At a time when analysts are watching with interest to see where European energy storage projects are going to find their future revenue, French utility giant EDF gave its backing to one prospective model this week.

Its acquisition of the U.K. battery storage and electric vehicle infrastructure developer Pivot Power is a nod to how it views the future composition of the revenue stack for energy storage.

With tenders for frequency response and various other grid services maxed out, utility-scale energy storage has been on something of a hiatus in Europe.

Pivot Power has 40 projects in development in the U.K. All are proposed at 49.9 megawatts (energy infrastructure over 50 megawatts gets channeled through the national rather than the local planning process). In addition to bidding for contracted revenue, such as frequency response, its batteries will also participate in the power markets.

Pivot’s differentiator is a third pillar of revenue derived from building private wire connections from the batteries to “megawatt-scale” EV charging sites.

Matthew Boulton, Pivot Power’s chief commercial officer, told GTM that the contribution from EV revenue would “evolve” over time, with ancillary services and trading revenues doing the heavy lifting.

“As a rule of thumb, the battery is 90 percent of the capex and over 90 percent of the revenue in the early years,” he said. “But scroll forward 10 years, and across the portfolio, we expect the EV side to be generating 30 percent of the revenues.”

“By virtue of what we’re offering, this is new cable we’re laying, so we’re only interested in megawatt-scale offtake,” Boulton continued. “The typical model for a middle-of-the-pack project [is that] in 10 years we’ll see 10 megawatts of daytime peak demand and 10 megawatts of overnight demand. We’ll be laying cable for 25-megawatt absolute peak and expecting to contract for 10 to 12 megawatts.”

The Pivot deal brings EDF’s trading expertise to the fore, and Boulton considers the acquisition an endorsement of the contribution batteries can play in trading markets — namely, intra-day, day-ahead and the balancing mechanism.

Now that it has become abundantly clear energy storage is the most important factor that can ensure the long-term success of renewable energy, the field has been brimming with potential breakthroughs. But while the majority of these seem to focus on improving existing batteries or finding alternatives to them, some scientists have taken a different path: heat storage.

A team of chemistry scholars from the Chalmers University of Technology on Sweden have been working on a project for the development of a so-called molecular solar thermal system since 2013, and now they have news to report.

The project, led by chemistry professor Kasper Moth-Poulsen, involved the design of a molecule—carbon, hydrogen, and nitrogen—which can capture solar energy and store it for as long as necessary until a catalyst causes a chemical reaction that results in the release of the energy in the form of heat.

According to the team, as quoted by Bloomberg Businessweek’s Adam Popescu, the molecule can store the energy for decades, which suggests it could outperform existing battery storage systems on durability: the average lithium ion battery lasts between five and 10 years.
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But that’s not all. The researchers also say their system is much lower on the carbon footprint scale.

How does it work? The molecule captures the energy emitted from sun rays upon contact. It is then stored in a cold liquid until needed. When needed, the liquid with the energy storage molecules are introduced to a catalyst. The liquid warms and the energy is released as heat.

Yet it is not just liquid that the molecule can be stored in. In fact, Moth-Poulsen’s team has developed a laminate coating with the molecules that can be applied to a variety of surfaces, from clothing to windows and used to store and, when needed, release heat. While not the same as existing energy storage that stores electricity, heat storage could cut the electricity consumption of a household and, consequently, its carbon footprint, which seems to have become goal number-one for the human civilization.

The four agencies are looking to the solicitation as a means to use local resources to meet California’s Resource Adequacy requirements, which have “historically been filled through [purchases] from distant power plants,” the groups said in a joint statement.

“This new program shifts the purchase of Resource Adequacy to new local solar power and battery storage systems that provide the benefits of backup power directly to local homes and businesses as well as bill savings,” the groups continued.

