Electrochemical batteries have been around for more than 100 years and solar photovoltaic (PV) panels have been in use for half a century. During the early days of solar, users deployed PV panels to charge batteries in places far from a power line or gas station. Those batteries powered things like satellites, weather stations and remote homes. Around the turn of the century, people began connecting PV systems directly to the electrical grid.

At first, the grid connection was for purely scientific or ideological reasons, and, as regions and businesses offered incentives and PV sped down the cost curve, people used PV to save money on electricity. In 2004, PV systems installed without batteries outnumbered battery-based systems for the first time – by 2010, solar-plus-storage systems were relegated to a small niche of the booming solar industry. But now the industry is coming full circle.

In October of 2015, Hawaii’s public utilities commission became the first in the U.S. to start limiting grid-direct PV installations due to impacts on local grids from midday power exports. New systems would not be allowed to send surplus power back to the grid indiscriminately. Thanks to a small but thriving number of businesses that still installed off-grid and backup systems, many Hawaiian solar customers deployed batteries to ensure their PV output was stored for nighttime use rather than pushed back to the grid. The writing was on the wall: PV and batteries were not as separable as we thought.

Since then, utility rates in several more states have been made more sophisticated, in part to discourage the export of solar PV power onto the grid at inopportune times. The industry is responding by making batteries available to most new solar customers. While the added cost of the batteries can make the financial payback of these PV systems less lucrative than the direct grid models, batteries provide additional resilience and control for the system owner – which is increasingly important to consumers and businesses alike. All of the industry signs are clear: storage is going to be part of most solar PV systems going forward.

Sungrow is to partner with Huanghe Hydropower, providing PV inverter and energy storage systems for a major solar-plus-storage project in Qinghai Province, China.

Chinese developer Huanghe Hydropower Development is bringing forward the 202.86MW/202.86MWh solar-plus-storage project, selecting Sungrow’s 1500V SG250HX inverters alongside the manufacturer’s integrated energy storage systems.

Sungrow said the combination of the two technologies enabled shorter construction times and easier operations and maintenance, while also bringing additional benefits to the grid when operational. The system will come with an embedded sub-array energy management function that can, in turn, be used to control the output of the solar farm by utilising its co-located storage capacity, allowing for improved accuracy of solar generation forecasts.

Huanghe Hydropower is developing the project within a hub of ground-mounted solar plants in a particularly remote region of China, selected for its high irradiation. These “bases” are then connected to transmission grids in the country using ultra-high voltage (UHV) technologies, facilitating the transfer of power from the west of China to the country’s densely populated east.

Describing the project as a landmark for the country, a spokesperson for Huanghe Hydropower said Sungrow’s energy management system was the first to pass functionality tests in controlling both solar PV and energy storage system output.

Jack Gu, senior vice president at Sungrow, said the combination of solar with storage and other technologies was critical to reducing the levelised cost of electricity (LCOE) further.

Zinc battery storage manufacturer Eos Energy Storage was awarded contracts for systems providing on-site power resiliency at an oil refinery in Greece.

New Jersey-based Eos has partnered with Motor Oil Hellas and Ingeteam on the two projects. Eos will design, build and deliver a 1-MW/4 MWh behind-the-meter battery system at Motor Oil’s Corinth Refinery in Athens.

“This project is not only our initial entry into the dynamic Greece energy storage market, but it’s also an opportunity to demonstrate the many advantages of our storage technologies including performance, safety, and environmental conditions,” said Joe Mastrangelo, CEO of Eos Energy Storage.

The project with Ingeteam calls for Eos to provide the full AC-integrated system for the INGECON Bseries inverter and miniskid MC solution and EMS plant controller.

The work at the Corinth Refinery is focused on helping lower costs, shaving peak demand and optimizing the site’s grid resiliency. The high temperatures of the Mediterranean climate post challenges for lithium ion chemistries which require HVAC additions, and the Eos’ zinc system does not, according to the release.

Eos will plan, design and commission its patented Znyth storage system. This technology employs a unique zinc-halide oxidation/reduction cycle packaged in a modular, sealed, static-cell, flooded, bipolar battery.

“We consider Eos battery technology as the most competitive and attractive one compared to Li Ion batteries, capable of offering a lot of opportunities in large scale BESS in the future,” said Vassilis Viziryiannakis, Head of Electricity Business of Motor Oil Hellas.

Merchant energy storage has become an investable asset class in the UK, a provider of battery optimisation services has said, with the market moving away from an emphasis on contracted revenue streams for supplying grid services.

Dr Ben Irons, co-founder at Habitat Energy, said that “three years or so ago, firm frequency response (FFR) contracts were where 100% of the action was for battery storage in the UK,” as battery storage became eligible to provide the grid-balancing service to transmission system operator (TSO) National Grid.

However, according to Irons, the idea of a contracted revenue stream “gave a false sense of security,” with contracts generally only two years long for FFR, and even the longer contracts award through the UK’s landmark 200MW tender for enhanced frequency response (EFR) were four years and were “quickly snapped up”.

