.0- 3.6-

Import 2,534.2 3,139.5 3,302.9 3,732.9 4,173.3 4,537.3 4,715.0 4,723.9 9.3 3.8

From other regions - - - - - - - - n.a. n.a.

Destination 3,439.3 3,704.4 3,736.6 4,220.0 4,720.8 5,123.9 5,308.8 5,300.8 6.4 2.5

Regional demand 2,464.2 2,521.8 2,570.6 2,592.1 2,734.5 2,673.2 2,611.4 2,657.4 1.1 1.3

Oil sector 234.0 225.7 225.7 226.3 219.6 236.2 235.4 236.4 0.1 0.1

Industrial sector 512.6 515.6 552.6 588.4 598.5 609.2 619.3 627.8 2.9 1.7

Electricity sector 1,635.5 1,699.5 1,709.7 1,692.8 1,830.8 1,741.0 1,669.1 1,704.7 0.6 1.3

Residential sector 62.0 61.3 62.7 64.2 64.8 65.7 66.0 66.3 1.0 0.4

Services sector 20.0 19.6 19.9 20.3 20.6 21.0 21.5 22.0 1.4 2.2

Motor-carrier sector 0.1 0.1 0.1 0.1 0.1 0.1 0.2 0.2 13.4 15.5

Export 2.8 1.3 1.3 3.1 1.5 1.6 1.1 0.2 31.7- 23.6-

To other regions 972.4 1,181.3 1,164.6 1,624.8 1,984.7 2,449.1 2,696.3 2,643.2 15.4 5.0

Inventories variation and differences 52.4 - - - - - - - n.a. n.a.

Concept 2023 2024 2025 2026 2027 2028 2029 2030 AAGR 2023-2030

AAGR2015-2030

Origin 5,059.9 4,773.2 4,754.4 4,654.8 4,564.2 4,785.2 4,896.7 5,016.4 0.1- 2.4

Regional production 625.0 668.7 714.7 806.9 766.0 783.3 642.7 551.7 1.8- 3.6-

Import 4,434.9 4,104.5 4,039.7 3,848.0 3,798.3 4,001.9 4,254.1 4,464.7 0.1 3.8

From other regions - - - - - - - - n.a. n.a.

Destination 5,059.9 4,773.2 4,754.4 4,654.8 4,564.2 4,785.2 4,896.7 5,016.4 0.1- 2.5

Regional demand 2,812.9 2,820.8 2,881.4 2,897.6 2,850.7 2,933.7 2,963.0 2,981.0 0.8 1.3

Oil sector 236.4 236.4 236.5 236.6 236.6 236.6 236.6 236.6 0.0 0.1

Industrial sector 634.1 639.4 645.1 651.3 656.3 659.6 661.2 661.2 0.6 1.7

Electricity sector 1,852.8 1,854.7 1,909.0 1,918.3 1,865.9 1,944.7 1,971.6 1,989.1 1.0 1.3

Residential sector 66.9 66.9 66.8 66.6 66.4 66.6 66.2 65.9 0.2- 0.4

Services sector 22.6 23.2 23.8 24.5 25.2 25.9 26.7 27.5 2.9 2.2

Motor-carrier sector 0.2 0.2 0.2 0.3 0.3 0.3 0.6 0.6 18.4 15.5

Export 0.2 0.2 0.2 0.1 0.1 0.1 0.1 0.0 18.0- 23.6-

To other regions 2,246.8 1,952.2 1,872.8 1,757.1 1,713.4 1,851.4 1,933.7 2,035.4 1.4- 5.0

Inventories variation and differences - - - - - - - - n.a. n.a.

77

TABLE A. 17 NATURAL GAS BALANCE OF THE NORTHWEST REGION, 2015-2030 (million cubic feet per day)

Source: prepared by IMP, based on information from CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

Concept 2015 2016 2017 2018 2019 2020 2021 2022 AAGR 2015-2022

AAGR2015-2030

Origin 637.3 420.9 568.4 641.8 720.2 693.9 674.9 724.2 1.8 2.6

Regional production - - - - - - - - n.a. n.a.

Import 637.3 420.9 568.4 641.8 720.2 693.9 674.9 724.2 1.8 2.6

From other regions - - - 0.0 - - - - n.a. n.a.

