Modelling the natural gas dynamics in the Southern Cone of Latin America

Applied Energy 201 (2017) 219–239

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Modelling the natural gas dynamics in the Southern Cone of Latin America Mauro F. Chávez-Rodríguez a,⇑, Luís Dias b, Sofia Simoes b, Júlia Seixas b, Adam Hawkes c, Alexandre Szklo a, Andre F.P. Lucena a a b c

Energy Planning Program, Federal University of Rio de Janeiro, Centro de Tecnologia, bloco C, sala 211, CEP: 21949-972 Cidade Universitária, Ilha do Fundão, Brazil CENSE – Centre for Environmental and Sustainability Research, Faculdade de Ciências e Tecnologia, Universidade NOVA de Lisboa, 2829–516 Caparica, Portugal Department of Chemical Engineering, Imperial College London, Exhibition Rd., London, United Kingdom

h i g h l i g h t s  We present an energy system model for natural gas in the Southern Cone region.  We modelled a new approach for upstream gas extraction and processing.  We use the TIMES_ConoSur gas & power optimization model from 2012 till 2030.  We present an natural gas outlook in the Southern Cone for 6 regions.

a r t i c l e

i n f o

Article history: Received 13 January 2017 Received in revised form 23 March 2017 Accepted 4 May 2017

Keywords: Latin America Integrated models Unconventional gas LNG

a b s t r a c t Natural gas plays an important role in the Southern cone energy system, and is expected to increase in primary supply in the future. This paper presents a new energy systems model for the Southern Cone region of Latin America, covering five regions (Argentina, Bolivia, South and Centre Chile, North Chile, and Brazil) with the aim to explore, up to 2030, the interplay between (i) the expected consumption of natural gas for electricity generation and end-use consumption (i.e. residential, commercial, transport and industry) in each country, (ii) the inter- and intra-country potential role as producer and consumer of natural gas, and (iii) the possible supply network of LNG and natural gas via pipeline and domestic production. It is found that, under a Constrained Investment Scenario, the gross domestic gas production of the Southern Cone from 2012 to 2030 could be 62 Tcf, whereas under an Unconstrained Scenario, it could rise to 75 Tcf. This highlights the economic potential of the unconventional gas resources of Argentina and projections of associated gas from the Campos and Santos basins in Brazil. However, accessing these resources poses financial challenges. Nonetheless, results clearly indicate significant potential for an increase in regional natural gas trade in the Southern Cone. Ó 2017 Elsevier Ltd. All rights reserved.

1. Introduction Natural gas is a promising transition energy carrier between higher-carbon fossil energy and renewable energy resources due to its relatively low emissions of carbon dioxide and local air pollutants, comparatively low-capital cost utilisation technologies and abundant global reserves [1–3]. Typically, natural gas plays an important role supporting the balancing of power systems with higher penetration of renewables, as they are flexible and can react quickly to changes in renewable output or electricity demand [4]. Natural gas is also an important feedstock to produce other energy ⇑ Corresponding author. E-mail address: [email protected] (M.F. Chávez-Rodríguez). http://dx.doi.org/10.1016/j.apenergy.2017.05.061 0306-2619/Ó 2017 Elsevier Ltd. All rights reserved.

carriers such as hydrogen [5], electricity in power plants [6], biofuels [7] medium distillates [8] and even extra-heavy oils [9]. The future balance of natural gas in the Southern Cone (SC) – here defined as Argentina, Bolivia, South and Centre Chile, North Chile, and Brazil1 – makes a timely study. On the supply side, three major new gas sources could alter energy system dynamics in the region: associated gas in Brazilian pre-salt fields (a major world petroleum frontier), unconventional gas (shale and tight) in Argentina, and imported liquefied natural gas (LNG). On the demand side, gas is becoming increasingly important to cope with the intermittency of variable electricity generation sources. This is particularly relevant 1 This simplification is due to the lack of available data for Uruguay and Paraguay and also to their relatively small amount of natural gas consumption.

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in Brazil where wind power generation is sharply increasing and new hydropower plants are mostly run-of-river [10]. Despite the important role that natural gas may play in the future Southern cone energy system, to date no models have been published that can adequately characterise the opportunities and challenges regarding natural gas in this region, including the competition with other energy vectors. While studies exist that characterise South America (or a coarse disaggregation thereof) as a region [11], and others that focus on single countries within or adjacent to the region [12–15], until now no spatially-resolved representation of the region has been produced. This paper provides this representation, enabling better characterisation of the pathways for gas infrastructure development. It also presents a novel way to characterise upstream resource extraction, which is an area that is often neglected in energy systems modelling. Furthermore, the use of an integrated system analysis to clarify the role of natural gas in the region is of high relevance. As of today, natural gas plays an important but still limited role in integrating Argentina, Bolivia, Brazil and Chile, mostly through exports from Bolivia [15]. The potential for increasing this integration is large, as Argentina and Brazil develop their own production, and natural gas demand shows complementarities between the countries. In order to properly explore the potential role of gas in this region, the energy system of the Southern Cone is modelled herein, focusing on natural gas and its use in the electricity system, while representing the gas spatial infrastructure development pathways. In order to convey these methodological novelties and regionspecific insights, two core elements are presented in this paper: (i) a new TIMES model representing the natural gas system in the Southern Cone, from upstream to final use, and (ii) an outlook on the role of natural gas in the Southern Cone till 2030. The outlook was developed over two scenarios of available capacity investments, and brings insights on: the role of each region supplying and/or consuming natural gas for power generation and for end-uses, the international trade of natural gas, relevance of LNG, influence of unconventional gas in Argentina, and associated natural gas in Brazil. The article is organised as follows: after this Introduction, a Background section presents previous relevant research focusing on systems modelling efforts that include some of the Southern Cone countries. This is followed by a description of the current situation with regards to natural gas in the region in order to provide a base year representation for the modelling, and to put the model development in context. Then the modelling methodology is presented in detail, segregated into downstream, midstream and upstream characterisations, followed by a description of the scenario analysis methodology. Finally, results are presented and discussed, leading to conclusions.

