Energy storage is expected to play a key role globally in the transition to low-carbon energy sectors by facilitating a smoother integration of renewable generation into the grid. Maintaining the power balance in the transmission grid will become a challenge in regions with expected high penetration of renewable distributed generation, as well as in states that have committed to ambitious carbon-reduction targets. Intermittent generation exacerbates net load variability, which traditionally has been addressed by flexible generation such as natural gas combustion units, dispatchable demand response, or pumped-hydroelectric energy storage. Recent improvements in technology have strengthened the business case for using electrochemical battery storage to address net load variability. Battery storage is a fast start-up resource that adds flexibility to the system by providing unique ramping capability. With the right financial incentives, battery storage will be charged during low-load conditions, absorbing excess generation from renewable resources. It then may be discharged at peak times, lowering the risk of energy shortages and subsequently high market prices in those hours. Energy storage also may potentially replace the addition of new peaking gas-based generation units. In the United States, state wide energy storage adoption targets have been mandated in California, New Jersey, New York, Massachusetts, Oregon, and Washington D.C., and other states also are beginning to consider energy storage in their resource plans.
Battery storage may be sited anywhere in the transmission and distribution systems, either directly connected to the network (front-of-the-meter) or sited on the customer premises (behind-the-meter) and paired to a rooftop solar facility. Utilities can play a crucial role in providing transparency to customers and third-party storage developers as to when and where deploying a storage solution may be beneficial to the distribution grid. Utilities also will need to develop pricing frameworks that incentivize these customers and third-party storage developers to provide their storage services to the grid. Further, to fully unlock the value of battery storage, rules should be put in place to better enable participation of stand-alone storage, as well as of aggregated small-scale storage systems, in wholesale capacity, energy, and ancillary services markets. The Federal Energy Regulatory Commission (FERC) has requested Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) to make any required changes to their tariffs and regulations to fulfill this goal. In this effort, special attention should be given to the implications of incorporating any storage resources that currently are funded by clean energy policies. In particular, a key goal is to ensure that the wholesale capacity market continues to send accurate price signals of the cost of new entry to avoid distortions.
Ideally, pricing frameworks for energy storage services should be comparable to those of other distributed energy resources (DERs). Payments should reflect how effectively energy storage is able to perform specific services and deliver specific incremental cost savings to the grid. One approach is for utilities to hold direct procurement of DERs through Non-Wires Alternatives (NWA) solicitations, to address identified distribution upgrade needs at specific congested substations or feeders. NWA solicitations may include energy efficiency, distributed generation, and/or energy storage. Payment for storage contracted through NWA solicitations should align with any wholesale, grid, or environmental benefits effectively provided to the utility, in order to provide costs savings over traditional solutions. The utility will be able to fully account for storage as a capacity resource, particularly if it has dispatch rights or has enforced penalty provisions for underperformance. If energy storage resources procured through NWA solicitations wish to participate directly in the wholesale market, the NWA contract payments should avoid duplicity of compensation for the same services. A clear allocation of dispatch rights among the utility and ISO or RTO will be important to ensure optimization of energy storage deployment for both the bulk and distribution systems.
NWA solicitations are not the only possible approach. Mass adoption of small-scale energy storage will be dependent on additional incentives provided through regulated price mechanisms, in principle involving both base electricity rates and export tariffs or rebates. Currently, net metering is the predominant compensation method for rooftop solar generation, and it is not well equipped to properly incentivize battery storage. For example, regulated delivery rate structures often are constrained for reasons other than economic efficiency goals, limiting the ability for volumetric charges to reflect the value of peak-shaving that may be enabled by storage resources and other DERs. As a result, net metering may render suboptimal adoption of energy storage. Enhanced tariff-based mechanisms, in place of net metering, can alleviate these issues by uncovering the economic value stack associated with load reductions or energy injections to the grid throughout the day. For optimal deployment of storage, a tariff-based framework should: 1) reflect marginal cost savings consistent with utility investment needs and peak load projections over the planning cycle; 2) recognize storage’s actual performance during critical peak hours with the tightest capacity conditions; 3) price differently by distribution area if needed, reflecting the higher value of storage in constrained locations; and 4) provide sufficient granularity so that aspects such as different durations of battery storage are implicitly considered.
While the objectives of an energy storage compensatory framework may generally be agreed upon, in practice there are a number of practical challenges. Regulators need to ensure that economically-efficient inducing price signals are put in place so that storage is compensated based on on-going and quantifiable marginal costs. Any interim subsidy provided to support early or accelerated development of storage or other DERs should be fully transparent in order to ensure that market participants and consumers anticipate the implications on future project returns as the subsidy phases out.