New York could go the extra mile under the energy storage roadmap released at the end of June.

The plan supports Democratic Gov. Andrew Cuomo’s energy storage target of 1,500 MW by 2025, but several sources say the final plan could call for an even more ambitious target. Reaching that target, though, could involve challenges that are largely outside of the scope of New York energy agencies.

The roadmap identifies near‐term policies, regulations, and initiatives needed to realize the governor’s 2025 target in anticipation of a 2030 target to be established later this year by the state’s Public Service Commission.

While higher storage targets will help with the growth of storage, the roadmap also addresses critical needs for clearer permitting guidelines. Progress for indoor siting is essential for deployment in congested areas like New York City, according to Doug Staker, vice president at energy storage developer Enel-X.

Shooting above the governor’s target

“The roadmap’s conclusion that the deployment of 2.8 GW to 3.6 GW of energy storage by 2030 would produce $3 billion in ratepayer benefits reinforces our expectation that the New York Public Service Commission could establish this December a 2030 storage target that builds upon and may likely exceed” Gov. Cuomo’s 1.5 GW by 2025 target, Timothy Fox, vice president at ClearView Energy Partners, told Utility Dive via email.

The 2,800 MW to 3,600 MW number laid out in the roadmap was the result of analysis by consulting firm Acelerex that examined system needs that can be met by energy storage in a least‐cost combination of resources as New York approaches its 50% by 2030 renewable portfolio standard target.

The report also says that analysis was “limited in its distribution system detail and consequently neither reflects an upper bound of ratepayer benefit nor maximizes the amount of storage that can be deployed in the state.”

“We see the ability to go up to 3,000 MW,” Bill Acker, executive director of the New York Battery and Energy Storage Technology consortium (NY-BEST), told Utility Dive. He said the document provides “a pathway” to reach a larger storage target by 2030.

The final target will “definitely be more than 1,500 MW” at the least because it is five years further out than the governor’s 2025 target, Jason Doling, program manager for energy storage at the New York State Energy Research and Development Authority, told Utility Dive. NYSERDA played a key role in the development of the roadmap.

A key factor when planning energy storage systems (ESS), for example for a microgrid, is to determine the expected cost savings and performance benefits provided by various ESS configurations.

Battery modelling offers a powerful way of predicting the lifetime performance and return on investment that will be provided by each ESS option.

Fuel savings are often a key factor in the choice of energy storage configuration, especially for microgrids which are often located in remote communities and rely on diesel generation, with logistical challenges around fuel delivery. However, cutting fuel consumption is just one of the purposes of battery modelling for microgrids.

Battery modelling techniques continue to evolve to better address the wider context of microgrid and renewable energy deployments. For example, simulations are now key to the project development process, as they deliver insights into renewable and storage applications ahead of deployment, and help determine how much power and energy are required overall.

Precise modelling

Modelling an entire microgrid at a high-level is a valuable exercise in assessing the viability of different deployments of renewable energy schemes with storage. However, when it comes to modelling the detail of these systems – such as bridging between multiple diesel generators in a large microgrid, or optimizing the set-points for operating with diesel generators in a smaller microgrid – more precise modelling is required.

High-frequency data, with granularity of no more than 10-minute intervals, is valuable. Such modelling provides insights into system operation, including diesel synchronization and cool-down times, to minimize diesel starts, maximize fuel savings and optimize battery life.

High-level modelling is typically based on hourly data, and the granularity of ESS dispatch is correspondingly coarse. This kind of modelling is feasible even with minimal data input.

For example, an initial model of a microgrid can be constructed with minimal inputs, such as the coordinates of an island village off the US Pacific coast having a peak load of 150 kW in January. Based on this information, high-level modelling can be used to construct a typical load profile, and location-specific solar or wind data can be downloaded.

The modelling software can then quickly carry out multiple simulations to discover the optimum renewable energy power rating, along with an appropriate level of energy storage. The results illustrate fuel savings and, if sufficient inputs are provided, ROI.

However, precise modelling requires more detailed inputs and time to optimize the dispatch methodology. Combining high-level and precise modelling leads to a more cohesive, informed insight into ESS requirements – in turn, enabling an accurate evaluation of a project’s viability, as well as the development of a detailed strategy to help ensure project success.