Destination 616.0 420.9 568.4 641.8 720.2 693.9 674.9 724.2 2.3 2.9

Regional demand 606.2 420.9 568.4 641.8 720.2 693.9 674.9 724.2 2.6 3.0

Oil sector 1.0 - - - - - - - n.a. n.a.

Industrial sector 35.3 37.0 158.3 159.8 162.8 165.6 167.4 169.6 25.1 11.2

Electricity sector 568.0 382.3 407.1 479.0 554.3 525.2 504.1 550.8 0.4- 2.0

Residential sector 1.7 1.3 2.6 2.6 2.6 2.5 2.7 2.9 8.4 6.0

Services sector 0.3 0.3 0.5 0.5 0.5 0.6 0.7 0.8 17.1 13.1

Motor-carrier sector - - - - - - - - n.a. n.a.

Export 9.7 - - - - - - - n.a. n.a.

To other regions - - 0.0 - - 0.0 - - n.a. n.a.

Inventories variation and differences 21.3 - - - - - - - n.a. n.a.

Concept 2023 2024 2025 2026 2027 2028 2029 2030 AAGR 2023-2030

AAGR2015-2030

Origin 749.7 751.3 789.4 859.0 978.4 916.5 932.0 942.2 3.3 2.6

Regional production - - - - - - - - n.a. n.a.

Import 749.7 751.3 789.4 859.0 978.4 916.5 932.0 942.2 3.3 2.6

From other regions - - - 0.0 - - - 0.0 n.a. n.a.

Destination 749.7 751.3 789.4 859.0 978.4 916.5 932.0 942.2 3.3 2.9

Regional demand 749.7 751.3 789.4 859.0 978.4 916.5 932.0 942.2 3.3 3.0

Oil sector - - - - - - - - n.a. n.a.

Industrial sector 171.0 171.9 172.5 173.4 174.1 174.9 175.2 174.2 0.3 11.2

Electricity sector 574.6 575.0 612.3 680.7 799.1 736.2 751.2 762.3 4.1 2.0

Residential sector 3.2 3.4 3.5 3.7 3.8 3.9 4.0 4.0 3.4 6.0

Services sector 0.9 1.0 1.1 1.3 1.4 1.5 1.6 1.7 9.3 13.1

Motor-carrier sector - - - - - - - - n.a. n.a.

Export - - - - - - - - n.a. n.a.

To other regions - 0.0 - - 0.0 - - - n.a. n.a.

Inventories variation and differences - - - - - - - - n.a. n.a.

78

TABLE A. 18 NATURAL GAS BALANCE OF THE CENTRAL-EASTERN REGION, 2015-2030 (million cubic feet per day)

Source: prepared by IMP, based on information from CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

Concept 2015 2016 2017 2018 2019 2020 2021 2022 AAGR 2015-2022

AAGR2015-2030

Origin 1,123.2 1,072.5 1,130.1 1,247.3 1,458.0 1,640.9 1,779.9 1,789.0 6.9 3.4

Regional production - - - - - - - - n.a. n.a.

Import 376.5 291.7 291.8 - - - - - n.a. n.a.

From other regions 746.7 780.8 838.3 1,247.3 1,458.0 1,640.9 1,779.9 1,789.0 13.3 6.3

Destination 1,134.6 1,072.5 1,130.1 1,247.3 1,458.0 1,640.9 1,779.9 1,789.0 6.7 3.4

Regional demand 1,134.6 1,072.5 1,130.1 1,247.3 1,458.0 1,640.9 1,779.9 1,789.0 6.7 3.4

Oil sector 57.3 65.5 65.5 77.8 77.8 83.3 95.4 95.4 7.6 3.5

Industrial sector 391.1 421.9 518.5 606.8 614.6 624.9 634.9 645.7 7.4 4.0

Electricity sector 674.1 574.3 534.4 550.2 752.4 918.8 1,035.0 1,032.7 6.3 3.0

Residential sector 6.1 6.8 7.2 7.6 8.0 8.4 8.6 8.8 5.4 2.6

Services sector 5.7 3.8 4.1 4.5 4.8 5.1 5.5 5.8 0.4 2.1

Motor-carrier sector 0.3 0.3 0.3 0.3 0.4 0.4 0.5 0.5 10.1 8.1

Export - - - - - - - - n.a. n.a.

