“There will not be an electrification revolution within mobility without some adaptation of how we generate, consume and transform energy because all of these cars will have to be charged somehow,” Lior Handelsman of SolarEdge says.

We are talking to discuss the company’s recently-announced acquisition of SMRE, an Italian integrated EV technology firm. SMRE has since 1999 been producing e-mobility solutions including powertrains and batter management systems (BMS), software and a range of other critical components.

SolarEdge agreed to purchase 51% of SMRE for an investment of around US$77 million, valuing the Italian company at US$150 million. Handelsman said that while there are no immediate plans to integrate the EV company’s technologies with SolarEdge’s own offerings, or indeed with the supply chain of Kokam – the battery and storage system manufacturer SolarEdge bought into earlier in 2018 – there are obvious synergies.

The acquisition feeds into the inverter and smart energy company’s overall ‘masterplan’ to involve itself in the full gamut of distributed and clean energy market segments, according to the SolarEdge co-founder, who is also VP of product strategy and marketing.

“We are at an interesting time when the world of energy and the world of mobility are changing and are changing together and that change is also related,” Handelsman says.

“These are related revolutions. We are already covering a big part of the energy revolution with PV, which we’ve spoken about in the past, pro-suming and the smart grid of the future. That is actually tied to mobility. It’s tied in with the supply chain, for the lithium cells involved, it’s tied in the consumption side, the demand side, so this is something that was done by design. It has a masterplan behind it.”

Stefan Schauss: The British energy storage industry should move forward strongly, independent from [exiting] the Brexit [process] or [a] no-deal Brexit. [The] fact is that Great Britain always has been an, electrically, [relatively] isolated terrain. However, we would expect a shift in the applications that would generate future deployment of energy storage. In case of [a disorderly] Brexit, there will be a currency impact that most likely leads to higher energy storage prices, and will shift supplies from countries with no bilateral agreements to countries of origin that do have trade agreements in place.

Another impact will surely come from import factors – customs, trade routes – to service battery deliveries in fast asset deployments. Delays and higher fees should, however, be short lived.

CellCube’s engagement in the UK is focused on long-duration, capacity-driven projects either in front or behind the meter. We take a more long-term oriented view and hence do not foresee a major impact on our strategy. Instead, it might accelerate our timeline. However, there will be some risk factors to be priced in, like currency fluctuations and, immediately following the event, most likely some delivery time adjustments.

In all, it will be a manageable risk for CellCube going forward, and project impacts for UK installations are scheduled into our plans.

How can British companies still participate and compete?

In a hard Brexit case, [the] U.K.’s many energy storage manufacturers are expanding globally. British companies should be able to participate in much the same fashion as any Asian company.

Europe has just launched its Battery Alliance, to become a world leader in battery manufacturing. Is Britain out of the equation from that project, if a chaotic Brexit were to come?

We do believe this will have a major impact for [production operations] which are to be set up in Britain and would be planned under an EBA [European Banking Authority] funding scheme. Most likely [it would] also impact British companies who are trying to establish [production] in the EU.

There are rumors Europe will achieve its battery ambitions by turning away from Li-ion solutions for better alternatives, performancewise and socio-ecologically.

Across Europe, there is a common consensus building that lithium might be limited, by its cost structure, to solve the transition to a fully renewable power grid on the stationary energy storage side.[That is] paired with some of the safety problems we are currently experiencing on global deployments of large-scale lithium cell-based installations, as well as the recycling question, which still remains unsolved to a large extent.

The utility will use Sunverge’s platform to integrate battery energy storage systems with consumer on-site distributed energy resources including solar photovoltaic, smart thermostats, electric vehicle chargers and other smart controllable loads.

The aim is to ensure grid reliability, as well as reduce consumer energy bills and carbon footprint by making the grid greener and smarter for the state’s largest utility.

The system will be used by both the utility and consumers to monitor onsite energy generation, storage and usage, as well as grid status and integrated energy.

Ben Farrow, manager of new products and services at PSE, said: “These batteries can help by giving our customers reliable backup power, while providing us with the ability to learn more about operational capabilities and efficiencies of energy storage on our distribution grid.

“By gaining experience with battery storage on our grid, we hope to expand this technology to benefit all customers in the future.”

Martin Milani, CEO of Sunverge, added: “DERs and Virtual Power Plant technologies are becoming a key component in many utilities’ future planning. Increasingly, it will be a required capability to achieving the optimal mix of traditional infrastructure, renewables integration, grid modernisation, resiliency and cost-effective demand-side management efforts and 

The UK Government has launched a consultation to determine how best it can alter planning policy frameworks to support developers and businesses seeking to build energy storage facilities in England.

