New York State could be on its way to crafting the most aggressive energy storage goal in the country.

The target is still a work in progress, but based on Gov. Andrew Cuomo’s (D) recent announcement and interviews with analysts, it could be set above 1,500 MW by 2030.

“I think the target would be higher than 1,500 MW,” Conor Bambrick, air and energy director at Environmental Advocates of New York, told Utility Dive.

California’s energy storage target is 1,300 MW by 2020. In his state of the state address in early January, Cuomo set a target of 1,500 MW by 2025. But 2030 is the target year that will be established by New York’s current energy storage bill, to keep it on the same track as the state’s 50% renewables goal in its Clean Energy Standard.

‘Eye catching’ goal

Cuomo’s 1,500 MW goal is “eye catching,” Dan Finn-Foley, senior storage analyst at GTM Research, told Utility Dive. But “at most,” he said, “it will serve as one input for the Public Service Commission as they begin the process of designing and setting policy around the final target.”

Finn-Foley called the 1,500 MW goal “aspirational,” but noted that “it comes with serious teeth” in the form of $200 million from the New York Green Bank and $60 million from NYSERDA towards energy storage pilots and deployments. “This level of investment has real potential to kick-start the market, though the timing is still up in the air,” Finn-Foley said.

The timing of New York’s energy storage target has been a stop and go affair from the start. The state’s legislature passed a pair of bills last June that directed the New York Public Service Commission to develop an Energy Storage Deployment Program, including a storage procurement target for 2030. The program would be run by the New York Energy Research and Development Authority (NYSERDA) and the Long Island Power Authority (LIPA). Cuomo signed the bill nearly six months later, but with a catch — a “chapter amendment,” which is sometimes used when a bill is passed without executive input.

In a signing memo attached to the bill, Cuomo said his office had “secured an agreement with the Legislature to pass legislation in the upcoming session” that would amend the law. That means the storage legislation will not reach its final form until it is amended by the passage of A8921, which has been introduced and is working its way through the legislative process. The bill is expected to pass soon, according to the office of Representative Amy Paulin (D), one of the bill’s sponsors.

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States in the Pacific Northwest are moving forward with policies encouraging new energy storage projects, but the region already has a lot of old fashioned storage — the type that sits behind a dam.

Hydropower provides the region with a cheap and abundant source of renewable energy that can also be used, in some instances, to store energy; and that presents a challenge for newer technologies, such as lithium ion batteries.

“Policy is pushing energy storage in the Pacific Northwest, but the economics of storage could have an uphill battle against the economics of hydropower,” said Jay Paidipati, a director at Navigant Consulting.

In a new report, consulting firm Cadmus Group says energy storage development in the Pacific Northwest is stymied by the lack of a compelling business case, policies and pricing structures that favor large power plant development over distributed energy resources, sluggish movement towards grid resiliency planning, and potential concerns about storage technology lifetimes.

The Northwest does not have an organized capacity market, which means that storage cannot be traded with clear price signals. The region also lacks differential pricing that recognizes the locational and temporal flexibility of storage. That severely limits two possible revenue sources for a potential battery storage project: the sale of ancillary services and the opportunities that high electricity prices create for price arbitrage.

The Cadmus report, which takes a broad look at energy storage in the Northwest, also notes that there are many balancing authorities in the region, but there is no mechanism to easily aggregate and transfer storage resources across them. That engenders a need for complex bilateral agreements that make collaboration more difficult.

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Six months after a target was set, energy storage in Massachusetts is beginning to take off, albeit slowly, as policies continue to evolve.

Ongoing challenges to wider adoption include questions about whether storage is eligible to net meter under the state’s rules and who retains the capacity value of storage in ISO New England’s forward capacity market.

Target spurs projects

In June, the state’s Department of Energy Resources set a 200 MWh-by-Jan. 1, 2020, target for energy storage.

Since then, the state’s Department of Public Utilities (DPU) has approved a rate increase for Eversource Energy utilities NSTAR Electric and Western Massachusetts Electric that includes $15 million for a 5 MW storage facility on Martha’s Vineyard and up to $40 million for a 12 MW energy storage project on Cape Cod.

In October, ENGIE North America and Holyoke Gas & Electric said they would build a 3 MW, 6 MWh storage project, the largest to date in Massachusetts, at the 5.7 MW Mt. Tom solar farm that went online in January 2017.

In November, National Grid said it plans to install a 6 MW, 48 MWh battery storage system on Nantucket to back up a new diesel generator on the island. 

And in mid-December, Massachusetts awarded $20 million in grants to 26 energy storage projects, doubling the state’s original $10 million commitment. The grants were awarded under the state’s Advancing Commonwealth Energy Storage (ACES) program that is part of the Energy Storage Initiative (ESI) funded by the Department of Energy Resources.