Investors’ focus and priorities shifting

Australia’s energy and environment minister has hailed the country’s accelerating residential energy storage sales as a report has emerged from Chief Scientist Dr Alan Finkel which says the “financial equation is straightforward” for adding batteries to home PV systems.

Finkel’s office produced reports during 2017 which advised the government on the power market, opportunities and challenges for renewables and decarbonisation and the role of clean energy technologies in boosting the resiliency of energy networks across Australia. At the tail end of the year, he also published a report on the “transformative role” of energy storage.

Finkel had said that there should be better market designs to incentivise peak shifting of solar and other forms of generation, which could be done with battery energy storage in those reports. Nonetheless, in an Occasional Paper on energy storage which he has just put his name to, the Chief Scientist has said that it already makes financial sense for home PV system owners to combine them with energy storage systems.

“The financial equation [to buy energy storage systems] is straightforward, driven by the difference in the high price to purchase electricity compared with the low price to sell it to the grid,” the paper said.

Over 1.8 million Australian rooftops are fitted with solar PV, most of which are residential. Feeding solar into the grid only makes the seller around AU$0.08 per kWh, to give the ballpark figure quoted in Finkel’s paper, while retail prices the same homeowner would pay for grid power are at around AU$0.30 per kWh. Storing the electricity generated and self-consuming it onsite instead therefore represents a significant potential for savings.

Minister for Energy and the Environment Josh Frydenberg hailed the success of the market. Finkel found that around 21,000 home systems were installed during 2017, which Frydenberg claimed made Australia a world leader for installed capacity of batteries, when taken with large grid-scale projects such as Tesla-Neoen’s 129MWh Hornsdale battery project in South Australia and two others which Frydenberg’s government funded the installation of.

“We are now not only the world leader in the use of rooftop solar, but also the world leader in the installation of residential battery storage by power capacity. As more renewable energy – mainly in the form of solar and wind power – enters our electricity grid, the need for energy storage solutions grows,” Frydenberg said.

CellCube Energy Storage Systems Inc. (“CellCube” or the “Company”) (CSE: CUBE) (CSE: CUBE.CN) (OTCQB: CECBF) (Frankfurt: 01X) is pleased to announce that, further to the Company’s acquisition of ENEROX GmbH (“Enerox“) in April 2018, it has now shipped the first energy storage system to the German municipal utility Gelsenwasser for their EnerPrax project.

About Project EnerPrax:

The pilot project EnerPrax – Energy storage in Practice – is a close to commercial proof of concept project incorporating various storage technologies (eg, electrical, gas, heat) for several grid stability and supply functions in the Saerbeck Bioenergy Park, the Smart City pilot site of the utility Gelsenwasser.

At EnerPrax, the CellCube system is performing energy-centric, electricity storage functions of providing grid stability and time shifting for 8-hour base energy delivery. This is a natural fit for vanadium redox flow batteries where long duration, reliable base load supply is required. Enerox’s CellCube vanadium redox flow battery will be the backbone storage technology for the EnerPrax project.

It is estimated by BMWi (German Federal Ministry of Economic Affairs and Energy) that by 2035, close to 60 percent, then by 2050 reaching to 80 percent of the electricity in Germany will be generated be renewable power sources. Wind energy and photovoltaics, which are intermittent in nature, will be the main components of power delivery. With large volumes of fluctuating renewable energy generation connected to the grid system, at times there will be an oversupply of electricity followed by periods of scarcity which pushes the power grids to their capacity limits. This is currently being compensated by conventional power plants. With the growing share of renewable energies, flexibility in the grid system and electricity requires the use of energy storage of all sorts to mitigate generation and load peaks. In this situation, energy storage systems are the clear favorite choice due to fast reaction and versatility that energy storage allows.

Stefan Schauss, President and CEO of Enerox stated: “We are delighted to have been selected by Gelsenwasser for this important project. We are able to supply the long duration battery system for this pioneering project which reflects the company’s vision and focus on becoming an integral part of future energy infrastructure solutions that CellCube intends to deploy worldwide.”