Launched on Monday (14 January), the Department for Business, Energy and Industrial Strategy’s (BEIS) consultation asks developers, investors and other energy storage sector stakeholders how policy can help stimulate the construction of co-located renewable arrays and storage systems.

Specifically, the consultation aims to garner opinions on whether BEIS should alter current regulation surrounding large-scale storage projects with a capacity of 50MW or more. Currently, these projects are required to pass through the Nationally Significant Infrastructure Projects (NSIP) regime, while smaller developments are processed through local planning frameworks.

The consultation proposes that the 50MW “cap” is removed, allowing all storage projects, regardless of capacity or output, to be sent to local authorities for planning committee approval.

It additionally recommends that storage projects co-located with other forms of generation should only need to pass through the national planning system if the capacity of each aspect exceeds 50MW.

According to BEIS, such moves would spur the uptake of renewables and storage without distorting investment decisions.

“Our findings so far indicate that the 50MW capacity threshold, which triggers the need for a proposal to be brought into the NSIP regime, does not in itself distort storage developers’ sizing and investment decisions to a significant degree,” the consultation document states.

The consultation closes on March 25, with respondents encouraged to submit their evidence online, by email or by post. Any policy changes resulting from the consultation will apply to England only. 

Industry reaction

The launch of the consultation has been welcomed by the Renewable Energy Association’s head of policy Frank Gordon, who said: “A future UK electricity system with high energy storage deployment will reduce the need to produce ‘peak’ demand from fossil fuels, accelerate decarbonisation by improving the efficiency of wind and solar generation and reduce the need for costly grid reinforcement.

The debate over energy storage replacing gas-fired peakers has raged for years, but a new approach that shifts the terms of the argument could lead to an acceleration of storage deployments.

Rather than looking at peak demand as a single mountainous peak, some analysts now advocate a layered approach that allows energy storage to better match peak needs. The idea is beginning to gain traction with some states and utilities.

“You don’t have to have batteries that run to infinity.”

Ray Hohenstein

Market applications director, Fluence

Some developers of solar-plus-storage projects say they can already compete head-to-head with gas-fired peakers. “I can beat a gas peaker anywhere in the country today with a solar-plus-storage power plant,” Tom Buttgenbach, president and CEO of developer 8minutenergy Renewables, recently told S&P Global.

Others disagree. Storage is not disruptive for generation, but will be disruptive for transmission and distribution, Kris Zadlo, executive vice president and chief development officer at Invenergy, told the audience at a Bloomberg New Energy Finance conference last spring. Invenergy develops generation, energy storage and transmission projects.

But there is another path that avoids the pitfalls of positions on either end of the all-or-none approach. “Do the analysis of the need itself,” Ray Hohenstein, market applications director at Fluence, told Utility Dive. If the need is only two hours in duration, it may be best served by a two-hour battery. “You don’t have to have batteries that run to infinity.”

Storage vs. fossil fuel peakers

Energy storage has several benefits over traditional fossil fuel peaking plants, Hohenstein said. It is instantaneous, it has no emissions and requires no fuel, and has limited infrastructure needs. It can also help the grid absorb higher levels of renewable generation by soaking up excess output, such as solar power at noon. But the one thing energy storage cannot do, he said, is provide limitless energy.

So, instead of looking at replacing an individual peaker, Hohenstein advocated a “duration portfolio” approach that uses energy storage to shave peak load.

Last summer, my family and I visited London.

I’m not much of an Ikea customer in the States, but there are a handful of the iconic retailer’s giant stores in the London area too.

In the name of research, I wandered into one. The way I figure, if you want to know what “mainstream” looks like, Ikea — with more than 300 stores on both sides of the Atlantic — is a good place to start.

What caught my eye?

Ikea’s “energy storage system.”

Basically, it’s a big ol’ battery that, when hooked up to a handful of solar panels (which Ikea also sells), allows a homeowner to store electrical power for use at night and on cloudy days.

As I’ve written before, energy storage — for utilities and homeowners — is a gigantic opportunity for investors. We ignore it at our wallet’s peril.

Energy Storage = Profits

It’s the missing link in our “electrified” digital economy.

Fossil fuels are easily stored, of course, but provide an increasingly smaller mix of America’s energy needs.

Wind and solar provide an ever larger share — but what does a utility (or homeowner) do when there’s no wind, or no sun?

Energy storage is the answer.

In the Total Wealth Insider model portfolio, I already have one stock in this sector that’s up more than 40%, with more on the way.

Investors like ValueAct’s Jeffrey Ubben describe a 21st-century electrical grid — with energy storage at its center — as “an Amazon-like opportunity. You haven’t had electricity as a growth business in a long, long time.”

