Tesla (NASDAQ:TSLA) CEO Elon Musk’s update on the electric-car maker’s business on Tuesday afternoon at the company’s annual shareholder meeting obviously impressed investors. The stock surged higher on Wednesday, finishing the trading day up nearly 10%.

For the most part, headlines after the meeting seemed focused on Musk confirming that the automaker is on track with its production and profitability plans. Of course, there’s good reason to believe the news that Tesla is on track to achieve a production rate for its Model 3 of 5,000 units per week by the end of June and GAAP profitability in both Q3 and Q4. Production delays have previously plagued the Model 3 as Tesla attempts to transform into a mass-market auto company, which has weighed on profitability. But another narrative discussed during the shareholder meeting is worth examining: Tesla’s surging energy storage business.

What Musk said about Tesla’s energy storage business

Musk was extremely optimistic about Tesla’s energy storage business, implying energy storage sales will see wild growth at rates that exceed the sharp growth in Tesla’s vehicles sales.

Launched just three years ago, its energy storage business has already swelled to a total of 1 gigawatt-hours of energy storage deployments globally as of May, Musk said during the shareholder meeting. He also said he expects that in “less than a year from now” Tesla will deploy another GWh of energy storage.

But this is just the beginning, according to Musk. “I think for many years to come, each incremental year will be about as much as all of the preceding years [in terms of energy storage deployments],” the CEO predicted.

Furthermore, he said deployments are ultimately limited by production, which is notable since Tesla’s Gigafactory has morphed into the world’s highest-volume battery factory when measured by battery capacity output.

Musk put the extraordinary demand for energy storage and the scale of the Gigafactory’s output into perspective:

We would actually be able to do more if we could produce more. And we are producing a lot of batteries. So in fact, next quarter, at the Gigafactory, we expect to make more battery capacity than all other EVs combined worldwide, including China. So I mean, this is a really crazy amount of batteries. This one factory is making — will make more than all the other factories on earth…

San Diego Gas & Electric (SDG&E) has obtained approval to add 83.5 MW of energy storage facilities in California, the power utility said on Monday.

The company has been given the green light by the California Public Utilities Commission (CPUC) to contract five projects envisaging the installation of lithium-ion battery storage facilities in San Diego and south Orange counties. A 30-MW/120-MWh storage system will be constructed in San Diego by Renewable Energy Systems (RES) America, while Advanced Microgrid Solutions will build a 4-MW/16-MWh lithium-ion battery in San Juan Capistrano. Both facilities are planned to be switched on by December 2019.

The approved capacity also includes a 40-MW/160-MW energy storage project in Fallbrook, proposed by Fluence, a business created in January 2018 by Siemens AG (ETR:SIE) and AES Corp (NYSE:AES), as well as a 6.5-MW/26-MWh facility in Escondido, to be installed by Powin Energy. Those two lithium-ion systems are scheduled for completion by March 2021 and June 2021, respectively.

The fifth storage project, under which SDG&E is contracting Enel Green Power, is for a 3-MW/12-MWh facility in Poway, slated for completion by December 2021.

CPUC’s clearance also covers a contract between SDG&E and OhmConnect under which the latter is providing a demand response programme for the equivalent of 4.5 MW.

The projects are seen to improve the reliability of the local power grid and enable the addition of more renewable energy capacity, SDG&E said. They are in line with its goal to develop or interconnect more than 330 MW of energy storage capacity by 2030.

As the electric car (and truck and bus and heavy equipment) revolution sweeps across Europe, policymakers and investors are divided on whether the EU should push an aggressive strategy of constructing lithium-ion battery factories or just let the companies from China, Japan, and South Korea do the heavy lifting while Europe pivots toward next-generation batteries. In fact, with the push from Asian companies already well underway and Northvolt the only European company actually building a new battery factory on the continent at the present time, it may already be too late for the EU to catch up.

A year ago, the EU announced a major initiative called the European Battery Alliance, which was designed to bring battery factories built by European companies to the continent. At that time, Maros Sefcovic, vice president of the European Commission, said, “We have to move fast because here we are in a global race. We need to prevent technological dependence on competitors.”

But Gerard Reid, founder of Alexa Capital, tells Reuters, “I don’t believe anyone in Europe can be competitive with the Asians.” His company advises firms in the energy, technology, and power infrastructure sectors. One factor is that Asian companies often benefit from significant subsidies from their governments. European companies will need billions in subsidies from the EU in order to compete.

