CS27: Energy Economics and Modeling

Medium-Sized Systems in Chile are isolated power systems located in the southern regions of the country, with installed capacity ranging from 1.5 to 200 MW. Economies of scale lead these systems to operate as natural monopolies, with vertically integrated generation and transmission under centralized expansion planning and regulated tariffs.
Geographic isolation and severe climatic conditions have resulted in a strong dependence on natural gas for both heating and electricity generation. In the Magallanes Region, gas prices are subsidized by the Ministry of Energy and the state-owned company ENAP, which supplies gas in the region. The subsidy represents 53% of production costs, distorting the price signals faced by consumers and generators. These signals shape not only dispatch but also long-run investment decisions, as the subsidized fuel price constitutes the reference cost in the centralized expansion planning framework.
This paper examines the impact of the gas subsidy on long-term expansion planning, and the resulting generation mix in the Medium-Sized Systems of Magallanes. The analysis focuses on ENAP, the only gas supplier in the region, which developed a wind project in Punta Arenas. The project sought to displace gas-fired generation, reduce ENAP's gas sales to the power sector, and limit its exposure to the subsidy mechanism.
The methodology relies on an optimal expansion model that minimizes investment, operating, and unserved energy costs over a 15-year planning horizon, subject to demand and operational constraints. Scenarios with and without the gas subsidy are compared to assess impacts on technology adoption and regulated end-user tariffs.
Results indicate that the gas subsidy acts as a barrier to renewable integration by distorting fuel price signals. Internalizing the true cost of gas makes renewable generation cost-effective, suggesting that gradual subsidy reform could improve efficiency and facilitate transition in Chile's Medium-Sized Systems.

Electricity system reliability is a key determinant of economic performance, social welfare and the credibility of electrification strategies. As power systems become more complex and interconnected, large-scale blackouts increasingly represent economy-wide shocks whose impacts depend on sectoral structure, regional exposure and production networks. This paper determines the Value of Lost Load (VoLL) through a systemic framework and applies it to estimate the macroeconomic cost of the nationwide blackout that affected Chile's National Electric System (SEN) on 25 February 2025.
Sector-specific VoLL values are calculated using value-added and electricity consumption data combined with detailed records of unserved energy across economic activities. To capture propagation mechanisms, we apply an input–output matrix methodology to estimate both direct sectoral losses and indirect effects transmitted through intersectoral production linkages. This approach allows consistent measurement of how supply disruptions propagate across production chains and identifies economically central sectors whose electricity dependence generates amplified systemic effects. The framework also highlights geographical heterogeneity in blackout exposure, reflecting regional differences in demand structure and sectoral concentration.
The blackout interrupted 81.43 GWh of electricity and generated an estimated direct economic cost of approximately USD 984.2 million. Results reveal substantial sectoral heterogeneity in VoLL, ranging from very low values in energy-intensive sectors such as mining to very high values in service-oriented and high value-added sectors including business services, finance and construction. Once network effects are incorporated, these sectors exhibit disproportionately large systemic impacts. Regulated non-residential customers account for nearly half of total losses.
This integrated sectoral and network-based framework provides a unified methodology to measure the full economic cost of electricity supply disruptions and informs resilience planning and infrastructure investment decisions.

 
Net-zero transition modelling studies often do not adequately account for the critical minerals required for large-scale deployment of battery technologies. This paper addresses this gap by explicitly incorporating critical mineral availability within an integrated energy system optimization framework and assesses its implications on the net-zero ambition trajectory for India.
The analysis uses the KINESYS-TIMES model, representing electricity, mobility, industry, and residential and commercial sectors within a unified, inter-temporal cost-minimization whole energy system framework that endogenously determines technology deployment under policy ambitions. A Reference scenario and a Net-zero by 2070 scenario are developed, with lithium-constrained variants that limit the material availability to fixed shares of unconstrained net-zero demand. 
Battery-related mineral requirements are derived from modeled technology deployment using time-varying life-cycle intensity coefficients. The integrated framework captures interactions between transport electrification, electricity generation expansion, and cross-sectoral technology substitution, allowing mineral constraints to propagate endogenously through the energy system rather than being treated as an external sensitivity.
In the Net-Zero scenario, electricity consumption in the transport sector reaches 5,000 PJ by 2070. The rapid transition in transport electrification is coincident with accelerated growth in battery-related mineral demand, especially after 2040. Lithium demand grows from 36.8 kt in 2030 to 678.9 kt in 2070, mostly due to passenger and commercial vehicle electrification. With lithium availability limited to 60% of unconstrained demand, the pace of electric vehicle adoption is reduced, and hydrogen transport gains market share. For the 30% availability scenario, the electricity transport sector share remains below 30% by 2070, and system costs increase as the model shifts towards more battery-averse alternatives.
The research findings by integrating critical mineral limits within energy system optimization enhance the realism and robustness of long-term decarbonization pathways, particularly for import-dependent emerging economies.

This study provides novel evidence on what we call the "hardship trilemma" regarding difficult choices of heating, eating or moving faced by New Zealand households. Using six triennial rounds of the household-level survey, we estimate three pairwise expenditure nexus across energy, food, and transport through the three-stage least squares (3SLS) method. Our estimates reveal that a 1% increase in electricity price relative to food price raises household energy expenditure by 0.56% and reduces food spending by 0.51%, while a 1% increase in electricity prices relative to transport price lowers mobility expenditure by 0.35%. We do not find evidence of a trade-off between food and transport. These adjustments are pronounced among low-income households, while expenditure responses by ethnic group are directionally consistent yet statistically insignificant. Given the unique nature of New Zealand's electricity market (i.e., renewables account for more than 90% of gross electricity generation), we also consider the moderating role played by dry years in the underlying trade-offs. Interestingly, the trade-offs intensify during dry years, when low hydro inflows raise generation costs and retail electricity prices. Our findings suggest that environmental variability and market conditions jointly affect difficult household choices and welfare, highlighting the social desirability of coordinated policies that enhance energy affordability without compromising nutrition or mobility in New Zealand.