Elon Musk’s Tesla company last year built the world’s most powerful battery, but a new project means it could soon be out of the record books.

British billionaire Sanjeev Gupta is behind the development of a 120 megawatts/140 megawatt-hours storage facility, which will be larger than the 100 megawatt/129 megawatt-hours battery constructed by Tesla in Jamestown, South Australia, last year.

The new battery storage facility will be built at a location less than 100 miles from Tesla’s effort and be linked to a new solar farm at the Whyalla Steelworks, a site recently acquired by Gupta’s Liberty House firm when it bought Australian mining and materials company Arrium last year, ABC News reported.

The plan for another mega-battery reflects South Australia’s ongoing interest in renewable energy that was largely motivated by a widespread power outage that hit the state in 2016 during a huge storm. Described as a once-in-every-50-years weather event, the storm temporarily cut power for 1.7 million residents in Adelaide and the surrounding area, and served to focus the minds of local officials as they sought an effective solution to ensure that such serious outages could never happen again.

South Australia currently sources nearly 50 percent of its power from wind and solar, and according to outgoing South Australia premier Jay Weatherill, the new battery will “help underpin the long-term viability of the Whyalla steelworks, as well as provide additional benefits to the South Australian grid.” Construction will begin later this year.

The age of storage serving peak power has only just begun, so the size of that market is very much up for debate.

California has already halted a new gas plant in favor of deploying energy storage in its place. Elsewhere, regulators called on PG&E to acquire storage instead of paying to maintain two existing gas peaker plants. An Arizona utility recently procured asolarand battery project specifically to serve capacity for system peak hours.

These are early signs of a dramatic shift in how the grid gets electricity when demand is highest. “The amount of press written on storage as a peaker replacement has grown tremendously over the last several years,” said Paul Denholm, a researcher at the National Renewable Energy Laboratory. “My concern was, this might be exciting, but is there a real market there?”

When a new market appears and draws investment, it comes with the risk of proving shorter-lived than developers hoped. That dynamic played out in the early storage market for frequency regulation in PJM, which has mostly dried up due to oversaturation and rule changes.

Denholm and colleague Robert Margolis decided to test the market potential for storage-as-peakers, using load data and simulated solar PV production from California. Their new study suggests that peak power in California alone constitutes a massive market opportunity, which will continue to grow as solar capacity increases.

First, Denholm and Margolis established a baseline of how much storage could compete for peak capacity without any intermittent renewables to deal with. They modeled 4-hour storage, because that’s the threshold that California rewards with a full resource adequacy credit. As more batteries come online, they incrementally flatten the peak, eventually requiring longer-duration units to meet additional peak demands, as illustrated in the following chart.

The US Department of Energy recently floated the idea of carving out a place for small coal power plants in the distributed energy landscape of the future, but it looks like the agency’s latest attempt to save coal is a day late and a dollar short. In the latest development, GE has just begun pitching a new energy storage project with the evocative name The Reservoir, and it puts the prospect of a coal powered future where it belongs: on the shelf.

Last week CleanTechnica grabbed a few minutes on the phone with Eric Gebhardt, GE’s Vice President and Strategic Technology Officer, to get some insights into the Reservoir, and he had something to say that will bring little comfort to coal fans.

So, What Is The Reservoir?

When GE announced The Reservoir, it made the implications for renewable energyabundantly clear. GE described the new energy storage project as a “comprehensive” platform that “delivers a suite of customized storage solutions to help customers address new challenges and seek new opportunities in a rapidly transforming power grid that is becoming more highly diversified and distributed.”

That’s kind of a mouthful. What it means in practice is a lesson that grid planners have already absorbed: the old model of large scale, centralized energy generation is, well, old.  The rise of digital technology, renewable energy, and distributed energy have resulted in a “paradigm shift” in energy generation and distribution.

Gebhardt’s statement in a press release for The Reservoir is definitive on that score:

GE’s Reservoir platform enables cost-effective distribution, storage, and utilization of cleaner, more reliable power where and when it is needed most. It can fit into most any setting, from centralized grid systems to the most remote villages and communities. The Reservoir also allows energy providers new degrees of flexibility for more intelligently managing and getting the most out of all their power assets.

That sounds pretty fancy, right? The innards consist of a fairly standard lithium-ion energy storage arrangement of 1.2 megawatts and 4 megawatt-hours, but all the system control and operation overlays are exclusive to GE. The “reservoir” name evokes energy storage but it could just as easily refer to the storehouse of knowledge GE brings to the design. Here’s another snippet from the press release:

…It is a modular solution that integrates GE’s Battery Blade design (module stack design) with key technologies from across the company’s portfolio to achieve an industry-leading energy density, footprint and lifetime performance. GE’s proprietary Blade Protection Unit (BPU) actively balances the safety, life, and production of each battery Blade, extending battery life by up to 15 % and reducing fault currents by up to 5X.

Vertically integrated energy company Scottish Power has submitted a proposal to extend recently introduced battery de-rating factors in Britain’s Capacity Market to storage included in demand side response bids in what has been described as a latest attack on the battery market.