To other regions - - - - - - - - n.a. n.a.

Inventories variation and differences 11.4- - - - - - - - n.a. n.a.

Concept 2023 2024 2025 2026 2027 2028 2029 2030 AAGR 2023-2030

AAGR2015-2030

Origin 1,694.0 1,725.9 1,740.8 1,776.9 1,811.7 1,816.4 1,844.2 1,863.6 1.4 3.4

Regional production - - - - - - - - n.a. n.a.

Import - - - - - - - - n.a. n.a.

From other regions 1,694.0 1,725.9 1,740.8 1,776.9 1,811.7 1,816.4 1,844.2 1,863.6 1.4 6.3 Destination 1,694.0 1,725.9 1,740.8 1,776.9 1,811.7 1,816.4 1,844.2 1,863.6 1.4 3.4

Regional demand 1,694.0 1,725.9 1,740.8 1,776.9 1,811.7 1,816.4 1,844.2 1,863.6 1.4 3.4

Oil sector 95.4 95.4 95.4 95.4 95.4 95.4 95.4 95.4 - 3.5

Industrial sector 654.8 662.0 669.8 676.4 683.8 690.1 695.9 700.4 1.0 4.0

Electricity sector 928.0 952.4 959.1 988.2 1,015.4 1,013.5 1,035.4 1,050.3 1.8 3.0

Residential sector 9.0 9.1 9.2 9.2 9.2 9.2 9.1 9.0 0.1- 2.6

Services sector 6.2 6.5 6.7 7.0 7.2 7.4 7.6 7.8 3.4 2.1

Motor-carrier sector 0.6 0.6 0.7 0.7 0.8 0.8 0.8 0.9 6.0 8.1

Export - - - - - - - - n.a. n.a.

To other regions - - - - - - - - n.a. n.a.

Inventories variation and differences - - - - - - - - n.a. n.a.

79

TABLE A. 19 NATURAL GAS BALANCE OF THE CENTRAL REGION, 2015-2030 (million cubic feet per day)

Source: prepared by IMP, based on information from CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

Concept 2015 2016 2017 2018 2019 2020 2021 2022 AAGR 2015-2022

AAGR2015-2030

Origin 919.4 1,030.5 979.0 978.0 988.7 1,076.5 1,093.3 1,098.3 2.6 2.3

Regional production - - - - - - - - n.a. n.a.

Import - - - - - - - - n.a. n.a.

From other regions 919.4 1,030.5 979.0 978.0 988.7 1,076.5 1,093.3 1,098.3 2.6 2.3

Destination 919.4 1,030.5 979.0 978.0 988.7 1,076.5 1,093.3 1,098.3 2.6 2.3

Regional demand 919.4 1,030.5 979.0 978.0 988.7 1,076.5 1,093.3 1,098.3 2.6 2.3

Oil sector 114.8 243.5 243.5 243.5 247.4 266.0 278.7 278.7 13.5 2.7

Industrial sector 322.1 329.5 351.4 375.1 379.0 382.9 386.1 389.0 2.7 1.3

Electricity sector 448.2 417.7 342.2 315.0 315.7 378.8 378.6 379.2 2.4- 2.8

Residential sector 24.9 28.6 30.4 32.3 33.9 35.3 35.6 36.2 5.5 2.8

Services sector 7.5 8.6 8.8 9.2 9.5 9.8 10.2 10.6 5.0 3.7

Motor-carrier sector 2.0 2.6 2.7 3.0 3.3 3.7 4.2 4.7 12.8 9.7

Export - - - - - - - - n.a. n.a.

To other regions - - - - - - - - n.a. n.a.

Inventories variation and differences 0.0 - - - - - - - n.a. n.a.

Concept 2023 2024 2025 2026 2027 2028 2029 2030 AAGR 2023-2030

AAGR2015-2030

Origin 1,048.7 1,006.3 1,007.2 1,010.4 1,026.4 1,128.9 1,210.5 1,293.5 3.0 2.3

Regional production - - - - - - - - n.a. n.a.

Import - - - - - - - - n.a. n.a.

