Luiz Barroso

Political fragmentation continues to block urgently needed power integration in Latin America, despite the region’s vast renewable energy potential. Using the Multiple Streams Approach, this study argues that the escalating climate crisis now acts as a focusing event, aligning a pressing energy problem, viable integration solutions, and growing political will. This alignment signals that a policy window is open. This study combines the Multiple Streams Approach with system modeling to quantify overlooked political costs of inaction, specifically, geopolitical tensions and erosion of trust, offering actionable leverage for policy entrepreneurs. Simulations for 2025–2050 show that continued fragmentation increases system costs by up to 7%, reduces resilience to hydroclimatic shocks, and concentrates benefits within narrow cooperating blocs under low-trust conditions. These measurable and rising costs underscore that regional energy integration is no longer just a technical or economic issue; it is a political imperative. Bold leadership must act now to seize this fleeting window of opportunity.

Political fragmentation continues to block urgently needed power integration in Latin America, despite the region’s vast renewable energy potential. Using the Multiple Streams Approach (MSA), we argue that the escalating climate crisis now acts as a focusing event, aligning a pressing energy problem, viable integration solutions, and growing political will. This alignment signals that a policy window is currently open. We combine MSA with system modeling to quantify overlooked political costs of inaction—specifically, geopolitical tensions and erosion of trust—offering new leverage for policy entrepreneurs. Simulations for 2025–2050 show that continued fragmentation increases system costs by up to 7%, reduces resilience to hydroclimatic shocks, and concentrates benefits within narrow cooperating blocs under low-trust conditions. These measurable and rising costs underscore that regional energy integration is no longer just a technical or economic issue—it is a political imperative. Bold leadership must act now to seize this fleeting window of opportunity.

This article highlights robustness as an essential factor to cope with the ever-increasing levels of uncertainty in generation scheduling under significant renewable energy penetration, as is the case in Brazil and Spain. To that end, robust generation scheduling is framed within the different optimization-based approaches that are available for uncertainty handling. In addition, the suitability of robust optimization to accommodate practical security criteria in generation scheduling is also emphasized. Interestingly, this article points out the existence of an effective algorithm allowing the discovery of critical or so-called umbrella scenarios, which paves the way for the implementation of robust generation scheduling in industry practice.

Since their introduction decades ago, electricity markets have been largely one-sided. In most cases, end users have not even played the role of passive observers of market price fluctuations, they have directly ignored them.

Electricity market liberalization initiatives have swept the world since they were first proposed and thoroughly studied in the 1980s, finding significant buy-in from middle-income countries. Many of these countries embarked in the wave of electricity liberalization in the 1990s following the United Kingdom’s market reform and have, as of today, successfully implemented wholesale competition. Generally speaking, most middle-income countries have interrupted the process before reaching full retail liberalization, and thus consumer choice is still mostly restricted to industries. The technological and social advances of decarbonization, decentralization, and digitalization have brought back the full retail liberalization agenda so that consumers can be empowered to freely select their own supplier, type of energy, and hence be active players in the power market.

In recent years electricity sectors worldwide have undergone major transformations, referred to as the “energy transition”. This has required energy planning to quickly adapt to provide useful inputs to the regulation activity so that a cost-effective electricity market emerges to facilitate the integration of renewables. This paper analyzes the role of system planning and regulations on two specific elements in the energy market design: the concept of firm capacity and the presence of distributed energy resources, both of which can be influenced by regulation. We assess the total cost of different regulatory mechanisms in the Brazilian and Mexican systems using optimization tools to determine optimal long-term expansion for a given regulatory framework. In particular, we quantitatively analyze the role of the current regulation in the total cost of these two electricity systems when compared to a reference “efficient” energy planning scenario that adopts standard cost-minimization principles and that is well suited to the most relevant features of the new energy transformation scenario. We show that two very common features of regulatory designs that can lead to distortions are: (i) renewables commonly having a lower “perceived cost” under the current regulations, either due to direct incentives such as tax breaks or due to indirect access to more attractive contracts or financing conditions; and (ii) requirements for reliability are often defined more conservatively than they should be, overstating the hardships imposed by renewable generation on the existing system and underestimating their potential to form portfolios.

The main challenge with the penetration of variable renewable energy (VRE) in thermal-dominated systems has been the increase in the need for operating reserves, relying on dispatchable and flexible resources. In the case of hydro-dominated systems, the cost-effective flexibility provided by hydro-plants facilitates the penetration of VRE, but the compounded production variability of these resources challenges the integration of baseload gas-fired plants. The Brazilian power system illustrates this situation, in which the development of large associated gas fields economically depends on the operation of gas-fired plants. Given the current competitiveness of VRE, a natural question is the economic value and tradeoffs for expanding the system opting between baseload gas-fired generation and VRE in an already flexible hydropower system. This paper presents a methodology based on a multi-stage and stochastic capacity expansion model to estimate the optimal mix of baseload thermal power plants and VRE additions considering their contributions for security of supply, which includes peak, energy, and operating reserves, which are endogenously defined in a time-varying and sized in a dynamic way as well as adequacy constraints. The presented model calculates the optimal decision plan, allowing for the estimation of the economical tradeoffs between baseload gas and VRE supply considering their value for the required services to the system. This allows for a comparison between the integration costs of these technologies on the same basis, thus helping policymakers and system planners to better decide on the best way to integrate the gas resources in an electricity industry increasingly renewable. A case study based on a real industrial application is presented for the Brazilian power system.

Large reductions in the cost of renewable energy technologies, particularly wind and solar, as well as various instruments used to achieve decarbonization targets (e.g., renewable mandates, renewable auctions, subsidies, and carbon pricing mechanisms) are driving the rapid growth of investments in these generation technologies worldwide.

Decarbonization goals have created a technological revolution that has enabled renewables—in particular, solar and wind generation—to be in the center of most electricity markets all over the world. Renewables are inherently characterized by high production variability combined with limited predictability and controllability, which have created significant flexibility challenges for power systems planning and operations all around the world. Renewables also produce electricity at an almost zero marginal cost. In the presence of high shares of renewables, restructured electricity markets based on setting locational marginal prices will also be challenged, as electricity prices can fall to zero or even negative values if abundant renewable generation is observed. Conversely, prices can rise quickly and may reach high figures if renewables are not producing and scarcity takes place. These effects can be exacerbated in the presence of transmission bottlenecks and high levels of distributed generation.