Alison Ong

Electricity affordability is a salient policy concern in California. We compare drivers of increasing utility costs for three types of power providers in California: investor-owned utilities (IOUs), publicly owned utilities (POUs), and community choice aggregators (CCAs). Since 2019, the IOU and CCA residential baseline electricity rates have increased by 44-80% after accounting for inflation, making them some of the most expensive power providers in the United States. POU prices, however, remained nearly unchanged. We compare long-term trends in capital assets, returns, and operation and maintenance expenses to identify sources of increasing utility costs, one of the factors contributing to rising electricity prices in the state. Across IOUs, generation capital assets have declined. Fuel and power purchase expenses have increased, although these increases remain within their historical ranges. Transmission and distribution (T&D) expenses have increased significantly and are the majority of overall costs. T&D operations and maintenance spiked following major wildfires after years of remaining constant despite an aging and expanding electricity grid. CCAs reach price parity with IOUs due to the high costs of T&D infrastructure and exit fees levied on them. POUs, which service smaller territories with low wildfire risks, also expanded their T&D capital assets, operations, and maintenance expenses, but the increase is modest. We foresee continued price divergence among power providers due to wildfire mitigation costs, which will have important affordability consequences.

An increasing number of corporations have voluntarily implemented climate targets. Some firms announce quantitative climate targets, including net-zero goals; some adopt internal carbon pricing to inform strategy and investment risk; some use both approaches. We study how emissions and financial performance evolve after a firm adopts a quantitative target, compared to performance after a firm adopts a hybrid approach of both a quantitative target and internal carbon price. Using a novel, comprehensive dataset that encompasses all major climate targets for the Russell 3000, we document trends in internal carbon price adoption and resulting implications for firm-level emissions. We find that emissions-intensive firms tend to benefit most from hybrid approaches, and that hybrid approaches yield larger amounts of emissions reductions compared to quantity-goal-only approaches.

Overlapping environmental policies can be net beneficial if they yield additional, cost-effective mitigation. I study this overlap in the Californian context, where aggressive decarbonization regulation exists alongside high participation in voluntary green power providers called Community Choice Aggregators (CCAs). I find that CCAs procure more green power for their customers and exhibit measures of higher willingness-to-pay for decarbonized power. However, CCAs amount to a reshuffling of voluntary greenness rather than additionality at a statewide level, suggesting that while voluntary green power programs can advance participants’ decarbonization goals, overall system benefits can be undermined by dynamic responses to voluntary green participation.

Well-functioning electricity systems require not only the provision of energy but also a range of grid stability products, known as ancillary services (AS). Efficient electricity markets should compensate generators for all value streams they contribute to the grid. However, in practice, markets differ significantly in their approaches to valuing ancillary services. Sometimes, some AS products are presumed to be sufficient without a market mechanism to explicitly procure them. Our study focuses on a system that faced a significant increase in the need to procure a previously unvalued ancillary service product called Primary Frequency Response (PFR). We quantify the costs associated with the chosen policy approach—a blanket mandate requiring all generators to provide PFR—and compare these costs to the potential efficiency gains of implementing a dedicated market for PFR. Our empirical setting is Australia’s National Electricity Market, which is notable for its rapid increase in renewable energy penetration and a physical grid that faces inherent operational challenges due to its large, sparsely interconnected network.

Integrating renewable energy sources into electricity systems introduces challenges such as intermittent power generation. These challenges are not only confined to energy procurement but also impact grid stability, particularly in terms of frequency regulation. When frequency disturbances occur, an immediate (sub-second) power exchange known as an inertial response helps mitigate the rate of change of frequency. Traditional power generators like coal and natural gas plants provide the necessary inertia to dampen frequency changes, but this feature is absent in renewable sources. As renewables increasingly displace fossil fuels, the lack of sufficient inertia becomes a concern for grid operators and policymakers. This study examines the potential of battery energy storage systems in supplying synthetic inertia, offering a fast-responding power injection to mimic traditional generators’ inertial response.

This study quantifies the potential increases in residential natural gas rates associated with building decarbonization approaches under consideration by policy makers in California. We conclude that planned system safety investments and some but not all potential decarbonization policies may pose serious affordability challenges to California consumers over time, exacerbating affordability challenges that already exist for lower income communities and customers. Policy alternatives that affect existing buildings, as opposed to only targeting new construction, result in greater rate increases while also achieving greater emission reductions. Our analysis also suggests that strategically shrinking the size of the natural gas distribution system could be a promising cost- and emissions-mitigation measure that leads to greater emission reductions while moderating rate increases. However, we note that system retirement will require intensive planning and regulatory change in order to execute successfully. Our results highlight the need for a gas transition strategy that involves actively protecting customers from rate increases.