According to Highview Power, the first grid-scale liquid air energy-storage (LAES) plant has officially launched. The 5-MW/15-MWh LAES plant, located near Manchester, U.K., will be able to store and deliver enough electricity to power about 5,000 average-sized homes for around three hours, as well as offer a number of reserve, grid-balancing, and regulation services. Check out the video on the plant’s launch:

“The global energy storage market will grow to a cumulative 125 GW/305 GWh by 2030, attracting $103 billion in investment over this period,” says Logan Goldie-Scot, head of energy storage analysis at Bloomberg New Energy Finance. “Utility-scale storage becomes a practical alternative to new-build generation or network reinforcement, especially for underutilized assets in some markets. We expect energy storage to increasingly be used for longer durations over this period, providing such services as peaking capacity and renewable-energy integration.”

With LAES technology now being proven at grid scale, the plant paves the way for wider adoption of LAES technology globally. True long-duration energy storage is critical to enable the broader deployment of renewable energy; overcome the intermittency of solar and wind energy; and help smooth peaks and troughs in demand. LAES can easily and cost-effectively scale up to hundreds of megawatts, and could easily store enough electricity to power a town of around 100,000 homes over a period of many days.

Highview Power’s patented technology draws on established processes from the turbo-machinery, power-generation, and industrial gas sectors. LAES uses components and subsystems that are mature technologies available from major OEMs. The technology draws heavily on established processes from the power-generation and industrial gas sectors, with known costs, performance, and life cycles all ensuring a low technology risk.

How Does LAES Work?

LAES, also referred to as cryogenic energy storage (CES), is a long-duration, large-scale energy-storage technology that can be located at the point of demand. LAES plants can provide the long-duration energy storage. The working fluid is liquefied air or liquid nitrogen (~78% of air). Size extends from around 5 MW to hundreds of megawatts, and with capacity and energy being decoupled, the systems are well-suited to long-duration applications.

The basic principle for LAES is that air turns to liquid when cooled down to −196°C (−320˚F), so it can then be stored very efficiently in insulated, low-pressure vessels. When it’s cheaper (usually at night), electricity is used to cool air from the atmosphere to −196°C using the Claude Cycle to the point where it liquefies. The liquid air, which takes up one-thousandth of the volume of the gas, can be kept for a long time in a large vacuum flask at atmospheric pressure.

2017 WAS A BREAKOUT YEAR for battery-based energy storage in the US electric utility space. With 431MWHr of new capacity added during the year, it nearly doubled the total of existing prior amounts, with the total now exceeding 1GWHr of storage. 2018 should again double the total installation, with the total then to exceed 2GWhr. Both behind the meter and front-of-the-meter areas are growing, and by 2019, the US market for energy storage should exceed $1.2 billion, according to GTM and the Energy Storage Association.

Global markets were just as exciting. Outside of the US, another 1.9 GWHr of storage capacity was added, with Australia coming in second, just behind the US, at nearly 420MWHr of new capacity. Germany, China and Japan rounded out the top five installers, with 380, 330, and 280 MWHr respectively. This is substantial, especially considering the populations of Australia and Germany to be about 8 percent and 25 percent that of the US. There is now enough installed base to provide significant O&M information for the benefit of upcoming owners of such technology. By 2022, this will be a reasonably mature technology, with global deployment totals increasing tenfold between the beginning of 2018 and the end of 2022.

There are several mainstream utility system suppliers currently engaged in projects of 10MWhr and larger. Early in 2018, FERC directed the regional authorities, in the ISO/RTO category, to explicitly define tariffs (i.e. revenue opportunities) for the specific services that energy storage facilities can provide to the grid. These are sure to include fast-response regulation services for load and frequency, spinning reserve, black start, and energy arbitrage.

While battery energy storage systems (BESS) are in the high-growth spotlight, there are alternative technologies which can provide even better ROI for existing traditional plants. Thermal storage of media at both low and high temperatures create interesting opportunities. Storage of sufficient chilled media at just 40 deg-F (5 deg-C) improves the economics, efficiency and output capabilities for gas turbines, replacing simple inlet sprays or chilling systems with a more energy efficient alternative, using easily operated and maintained existing technologies. For the more conservative owners, there’s no need to worry about the risks of a “science experiment” here.

