The BP-backed solar developer Lightsource sees a very compelling case for deploying energy storage in the Western U.S.

All major utility-scale solar developers have added storage development talent, and some have begun regularly bidding on combined projects. But few have actually won bids for, much less constructed, hybrid plants. That makes it hard to determine just how central that kind of project is to their business models.

Not so with Lightsource, the largest European solar developer, which launched its U.S. branch last year and soon after received $200 million from oil and gas giant BP in exchange for a 43 percent ownership stake.

North America Chief Commercial Officer Katherine Ryzhaya affirmed the company’s view on storage in a keynote interview at GTM’s Solar Summit in San Diego last week.

“For a utility-scale solar developer, we’re not putting forward any proposals without storage, currently, to anybody west of the Colorado,” she said. “Every utility process, every bilateral at this point, at least on the West Coast, is looking at solar-storage hybrids.”

The American West enjoys a considerable solar resource, such that states like California and Arizona are starting to worry about a surfeit of solar on the grid at midday, with steep ramp requirements to meet peak demand in the evenings.

That dynamic has driven groundbreaking solar and storage contracts, like the NextEra project for Tucson Electric Power and the First Solar plant to deliver evening power to Arizona Public Service (the cartographically inclined may counter that most of Arizona lies east of the Colorado River, but it does sit west of the river’s source in the Rockies, so I’m going to count it for the purposes of this article).

So far, though, developers have kept their commitment to dispatchable solar more vague than “every proposal in the West.”

Co-location isn’t strictly necessary; on an interconnected grid, an offsite battery can store surplus solar power. Developing both resources together, however, creates savings on interconnection and installation costs, and improves system efficiency through DC coupling, which simplifies the power conversion process.

In order for power grids to rely mostly or entirely on intermittent energy sources such as wind and solar power, we’re going to need a lot of energy storage. Some studies have suggested that the United States would need 12 hours of energy storage in order to meet 80% of our grid needs from wind and solar, and in order to hit 100% wind+solar – without oversizing capacity or nationwide HVDC – the same study says we’ll need three weeks of energy storage.

While current technologies – namely lithium ion batteries – can technically run for as many hours as is needed, it is assumed that this technology won’t scale well due to its cost.

With that, the U.S. Department of Energy’s (DOE) Advanced Research Projects Agency-Energy (ARPA-E), has put out a request for projects to develop energy storage systems that provide power to the electric grid for durations of 10 to approximately 100 hours, or up to a month.

The program application page can be found here.

The DAYS program (Duration Addition to electricitY Storage) seeks two categories of projects – 1) DAYS systems that provide daily cycling in addition to longer duration, less frequent cycling and 2) DAYS systems that do not provide daily cycling, but can take over when daily cycling resources are either filled or depleted.

The program’s LCOS (Levelized Cost of Storage) target is 5 center per kilowatt-hour (kWh)-cycle, and ARPA-E suggests it likely requires system round-trip efficiencies greater than 50%. ARPA-E believes that long durations and infrequent cycling provide opportunities for design tradeoffs that may be leveraged to reduce costs and realize economically-viable long-duration energy storage systems. As can be seen in the image above, the goal is to be able to resell the wind and solar power, when including the generation costs of 2.5¢/kWh at 7.5¢/kWh.

The U.S. Department of Energy (DOE) today announced up to $30 million in funding for projects as part of a new Advanced Research Projects Agency-Energy (ARPA-E) program: Duration Addition to electricitY Storage (DAYS). DAYS project teams will build innovative technologies to enable long-duration energy storage on the power grid, providing reliable electricity for 10 to approximately 100 hours.

Energy storage will play an increasingly critical role in the resilient grid of the future. Storage systems provide important services, including improving grid stability, providing backup power, and allowing for greater integration of renewable resources. Today’s dominant storage options have limitations that inhibit their use as long-duration solutions, particularly their high cost.

“Building the grid of tomorrow will require new tools and technologies to ensure Americans have access to affordable and secure energy,” said U.S. Secretary of Energy Rick Perry. “At DOE, we are peering over the energy horizon and identifying the key technologies we need to support the power system of the future. These new storage options will offer us the opportunity to make the grid more resilient while enabling greater integration of our domestic energy resources.”

