Tesla has unveiled yet another new large Powerpack energy storage project and this time, it’s going to be used as a virtual power plant for grid balancing in Europe.

The new project has been unveiled today in Terhills, Belgium.

It is made of 140 Powerpacks and a bunch of Tesla inverters for a total power output of 18.2 MW.

The Powerpack system will be used for similar grid services as Tesla’s 100MW/129MWh Powerpack project in South Australia, where the project had a massive impact on the cost of FCAS (frequency control and ancillary services).

Tesla partnered with Restore, a demand response aggregator, to build the system and offer balancing services to European transmission system operators.

Instead of using gas generators and steam turbines kicking to compensate for losses of power on the grid, Tesla’s batteries are charged when there’s excess power and then discharge when there’s a need for more power.

Restore UK Vice President Louis Burford told The Energyst that they are bundling their assets like batteries as a ‘synthetic pool’:

“By creating synthetic pools or portfolios, you reduce the technical requirements on individual assets that otherwise would not be able to participate [in certain balancing services]. By doing so you create value where it does not ordinarily exist. That is only achievable through synthetic portfolios.”

The executive said that they have a second similar project that they are soon launching in the UK.

Tesla released a cool video about the project:

High-tech grid resources that have become commonplace in some utility territories aren’t even considered in others. California utilities are already deploying energy storage in place of new gas plants. Regulated utilities in places like Arizona, Florida and North Carolina have begun factoring substantial amounts of storage into their grid planning, to tackle peak demand and make the grid more flexible.

Meanwhile, Dominion Energy’s new long-term plan for Virginia and North Carolina barely mentions storage and instead calls for intensive deployment of new gas peakers.

The disparity in adoption of tools like battery storage means that ratepayers in some places get a fuller consideration of alternatives for utility investment. That analytical process impacts the kind of investments utilities end up making and the rates their customers have to pay.

From Dominion’s perspective, the price point of battery storage wasn’t ready for full consideration. For the storage industry, the time has already come.

“There’s really no excuse for any utility today to ignore storage as an investment option,” said Kelly Speakes-Backman, CEO of the Energy Storage Association.

GTM is hosting the first ever Energy Storage vs. Gas Forum in New York City May 21. The daylong event will examine the growing competition between energy storage and natural gas to provide peak power. Can storage really compete with gas peakers? Do gas investors need to be worried? Find out more here.

Flexibility, traditionally

Dominion Energy’s integrated resource plan studies the regulated utility’s expected needs through the next five, 15 and 25 years. The document embraces new solar energy and even maps out scenarios for possible carbon regulation, while affirming the need for a more modern, flexible electricity system.

CARMEL, Ind. — Stakeholders last week said they foresee MISO making multiple changes to its markets to accommodate storage in response to FERC Order 841.

MISO invited stakeholders to give presentations on storage integration under the order during a May 10 Market Subcommittee meeting. The RTO will explore how to best comply with the order during a more comprehensive meeting scheduled for June 6, a joint effort of its Reliability, Market and Resource Adequacy subcommittees.

NextEra Energy’s Holly Carias, also representing the Energy Storage Association, said MISO’s participation model should not exclude any type of resource that meets the definition of storage.

“I think it’s not simply enough to fit storage into the traditional generator definition,” she said.

Instead, Carias said, storage resources should be able to self-bid instead of being subjected to must-offer obligations, in order to prevent battery life from being cut short by unpredictable injections. She also said MISO might need to update rules on physical withholding given storage’s operational nature.

But Minnesota Public Utilities Commission staff member Hwikwon Ham cautioned that allowing storage resources too much flexibility in the market could open MISO up to attempts to game the system.

The RTO’s market platform replacement comes at an opportune time then, Carias said, as it will be able to handle how storage will change energy use.

“In 10 years, battery storage is going to be so cheap that it will disrupt how we use energy,” Carias said, adding that by 2025, storage prices are estimated to fall to about $100/kWh.

MISO Executive Director of Market Operations Jeff Bladen reminded stakeholders that Order 841 simply requires RTOs to open their markets to storage participation and does not mandate any market design changes, although MISO will nevertheless debate to facilitate storage additions.