From other regions 1,048.7 1,006.3 1,007.2 1,010.4 1,026.4 1,128.9 1,210.5 1,293.5 3.0 2.3

Destination 1,048.7 1,006.3 1,007.2 1,010.4 1,026.4 1,128.9 1,210.5 1,293.5 3.0 2.3

Regional demand 1,048.7 1,006.3 1,007.2 1,010.4 1,026.4 1,128.9 1,210.5 1,293.5 3.0 2.3

Oil sector 215.3 170.5 170.5 170.5 170.5 170.5 170.5 170.5 3.3- 2.7

Industrial sector 390.7 391.7 393.0 394.0 393.7 393.3 392.0 390.3 0.0- 1.3

Electricity sector 389.8 390.0 388.6 390.1 405.6 507.6 589.8 674.0 8.1 2.8

Residential sector 36.9 37.2 37.4 37.6 37.6 37.9 37.8 37.7 0.3 2.8

Services sector 11.0 11.3 11.6 11.8 12.1 12.4 12.6 12.9 2.4 3.7

Motor-carrier sector 5.2 5.6 6.0 6.4 6.9 7.3 7.7 8.1 6.6 9.7

Export - - - - - - - - n.a. n.a.

To other regions - - - - - - - - n.a. n.a.

Inventories variation and differences - - - - - - - - n.a. n.a.

80

TABLE A. 20 NATURAL GAS BALANCE OF THE SOUTH-SOUTHEAST REGION, 2015-2030 (million cubic feet per day)

Source: prepared by IMP, based on information from CFE, CNIAA, CONAGUA, CONAPO, CONUEE, CRE, EIA, EPA, IEA, INEGI, Pemex, SENER and private companies.

Concept 2015 2016 2017 2018 2019 2020 2021 2022AAGR

2015-2022AAGR

2015-2030

Origin 3,109.3 3,217.2 3,246.7 3,116.0 2,980.2 2,874.5 2,885.7 2,957.0 0.7- 0.2

Regional production 3,109.3 3,217.2 3,246.7 3,116.0 2,980.2 2,874.5 2,885.7 2,957.0 0.7- 0.2

Import - - - - - - - - n.a. n.a.

From other regions - - - - - - - - n.a. n.a.

Destination 3,073.4 3,217.2 3,246.7 3,116.0 2,980.2 2,874.5 2,885.7 2,957.0 0.6- 0.2

Regional demand 2,379.7 2,587.2 2,594.0 2,515.5 2,518.3 2,592.2 2,691.4 2,691.5 1.8 1.3-

Oil sector 1,793.0 1,735.8 1,735.8 1,601.9 1,559.3 1,663.1 1,778.7 1,788.9 0.0- 4.2-

Industrial sector 114.6 131.4 156.2 175.2 177.0 177.8 177.9 178.8 6.6 2.7

Electricity sector 471.8 719.0 700.4 735.9 778.3 746.7 730.1 718.9 6.2 3.8

Residential sector - 0.5 1.1 1.9 2.8 3.7 4.0 4.0 n.a. n.a.

Services sector 0.3 0.5 0.5 0.7 0.9 0.8 0.8 0.8 14.5 7.9

Motor-carrier sector - - - - - - - - n.a. n.a.

Export - - - - - 14.1 17.4 21.4 n.a. n.a.

To other regions 693.7 630.0 652.7 600.5 461.9 268.3 176.9 244.1 13.9- 3.3

Inventories variation and differences 35.9 - - - - - - - n.a. n.a.

Concept 2023 2024 2025 2026 2027 2028 2029 2030 AAGR 2023-2030

AAGR2015-2030

Origin 3,175.1 3,382.1 3,354.9 3,432.4 3,487.9 3,337.7 3,257.5 3,185.7 0.0 0.2

Regional production 3,175.1 3,382.1 3,354.9 3,432.4 3,487.9 3,337.7 3,257.5 3,185.7 0.0 0.2

Import - - - - - - - - n.a. n.a.

From other regions - - - - - - - - n.a. n.a.

