The effect that fossil fuels are having on the climate emergency is driving an international push to use low-carbon sources of energy. At the moment, the best options for producing low-carbon energy on a large scale are wind and solar power.

But despite improvements over the last few years to both their performance and cost, a significant problem remains: the wind doesn’t always blow, and the sun doesn’t always shine.

A power grid that relies on these fluctuating sources struggles to constantly match supply and demand, and so renewable energy sometimes goes to waste because it’s not produced when needed.

One of the main solutions to this problem is large-scale electricity storage technologies. These work by accumulating electricity when supply exceeds demand, then releasing it when the opposite happens. However, one issue with this method is that it involves enormous quantities of electricity.

Existing storage technologies like batteries wouldn’t be good for this kind of process, due to their high cost per unit energy. Currently, over 99 percent of large-scale electricity storage is handled by pumped hydro dams, which move water between two reservoirs through a pump or turbine to store or produce power.

However, there are limits to how much more pumped hydro can be built due to its geographical requirements.

One promising storage option is pumped thermal electricity storage. This relatively new technology has been around for about ten years, and is currently being tested in pilot plants.

Pumped thermal electricity storage works by turning electricity into heat using a large-scale heat pump. This heat is then stored in a hot material, such as water or gravel, inside an insulated tank.

When needed, the heat is then turned back into electricity using a heat engine. These energy conversions are done with thermodynamic cycles, the same physical principles used to run refrigerators, car engines or thermal power plants.

Long-duration grid storage company Highview Power announced Tuesday it had raised a major equity investment to support its journey to market.

Global industrial conglomerate Sumitomo Heavy Industries invested $46 million in Highview, becoming the largest minority shareholder in the company. The money will support Highview’s quest to commercialize large-scale energy storage plants, a crucial component for a power system with large amounts of renewable generation.

“For Sumitomo Heavy Industries, this is not a venture capital investment — this is a strategic bet,” Highview President and CEO Javier Cavada told Greentech Media. “This is a huge corporation that sees this [technology] as a cornerstone of its future.”

Highview currently operates two pilot plants in the U.K. that showcase its cryogenic thermal storage design, which uses well-known equipment from other industries to minimize technology risk. With several years of field-testing under its belt, the company began developing full-scale plants in the U.K. and Vermont last year.

In the long term, Highview aims to supply its technology to other power plant developers, but for early projects, the company chose to develop in-house. And since securing financing is difficult for conventional storage, not to mention unconventional long-duration technologies, Highview plans to use its own equity to finance the early deployments.

“We needed equity to be able to develop the projects,” said Cavada. “This investment is way bigger than all the money that was invested before into the company.”

Valuation soars past $300 million
Over its 15 years in operation, Highview had raised £25 million (roughly $32 million), according to Cavada. The new raise, which other investors could join, pegs the company’s valuation at $330 million.

“This is a big, big milestone,” he said. “There is no other energy storage company at this level of valuation.”

That’s a hard claim to verify because companies typically keep their valuations private, and there aren’t many pure-play grid storage companies to be found in the public markets. Cavada attributes his company’s value to its ownership of intellectual property for a storage technology whose time has finally come.

The UK energy storage sector is forging ahead after a landmark year in 2019 which saw maturing business models further the asset class’ role in the country’s energy system.

That was the sentiment expressed by a panel discussion on the sourcing of equity for battery storage featuring asset owners and operators at Solar Media’s Energy Storage Summit, led by Eelpower chief Mark Simon who described 2019 as “Year Zero” for the nascent battery storage market.

Simon’s view was echoed by Ben Guest, head of new energy at listed storage fund Gresham House, who said that investors had grown comfortable with business models surrounding energy storage assets, driven by returns improving on the back of an increasing number of markets to participate in.

While grid-scale batteries had been deployed in the UK – and at scale – prior to last year, the market was principally led by transmission system operator National Grid’s Enhanced Frequency Response (EFR) tender in 2016, which provided lucrative, long-term contracts to bolster the nation’s security of supply.

That ancillary services programme created significant interest and the tender itself was significantly oversubscribed. A total of 37 providers submitted 64 unique projects for the EFR tender, however just seven projects comprising 200MW of capacity were selected.

Those projects came onstream from late 2017 and into 2018, creating a spike in deployment figures. But National Grid’s decision not to hold a second EFR auction, coupled with other market factors such as the implementation of steep de-rating factors for Capacity Market contracts, led to a slump in market activity.