2. Background Several global and regional studies have looked at the mediumand long-term role of natural gas within the energy system (i.e. from primary energy production, conversion into energy carriers such as electricity and end-use consumption). At global level, the ETP energy system model has been used to develop scenarios up to 2050 [16]. Also at the global energy system model ETSAPTIAM was used to analyze how shale gas can impact on regional gas production, inter-regional trade, demand and price until 2050 [17]. The European Union (EU) research project REACCESS used the two energy system optimization models, TIAM (for the world) and PET – Pan European TIMES (for EU27+), to evaluate technical, economic and environmental features of existing and future energy corridors within Europe and between European countries

and rest of the world. A detailed representation of the natural gas supply chain was modelled in PET, including re-gasification plants to take in account the liquefied natural gas imported by ships, seasonal exchanges within natural gas trade and a detailed import and trade matrix between EU countries and world supplying regions [18]. Other authors [19,20] used the PRIMES partial equilibrium energy system model to assess the decarbonisation of the EU energy system until 2050 concluding that the EU power sector can reduce its CO2 emissions by 98% with respect to1990 levels by replacing coal and gas power plants with RES electricity and carbon capture and storage (CCS) gas plants. A more recent study [21] performed a multi model analysis (PRIMES, GEM-E3 and TIMES Pan EU) to explore the required EU wide energy system transformations to reduce Greenhouse Gas (GHG) emissions in 2050 to less 80% of 1990 levels. At national level, the general equilibrium economic model EPPA was applied to study energy scenarios for natural gas exports from Russia [22]. Also, [22], through the use of PLEXOS model, evaluated future primary energy consumption in the Italian thermoelectric sector and the impact of different fuel and carbon price scenarios. A simulation model was used in [23] to assess investment decisions on natural gas trade in Colombia to increase short-term security of supply. A cost-benefit analysis was applied to evaluate Peru’s liquefied natural gas export policy and found the policy’s associated costs exceed the benefits [24]. Although some studies, as previously referred, exist for selected countries of the Southern Cone region (i.e. Brazil, Bolivia, Argentina, Chile, Uruguay and Paraguay), they do not undertake to an integrated analysis from the perspective of the energy system optimization, and do not consider the linkages among those countries. There are no public studies of natural gas integration for the Southern Cone region, although the Latin America Energy Organization (OLADE) has made some efforts to collect and represent data on natural gas international pipelines projects using a Geographical Information System (GIS). Studies using energy planning tools in the region have addressed only the electricity integration [25].

3. Natural gas in the Southern Cone The Southern Cone region encompasses countries with highly varied energy landscapes, reflecting the different countries’ economic structure and development, climatic conditions, population distribution and density, availability of primary energy resources, and the degree of coverage of transport and distribution system, to name but a few [26]. In this paper, the Southern Cone region corresponds to the group of countries: Argentina, Bolivia, Brazil, and Chile. The combined natural gas consumption represented 63% of the total natural gas consumption in South America in 20142 [27]. Natural gas has played an important role in diversifying the energy mix in the SC, with consistent market share increase since 2000 (except for Chile), as shown in Fig. 1. In the case of Argentina and Bolivia, natural gas is the main primary energy source. In the last 14 years, natural gas consumption in the Southern Cone increased 4.6% per year, mostly driven by the Brazilian market evolution that has increased consumption almost fourfold in that period [27,28]. There are significant differences in market size among the four SC countries, with Argentina and Brazil as major markets, consuming 1.848 TJ and 1.731 TJ respectively in 2014 [29,30], while Bolivia and Chile are substantially smaller consuming 133 TJ and 159 TJ, respectively in the same year [28,31]. Overall, the region relies greatly on gas and oil, but also on hydropower and biomass in the energy-mix. 2 Other important consumers in the continent include Venezuela (20%) and Colombia (7%) [27].

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Fig. 1. Evolution of primary energy consumption in the four studied SC countries. Note different vertical scales on sub-figures. Source: [28,30–32].

Although the structure of natural gas consumption varies across these countries, the industry and power generation sectors are the key consumers in all countries [28,30–32]. It is also apparent that the annual pattern of natural gas consumption in Argentina and Chile are seasonal, driven by the buildings’ space heating in cold seasons [33,34]. Fig. 2 illustrates how natural gas net production and imports have evolved in the SC countries. In the 1990s the market liberalization in South America triggered investments to exploit natural gas resources, especially in Bolivia and Argentina, not only in the upstream section, but also in the expansion of domestic and international pipelines to trade natural gas with neighbouring countries. During this decade, Brazil’s natural gas industry expansion relied considerably on the idea of energy integration within South America, especially through natural gas [35]. The construction of 3150 km of pipelines connecting Bolivia’s gas sources with the southeast region of Brazil started in 1997 and began operating in 1999. For example, the GasBol pipeline reached its full capacity in 2005 (30 million m3/day). Further in the south, important investments in transport infrastructure allowed connection of Chilean consumers in the north, centre and south of the country with the Argentinean basins by the end of the 1990s. As a result, seven pipelines with a combined length of over 3500 km were built. Due to the lack of investment in the natural gas upstream and the high demand in Argentina, the government decided to suspend exports of excess domestic supply to Chile, instead reserving them to satisfy the internal demand. The gas crisis peaked in 2007 when Argentinean exports went zero. To secure natural gas supply, Chile constructed two LNG regasification terminals with 5.7 MTPA (metric tonnes per annum) total

regasification capacity [42]. Also, to ensure supply facing potential disruptions from Bolivian natural gas imports, and due to growing demand, Brazil and Argentina built LNG regasification plants, with a total capacity of 11.7 MTPA and 7.6 MTPA respectively [42]. LNG imports are increasing their market share in Argentina, Chile and Brazil. Fig. 3 shows the geographic locations of the natural gas pipelines infrastructure and LNG regasification plants. The natural gas has been a key resource to supply the increasing energy demand in the countries of the Southern Cone, requiring new infrastructures development. However, the energy system is changing with increasing participation of renewables while constraining high-carbon energy resources, alongside new discoveries of gas, and hence it is worth to assess the role reserved for the natural gas in the next decades. 4. Methods In this section we present the methodology to model the natural gas chain in the Southern Cone countries, from an energy system perspective. A generic overview of the modelling approach is presented, followed by detailed descriptions of how the demand and the supply side are addressed in the modelling framework. The modelled scenarios are then described. 4.1. Overview of the modelling approach A hybrid approach was developed, combining several analytical tools, including two robust modelling tools: the simulation model LEAP (Long range Energy Alternatives Planning System) was used

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Fig. 2. Natural gas net production and imports in the Southern Cone countries. Source: Own elaboration based on [27,36–41].

