UTILITY MARKETS: EMERGING ROLE OF LARGE-SCALE ENERGY STORAGE SYSTEMS
“Energy storage is the next step for our industry. We’ve been doing one thing for a hundred years, it’s time to do something different.” Sean Hamilton, General Manager, Sterling Municipal Light Department
Without energy storage, generation and transmission must be overbuilt to accommodate rare demand peaks and maintain grid stability while integrating high volumes of variable resources like solar and wind. Energy storage can help to solve these problems, while providing valuable grid services as a least-cost alternative that pays for itself. These benefits can be provided by batteries installed behind customer meters as well as on utility distribution grids.
Updated July 2018.
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.
It’s important to understand that utilities need not own the energy storage resource, as in the Sterling example, to get these results; utilities can contract with third-party storage owners to purchase battery services. In fact, the batteries need not even sit on the utility side of the meter.
Similar results can be obtained by allowing utilities (or resource aggregation companies) to remotely access smaller batteries in customers’ homes and commercial properties.
This has been demonstrated by Green Mountain Power in Vermont and by Southern California Edison in California, both of which have customer-sited battery programs (7). And it has been shown that siting storage behind the customer’s meter allows it to provide a greater variety of services and benefits than siting it on utility substations (8).
For example, in the summer of 2018, when record-breaking heat waves hit the Northeast, it was reported that Green Mountain Power had saved up to $500,000 in one week through the use of battery storage, by avoiding power purchases during peak pricing (annual capacity peaks in New England typically occur during the hottest days of the year ). GMP achieved this through dispatching two utility-scale batteries, which it owns and operates, along with some 500 Tesla Powerwalls, which it has placed behind residential customer meters. By aggregating many smaller, distributed batteries, GMP was able to achieve the same cost savings as it gained from operating its two big, centrally located batteries – and those small, distributed batteries are also able to provide resilient power services by supporting customers’ critical loads in case of a grid outage.
Similarly, utility-scale storage services can be provided to utilities by independent third parties, just as merchant generators sell electricity onto the grid. This is important, because merchant energy storage providers can offer many services, and often these services can be “stacked,” meaning that battery owners can sell various services into various markets.
Thus, an independent storage provider might sell capacity reduction services to a utility, resiliency services to a large commercial/industrial customer, and frequency regulation services to the grid operator. Stacking services this way makes energy storage more economical, and more beneficial to society.
Energy storage can also take the place of expensive utility equipment upgrades. This is known as “T&D (transmission and distribution) Deferral,” and it can save enormous amounts of money. As an example, in 2016–2017, Con Edison in New York was faced with the need to replace a substation, at a cost of $1.2 billion. Instead, the company developed the Brooklyn-Queens Demand Management project, a combination of battery storage, demand response and distributed resources that together rendered the new substation unnecessary. The cost of all these advanced technologies and distributed resources was $200 million, one-sixth the price of the planned substation—and the distributed resources will provide more benefits.
In addition to its many other services and benefits, energy storage can provide ancillary services to the grid. These are electricity services, such as frequency regulation, that are needed to keep the grid stable. Many electricity services markets have historically been closed to independent and distributed providers, but some have been opened by the Federal Energy Regulatory Commission (FERC). For example, in 2012, FERC order 755 required grid operators to pay faster, more accurate providers of frequency regulation a premium for their service (9). This created a temporary but significant market for grid scale energy storage in PJM, the wholesale electricity market that serves the northern mid-Atlantic region, with the result that more than 265 MW of grid-connected storage were installed there in just a few years.
At this writing, a new FERC order (Order 841) directs grid operators to revise all wholesale energy services market rules to make these markets accessible to energy storage, taking the operational attributes of storage into account. Once these market rules are updated, storage developers will gain access to a much broader array of markets in those areas of the country where grids operate under FERC jurisdiction (10). However, large regions of the nation do not have regulated markets of this type, and in these areas, it is difficult for storage to sell such services (and it can be difficult even to determine what such services would be worth).
Utilities, especially municipal utilities and electric co-ops, should be encouraged to consider energy storage as a cost-saving alternative to more expensive and polluting technologies. This can be achieved in various ways—for example, through the IRP process or via regulation for regulated utilities, or through state grants and incentives.