The local energy agencies issuing the joint solicitation include East Bay Community Energy, Peninsula Clean Energy, Silicon Valley Clean Energy & Silicon Valley Power. The first three are Community Choice Aggregators (CCAs) that serve Alameda, San Mateo, and Santa Clara counties. The fourth is a municipal utility that serves Santa Clara.

CCAs are proliferating around the country and have seen significant growth in California in the past three years. They were formed to leverage the buying power of large groups of electricity users to get lower electricity prices and meet other customer priorities. In deregulated power market states, this includes a demand for renewable, distributed and — increasingly — local generation.

The Nov. 5 solicitation is not prescriptive, but “includes goals of supporting low-income residents, customers with life-dependent medical equipment, and residents and businesses located in disadvantaged communities,” the groups said.

“One potential model for the program is EBCE’s ten-year agreement with San Francisco-based Sunrun for 0.5 megawatts of energy storage in and around Oakland drawn from new solar plus storage installations on low-income housing,” they continued.

Responses to the solicitation are due by December 23.

Energy storage has been the hot topic in solar and e-mobility over the last couple years, and it’s only getting hotter. Last year, energy storage installations in the U.S. totaled 311 MW and 777 MWh, up from next to nothing six years prior, and this is just the beginning. Wood Mackenzie and Energy Storage Association analysts predict that total MWh deployed will grow nearly 14 times in the next five years.

To ensure solar, e-mobility, and energy storage professionals have the knowledge and insight to make important business decisions in the new year, Intersolar North America teamed up with NAATBatt International—an association of companies and research institutions commercializing advanced electrochemical energy storage technology for emerging applications—to understand the top five trends shaping the market as it continues to grow into the next decade and beyond.

Plummeting Lithium-Ion Costs
The declining cost of lithium-ion battery technology is the primary trend driving market growth for the energy storage industry this year. Since 2013, prices have dropped by nearly 73%; in the first quarter of 2019, the market achieved a record-breaking 232% growth.

The downward price trajectory of lithium-ion technology continues to confound many projections that forecast the price to plateau or even reverse. Instead, experts now expect the cost reductions to continue as lithium prices fall an expected 45% by 2021. Bloomberg New Energy Finance has observed an 18% reduction in price for each doubling of cumulative volume, meaning that an average battery pack could be only $94/kWh by 2024 and $62/kWh by 2030.

Using batteries to do things like power vehicles and store electric energy on the grid were once thought to be completely uneconomic propositions. Today, because of falling costs across the battery industry, using batteries to perform these functions is not only possible, but can also offer advantages over the incumbent technologies of fossil fuel generation and internal combustion. As technology prices continue to fall, the economic benefits of energy storage applications will only see larger margins.

Utilities Making Moves at Scale
Utility adoption of energy storage and associated grid management technologies is another trend the industry is watching closely. As utility-scale solar maintains and gains popularity, utility asset owners are now looking to storage to help smooth peak demand curves and provide back-up power.

European utility giant EDF has acquired the British energy storage and EV infrastructure developer Pivot Power, following the French state-owned energy firm’s declaration last year that it would invest $10 billion in energy storage by 2035.

The deal gives EDF access to a 2-gigawatt pipeline of projects and to Pivot’s inventive route to market, in the absence of readily available contracted revenue for battery assets.

In Europe, tenders for services such as enhanced frequency response (EFR) have become saturated to a large extent, leaving storage developers to either look for new sources of contracted revenues or take a chance with some merchant risk.

This deal could allow EDF and Pivot to boost deployment against a backdrop of stagnant growth in the U.K.

“EDF has made a lot of noise with ambitions to be a leader of the global energy storage market announced last year,” said Rory McCarthy, senior storage analyst at Wood Mackenzie. “However, they haven’t [followed through on] this with anything in the U.K. market — until now.”

EDF’s last activity in the U.K. storage market was the completion of a 49-megawatt project won in the 2016 EFR tender. The Pivot Power acquisition gives it access to 40 projects, with two of them, both 50 megawatts, expected to be commissioned in 2020. Attention will now turn to the other 38.