DAYS teams will develop energy storage systems that are deployable in almost any location and discharge electricity at a per-cycle cost target much lower than what is possible in systems available today.

The funding opportunity is open to a range of storage technology choices, including thermal, mechanical, electrochemical, chemical, and others. Driving the challenge are an aggressive set of cost targets, siting, power output, and duty cycle requirements.

A summary of the DAYS program can be found HERE. Additional information, including the full FOA, is available on ARPA-E’s online application portal, ARPA-E eXCHANGE.

CARMEL, Ind. — FERC’s extensive energy storage order has handed MISO’sReliability Subcommittee a new set of to-dos, including devising a storage capacity accreditation process and deciding whether storage will be subject to a must-offer requirement.

The subcommittee will also vet a proposal that will determine whether energy storage owners or MISO will manage the state of charge for resources. The group will additionally consider broader issues around storage, including:

• What information MISO needs about batteries to manage real-time operations;
• The risks of allowing market participation of energy storage at times when it’s not dispatched; and
• Whether MISO should employ reliability improvements to mitigate risks of storage use.

Finally, the group could lay out rules to clarify that energy used for charging is not considered “station power,” which MISO defines as the power a generating facility uses for operating electrical equipment. MISO’s current definition of station power does not include energy used for pumping at a pumped storage facility.

The items were handed down from MISO’s Steering Committee based on recommendations made from the Energy Storage Task Force after discussions on Order 841 and storage’s potential in the RTO.

At a May 3 RSC meeting, MISO Market Design Manager Kevin Vannoy said the RTO will bring storage participation straw proposals to a June 6 joint meeting of the RSC, Resource Adequacy Subcommittee and Market Subcommittee. He said MISO will vet storage proposals throughout summer to prepare for a December compliance filing.

Vannoy said MISO still hopes FERC will allow it to set a limit on the number of storage resources that can participate in its markets. FERC’s order set a 100-kW minimum size requirement for participation, causing RTO staff to worry that small resources will flood markets with finite capabilities.

GE Power has tapped former AES and RES Americas executive Robert Morgan to lead its new energy storage unit.

One of Morgan’s principal roles as GE’s CEO of energy storage will be to grow and expand the recently launched Reservoir – a comprehensive energy storage platform that delivers customized storage solutions to help customers manage the changing power landscape, according to GE Power.

“Energy storage is a key opportunity for our customers as they look for solutions with the best cost, lowest-carbon footprint, and greater reliability and resiliency,” says Russell Stokes, president and CEO of GE Power. “Rob brings the right skillset to lead GE Power’s energy storage unit as the industry shifts toward a more decentralized, decarbonized and digitized electricity infrastructure.”

According to Morgan’s LinkedIn profile, he served in various roles at AES from 1996 to 2003. He also founded Agile Energy LLC and served as the chief strategy officer and executive vice president of business development at RES Americas in 2013-2016.

Eric Gebhardt, vice president and strategic technology officer of GE Power, adds, “The global energy landscape is experiencing a dramatic shift with increasing renewables integration and the growth of distributed power. In his most recent roles as a founder of energy start-up Agile Energy and executive at RES Americas, Rob has been at the center of this market disruption and has demonstrated how to successfully build market-leading businesses. We’re confident he will do the same for GE Power’s energy storage portfolio.”

Tesla has recently deployed several very large energy storage projects, but a new one could apparently dwarf them all.

There was an important detail that came out of Tesla’s Q1 conference call but was mostly overlooked: Elon Musk teased a potential giant 1 GWh energy storage project, which would make it the biggest in the world by a wide margin, to be announced soon.

We published plenty of articles about the things that came out of the conference call, but I forgot about that particular comment until Galileo Russel reminded me of it during our podcast this week.

When Russel asked Musk about the impact of bringing online the giant 129 MWh Powerpack project in South Australia, the CEO answered:

“I think it had quite a profound effect. South Australia took a chance on doing the world’s biggest battery,and it’s worked out really well. If you read the articles, it worked out far beyond their expectations because the battery is able to respond at the millisecond level – far faster than any hydrocarbon plant. So, its grid stabilization was much greater actually than even a gas turbine plant, which normally respond quite fast.