Many in Europe remember what happened when local companies tried to cash in on the nascent solar panel market. They were soon swamped by cheaper imports from Asia. (For readers in America, please see Solyndra for more on this subject.) “Once burned, twice shy,” they reason. Maybe it’s better to let the Asian companies devour this particular pie while creating a whole new pie based on next-generation battery technology for the future.

“The development cycle and the speed of technology progress in batteries is so huge at the moment, there’s an opportunity for new and additional players to enter,” says Timo Moeller, head of the McKinsey Center for Future Mobility in Cologne. Diego Pavia, CEO of InnoEnergy, a sustainable energy company that has invested in Northvolt, agrees. “Everybody is developing solid state batteries so the gap (with Asia) will be narrower and narrower as we go along.”

Of course, we here at CleanTechnica know about solid-state batteries and the painfully slow pace of progress transitioning basic research into commercial reality. Based on that knowledge, Pavia’s pronouncements may be entirely too glib. But some European investors are pondering the commercial opportunities presented by making so-called “green” batteries — ones that are made in Europe by European companies using local workers and 100% renewable energy from locally sourced raw materials. Exactly where Europe might find local sources of cobalt is unclear in that scenario, however. Perhaps those next-generation solid-state batteries will require little to no cobalt.

Remember when U.S. states started voting renewable portfolio standards (RPS) into law? Iowa had the first and it was passed in 1983 requiring investor-owned utilities to build or procure 105 MW of alternative energy generating capacity. (Funny how small that amount is — 105 MWs would not even qualify as a “large” wind farm today).

Other states followed Iowa, creating statutes with renewable energy targets all the way through the 2000s, at which time states then began to modify their goals. Today, states are still upping the ante. California, New York and Hawaii boast the most aggressive RPS’s having modified their original goals multiple times.

These early RPS’s were indications that states were serious about forcing utilities to incorporate renewable energy into their energy portfolios.

In April, we witnessed two historic laws that once again showcase state leadership on clean energy. Hawaiian legislators passed the Ratepayer Protection Act, which directs utilities and the PUC to come up with mechanisms to reward utility performance such as affordability, reliability, customer engagement, integration of renewable energy and timely execution of competitive procurement. Utilities in Hawaii will no longer be able to “rate-base” capital expenditures but will instead be rewarded for meeting these new metrics. How? No one is sure yet. As State Senator Stanley Chang told me, “this is uncharted territory.”

On the other side of the country, the District of Columbia proposed the Distributed Energy Resources Authority Act, a law that would establish an independent body that ensures DC utilities look at non-wires alternatives whenever they propose to spend more than $25M on construction to expand capacity or enhance reliability. The independent body would determine if any of the capacity or reliability requirements could be met with energy efficiency, demand response or distributed energy resources like solar and storage.

These two laws (DC’s has not passed yet) represent very big changes for our utility system and are baby steps toward the utility of the future. Hawaii’s Senator Chang told me in an interview that he thinks these movements are the wave of the future and I agree. “I think we will see a lot more of this around this country and around the world,” he said.

When Vaclav Smil writes about energy, the world pays attention. “I wait for new Smil books the way some people wait for the next Star Wars movie,” Bill Gates once tweeted.

Smil is a professor at the University of Manitoba, and one of his key arguments is that the world is unlikely to transition away from fossil fuels fast enough to avoid catastrophic climate change. His observation is based on previous energy transitions, such as from wood to coal and from coal to oil, which moved very slowly.

But Smil says one technology could change the prevailing trends: energy storage. “Give me mass-scale storage and I don’t worry at all. With my wind and [solar] photovoltaics I can take care of everything,” he told Science. “But we are nowhere close to it.”

Better energy storage could overcome the biggest limitation of renewable power: Instead of using it only when the sun is out or the wind is blowing, electricity generated by renewable sources could be held for when it is most needed.

Mass-scale energy storage already exists, but there is only one mature technology: pumped hydro storage. When there is excess power on the grid, this technology is used to pump water to a dam. When the grid needs more power, the stored water is used to run turbines to generate it.

Other technologies feature electrochemical storage in the form of batteries, electro-mechanical storage in the form of compressed air or flywheels, and thermal storage in the form of hot or cold materials in insulated chambers. These comprise a tiny share of overall energy-storage capacity, according to a new report by policy group REN21.

The UK is pioneering a new way to store power with the world’s first grid-scale liquid air energy storage plant.

The Pilsworth liquid air energy storage (LAES) plant, which is owned by Highview Power, opens on Tuesday in Bury and will act as a giant rechargeable battery, soaking up excess energy and releasing it when needed.

This is particularly useful with the rapid growth in renewable energy, which accounted for 29 per cent of all electricity generated in the UK in 2017. It generates excess power when the sun is shining and the wind is blowing but is not reliable at times of peak demand.