Destination 3,175.1 3,382.1 3,354.9 3,432.4 3,487.9 3,337.7 3,257.5 3,185.7 0.0 0.2

Regional demand 2,652.8 2,569.5 2,439.7 2,352.8 2,302.4 2,168.8 2,044.1 1,950.1 4.3- 1.3-

Oil sector 1,654.0 1,548.0 1,375.3 1,267.1 1,186.5 1,106.3 1,017.6 948.6 7.6- 4.2-

Industrial sector 178.5 177.9 177.6 176.2 175.6 174.2 172.7 171.2 0.6- 2.7 Electricity sector 815.4 838.8 881.9 904.7 935.6 883.5 849.1 825.5 0.2 3.8

Residential sector 4.0 4.0 4.0 3.9 3.9 3.9 3.8 3.8 0.9- n.a.

Services sector 0.8 0.8 0.9 0.9 0.9 0.9 0.9 1.0 2.4 7.9

Motor-carrier sector - - - - - - - - n.a. n.a.

Export 26.4 32.5 40.1 49.4 60.9 75.0 92.4 113.9 23.2 n.a.

To other regions 495.9 780.0 875.2 1,030.2 1,124.6 1,093.8 1,121.0 1,121.7 12.4 3.3

Inventories variation and differences - - - - - - - - n.a. n.a.

81

Glossary

Acid gas Compound occasionally present in the NG, like sulfuric acid and carbon dioxide, and which give NG acid peculiarities due to their physical and chemical properties.

Associated gas NG in direct contact and/or dissolved in the crude oil of the reservoir. This can be classified as tapped gas (free) or solution gas (dissolved).

Benchmark price Price taken within the relevant markets for trading hydrocarbons produced or purchased by PEMEX. Such benchmark price is the most representative one for simulating competitive conditions in an open market.

Butane Hydrocarbons that belong to the alkane family formed by four atoms of carbon, and ten of hydrogen and which are produced by fractionating NG liquids, condensates, and some refining processes, like crude-oil atmospheric distillation, catalytic disintegration, and naphthas reforming. Mixed with propane, it produces liquefied petroleum gas.

Cogeneration Technology used to sequentially produce two types of energy useful to industrial processes. Normally thermal energy and electric power.

Combined cycle Technology which uses NG as a fuel to generate electricity. It is formed by two parts; in the first one, the NG combustion gases go through a gas turbine for producing electricity. In the second one, the thermal energy from the exhaust gas is used, through an interchanger, for producing steam and feed a steam turbine in order to generate even more electricity.

Compressed natural gas Dry natural gas stored at a pressure of 200-250 atmospheres in gaseous state in a container.

Compression station Station located each 60 km or 80 km along a gas pipeline and whose operation consists on compressing gas in order to keep its pressure and flowing as specified.

Cryogenic plant Plant which, through a low-temperatures process separates and eliminates any gas component that could affect the transport and distribution systems, such as carbon dioxide, water steam, and heavy hydrocarbons.

Cryogenic process Industrial process which uses the intrinsic energy contained in NG to, by means of a sudden change of pressure, generate a temperature reduction and thus achieving a 100% recovery of hydrocarbons contained in the NG from the propane.

Distributor Permit holder of a distribution permit.

Distribution Activity of receiving, conveying, delivering, and if the case, commercialize NG through pipelines within a geographical zone.

82

Dry gas NG containing less amounts of hydrocarbons heavier than methane. It is also obtained from processing plants.

End user Person who purchases gas for his/her consumption.

First-hand sales They are defined as the first sale of natural gas, produced in Mexico and sold by Petroleos Mexicanos to a third party for delivery in the national territory, the First-Hand Sale (FHS) is an activity regulated by the Energy Regulatory Commission (CRE).

Fuel Substance used to produce thermal energy through a chemical or nuclear reaction. The energy is produced by the conversion of the fuel mass into heat.

Fueling L.P. Gas Name given to the LP Gas used in vehicles with internal combustion engines.

Gas liquefaction Process of cooling NG at -162 ˚C which reduces its volumes by a factor of 600, becoming a liquid. The resulting liquefied natural gas is thus transportable in tankers designed for that purpose, or it can be stored in containers.

Gas pipeline System or group of facilities which is used for transporting the NG coming from production centers of from processing and utilization plants, to large-volumes consumers.

