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.

Since the turn of the century, there has been a global explosion in the production of renewable power. According to the 2018 BP Statistical Review of World Energy, global renewable energy production in 2000 was 218 Terawatt-hours (TWh). By 2018, that number had reached 2,480 TWh, with average annual growth over the past decade averaging 16 percent.

This rapid increase in renewable power has been driven by falling cost curves and aided by legislation directed at reducing air emissions like carbon dioxide. But it has also required utilities to accommodate this influx of intermittent renewable power.

Storing Power

Because renewable sources like wind and solar power can suddenly change output with little warning, the ability to store intermittent power has become more important. Historically, pumped hydroelectric energy storage (PHES) has been the primary type of grid-scale storage. PHES involves pumping water uphill to a reservoir, and then allowing that water to flow back downhill through a turbine as needed.

PHES still accounts for about 95 percent of all grid-scale storage, but that number has been falling in recent years as battery storage solutions have become more economical.

In December 2017, the largest battery storage system to date was connected to the grid in South Australia. The 100 megawatt (MW) Hornsdale Power Reserve was built by Tesla to back up the adjacent 315 MW Hornsdale wind farm.

That’s still only about 1/30th the capacity of the world’s largest PHES facility. However, the Energy Information Administration (EIA) recently reported that battery storage capacity has quadrupled in the past four years. A 409 MW solar battery storage project is expected to start up in Florida in 2021.

The Carbon Emission Footprint of Battery Storage

As battery storage applications grow, there has been increasing interest in the carbon emissions associated with those applications. Conventional power production emissions have been characterized for numerous sources of power, but 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 (LCA) 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.

More than 3.7 million electric vehicles (EVs) were sold worldwide over the past two years. That’s creating business opportunities for electrical contractors, many of which aren’t immediately obvious. One case in point involves electric utility-scale battery energy storage systems (BESS), which typically use the same lithium-ion (Li-ion) technology as EVs. As EV sales grow, so do Li-ion volumes. That helps send Li-ion technology down the cost curve, making BESS more attractive to more electric utilities.

“One of the largest drivers is the rapidly declining cost,” says Roger Lueken, a senior associate at The Brattle Group, which tracks the utility market. “We’ve seen double-digit percentage [declines] per year for battery packs for the past 10 years.”

The EV trend is also prompting electric utilities to look for new ways to keep up with demand. For example, a household with one or more EVs can use four to five times more electricity than homes without. BESS is one way to manage that demand, such as with batteries installed in or near neighborhoods with high concentrations of EVs. During the day, when most of those vehicles are elsewhere, solar or wind systems can charge the batteries. At night, they help shoulder the increased charging load.

“BESS also provides utilities with new flexibility to generate, control, and manage power within their grid,” says Clay Williams, project executive for energy/utilities at Pittsburgh-based Sargent Electric Co. “Many utilities are considering BESS to replace their peaker plants.

“Also, the utilities can dispatch the power, or have the grid operators dispatch the power, at times of peak demand, which will result in a higher price per kilowatt-hour being sold. The utilities may be able to obtain a more lucrative power purchase agreement.”

Finally, BESS is another option for serving customers in areas prone to outages. Take the example of a remote, six-home subdivision fed by a 20-mile-long distribution line that passes through an area where wildfires are common. A BESS could support a microgrid for those customers to ensure they have power when that line goes down. It also could eliminate the need for that line altogether.