With new energy storage projects seeming to come online every week, 2016 was likely the “turning point” for grid-connected batteries in the United States. Utility-scale battery storage installed capacity grew by 221 MW in 2016, aided by the falling price of battery cells. And longer-duration batteries are taking hold as well.

Platts’ report shows all of the nation’s grid-connected storage is in 12 states, and about 277 MW is focused on frequency regulation. However, more utilities are using storage as a way to defer costly infrastructure upgrades and skirt natural gas construction.

APS’ recent announcement is focused on deferring investment on a 20-mile transmission line. The battery will provide local generation during 20 to 30 peak power demand days per year, and on other days it will provide grid services to APS. The utility’s 15-year integrated resource plan calls for the addition of 500 MW of energy storage.

Southern California Edison, for instance, is another utility using storage as a way to avoid natural gas construction and cut emissions. SCE’s President Ron Nichols told Utility Dive the utility is also looking to pair energy storage with natural gas peakers to help cut emissions to meet California’s carbon goals.

“We will constantly be looking at, every time we need a new resource — how can we avoid the need to add another gas-powered resource?” Nichols told Utility Dive in an interview at the Energy Storage North America conference this week. “Even if they are built, they’re not gonna run much. They’re going to be there exclusively for reliability, full stop. That would be the only reason they’re added.”

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Energy storage providers are finding that aggregating storage and distributed energy resources can give them “a foot in the door” in wholesale power markets.

The California ISO has two products available for aggregated DERs: one for demand response providers, proxy demand response (PDR), and one for DER providers, known as DERP.  In particular, CAISO developed rules for DERPs to allow for aggregating different types of resources in the ISO markets, but these complex rules have yet to be put into practice. 

Still, companies are sussing out opportunities to leverage aggregated DERs, as the emerging market begins to gain traction.  It is an approach companies such as Tesla and EnerNOC have taken, as have Advanced Microgrid Solutions and PowerSecure. In their new partnership, Stem and CPower say California is one of the first markets they plan to target.

The company told Greentech Media it is already “engaging with customers” and looking “forward to some quick wins in California.”

The partners hope to find synergies by joining batteries’ demand cutting ability with demand response tools that can turn down air conditioning and heating systems, refrigerators and motors.

“If you’re solving it all with a battery, it’s going to be an expensive solution. If you’re doing it all with curtailment, it’s going to be a potentially disruptive solution,” Jason Babik, senior vice president of business strategy and development at CPower, told Greentech Media. Combining the two “can be really a ‘one plus one equals three’ type play,” he said.

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Deepwater and Tesla, two powerhouse clean energy companies, are pairing up for the biggest offshore wind and battery storage project so far. The 144 MW project was submitted as a bid for a 15-20 year contract under the RFP to help the state meet its goal of 1,200 MW of new renewable energy.

The Revolution Wind project would be located 30 miles off the coast near New Bedford. According to a Deepwater Wind press release, the wind farm and storage system would help Massachusetts meet two policy goals: the 1,200 MW of new renewables and open the door for more offshore wind development, key to the state meeting its separate goal of 1,600 MW of offshore wind by 2027. This project, however, will not count toward the offshore wind target since it was not submitted as a bid under its recent RFP, a spokesperson from Deepwater Wind said. 

Deepwater Wind is already a familiar name in the offshore wind sector. The developer successfully completed the United States’ first offshore wind project, the 30 MW Block Island wind farm off the coast of Rhode Island. Deepwater Wind is also working on offshore wind projects in Maryland and New York’s Long Island, and plans to submit a separate offshore wind projectfor an RFP by Massachusetts utilities for 400 MW of the resource. 

Tesla’s batteries have historically been linked to solar-plus-storage projects, but the company has since announced projects that would help store and dispatch intermittent wind energy during high peak periods. One such project is in Australia. 

The Deepwater/Tesla proposal isn’t the only project contending for the Massachusetts RFP contracts. Five companies announced bids under the RFP for transmission projects to ship renewable energy and hydropower from nearby states and Canada. Existing Massachusetts wind farms and solar projects were not eligible.

Projects will be chosen by Jan. 25 2018; contract negotiations are expected to be completed by March 27 and sent to regulators by April 25 for review. 

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Only a handful of states – California, Oregon and Massachusetts – have energy storage procurement targets. California and Oregon were the first to enact mandates for energy storage. They were followed by Massachusetts, which recently set an “aspirational” 200 MWh storage target. And in June, the New York legislature passed a bill calling for an energy storage target.

But a new report from the ESA put establishing a procurement target at the top of its list of state policies needed to jump start energy storage deployment. A target creates an environment in which storage purveyors can learn by doing. In states like California, this has already resulted in procurements that have exceeded mandated targets, the report says.

Among the other recommendations from the ESA is the creation of time-varying electricity rates that can demonstrate the value of storage to customers while better aligning customer costs with system costs.

