The colonization of American grid innovation by European utilities has advanced with remarkable speed.

A promising U.S. energy startup, tackling such problems as energystorage EV charging or demand response, is more likely to find its way into the hands of Enel, Engie, Innogy or E.ON than their U.S. counterparts. This allows the Europeans to test out future business models far from their home markets, with negligible risk of cannibalizing their own core businesses.

Groupe EDF, which runs the electricity system in France and develops renewables around the world, has taken an inquisitive but less acquisitive approach to mining the U.S. energy sector.

It bought Maryland-based* groSolar in 2016 and turned that into the New World distributed development arm of its Renewable Energy practice. This past year it expanded that team with a new Distributed Energy and Storage unit, making use of the Store & Forecast software developed in France.

As a result, the company responsible for massive grid storage to balance France’s nuclear fleet has moved into distributed, behind-the-meter storage in the U.S.

Earlier this month, EDF won a 10-megawatt/40-megawatt-hour contract with Pacific Gas & Electric. If approved by regulators, EDF will tap a group of commercial customers to host batteries to fulfill the utility’s resource adequacy obligation, while generating savings for the customers.

This was not an obvious or guaranteed chain of events, but EDF determined that there’s a market for distributed storage that it cannot afford to ignore.

“Jumping over the fence and getting behind the meter comes from solar,” said Raphael Declercq, vice president of portfolio strategy at EDF Renewable Energy. “It was really a realization that customers were interested in this and there could be a very substantial reduction in their energy costs in some places.”

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In our previous article, we covered how technology costs aren’t yet low enough for energy storage to be economically viable as standalone projects, and some of the innovative ways developers are using to overcome these limitations. Here we’ll flesh out one of the more attractive – yet elusive – options: revenue stacking.

Mentions of revenue stacking frequently crop up in energy storage publications and in our own interviews, but why does it appeal so much? It’s simple. When making a business case for a new project and examining all the potential sources of revenue one could think “Why not offer many of these services, increase our revenue and diversify our income stream?”

If this sounds simplistic and too good to be true to you, you’re absolutely correct.

Most obviously, some revenue streams are not suitable for stacking, with different and even opposing technical requirements for optimum operation – frequency response and arbitrage, for example. Even for applications where operational requirements are more closely aligned, there’s a real risk of being forced into a solution that is average for every application rather than great for one.

Another challenge is that regulation still lags behind energy storage advancements. Existing revenue streams are subject to complex regulatory policies, which again, can inhibit or oppose one another. The restrictions in most countries, such as the UK, as to who can own and operate energy storage assets make co-ordinating grid-level applications difficult.

While there is no question that current regulations are outdated for today’s energy storage landscape, it is equally true that regulation changes can be introduced rapidly – for example, last week’s announced change in Capacity Market de-rating factors. The future is inherently uncertain, characterised by rapidly falling technology costs, saturated markets, planned regulatory changes and changing contract lengths. Accurate forecasting is a risky business for one revenue stream, let alone three, or six.

So does this mean that the benefits of revenue stacking should be discounted? We think not, and we can look to successful examples to see who is making it work, and how:

Don’t take on too much: There are far more successful examples focusing on two or three complimentary revenue streams than four/five. Fewer variables mean more accurate forecasting and better optimisation. An example of this strategy include solar plus storage “virtual power plants”, which receive income from direct energy consumers as well as for grid ancillary services.

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In an overwhelming show of solidarity, 37 energy-storage companies and associations have written a letter to Congressional leaders asking them for clarification on whether their products qualify for the investment tax credit (ITC) and urged them to support their inclusion in upcoming tax legislation.

With a vote on the Trump Administration’s comprehensive tax reform bill looming on the horizon, the group is asking Congress to codify the Internal Revenue Service’s previous Private Letter Rulings and guidance on the issue.

The group also said the energy-storage industry supports 70,000 employees that would benefit from this clarification because it would encourage further investment in the segment and grow that  number even further.

If those arguments sound familiar, it’s because they echo the arguments made by the solar industry in 2008 when it lobbied for the original ITC for the industry, and reiterated most recently in 2015, when the ITC was extended.