Coal-fired power stations that typically handled peak electricity demand are being shut down and National Grid, which owns and operates the electricity transmission network, pays small gas and diesel generators to bridge the gap.

LAES is another, non-polluting option, according to Gareth Brett, chief executive of Highview Power, which developed the technology. “LAES is arguably the only viable, long-duration, locatable energy storage technology available,” he said.

He added that the system, which was developed in conjunction with Birmingham university, has 33 patents and is cheaper than batteries at large scale. It is also more durable: plants last for up to 40 years and can be installed anywhere.

LAES works by cooling air to -196°C, transforming it into a liquid that is stored at low pressure in insulated tanks. When power is needed the liquid air is pumped to high pressure and heated. The result is a high-pressure gas that is used to power a turbine and create electricity.

The Pilsworth plant has a capacity of five megawatts and can store 15 megawatt hours (MWh) of electricity — enough to power about 5,000 average-sized homes for around three hours. A commercial-scale plant would have a capacity of 50mw.

Plans hinge on Question 3 legislation

Battery technologies are all the craze these days as everyone is racing to find the perfect solution to energy storage for the growing share of solar and wind power in the grid.

But energy storage solutions are also making forays into the railways industry where batteries can help stabilize the railway electricity grid.

One new battery storage solution, developed by Italy-based power group Enel, will be tested and installed on the network of the Russian Railways.

“This is the first time this type of battery technology is used in the railway sector,” Enel, which has a very strong international renewables business, said upon announcing that it would test the “first-of-its-kind innovative storage system on Russia’s railway network.”

Enel and Russian Railways will team up to develop the energy storage solution in the hopes that it could help stabilize the Russian railway electricity grid, improve train operations, and avoid expensive grid upgrades that might otherwise be required.

While Enel was scarce on details in the announcement, CleanTechnica obtained more information from the Italian company about what this “first-of-its-kind” innovative storage system is.

The batteries will be lithium, with a minimum capacity of 10 MWh, Enel told CleanTechnica. At times of peak demand, the batteries can be automatically activated through an Enel in-house software to help respond to the growing energy demand of the railways system. Once installed on certain railway sections, the batteries could help make the train service faster, Enel says.Related: Why U.S. Oil Exports Are Only Heading Higher

The power company plans to couple the energy storage system with regenerative braking technology. This regenerative braking tech uses the energy that the train generates when it brakes to charge the batteries. The energy will be stored in the batteries for later use, which could help the railway network to reduce its overall energy consumption.

However, the Enel technology is still in a development and test phase—it’s not ready to be installed on the network of the Russian Railways yet.

The partnership with Russian Railways will entail a testing phase of up to three months, which is expected to begin by the end of 2018, Enel told CleanTechnica. During the test phase, Enel will install a single battery in a laboratory at Russian Railways, where the energy storage technology can be tested for performance in a controlled environment.

Swedish energy giant Vattenfall has found a way to further cut the cost of grid-scale energy storage: share the infrastructure with a wind farm.

The company has announced the commissioning of what it said was “the largest co-located battery installed in the United Kingdom” — a 22-megawatt plant, which shares electrical plans with the Pen y CyMoedd wind farm in Wales.

Developers of many current and upcoming wind projects are studying energy storage as a way of earning extra revenues from arbitrage, by storing power until it can be sold for a higher price. But in Vattenfall’s case, the wind and battery plants will operate independently.

The 76-turbine wind farm, which is Vattenfall’s largest onshore project and also the biggest in England and Wales, was opened for business in September 2017 and delivers up to 228 megawatts of power direct to the U.K. grid.

Pen y Cymoedd is capable of meeting the equivalent electricity needs of more than 13 percent of households in Wales and displaces an average of around 331,000 tons of carbon dioxide from fossil-fueled generation every year, said Vattenfall in a press release.

The GBP £400 million ($532 million) project was officially opened in September 2017.

The battery system, meanwhile, shares electrical infrastructure with the wind farm but earns its keep by delivering ancillary services, and specifically enhanced frequency response, to electricity network operator National Grid.

The battery system is made up of six shipping container-sized units, five of which house 500 i3 BMW-manufactured battery packs. Each of the new BMW lithium-ion batteries has a capacity of 33 kilowatt hours and is adapted for stationary storage applications, Vattenfall said.

In March last year, Vattenfall inked a deal with BMW Group for a supply of batteries originally destined for the i3 electric vehicle series. The energy company committed to buy 1,000 of the lithium-ion batteries.