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Large-scale battery storage capacity on the U.S. electricity grid has steadily increased in recent years, and we expect the trend to continue.1,2 Battery systems have the technical flexibility to perform various applications for the electricity grid. They have fast response times in response to changing power grid conditions and can also store excess generation from the grid, allowing energy from solar or wind resources to be used during the time of highest value, not just when produced. However, the degree to which different applications will drive future battery storage deployment is uncertain.
Our analysis of the economics of future standalone battery storage deployments suggests that combining revenue streams from different applications is important when evaluating future investment decisions. In addition, in some scenarios one application may be a larger economic driver than the other:
Battery storage can provide flexible capacity and energy to the power grid, and can be used in a wide range of applications3 that we categorized into three primary types:
In AEO2022, we model battery storage used in two applications, energy arbitrage and capacity reserve, which represent the primary long term economic opportunities for large-scale deployment of batteries under the conditions generally represented in the AEO Reference case and its side cases. We do not model ancillary services for battery storage, which represent high-value but low-volume markets that are not likely to significantly affect the gross characteristics of the generation and capacity mix for electricity markets as represented in EIA''s AEO projections.
The potential economics of battery storage as modeled for this study include revenue received from energy arbitrage and capacity reserve applications. It is important to note that we expect the U.S. electric power system in 2050 to be very different than today, as represented in the AEO Reference and side cases. System conditions become more favorable for storage over time, particularly with respect to the high incidence of solar generation and how solar interacts with demand.
We assume battery storage participates in the energy market and receives energy payments for generating at the marginal cost of electricity when the facility is dispatched. In our model, the marginal cost of electricity, or marginal generation price, is the cost of meeting demand in a specified period and is typically determined by the variable cost (fuel cost plus variable operation and maintenance, or O&M, cost) of the most expensive generating unit dispatched to satisfy demand.
Standalone energy storage facilities in our model must also purchase electricity from the grid, ideally during low-demand hours, to recharge. In some cases, grid operators may pay the battery project operator for storage to off-load excess generation from the grid (reflected as negative prices). Net revenue for the energy arbitrage application then becomes the difference between the price paid to recharge (positive, free, or negative) and the price received to discharge.
High grid penetration of solar generation can result in zero or negative prices during hours when generation from zero-marginal-cost and inflexible generators exceeds demand and solar generation would otherwise be curtailed. Battery storage uses these hours of excess solar generation and lower electricity prices for charging, generally between the hours of 9:00 a.m. and 5:00 p.m. (Figure 1). As demand increases in the evening and overnight hours, battery storage discharges to capture the benefit of higher electricity prices, usually between 5:00 p.m. and midnight, and in some cases, between midnight and 8:00 a.m.7
When a battery storage unit contributes to the required reserve margin through a capacity market, it receives revenue for its available capacity, which is calculated as a capacity price times a capacity credit.
About United states grid-scale energy storage
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