The utility submitted the proposal on 13 March, which would create DSR technology classes with different minimum durations, and apply the extended performance testing to these newly created groups.

Among these would be a ‘Storage DSR’ class, which National Grid’s electricity market reform delivery body would be obligated to consult on applying the lower de-rating factors to.

Scottish Power argues that under current market rules if a DSR CMU (Capacity Market Unit – “a unit of electricity generation capacity or electricity demand reduction that can then be put forward in a future Capacity Market auction” according to the government definition), consisting of energy storage, is located behind the meter (BTM) it will not be subject to duration de-rating.

“This risks over-rewarding such storage and increasing costs to consumers. It is also contrary to the CM policy of technology neutrality and unfair to other market participants,” the company stated.

It adds that without such a change, storage developers are able to bypass the extended performance tests which are applied to capacity storage generating technology classes by going behind the meter.

The proposal suggests that each applicant for an unproven DSR CMU “must include details of any known intention to use a generating unit that is categorised as a DSR storage technology class”, a suggestion that has been refuted by those offering behind the meter battery services for DSR.

The agreement will see Rolls-Royce combine its material science and technical expertise with Superdielectrics’ novel hydrophilic polymers that have been shown, in partnership with researchers from the Universities of Bristol and Surrey, to have potentially outstanding energy storage properties.

Dr Dave Smith, director of Central Technology, Rolls-Royce, said: “We believe that electrification will play an increasingly important role in many of our markets over the coming years and by working with partners on potential new technologies for energy storage we can ensure that Rolls-Royce is well positioned to take advantage of new developments.”

Jim Heathcote CEO of Superdielectrics, said: “We are delighted to be working with Rolls-Royce in the global race to develop advanced energy storage systems. This agreement gives us access to their unparalleled scientific and technical expertise. I hope this agreement will ultimately create new jobs and business opportunities in the UK.”

Working with researchers from the Universities of Bristol and Surrey, Superdielectrics has been developing hydrophilic materials, similar to those originally designed for soft contact lenses, to increase the electricity storage capabilities of capacitors, which store electricity by creating electrostatic fields.

These dielectric polymers may provide an opportunity to create capacitors that are able to rival – and even exceed – the storage capacity of traditional rechargeable batteries. The resulting supercapacitors may also be able to charge much faster than existing lithium-ion batteries.

According to the current estimate of the German Energy Storage Association (BVES), the energy storage industry will grow by around 11% in 2018 and will generate a turnover of approximately EUR 5.1 billion. Medium-sized companies are the main driving force behind this increase. The development of Energy Storage Europe reflects this industry trend: With a total of 170 exhibitors and about 4.500 visitors, this year’s energy storage trade fair and the two conferences ESE and IRES continued the positive development of the past years.

“No other trade fair in the world covers the entire spectrum of energy storage solutions. Every year, new players enter the still young market with innovative solutions – often with new technological approaches to energy storage,” stated Hans Werner Reinhard, Managing Director of Messe Düsseldorf.

Urban Windelen, Executive Director of the BVES, added: “Energy Storage Europe 2018 once again demonstrated the solid growth of the industry across all storage technologies and various applications. The event is the decisive international business platform for energy storage systems and its success confirms the growing industry figures predicted by the BVES.”

Increasing international participation
Internationalization is a further industry trend apparent in the visitor structure of Energy Storage Europe and the IRES Conference: this year, the organizers welcomed delegations from Mexico, Costa Rica, El Salvador and other Central American countries as well as from Greece, Norway and Poland, Portugal. Overall, participants from 61 countries attended the conferences and trade fair.

Nearly 50 public utilities have yet to account for the recent corporate income tax cut in their transmission rate formulas, and the Federal Energy Regulatory Commission wants to know why.

FERC is asking the utilities to explain why they are still showing a maximum 35 percent corporate tax rates in their formulas which ultimately factor in costs for customers. The corporate income tax rate was cut to a flat 21 percent as part of the Tax Cuts and Jobs Act signed by President Trump into law late last year.

One of FERC’s show-cause orders identified 34 generation and/or integrated utilities still including the higher rates in their costs when it should have been reduced beginning January 1. Those companies include Avista, El Paso Electric, Florida Power & Light, Potomac Edison, Portland General Electric, Dayton Power & Light and Tucson Electric, among others. (See the complete order here).

“When tax expense decreases, so does the cost of service,” FERC’s show-cause order reads. “The commission must ensure that the rates, terms and conditions of jurisdictional services under the FPA (Federal Power Act) are just, reasonable and not unduly discriminatory or preferential.”

The second show-cause order focused on transmission rate formulas with 12 utility units of larger holding companies. Those include AEP’s transmission units Appalachia, Indian Michigan, Kentucky, Ohio, West Virginia, Oklahoma and Southwestern. (See order here).

Other utilities named in that order included Baltimore Gas & Electric, Black Hills Power, San Diego Gas & Electric, Transource and UNS. The parties named in the orders have two months to respond once the notice is published in the Federal Register.