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The automakers’ efforts share several common concerns. They are looking to extend the life of batteries that are no longer useful in an electric vehicle but have enough juice left to store power for a household or provide residential backup power. They are working toward energy systems that allow for a more sustainable energy ecosystem for electric vehicles. And, by increasing the market for batteries, they hope to improve the economies of scale of battery manufacturing and drive down costs.

Audi, for instance, said its recent announcement will help it move closer to providing “emission-free premium mobility.” That could also be a strong selling point among customers looking to purchase an electric vehicle as an EV is only as green as the network that provides the power to charge it.

Overall, most auto makers’ participation in the stationary storage market takes the form of pilot projects. There are exceptions, such as Tesla, which has a separate energy storage division, but most auto makers are trying to find ways to generate more revenue through electric vehicles, or make those revenue streams available to their customers, Chris Robinson, an energy storage analyst at Lux Research, told Utility Dive. In most of the pilot projects, the manufacturers “are trying to find a way to make EVs more affordable,” he said.

Recent announcements by Audi and Nissan follow earlier plans unveiled by Tesla, BMW and Mercedes Benz. Tesla, in April 2015, became the first auto maker to enter the energy storage market with the introduction of its Powerwall system. Last May, Tesla said it would combine Powerwall installations with its commercial scale Powerpack batteries as a way of aggregating storage capability and make it more useful for balancing the grid.

In June 2016, BMW said it was entering the market for home storage by making its i3 high lithium-ion batteries available to households. The car maker said it could potentially expand the program to include its re-purposed 2nd Life Batteries, as they become available in the market. The systems can be used to store power from a rooftop solar system or they can be used as a source of backup energy for a home charging station for electric vehicles.

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Energy storage’s unique operating characteristics — it can be load or supply — have made market participation a complicated problem. But California now has interim rules designed to address some of the difficulties and to ensure storage resources are providing all the services they can while also being properly valued. 

In the order, the CPUC acknowledged that current market rules, including utility standard contracts and program tariffs, fail to support the ability of an energy resource to access more than one service. Known as “stacking,” it would include incremental values to the wholesale market, distribution grid, transmission system, resource adequacy requirements and customers.

“As a result, energy storage cannot realize its full economic value to the electricity system even though it may be capable of providing multiple benefits and services,” according to the CPUC order.

The order adopted 11 interim rules, which state that “resources interconnected in the customer domain may provide services in any domain.” Resources interconnected in the distribution domain may provide services in all domains except the customer domain, with the possible exception of community storage resources.

“Resources interconnected in the transmission domain may provide services in all domains except the customer or distribution domains,” the rules continued. Resources interconnected “in any grid domain may provide
resource adequacy, transmission and wholesale market services.”

A report from Brattle Group last year identified regulatory barriers that needed to be addressed to realize the full potential of value stacking. The report, titled Stacked Benefits: Comprehensively Valuing Battery Storage in California, was prepared for Eos Energy Storage with funding from the California Energy Commission.

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Significant seasonal demand spikes affect a number of areas around the country. Addressing them in a cost effective manner is a priority for those utilities that face large differentials between summer and winter loads.

One of those places, Nantucket, is both an isolated island and a wealthy summer colony whose population swells in the warmest months. It is a growing load area served by National Grid, and to meet that new demand, an expensive new transmission line could be required in the future. With the island’s backup generation aging, it leaves residents and the tourism industry in a precarious spot, should anything go wrong.

In an increasingly prevalent move, the island is turning to energy storage for a solution that illustrates how scalable battery systems can be. But while National Grid plans to avoid a costly transmission upgrade, its storage-based solution won’t be in place until 2019, leaving Nantucket’s residents and businesses vulnerable to potential outages as demand rises this summer.

In some respects, Massachusetts’ Nantucket Island is similar to North Carolina’s Ocracoke — highly seasonal, powered by undersea transmission cables, with some backup generation in place.

Ocracoke lessons

Last summer, Ocracoke Island experienced a week-long partial outage when one of those undersea cables was cut. Tourists had to evacuate and island businesses lost a significant chunk of their seasonal revenues. A microgrid developed on the island managed to keep some power on for residents, but unfortunately its diesel backup generation failed as well.

Nantucket is looking to avoid a similar disaster, and has employed a larger, yet similar approach to resiliency. Each island is looking to diesel backup and energy storage from Tesla, along with demand management, to ensure they can meet summer peak demand.

Ocracoke Island has about 1,000 full-time residents, and so its system is much smaller, including a 3 MW diesel generator, 500 kW/1 MWh Tesla battery and 15 kW of solar.

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Leaders in the fledgling commercial and industrial (C&I) sector in the US have made energy storage ‘as-a-service’ the core of their proposition, a market analyst has said.

Julian Jansen, senior market analyst in energy storage at IHS Markit told Energy-Storage.News that his team’s latest work, looking at opportunities and business models in the behind-the-meter C&I space, which he said that to date has been “under-analysed”, for the most part.