“The level of development of these sites is unknown, but it was Pivot’s intention to develop each at 50 megawatts, with an initial portfolio target of 2 gigawatts,” said McCarthy.

The most recent update to Wood Mackenzie’s Energy Storage Outlook forecasts global 2019 storage deployment at around 4 gigawatts, with the U.K. and Germany contributing 600 megawatts of that total.

While recycling of lithium and other materials such as cobalt from batteries will greatly increase in the coming years, the potential availability of second life batteries should not be underestimated, according to new research and data.

Hans Eric Melin, an expert on the lifecycle management of lithium batteries with UK-headquartered consultancy Circular Energy Storage, previously commented on the growing volumes of batteries and their materials for this site – something else that the consultant claims is also widely underestimated.

In July, Melin told this site that that more than 70% of lithium-ion batteries recycled today are processed in China and South Korea, with “high” recovery rates of materials, with many of his findings to that point published in a report commissioned by the Swedish Energy Agency.

Circular Energy Storage’s newest data, which the consultant contacted this site about, predicts that “more than 1.2 million tonnes of waste lithium-ion batteries will be recycled worldwide by 2030”. By then, the amount of recycled lithium available to the global battery supply chain will be equivalent to about half of today’s lithium mining market, while the amount of recycled cobalt in 2030 will be around a quarter of today’s equivalent.

Second life importance
Between 2019 and 2030, close to 1,000GWh of “remanufactured and second life batteries” will be in use worldwide. Hans Eric Melin told Energy-Storage.news that it is inevitable that second life batteries will become available “for those who see the opportunities.” While portable electronics batteries will be the overall biggest sector lithium battery waste will come from, 75% of electric vehicle batteries – everything from e-scooters to buses, forklifts and trucks by 10 years’ time could be remanufactured into other vehicles or stationary energy storage systems, Circular Energy Storage has found.

With China expected to dominate lithium recycling efforts – as well as being a likely contributor of some 57% of lithium battery waste by 2030, it’s also likely the country will “take a tighter grip on” recycling and recovery and will also be the biggest source of second life batteries by volume.

November 4 (Renewables Now) – ABB (VTX:ABBN) last week officially opened a new manufacturing facility for energy storage systems in Baden, Switzerland, that will supply products for mobility applications.

The new factory will produce batteries for railways, e-busses and trolleybuses, as well as e-trucks, with the first orders already being in place. The Swiss-based power and automation group said on Thursday that several vehicle manufacturers from different countries have ordered energy storage systems.

The location of the new factory was chosen due to its proximity to the ABB Center of Excellence for Traction Converters in Turgi and to the ABB Corporate Research Centre in Dattwil. The storage systems made there use lithium-ion batteries. In the future, the manufacturing facility will make energy storage systems for new trolleybuses in the Swiss cities of Zurich, Lausanne and Fribourg.

The Swiss group noted that many European countries still have non-electrified trains and the integration of energy storage will facilitate the conversion of diesel trainsets into diesel hybrid vehicles, thus lowering carbon dioxide (CO2) emissions by 30%.

Pumped hydro storage, a tried-and-true technology for long-duration storage, involves using electricity to pump water to an upper reservoir from a lower reservoir or lake. When power demand is high, the water flows downhill from the upper reservoir, powering hydroelectric turbines that generate electricity.

Closed-loop pumped hydro uses two man-made reservoirs, with no connection to a natural body of water. A closed-loop system can be designed to generate power for eight to 10 hours, and to recharge by pumping water uphill for 10-14 hours, as indicated by plans for projects in Montana and Arizona.

Most of the 27 licensed pumped hydro projects in the United States, ranging across 16 states and totaling 18.8 GW, are at least 30 years old. However, there is also a robust pipeline: Preliminary permits for 20 GW of new capacity have been awarded by the Federal Energy Regulatory Commission, and applications have been submitted for another 19 GW.

