Alison Ong

A majority of US states have implemented renewable portfolio standard (RPS) programs, regulations that require minimum levels of renewable energy content for electricity providers; many jurisdictions have also introduced forms of voluntary green power, which enable customers to buy renewable power 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 a substantial portion of customers taking service from retail plans containing renewable energy levels in excess of the state’s RPS. This is facilitated by the recent entry of Community Choice Aggregators (CCAs), publicly-owned retailers who procure power on behalf of their member cities, and who often emphasize environmental sustainability values. Using regulatory filings and census data, I estimate a logistic regression model showing that higher income and pro-environment communities tend to join CCAs. I then estimate a second model that shows voluntary green procurement is correlated with community attributes indicating high willingness to pay for decarbonized power. However, CCA voluntary greenness did not translate to greater decarbonization relative to the RPS for the state overall: due to stagnation or backsliding in other parts of the sector, the state average was actually 1% below the soft target of 35.75% in 2021. Within CCAs, the high level of voluntary greenness exhibited by wealthier or larger CCAs does not translate to less wealthy or smaller CCAs. In addition, 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.

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 & maintenance expenses to identify sources of increasing utility costs contributing to rising electricity prices in the state. Across IOUs, generation capital assets have declined, and fuel and power purchase expenses have increased but are within historical ranges. Transmission and distribution (T&D) expenses have increased significantly and are the majority of overall costs. T&D operations and maintenance spiked post 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 they share and exit fees levied on them. POUs, servicing 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.

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.