In the US, C&I users of electricity, from retailers to factories are charged premiums for the portion of their power drawn from the grid during peak times on a monthly basis. These so-called demand charges can make up 50% of a C&I customer’s electricity bills in some cases. Storing energy in batteries and discharging them to mitigate those peaks is one way that energy storage companies can earn money. The customer pays a fee to the energy storage provider, who in turn commits to delivering bigger energy savings to the customer via demand charge reduction or management.

While C&I energy storage can also offer other benefits, such as backup power and resiliency, could increase or enable self-consumption of onsite solar generation or can be used by utilities as a capacity or grid services resource, the primary focus of IHS Markit’s analysis was on “techno-economic modelling” of the business case for demand charge management, as the current biggest business opportunity available.

Payback times for C&I installations in the US can be as short as one year, in some cases, although the analyst and his team were keen to point out that project economics vary greatly and can be customer-specific.

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Xcel Energy’s latest resource solicitation returned renewable energy and storage bids so competitive they have the sector abuzz on social media. While Kann noted details about battery duration and sizing were not made available, the price of battery-paired solar in the solicitation is a full $9/MWh cheaper than the cheapest contract announced just last year. 

Last year Xcel subsidiary Public Service Co. of Colorado announced a plan to shutter 660 MW of coal-fired capacity at the Comanche Generating Station and issued a competitive request for proposals of up to 1,000 MW of wind, 700 MW of solar, and 700 MW of natural gas and/or storage.

In its status report, Xcel told state regulators that “the response to this solicitation is unprecedented.” The utility received 430 total individual proposals including 238 total projects. More than 350 of the individual proposals are renewable energy proposals or renewable energy with storage proposals, according to the report.

For comparison, Xcel said it received 55 bids in its 2013 all-source solicitation.

Many developers provided multiple bids for a single project resulting in significantly more bids than projects, Xcel noted. Differing bid information, such as different proposed in-service dates, different power purchase
agreements terms, and different ownership structures can result in multiple bids from a single proposed
project.

Of the 238 projects proposed, 99 projects included some level of utility ownership. 

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Most of the focus on energy storage safety has been on mobile applications, given the spate of exploding laptop and phone batteries.

Lithium-ion batteries used in those applications are under tighter restrictions for size and density that can lead to higher risks. 

Stationary storage applications are often safer than mobile uses because there are not the same space constraints. But in some markets, space can also be an issue for stationary storage, especially with projects that use lithium-ion batteries.

Such systems could get a higher profile this year with the expected release of new safety protocols.

New York standards

New York City is a prime example. The Fire Department of New York (FDNY) is working on drawing up standards to ensure the safe installation of battery storage projects, but population density and bureaucratic overlap still make New York one of the most restrictive markets for energy storage projects.

FDNY is collaborating with the New York State Energy Research and Development Authority (NYSERDA), the National Fire Protection Association, insurance companies and Consolidated Edison. Together they are working to come up with procedures and protocols for battery safety.

NYSERDA also is working with Con Ed on a joint battery energy storage safety initiative that aims to answer critical safety questions confronting FDNY and other agencies that are responsible for reviewing applications for energy storage installations. The initiative was undertaken in support of Gov. Andrew Cuomo’s Reforming the Energy Vision, which, among other things, looks to reduce peak demand by using battery storage.

The city saw its first behind-the-meter installation last May — a 300 kW, 1.2 MWh lithium-ion battery project in Brooklyn. But that project is sited outside, where fire safety concerns are muted.

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Most of the focus on energy storage safety has been on mobile applications, given the spate of exploding laptop and phone batteries.

Lithium-ion batteries used in those applications are under tighter restrictions for size and density that can lead to higher risks. 

Stationary storage applications are often safer than mobile uses because there are not the same space constraints. But in some markets, space can also be an issue for stationary storage, especially with projects that use lithium-ion batteries.

Such systems could get a higher profile this year with the expected release of new safety protocols.

New York standards

New York City is a prime example. The Fire Department of New York (FDNY) is working on drawing up standards to ensure the safe installation of battery storage projects, but population density and bureaucratic overlap still make New York one of the most restrictive markets for energy storage projects.

FDNY is collaborating with the New York State Energy Research and Development Authority (NYSERDA), the National Fire Protection Association, insurance companies and Consolidated Edison. Together they are working to come up with procedures and protocols for battery safety.

NYSERDA also is working with Con Ed on a joint battery energy storage safety initiative that aims to answer critical safety questions confronting FDNY and other agencies that are responsible for reviewing applications for energy storage installations. The initiative was undertaken in support of Gov. Andrew Cuomo’s Reforming the Energy Vision, which, among other things, looks to reduce peak demand by using battery storage.

The city saw its first behind-the-meter installation last May — a 300 kW, 1.2 MWh lithium-ion battery project in Brooklyn. But that project is sited outside, where fire safety concerns are muted.

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