There may be even more feasible pumped hydro sites in the United States, as an estimated 500,000 sites are technically suitable globally, meaning that they have potential locations for both high and low reservoirs.

Cost projections for pumped hydro are scarce, perhaps because there is only one modular component used – the reversible hydro turbines. All other costs are site-specific, from engineering and earth moving, to construction of the powerhouse containing the turbines.

One cost projection concluded that pumped hydro storage with more favorable financing is cost-competitive with lithium-ion battery storage.

Copenhagen Infrastructure Partners appears to back that assessment, given the firm’s equity investment last summer in a 400 MW pumped hydro storage project in Montana. The project has a license for construction and operation, and construction could begin next year.

The United States is expected to lean on non-hydro renewables — namely, onshore wind and utility-scale solar — for an estimated 10% of its total electricity in 2019. That may not seem like much, but it’s up from virtually nothing at the start of the century. And the best is yet to come.

A combination of falling costs, improving technology, and supportive state policies make it likely that onshore wind and utility-scale solar will provide at least 30% of America’s total electricity by 2030. But it’s entirely possible that all renewable power sources — including hydroelectricity, small-scale solar, and others — could generate close to half of the nation’s electricity by that date.

Getting there requires some help from two emerging technologies in particular: energy storage and offshore wind. Both opportunities are nearing an important inflection point, which means investors may want to the renewable energy stocks positioned to benefit on their radar.

Are batteries ready for prime time?
The promise of energy storage is simple to understand: Owners of wind farms and solar farms (or a rooftop solar array) could lean on batteries to smooth out the daily or weekly generation profile of their assets. For example, that could allow a solar asset to deliver electricity to the grid at night and incentivize larger solar farms, since energy storage could capture the “overflow” during the day. But residential and grid-scale energy storage products face a familiar obstacle: cost.

Discussing energy storage costs can be tricky because the economics depend on the application (small-scale vs. utility-scale, short-duration vs. long-duration) and the specific materials used in the device. Therefore, while energy storage only makes good financial sense for a limited number of applications today, there are signs that the technology is beginning to find ways into the crowded energy market.

Tesla (NASDAQ:TSLA) manufactures lithium-ion batteries for both small- and large-scale customers. It deployed a record 477 megawatt-hours of storage across all customer types in the third quarter of 2019, representing year-over-year growth of 99%. Most of the company’s business comes from grid-scale projects, which may receive a big boost soon.

At 4:52pm on Friday 9 August 2019, the UK suffered its first wide-scale blackout in more than a decade. More than 1.1 million consumers were plunged into the dark as rail lines screeched to a halt, traffic lights failed and even airports reported problems. Liam Stoker looks at the root causes, and how battery storage came to the rescue in an article which first appeared in PV Tech Power Vol.20.

16:52:33.490. Those nine consecutive digits won’t mean much outside of the UK’s energy sector, but they’re likely to be etched into folklore. It’s the precise timestamp for when, on 9 August 2019, a single lightning strike sparked a cascade of events that caused the UK’s first major blackout in more than a decade.

More than one million people experienced power outages and significant disruption, with not insignificant swathes of the country’s rail network taken out of action, albeit temporarily. The incident made national headlines for days after, as theory and rumour abounded.

A cyber attack? No, the UK’s transmission system operator National Grid quickly dismissed. Were renewables to blame? Earlier that day wind had provided more than half of the country’s power,
a feat which had the renewables lobby celebrating. That just hours later the lights had gone out was a fact not lost on a number of climate change sceptics.

But those theories were also dismissed by National Grid in the days after the event. While there was indeed marginally less inertia on the grid that day, courtesy of less synchronous generation, this was not something that ultimately contributed to the blackout.

The true cause, National Grid’s preliminary investigation, released on 19 August, was perhaps both simpler and more complicated at the same time.