As has been referenced in recent reports, dozens of new large-scale pumped storage hydropower projects are being pursued (e.g. per the DOE’s Hydropower Market Report). So while the growth in battery-based electric energy storage is important and will provide ever-increasing benefits as it continues, it is important for us to put “traditional” pumped hydro storage in perspective.

Consider one of the largest hydro pumped storage facilities in the U.S.—the 3GW Bath County Pumped Storage Station (co-owned by Dominion and FirstEnergy):

If you needed several hours of power at a 3 GW capacity level, it would take around a million Tesla Powerwalls to do the same job as this one big plant. But to be fair, in contrast, if you wanted what we may call a “pumped hydro residential equivalent” of a single 13.5 kWhr Tesla Powerall for your home, you’d need to install, along with your own generator/pump set-up, a 440 cubic foot pool in your home’s attic—pumping its 14 tons of water up and down each time you needed to store and utilize desired energy.

While it is still a large-scale affair, pumped storage remains by far the dominant source of electric energy storage, at 97% of all U.S. MWhr of utility-scale stored electric energy, and 98% of world-wise (see table).

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Electrek has learned that Mateo Jaramillo, Vice-President at Tesla Energy and one of the early members of the company’s stationary storage effort, is leaving Tesla after 7 years. The company’s energy storage division has undergone a restructuring over the last few months ahead of the merger with SolarCity, but a source familiar with the situation told us that Jaramillo’s departure from the company is unrelated to the recent shake-up at Tesla Energy.

CEO Elon Musk once compared working at Tesla to being in the Special Forces:

“…the general understanding is that if you’re at Tesla, you’re choosing to be at the equivalent of the Special Forces. There’s the regular Army, and that’s fine, but if you are working at Tesla, you’re choosing to step up your game. And that has pluses and minuses. It’s cool to be Special Forces, but it also means you’re working your ass off.”

Seven years of Special Forces is a long time and our understanding is that Jaramillo is taking a break.

He joined Tesla back in 2009 as Director of Powertrain Business Development. At that time, Tesla was starting to work with other OEM to develop electric powertrains, namely for Toyota second generation Rav4 EV, Mercedes’ Smart EV and later Mercedes’ Electric B-Class.

Two years prior to Jaramillo coming on board, Tesla co-founder and former CEO, Martin Eberhard, launched the predecessor of ‘Tesla Energy’, ‘Tesla Energy Group’. The new division aimed to produce battery packs for other automakers and potentially for stationary energy storage.

In a since-deleted blog post, Eberhard explains the goal of the new Tesla division:

Tesla Energy Group is a group within Tesla Motors, Inc. created to allow us to design and sell Energy Storage Systems (ESS) to other companies.

Eberhard put Bernard Tse, a member of Tesla board of directors at the time, in charge of the new division.

Unfortunately, things were difficult at Tesla in 2007-2008 and Eberhard was replaced as CEO, leaving Tesla not long after. The company refocused its limited resources on the Roadster that had yet to start production and Tse also left the company. He started Atieva, now known as Lucid Motors, to enter the same business as ‘Tesla Energy Group’ – making energy storage systems for OEM.

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What do Gerald Ford, a fossil-fuel plant on the Houston Ship Channel, the second-largest utility in Vermont, and the California legislature have in common?

They each ushered in a major national market transformation in the U.S. power sector over the last 40 years, at a rate of one per decade.

And in 2016, right on schedule, that once-per-decade cycle repeated. This year, it was batteries that made a transformative advance into both the competitive and vertically integrated power markets. 

A quick review of how competition entered the power industry, decade by decade:

• 40 years ago: Energy efficiency bills signed by President Ford established incentives to encourage demand management.
• 30 years ago: Generation competition launched as the AES Deepwater co-generation plant began operating in Houston under PURPA.
• 20 years ago: Retail competition launched with Green Mountain Power, then the second-largest utility in Vermont, offering renewable energy choices in the first retail pilot programs in New England. 
• 10 years ago: Solar competition launched as California’s legislature passed SB1 supporting the California Solar Initiative, thus creating terminal market velocity for distributed solar to orbit across the U.S. — the ultimate form of retail choice.
• 2016: Battery competition hits early, widespread market penetration, culminating with FERC’s November efforts to establish national standardization for energy storage participation in organized wholesale markets.
• With four momentous market transformations under our belts, what have we learned that can inform industry and advocates’ efforts on the next stage of power market design evolution including central and distributed storage? Here are five conclusions.

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By some estimates, 30 percent or more of the typical organization’s non-capital expenditures are attributed to energy costs, making this line item a focal point for cost-management efforts. However, amid technological, regulatory, and political changes in the energy sector, it’s nearly impossible to predict a particular organization’s future energy costs, which hampers decision making. [Full disclosure: this post has been generously sponsored by Green Charge.]

