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.

Tesla is apparently significantly ramping up its effort to help rebuild the power grid in Puerto Rico after it was destroyed by hurricanes last year.

After having completed hundreds of energy storage project on the islands in the last few months, Tesla CEO Elon Musk now says that they have ‘about 11,000’ energy storage projects underway in Puerto Rico, which means something big is in the work.

Last month, Tesla CEO Elon Musk said that the company installed batteries at 662 locations in Puerto Rico.

We reported that they focused on critical services. For example, Tesla deployed a series of Powerpack systems on the Puerto Rican islands of Vieques and Culebra for a sanitary sewer treatment plant, the Arcadia water pumping station, the Ciudad Dorada elderly community, the Susan Centeno hospital, and the Boys and Girls Club of Vieques.

The automaker’s energy division also deployed a solar+battery system at a hospital in Puerto Rico.

While it’s one of the biggest examples of Tesla deploying energy storage systems in a single market, it now sounds like it’s only the beginning as Musk says that there are about 20 times more projects underway in Puerto Rico:

At the very minimum, it would be one Powerwall per project, which would add up to a deployment of at least ~150 MWh of energy capacity.

But that’s just the bare minimum since as we have recently seen, most projects include more than one Powerwall.

For example, we recently reported on a homeowner in Puerto Rico who received a 3-Powerwall installation that helped keep the lights on during the last power outage:

DNV GL, an Oslo, Norway-headquartered global quality assurance and risk management company that also acts as a certification body, handed the certificate to the Spanish conglomerate at WINDPOWER 2018 in Chicago this May. DNV GL’s certificate demonstrates the safety, performance, and reliability of ACCIONA’s hybrid plant for storing electricity in batteries as part of a grid-connected wind farm at Barásoain in Navarra, northern Spain.

The Barásoain plant has a storage system that consists of two batteries that are located in separate containers. One is a fast-response battery of 1 MW/0.39 MWh, which is capable of maintaining 1 MW of power for 20 minutes, and the other is a slower-response battery, though it has “greater autonomy” of 0.7 MW/0.7 MWh, maintaining 0.7 MW for 1 hour, said ACCIONA. Both employ Samsung SDI lithium-ion technology. The energy storage technology is connected to a single 3-MW AW116/300 wind turbine that uses ACCIONA Windpower (Nordex Group) technology. According to ACCIONA, the wind turbine is one of five that make up the Experimental Wind Farm at Barásoain, which it has operated since 2013. ACCIONA manages the entire system using control software it developed in-house. The system is monitored in real-time by the company’s Renewable Energies Control Center (Figure 4).

The certification milestone is important because while energy storage technologies are increasingly being deployed along with renewable projects at a grid-scale, a comprehensive standard that guarantees their safety and reliability is rare. The certification is designed to provide more certainty to industry, including technology designers and manufacturers, as well as auxiliary backers like investors, insurers, and government authorities, which often seek information about risk mitigation and cost controls, particularly for fledgling energy storage projects.

“Certifying new systems like ACCIONA’s grid-scale storage plant demonstrates that pioneering projects like this are meeting the required safety, performance and reliability standards and providing the industry with confidence in the quality of emerging new technologies,” said Kim Mørk, executive vice president, Renewables Certification at DNV GL.

According to Carlos Albero, global finance segment leader of DNV GL’s energy division, as well as providing a quality benchmark, the certification verifies ways a hybrid renewables-storage project can make money. “We’re not speaking about the batteries themselves,” he explained to POWER. “You are integrating the wind turbines with the storage platform, and at the end of the day, they have to work together.” Hybrid projects have the benefit of providing revenue streams from grid-related services, such as from frequency and voltage regulation. “So, these are the kinds of revenue considerations that will need to support storage projects in the future,” he said.