As grid operators prepare for even greater levels of bi-directional power flow, the fast regulation capabilities of storage will be needed to keep the grid stable and responsive. Flywheels added to BESS can amplify fast regulation down to millisecond response times. While not yet ready for primetime, flow battery systems promise greater lifetime and reduced physical footprint over the current technology of choice, lithium-ion batteries, so “stay tuned for further developments” here. Markets for BESS will be decades long, as renewables continue to penetrate, and older traditional coal-fired and nuclear generators age out of national fleets.

Clean energy news coverage often focuses on the successes and big strides taken forward by the industry in ‘record-breaking terms’: “world’s biggest battery,” “first hybrid to combine storage with x” and so on. Reporting in these terms is obviously an attention-getter, but in any relatively young industry such as ours, boundaries are there to be broken, so perhaps sometimes these developments in themselves are not as telling as might appear.

After reporting last week on the findings from EMMES, the European Market Monitor on Energy Storage from Delta-ee and trade association EASE, which demonstrated a big rise in installations by MWh in 2017 across the continent, we delved further behind another record-breaking year with the report’s lead author, Valts Grintals of Delta-ee. Today, we’re looking at the front-of-meter, grid-connected segment, with C&I and residential energy storage to follow later this week on Energy-Storage.news.

What are some of the key takeaways from the latest edition of EMMES?

If you look at the end of 2017 and compare it to the annual market for 2016, the annual market size has grown 50%. The 2016 overall market was around 400MWh and in 2017 it was close to 600MWh.

That’s in line with market expectations actually. However, the big difference is that while the overall growth rate was in line with expectations, there were differences in details. So while the FTM (front-of-the-meter) market underperformed, the residential market was bigger than expected, in large part due to the German market significantly exceeding expectations and the Italian market coming out with a good number of installations. In 2017, there were about 8,000 systems installed in Italy and 37,000 in Germany. That’s against an expectation of around half of that in Italy and about 31,000 systems in Germany if you look at the average scenarios.

In addition the C&I (commercial & industrial) space has finally taken off and if we look further beyond 2017, in 2018 and 2019 we see markets growing somewhere between 45% and that’s mainly because the C&I market is beginning to take off and there’s a significant pipeline of projects in the UK and Germany which are of significant sizes.

So, breaking the market down into the segments you looked at, namely front-of-meter utility-scale storage, C&I energy storage and residential, what are your observations of trends and are there distinct lessons to be earned from each? Let’s start with front-of-meter.

FTM [total deployment] was basically lower than expected, mainly because in the UK market, there were a few EFR (enhanced frequency response) projects that were planned or in the pipeline to be commissioned by the end of 2017, but a lot of projects have been pushed to early 2018.

If you would assume that those installations came in 2017 we would have an extra 90MWh, so the growth rate would be even bigger. But the commissioning dates have been pushed into 2018. Nonetheless, even if there are delays, FTM projects are still coming online which is good.

FTM tends to fluctuate, just like the values they tend to tap into – so frequency response gets saturated, it starts going down, then if you look at all of Europe there might be a bigger uptake – Italy or Spain goes through the process of putting together their framework for ancillary services which usually tends to include frequency response and looking at markets like Australia, UK, Germany, the number of batteries, installing significant numbers of lithium batteries usually follows schemes and we’ll see more information on those schemes.

A new study led by chief scientist Alan Finkel has underlined Australia’s role as a leader in the household battery storage sector, and says Australia can, and should, be a leader of energy storage of all types, including renewable hydrogen as an export opportunity.

Finkel’s new report Taking Charge: The Energy Storage Opportunity for Australia is a 9-page summary and update of a detailed report on energy storage by the Australian Council of Learned Academies (ACOLA) released in November 2017.

Readers may remember that report highlighted how little additional storage was needed – even with up to 35 per cent to 50 per cent wind and solar in the system, but also how critical it would be to a modern, decarbonised grid. Its conclusions were immediately attacked by conservatives as “eco-evangelism”.

The latest report includes updated data – such as the 21,000 battery storage systems estimated to have been installed in Australian homes in 2017.

More importantly, it includes much detail about the opportunities ahead, and comes at an important time as Australia’s political debate once again resolves, sometimes crazily, around the level of wind and solar that can be incorporated into the grid.

“We are entering an era of rapid technological transformation in electricity generation and usage,” Dr Finkel said in a statement.

“Energy storage technologies can not only help us benefit from the transition but to prosper through the creation of new industries, new jobs and opening up export markets.”