Fig. 3. Natural gas transport and regasification infrastructure in the Southern Cone.

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to estimate the natural gas demand, and the technology-rich energy systems TIMES model was used to optimize the natural gas supply. The modelling framework was implemented for the time horizon from 2012 till 2030, encompassing Argentina, Bolivia, Brazil and Chile, to assess the interplay between: (a) the expected consumption of natural gas for electricity generation or for end-use consumption (i.e. residential, commercial, transport and industry) in each country, (b) the inter- and intra-country potential role as producer or consumer of natural gas, and (c) the expected supply network of LNG, natural gas through pipeline imports, and domestic production. The TIMES model (hereafter referred to as TIMES_ConoSur) is central to the modelling exercise (see Fig. 4). It generates scenarios from the optimization of the allocation of natural gas supply (production and distribution pathways) across the four countries, taking into account the different uses, either as supply for the power system, and for end-uses (i.e. residential, commercial, transport and industry). The final end-use demand for natural gas was estimated using LEAP model, and taken as input to TIMES_ConoSur. This mean that the final consumption of natural gas was modelled as an exogenous demand.3 The TIMES_ConoSur model considers in detail the power sector, although constrained to expand to power system capacities according to plans adopted [10,44–46]. The model can optimize the operation of the existing and planned power plants to deliver the expected power demand. The TIMES_ConoSur model receives inputs from the different tools, as follows: (i) LEAP model, providing the end-use demand of natural gas per economic sector (e.g. industry and transport) as described above; (ii) Multi-Hubbert model, providing projections of oil production and estimated associated natural gas production (using oil-to-gas ratios); (iii) a bespoke excel-based model, providing projections of non-associated natural gas production, based on the resources (proven, probable and possible for both conventional and unconventional types) and on production costs estimates based on historical CAPEX (capital expenses) and OPEX (operational expenses); (iv) country’s specific assumptions on electricity generation expansion plans regarding the evolution of the annual installed capacity, and also the historical capacity curves for different technologies by location [15,41]; and (v) exogenous estimates of installed capacities and costs of natural gas technologies. The main model outputs are the optimal location of natural gas extraction points by domestic classification of reserves/resources, transport network across the five considered regions (Argentina, Bolivia, South and Centre Chile, North Chile, and Brazil), LNG imports, installed capacity of the different natural gas and power technologies; primary and final energy flows; natural gas demand calculated for power, final gas and electricity energy marginal prices and, as mentioned, overall system costs. 4.2. LEAP and projecting the final demand Forecasting techniques for natural gas demand are predominantly top-down approaches [47]. However, bottom-up approaches provide more details about the structure of the demand, allow to background the projections with storylines, and to test energy policies and measures (e.g. energy efficiency, fuel substitution) [48]. Due to the heterogeneity of the final energy use of natural gas in Southern Cone countries and the lack of data for a detailed standard bottom-up approach, two methodologies were applied: one 3 This is a reasonable simplification for our case, as can be observed in the historical consumptions of natural gas in Argentina and Chile [38,43] even in the scarcity period of natural gas during the 2000s the consumption of this fuel in the residential, commercial and public sectors did not have significant changes.

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based on the LEAP model and other based on an econometric fit, aiming at deriving natural gas demand functions. LEAP is a scenario-based energy-environment modelling tool for the analysis of energy policy [49]. We use LEAP to build natural gas demand projections in residential and transportation sectors until 2030. Industrial and commercial/public sectors were firstly modelled through an econometric approach and then input to LEAP. This drew upon econometric correlations from available natural gas consumption time-series and selected indicators, like population, number of households, vehicle fleet composition per type of fuel, and expected evolution of vehicle ownership number of commercial users connected to the distribution pipelines, GDP evolution (as a proxy for industry use of gas). Information on the gas demand projections can be found in [15] for Bolivia and in [33] for Argentina and Chile.4 In the case of Brazil the detailed projections made by EPE [10] were adopted. 4.3. TIMES_ConoSur TIMES_ConoSur is a bottom-up linear optimization model built within the TIMES modelling environment, as developed by the International Energy Agency Energy Technology Systems Analysis Programme (ETSAP) [50]. The ultimate objective of a standard TIMES model is the satisfaction of demand for energy services at the minimum system cost. To achieve this, TIMES simultaneously decides on technology investment and operation, primary energy supply and energy trade. For each modelled year, a TIMES model computes the discounted sum of the annual costs minus revenues. In the case of TIMES_ConoSur, only investment costs and fixed and variable operation and maintenance costs of the power and natural gas supply system are considered, and demand is stated as final energy demand instead of energy service demand. TIMES_ConoSur represents the natural gas supply of the energy system of the Southern Cone covering the following components: primary energy supply, including the extraction, transport and distribution of natural gas, and electricity generation (Fig. B.1 in Annex B). As previously mentioned, the demand sectors are modelled in an aggregated format. The model is structured in four main components: upstream extraction of natural gas, midstream (processing and transport of natural gas), power generation and final demand. Natural gas and power can be traded across the five regions, considering not only the existing pipelines but also future expansions, but also LNG terminals including transportation by ship. Imports and exports for the rest of the world are also possible. Therefore, TIMES_ConoSur can model the four countries in an integrated manner. This is further explained in Sections 4.3.3 and 4.3.4. Regarding the costs of energy technologies, although the capital costs for oil and gas technologies fluctuate according with the oil price [51,52], and learning curves can alter the feasibility of some technologies, as occurred with the technologies for unconventional gas in the last decade [53], the capital costs in TIMES_ConoSur remains constant for the different technologies over the assessed horizon. Finally, a real discount rate of 10% per year is incorporated to assess the investments. This is a standard value in the oil and gas industry [54–56], however it was applied as a global discount rate across used in the objective function. 4.3.1. Temporal and geographical resolution The model is built on different temporal resolutions depending on its components: in the case of upstream, a yearly resolution was adopted, whereas for midstream a monthly resolution incorporates the seasonality of natural gas consumption. For the case of power 4

Supplementary Material A shows the assumption and the projections of LEAP.