The report argues that the benefits of energy storage must be realized through accurate market signals that enable the value of storage to be monetized. This could include solutions such as locational pricing and crafting rates that signal the best time to leverage storage capabilities, the report says. New York’s Reforming the Energy Vision is one notable efforttackling these issues, including compensating distributed energy resources according to the value assigned by the location. 

As prerequisites for competition, ESA recommends that states include energy storage in its integrated resource planning, distribution system planning, grid resilience and emergency management planning, peak demand reduction and energy efficiency programs. The report also recommends cost-benefit analysis for storage, and potential tax incentives to scale deployment in states. 

To encourage access, the report recommends that interconnection rules and interconnection queues should be updated to reflect changes in the energy storage market.

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Alectra’s announcement comes as an increasing number of utilities move into the distributed energy space, forming partnerships or acquiring DER providers to enhance offerings to consumers, particularly C&I customers. 

Southern Co., for instance, acquired DER and efficiency provider PowerSecure last year, and the company recently formed a partnership with Advanced Microgrid Solutions to deploy behind-the-meter storage for large customers.

Alectra, the third largest municipal utility in North America, has already begun to explore combining energy storage with rooftop solar panels through its Power.House pilot program. The program aggregates residential solar-plus-storage installations to create a virtual power plant.

The company, with AMP, is now looking at providing energy storage for the C&I market in Ontario.

AMP’s skill set includes asset development, project and structured finance, commodity trading, risk management, and engineering. The company, founded in 2009, developed projects in Canada, India, Japan, the U.S. and the U.K.

Earlier this month, AMP acquired a 14.7 MW solar plant in Fukushima Prefecture, Japan. The output from the solar plant is being sold to Tohoku Electric Power under a 20-year contract.

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When it comes to energy storage, some of the most skeptical entities in the power sector are often utilities.

Most recognize the promise of storage to provide grid services and even help defer some investments as an alternative to traditional grid upgrades. But start talking about batteries as an alternative to generation — such as replacing gas peakers — and many utilities get sheepish.

That’s the case even with utility leaders in energy storage. When Tucson Electric Power signed a breakthrough 4.5¢/kWh contract for a solar-plus-storage facility, executives steered away from comparing its capabilities to gas peakers.

Storage still has some “significant limitations” to peak shaving, “which can easily be longer than four hours,” the duration of the TEP battery, said Carmine Tilghman, the utility’s senior director for energy supply. Gas peakers and storage are different products and “should not be compared with each other and as replacement for one another.”

AES seems to be cut from a different cloth. On Tuesday, the utility holding company announced its energy storage subsidiary would enter into a joint venture with Siemens to form Fluence, a commercial- and utility-scale storage provider with more than 460 MW of storage deployed or awarded today.

During a speech in Washington, D.C., announcing the partnership, AES CEO Andres Gluski situated storage as a potential replacement for all kinds of bulk power infrastructure, from transmission to generation. In a subsequent interview with Utility Dive, he said AES’s 10 years of experience in the storage space give him the confidence that other power providers may lack.

“If you look at Southern California Edison, the 100 MW, 4-hour system competed against peaker plants,” he said. “We’ve shown it to be cost effective today. It’ll only become more cost effective as time goes on.”

Gluski was touting AES’s 100 MW, 400 MWh Alamitos project, awarded in 2014 in a local capacity RFO from the utility. That project is set to go into service in 2021, and since then the company has won other major projects, including deploying the largest lithium-ion battery in service and contracting for a 100 MWh battery to pair with a solar project in Kauai.

“Now it’s kind of like the asset test, if you think about what Kauai is doing. The prices will vary, depending on location and what the competing energy is,” he said. “But in 10 years of experience, I think we’ve proved that and our systems are still up and operating … and still making money for us.”

Fluence, the new joint venture with Siemens, will have access to 160 countries. Siemens’ SieStorage product focuses on commercial and industrial applications, while AES is a utility-scale specialist, so the venture will allow the company to run “the whole gamut” of large storage offerings, Gluski said.

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Unveiled just before the July 4th holiday, Massachusetts’ new energy storage target left a bittersweet taste with many battery companies. 

On July 1, the state’s Department of Energy Resources set a target for the state’s electric distribution companies to procure an aggregate of 200 MWh of energy storage by Jan. 1, 2020. But the State of Charge report that the DOER issued in September 2016 had said that the state could support a 600 MW energy storage target.

“The 200 MWh target is slightly under par even after accounting for potential market ramping from 2020 to 2025, as costs keep coming down and market is more mature,” said Ravi Manghani, director, energy storage at GTM Research.

And Timothy Fox, vice president and research analyst at Clearview Energy Partners, said the target set was “far more modest than broad stakeholder expectations.”

Fox also noted that the DOER target is less stringent than proposals offered by the state’s electric companies. “Unitil, Eversource and National Grid collectively recommended voluntary targets of 200 MW, 500 MWh by 2020, and 600 MW, 1,500 MWh by 2025.”

