“You could say that maybe 10 or 12 years ago, it was interesting and cutting edge, then it sort of went and fell by the wayside, a lot of companies went into administration; and now we’ve come out of the other end now.”

For some people, like Adam Bond of fuel cell maker AFC the interest in hydrogen and fuel cells in terms of repowering the planet with cleaner energy, never went away. While a few years ago, we observed efforts in Japan to build on years of academic work in the technologies through launching vehicles for the consumer market, it’s fair to say that hydrogen, and its use in conjunction with fuel cells, was put aside by some of its early big players.

This week at the Solar & Storage Live show in England, Energy-Storage.news met with system integrator and inverter maker Multi-Source Power (MSP), the CEO of which in turn introduced us to Alkali Fuel Cell (AFC). MSP chief exec Simon Patterson told Energy-Storage.news that in addition to working with battery and energy storage system providers such as Tesvolt, as we had heard in the past, MSP is now also working with the fuel cell player, in this case developing technologies to charge electric vehicles through strategically-sited systems placed in so-called ‘soft grid’ locations.

“The core of our product is in our flexible inverter technology, which allows us to integrate multiple energy sources. That can mean energy storage, power generation or in this case, a novel power source, which is AFC’s fuel cell.”

AFC’s Adam Bond agrees with the assessment that a lot has changed in the fuel cell space over the past decade or so, but disagrees that the exit of many companies, particularly big names, mean the battle for a place for fuel cells in the energy transition is far from over.

“The hydrogen economy has largely been driven by academic institutions. AFC stands for Alkali Fuel Cell: our technology was originally used in space programmes, so it was ‘the original’ and from there you’ve seen different variants of fuel cell,” Bond said.

“But as the renewable market starts to kick in, prices go down, everyone realises that there’s a gap in the market for a baseload clean energy solution.”

The supplier of what has been touted as “one of the largest” grid-connected batteries in the world, to be installed alongside the 200MW Solar River Project in South Australia, has been revealed as GE Renewable Energy.

In an announcement on Thursday, GE said it had been selected to supply and integrate a 100MW/300MWh big battery for the 200MW solar PV plant.

By our calculations, if built now, it would be the biggest lithium ion battery in the world, besting the Tesla big battery at nearby Hornsdale which stands at 100MW/129MWh. However, other big batteries may beat it to the title before it is completed as several are under construction in the US.

Construction of the Solar River Project is due to get underway by Christmas this year, after its developers snared a power purchase agreement with major utility, Alinta Energy.

That deal, announced in July, locked in finance for the $480 million project, which is being developed by Jason May and Richard Winter near Robertstown, in South Australia’s mid-north, the starting point for the proposed new inter-connector to NSW.

The company has not disclosed the financial details of the 15-year PPA, but told RenewEconomy at the time that the deal with Hong Kong-owned Alinta was for 75 per cent of the solar farm’s output, making Solar River “very bankable.”

At that time, the supplier of the battery system remained a mystery, but May, who is the Solar River Project CEO, suggested the decision had already been made.

“This is the first purpose-built PV battery system in the world,” he told RE. “It’s never been deployed before, but because of who (the company supplying the battery) are, it can be banked.”

In comments this week, May said locking in GE as the supplier of the big battery system marked another major milestone for the project.

“General Electric is a world leader in renewable energy storage technology… (and) brings a cutting-edge technology to South Australia, by delivering huge energy transfer capacity with an intelligent operating system,” May said.

The world has watched on as some of its leading regional markets, China, South Korea, Australia, Japan, parts of the US, the UK, and many parts of Europe have raced ahead in deploying energy storage in the last five years, mostly, but not only, lithium-ion batteries. IHS Markit says that the US in 2019 will deploy around 712MW, becoming the world’s largest market for grid-connected batteries this year, while another research firm, Wood Mackenzie Power & Renewables, has predicted that 4.3GW could be installed worldwide during 2019.

