The makeup of the combined energy market in Latin America (LatAm) is tilted toward renewables, with 37% in hydro, 14% in wind, 10% solar, and 28% natural gas, while globally it's 37% combined hydro, wind, and solar, and 23% natural gas. Nevertheless, the energy matrix is heterogeneous among the countries in the region, ranging from Brazil's 115 gigawatt (GW) hydro capacity (57% of matrix) and Mexico's 38 GW natural gas capacity (55% of matrix). This translates to a distinct energy transition path for each country.

Even though coal only represents 2% of the amount of energy that LatAm produces, it is mostly concentrated in Chile, with 5.7 GW installed capacity as of December 2022 (30% of matrix). Chile also has the region's most ambitious plan to decommission 1.5 GW of coal in the next three years and achieve full decommission of its carbon plants by 2040.

In this scenario, we see two similarities in the energy transitions plans for Latin American countries: (i) investments are focused to develop both wind and solar, including small solar plants and distributed generation, and (ii) transmission line capacity (namely curtailment) has been an underestimated risk.

Since new development of wind and solar is usually in areas physically distant from consumption centers, transmission capacity is becoming a recurring risk because the existing network might not have sufficient capacity to attend the increased supply, especially during peak hours. We have seen this occur in Chile, with a decoupling effect--for example, a high price difference between energy injection and withdrawn nodes. In Mexico, constraints in the grid are causing energy spills in Oaxaca, a region known for its wind resource capacity. Finally, Brazil presented some intraday spot price volatility amid unusually high temperatures for September and October, while its hydro reservoirs remained high in the Center-South region versus a drought in the North region.

Another issue related to execution of the energy transition plan is the speed of solar and wind construction, which takes two to three years compared with seven to eight years for a large-scale transmission line to get the energy where it needs to go. For example, the Kimal Lo Aguirre transmission line under construction in Chile will connect the north, where most of new solar capacity is being deployed, and the center, where consumption is higher. Still, this 1,500 kilometer (km) line is expected to be completed in late 2029, pushing the system operation to find an interim solution. Similarly, there is a delay in the construction of the renewable capacity projects awarded in 2019 in Colombia. This was a landmark auction to deploy wind and solar, supported by 15-year power purchase agreements (PPAs), but the lack of connectivity has been a bottleneck for its execution.

Hence, we believe that early planning is key for the region to leverage its renewable potential to develop new business opportunities that will arise as the world is focused on achieving net-zero targets. While the pace of new technologies, like green hydrogen, is still uncertain, we have seen an indication of quick deployment of solar photovoltaic (PV) on a large scale in the last 10 years, driven by a 90% drop of cost around $1 per watt. Below, we outline the characteristics and planning of each of the key countries in the region.

Key National Market Characteristics

Argentina

Given the political and regulatory uncertainties in Argentina, power prices are mostly discretional from the government without a clear driver, and we expect this to continue in the short to medium term. Moreover, we forecast the power supply will continue to rely on gas and oil-fired generation.

Brazil

Brazil's energy matrix is mostly skewed toward renewables, with 59% hydro, 14% wind, and 5% solar installed capacity in the interconnected system. That reduces the country's dependence on fossil fuels and contributes to lower carbon emissions.

Hydrology conditions are the main driver of spot prices in the short term. Since October 2021, the country's reservoirs started to recover after one of the worst droughts ever seen. For instance, the Southeast/Midwest reservoir, responsible for about 70% of Brazil's storage capacity, is at 66% of its capacity (versus about 50% in 2022 and 20% in 2021), which is more than enough to address the country's energy needs until the end of 2024. That contributed to a consistent drop in average energy spot prices, which reached the regulatory bottom of Brazilian real (R$) 55.7/megawatt hour (MWh) in 2022 and R$69/MWh in 2023.

In spite of recent peaks in hourly energy spot prices due to one-off supply shortages and higher load demand caused by higher temperatures--especially by the end of the afternoon when solar generation declines--we expect energy oversupply and favorable hydrology to continue favoring low energy prices, at about R$110/MWh to R$130/MWh in the medium to long term. According to Brazil's energy regulator, ANEEL, there are 155 GW of projects approved but not yet built, which represents roughly 78% of the country's current installed capacity.

Part of these projects might not end up getting built considering current low energy prices and still mild GDP growth in Brazil, which we expect to be between 1.5% and 2.0% from 2024 onward. That should translate into maximum electricity demand growth of about 3% per year until 2032, according to the 2032 Ten-Year Energy Expansion Plan issued by government agency Empresa de Pesquisa Energetica. Energy demand in Brazil has grown slowly, registering an accumulated increase of 10% in 2013-2022, while Brazil's installed capacity grew about 50% in the same period.