One way to minimize risk in the face of such uncertainty is to hedge against some of the variables in the energy cost equation. Many businesses and public sector organizations are realizing that a judicious combination of self-generated solar PV and behind-the-meter energy storage can greatly reduce overall energy costs while increasing ratepayer control over those costs. To understand how, let’s look at a typical commercial energy bill.

The two main cost components on most bills are energy use charges (measured in kWh) and demand charges (measured in kW). Energy-efficiency programs address the former. Examples include lighting and HVAC retrofits, building upgrades, and renewable self-generation plants, such as solar PV.

The second component is demand charges, surcharges for maximum demand within a billing period. Demand charges can be hefty for non-residential customers, sometimes accounting for as much as 50 percent of an organization’s utility bill. Even after implementing every feasible energy-efficiency program, demand spikes will occur—and demand charges will persist. Over-reliance on solar PV can actually exacerbate the problem. A short period of cloud cover disrupting solar generation during a peak usage event can result in a very costly demand spike.

One way to reduce demand charges is to negotiate a more advantageous rate structure. However, this is only a temporary fix, since the utility may change its rate structures at any time. A less risky approach is to prevent peak usage events from showing up on the utility’s meter. This is one of the functions of a behind-the-meter energy storage system. It can sense peak load events and instantaneously discharge power to cover that demand. The utility meter never registers the peak, so it does not factor into the demand charge.

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The cost of energy storage technologies is set to reduce significantly over the next five years driven by economies of scale and improvements in both technology and standardisation, according to a new report from financial advisory and asset management firm Lazard.

The second of Lazard’s Levelized Cost of Storage Analysis compares the costs of various energy storage technologies in detail across different segments in terms of capital cost and LCOE. The analysis was conducted with support from Enovation Partners.

The cost reductions will also be pushed forward by increased demand as regulatory environments improve, the penetration of renewables increases, and as ageing grids begin to need more support.

More demand for energy storage will also result in enhanced manufacturing scale. Meanwhile, the increasing deployment of both renewables and storage will create a mutually beneficial growth cycle where one technology’s success supports the other.

However, the extent of cost reductions in the five-year period has seen a mix of projections. Lazard cited some industry members forecasting lithium, flow and lead battery capital cost declines of around 40%. Lazard said cost reductions for lithium are already well underway since last year.

Ultimately it will be manufacturing and engineering improvements in batteries rather than balance of system (BOS) costs that drive the cost reductions.

Another key takeaway from Lazard was that some technologies are increasingly attractive for a number of specialised power grid uses, but not all uses are economically attractive right now. The main use at present is to strengthen the power grid through frequency regulation, transmission and distribution investment deferral. Another main use is to reduce energy bills for commercial and industrial energy users.

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Ambri, with its liquid metal battery technology, has returned to the energy storage race after “a pause” during which it redesigned its high-temperature seals and worked on other facets of its storage system.

Getting an entirely new and novel battery chemistry to commercial scale is Sisyphean work. About a year ago, the firm had to lay off approximately 25 percent of its staff because the startup had “not made the technology progress [it] had anticipated.” The CEO said at the time, “Bringing new scientific discoveries in the physical sciences to commercial success is hard; the process is not entirely knowable or amenable to predictable timelines.” Ambri had been working on prototype storage systems with project partners such as Hawaiian Electric and Con Edison.

The now 37-employee company just announced that it’s still going after the potentially immense stationary energy storage market, but with an improved version of its unique battery.

Ambri’s technology is based on the research of Donald Sadoway, MIT professor of materials chemistry, and inspired by the economies of scale facilitated by modern electrometallurgy and the aluminum smelter. The big-battery startup has raised more than $50 million in venture capital from investors KLP Enterprises, the family office of Karen Pritzker and Michael Vlock, Building Insurance Bern, Khosla Ventures, Bill Gates and French energy giant Total. 

Over the last year, the firm kept busy redesigning high-temperature seals and developing its battery management system and heater control. Ambri has been testing a “fully functioning in-lab” energy storage system, which provides 20 kilowatt-hours of energy storage with a peak capacity of 6 kilowatts.

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The energy storage industry has grown to become a $100 billion market, projected to reach $250 billion by 2040.

This massive valuation is due, in part, to more than 50% of consumer energy bills being attributed to peak hour charges. Noticing the need to make energy usage more affordable and efficient, paired with a passion to improve the planet, one entrepreneur launched a company aimed at transforming the way we use energy.

Founded in 2009 by Vic Shao, Green Charge Networks designs and installs commercial energy storage systems. Their mission is to empower businesses, municipalities, and schools of all scales to use energy more efficiently, by limiting carbon emissions and minimizing costs through servicing energy storage. Energy storage is designed to help avoid drawing energy from the grid during peak hours, instead charging itself during regular hours when energy is cheaper. By using energy storage as a method to balance peak power demands, power efficiency increases. This subsequently reduces demand charges, reduces capital expenditures for service upgrades, and improves the planet by decreasing the usage of power plants.