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Fig. 4. Natural gas & power modelling approach developed for this study.

generation, a temporal resolution of 24 h per typical day of the month (24  12 = 288 time-slices per year) was used. This enables better treatment of natural gas fired power plants, that often operate during the peak hours of the day as shown further in Fig. 5. As there are time differences between the SC countries (up to 3 h from Chile with Brazil), hourly data was transposed to Brazilian time (GMT-3). This can be illustrated in the load curve of the electricity demand used for each country shown in Fig. 5. Regarding geographical resolution, the model approach covers five regions as shown in Fig. 6: Argentina, Bolivia, South and Centre Chile, North Chile, North Brazil and Integrated Brazil. This division was made based on the topology of gas pipeline networks, the different sources of natural gas supply and the different structure of natural gas demand in each region. Energy flows between these regions are an output from TIMES_ConoSur. 4.3.2. Power generation capacity assumptions The mid-term power expansion plans for the four assessed countries [10,45,46,44] were included into TIMES_ConoSur as exogenous assumptions, namely the power expansion capacities per technologies and the electricity demand, as shown in Fig. 7. Based on these planned expansion capacity for each technology and the electricity demand, the model carries out a least-cost operation of the power system, generating the natural gas consumption as one of its outcomes. Neither ramp-up nor ramp-down constraints were considered for power plants operation. Each power generation technology used in the six regions was modelled based on general technical and economic characteristics

such as: effective capacity, conversion efficiency and costs. Conventional power technologies and renewables costs were based on [61] and [62], respectively. We incorporated the availability factors of renewable resources (hydro, wind and solar) based on historical information for each country. Availability factors of hydro and wind were modelled on a monthly basis and of solar technologies on an hourly basis to fit the time resolution of TIMES_ConoSur (Table B.1 in Annex B). Finally, fuel prices for power generation were taken from current prices of each country [32,36,46,63-65]. This is a relevant feature since, in Bolivia for instance, oil products for power generation are subsidized [15]. The planned expansion of interconnected electricity capacity between North Brazil and Integrated Brazil and also between from North Chile and Central-South Chile were considered [10,68], as well as the existing interconnections between Chile and Argentina. Although there are plans for Bolivia to build a line to export electricity to Argentina, this international interconnection was not incorporated in the model, as no public data about its capacity is available. International electricity trade using the existing transmission lines were left unconstrained from 2016 onwards. 4.3.3. Midstream in TIMES_ConoSur Two modules compose the midstream: the natural gas processing plants and the imports/exports. The net natural gas production is the feedstock of natural gas processing plants, with three outputs: liquids of natural gas, ethane and dry-gas. Liquids of natural gas are then converted to LPG and gasoline. As our focus was only on the natural gas market, we did not model the downstream of the

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Fig. 5. Commodity fraction (Commodity fraction is referred as the distribution of the yearly total energy in the defined time slices. The sum of the commodity fractions across the year is 1) of the electricity demand modelled in the base year. Source: [57–60].

Fig. 6. Geographical resolution of the TIMES_ConoSur model.

by-products of natural gas, consequently LPG, gasoline and ethane produced were considered to be sold at international prices [69]. Dry-gas is an input of ‘‘Gasmarket” and a commodity, which represents the pool of natural gas availability in the midstream (see Fig. B.1). The inputs to this pool include the domestic produc-

tion, the import through natural gas pipelines and the import through regasification plants. The outputs of this pool is domestic natural gas, including natural gas for power generation and for consumption in final sectors, and exports through international pipelines or new liquefaction plants. International pipelines were

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Fig. 7. Power generation capacity expansion by technologies. Source: [10,45,46,44,66,67].

modelled as a total transport capacity across regions and are assumed to be a unidirectional flow processes. Table 1 shows the data used to model the existing international gas pipelines, and Table 2 presents data on the regasification plants capacities. Until 2014, historical import/export flows for both international gas pipelines and regasification plants were used. From 2015 onwards, the flows are an output from the TIMES_ConoSur model.

Defining LNG prices is a critical issue for the modelling exercise, since it may determine if it is less costly relying on the importation of LNG or tapping the domestic resources to supply the domestic demands. From 2014 onwards, prices of LNG has been declining, and prices are expected to remain low [76]. We assumed that prices of the first quarter of 2016 (Fig. B.3 in the Annex B) will remain constant over the horizon of analysis.

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M.F. Chávez-Rodríguez et al. / Applied Energy 201 (2017) 219–239 Table 1 International natural gas pipelines in the Southern Cone. International pipelines Exporters

Importers Argentina

Argentina

Brazil

North Chile

Central and South Chile

Aldea Brasileña-Uruguaiana: 12 MMm3/d. Flows interrupted in 2008

Norandino: 5 MMm3/ d. Flows interrupted in 2008

For all these pipelines the natural gas flow was interrupted in 2008 GasAndes: 9.5 MMm3/d Gasoducto del Pacífico: 3.5 MMm3/d Methanex I: 2 MMm3/d Methanex II: 2.8 MMm3/d Methanex III: 2 MMm3/d

Atacama: 9 MMm3/ d. Flows interrupted in 2008 Yabog: 6.5 MMm3/d. Currently working as contingency pipeline Madrejones-Campo Duran: 1.2 MMm3/d. Abandoned in 2012 Juana Azurduy de Padilla (GIJA): 24 MMm3/d. In operation since 2011, it is planned to be expanded until 33 M3/d in 2019

Bolivia

Gasbol: 30 MMm3/d. At full capacity

Cuiaba: 2.6 MMm3/d. At full capacity

Table 2 Regasification terminals in the Southern Cone. Source: [70–75]. 1st year of operation

Name

Region

Capacity (Million m3 per day of gas)

Storage capacity (thousand m3 of LNG)

Storage capacity (Million m3 of gas)

2008

Bahia Blanca Gas Port Quintero LNG

Argentina

17

151

94

Central and South Chile Brazil North Chile Argentina Brazil Brazil Central and South Chile