Gas Processing Center PGPB facility in which the sweetening process of the sour gas is carried out; the resultant sweet gas is processed for extracting, through cryogenic and fracking processes, liquid hydrocarbons contained in the NG, obtaining -among others- the products which form the L.P. gas.

Gasification Producing of gaseous fuel from a solid or liquid fuel.

Henry Hub Confluence point of gas pipelines located in Louisiana, USA. This is used as a reference for establishing future NG contracts to be negotiated in the NYMEX (New York Mercantile Exchange).

Liquefied natural gas NG mainly composed by methane (CH4) which is liquefied to facilitate its transportation; it is liquefied through cooling at approximately less than 161 ˚C at atmospheric pressure.

Liquid or gas fossil fuels Derivatives of crude oil or NT such as limpid petroleum (kerosene), gasolines, diesel, fuel oil, gasoil, LP gas, butane, methane, isobutane, propylene, butylene, or any of their combinations.

Liquids fractionation Process through which condensates and gas liquids are separated by distillation to obtain mainly LP gas and gasoline.

Logistics imports Imports carried out in border points to supply the demand which cannot access domestic production due to a lack of infrastructure or transportation costs.

LP gas fueling station Storage system using containers exclusively destined to deliver LP gas for gas-fueled vehicles.

83

Lutites Rocks containing gas and oil which required to be fractured in order to obtain them.

Methane Gas that, when found in pure state is colorless, odorless, and tasteless, and lighter than air. Its condensation temperature at normal pressure (1 atmosphere) is -161.5 ˚C, in a mixture of 5 to 15 percent in volume with air it forms an explosive mixture. It is the first member of the series of saturated hydrocarbons (also known as paraffins or alkanes); its condensed formula is CH4. It is also known as 'marsh gas' since it is generated there as the anaerobic decomposition produce of organic matter. It is the main component of NG, accounting for more than 90% in volume. It is also obtained from the distillation of bituminous coal.

Mexican Official Standards Mandatory norms issued by the competent entities subjected to what is ordered in the Federal Law on Metrology and Normalization.

Natural gas (NG) Gaseous blend which is extracted associated with oil or from sole-gas reservoirs. Its main components, in descending value of amount are methane, ethane, propane, butanes, pentanes, and hexanes. When it is extracted from wells, it generally contains impurities such as sulfuric acid, mercaptans, carbon dioxide, and water steam. Impurities are eliminated in gas processing plants using solvents or absorbents. The term is also used to name the processed gas which is supplied to the industry and to commercial or individual users and which has a specified quality.

Natural gas liquids Liquids obtained in gas/liquid separators on field facilities; in the handling, transportation and compression of NG; and in gas processing plants through separators. Mainly constituted by ethane and heavier hydrocarbons, they are classified into sour condensates (for their content of sulfuric acid and mercaptans), sweet condensates (do not contain sulfur compounds), and stabilized (when all light gases and CO2 have been extracted). They are the largest ethane source for the petrochemistry industry and of liquefied petroleum gas used as a fuel or as petrochemical raw material.

Natural Gas quality Composition and group of physical-chemical features of the NG according to the following characteristics: heat of combustion, Wobbe index, density, compressibility factor, and dew points.

Non-associated gas NG found in reservoirs not containing crude oil at original pressure and temperature conditions.

Permittee Owner of a permit for transportation, storage, and distribution.

Pipelines Piping and facilities for conveying NG or liquefied gas.

Pipelines or LPG pipelines Piping systems used for transporting LP gas according to the Mexican Official Standards.

Play Group of fields and/or prospects within a defined region, which are controlled by the same general geological features.

84

Pneumatic pumping Artificial production system in which special valves are introduced into the production piping and through which is injected pressurized gas; this gas, mixed with the oil, help the latter raise to the surface.

Propane Hydrocarbon found in small amounts within NG. It is obtained by fractionating NG liquids, from condensates, and from diverse refining processes such as crude-oil atmospheric distillation, catalytic disintegration, and naphthas reforming. It is relatively easy to liquefy if compressed, and thereby is used on its own or blended with butane to form LP gas.

Refining capacity Refers to the capacity per operation day, not to the capacity per calendar day. The capacity per operation day of a plant is the maximum volume that can be processed working uninterruptedly, while the capacity per calendar day considers stoppages normally demanded due to maintenance and other events.

