The existing power grid has not fundamentally changed in 100 years: it is still organized around big central generating plants and one-way flows of electricity, with instantaneous balancing of generation with consumption.
Consider the implications of that last sentence. In our society, we store every other critical commodity—food, water, fuel, heat, raw materials—but we have little to no capacity to store electricity. Because of this, production of electricity must be adjusted to exactly equal demand every second of every day. In other words, without storage, the electric grid is the world’s biggest just-in-time delivery system.
This has enormous consequences for the overall efficiency of the power grid. Without the ability to store electricity, generation and transmission assets must be sized to meet demand peaks that only occur a few times each year. This means that our current systems are enormously overbuilt, and ratepayers pay for this inefficiency.
According to the State of Charge report issued in 2016 by the state of Massachusetts, from 2013 to 2015, the top 10 percent of hours of demand for electricity generation, on average, accounted for 40 percent of the state’s annual electricity spending, or over $3 billion (1).
In other words, nearly half the cost of the electricity system is devoted to meeting demand peaks that occur only a small portion of the time. This is not only a problem in Massachusetts, but in other parts of the country as well.
To understand why this is so, it is important to realize that many fossil-fueled electricity generators are paid when they are not actually generating power. These “peaker” plants, typically small plants fueled by natural gas, command high prices to be on standby in case demand for electricity should spike.
This makes gas peakers among the most expensive generators of electricity; they are also highly polluting.
The name for this “standby” power is “capacity.” In areas with organized wholesale electricity markets, capacity is among the most expensive services utilities must purchase (and these costs are passed along to ratepayers). In New England, the cost of capacity tripled in two years, from $3.15/kW-month in 2016–2017, to $9.55/kW-month in 2018–2019.
According to ISO-New England, the annual cost of capacity paid by New England ratepayers will increase accordingly, “from a historical annual average of about $1.2 billion . . . to a projected annual average of about $3.1 billion from June 2017 through May 2021” (2).
Along with capacity, utilities must pay for transmission—the poles and wires that allow electricity to travel from the generator to the customer. Just like a water hose, a transmission line can only carry so much electricity at once. If transmission is not sufficient to meet demand, it is said to be “constrained.” Transmission constraints can keep power generated upstream from reaching customers who need it downstream.
Capacity and transmission costs together are the equivalent, for utilities, of demand charges for commercial customers. And, like demand charges on a commercial customer’s bill, they can be managed with energy storage.
In ISO and RTO markets, utilities pay annual capacity charges, often based on a single regional peak-demand hour each year. And they pay transmission charges, often based on a single regional peak-demand hour each month. By keeping their power purchases low during these 12 critical hours each month, utilities can reduce capacity and transmission costs for the entire year. Energy storage is a perfect technology to provide this service, because it can store electricity to be used during peak demand spikes.
This has been demonstrated by the Sterling Municipal Light Department (SMLD) in Sterling, Massachusetts (3). The SMLD had seen the cost of capacity and transmission rise from $500,000 in 2010 to $1.2 million in 2017. Facing further steep increases as capacity costs were about to triple, the utility installed a battery storage system at one of its substations to hold costs down (4).
Sterling’s battery storage system is now saving the municipal utility nearly $400,000/year, meaning the system, which cost $2.5 million, will pay itself off in just over six years—in only 2.5 years, if state and federal grants are counted against system costs (5).
This is mostly due to capacity and transmission cost savings, but the utility is also using its battery system to engage in arbitrage—buying grid power when it is cheapest, for example at night, and using it to offset purchases of more expensive power during the day.
In addition to lowering costs for its municipal ratepayers, the Sterling battery system is helping the utility integrate its large solar resource and providing backup power to the town’s police station and emergency dispatch center. On the regional grid, Sterling’s energy storage system helps to flatten the New England demand curve for electricity, making the grid more efficient for all.
These results have been replicated by other New England utilities and confirmed by a Sandia National Laboratories study (6). Sandia concluded that Sterling exemplified the best known economic case for battery storage in the nation.
The Sterling example illustrates a fundamental fact about energy storage: its highest value lies in the provision of capacity, not energy. In most markets today, efforts to deploy energy storage should focus primarily on capacity services, like demand charge management and frequency regulation, rather than energy services, like arbitrage and reductions in generation curtailment. The latter can be important added services in a storage benefit stack but are unlikely to make up the core services that storage provides to pay its way, at least in the foreseeable future.