Recently, the solar ITC came under attack in the Senate’s version of the tax reform bill, but intense lobbying by the solar industry helped mitigate the damage, though it did not emerge unscathed. It appears the energy storage industry learned from that experience and is trying to codify its ITC eligibility in a separate law to keep any tax legislation from harming it.

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In Massachusetts, grants totaling $20 million were recently awarded to 26 projects that will develop the state’s energy storage market.

The programs are positioned to deliver benefits to the Massachusetts’s ratepayers and the electrical grid. The awarded projects will benefit 25 communities and draw in $32 million in matching funds, helping to grow the Commonwealth’s energy storage economy.

According to telegram.com, the grants were awarded as part of the Baker-Polito Administration’s Energy Storage Initiative (ESI) Advancing Commonwealth Energy Storage (ACES) program, funded by the Department of Energy Resources (DOER) through Alternative Compliance Payments (ACP) and administered by the Massachusetts Clean Energy Center (MassCEC).

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‘The cornerstone of the redesign of the electricity market’

California has already postponed and even canceled plans to build new natural-gas-fired power plants in favor of distributed energy. But it hasn’t proposed to replace an existing power plant with them — until now.

Early this month, the California Public Utilities Commission issued a resolution that would direct utility Pacific Gas & Electric to open competitive solicitations for DERs — energystorage mostly, but with room for other carbon-neutral “preferred resources” like demand response — to cover the grid capacity and voltage needs now being served by three Northern California natural-gas-fired power plants. 

Choosing which power plants are vital to keep the transmission grid running is the domain of the California Independent System Operator, not the CPUC. And the grid operator has designated the 580-megawatt Metcalf Energy Center south of San Jose, as well as the 47.6-megawatt Yuba River and Feather River generators as reliability must-run (RMR) resources. 

These RMR contracts come with secure, high payments for running relatively few hours per year — mainly during hot summer afternoons when air conditioning loads surge, demand spikes, and CAISO struggles to maintain the reserves to cover potential emergencies. Calpine, the owner of the plants, said they aren’t cost-competitive without RMR, and intends to seek that status with federal regulators, having passed over opportunities to bid their energy or capacity into resource adequacy or bilateral agreements. 

But California regulators argue that these must-run contracts are too expensive, and that distributed resources can replace them at lower cost to ratepayers. It also states that Calpine’s contracts failed to go through CAISO’s procurement process for flexible capacity, which could “lead to market distortions and unjust rates for power” in years to come.

That, the CPUC contends, gives it broad authority to allow solicitation of resources that can “fill local deficiencies.”

While the resolution doesn’t set a specific megawatt-hour target on what PG&E should procure, it does set some clear deadlines. If the resolution is passed, PG&E will have no more than 30 days to issue its first solicitations. Any resources the utility does procure will have to prove they’ll be ready in time to assure the RMR contracts won’t be renewed in 2019.

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Battery energy storage systems have always been in news. Given that inefficiencies in the power sector are always attributed to the fact that power can’t be stored at scale (so you need to over-build in every part of the value chain), grid scale storage solutions have been the holy grail for quite some time! As recent data suggests, this is not too far in the future. Bloomberg New Energy Finance (BNEF) has predicted cost of storage systems to fall to 1/10th of the 2010 levels by 2025 (see below). The learning curve of storage lies at 20%, which means that cost reduces by 20% for every doubling of storage capacity.

In addition to this story of energy storage becoming more mainstream, generally speaking, there are a few examples where BESS have solved here-and-now challenges for the grid. I want to highlight three such cases which highlight the coming of age of BESS. Two of them are for solving real, grid-scale challenges and one for grid planning.

Case 1: South Australia

This definitely is the most public of the cases so I might as well not talk about it! Legend has it that South Australia was suffering through a major grid instability back in December, 2016. Elon offered to solve the problem (through a series of tweets, mind you!) by installing a 100 MW/129 MWh battery pack in 100 days and ended up achieving it in 60 days!

