Author's note: We’re embarking on a multipart series to explore the emerging state markets for energy storage. The goal is to expose readers to the new market opportunities popping up around the country, along with the local challenges and the cast of characters you should be familiar with in each location.
The “emerging” label deserves some explanation, as energy storage remains fairly novel everywhere. The key here is to investigate places where the industry is in flux. Maybe a new law breaks open deployment opportunities where none existed or new rate designs create a price signal that’s spurring investment. Or broader market dynamics organically made storage a cost-effective tool for customers.
If you follow Storage Plus, you’ve absorbed plenty of news about California’s bustling storage market and all the many policies it passed to support that. PJM is old news — who even develops there any more? And Hawaii is pretty well established; it kicked off the 100 percent renewable commitment trend way back in 2015 and has several rounds of large-scale storage procurement under its belt already. We’ll set those three aside for now.
To kick things off, we turn to New York, which has emerged as a vital hub of storage activity on the East Coast.
It turns out, policy works
New York state proved how quickly an all-hands-on-deck policy charge can create market activity.
It wasn’t always like that. As recently as 2017, state leaders had little action to show for their stated interest in energy storage as a tool for the state’s decarbonization strategy. The state was mandating 50 percent renewables, but leadership hesitated when it came to applying a "centrally planned" approach to storage. The legislature unanimously passed a bill to create a storage target, only to watch Gov. Andrew Cuomo sit on it for months.
That policy inaction shifted rapidly by the dawn of 2018. Cuomo finally signed the storage law, then upped the ante by proposing his own (non-binding) storage deployment target of 1,500 megawatts by 2025.
Since then, storage policies have come fast and furious, including:
- A $280 million “bridge incentive,” launched in the spring of 2019, that covers some of the calculated gap between what storage can earn given current market rules and what value it provides to the system. Wood Mackenzie analyst Brett Simon estimates this would incentivize at least 1.8 gigawatt-hours of additional storage by 2025.
- $55 million for a similar program in Long Island, which grapples with geographical constraints on power supply exacerbated by summer peaks from seasonal tourist influx. The local distribution grid operator will also pay homeowners for using their own batteries to reduce usage during crucial peak hours. That "bring-your-own-device" program gives homeowners an additional reason to combine batteries with home solar.
- A nitrogen oxide emissions rule that tightens enforcement on the worst-polluting peaker plants. Operators can comply by shutting down old plants and replacing them with storage, or by adding storage to hybridize plants so the thermal generators run less often.
- The non-wires alternative doctrine, which gives utilities a share of profit for money they save by avoiding capital-intensive grid upgrades. This hasn’t proven itself a huge source of business for storage, but it has supported a few installations, and storage is a natural tool for non-wires alternatives to use if they proliferate.
- Aggressive offshore wind development. The state targeted 9 gigawatts of offshore wind by 2035, compared to zero offshore capacity currently installed. Dealing with the influx of this generation to the transmission-constrained New York City region will almost certainly require grid storage, and quite possibly long-duration storage.
The full range of impacts from these policies is still being determined. The peaker emission rule, for instance, has taken effect but does not kick in the enhanced pollution restrictions until May 2023, so it hasn’t changed things on the ground yet. But the block grant program is clearly achieving its intended purpose of getting installations going; the stream of press releases about battery plants being built or developed with grant funds attest to that.
The retail storage grants have stimulated “substantial numbers of projects,” especially solar-plus-storage systems in the 1- to 5-megawatt range, said Bill Acker, executive director of the New York Battery and Energy Storage Technology Consortium, a local industry group more commonly known as NY-BEST. Numerous larger bulk storage systems have entered the queue to serve the NYISO wholesale markets, although they take longer to develop. And several utility procurements are wrapping up that could lead to more large-scale battery capacity.
As of Q3 2019, New York had built 47 megawatts of advanced energy storage, placing it in fifth place among single-state markets, according to data from Wood Mackenzie.
Regulatory challenges from near and afar
That’s the good news for storage developers. But two regionally specific challenges could stymie development: an arcane matter of federal energy regulation and the risk-averse fire-permitting process for batteries in New York City.
The partially populated Federal Energy Regulatory Commission decided in February that energy storage plants should be subject to a rule that will likely make them less competitive in the NYISO capacity markets.
Power plants in an area spanning the lower Hudson Valley, Westchester and New York City must undergo a “buyer-side mitigation” test before they can compete in the capacity markets. This test was designed to ensure that utilities that own generation don’t use out-of-market revenue streams to undercut the market and suppress prices.