Record-breaking figures have been reported in the US and other territories such as the UK, year-on-year. Yet from other territories reports come in of interminable delays, of hotly contested jurisdictional rights, the difficulty in overhauling not only the technical design of the grid but the ways in which we think about energy markets too. Everyone seems certain energy storage is a key part of the decarbonised energy system, but no one seems certain when we will be able to breathe a sigh of relief that that place is assured. And of course, there’s the question of whether success in these leading markets can be replicated all over the world.

In those leading regions, the rapid rise is happening both in front of and behind the meter, with economic cases that are finally starting to make sense and often – but not always – with specific policy support. And while solar industry investor and commentator Jigar Shah predicted confidently that utilities would try to take ownership of energy storage as much as they could themselves at the beginning of 2018, it seems as though 2019 was the year that this really took shape.

A quick case study of a utility in one of those ‘leading regions’ is municipal power provider LADWP in California, which over the next few years will deploy enough batteries to cover more storage output and capacity than its existing 1.5GW pumped hydro plant. We also asked Janice Lin and Jack Chang at consultancy Strategen, itself based in California, to write about the ‘challenges in the sun’ California faces and some of the initiatives, both private and public, that are seeking to overcome them (see p.32 of PV Tech Power Vol.20 and on this site here).

Meanwhile in Australia, major utility AGL is now offering rebates of up to AU$7,000 (US$4,811) off the cost of residential ESS purchases, as well as a virtual power plant programme which benefits homeowners in some states to the tune of AU$280 credit for a year for enrolling.

Last week, the city of Los Angeles inked a deal for a solar-plus-storage system at a record-low price. The 400-MW Eland solar power project will be capable of storing 1,200 megawatt-hours of energy in lithium-ion batteries to meet demand at night. The project is a part of the city’s climate commitment to reach 100 percent renewable energy by 2045.

Electricity and heat production are the largest sources of greenhouse gas emissions in the world. Carbon-free electricity will be critical for keeping the average global temperature rise to within the United Nations’ target of 1.5 degrees Celsius and avoid the worst effects of climate change. As world leaders meet at the United Nations Climate Action Summit next week, boosting renewable energy and energy storage will be major priorities.

Wind and solar skeptics are quick to point out that such systems are expensive and can’t keep the lights on 24/7. The first argument is wilting as renewables become cost-competitive with fossil fuels. The second one also boils down to cost: that of energy storage, which will be essential for sending large amounts of renewable energy to the grid when needed.

“Low-cost storage is the key to enabling renewable electricity to compete with fossil fuel generated electricity on a cost basis,” says Yet-Ming Chiang, a materials science and engineering professor at MIT.

But exactly how low? Chiang, professor of energy studies Jessika Trancik, and others have determined that energy storage would have to cost roughly US $20 per kilowatt-hour (kWh) for the grid to be 100 percent powered by a wind-solar mix. Their analysis is published in Joule.

That’s an intimidating stretch for lithium-ion batteries, which dipped to $175/kWh in 2018. But things look up if you loosen the constraints on renewable energy, the researchers say. Then, storage technologies that meet the cost target are within reach.

The team picked four locations—Arizona, Iowa, Massachusetts, and Texas—and gathered 20 years of data on those solar and wind resources there. Such resources can change considerably with the seasons and over the years, and their longer-term analysis—while previous studies had used data from just a year or two—captures the variations that may occur over the lifetime of a power plant, the researchers say. They modeled the costs of wind-solar-plus-storage systems that would reliably meet various grid demands, such as providing baseload energy 24/7 and meeting peak-hour spikes in demand for a few hours.

Additions of new residential energy storage capacity in the United States reached a record high in the second quarter of the year, exceeding 30 MW, a new report by Wood Mackenzie says. The market for energy storage in the country is growing fast, the authors note, driven by customer interest and government incentives.

In May this year, IHS Markit forecast grid-connected energy storage capacity would jump twofold by the end of 2019, from 376 MW last to 712 MW. There may be a good chance of such an increase taking place: total new storage additions during the first half of the year were over 200 MW, with 148.8 MW deployed during the first quarter and 79.5 MW deployed during the second quarter.