10

334

207

7 5.5 17 20 14 5

129 175 151 173 137 334

80 109 94 107 85 207

2009 2009 2010 2011 2012 2014 2015

Pecém Mejillones LNG Puerto Escobar Guanabara LNG TRBA Quintero LNG Expansion

4.3.4. Upstream in TIMES_ConoSur Fossil resources are usually modelled in TIMES as disaggregated step curves of increasing extraction costs. This typically results in a resource consumption of each tranche in order of increasing costs. However, low-cost resources are not always exploited first. In reality, companies prefer low-cost resources; they compete between them to earn a license to exploit them, which has a validity period, usually between 20 and 30 years. In the meantime, higher-cost resources, which are still profitable, are exploited under the same procedure. This results in a supply curve composed by production curves with different costs. This principle can be applied both for oil or natural gas extraction. In addition, upstream disaggregated data by fields is limited for the Southern Cone, while aggregated public data at national level is available. Based on the these limitations, the methodology developed by [15] was used in TIMES_ConoSur to represent the production of non-associated conventional and unconventional natural gas. Associated natural gas production is relevant in Argentina and Brazil. Since associated natural gas production relies on the dynamics of oil production, firstly oil production was projected using a Multi-Hubbert approach [77,78],5 then natural gas to oil production ratios were used based on [79] and [41] for Brazil and Argentina, respectively. To apply the methodology of [15] for project the production curves of non-associated natural gas, the amount of reserves and resources of non-associated gas is required. As the methodology does not incorporate a process to increase reserves over time through exploration of undiscovered resources or a reserves

5

In the case of Argentina we used the Multi-Hubbert oil curve elaborated by [33].

growth mechanism based on contingent resources, these resources are incorporated according to a static EUR (Estimated ultimate recovery) definition. Reserves and resources statistics usually does not detail nonassociated and associated natural gas [36,72,80–83]. Where data of reserves and natural gas and oil production is available at field level, as in Argentina, it is possible to infer which fields are oil or gas fields, by using the ratios presented by [84]. However, for the other countries, assumptions were necessary based on aggregated data and knowledge of the local hydrocarbons production, e.g., in Chile and Bolivia natural gas domestic production relies only on gas fields. Table 3 summarizes the EUR used for modelling in each region according to the reserves/resources classification and the type of natural gas. An important feature of TIMES_ConoSur regarding the natural gas industry is that condensates are considered as an output of the non-associated gas wells. This can have a significant impact on the shadow price of the natural gas produced, in view of the opportunity cost of condensates. The price for condensates produced was assumed to be 44 US$/bbl based on [69]. Fig. 8 shows the ratio of condensates to wet gas on an energy basis for each country, adopted for modelling natural gas upstream in TIMES_ConoSur. The consumption and losses of natural gas in the upstream (self-consumption, flaring, venting and fugitive emissions) were subtracted from the gross natural gas production. Estimating upstream costs for gas is a challenging task [85], not only due to the lack of related published data but also due to the uncertainty on the different components considered in the companies’ report of aggregated costs (e.g. overhead costs, government take, financial costs). In order to estimate costs for the modelling, an the aggregated approach based on the reserves and resources

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Table 3 Estimated ultimate recovery in MMm3 of natural gas used in each region. Source: [36,72,80–83]. Country

Natural gas type

Argentina

Associated natural gas Conventional Non-associated natural gas Unconventional Non-associated natural gas Conventional Non-associated natural gas Conventional Non-associated natural gas Unconventional Non-associated natural gas Associated natural gasa Conventional Non-associated natural gas Associated natural gas Conventional Non-associated natural gas

Bolivia Chile Integrated Brazil North Brazil a b c

Reserves/resources classification Proven

Probable

Possible

Other resources

90 874 241 297 5 978 256b 295 944 41 000

36 282 112 795

24 677 120 368

118 291 395 675

99 120 57 000

117 528 –

278 528 104 267 23 660 30 389

475 407 211 471

196 878 107 204

662 103 42 583 69 458c 58 175 25 878

58 848

EUR for associated natural will be defined indirectly by the EUR of oil defined for the Multi-Hubbert curve elaboration. Economically recoverable. Undiscovered fraction 95%.

boe Condensates/ boe Wet Gas 0.18 0.16 0.14 0.12 0.10 0.08 0.06 0.04 0.02 0.00

Bolivia

Argenna

Chile

Integrated Brazil

North Brazil

Fig. 8. Condensates to wet gas ratio on energy basis for non-associated gas for each region.

categorization to estimate the escalated costs gas production was used. CAPEX and OPEX ratios were estimated based on historical investments reported by the different companies/agencies and the historical natural gas production [12,36,41,86–90]. More information about Reserves/Resources classification and costs can be found in the Supplementary Material B. 4.4. Scenarios Previous studies [91] found that the extent of limitations on capital investments in upstream is pivotal for the future supply of natural gas in the Southern Cone, and may shape the future of LNG and regional gas trade. Limitations on capital investments in upstream limitations might be explained by financial constraints, lack of industrial capacity and regulatory constraints. Therefore, two scenarios were developed around the extent to which capital investments can be made in natural gas upstream processes: a Constrained Investment and an Unconstrained Investment scenario. The major distinguishing factor between the scenarios was the exogenous assumption of a limit on the total investments per year for all non-associated gas fields where CAPEX costs were specified. This CAPEX costs restriction was used for Argentina non-associated conventional and unconventional gas. As the levels of investment per year are difficult to predict, the Constrained Investment Scenario includes estimated conservative assumptions towards low natural gas production, aiming to test how the natural gas markets would evolve under this situation. Oil fields, where associated gas is produced, were modelled under a top-down methodology (Multi-Hubbert curve) and costs of oil fields were not included. Under this top-down approach, each scenario included a different EUR for the Multi-Hubbert curves in order to incorporate indirectly the restriction on the capacity of