Retail price Selling price of the completed products to consumers and which includes taxes (IVA, IEPS, etc.).

Self-supply Electric power production destined to meet the own needs of individuals and companies, or of the group of co-owners or associates.

Solid fuels Varieties of mineral coal and oil coke whose fixed content of carbon ranges from 10% to 90% in weight.

Sour gas NG containing sulfur derivatives such as sulfuric acid, mercaptans, sulfurs, and disulfurs. Comes directly from crude oil reservoirs or from the various refining processes.

Sweet gas NG free of sulfuric acid, mercaptans, and other sulfur derivatives. There are sweet gas reservoirs, but it is mostly obtained through sweetening sour natural gas using chemical solvents, physical solvents, or absorbents.

Sweetener plant Plant in which the acid gases of the sour gas or the condensates are separated. That is, sulfur and carbon dioxide compounds are eliminated.

Sweetening Process which removes pollutants such as sulfuric acid and carbon dioxide from the sour wet gas received from the producing wells. The process consists of scrubbing sour gas with an aqueous solution of diethanolamine (DEA) or monoethanolamine (MEA); DEA is the most commonly used given is low corrosion range. These substances absorbed impurities, so in the next stage of the process, the DEA or MEA is regenerated through a steam treatment and is recycled, delivering the CO2 and the sulfur absorbed like sulfuric acid.

Tank car Container designed to work under pressure or at atmospheric conditions, assembled on a platform or directly on wheels to be transported on railways.

Tanker truck Vehicle in which chassis is permanently installed a container for LPG with a 25,000 l-maximum capacity, and is used to exclusively supply fuel to non-transportable containers within utilization facilities and LPG stations for fuel through a filling system. They are known as "pipes".

85

Trade-deficit imports Imports for covering the deficit between demand and supply in PGPB's National Gas Pipelines System.

Transportation Reception, conveyance, and delivery of NG by means of pipelines to people who are no end users.

User Person who uses or asks for the services of a permit-holder.

Wet gas Hydrocarbons blend obtained from processing NG from which impurities or non-hydrocarbons compounds have been eliminated, and whose content of components heavier than methane is such that allow its commercial processing.

86

Acronyms

AAGR Annual Average Growth Rate

BTU British Thermal Unit

CENAGAS National Center for Natural Gas Control

CFE Federal Electricity Commission

CNG Compressed natural gas

CNH National Hydrocarbons Commission

CONAGUA National Water Commission

CONAPO National Population Council

CPG Gas Processing Center

CRE Energy Regulatory Commission

DOF Official Journal of the Federation

EIA Energy Information Administration (U.S)

EIP Energy Independent Producer

EPE State Productive Enterprise

EPS Subsidiary Productive Enterprise

FHS First-Hand Sales

Gcal Gigacalory

GDP Gross Domestic Product

Ibidem Same as the previous

IEA International Energy Agency

IMP Mexican Petroleum Institute

INEGI National Institute of Statistics and Geography

LNG Liquefied natural gas

LP Gas Liquefied Petroleum Gas

MBD Thousand barrels per day

MBDGE Thousand barrels per day of gasoline equivalent

87

MBDLPGE Thousand barrels per day of LP gas equivalent

MCFD Thousand cubic feet per day

MMCFD Million cubic feet per day

MMCFDNGE Million cubic feet per day of natural gas equivalent

MMT Million tons

MT Thousand tons

N. A Not applicable

NG Natural gas

PEMEX Petróleos Mexicanos

PEP PEMEX Exploration and Production

PGPB PEMEX Gas and Basic Petrochemistry

PPQ PEMEX Petrochemistry

PR PEMEX Refining

SENER Secretariat of Energy

SISTRANGAS National Comprehensive System for Transportation and Storage of Natural Gas

SNG National Gas-Pipelines System

SNR National Refining System

US$ American dollars

88

Conversion Factors

TABLE B. 1 VOLUME EQUIVALENCES

TABLE B. 2 POWER EQUIVALENCES

Change cells

Base unit Conversion factor

New unit

1 cubic meter 6.2898104 barrels1 cubic meter 35.31467 cubic feet1 cubic meter 1,000 liters1 million cubic meters 62,289.8 thousand barrels1 million cubic feet 178.107 thousand barrels1 cubic foot 0.0283168 cubic meter1 gallon 0.0238 barrels1 baril 42 gallons1 barrel 158.987304 liters