According to Wood Mac, the reason for the slowdown in total storage capacity additions was due to a sizeable fall in front-of-the-meter storage additions. These, however, would pick up in the second half of the year, the consultancy said, with the pipeline for new FTM storage projects soaring 66 percent from a year earlier.

“The nascent energy storage market in the U.S. continues to grow in fits and starts,” said Wood Mac’s head of energy storage, Dan Finn-Foley. “But signposts such as the record residential storage quarter, massive FTM pipeline growth, and innovative policies such as the Massachusetts clean peak standard point towards an industry that is maturing and should stabilize at scale over the next two years.”

Energy storage used to be a neglected part of the renewable energy bet until it became clear that there could be no renewable energy transformation without it. Solar and wind power systems need storage capacity in order to be able to compete with power generation plants on reliability. Now, with the costs of battery components falling and tax credits, the energy storage industry is exploding.
Related: World’s Top Oil Trader Sees Oil Prices Weakening This Year

Both IHS and Wood Mac have upbeat projections about the medium term. Despite the temporary sequential drop in total new energy storage additions in the second quarter—down 49 percent on Q1—both consultancies expect total energy storage capacity to enter gigawatt territory soon and reach between 5 GW and over 10 GW by 2024.

IHS Markit sees capacity as of 2025 at almost 5 GW. Wood Mac is a lot more optimistic, forecasting over 10 GW in energy storage capacity by that year, of which more than two-thirds in California. A third, more cautious forecast, by Global Market Insights, sees U.S. energy storage capacity hitting 3 GW by 2025.

Enwave Australia has been appointed by the Western Australian Government to develop Australia’s first ever industrial renewable energy microgrid at the Peel Business Park in Nambeelup.

The microgrid will use a solar farm and battery storage with electricity supplemented from the Western Power grid when required, to power the 120-hectare lot within the park.

The microgrid is an innovative solution to the high costs of extending the mains grid into the estate, and will speed up the development of industrial land and development opportunities for the Business Park delivering much needed jobs to the region.

The microgrid will it make it possible for 1862 jobs to be created in the first 120ha lot, with a further 2000 local jobs once the park is fully built out.

The Peel Business Park has the potential to inject around $1 billion into the State’s economy each year.

In addition, the microgrid will offer businesses looking to relocate into the Park a saving of around 30 per cent off their yearly power bills.

Furthermore, to meet the increasing power needs of the Peel Business Park as it grows, the operator can lease roof space from businesses to install a network of solar panels that will feed additional energy into the microgrid.

The microgrid can also be increased in size and is expected to extend beyond LandCorp’s current landholding within the Peel Business Park, with potential uptake from interested neighbouring landowners.

WA Regional Development Minister, Alannah MacTiernan, said, “The Peel Business Park in Nambeelup is being created for forward-thinking businesses and this next generation thinking is reflected in the park’s proposed microgrid.

“The microgrid offers clear incentives for businesses to relocate to the Peel Business Park, helping to drive job creation in the Peel region.

“The Peel Business Park and Transform Peel are part of the McGowan Government’s commitment to driving industry diversification, investment and job opportunities in our regional centres.”

WA Lands Minister, Ben Wyatt, said, “The McGowan Government’s vision for the Peel Business Park is a place where business, industry, training, research and development come together, invigorating the Peel region and creating jobs that cannot be achieved without providing a secure and affordable power supply.

Germany must embrace renewables and energy storage at an unprecedented scale if it hopes to offset the void left behind by coal and nuclear phase-outs, a new study has said.

A review sponsored by German solar association BSW found Germany will have to drive a structural shift in its energy system to satisfy future demand, set to rise even as the country’s existing generation fleet takes a “massive” hit from decommissioning.