Speaking to Energy-Storage.news following his appearance at last week’s online Energy Storage Digital Series conference – at which he explained instead that merchant opportunities including arbitrage have matured to provide decent revenues for Habitat’s clients – Ben Irons said that those two or even four years contracts were not “nearly enough to cover the investment horizon or reach a payback on capex, without coming back for a series of further contracts later”.

“The problem was there was no guarantee on the price for those subsequent contracts, as many early battery investors learned to their cost when the FFR price dropped from 19 to 5 £/MW/hr in the space of a couple of months,” Ben Irons said.

SAN FRANCISCO–(BUSINESS WIRE)–Pacific Gas and Electric Company (PG&E) has requested approval of five energy storage projects totaling 423 megawatts (MW), in a filing with the California Public Utilities Commission (CPUC).

The projects are intended to further integrate clean energy from renewable generation sources while ensuring future reliability of the electric system.

“PG&E is deeply committed to the California vision of a sustainable energy future. As we continue to integrate large amounts of intermittent renewable energy, we are now taking advantage of advancements in energy storage technology to ensure that customers continue to receive clean and reliable power from a flexible and dependable electric grid,” said Fong Wan, senior vice president, Energy Policy and Procurement, PG&E.

The agreements for the projects are a result of a competitive request for offers (RFO) PG&E launched in February following a November 2019 CPUC decision that identified potential reliability issues beginning in 2021.

The CPUC authorized utilities and other load-serving entities in California to procure resources that would address those potential future system reliability issues while building progress in meeting the state’s greenhouse gas emissions reduction goals.

PG&E was authorized to procure at least 716.9 MW of system reliability resources to come online between August 1, 2021 and August 1, 2023. The five new battery energy storage projects announced today represent PG&E’s first phase of procuring system reliability resources that need to come online within that timeframe.

PG&E will issue another (phase two) competitive solicitation this summer for resources to come online by August 1, 2022 and August 1, 2023.

“One can expect that the number of EVs in fleets will grow very rapidly over the next ten years,” according to Rhombus’ report. But that means many fleet staging areas will have trouble securing sufficient charging capacity.

“Given the amount of time it takes to add new megawatt-level power feeds in most cities (think years), fleet EVs will run into a significant ‘power crisis’ by 2030,” according to Rhombus.

“Grid power availability will become a significant problem for fleets as they increase the number of electric vehicles they operate,” Rhombus CEO Rick Sander said in a statement. “Integrating energy storage with vehicle-to-grid capable chargers and smart [energy management system] solutions is a quick and effective mitigation strategy for this issue.”

Along with energy storage, Guidehouse says a new, more flexible approach to charger deployment will help meet demand. That means chargers deployed by a van or other mobile stations, and “temporary” chargers that can help fleets expand capacity.

According to Guidehouse, the temporary units “are well positioned to de-risk large investments in stationary charging infrastructure” while also providing charge point networks and service providers “with new capabilities to flexibly supply predictable changes in EV transportation behaviors and demand surges.”

“Mobile charging is a bit of a new area in the EV charging scene. It primarily leverages batteries to make chargers mobile, but it doesn’t necessarily have to,” Guidehouse Senior Research Analyst Scott Shepard told Utility Dive.

“The biggest opportunity is with the temporary charging format,” said Shepard. “The bigger units are meant to be located at a certain site for a period of time. Those units are interesting because they create a little more scale-ability for sites and a little risk mitigation when it comes to investing in a site.”

“Utilities could use temporary chargers as a way to provide more resilient service, using these chargers in line with on-site generation,” Shepard said.

Long duration energy storage is an “essential” technology to help accelerate renewable deployment, according to the US Department of Energy’s Dr Imre Gyuk, but will require “appropriate regulatory frameworks”.

This is to ensure costs of the technology are covered in a well-regulated way, Gyuk said during a session entitled Making a Business Case for Long Duration as part of the Energy Storage Digital Summit that took place across last week.

Gyuk, who is the director of Energy Storage Research in the Office of Electricity at the DoE, said that across his 20 years of experience in the sector, he’s seen a “real evolution” of energy storage, so much so that is has now become “one of the hottest topics in the energy business”.

Projects in the US are only getting bigger, he said, with southern California to see 700MW of new storage in the ground by August 2021. Most of these are together with solar PV, which Gyuk described as the “essential feature”.

Whilst these are all 4-hour duration and all lithium-ion, eventually there will be a need for longer durations to work with PV for reasons including intermittency of generation and for storing and using energy overnight. This was echoed by fellow panellist Matt Harper, chief commercial officer of the vanadium flow battery provider Invinity Energy Systems – the company recently formed by the merger of redT and Avalon battery, two existing players in vanadium flow – who said that long duration storage would help “accelerate a high solar future”.

However, the interaction between long duration energy storage and solar was not the sole focus of the session. Speaking of the technology in comparison to lithium-ion, Gyuk said “we’re not totally happy with the incumbent lithium-ion”, citing sourcing problems, safety and reliability concerns and “above all” problems surrounding reuse, recycling and disposal.

