CS36: Grids, Storage and Infrastructure for Renewable Integration

The impacts of coal power retirement on water resources have been widely examined in the context of carbon neutrality. However, existing studies primarily focus on retirement scale or technology substitution, with limited attention to how retirement sequencing as a structural decision variable may generate differentiated water outcomes. Given the substantial heterogeneity in cooling technologies, plant scale, geographic location, and basin-level water endowments, different sequencing strategies may lead to significantly different regional water stress even under identical total retirement volumes.
This study integrates the GCAM-China integrated assessment model with plant-level operational data and basin-scale hydrological information to construct multiple retirement sequencing mechanisms under consistent retirement scale constraints. We dynamically simulate carbon emissions and water withdrawal from 2020 to 2060 to assess the spatiotemporal evolution of carbon–water interactions.
Results indicate that, holding total retirement capacity constant, alternative sequencing mechanisms can generate regional water withdrawal differences of 20%–35%, particularly in water-constrained basins. Carbon emissions and water withdrawal exhibit temporal divergence during the transition process, suggesting that low-carbon pathways do not necessarily minimize water risks. Furthermore, CCS deployment may reduce emissions while increasing water withdrawal during transitional periods, exacerbating local water pressure.
These findings highlight that coal phase-out is not solely a question of scale reduction but also of sequencing design. Ignoring plant heterogeneity and spatial variation may underestimate water-related risks in energy transition planning.

Rate-regulated utilities must continuously invest in long-lived infrastructure while operating under regulatory frameworks designed for stable or growing markets. How should regulators evaluate utility investment when demand is uncertain and structural transitions, such as electrification, decarbonization, distributed generation, threaten to strand existing assets?
This paper develops a tractable heuristic model combining stock-flow dynamics incorporating investment theory to analyze infrastructure investment, extraordinary cost recovery, and stranded asset risk in regulated industries. We model how household demand, infrastructure stocks, and regulatory rate-setting interact to determine equilibrium outcomes. We integrate cost of capital decisions to derive a closed-form benchmark investment rate, a function of the capital share, demand growth, depreciation, and the weighted-average cost of capital. The model also includes a graphical representations allowing regulators to assess whether utility capital expenditure is aligned with long-run economic fundamentals.
Our analysis reveals a fundamental asymmetry: positive demand shocks are accommodated smoothly through capacity expansion, while negative demand shocks can trigger instability through a feedback loop of rising average costs and customer attrition. We show that equilibrium stability requires inelastic demand; when price elasticity exceeds unity, the regulatory equilibrium breaks down entirely. We calibrate the model using realistic parameters for electricity and natural gas distribution utilities and demonstrate how different cost recovery methods, including immediate pass-through, amortization, rate base inclusion, securitization, and deferral. Each of these mechanisms affect the benchmark investment rate and stranding risk.
These findings carry direct implications for energy regulators navigating the energy transition. The benchmark investment rate provides a transparent tool for identifying over- or under-investment. The graphical framework enables scenario analysis accessible to non-technical stakeholders. Our results support accelerated depreciation, managed network contraction, and forward-looking regulatory approaches to equitably manage stranded asset risk.

High rates of renewable energy curtailment, an undesirable phenomenon, can become an opportunity to promote regional electricity integration in South America and expand this experience to the rest of the world that does not have power interconnection systems. The so-called energy transition, whose origin is largely explained by climate change postulates, has focused almost exclusively on changing the energy matrix, attempting to move from the use of fossil fuels for electricity generation to the use and development of renewable energy generation, but always with the focus on the generation segment. On the other hand, the electricity transmission has been the great forgotten factor in this discussion, which is strategically misguided, as a diversified matrix with high penetration of renewables requires a strengthening of transmission networks. 


The lack of capacity in electricity transmission networks in several South American countries, coupled with the high penetration of renewables, has caused a very significant increase in the curtailment rate, which represents an inefficiency from the point of view of economic load dispatch. The necessary and urgent investment in increasing transmission capacity that this problem generates represents a unique opportunity for countries in the region to consider strengthening regulatory frameworks that promote regional, cross-border electrical interconnection, so that energy that cannot be injected into one country's electrical system can be injected into another, with all the economic and social consequences that the phenomenon of power interconnection brings with it. There are organizations and institutions in the region that have historically promoted regional electricity integration (OLACDE, SINEA, SIESUR, among others), which must continue to support the creation of internal regulatory frameworks in countries to promote electricity interconnections, thus reducing the harmful effects of curtailment and making better use of electrical energy in the respective jurisdictions.

Under the guidance of the "dual carbon" goals, promoting renewable energy development to advance the transition of the energy structure has become a core strategic pathway for China's sustainable development. However, the continuous integration of a high share of renewable energy into the grid-characterized by inherent intermittency and volatility-poses significant challenges to the secure and stable operation of power systems, while digital technology innovation offers critical technical support to address these challenges. Using provincial grid panel data for 31 Chinese provinces from 2008 to 2022, this study employs a Spatial Durbin Stochastic Frontier Model to empirically examine the effects and mechanisms of high renewable energy penetration and digital technology innovation on provincial power grid service efficiency, and further tests their spatial spillover effects. The results show that: (1) high renewable energy penetration not only directly suppresses local grid service efficiency, but also reduces the efficiency of grids in electrically interconnected regions through spatial spillovers; by contrast, digital technology innovation enhances local grid service efficiency and positively drives efficiency improvements in other regions via power network linkages. (2) Digital technology innovation significantly mitigates the adverse impact of high renewable energy penetration on grid service efficiency, further analysis indicates that the moderating effect of the breadth of digital technology use is more pronounced than that of usage depth. (3) Heterogeneity analysis reveals that the mitigating effect of digital technology innovation is stronger in electricity-importing provinces and in provinces with more abundant wind energy resources. These findings provide empirical evidence for formulating differentiated regional grid development policies, highlighting that effective strategies should be grounded in spatial interdependencies and promote coordinated digital technology innovation among electrically interconnected provinces to address both the direct and indirect impacts of high renewable energy penetration.

Coal power and energy storage play critical roles in mitigating power supply-demand imbalances. However, climate change exacerbates the volatility of load and renewable energy output, intensifying the dynamics of these imbalances and potentially increasing economic losses. This study integrates the CMIP6 climate model with the SWITCH-China provincial electricity system optimization model to explore the spatiotemporal evolution of flexibility demand under various climate scenarios and to compare the cost-effectiveness of energy storage and coal power flexibility. The results show that climate change, by increasing high-temperature events and amplifying fluctuations in load and wind-solar generation, significantly impacts flexibility demand. To meet China's 2060 carbon neutrality goal, non-fossil generation must exceed 90%, requiring an additional 1,000–1,500 GW of flexibility capacity. Short-term ramping demand grows faster than daily peak shaving demand, while seasonal energy imbalances decline in some regions. With coal power flexibility retrofits, total flexibility supply costs decrease by about 10% relative to the baseline scenario, primarily addressing peak shaving. In contrast, energy storage, with varying cost reductions, leads to a 20%-30% decrease in total flexibility supply costs, mainly covering ramping and energy imbalance needs. Moreover, in low-emission scenarios (SSP1-2.6), energy storage in provinces with abundant solar resources but insufficient local power supply alleviates supply-demand imbalances and reduces flexibility supply costs compared to high-emission scenarios (SSP5-8.5). This study highlights that, under increasing volatility and rapid demand for flexibility, energy storage provides more efficient and cost-effective flexibility regulation than coal power, making it crucial for designing decarbonized, climate-resilient power systems.