“Clearly, no one in the storage industry has the intent to do that,” Acker said.
Not only does a fledgling storage industry lack the market power to game the system but price suppression would directly undercut the business case of a battery, which would be to earn as much money as possible for the delivery of capacity. The state, the ISO, NY-BEST and others petitioned FERC to make an exception.
But in a 2-1 ruling, the Republican majority applied the buyer-side mitigation test to storage and renewables in that mitigation zone.
“It’s certainly a bit of a barrier; there’s no doubt about that,” Acker said.
The test only applies to that delineated region, so upstate batteries can bid their capacity unencumbered. Some facilities could pass the test and avoid the administrative price hike, Acker noted. But the state is exploring other options via proceedings to revamp resource adequacy procurement and to reform the buyer-side mitigation rule itself.
File this under the broader theme of state clean energy policy clashing with the market rules adjudicated by FERC. In practical terms, though, it could deny storage developers valuable capacity revenue that they need to make projects worthwhile, unless the state figures out a workaround.
“The key thing for us in 2020 is sorting through the ability to participate in the ISO markets and/or the state resource adequacy parallel path,” Acker said.
If federal oversight can slow storage deployment, so can local permitting decisions. In particular, New York City’s Fire Department has taken a cautious approach to allowing lithium-ion batteries into densely packed city buildings. Last April’s explosion at a grid battery in Arizona corroborated the need to ensure safe installations.
The fire department has issued guidance for outdoor battery projects, which will speed things up compared to the early days when the standards were still being figured out. But it remains very challenging to do indoor projects in occupied buildings, like the basement of a high rise, Acker said. That so far has kept things pretty quiet in the state's largest load pocket, where local capacity has unusually high value.
To close, we're going to examine a few early projects that exemplify New York's specific style of storage market development.
Revamping commercial storage
The commercial storage business model that developed in California — subsidized batteries helping businesses reduce demand charges — has largely failed to spread elsewhere. Now even the pioneers of that model are pursuing alternatives, including selling software or supplying solar-plus-storage developments.
New York City has developed an alternative model: batteries that rent space from commercial landlords in order to serve specific grid needs. This drastically simplifies the relationship with the host company: It merely needs to have space and a desire to cash a regular lease check; no complicated demand analytics required.
GI Energy, a Shell company, tested this out in a four-battery demonstration with utility Con Edison in 2019. Enel X later put it to work at a big-box store mall in Brooklyn's East New York neighborhood, building the city's biggest battery.
These systems hold promise for future development. They give Con Ed access to local capacity in dense urban areas, where gas plant development would be impractical. Recall that these are the same areas that have the old, dirty peakers targeted by the new nitrous oxide regulation. And since these are larger outdoor systems, they don’t need to worry about the higher scrutiny applied to indoor batteries.
Putting the bridge grant to work
Key Capture Energy used the bridge grant to build a 20-megawatt battery near Albany, claiming the title of largest battery in the state when it reached completion last fall. It will face competition from a 20-megawatt system GlidePath Power Solutions is developing in Ulster, replacing a previously planned gas plant, but that won’t be online until 2021.
Key Capture approaches storage much like developing a merchant thermal plant. The team runs quantitative analyses on transmission flows and congestion to pinpoint promising nodes for siting, then assesses a range of wholesale market activities and contracted activities to maximize revenue.
As the first bulk storage project to make use of the incentive, this one serves as a proof of concept that the policy can spur development. Now we need to see how it performs. But the folks at Key Capture don’t seem interested in money-losing projects that claim market share; they have to answer to private equity firm Vision Ridge Partners, which means they need to justify projects based on private equity-grade returns.
Clean peaker for real
Ravenswood Generating Station sits on the banks of the East River, pumping out 2.2 gigawatts of power for New York City. But it soon could transform into a vision of the future grid.
Owner LS Power got regulatory approval in 2019 to add 316 megawatts of batteries to the site, replacing 16 old peaking units that have retired already or rarely run. It could be the first major use of batteries on the East Coast to deliver power comparable to a conventional peaker plant.
The deal is not yet done, however. Projects this size don’t just happen without some revenue locked in; watch for the results of Con Ed’s capacity solicitation from last fall for clues as to how the developer might secure that. The dynamics around FERC’s capacity market ruling also need to be sorted out.
But this project rides a few trends that aren’t going away: New York City needs peak capacity; the state wants more capacity from batteries rather than fossil fuels; land is scarce, giving LS Power an advantage since it has the land and interconnection already. If LS can turn those structural needs into a business case, others will surely follow.