Not only did this battery pack help solve a real problem for the customers in South Australia, it ended up doing it in record time. What’s more impressive is that another, larger, BESS system (100 MW/400 MWh) is already being deployed next to this system. BESS as a grid-scale solution has really arrived.

Case 2: Aliso Canyon (Southern California)

Although not talked about as broadly as South Australia, Aliso Canyon set the benchmark for speed of execution just earlier this year. For background, Aliso Canyon is a massive natural gas storage site in Southern California that experienced a catastrophic gas leak back in October, 2015, which impacted fuel supply for the gas plants in the area. This led to a declaration of state of emergency in California, with blackouts, and the Government hastily sanctioned procurement of 100 MW of BESS in Southern California.

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New York is the birthplace of our modern electrical grid. It’s a point of pride, but also a source of pain for New Yorkers since it means that we have the oldest and most outdated system in the nation. The inefficiencies and periodic failures of our electric grid cost New York businesses and citizens billions of dollars every year.

Entrepreneurs and investors are ready to deploy more advanced, cleaner technologies and services that will reduce the vulnerability of our grid to natural disasters (like Hurricanes Sandy and Irene) and terrorist threats. They’re ready to deploy solutions that will benefit both urban and rural communities.

There’s one problem: They’re prevented by outdated electricity sector regulations. 

In an effort to address the outmoded rules and regulations that prevent innovation in our electrical system, New York state has been working for three and a half years on the Reforming the Energy Vision (REV) process. The purpose is to enable the transition to a modern, distributed and clean electrical grid that includes critical energystoragetechnologies.

Much emphasis has been put on solar power and other renewables, but there are still no clear market guidelines for energy storage — meaning that many of the critical technologies needed to modernize and harden our grid to both natural and manmade disasters cannot be deployed at meaningful scale in the Empire State.

This inability of the New York Public Service Commission (PSC) to successfully implement REV has forced the legislature to take action. In June legislators unanimously passed an energy storage bill (A.6571 in the Assembly and S.5190 in the Senate). Thankfully, Governor Cuomo signed it into law at the beginning of December.

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AMHERST — Chemists have been trying for years to make a new type of battery that can store solar energy in chemical bonds rather than electrons, and release the energy on demand as heat instead of electricity — addressing the need for long-term, stable, efficient storage of solar power.

Now, chemists at the University of Massachusetts report that they have solved one of the major hurdles in the field by developing a polymer-based system. This method can yield energy storage density — the amount of energy stored — more than two times higher than previous polymer systems. Details appear in the current issue of Scientific Reports​​​​​​.

UMass researchers said previous high energy storage density achieved in a polymeric system was in the range of 200 Joules per gram, while the new system is able to reach an average of 510 Joules per gram, with a maximum of 690.

Lead researcher Dhandapani Venkataraman said, “Theory says that we should be able to achieve 800 Joules per gram, but nobody could do it. This paper reports that we’ve reached one of the highest energy densities stored per gram in a polymeric system, and how we did it.”

The authors said applications for the new technology include solar pads that collect and store energy by day then heat food, living spaces, clothing or blankets at night. They noted that this approach will be especially valuable in areas where there is no access to a power grid.

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LONDON/AMSTERDAM (Reuters) – Dutch energy storage systems group Alfen is planning a share market listing in Amsterdam in the first half of 2018, hoping to benefit from surging demand for its large batteries and electronic vehicle charging stations, people close to the matter said.

The company’s owner, investment firm Infestos, is working with ABN Amro (ABNd.AS) and Barclays (BARC.L) to organize the flotation as global coordinators, they added.

The firm may be valued at 500 to 600 million euros ($591-709 million) in a flotation, one of the people said.

Infestos, Alfen and the banks declined to comment or were not immediately available for comment.

Alfen, founded in 1937 as a maker of high- and low-voltage equipment, diversified into electronic car charging stations in 2007 and into large-scale batteries in 2013. The energy storage systems provide utilities with a means to help balance supplies from intermittent solar and wind power production.

Alfen was part of construction group TBI from 1971, which sold the company to Infestos in 2014.

According to an undated page on Infestos’s website, Alfen has 250 employees and about 100 million euros in annual revenue.

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