The FERC notice also questioned the same issue with interstate natural gas pipeline companies. The cost of fuel transport and expense also are reflected in utility’s customer rate formulas filed with state regulators, many of which have expressed a desire for those cuts.

Energy storage is a tough concept to grasp. And until now, it’s been an even tougher technology to deploy. But the market for such technology is forecast to exceed the previous four years in this year alone because of falling prices and favorable policies.

Most people envision energy storage as a system that siphons power from the grid at night and harnesses that electricity inside of a device. It is then released during the day at peak demand. That’s coming — and the evidence is starting to mount. The more immediate application, though, is infusing the grid with electrons if the lights start to flicker out.

What’s the proof that the energy storage market is getting past its infancy? GTM Research and the Energy Storage Association have just released the U.S. Energy Storage Monitor 2017 Year-in-Review, which says that 1,000 megawatt-hours were deployed between 2013 and 2017 and which predicts that more than 1,200 megawatt-hours of energy storage will get deployed in 2018 alone; last year, it was 431 megawatt-hours. Altogether, GTM estimates that the annual value of the U.S. energy storage market will exceed $1.2 billion in 2019.

Moreover, the Federal Energy Regulatory Commission voted in mid February to allow grid managers to compensate energy storage in the same way they do traditional power generators. Energy storage would thus graduate beyond the injection of electrons to prevent lights from flickering out and into the wholesale energy markets.

The regional transmission organizations and independent system operators are required to present their plans on how to achieve the commission’s goals later this year. The PJM Interconnection has delivered about 250 megawatts of cumulative energy storage power since 2013. California’s Independent System Operator is also actively trying to incorporate energy storage into mix of generation assets, as PG&E Corp., Sempra Energy and Edison International must collectively buy 1,325 megawatts of energy storage by 2020.

The San Diego County Water Authority is expecting to save approximately $100,000 per year with commercial-scale batteries installed at the agency’s solar-powered Twin Oaks Valley Water Treatment Plant near San Marcos.

The energy storage system is designed to reduce operational costs at the facility by storing low-cost energy for use during high-demand periods when energy prices increase.

The batteries were installed at no charge to the agency as part of an agreement with Santa Clara-based ENGIE Storage, formerly known as Green Charge.

The system charges from either the grid or on-site solar energy production to store energy. ENGIE Storage’s GridSynergy software allows the water authority to use that energy for plant operations during high-demand periods when market prices typically peak. At the Twin Oaks facility, on-site energy is generated by more than 4,800 solar panels that produce an estimated 1.75 million kWh of electricity each year.

“Energy storage is a strategic addition to the water authority’s solar energy installations, which have already reduced power costs and made the agency more environmentally friendly,” says Mark Muir, chair of the water authority’s board of directors. “This project is a good example of how we continually look for ways to maximize investments in the regional water treatment and delivery system to the benefit of our ratepayers. This includes advances in our growing list of energy initiatives.”

ENGIE Storage installed the batteries at Twin Oaks through a power efficiency agreement to install, at no cost to the water authority, a 1 MW/2 MWh energy storage system. ENGIE will own, operate and maintain the $2 million system on water authority land for 10 years, after which the agency can choose to extend the agreement, purchase the batteries, or have them removed and the site returned to its original condition.

A $1 million incentive from the California Public Utilities Commission (CPUC) helped fund the project. The incentive, awarded in 2017 under the CPUC’s Self Generation Incentive Program, encourages the adoption of energy storage technologies that reduce both electricity demand and greenhouse gases.

GE has released a containerized energy storage product with a competitive advantage for installation time.

The 1.2-megawatt, 4-megawatt-hour Reservoir system marks a new entry into the standardized, large-scale battery market. It reflects a strategic shift at GE’s storage practice, which recently reorganized after an initial foray into battery manufacturing and a detour in commercial and industrial energy services.

Reservoir sounds like many other containerized battery solutions already available from companies like Fluence, BYD, Mitsubishi, LG, Samsung and others. The goal is to lower costs to developers by standardizing the product and factory-testing the enclosures for quality control.

What GE does differently is ship the containers fully loaded.

“We will fully assemble and test the equipment in a controlled environment and drop ship to the site fully assembled,” said Eric Gebhardt, vice president and strategic technology officer at GE Power.

Typically, containerized battery systems ship without the battery cells inside, due to weight, safety or quality concerns. GE bucked the trend by designing a box that can travel with batteries in place but disconnected. A technician with a hot stick can flip a switch onsite to reconnect the electrical circuit and get the system operational again.

That could cut installation time in half, Gebhardt said, because it eliminates time-intensive battery installation onsite.

This appears to be the first large-scale battery design with this capability.

The 50 percent cut to installation time “seems plausible and realistic,” said Ravi Manghani, energy storage director at GTM Research. That still leaves other tasks like putting in a transformer, wiring different containers together and connecting to the broader grid.

“These assets can come online and start making money faster than another system that has to be assembled onsite,” Manghani noted.