The UK’s energy storage sector has, however, not been deterred. New market developments – specifically National Grid ESO’s decision to open up the Balancing Mechanism to distributed generation alongside the establishment of a distributed energy resource desk at the system operator – has given rise to more sophisticated business models for energy storage assets in the UK.

US federal energy regulator FERC has been accused of promoting fossil fuels after upholding a provision said to be hindering green energy’s involvement in New York state’s capacity market.

On Thursday, FERC was censored by green energy representatives after rejecting a complaint against the power mitigation regime, which applies to projects looking to take part in the installed capacity market (ICAP) auctions run by the New York Independent System Operator (NYISO).

The so-called buyer-side mitigation measures set minimum offer prices to ensure those purchasing capacity cannot distort competition by “artificially suppressing” capacity prices. However, various associations have long argued the measures only serve to cripple New York’s renewable progress.

In a complaint filed against NYISO last July, state energy agencies NYSERDA and the New York Public Service Commission said the measures are “unjust, unreasonable, unduly discriminatory” and may prevent storage from growing under state-wide targets for 2025 (1.5GW) and 2030 (3GW).

The complaint was backed by the Energy Storage Association (ESA) – the trade body said the mitigation rule “directly interferes and conflicts with New York’s legitimate policy objectives” – but was, ultimately, quashed by the FERC decision made public this week.

The federal energy regulator said it was dismissing the complaint against NYISO because, among other reasons, it “does not agree” with the claim that subjecting storage to buyer-side mitigation rules limits its entry to the capacity market.

Storage, the FERC argued, can participate in the auctions same as “any other resources”. The regulator noted that the segment is not alone in facing mitigation measures – they apply to all energy projects in certain designated zones – and can be exempted if it meets certain criteria.

The global energy storage market quadrupled last year to 4 gigawatts of new installations and will surge to a 15-gigawatt annual market in 2024, even as system price declines slow down, according to Wood Mackenzie.

The energy storage industry begins the new decade in the midst of a rapid transformation from a niche market to one at the center of the global energy transition. Most grid-scale projects built over the past decade were limited to shorter-duration applications, such as ancillary services for the grid, the “lowest-hanging fruit of the storage tree,” a new WoodMac research note says.

But the market has seen a rash of major project announcements recently, driven in particular by the U.S., where developers are increasingly pairing large-scale solar arrays with batteries. NextEra Energy, North America’s leading renewables developer, is adding substantial storage capacity through both its regulated Florida utility and its independent generation arm.

Meanwhile, Google’s blockbuster solar-plus-storage deal last month with NV Energy could blaze a trail for other companies looking to meet their real-time energy needs with renewables. Shortly afterward, Daimler announced a deal with Norwegian power firm Statkraft to cover its 24/7 electricity demand in Germany with renewables.

“If this catches on among other climate-forward corporations, the upside could be huge [for storage],” said Daniel Finn-Foley, WoodMac’s head of energy storage, of the Google deal.

Storage developers still face challenges in getting paid for all the various services a battery can offer the grid. But the industry is in the “enviable position of juggling growth game-changers from multiple directions,” Finn-Foley observed.

“Plunging costs drove speculation in the first scaled markets, but as price declines enter a steadier rate, further recognition of storage’s value — rather than cost — will be the key factor in determining growth,” he said.

While the cost of energy storage systems fell by double-digit percentages regularly through the middle part of the last decade, the decline has moderated in recent years. System prices fell by around 6 percent last year, and that’s more or less the trajectory the industry can expect for the foreseeable future, WoodMac says.

Federal Minister for Education Dan Tehan was on hand at the University of New South Wales (UNSW) last week to launch the ARC Research Hub alongside scientific and technological leaders. The world-class facility aims to develop energy storage technologies to aid the nation’s, and the world’s, transition to renewable energies through the overcoming of intermittency issues.

“What this Integrated Energy Storage Solutions Hub will embark on is absolutely vital to our nation’s future,” Tehan said. “If we are to transition our economy, then having the energy solutions to do it is absolutely vital because if we don’t, we won’t be able to transition in a way which takes all Australians with us.”

The Research Hub for Integrated Energy Storage Solutions is funded through the Australian Research Council’s Industrial Transformation Research Hubs Scheme, and led by Professor Joe Dong. The goal is to bring together experts across universities and industry to develop energy storage technologies solutions that can best capture surplus energy from renewables.