This was a “very difficult issue” for lithium-ion, Gyuk said, although it is “perhaps not insurmountable”.

Researchers from Germany’s Helmholtz Institute Ulm (HIU) and the Technion – Israel Institute of Technology recently convened for a three-day discussion on the future of energy storage with a basic assumption: “The quest for post Li‐ion and lithium battery technologies is incorrect in its essence.”

The groups discussed the kind of storage technologies that might be considered solid alternatives to Li‐ion storage, and their conclusion was unequivocal: There is no end in sight for the “post Li‐ion” era.

“After extensive deliberations, the group concluded that the current vibe [!, ed.] about the need of future technologies after the lithium era and, thus, the quest for which new technologies can replace lithium‐based battery technology, are somewhat inappropriate and misleading (partially incorrect), respectively,” the researchers tried to say.

Instead, they have recommended a “side‐by‐side” approach for all storage technologies. They also identified the technologies that they see as more promising for the future.

Sodium‐ion batteries

Sodium‐ion batteries (Na‐Ion), which rely on the same ion storage principle of lithium-ion technologies, are considered an interesting alternative as they could provide an affordable solution, due to potential shortages of lithium and cobalt, or possible price surges. They are also easy to ship and have strong potential for further raw material cost reduction. “Actually, the cost and environmental friendliness of the layered oxide cathode materials proposed so far, appear to be the major advantages of sodium‐ion batteries,” the group stated.

It added that Na‐ion batteries face similar safety issues as Li‐ion batteries in large-scale applications, but development is still limited and not enough is known about failure modes, mechanisms, and analysis at the full cell level. Their use is recommended for stationary energy storage systems and light‐duty vehicles for short‐range transportation.

The Asian Development Bank (ADB) has signed a loan deal for its first wind energy-plus-battery storage project in Thailand, which is also the country’s first private sector initiative to combine the two technologies at scale.

The ADB told Energy-Storage.news this morning that it will lend THB235.55 million (US$7.2 million) for the construction of the Southern Thailand Wind Power and Battery Energy Storage Project, has added an “integrated” 1.88MWh battery energy storage system (BESS) to an existing 10MW wind turbine power plant. The addition of the BESS is being considered a pilot scheme that could go on to be replicated and scaled-up elsewhere in Southeast Asia. An ADB representative said the project “represents a number of firsts for ADB, particularly related to battery storage”.

While the majority of the turbines’ output will go straight into the local electrical grid, the BESS will store energy at times when the output exceeds the grid’s capacity to take it, increasing the amount of renewables that can go into the grid as well as helping to “ensure the stability and reliability of the renewable energy source,” the ADB said in its press release. The ADB representative confirmed today that the financing followed the project’s completion.

The multilaterally-owned bank has signed the loan deal with Lom Ligor Company Limited, a subsidiary of Thailand-headquartered renewable energy development company BCPG Public Company Limited (BCPG). BCPG purchased Lom Ligor Company in 2018, with Low Ligor the operator of the 10MW project at the time, in Pak Panang, Nakhon Si Thammarat Province. It was BCPG’s first foray into wind energy in Thailand.

The ADB loan includes US$4.75 million in concessional loan financing from the Clean Technology Fund of the international Climate Investment Funds, which has provided financing for development efforts relating to climate. Private Thai banking group Kasikornbank (KBank) will also provide a loan equivalent to US$7.2 million.

Developers are awaiting approval by the California Public Utilities Commission to begin construction on 770 MW of four-hour lithium-ion battery energy storage systems for Southern California Edison in what is seen as one of the the largest such U.S. procurements.

The systems will support new clean energy projects for which the utility has signed contracts with four developers, also subject to regulators approval. These will replace capacity of aging natural gas power plants being retired.

Solar and wind poweradditions will require energy storage to maintain system reliability. The procurement’s cost was not disclosed.

Most of the selected battery projects will be co-located with solar plants to charge the batteries.

“This is just the first part of a two-part process,” says William V. Walsh, SCE vice president of energy procurement and management. The utility expects to procure more capacity over the next six months.

NextEra Energy Resources has three storage system contracts totaling 460 MW, while Southern Power won two totaling 160 MW; LS Power is contracted for 100 MW and TerraGen Power will build 50 MW. All contracts have a commercial online date of Aug. 1, 2021.

“California has a pretty aggressive mandate to have 100% of their electricity coming from renewable-energy sources by 2045,” says Tim Grejtak, analyst for Lux Research Inc., and battery systems are “getting bigger. . . . We’re now getting into the triple-digit-megawatt range for these installations.”

SCE’s procurement represents a huge acceleration in the rate of energy-storage growth in the U.S.

BloombergNEF reports that 293 MW went on line last year across the country. A 300-MW Moss Landing project is due to open this year in central California and the 409-MW Manatee Energy Storage Center in Florida is scheduled to open late next year.

“We believe that asset scales are now at a tipping point,” Grejtak says, and that may make other energy-storage solutions more attractive than lithium-ion. Vanadium redox flow batteries have a different scaling factor and performance variable from lithium-ion, which makes them attractive beyond 100 MW, he adds.