Conference Agenda

As power systems across the world transition to being powered by renewables, many are seeing a shortfall in stability services, a broad basket of services that keep the power system within its engineering limits. To combat this shortfall, many jurisdictions are making investments to displace provision of stability from fossil-fueled generators. These investments are predicated on the high sticker price of status quo provision. This paper analyzes the provision of stability services in South Australia, a region in Australia’s National Electricity Market that has seen high-cost investments to provide stability service.

I find that, while the sticker price of provision of stability from generators is high, the economic costs are low, limiting the potential for efficient investment in infrastructure that provide stability services. As part of estimating the costs of provision, I also introduce a novel method of estimating the costs of operating electricity generators with information revealed from market offers.

Abstract Utility-scale batteries play an increasingly active role in electricity markets by arbitraging energy across time, yet their efficiency depends critically on market design. This paper studies a prevalent feature of real-time electricity auctions: bid lead time, which requires batteries to commit bids in advance of dispatch. Using comprehensive 15-minute bidding and settlement data for all utility-scale batteries in ERCOT from 2018–2025, we document active dynamic bidding, rapid responses to price shocks, and the importance of recent price information for forecasting. We develop an equilibrium model of electricity markets with dynamic battery bidding and show that longer bid lead times substantially reduce operational efficiency and profits, and dampen complementarity between batteries and renewable energy. Allowing bids to depend on state of charge significantly mitigates these losses. Our results highlight bid lead time as a key determinant of battery performance and market outcomes.

We investigate the optimal design of CO$_2$ taxation policies along with renewable energy de-risking instruments in the context of decarbonizing power sectors that are subject to investment risk. We develop a multi-stage stochastic equilibrium model that captures endogenous investment decisions regarding production and storage assets. Some market fundamentals, such as demand, prices, and production profiles, are risky. Furthermore, investors are risk-averse and the financial market is incomplete inasmuch as it lacks sufficient risk-sharing instruments. The model integrates economic and environmental incentives through a multi-objective framework based on social welfare and emissions, allowing for the characterization of the \textit{Pareto-optimal frontier} for de-risking/emissions-taxation policies. We apply the model to the French power system, considering a diverse mix of generation and storage technologies. Our results show that de-risking instruments and CO$_2$ taxes are imperfect substitutes and must be optimized \textit{jointly} to avoid suboptimal outcomes\textemdash such as over-investment in renewable production, market distortions induced by excessive de-risking, or insufficient emissions reductions. Furthermore, we demonstrate that commonly used de-risking instruments in Europe may lead to spot-market inefficiencies and welfare losses. Our findings provide actionable policy guidance by identifying optimal de-risking/emissions-taxation combinations and quantifying the performance gap in current European policies relative to the Pareto frontier.

This study quantifies the effect of rooftop solar generation on the electricity distribution system using unique, proprietary data on solar generation and infrastructure load. We find that an additional kilowatt (kW) of solar reduces the annual peak load on a main feeder line coming from a substation by 0.10 kW and the top percentile of feeder load by 0.11 kW. We also estimate a 6.1% solar rebound effect, primarily occurring in spring and fall. The value of deferred distribution capacity ranges from $0.2 to $2.3 per MWh, well below the cost premium of rooftop solar above utility-scale solar.