The Hub has quite a broad mandate, seeking to participate not only in areas of storage technology manufacturing but also integration, optimisation, management, life cycle assessment, and economic valuation.

In terms of batteries and supercapacitor technologies, research will be performed using vanadium, lithium-sulphur, iron-slurry and sodium-ion, and lithium-ion batteries, one focus area is a battery solution for extreme environments.

As for fuel cells, the Hub is looking to create novel and improved fuel cell technologies, specifically ammonia-based fuel cells that would better enable hydrogen export, a key part of the Australia’s National Hydrogen Strategy.

Power-to-gas falls into a similar and indeed interconnected basket, for research into advanced catalytic systems for power-to-gas conversion is looking to extend the capability of fuel cell technology to allow for direct input from renewable energies like solar PV.

The two-Republican majority on the Federal Energy Regulatory Commission has issued another set of decisions that will aid fossil-fuel power plants at the expense of renewable energy and energy storage — this time in New York.

On Thursday, FERC Chairman Neil Chatterjee and Commissioner Bernard McNamee voted to reject proposals from New York state agencies and its grid operator, NYISO, to allow up to 1,000 megawatts of renewable energy, and up to 300 megawatts of electrical energy storage resources per year, to be exempt from “buyer-side mitigation” rules.

The exemptions were sought last year to allow those resources to participate in NYISO’s capacity market without being forced to bid at an administratively determined minimum price instead of their true cost. New York, which has set a goal of 70 percent renewables by 2030 and 100 percent clean energy by 2040, argued that the rules are meant to prevent utilities that own generation from gaming the market, not to restrict new resources.

But Chatterjee and McNamee rejected New York’s requests, a move critics say could price those renewable and storage resources out of NYISO’s capacity market and provide an advantage to otherwise economically uncompetitive fossil-fuel-fired power plants.

FERC Chairman Chatterjee, previously a senior aide to Senate Majority Leader Mitch McConnell (R-Kentucky), wrote that the decisions would help “send accurate price signals to markets and to ensure adequate supplies for consumers.”

Richard Glick, the sole Democrat on FERC, voted against Thursday’s decisions. In his Thursday dissent, he excoriated the decision as an attempt by his Republican colleagues to “prop up prices, lock in the current resource mix, and attack state policies that promote clean energy.”

Seasonal pumped hydropower storage (SPHS), an already established yet infrequently used technology, could be an affordable and sustainable solution to store energy and water on an annual scale, according to new IIASA research published in the journal Nature Communications. Compared with other mature storage solutions, such as natural gas, the study shows that there is considerable potential for SPHS to provide highly competitive energy storage costs.

“The energy sectors of most countries are undergoing a transition to renewable energy sources, particularly wind and solar generation,” says IIASA postdoc Julian Hunt, the study lead author. “These sources are intermittent and have seasonal variations, so they need storage alternatives to guarantee that the demand can be met at any time. Short-term energy storage solutions with batteries are underway to resolve intermittency issues, however, the alternative for long-term energy storage that is usually considered to resolve seasonal variations in electricity generation is hydrogen, which is not yet economically competitive.”

Seasonal pumped hydropower storage means pumping water into a deep storage reservoir, built parallel to a major river, during times of high water flow or low energy demand. When water is scarce or energy demand increases, stored water is then released from the reservoir to generate electricity.

The new study is the first to provide a global, high-resolution analysis of the potential and costs for SPHS technology. In their analysis, researchers assessed the theoretical global potential for storing energy and water seasonally with SPHS, focusing on the locations with the highest potential and lowest cost. They also analyzed different scenarios where the storage of energy and water with SPHS could be a viable alternative. The study included topographical, river network and hydrology data, infrastructure cost estimation, and project design optimization, to identify technically feasible candidate sites.

The new study shows that water storage costs with SPHS plants vary from 0.007 to 0.2 US$/m3, long-term energy storage costs vary from 1.8 to 50 US$/MWh and short-term energy storage costs vary from 370 to 600 US$/KW of installed power generation capacity, considering dam, tunnel, turbine, generator, excavation, and land costs. The estimated world energy storage potential below a cost of 50 $/MWh is 17.3 PWh, which is approximately 79% of the world electricity consumption in 2017.

The researchers found that significant potential exists for SPHS around the world, in particular in the lower part of the Himalayas, Andes, Alps, Rocky Mountains, northern part of the Middle East, Ethiopian Highlands, Brazilian Highlands, Central America, East Asia, Papua New Guinea, the Sayan, Yablonoi and Stanovoy mountain ranges in Russia, as well as a number of other locations with smaller potential.