Green Charge was the first to market with an ROI-driven energy storage product. Now, the company stands as the largest provider of commercial energy storage in the country, boasting a growing portfolio of 48 MWh of battery storage projects deployed or under construction across more than 150 sites. In addition to expanding their reach, the startup has successfully helped customers across the United States cut the cost of their electric bills by up to 30%.

To date, Green Charge has raised over $56 million in two rounds of funding. In May, Green Charge was acquired by global energy power Engie, an industry-leading battery storage company. Leveraging an innovative suite of patented software algorithms and smart data, Green Charge deploys, owns, operates, and optimizes battery systems across both private and public sectors.

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Dynapower and Samsung SDI are launching their integrated behind-the-meter ESS offering with an immediate first deployment at the University of Minnesota, and are working with several behind-the-meter ESS developers to deploy their integrated solution across the nation during 2017.

The integrated energy storage offering provides energy storage system vendors, project developers, and utilities with a fully engineered solution that reduces costs for commercial and industrial end users in the deployment of energy storage.

The two companies’ integration experience includes the Electrical Training Institute Net Zero Plus building microgrid and the Duke Energy Notrees 36MW/14MWh ESS project.

Adam M. Knudsen, president of South Burlington, Vermont-based Dynapower says, “As the energy storage industry has rapidly evolved we have seen a clear demand from the market for engineered solutions that are flexible and proven. This is a solution customers can rely upon.”

Fabrice Hudry, the vice president of Energy Storage Solutions at Samsung SDI says. “Samsung SDI is the world leader in Li-ion battery technology specifically for stationary energy storage application, and it is only fitting that we integrate our batteries with Dynapower’s leading inverter technology.”

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The cost of energy storage technologies is set to reduce significantly over the next five years driven by economies of scale and improvements in both technology and standardisation, according to a new report from financial advisory and asset management firm Lazard.

The second of Lazard’s Levelized Cost of Storage Analysis compares the costs of various energy storage technologies in detail across different segments in terms of capital cost and LCOE. The analysis was conducted with support from Enovation Partners.

The cost reductions will also be pushed forward by increased demand as regulatory environments improve, the penetration of renewables increases, and as ageing grids begin to need more support.

More demand for energy storage will also result in enhanced manufacturing scale. Meanwhile, the increasing deployment of both renewables and storage will create a mutually beneficial growth cycle where one technology’s success supports the other.

However, the extent of cost reductions in the five-year period has seen a mix of projections. Lazard cited some industry members forecasting lithium, flow and lead battery capital cost declines of around 40%. Lazard said cost reductions for lithium are already well underway since last year.

Ultimately it will be manufacturing and engineering improvements in batteries rather than balance of system (BOS) costs that drive the cost reductions.

Another key takeaway from Lazard was that some technologies are increasingly attractive for a number of specialised power grid uses, but not all uses are economically attractive right now. The main use at present is to strengthen the power grid through frequency regulation, transmission and distribution investment deferral. Another main use is to reduce energy bills for commercial and industrial energy users.

The report stated: “Energy storage appears most economically viable in use cases that require relatively greater power capacity and flexibility as opposed to energy density or duration.”

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China’s deployment of energy storage looks set to continue an upward trajectory, with almost 600MW in the pipeline as of the third quarter this year.

According to figures released by the China Energy Storage Alliance (CNESA), 14 new projects were announced in Q3 2016 totalling 587MW. This includes projects that are in planning stages, under construction and that have gone online in the quarter. This appears to represent a significant boost to the sector, and is a vast 586% increase on the same period of last year. Up until the beginning of the quarter, CNESA found, 170.6MW of energy storage was in operation in the country.  

The bulk of this large figure is contributed by a single project, a touted 400MW supercapacitor storage station with storage duration of four hours in Guazhou County, in the northern Gansu province, a couple of hundred kilometres south of the border with Mongolia. This project will be used to demonstrate the use of storage in preventing wind power capacity curtailment on a microgrid. The project, by Shidai Jiahua Co, requires US$680 million in investment and has an expected payback time of 16 to 18 years.

There was also a 160MW local government project in Inner Mongolia, another microgrid to be used for renewables integration. The local authority of Xilin Gol, one of Inner Mongolia’s 12 sub-divided regions, is keen to trial retail sales of electricity from independent suppliers and this project represents a major step forward in this regard.

While these two huge projects are in northwestern regions of China, Jiangsu in the east will get some significant new projects including a 1.5MW/12MWh project from partners including battery maker Narada Power, inverter maker Sungrow and project developer GCL Power, which is an arm of one of China’s biggest PV groups, GCL Poly. Narada Power was also involved in a 15MW/120MWh project in Jiangsu’s Wuxi City Xingzhou Industrial Park.

Overall, renewables integration appears to be the biggest application driver for energy storage in China, as seen in the diagram below. While big announcements were plentiful, only 1.5MW of storage actually came online in Q3, which was nonetheless a 50% increase on the same period of 2015.

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