Energy storage has inspired many metaphors to convey the versatility of its uses. Some call it the bacon of the grid, making other resources taste better. But the image of the Swiss Army knife captures the sheer number of different roles this technology can play.
Last week, Storage Plus examined the capacity use case, which analysts believe will drive 80 to 90 percent of deployments in the coming decade. Before that, we told the story of frequency regulation, the tool in the toolkit that launched the modern grid storage industry. This week, we turn to a niche yet promising battery application: deferring more expensive infrastructure investment.
If storage applications were ranked by the ratio of industry chatter to actual installations, non-wires alternatives would top the charts.
The concept, often abbreviated by grid wonks as "NWA," posits that batteries can deliver services that would otherwise require more expensive grid investment. If it’s possible to fulfill the needs of the electrical system while spending less money, that should be an obvious winner. Early projects in this vein have shown that this is possible.
And yet, one would be hard-pressed to point to any place where a proper market has materialized for batteries serving as non-wires alternatives.
New York, which popularized the concept in its Reforming the Energy Vision grid overhaul, has a handful of examples to point to, but several utilities are still working on their first demo projects. Arizona Public Service saved a bunch of money by building a battery in the desert town of Punkin Center in 2018, and New England utilities are building batteries for island destinations. But these are still highly site-specific projects.
“We’ve seen it proven, so it’s not a lack of proof,” said Jason Burwen, vice president for policy at the U.S. Energy Storage Association trade group. “It’s a lack of a systematic framework for doing this.”
This lack of regular pathways poses a challenge for modeling the size of the NWA market for storage: Though undeniably useful, the growth of this opportunity depends on utilities valuing it, and on regulatory breakthroughs in areas such as using batteries as transmission assets. It will remain an opportunistic target for developers until regular procurement systems emerge.
“Of all of the storage applications, this one, I think, has the widest error bars in the forecast,” said Daniel Finn-Foley, energy storage director at research firm Wood Mackenzie. But, he added, “If there is a big push toward eligibility and costs continue to fall, energy storage can solve a lot of problems.”
Thriving where wires are hard to build
Ask a seasoned grid edge professional what they think of when they hear NWA, and they’ll probably say BQDM.
The latter acronym corresponds to the Brooklyn Queens Demand Management project, in which utility Con Ed invested in distributed resources to avoid paying $1.2 billion to upgrade an urban substation. The portfolio included one of the first major lithium-ion batteries in the city, installed at an affordable housing complex in 2018 by Demand Energy (the company was later acquired by Enel X).
Central to that project working out was that New York regulators agreed to let Con Ed make money on a subset of the expense saved by deferring the more expensive substation upgrade. As a wires utility, Con Ed earns profit on the capital it spends building stuff; to incentivize not building as much, the state sweetened the deal.
Other New York utilities are now working on their own NWA demonstrations. Key Capture Energy is building a 4.4-megawatt/12-megawatt-hour build-transfer battery at Orange & Rockland’s Pomona substation, slated for completion by the end of the year. By supplying an extra 2 MW during summer peak hours, the project avoids a traditional wires investment on the order of $40 million, CEO Jeff Bishop said in an email.
Other early NWA batteries popped up where the cost of building out wires was especially high or otherwise difficult to execute.
National Grid gave the island of Nantucket a battery to help supply the seasonal tourist demand for electricity. Installing a battery proved easier and far cheaper than running a new undersea cable from the mainland. It says something about the circumstances that a battery with eight hours of duration was the cheaper option — that’s longer-lasting, and therefore more expensive, than most large batteries getting built even now. Eversource is building a similar project at the tip of Cape Cod to avoid messing with miles of scenic seashore.
Arizona Public Service tapped Fluence in 2017 to supply a battery in Punkin Center. The utility needed to serve growing load in this remote desert town at the end of a long line. The cost of running another conventional line to the town was such that building a battery there cut the project expense in half.
Then there was Duke Energy, which used a solar-battery microgrid to cut the cord entirely to a remote outpost in the Smoky Mountains.
These batteries all proved their worth, but they also stand out as edge cases, peculiar circumstances where lithium-ion (or zinc-air, in the Smoky Mountains) performed exceptionally well compared to traditional grid construction. That they can still be recalled by name speaks to the fact that these pioneers have not inspired a wave of similar investments in the years since.
Distributed batteries work too
The list above largely reflects utility-led, centralized batteries offsetting wires upgrades. But the Demand Energy project showed that batteries located on customer property can help defer system upgrades too.
When the economics are as clear-cut as they were for Punkin Center, value-stacking becomes unnecessary. But smaller batteries at homes and businesses can solve problems in ways that larger battery plants can’t.
“I like the distributed approach because you’re a lot closer to where the load is,” said Josh Castonguay, vice president and chief innovation officer at Vermont utility Green Mountain Power. “You can be much more precise on a problem that you’re solving.”