“To be clear, our view at MISO is that we want to evolve our markets. The pathway to changing our markets is not Order 841 compliance; it’s our own Market Roadmap [improvements]. … I want to make sure we don’t lose sight of that,” Bladen said.

Last week, CleanTechnica took a look the Energy Department’s vision for long duration energy storage, and we kind of brushed right past the nuclear energy angle. Here to fill in the gap is Mike Jacobs, senior energy analyst with the Union of Concerned Scientists’ Climate & Energy program.

Is There Something Going On Between Nuclear Energy And Energy Storage?

CleanTechnica called upon Mike to provide some additional insights into the Energy Department’s “DAYS” program, which is aimed at developing next-generation energy storage that can provide electricity in the 10-to-100 hour range.

A main goal of the program is to accelerate the transition away from fossil fuels and into wind and solar, while ensuring grid reliability and stability.

In an exclusive email to CleanTechnica, Mike indicates that the agency’s $30 million in funding is needed because the need for long-duration energy storage hasn’t jogged private investment dollars into action yet (following are Mike’s remarks in full, unedited except breaks added for readability and explication):

The ARPA-E initiative for long-duration energy storage (DAYS) is a welcome contribution to the RD&D stimulation of new solutions for our economy.  The economic signals for private sector investment in long-duration stationary storage are weak, because the “customer” in the utility sector has separated the competitive power plant market, which has a short time horizon, from the responsibilities for reliability and over-all integration of technology types.

Mike notes that pumped hydro, which is virtually the only bulk energy storage technology on the market today, has limited application:

You can see the change in the utility industry that once supported the construction (if not new innovations) of long-duration storage. As ARPA-E says, pumped storage hydro (PSH) has played a role on the grid, but has been limited by the large size that inhibits financing and the large environmental impacts that reduce the chance for permitting.

The nuclear angle comes in where Mike points out that the nuclear energy boom spurred the development of pumped hydro:

The boom-times for PSH was when the utilities were building nuclear power plants, and the storage in PSH was intended to absorb surplus production from nuclear plants at night and use that energy in the day.

Interesting, right?

The California Energy Commission this week required all new homes built in that state to have rooftop solar starting in 2020.

The bold new requirement raises an interesting question for the Golden State’s sun-drenched neighbor: What would happen if Arizona enacted such a policy?

Some new housing developments offer solar as an option, or even a standard feature, but Arizona doesn’t require the panels on new homes.

The new California regulations, which also include a variety of energy-efficiency measures like low-power lighting and insulation, are expected to add about $9,500 to the cost of a new home.

That should add about $40 to the average monthly payment on a 30-year mortgage, according to the energy commission.

But the panels are estimated to save customers about $80 a month in heating, cooling and lighting, according to the commission. That is a savings of about $19,000 over the usual 20-year lifespan of solar panels.

If Arizona passed a similar initiative, the cost would be about the same, though housing prices, in general, are higher in California than Arizona.

The value of rooftop solar would be slightly less for Arizonans, however, because energy generally costs less here. According to the U.S. Energy Information Administration, homes in Arizona paid about 12 cents per kilowatt-hour of electricity in February this year. In California, the cost was about 19 cents per kilowatt-hour.

So a system that generates 500 kilowatt-hours of electricity a month in California saves customers $95 a month there, while the same system (not accounting for weather differences in each state) would save an Arizonan $60.

Supply-demand concerns in Arizona

Arizonans have shown strong interest in solar — more than 77,000 Arizona Public Service Co. customers have rooftop panels.

But utilities here are increasingly focused on using batteries in addition to solar so that the supply of energy from solar panels can be stored and used when it is needed later in the day.

APS spokeswoman Jenna Rowell said the utility has not taken a formal position on the California requirement. Salt River Project officials didn’t immediately respond to questions regarding whether they would support a similar measure in Arizona.

The new California standards don’t require battery storage for homes, but if a home has a battery, the size of the solar array required on the roof is reduced.