The analysis by energy consultancy EuPD says Berlin will require a surge of installed PV capacity between today (48GW), 2030 (162GW) and 2040 (252GW) to plug the energy shortfall, which could soar to 70TWh by 2030.

The boom, the document claims, should not only cover the large-ground mounted PV segment (from 15.7GW capacity today to 126.7GW by 2040) but also extend to C&I (from 24GW to 91GW) and domestic (from 6.6GW to 35GW) PV installations.

The transformation, the study notes, will fail to take hold unless Germany pairs renewable growth with that of energy storage. According to EuPD, a mix of cheaper technology and rising demand could see the nation-wide market boom from 1.9GWh today to 59GWh by 2040.

Europe’s PV giant eyes subsidy-free transition
EuDP’s findings were used by German PV body BSW to renew its long-running campaign against the discontinuation of solar subsidies. Under current legislation, the 48GW industry will see state incentives frozen for new projects once capacity hits 52GW.

In a statement released alongside the study, BSW’s managing director Carsten Körnig urged cabinet ministers to make the “appropriate decision” when they meet to discuss the issue on 20 September. The 52GW PV subsidy threshold will be breached next year unless it is scrapped now, Körnig warned.

The industry efforts to retain government support come as more and more developers attempt subsidy-free ventures, a market Germany has been slower to embrace than Spain and other Southern counterparts.

Initially smaller zero-subsidy deals – such as BayWa r.e.’s 8.8MW and Axpo’s 1.5MW – are slowly giving way to far larger moves, including a 500MW pipeline proposed by THEE and CEE. However, the country risks stifling further PPA activity if it does not de-risk these deals, experts have warned.

The spotlight on storage as enabler of Germany’s energy shift comes as the sector teeters at the “edge of profitability”, as argued by analysts for a recent PV Tech Power article. Separate research has identified particularly strong economics for the country’s solar-plus-storage hybrids.

The second draft of the US National Fire Protection Association (NFPA) energy storage system guidance on fire hazards and safe installation best practice for stakeholders has been published.

The standard, NFPA 855, “provides requirements based on the technology used in ESS, the setting where the technology is being installed, the size and separation of ESS installations, and the fire suppression and control systems that are in place,” according to a NFPA release yesterday.

The association said it seeks to inform “designers, builders, facility managers, manufacturers, responders and others” about fire hazards. The NFPA noted that some ESS technologies are becoming increasingly energy dense, increasing their potential usefulness but also presenting challenges that require the first responders and the industry to “become educated and proactive about ESS safety.”

The standard has been in development since 2016 and has taken into account more than 600 public inputs and 800 public comments, while the NFPA also offers online training for fire service members, conducts research, offers factsheets to policymakers and makes resources available online.

Analysis – Andy Colthorpe, Editor, E-S.n
It is thought that the development of more unified standards across industry could not only help with safety but also help streamline installation and permitting processes among other benefits, if done correctly.

Previously, Roger Lin at NEC’s Energy Solutions division has told Energy-Storage.news of his role on the standards committee at NFPA, commenting that “there’s a lot of great stuff in there [ NFPA 855],” including “seemingly trivial” considerations that can end up causing serious problems. Lin noted also that in New York, considered to be the US state with the most stringent fire codes, NEC is testing lithium-ion battery systems to UL standards with New York’s fire department.

September 13 (Renewables Now) – The New York State Energy Research and Development Authority (NYSERDA) has completed what it says is the state’s largest battery storage system — a 20-MW installation in New York’s Capital Region.

The facility, called KCE NY1, was supplied by Key Capture Energy and will be used to enhance the state’s electrical system by improving power grid performance and reliability, thus helping lower greenhouse gas emissions. The project will also support the state’s target for 70% of its power to come from renewables by 2030 and for the deployment of 3 GW of energy storage capacity by the same year, NYSERDA said on Thursday.

Key Capture Energy is part of the START-UP NY programme, administered by Empire State Development, which helps new and expanding businesses through tax-based incentives and academic partnerships. The Albany-based firm is partnering with the University at Albany.