But “the key to understanding the target is the time frame,” said Judith Judson, Commissioner of DOER.

The 600 MW target recommended in the State of Charge report was for a 2025 timeframe. The recently set target has a 2020 target date to coincide with the deadlines in Massachusetts’ comprehensive energy bill signed in August 2016.

The energy storage target is “more aggressive than what was required in the law, Judson noted, but she also notes that there are several other programs aimed at bolstering energy storage, and they should all work in concert to move storage forward in Massachusetts.

“The new target sets up the state perfectly for hitting the 600 MW target by 2025,” she said.

In addition to the recent energy storage target, the DOER has implemented several measures to promote energy storage in Massachusetts since the State of Charge report was released last year,

Judson said Massachusetts was the first state in the nation to offer incentives for combining solar power installations with energy storage through its Solar Massachusetts Renewable Target (SMART) program. And the state’s ongoing solicitation for 1,600 MW of offshore wind also allows for pairing storage with wind resources.

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California’s SGIP program is the largest state-sponsored behind-the-meter storage incentive in the country, and the application process is exceedingly complicated.

The program recently re-opened after a nearly two year hiatus so that it could be reformulated in order to make the process more equitable. SGIP attracted controversy in previous years with reports that some companies were able to wind a lion’s share of the awards.

In revamping the process, the state also put a greater emphasis on energy storage and de-emphasized other renewable technologies, which are covered under other incentives. The program now has $448 million earmarked for storage, 79% of the total, spread over five rounds of allocations.

That funding could beget as much as 800 MW (1600 MWh) of storage, depending on how incentives are allocated, according to an analysis of the program from consultancy Strategen. That likely means hundreds of permit requests for installation and interconnection of small storage systems — a burden some local governments could find difficult.

AB 546 seeks to help, calling for a storage permitting handbook for government agencies. A similar guide already exists for applicants to the storage program, and the government handbook would be positioned as a model for other states. 

“The purpose here is to give cities and counties helpful tools,” Alex Morris, director of policy and regulatory affairs for the California Energy Storage Association, told Microgrid Knowledge. “The vast majority of projects are small behind-the-meter projects that have to connect with the utility and go through the permitting process.”

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Back in March, Musk tweeted that he could solve South Australia’s power crisis in 100 days. Roughly four months later, he is getting his chance.

The 129 MWh project Tesla is building at Neoen’s wind farm is contracted to come online by Dec. 1.

South Australia earlier this year experienced rolling blackouts that attracted the interest of developers eager to demonstrate the capabilities of energy storage.

Tesla’s proposed storage facility will be used to reinforce South Australia’s grid and improve resiliency. The batteries will be charged by the wind farm and will discharge into the grid during times of peak and high demand. The batteries will also serve to smooth the integration of variable wind energy into the network and to provide backup power in the event of outages.

When completed, the 129 MWh facility would be the largest lithium-ion battery facility in operation, at least for a time. The title is currently held by San Diego Gas & Electric’s 120 MWh Escondido storage facility, though there are larger non-lithium batteries in operation, such as the Kyushu Electric Power Co​. 300 MWh sodium-sulfur battery facility.

All those batteries could soon be eclipsed by other planned facilities down under, however. Brisbane renewable energy firm Lyon group announced plans for a 100 MW, 400 MWh battery storage facility in March, slated for siting alongside a 330 MW solar farm. And Queensland’s SolarQ is planning a lithium storage facility of up to 4,000 MWh to be paired with a 350 MW solar facility.

Those batteries aren’t planned to be installed before the Tesla facility, however, giving the company the title of largest lithium-ion facility once again. Before SDG&E’s Escondido project came online, Tesla briefly held the distinction for its 80 MWh facility for Southern California Edison.

“Battery storage is the future of our national energy market, and the eyes of the world will be following our leadership in this space,” Weatherill said in a statement.

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The installations, which are slated to begin this summer, are tasked with demonstrating a non-wires alternative to defer the need for a third undersea cable to Nantucket at a cost of between $75 million and $100 million.

The storage systems, which would cost about $3 million, would replace standard residential air conditioning units.

Ice Energy’s Ice Bear technology fits on traditional air conditioners and freezes water into ice at night when demand for power is low. During the day, the stored ice is used to provide air conditioning at peak hours, drawing down customer power demand. 

The Nantucket contract is the latest in a string of projects for the thermal storage company. In 2014, Ice Energy made headlines with a 26.5 MW contract with Southern California Edison and more recently signed a 1 MW contract with the Southern California Public Power Authority.

“Local participants will enjoy increased comfort as well as savings on their energy bills … and defer the need for traditional contingency support, such as back-up diesel generation and a costly third undersea cable,” Lauren Sinatra, energy project and outreach coordinator for Nantucket, said in a statement.

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