Experts are asking whether project portfolio sell-offs by Amber Kinetics and Powin Energy represent a new trend.

Last month, Flywheel maker Amber Kinetics said it was giving up on a 20-megawatt project, Energy Nuevo, for Pacific Gas and Electric in California.

“The company’s new five-year strategic plan calls for an acceleration of equipment deployment and a de-emphasis on project development,” said Amber Kinetics in a press release.

Ed Chiao, co-founder and CEO, said the money earmarked for project development would now be spent on commercializing a new product, the 40-kilowatt, 160-kilowatt-hour M160, which is due for testing in the first quarter of 2018.

“Energy Nuevo would have required almost $10 million in security deposits and development costs,” Chiao said in the statement. “When we compared investing a similar amount in bringing the M160 to market on schedule, and focusing on generating greater near-term revenue, we chose to prioritize commercialization over project development.”

Portland, Oregon-based Powin Energy has since revealed it is selling its entire project portfolio, comprising around 100 megawatt-hours of energy storage assets, as a precursor to refinancing and refocusing on product development.

“We will be looking to strengthen our finances once we’ve moved these assets,” said Jan Jacobson, vice president of business development, in an interview. “We’re selling everything.”

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There’s a difference between knowing why energy storage is so useful to integrating wind and solar power into the grid, and being able to prove it to a banker. They’re going to want to know all the details in between, such as: Has anyone ever been paid for performing these tasks? If so, how much? And can we get that price in a 10-year contract? 

To be sure, we’ve seen hundreds of megawatts of energy storage bankrolled through utility contracts, as in California, or to serve once-lucrative frequency regulation services, as in the territory of mid-Atlantic grid operator PJM. 

But the structures aren’t quite there yet for energy storage to provide the bankable revenue streams that wind and solar project financial backers need to make deals — even if the desire for them is peaking. 

“The reality is that storage hasn’t been widely financed yet, and we’re still several years away,” Ravina Advani, managing director of BNP Paribas’ power and infrastructure project finance group, said during a webinar on merchant power trends held Wednesday by the American Council on Renewable Energy (ACORE) and Bloomberg New Energy Finance. “Financing with a renewal asset,” on the other hand, “I think is something the market hasn’t yet seen — but it’s an up-and-coming trend.”

Wednesday’s storage discussion came during a broader overview of merchant power industry trends, from the latest BNEF data on global clean energy investments, to forecasts on solar industry impacts from the Suniva trade case.

But for renewables, the key long-term market trends are the shift from state renewable portfolio standards, power-purchase agreements and renewable energy credits as key drivers, to a world in which corporate investors, community choice aggregators and the Public Utility Regulatory Policies Act (PURPA) are playing a larger role, said Steve Doyon, CEO of Novatus Energy. Energy storage “could help renewables transition to that type of market.”

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In the second quarter of 2017, 443 residential and commercial energy systems were deployed across the United States, representing 32 megawatt-hours of capacity.

According to GTM Research and the Energy Storage Association’s (ESA) U.S. Energy Storage Monitor, this is the most grid-interactive behind-the-meter energy storage ever deployed in a single quarter.

California will soon release an updated evaluation of greenhouse gas emissions from storage systems participating in the Self-Generation Incentive Program. Unfortunately, due to incomplete policies and methodology, the state may again reinforce the erroneous narrative that customer-sited storage drives up emissions.

There’s a better approach for customer-sited storage designs and applications to be applied to the greatest benefit of the state, and to prevent storage from being artificially constrained from helping California reach its GHG goals. As it has done with programs, tariffs and incentives to encourage customers to reduce energy consumption or peak demand, or to shift consumption to better utilize resources and reduce costs, the state should apply the same approach to enable storage to maximize GHG emissions reductions.

Customer-sited or behind-the-meter (BTM) storage, sited anywhere on the grid, can enable higher penetrations of renewables, and in doing so, reduce systemwide GHG emissions. Furthermore, when energy storage is charging during the duck belly, it absorbs and shifts power to the ramp “neck,” helping to reduce greenhouse gas emissions by avoiding fossil ramping assets. These benefits should be recognized.

California must develop an accurate methodology based on a GHG signal

The California Public Utilities Commission (CPUC) issued a Decision in 2015 on Self-Generation Incentive Program GHG evaluation approaches (D.15-11-027) that acknowledged the need to improve the storage GHG methodology. Others agree: A Carnegie Mellon December 2016 study criticized the SGIP methodology’s operating assumptions and inattention to retail tariffs and load profiles, and suggested a shift to production cost modeling.  

The CPUC methodology mistakenly assumes all BTM storage charging is done “off-peak,” that 100 percent of off-peak electrons are generated from combined-cycle gas turbines, and that all discharging is “on-peak” to offset combustion turbine peaker plants. Like most related studies, these assumptions are flawed in their failure to understand the economic market signals that determine storage behavior.

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Pushback against the proposed Puente natural gas plant in California now hinges on whether energy storage could do the job instead.