Still, we expect nonconventional renewables to continue driving the growth of the country's installed capacity in the next few years. In the Ten-Year Energy Expansion Plan, onshore wind and solar (including distributed generation) should add 32 GW capacity to the interconnected system through 2032. For instance, distributed generation--which consists of smaller photovoltaic solar projects connected directly in the grid and near the consumer centers--is experiencing a boom since the past few years, thanks to tax incentives.

Brazil reached roughly 25 GW of installed capacity of photovoltaic panels as of November 2023 (against 1 GW in 2019) and is forecast to add an additional 23 GW through 2032. In addition, Congress is currently discussing the regulatory framework for development of offshore wind power, which should add capacity to also drive the increase of renewables in Brazil's energy matrix in the medium term. In light of continued intermittent capacity expansion, we believe Brazil's challenge will be to continue investing in transmission capacity to foster system interconnectivity and improve system reliance.

Chile

The Chilean electricity market is dominated by a hydro-thermal energy mix. This makes it dependent on commodities prices and their availability, as well as dependent on hydro production. Hence, power prices follow a seasonal trend, with lower prices during rainy seasons and higher prices during dry ones. Nonetheless, as the country continues its ambitious energy transition plan toward renewables, inclusion of new renewable energy sources (RES) projects will be a key driver for power prices in Chile. We expect around 6 GW of new capacity in the next three years, of which around 90% will come from solar and wind resources, along with the decommissioning of 1.5 GW of coal plants.

In this context, we expect a decrease in power prices in the medium term as new renewable capacity comes into the system and following our expectations of a decrease in commodities prices for the remainder of 2023 and 2024, compared with 2022.

Finally, due to its geography and concentration in some regions of generation sources and demand, the country depends strongly on its transmission system, which has been relatively limited for years due to the lack of investments in key reinforcements. Therefore, producing price decoupling is occurring in different regions, and there is a significant difference between capture prices and base-load prices. Moreover, we expect this to continue in the short to medium term as new renewable capacity outpace reinforcements in the grid.

Colombia

Power prices in Colombia are mainly set by hydrological conditions, and we expect this to continue in the short to medium term as the 2.4 GW hydro project of Hidroituango starts operating. In this context, power prices in Colombia were low as reservoir levels increase during the La Niña climate event. However, climate events of low precipitation, such as El Niño, are making prices peak, as thermal energy will need to be used because there is no sufficient solar and wind capacity installed to fully cover the needs of the system in case of a dry season.

In the long term, after adding hydro capacity in the system, new nonconventional renewable capacity should cover demand growth, decreasing and stabilizing prices, mainly through the already fostered regulated renewable power auctions and the emerging PPAs scheme. However, significant investments in the transmission system would be needed to avoid intermittencies in the grid.

Mexico

Since we do not expect a significant shift in Mexico's overall electric matrix composition in the next three to five years, we continue to think that fossil fuel prices will remain the main driver for power prices in Mexico, and to a lesser extent, the inclusion of renewable capacity to the system, and overall national and regional demand and supply. In this context, we project power prices in the wholesale market to decline in the next 12 to 24 months as commodities prices decrease to around $40/MWh from an average of $50/MWh in 2022 (see "S&P Global Ratings Lowers Hydrocarbon Price Assumptions On Moderate Demand," June 22, 2023).

We expect renewables nominal capacity will increase about 8 GW by 2026. This will also support the decline in power prices for the upcoming years. However, we don't expect energy prices to plummet significantly as nonconventional renewables enter into the system because baseload plants will offset the increase in renewable capacity, and we project additional gas-fired combined-cycle natural gas plants will likely mostly fill an increase in demand.

Lastly, given the lack of clarity in large investments in the transmission network in Mexico, we expect price gaps between regions to continue and even widen as curtailment risk increases. We think prices for high demand regions (with low energy supply), such as the Yucatan Peninsula, will be significantly higher than average and could increase if transmission bottlenecks arise, and prices will stay low in regions with high renewable energy supply.

Peru

Given that natural gas plays an important role in the Peruvian power system, we forecast commodities prices will remain the main driver of power prices in the country, especially with the construction of the STIGAS pipeline and the conversion of Nepi and Puerto Bravo power plants from oil to natural gas.

Although there is a clear target to achieve certain nonconventional renewable capacity share in the system, recent political turmoil along with low economic growth prospects could dampen investments and additions of solar and wind plants in the next two years. In this context, reaching the expected US$30/MWh optimal price could be delayed even further--in addition, considering a possible delay in transmission infrastructure in Peru.