Musk is referring to the grid services that the battery pack has been performing for the South Australian grid.

As we previously reported, the giant battery system made around $1 million in just a few days back in January though frequency response and it is already eating away at ‘gas cartel’s’ profits, according to a recent report.

Like Musk mentioned, it is proving to be much more efficient than the hydrocarbon peaker plants that the grid operators generally use to stabilize the grid.

But the question was about how it is impacting demand, so Musk continued:

The utilities that we’ve worked eith thus far have really loved the battery pack and I feel confident that we’ll be able to announce a deal at the gigawatt-hour scale within a matter of months. So, it’s 1,000-megawatt-hours…”

That comment is extremely important, but it sort of fell through the cracks.

Sonnen is one of our favorite cleantech leaders. It is great at innovation, leadership, and vision. Last month, I published a January interview with sonnen CEO and co-founder Christoph Ostermann. The good folks at The Beam went and created a transcript of it. If you can’t be bothered to watch a video but would like to read it, here you go!

Zach: So, we talked with you last year after you won the prize, I remember mentioning I was not surprised at all — I’m not surprised to see your ongoing progress, because Sonnen seems to be at the head of the game. What are some of the most recent big projects you guys have been excited about in the past year?

Christoph Ostermann: Oh, well, we had a very good year in 2017. Finally, the Australian market developed very, very nicely for us, mainly due to the reason of a retail power priceincrease on the first of July, by 25 or 30 percent or something like that.

You’re talking about for residential storage, right?

Absolutely. This has really kicked off the market and we are developing nicely over there, and then another highlight of 2017 is that the US business did very well. Unfortunately…

California and Hawaii?

California and Hawaii not as much as we thought. It was rather on the East Coast and also in the Caribbean Islands — for example, Puerto Rico due to the hurricanes….

We saw you were on the ground there, you made it to Puerto Rico, we have some coverage of your great work there. (See this, this, and this.)

It’s really unbelievable … if you have not seen it, you would not believe it. It’s unbelievable how the island is destroyed.

And the depressing thing now … there are still so many people without electricity, with roofs not on their homes. It’s a systemic problem. But what was your role? How did you get in to help them? I mean this is sort of a question that has been a little bit still unclear with you and Tesla. You have great — obviously, some of the best solutions to offer — but how did you get in?

How did we get in? I mean, first of all, we saw there is a huge need we have a partner in Puerto Rico we are working with since three years. It’s a company called Pura Energia. They told us about the problems they have on the island and then we sent a team over there.

Virtual power plants (VPPs) can greatly increase the value of home energy storage systems for a range of stakeholders including grid operators, utilities and their customers, according to SolarEdge, which has just launched a VPP software platform.

The Israeli company, known for products ranging from power optimisers and inverters to monitoring and energy management solutions, has over the past couple of years introduced more energy storage compatible inverter products and management solutions to markets including Europe and the US.

“The one word that is most important here is aggregation,” Lior Handelsman, VP for marketing and product strategy and also one of the company’s founders, told Energy-Storage.News of the platform, which Handelsman said “starts in the cloud”.

Essentially, VPPs take numerous battery energy storage systems, typically sited behind-the-meter in customer’s houses, and aggregate together their capabilities. It means they can be more easily controlled by the network operator and can be used to provide grid services.

“To take one example: [Let’s say] you are a network operator, tasked with stabilising the grid and keeping the grid stable. There are so many different distributed generation resources on the grid making your task more and more complex,” Handelsman said.

Network operators could be constrained by money, space or time from building out new infrastructure such as substations in neighbourhoods where there is high peak demand in summer. Instead those same operators could take advantage of growing numbers of distributed energy resources (DERs) on their grid that include solar PV systems, EVs and EV chargers and of course battery energy storage systems.

“If you have a peak in a specific suburb, all you need to do is tell the storage systems in that suburbs to feed energy just for a few minutes into the grid to support that peak. Or if you have a peak you ask all the EV chargers in that area to stop charging or throttle down their charging for a few minutes. These are the bigger examples, but that can be made more and more complex as the challenge becomes more and more complex,” Handelsman said.