Change cells

Base unit Conversion factor

New unit

1 cubic foot 1.03 thousand BTU of natural gas1 BTU 1,055.06 Joules1 BTU 252 calories1 calory 4.1868 Joules1 Kilocalory 3.968254 BTU1 petajoules(1*10 15) 0.94708 thousand barrels of crude oil equivalent 1 Gigajoule 239,000,000 calories1 Petacalory 132.76 megawatts1 watt hour 3,600 Joules

89

TABLE B. 3 HEAT EQUIVALENCES

* Factor applied to fuels in the diesel group.

Change cells Base unit Conversion factor

New unit

1 million tons of oil 40.4 BTU (1012 British Thermal Units)1 ton of crude oil equivalent 41.868 Gigajoules (109 Joules)1 million tons of crude oil equivalent 41.868 Petajoules (1015 Joules)1 metric ton 7.33 barrels of oil1 barrel of oil 5,000 cubic feet of natural gas1 million cubic feet of natural gas 0.9 thousand tons of crude oil1 million cubic feet of natural gas 0.026 thousand tons of crude oil1 cubic meter of natural gas 8,460,000 calories (for purposes of invoicing dry gas)1 cubic meter of natural gas 8,967,600 calories (with a heat correction factor of 1.06)1 cubic meter of kerosine 8,841,586 Kilocalories1 cubic meter of blast furnace gas 8,825,000 calories1 cubic meter of coke gas 4,400,000 calories1 barrel of heavy fuel oil 1,593,000 Kilocalories1 barrel of diesel* 1,469,600 Kilocalories1 ton of petroleum coke 7,465,500 Kilocalories1 kilogram of LP gas (domestic blend) 11,823.86 Kilocalories1 kilogram of LP gas (importing blend) 11,917.30 Kilocalories1 ton of bagasse 1,648,990 Kilocalories1 ton of coal 4,662,000 Kilocalories1 ton of coal coke 6,933,000 Kilocalories

90

References

• Informe Anual 2015, PEMEX.

• Informe Anual 2015, CFE

• Ley de Hidrocarburos

• Plan Quinquenal de licitaciones para la Exploración y Extracción de Hidrocarburos 2015-2019

• Primera revisión annual del Plan Quinquenal de Expansión del Sistema de Transporte y Almacenamiento Nacional Integrado de Gas Natural 2015-2019

• CRE (Nuevo Marco Regulatorio en Materia de Gas Natural)

• Política pública para la implementación del mercado de gas natural

• BP Statistical Review of World Energy June 2016

• U.S. Energy Information Administration | Annual Energy Outlook 2016.

• http://www.gob.mx/sener/presentacion-de-la-firma-del-primer-contrato-de-la-2a-licitacion-de-la-ronda-1.

• http://www.gob.mx/sener/articulos/se-firman-los-contratos-de-la-2-licitacion-de-la-rondauno-area-contractual-2-hokchi-y-4-pokoch-e-ichalkil.

• http://rondasmexico.gob.mx/l03-bloques/

• http://www.gob.mx/sener/prensa/resultados-de-la-tercera-convocatoria-de-la-ronda-uno.

• http://www.gob.mx/cnh/acciones-y-programas/contratos-tercera-licitacion-de-la-ronda-1?idiom=es

• http://rondasmexico.gob.mx/l04-ap-bloques/

• http://rondasmexico.gob.mx/wp-content/uploads/2016/08/20160831-9a-VERSION-FINAL-DE-BASES-limpia-aguas-profundas.pdf.

• http://rondasmexico.gob.mx/wp-content/uploads/2016/07/Bases-Aguas-Someras-R02-L01_n.pdf

• http://rondasmexico.gob.mx/r02-licitaciones/

• 1http://rondasmexico.gob.mx/wp-content/uploads/2016/08/20160823-Proyecto-Bases-Terrestres-R02-L02.pdf

• Informe 2015: http://www.cre.gob.mx/articulo.aspx?id=671