investments. For instance, a lower EUR incorporates assumptions about a low oil price scenario, regulatory challenges, lack of industrial capacity, etc. that can jeopardize the investments to tap the oil resources [77]. This methodology was used for Brazilian offshore oil production. For both Constrained and Unconstrained Investment Scenarios, the expansion of regasification plants for LNG is allowed only from 2018 onwards, to take into account the engineering and construction duration if any decision to expand them is taken in 2016. 4.4.1. Constrained investment scenario Investment in CAPEX in E&P in 2016 in upstream worldwide are estimated to be around 40–50% of the 2014 value, due to many factors, but mainly to low oil prices [92]. To capture this condition in the model for Argentina, a decline of 50% in the CAPEX investments for 2016 when compared to the historical values estimated for 2014 based on [88] was projected. From 2016 onwards the Constrained Investment scenario considers a CAPEX investments decline of 3% in non-associated conventional gas projects and a growth of 15% in non-associated unconventional gas projects. For Brazil, it is assumed that P95 reserves are used as the EUR for Post-salt oil production and 30 billion oil barrels as the EUR for the Pre-Salt oil production. The Constrained Investment scenario assumes that Post-Salt production maintains the declining pattern and the growth production of Pre-Salt oil fields are not enough to increase the oil production at country level. Only from 2020 the oil production rise again an in 2030 it reaches 2.5 MMbpd. 4.4.2. Unconstrained investment scenario Unconstrained Investment scenario also considers the fall of CAPEX investment up to 2016. However, from 2016 onwards there

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are no restrictions on CAPEX for Argentina. This unconstrained capacity of investment aims to test what may happen if funding and industrial capacity would be adequate to tap the conventional and unconventional gas resources in Argentina. For Brazil, under the Unconstrained Investment Scenario, P50 reserves are assumed to be used as the EUR for Post-salt oil production, and 100 billion oil barrels as EUR for the Pre-Salt oil production. It is also assumed that in 2030, the Brazilian oil production reaches nearly 3.5 MMbpd: 40% more than in the Constrained Investment Scenario. Differently from the Constrained Investment Scenario, the Post-Salt fields raise their production together with a higher production level of Pre-Salt fields. Assumptions made for both Constrained and Unconstrained Investment Scenarios are summarized in Fig. 9 (numerical values for these assumption can be found in Supplementary Material C). 5. Results and discussion This section presents an overview of the results from the TIMES_ConoSur model described above. 5.1. Natural gas production On the production side, the TIMES_ConoSur model outputs provide useful insights on when and how much natural gas resources

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would be exploited and depleted in each reserve category. In the Constrained Investment Scenario (Fig. 10), natural gas production in Argentina continues its decline lowering to 83% of 2012s gross production. Conventional gas is still the major supply source, as unconventional gas maintains its current production levels. However, under the Unconstrained Investment Scenario (Fig. 11), from the moment there are no longer limitations in investments in upstream processes (2017), the production boosts using conventional gas possible reserves and other resources. This may be unlikely as these resources should be classified as proven reserves now for such investments to occur in such a short timeframe. Interestingly in this scenario, 2017 would be the peak production of conventional gas. From 2018 onwards the natural gas production would expand on unconventional resources reaching 63% of total gas production in the country in 2030. For Bolivia, both scenarios are similar despite the changes in the supply dynamics of importers. Under the Unconstrained Scenario, the accumulated production up to 2030 is 2% lower than in the Constrained scenario. This can be explained by the low-cost of natural gas production. In both scenarios, 3P reserves would be committed already in 2021, and from 2022 onwards the expansion of production would rely on other resources. In Brazil, both Pre-Salt and Post-Salt associated natural gas will play a major role for the supplying of this resource for the country. In the Constrained Scenario, provided the decline rates of Post-Salt

Fig. 9. Constrained and Unconstrained Investment Scenarios assumptions for upstream natural gas.

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Fig. 10. Gross natural gas domestic production under the Constrained Investments Scenario.

fields production continues, despite the increase of Pre-Salt fields production, the total natural gas production will follow a declining pattern until 2022 when the growing effect of Pre-Salt Fields overcomes the declining effect of both Post-Salt Fields and nonassociated developed gas fields. In 2030, in the Constrained Investment Scenario, the production level of associated gas is similar to the production by 2012. Interestingly in this scenario, undeveloped non-associated gas reserves are extracted in the second half of the next decade, while this will not occur in the Unconstrained Scenario, due to the flood of associated gas. In the Unconstrained Scenario, the declining effect of existing non-associated gas fields dominates until 2019, when associated gas production starts to grow again In this scenario, the associated gas production in 2030 would be 134% higher than the 2012 production level. In North Brazil, the natural gas production will remain low this decade for both scenarios. However, in the next decade nonassociated gas is triggered in both scenarios at different levels, explained by the consumption for power generation producing electricity that is consumed in the Integrated Brazil region, as

observed further in the ‘‘Natural gas demand results” section below. North Brazil gross-production in the Constrained investment Scenario nearly doubles the production of the Unconstrained investment Scenario, explained by the lack of associated gas production for power generation in the Unconstrained scenario and the cost-differential of non-associated gas production between North and Integrated Brazil. In Chile, the production does not vary significantly between the two scenarios. The natural gas production is triggered in the firstyear of modelling (2017). It is relevant to point out that the model did not choose to produce the high-cost unconventional resources in Chile despite the lack of limitations on the capacity of investments for this country. Instead, to supply domestic demand the model preferred the deployment of LNG regasification plants. 5.2. Natural gas supply and trade The supply sources of natural gas for each region, including domestic production, LNG and imports by pipelines from other

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Fig. 11. Gross natural gas domestic production under the Unconstrained Investment Scenario.