It’s worth noting that the world’s largest solar energy storage plant was just switched on in Hawaii.

With the ability to store 100 megawatt-hours’ worth of power for up to five hours straight, utility executives say the plant provides as much as 40% of the island’s evening peak power via stored solar energy.

According to researchers at Wood Mackenzie, the amount of energy-storage deployments tripled on a year-over-year basis for two quarters in a row.

In Q3 last year (Q4 numbers aren’t out yet), utilities and homeowners together deployed roughly 150 megawatt-hours’ worth of energy storage.

Renewable energy developer Invenergy has initiated commercial operations of a utility-scale battery storage system located in Knoxville, Iowa, for MidAmerican Energy.

The 4 MWh lithium-iron phosphate battery system is housed in two truck-sized steel containers at a MidAmerican Energy substation.

The utility can use the system in concert with wind and solar power generation, by storing energy produced when wind speeds and sun exposure are high and using it later. MidAmerican Energy owns an expansive portfolio of wind-powered generation capacity.

This is the fifth utility-scale advanced energy storage project Invenergy has developed, and the first where the company acted as the engineering, procurement and construction (EPC) provider.

“We are excited by the new opportunities for battery storage that we are seeing around the country,” said Kris Zadlo, senior vice president responsible for storage development at Invenergy.

El Paso Electric Company, a Texas electric utility, has revealed the winning bids for its 2017 request for proposals, including a total of 200MW of utility-scale solar and 100MW of battery storage.

Announced on Boxing Day, El Paso Electric revealed the winning bids for its competitive 2017 All Source Request for Proposals for Electric Power Supply and Load Management Resources.

The company announced that winning bids included a total of 200MW of utility-scale solar resources, another 100MW of battery storage, and the construction of a 226MW natural-gas unit at the Company’s Newman Power Station.

In addition, El Paso Electric also revealed that it would seek to purchase between 50MW to 150MW of wind and solar generated power.

“These technologies provide a mix of carbon-free renewable and clean burning natural gas generation that will enable us to meet the growing need for power in our region in a safe, clean, reliable, and cost-effective manner,” said Mary Kipp, El Paso Electric President and Chief Executive Officer.

“This balanced combination of resources will work with our existing energy portfolio as we move to retire aging, less efficient plants while continuing to meet our customers’ changing energy needs.”

No specifics were given regarding the solar and battery storage projects, while the natural gas combustion turbine generating unit intended for El Paso Electric’s Newman Power Station is expected to begin operation in 2023 and incur a cost of US$143 million.

California’s rising adoption of solar power has fundamentally altered traditional dynamics on its electric grid. In response, the state’s electricity providers are moving ahead with rate changes that will have a significant impact on electricity costs and the financial performance of behind-the-meter solar photovoltaics (PV) on commercial and industrial facilities in the state.

Since delivering electricity during periods of high demand is cost-intensive, utilities in California have long implemented time-of-use (TOU) rates that followed the grid’s traditional load curve — which ramped in the morning, peaked in the mid-day hours, and gradually decreased in the afternoon into the evening. Higher rates were applied during “on-peak” and “part peak” hours to accommodate the cost of the mid-day peak, while lower rates were applied during “off-peak” hours at night and in the early morning.

The rapid growth of solar in the state’s generation mix has upended the traditional load curve. On a day-to-day basis, solar power production rises through the morning hours and peaks around noon before tailing off in the late afternoon/early evening hours. At scale, this reduces the demand for natural gas in the mid-day hours. However, as solar power diminishes in the late afternoon, utilities experience a spike in demand for power from traditional sources from the late afternoon and into the early evening — a trend which has been referred to as the “duck curve” since a report by the California Independent System Operator (CAISO) publicized the graphic below:

The duck curve represents a challenge to the grid for multiple reasons:

• Lost revenue: The decline in mid-day demand has eaten into a strong source of revenue for natural gas generators, while an abundance of solar power has lowered electricity prices across the board — occasionally resulting in negative prices.
• Higher costs: Supplying the demand spike in the mid-afternoon/early evening hours requires the use of natural gas peaker plants, which are expensive to run.

Traditionally, TOU rates accounted for the costs to meet the daily peak in demand. The more electricity customers used during on-peak hours, the more money they spent on TOU rates. Now that the peak in demand has shifted to a later period in the day, California’s utilities are adapting their TOU rate schedules accordingly. San Diego Gas & Electric (SDG&E) shifted on-peak hours for its summer season to 4 p.m.-9 p.m., from its previous schedule of 11 a.m.-6 p.m. Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) are expected to implement the same schedule for on-peak hours in 2019.