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.

Renewable portfolio standard (RPS) programs are common regulatory tools to stimulate renewable energy procurement. An alternative approach is voluntary green power, where electricity providers procure renewables in quantities that exceed mandated levels. This paper assesses whether voluntary green mechanisms have accelerated decarbonization progress relative to just an RPS. I study the case of California, which is notable for having both an aggressive RPS and high participation in voluntary green power providers. Participation has been facilitated by Community Choice Aggregators (CCAs), publicly-owned retailers who procure power on behalf of their member cities, and who often emphasize environmental sustainability values. I first study the extent to which CCAs successfully procure voluntary green power for their customers, and characterize the community traits most closely correlated with CCA participation. I find that higher income and pro-environmental political attitudes are strong predictors of selection into CCAs; measures of higher willingness-to-pay for decarbonized power among communities also correlate with higher voluntary green procurement. Second, I assess CCAs’ impacts on statewide decarbonization progress. I find that CCAs amount to a reshuffling of voluntary greenness rather than statewide additionality. This is because, prior to large-scale CCA entry, California’s incumbent utilities already engaged in voluntary green procurement. After CCAs began serving a larger proportion of statewide load, stagnation or backsliding in other parts of the sector occurred, such that the state performed 5% above the RPS in 2017 but 0% above it in 2022, while CCA load share grew from 2% to 21% of statewide sales in the same timeframe. Finally, I provide evidence that CCAs’ elevated levels of renewable energy are mostly attributable to resources originally procured on behalf of other incumbents, such that CCAs fare no better than other types of retailers at adding new renewable generators to the system on a per-kWh basis. These findings suggest that the primary effect of voluntary green power is to affect the distribution rather than the overall magnitude of decarbonization.

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.