countries are depicted in Figs. 12 and 13. In general terms, the results show evidence of a strong dependence and interaction between regions. Bolivia will keep its main supplier role of the region. Under the Unconstrained Scenario, Argentina would resume natural gas exports to Chile, with higher volumes sent to Central-South Chile than North Chile region. No exports to Brazil are evident in the scenarios if contracts are not considered. Despite its natural gas exporter position under an unconstrained scenario, Argentina keeps its imports of LNG during winter season in both scenarios. The domestic production level of the two scenarios determines the degree of dependence on LNG of Argentina. LNG regasification plants in Argentina are required by 2018, the first year the model is able to consider them. A least-cost system will require Chile also to expand its LNG regasification capacity in both scenarios. However, under an Unconstrained Scenario, the volumes of LNG will be much lower due to the Argentinian natural gas imports in the summer. Interestingly, the results for Chile suggest that Argentinian exports

would be in higher volume in the first ten years when low-cost resources production have lower break-even prices than imports of LNG (of course the model does not incorporate learning costs). In North Chile, current regasification capacity is enough for regional needs in this decade. This brings opportunities, for instance, to use the spare regasification capacity in Chile for exports to Argentina. For Brazil, in the next five years LNG would not be required if there are regular inflows for hydropower plants that provide the capacity factor assumed for this study. Imports of LNG in both scenarios occur in Brazil in the dry-seasons at different levels of volume depending on the domestic production of natural gas of each scenario. These figures make evident the strong complementarity of LNG imports and hydropower seasonality to ensure a reliable power generation system. It should be highlighted that none of the scenarios shows the need to expand the regasification capacity in Brazil. Alternatively to LNG, the model suggests that swing producer petroleum fields would be required to increase its pro-

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Fig. 12. Natural gas supply projections in the Southern Cone under the Constrained Investment Scenarios. Note differing vertical scales on sub-figures.

duction in dry-seasons. This is a monthly allocation of the model for the associated natural gas inputted on yearly resolution. Of course, oil fields will not follow a swing producer pattern just to allocate associated-natural gas. Therefore, without natural gas storage, this supply pattern for dry-season will not occur. Further studies are required to assess natural gas storage and its benefits. The North Brazil Region (the Cuiaba Thermal power plant) will reduce slightly the consumption of Bolivian imported natural gas in the Unconstrained Scenario, where other natural gas power plants are operating in the Integrated Brazil region using domestic production. 5.3. Power generation Power generation results show the role of natural gas as a flexible and reliable source to cover the power demand in peak hours. In the case of Argentina and Bolivia, natural gas power plants cover a significant part of the base load, and the power generation based on natural gas is expected to increase. Nuclear and wind increases

significantly in Argentina as well. For Argentina, in winter the model operates natural gas power plants in a lower level than summer, reflecting the real historical seasonal pattern [64]. Seasonality and the increase of hydropower in North of Brazil are remarkable. Dry-season is defined from June to December for hydro-power in this region. As can be observed in Figs. 14 and 15 for the Integrated Brazil, the electricity transfers from North Brazil are higher in the wet season, January to June. Combined cycle plants will operate in the dry season in Integrated Brazil with higher capacity factors. Coal consumption for power generation increases in Chile, while solar will play a major role as well. The hourly resolution of the power sector allows the model to capture the operation of solar power plants during the day, and interplay between solar and natural gas power plants in the peak hours. In Central-South Chile natural gas power plants have a larger operation in the dry-seasons (from February to August). Interestingly, while the capacity of coal plants are sufficient for North Chile, when the interconnections between the Interconnected Central System and the Interconnected Major North System is built in 2018, the model

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Fig. 13. Natural gas supply projections in the Southern Cone under the Unconstrained Investment Scenarios. Note differing vertical scales on sub-figures.

instead runs combined cycle plants in North Chile to export electricity to the Central-South region. In general terms, excluding the case of North Brazil, there are no significant differences between the two scenarios regarding the operation of the power sector and the participation of natural gas. This means that the prices of LNG assumed would bring similar costs as those of domestic production to natural gas power plants. 5.4. Natural gas consumption in end-use sectors In Argentina, the results of the following figures shows the seasonality of end-consumption of natural gas with peaks in winter and the natural gas for power generation with peaks in summer. In the Unconstrained Scenario, Fig. 16 shows that in the summer season Argentina would be able to export natural gas to Chile with its nominal production capacity. The figures for Bolivia highlight the fact that export markets can be extremely relevant when compared to domestic demand in

terms of volume. Differences between scenarios are projected to happen in the second half of the next decade, according to Figs. 16 and 17 these changes are explained by different consumptions in North Brazil and Argentina. Fig. 17 also evidence a higher consumption in North Brazil (1923 PJ accumulated up to 2030) in a Constrained Scenario compared to the consumption in the Unconstrained Scenario (1196 PJ) due to a lower availability of natural gas for power generation in the Integrated Brazil region. This shows that if less associated natural gas is produced offshore, other natural gas resources from Amazonia will be required to supply the power generation demand. Finally, relying on Argentinian gas imports in the summer season under the Unconstrained Scenario, Central-South Chile will have a higher consumption of natural gas for power generation. The intermittent consumption pattern of natural gas for power observed in North Chile is explained by the relatively high share of coal in the energy mix. Natural gas is consumed when ‘‘spot” monthly price (shadow price) makes the operation of combined

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Fig. 14. Power generation profiles in the Southern Cone under the Constrained Investment Scenario. Note differing vertical scales on sub-figures.

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Fig. 15. Power generation profiles in the Southern Cone under the Unconstrained Investment Scenario. Note differing vertical scales on sub-figures.

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Fig. 16. Natural gas demand projection in the Southern Cone under the Constrained Investment Scenarios.

cycle power plants feasible, where power generated is transmitted to the Central-South region (Figs. 14 and 15).6

6. Final remarks This paper has presented a new energy system model for the Southern Cone region of Latin America. This model, implemented in the TIMES modelling framework, has two distinctive model features; (1) a relatively high level of spatial disaggregation in order to capture the diversity of energy landscapes within the region, and (2) a new and more credible approach to characterising upstream resource extraction and processing. These features enable more nuanced insight on possible energy pathways for the region given the abundance of natural resources, potentially rapid economic growth, and increasingly interconnected markets within the region. 6 According to the outputs of the model, natural gas power plants in North-Chile are not used for peaks in the North region since this region has a ‘‘flat” load shape (see Fig. 5).

