Energy storage: not so fast
Markets should determine right application, right price
I was among those who reviewed the California Energy Commission's recently released "2020 Strategic Analysis of Energy Storage in California" report, referenced in Phil Carson's column last week, "Energy Storage, EVs and Collaboration." I was listed as an "advisor" to the CEC process that produced the report. In his column, Carson lamented that dissenting views were not published with the report. I'll provide such a view here.
While I agree that storage could be an attractive resource as California pursues the 33 percent renewable portfolio standard (RPS) target, in my view the report is biased toward advocacy and does not give enough weight to several other critical factors.
The first factor is cost-effectiveness. Storage is currently more expensive than competing alternatives, which is a key reason utilities have been reluctant to deploy it. In California's current market environment, low, stable energy prices and low incremental capacity values make it impossible for storage to compete.
Second, it's unlikely that all of the identified economic benefits can actually be realized, particularly for storage projects that are built to time-shift energy. Wholesale electricity markets in the United States are designed around thermal plants whose marginal costs are known with a high degree of precision. Even if day-night price differences are sufficiently large, and it is not certain they will be, the only way a storage device can consistently generate operating profits is by being able to purchase and sell electricity at prices that are known with a fair degree of certainty in any or all of the upcoming 24 hours. Today's wholesale markets provide neither the forward price visibility nor the opportunity to trade on those prices once the day-ahead auction is finished. Having an Independent System Operator (ISO) determine how to operate storage is also not a feasible solution. PJM found that trying to determine an optimal day-ahead operating schedule for a single large storage system in its footprint led to a five-fold increase in computing effort.
Third, subsidized storage may conflict with electric vehicle (EV) deployments. If California policymakers are serious about promoting electric transportation, and if they are also serious about encouraging EV users to charge off-peak, then they should be aware that subsidized storage for time-shifting energy disadvantages EV users in two important ways. First, it will increase competition for access to off-peak energy, which will increase the cost of off-peak charging energy for those EV users who do choose to charge their vehicles at night. Second, EV users will be forced to effectively pay for those subsidies even though they provide many of the same benefits at no cost.
Fourth, the emissions-related impacts of deploying storage need to be better understood and articulated. While it is true that storage devices other than certain compressed air energy storage (CAES) implementations do not emit CO2 or other pollutants directly, their use either increases emissions from other supply resources or drives the need for more renewable production. A pumped storage plant operating at 75 percent efficiency withdraws one third more energy from the grid when charging than it injects back into the grid when it is discharged. If that additional energy is deemed to be supplied by a fossil-fired plant or from imports, then storage operation leads to a corresponding increase in emissions. If the losses are deemed to be supplied by renewable energy, then additional renewable resources must be built because the RPS is tied to retail sales rather than electric production.
Fifth, regulators, policymakers and lawmakers need to realize that the benefits of storage used to time-shift renewable production and to provide longer duration balancing services depend on credible economic signals. Wholesale prices that are low and stable make storage operation economically challenging because revenues from discharging the storage device might not cover the cost of charging energy that includes losses. Overly generous supply margins that minimize the likelihood of politically inconvenient price spikes undermine storage economics and needlessly inflate customer bills.
The report also suggests storage is essential in order to meet the 33 percent RPS by citing a conclusion from an analysis prepared in 2010 by KEMA Corporation. This isn't true. What the KEMA report did say was, "large-scale storage can improve system performance by providing regulation and imbalance energy for ramping or load-following capability. The 3,000 to 4,000 megawatts (MW) range of fast-acting storage with a two-hour duration achieved solid system performance across all renewable penetration scenarios examined."
Storage has a place in modern electric grids, but only in the right applications and at the right price point. The economic burden of market transformation, which is what this report seeks to promote, should be shared more broadly via carefully targeted, federally sponsored research and development efforts that focus on technology improvements and cost reductions, rather than falling solely on California electricity consumers.
Jack Ellis, ME, works as a consultant to the power industry, advising utilities and other stakeholders on a variety of contemporary regulatory and business issues, including the operational impacts of renewable resources, wholesale electricity market design and policy, and demand response policy and implementation.