The most significant barrier for the utility-scale battery industry is accurately valuing the multitude of services that batteries provide to the grid. Utility-scale batteries do not generate electricity or direct revenue. However, the efficiency, resiliency, transmission, and other valuable ancillary services they do offer are not typically assigned a dollar value. Instead, single metrics are used, which fail to account for the wide array of benefits that batteries provide. In the past five years, new federal and regional policies have updated electricity market structures, which allow utilities to monetize the benefits of energy storage. As a result, battery markets are growing rapidly in some regions.
The utilities located in the PJM Interconnection have become national leaders in energy storage due to PJM’s early adoption of an energy storage valuation methodology. In 2014, approximately two-thirds of all energy storage installed in the United States was located in the PJM territory. This success is due to PJM’s quick implementation of FERC’s Order 755, which creates a market for frequency regulation with a pay for performance premium for storage. As part of a larger mission to formally define the revenue streams for energy storage at the federal level, FERC has issued several orders to create fair treatment (Orders 1000 and 792) and proper compensation (Orders 755 and 784) for energy storage assets. Moving forward, utilities within PJM are planning to increase their investments in energy storage: more than 500 megawatts (MW) of storage are in the pipeline, five times the amount currently installed.
Oregon’s lawmakers recently passed legislation (HB 2193) that requires the utilities commission to create valuation guidelines that include all the benefits of storage. The law states that each of the following parameters should be included: (1) deferred investment in electricity generation, transmission, or distribution, (2) reduced need for supply during peak demand, (3) improved reliability of transmission systems, (4) improved integration of renewables, (5) reduced greenhouse gas emissions, and (6) reduced portfolio variable power costs. Additionally, public utilities are required to procure at least one energy storage system capable of storing 5 megawatts per hour by 2020. The utilities may recover all costs (including above-market costs) incurred in the procurement through rates.
Using lessons learned from other states, state legislators could direct the state public utilities commission to establish a proper valuation method for the use of utility-scale batteries. To do this, the commission could use FERC’s orders and resources developed by industry experts as guides. Given the complexity of energy storage, the commission could actively engage industry experts to assist in this process.
With a new valuation method, a state’s utilities commission could determine whether adding utility-scale batteries to the in-state grid is economically and technically feasible. If deemed feasible, the commission could require that utilities include utility-scale batteries in their Integrated Resource Plans (IRPs). The IRP process would demonstrate the use-cases where batteries are a more cost-effective investment than other resources. The commission could also issue specific guidelines for utilities to request permission to deploy batteries outside of the IRP process. By establishing a valuation model for batteries, policymakers could send a market signal to utility-scale battery manufacturers that the state is ripe for investment.