Is energy storage as clean as we think? As battery storage applications grow, there has been increasing interest in the carbon emissions associated with those applications…there have been few studies to characterize emissions associated with battery usage in storage applications.

In order to do this, we can consider the Hornsdale Power Reserve as an example. It is powered with lithium-ion batteries. In order to do a life cycle assessment of this project’s carbon dioxide emissions, we need to consider 1.) Emissions associated with building the batteries; 2.) Emissions associated with charging and discharging the batteries during normal operations; and 3.) Emissions associated with recycling or disposing of the batteries. Read more: Oilprice.com, author: Robert Rapier

FERC rules clean energy must pay higher market price in New York: Acore, in a release: “FERC delivered a new subsidy to the fossil fuel industry today at the unfortunate expense of New York ratepayers. So called ‘Expanded Buyer-Side Mitigation’ measures directly conflict with policies New York expressly designed to accelerate the transition to pollution-free, renewable power.”

FERC “issued a suite of orders that will require subsidized energy storage and renewable power resource providers to meet a price floor in New York state’s capacity market, making it harder for them to compete with fossil fuel plants. The move, which environmental groups said effectively bolsters fossil fuel generators by forcing renewable resource providers to pay a premium in the capacity market, follows a similar FERC order in December that applied to PJM Interconnection, the largest U.S. power grid operator.” Source: Reuters

Loopholes in the California solar mandate: In a precedent-setting decision, state energy officials Thursday approved a controversial request by Sacramento’s electricity company to allow home builders and buyers an alternative to the state’s 7-week-old rooftop solar panel mandate. California Energy Commissioners gave the Sacramento Municipal Utility District unanimous clearance to offer builders the option of buying solar energy from SMUD, via local solar farms SMUD would build, rather than install solar panels on new-home roofs.

SMUD…argues its proposed Neighborhood SolarShares Program will aid builders of homes or low-rise apartments who find it too expensive or unworkable to mount solar panels on roofs. Read more: The Sacramento Bee.

Seasonal pumped hydropower storage (SPHS), an already established yet infrequently used technology, could be an affordable and sustainable solution to store energy and water on an annual scale, according to new IIASA research published in the journal Nature Communications. Compared with other mature storage solutions, such as natural gas, the study shows that there is considerable potential for SPHS to provide highly competitive energy storage costs.

“The energy sectors of most countries are undergoing a transition to renewable energy sources, particularly wind and solar generation,” says IIASA postdoc Julian Hunt, the study lead author. “These sources are intermittent and have seasonal variations, so they need storage alternatives to guarantee that the demand can be met at any time. Short-term energy storage solutions with batteries are underway to resolve intermittency issues, however, the alternative for long-term energy storage that is usually considered to resolve seasonal variations in electricity generation is hydrogen, which is not yet economically competitive.”

Seasonal pumped hydropower storage means pumping water into a deep storage reservoir, built parallel to a major river, during times of high water flow or low energy demand. When water is scarce or energy demand increases, stored water is then released from the reservoir to generate electricity.

The new study is the first to provide a global, high-resolution analysis of the potential and costs for SPHS technology. In their analysis, researchers assessed the theoretical global potential for storing energy and water seasonally with SPHS, focusing on the locations with the highest potential and lowest cost. They also analyzed different scenarios where the storage of energy and water with SPHS could be a viable alternative. The study included topographical, river network and hydrology data, infrastructure cost estimation, and project design optimization, to identify technically feasible candidate sites.

The new study shows that water storage costs with SPHS plants vary from 0.007 to 0.2 US$/m3, long-term energy storage costs vary from 1.8 to 50 US$/MWh and short-term energy storage costs vary from 370 to 600 US$/KW of installed power generation capacity, considering dam, tunnel, turbine, generator, excavation, and land costs. The estimated world energy storage potential below a cost of 50 $/MWh is 17.3 PWh, which is approximately 79% of the world electricity consumption in 2017.

The researchers found that significant potential exists for SPHS around the world, in particular in the lower part of the Himalayas, Andes, Alps, Rocky Mountains, northern part of the Middle East, Ethiopian Highlands, Brazilian Highlands, Central America, East Asia, Papua New Guinea, the Sayan, Yablonoi and Stanovoy mountain ranges in Russia, as well as a number of other locations with smaller potential.