Policymakers and regulators should mandate that regulated utilities acquire storage as an asset to reduce grid congestion and peak pricing. Such a mandate has been successful in California, which now has the largest storage market in the country (11).
Policymakers must ensure that the ownership, attributes, and benefits of energy storage are shared with consumers and utility customers; investor-owned utilities should not be the only owners and beneficiaries of storage systems. Where utility procurement of energy storage is required, as in California, there should be a cap on utility ownership and a carve-out for behind-the-meter systems to create competitive markets with third-party providers. And in any such policy efforts, customers must be able to interconnect behind-the-meter (BTM) storage systems in a non-discriminatory fashion with utilities and realize the economic benefits. Advocates will need to step in to fight this battle on behalf of consumers.
Independent grid operators should open wholesale electricity services markets to energy storage, as required by FERC Order 841. This includes behind-the-meter and third-party systems. And, FERC should go a step further and require that aggregated distributed storage be made eligible for participation in energy markets—something Order 841 does not do. While energy storage is not explicitly barred from participating in many energy markets, specifications such as resource performance requirements can effectively make it impossible for storage systems to qualify. As stated by the outgoing head of GTM Research, “Energy storage doesn’t need big subsidies. It just needs to be eligible to compete” (12).
(1) State of Massachusetts, “State of Charge, Massachusetts Energy Storage Initiative,” February 2016, www.mass.gov/eea/docs/doer/state-of-charge-report.pdf.
(2) ISO New England, “ISO New England’s Internal Market Monitor 2016 Annual Markets Report.” May 30, 2017, www.iso-ne.com/static-assets/documents/2017/05/annual_markets_report_2016.pdf.
(3) Clean Energy Group, “Sterling Municipal Light Department Energy Storage System,” Featured Resilient Power Installations, August 25, 2017, www.cleanegroup.org/ceg-projects/resilient-power-project/featured-installations/sterling-energy-storage.
(4) Ibid.
(5) Ibid, and “SMLD Energy Storage System – A Revolution for The Electric Grid,” Sterling Municipal Light Department, September 2017, http://www.energysterling.com/batterystorage.asp.
(6) Byrne, Raymond H. et al, “The Value Proposition for Energy Storage at the Sterling Municipal Light Department,” Sandia National Laboratories, 2017, http://www.sandia.gov/ess/docs/journals/SterlingMA_2017PES_SAND2017-1093.pdf.
(7) GMP offers to site Tesla batteries at customers’ residences, for a monthly fee, but also has a “bring your own device” program under which it offers bill credits to residential customers in exchange for periodic use of batteries the customer has purchased and installed. Several brands of batteries are eligible. The customer agrees to use the batteries only for emergency power during grid outages; the remainder of the time, GMP uses them to reduce costs associated with regional demand peaks, and shares cost savings with the customer. More information about this program can be found on GMP’s website: https://greenmountainpower.com/bring-your-owndevice/battery-systems.
(8) Fitzgerald, Garrett, et al, “The Economics of Battery Energy Storage How Multi-Use, Customer-Sited Batteries Deliver the Most Services and Value to Customers And The Grid,” Rocky Mountain Institute, September 2015, www.rmi.org/wp-content/uploads/2017/03/RMITheEconomicsOfBatteryEnergyStorage-FullReport-FINAL.pdf.
(9) Federal Energy Regulatory Commission, “Frequency Regulation Compensation in the Organized Wholesale Power Markets,” Docket Nos. RM11-7-000, Final Rule, October 20, 2011, www.ferc.gov/whats-new/comm-meet/2011/102011/E-28.pdf.
(10) Maloney, Peter, “FERC Order Opens ‘Floodgates’ for Energy Storage in Wholesale Markets,” Utility Dive, February 20, 2018, www.utilitydive.com/news/ferc-order-opens-floodgates-for-energy-storage-inwholesale-markets/517326.
(11) Ciampoli, Paul, “California Largest Utility-Scale Storage Market in 2016,” American Public Power Association, March 8, 2017, www.publicpower.org/periodical/article/california-largest-utility-scalestorage-market-2016.
(12) Kann, Shayle, “Next-Generation Energy Technologies Are Constrained by Outdated Markets. Here’s How to Fix Them,” Greentech Media, October 30, 2017, www.greentechmedia.com/articles/read/next-generation-electricity-technology-is-being-held-backby-outdated-marke.
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