The model has been applied to investigate the potential role of natural gas within the future Southern Cone energy system. Gas is an interesting energy resource in this region given large proven and possible reserves, and a growing need to use it as a costeffective partner in low carbon electricity systems, where it can help ensure security of supply. The critical variable chosen to distinguish two scenarios in TIMES_ConoSur was the CAPEX in upstream production. This was an attempt to reflect the financial constraints to perform investments in the sector. Hence, two scenarios were developed: the Constrained Investment Scenario, where Argentinian investments for both conventional and unconventional gas production were limited and a lower offshore oil production projection for Brazil was adopted; and the Unconstrained Investment Scenario, with no financial limits for upstream in Argentina and with an optimistic offshore oil production projection for Brazil. In the Constrained Scenario, the gross domestic production of the Southern Cone accumulated from 2012 to 2030 was 62 trillion cubic feet (Tcf) whereas in the Unconstrained Scenario it rose to 75 Tcf for the same period. This illustrates the economic potential of the unconventional gas resources in Argentina and a more optimistic

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Fig. 17. Natural gas demand projection in the Southern Cone under the Unconstrained Investment Scenarios.

projection of associated gas from the Campos and Santos basins in Brazil. Indeed, unconventional gas in Argentina can be a game-changer for the natural gas dynamics in the Southern Cone. No financial restrictions to produce these unconventional resources allowed reduced accumulated LNG imports in Argentina between 2012 and 2030 from 6.7 Tcf (Constrained Scenario) to 2.4 Tcf (Unconstrained Scenario). Unconventional gas in Argentina also allowed this country to resume exports to Chile and Brazil. However, tapping these resources poses a financial challenge. For instance, to develop the Unconstrained Scenario the investments estimated in upstream for Argentina were 36 billion US$ (CAPEX) and 11.4 billion US$ (OPEX). There are also uncertainties about the costs assumed for unconventional gas in Argentina. On the upwards side, cost might rise as the more economic fields are depleted first. On the downward side, our analysis has not considered learning curve effects and did not disaggregate costs between tight and shale gas. Currently, tight gas is the major share of unconventional gas production. To have more reliable and detailed upstream cost data will be key for the robustness of the domestic gas supply projections. Brazilian associated gas from offshore oil fields was also pivotal.

Although it did not cause any breakthrough effects in the other countries’ natural gas markets, it had a dramatic effect on LNG imports, almost eliminating them in Brazil from 2017 up to 2030 in an optimistic oil production scenario. The scenarios can help policy makers dealing with uncertainties. Critical uncertainties include financial constraints and the rhythm of endogenous gas resources development in Brazil (offshore), Argentina (unconventional) and Bolivia (conventional resources). Under a pure least-cost optimization model the choice points to inforce Bolivia’s low cost resources development, as a driving force for regional integration (retaking the strategy of Brazil-Bolivia gas integration of the 1990s). However, the need for monetizing Brazil’s stranded gas resources associated with oil production in pre-salt layers and the possible ramp-up of Argentinian unconventional production may alter this least cost strategy towards a costier but more resilient solution, where different gas supply sources may be combined to expand gas market in the Southern cone. Should this market be developed as an integrated market or should it be developed under the aegis of national strategy, this decision is always a matter of the combination between the best technical choices and the way these choices can or cannot

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be implemented, given regulatory and political barriers. To a gas market be integrated in the Southern cone, issues such as the seasonal and uncertain gas demand in Brazil (correlated to dry seasons) and the LNG imports in Chile (and even Uruguay) must be accounted for. Hubs and gas storage sites must be implemented as well as the possibility of trading gas. The countries in the Southern Cone are still far away from this situation, which would allow them to access the Pacific Basin (LNG imports in Chile) and the Atlantic Basin (LNG imports or exports in Brazil and Argentina). As the forecasts made in this study indicate, chances are that the Southern cone will see an increasing gas supply not coordinated by interregional policies but specific bilateral agreements, such as the one made between Bolivia and Brazil in the 1990s, or Argentina and Bolivia, and Argentina and Chile, in the 2000s. LNG imports will increase pulled by Chile demand and the seasonal and uncertain Brazilian demand. Nonetheless, regional natural gas trade is likely to increase in the Southern Cone. In the Unconstrained scenario, Argentina resumed gas exports into Chile during the summer season using the spare capacity of non-associated gas fields. Argentina also could export gas to the Uruguaiana combined cycle thermal power plant in Brazil during the dry-season. Bolivian exports are found to be able to increase to Argentina, and maintain the same values in Brazil for both scenarios. LNG still remains as the most economic option to supply peak demands in winter in Argentina and Chile. Finally, the outcomes of this paper are largely driven by the assumptions made for each scenario. Therefore, further studies should consider a set of different driving forces, besides constrains on investments. For instance, on the upstream side, Government take is not commonly incorporated in energy planning models, such as the TIMES_ConoSur. However, incorporating this factor might divert investments to produce natural gas towards other countries with higher resources costs but lower government take. On the demand side, to assume inelastic demand for natural gas end-uses is a simplification; however, the current available data on natural gas prices and consumption in the Southern Cone makes difficult to estimate this elasticity. An alternative could be modelling end-use sectors at the level of useful energy, but available data is also a limitation in this regard. In terms of the rationale of the model, the main two assumptions of perfect competition and perfect foresight ignore the real dynamic of the energy markets. Myopic simulations are possible to perform in TIMES. But, regarding on the perfect competition assumption, TIMES_Conosur objective function is to minimize the costs in the Southern Cone as a whole system, this approach neglects the contracts’ price and the market power of the agents which is essential to replicate the real world’s market dynamics. However, should the focus be to represent market and government failures, other types of tool (instead of TIMES) need to be used. This is also important when representing energy strategies related to geopolitics. Further research is also required to analyze: the role of natural gas storage in Argentina and future storage infrastructure in Brazil; how climate change mitigation policies can affect the future natural gas supply and demand; and the opportunities to integrate the Southern Cone with other natural gas markets in Latin America. Acknowledgements The authors wish to thank Rafael Soria for the data delivered to model power generation in Brazil and Kannan Ramachandran for his guidelines in CPLEX to solve in TIMES high memory usage models as the TIMES_ConoSur. We thank to Daniela Varela, Fabiola Rodrigues, Javier Bustos, Alex Koberle and Eveline Vasquez for their useful expertise and support about Argentinian and Chilean energy systems. We are grateful to Giovanni Machado of EPE for

the insights on natural gas modeling in Brazil. Finally, we acknowledge the financial support from CNPq, particularly the CNPq/TWAS (Processes 190318/2011-2) for the full time postgraduate fellowship that sponsored this research.

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