The first whack at the question, in a study by the California Independent System Operator, found that storage could provide the needed local reliability, but at 2.7 times the cost.

A GTM analysis of CAISO’s calculations, though, found that they rely on lithium-ion cost projections from 2014, which makes them just about ancient history in terms of the fast-moving storage industry. Battery costs keep falling faster than predicted, and in 2014 the industry was barely getting started.

CAISO doesn’t have access to proprietary cost data; the grid operator’s study makes clear the numbers are more of a ballpark calculation. It’s up to the California Energy Commission to decide whether to allow NRG to build its Puente gas plant in Oxnard for 2020, or whether more up-to-date cost data on alternative solutions would be helpful. 

“At a minimum, the prices assumed for energy storage and solar in the CAISO study are not reflective of today’s market for either technology,” said Shayle Kann, head of GTM Research. “It’s always hard for regulators to keep up with markets that are adapting as fast as both solar and storage are, but in particular storage costs are falling fast enough that using data from 2014 is like relying on gas prices from before the shale revolution.”

Environmentalists have rallied to squash Puente, arguing the plant perpetuates a history of Oxnard as a “sacrifice zone for polluting power plants,” even though alternatives now exist. The city itself opposes the plant and called it “expensive, obsolete before it is open” in comments on the draft of CAISO’s study. 

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If the temporary blotting out of the sun next week magnifies an inherent weakness of solar power, it also plays to the strengths of energy storage.

Advanced energy storage technologies have the ability to charge or discharge at a moment’s notice to shore up the needs of the grid. Whether or not the market structures exist to fully capitalize on those abilities is another question.

There’s little grid storage to speak of directly on the path of totality, where the sun will be entirely covered for a period of 2.5 minutes on Monday. That swath cuts southeast from Oregon to South Carolina. Indianapolis Power & Light has a 20-megawatt system just off of the path. Farther from the line, the sun will be 60 to 80 percent obscuredabove many of the nation’s largest solar plants in California, Nevada and Arizona.

The California Independent System Operator expects this to cause a shortfall of 6,000 megawatts that otherwise would have been produced by solar power between 9 a.m. and noon. 

California also wields considerable storage capacity: approximately 3,000 megawatts, said Alex Morris, policy director at the California Energy Storage Alliance. Some 2,600 megawatts of that are from old-school pumped hydro, with newfangled batteries making up the difference.

Members of the storage industry hope their response to the eclipse will demonstrate the flexibility of this tool and expand the opportunities for storage to help the grid in future challenges.

The grid response

Dealing with capacity shortfalls, especially ones with as much advance predictability as this one, is no trouble for grid operators. All they have to do is call up additional gas generators to pump out electrons when the sun starts to darken. This can get expensive, though, and involves a lot more greenhouse gas production than the solar would have.

The other trick is what happens on the back end. Gas generators spin large metal turbines to generate electricity, and there are physical limitations to how quickly those machines can stop spinning without damaging themselves. Many plants also have minimum run times they need to hit to justify the cost of starting up and burning fuel.

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Sonnen has signed a contract with an Arizona homebuilder to install its energy storage systems along with rooftop solar on each residence in forthcoming developments.

This has long been a goal for the company, which aims to create a community of homeowners who produce and exchange clean energy, while performing distributed grid services. The sonnenCommunity in Germany has grown to 8,000 members and functions like its own utility. That robust vision would be hard to implement in the U.S., given the regulatory structures in place here.

Loading up a new-build housing development with storage may be the next best thing.

Including storage offsets the potential strain on the grid that comes from packing a feeder with a lot of new distributed solar. Savvy site selection can place the fleet of battery-equipped homes at locations on the grid most in need of some help.

“Your duck curve in this very particular node without storage is extreme,” said Olaf Lohr, head of U.S. business development, describing a new neighborhood packed with rooftop solar. “But we add storage to it, and we actually alleviate that problem right away.”

That sounds like a decentralized version of what utility Arizona Public Service has done with its most recent grid battery deployment. It placed two 2-megawatt AES storage systems at different points on a solar-heavy feeder in a valley northwest of Phoenix, in order to test how the location influences the system’s ability to maintain power quality and voltage control.

That feeder serves a newly built housing community that features abundant rooftop solar, encouraged by the sunny climate and the west-facing roofs that can catch the late afternoon sun.

Sonnen has not finalized an agreement with a utility yet to make use of its forthcoming home network. Theoretically, the fleet of battery systems could deliver aggregated peak capacity, renewables integration, demand response or ancillary services. In practice, such virtual power plants are still being demonstrated in the U.S., especially when it comes to residential-sited systems. In Germany, Sonnen has already been doing it for several years.

The company wasn’t ready to reveal the name of the homebuilder partner, but described it as a progressive builder that typically constructs 200 homes a year and aims for 300 in 2018. The project is expected to break ground in Q4.

Customers who move into the homes will automatically join the sonnenCommunity. What exactly that means for a U.S. customer is still being decided, but it will include assistance on one’s energy bill, said Senior Vice President Blake Richetta. 

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