So far, GMP has installed a fleet of 2,567 Tesla Powerwall batteries in customer homes. The utility calls on them to reduce load during system peaks, which lowers costs for the customer base by millions of dollars. When storms roll in or trees fall on wires, the batteries provide residential backup power.
The program is a financial winner simply by lowering peak demand as much as it does. But going forward, when a substation or transmission upgrade arises and triggers a search for alternatives, distributed batteries will be on the menu. GMP would calculate the savings from deferring the upgrade and could then allocate some of that money to installing batteries in the affected area, putting the rest into savings for the rate base.
“With the experience with batteries that we have and the trust in the technology and performance, we’d have no issue with using a system like that to defer an upgrade if it’s feasible,” Castonguay said.
That’s a utility-driven approach to distributed energy. Independent providers could play a role too — if they earned compensation for helping out.
When a utility is considering spending money on wires upgrades, it should make that money available to customers who want to invest in localized energy that serves the grid's need, said Craig Lewis, executive director of Clean Coalition, a distributed energy advocacy nonprofit.
Clean Coalition recently crafted a solar-storage microgrid portfolio for Santa Barbara’s public schools. It provides bill savings and backup power. But more projects like it could yield enough local capacity that Santa Barbara wouldn’t have to worry about hardening the legacy poles and wires bringing power in over the rugged Santa Ynez Mountains, Lewis said.
The school project, however, had to make do without a line item paying for the deferral value of its incremental wires deferral value.
“What’s available today in policies and market mechanisms is the bill savings,” Lewis said. “Most places don’t believe that they can get bill savings, but in fact, larger sites that can accommodate solar microgrids can get bill savings.”
Longer-term, he’d like to see distributed energy compensated for its infrastructure deferral value as a matter of course.
“Non-wires alternatives isn’t just when you’re on the precipice of having to upgrade a substation or transmission line — it’s every single day,” Lewis said.
Non-wires alternatives occur when a utility identifies a grid infrastructure constraint and allows nontraditional projects to compete to solve it.
Even getting to that point requires a break from the traditional incentives utilities have to build and rate-base whatever they can. Utility leaders must want to save money for their customers, even if it reduces their return on equity. And they have to build up confidence in new technologies in place of tried and trusted century-old approaches.
“If you’re a poles-and-wires company, your first thought may be toward poles and wires,” Finn-Foley said.
Even when utility buy-in materializes, infrastructure deferral requires modeling the particular location and the need to see what technologies will work.
“Every single time you consider a non-wires alternative, it’s going to be a completely different situation,” Finn-Foley said. “A key challenge is how to replicate success at a larger scale.”
One way to streamline this process would be to systematize NWA procurement across a region and set a clear schedule for when developers should go to work.
“Ideally, consideration of NWAs would be incorporated at regular and expected intervals and standardized across the utilities in the state (to the extent possible) to provide developers with expectations of what is coming down the road,” Key Capture Energy’s Bishop noted in an email.
Storage as transmission: A work in progress
Regular compensation for distributed assets is still a work in progress, but so is the regulatory understanding of storage as a transmission asset.
In places that have more power to ship than capacity on the transmission lines, storage can absorb surplus power during peak times, then send that power over the lines when capacity opens up. Doing so could potentially save tremendous amounts of money compared to duplicative transmission lines, especially in places where the constraint only shows up for a fraction of the year.
This is eminently doable from a battery operations standpoint, but the regulatory implications are decidedly more challenging in places with competitive markets.
Wires assets are typically rate-based infrastructure. But to play this role, the battery would need to charge and discharge electrons, which requires buying and selling power. The trick is how to allow that without distorting power markets by having rate-based assets competing alongside normal generators and customers.
“It’s not just a lithium-ion battery dressed up like a pole and a wire,” Finn-Foley said. “This is a completely different solution.”
Instead of buying a second garden hose to pump more water, he said, it’s like buying a bucket you can fill with water to use when one hose is not enough.
But it's possible to resolve the definitional challenges for storage as a transmission asset, said Kiran Kumaraswamy, vice president of market applications at energy storage supplier Fluence.
In places where a line upgrade would be needed for just a few hours or days in the year — like those islands with heavy summer tourism load — a transmission utility could own the battery and lease it to market participants for all the months when there is no transmission need, he said. Or vice versa: A market participant owns the battery and leases it to a transmission utility for the months when it's needed.
"It creates a line of separation between who operates the battery and for what job," Kumaraswamy said.
Discussions are underway at several U.S. grid operators to figure this out. Because of these complexities, though, NWAs represent a much smaller storage market than capacity in the medium to long term. But if clear regulatory pathways arise to compensate NWA projects, this primary use case could become much larger than ancillary services, Finn-Foley said, especially as measured in megawatt-hour capacity. Frequency regulation drives investment in short-duration batteries, whereas grid-deferral batteries have already reached eight hours of energy duration.