Northern Power Systems and Eos Energy Storage bring you an industry-leading, turnkey ESS solution that seamlessly integrates batteries, power conversion, and controls. The suite of integrated solutions combines the safe, ultra-low-cost Eos Aurora® DC battery system with Northern Power’s advanced energy storage inverter, controls, and engineering expertise, and provides 4 hours of usable energy using modular 250kW battery building blocks that are scalable for multi-MW applications.

“Batteries represent a significant portion of the performance and cost of an energy storage system. By using the Eos Aurora, we can deliver a fully integrated ESS solution at an all-in, installed price of less than £400/kWh with the quality, functionality and reliability that is characteristic of Northern Power. We believe this offering will allow more customers than ever to access the benefits of an on-site energy storage system.” – Chris McKay, Director of Sales, Northern Power Systems

APPLICATIONS

The integrated ESS solution represents a cost effective solution for:

• Utilities who want to provide relief in grid constrained areas, lower capacity payments, defer substation upgrades, and/or better integrate renewable energy.
• Large commercial and industrial facilities looking to lower demand and peak energy charges, or provide resiliency against grid outages.
• Behind-the-Meter demand management, time of-use, resiliency, back-up power, critical load support
• Hybrid microgrids – remote/islanded operation, grid stability, black start, renewables utilization/ reduced fuel consumption.

NPS/Eos ESS 500kW|2000kWh

Northern Power’s FlexPhaseTM power converter technology leverages a modular, compact, and efficient design that is easy to service. The platform allows for a wide range of DC voltages suitable for a variety of battery types. Northern Power’s proprietary Power Router™ controls allow for seamless transitions between grid and islanded operation, as well as black start capability. The grid-friendly design improves power quality and system stability.

The revolutionary Eos Aurora battery solution is powered by the company’s aqueous, zinc hybrid cathode (Znyth®) technology and offers game-changing cost and performance for a critical segment of the energy storage market. With a volume price of $160/kWh for the DC system and an expected life of 5,000 full depth-of discharge cycles, the Eos Aurora offers the best-fit solution for multi-hour energy storage applications.

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Flex, the Sketch-to-Scale™ solutions provider that designs and builds intelligent products for a connected world, has just launched a new technological advancement that addresses a solution to the issue of integrating wind and solar power into an energy grid.

The latest innovation, Advanced Battery Energy Storage Systems (BESS) is billed as an important step in aiding the renewable energy sector by storing energy when production exceeds demand and by providing services, such as frequency control, to the grid.

Designed to maximize energy

The solution announced through a press release by Flex can support multiple cells and is designed in a way which can help to maximize energy and power density of BESS deployments.

“In designing our energy storage solution, we stressed ease-of-installation, minimizing complexity and facilitating rapid deployments,” said Scott Graybeal, senior vice president of Flex Energy Solutions.

“By introducing a standardized, cost-effective and easily-deployed solution, we are enabling wide-scale implementation, with the hopes of further stimulating growth of the renewable energy industry.”

Flex collaborated with Renewable Energy Systems (RES) – one of the top battery energy storage integrators and renewable energy companies in North America to help engineer this energy solution.

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“This is a proof of concept, but the idea of using water or other solvents to ‘tune’ the transport of ions in a layered material is very exciting,” says Veronica Augustyn, an assistant professor of materials science and engineering at NC State and corresponding author of a paper describing the work. “The fundamental idea is that this could allow an increased amount of energy to be stored per unit of volume, faster diffusion of ions through the material, and faster charge transfer.

“Again, this is only a first step, but this line of investigation could ultimately lead to things like thinner batteries, faster storage for renewable-based power grids, or faster acceleration in electric vehicles,” Augustyn says.

“The goal for many energy-storage researchers is to create technologies that have the high energy density of batteries and the high power of capacitors,” says James Mitchell, a Ph.D. student at NC State and lead author of the paper. “Pseudocapacitors like the one we discuss in the paper may allow us to develop technologies that bridge that gap.”

For this work, the researchers compared two materials: a crystalline tungsten oxide and a layered, crystalline tungsten oxide hydrate – which consists of crystalline tungsten oxide layers separated by atomically thin layers of water.

When charging the two materials for 10 minutes, the researchers found that the regular tungsten oxide stored more energy than the hydrate. But when the charging period was only 12 seconds, the hydrate stored more energy than the regular material. One thing that’s intriguing, the researchers say, is that the hydrate stored energy more efficiently – wasting less energy as heat.

“Incorporating these solvent layers could be a new strategy for high-powered energy-storage devices that make use of layered materials,” Augustyn says. “We think the water layer acts as a pathway that facilitates the transfer of ions through the material.

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The San Diego County Water Authority announced it will seek detailed proposals for a potential energy storage facility at the San Vicente Reservoir that could total up to 500 MW. The official RFP will go out this summer.

The request for proposals follows a January request for letters of intent to measure interest in the facility. In response, the Water Authority received 18 responses from qualified parties, including five full-service entities that would finance, design, permit, built and operate the potential project and secure an off-taker for the produced energy. The other respondents included two developers, five off-takers, and six other parties interested in constructing the project, providing equipment for the project or serving as a consultant for engineering, procurement, and construction services.

“We wanted to find out if there really is a broad desire among potential stakeholders to see a project like this in our region, and now we know there is,” said Mark Muir, chair of the Water Authority’s Board of Directors. “We’re now going to gather more details about how it could come together for the benefit of ratepayers.”

The Water Authority intends the project to ease pressure on the electric grid, keep electric service reliable and keep water rates from rising by providing a new source of revenue.

Discussions with entities that responded to the RFP confirmed the authority’s findings from feasibility studies that began in late 2013. Namely, the project would help stabilize the grid, the project size is appropriate and infrastructure to support the project already exists.

The project would include an interconnection and pumping system between the reservoir and a new, smaller reservoir uphill that would be used during off-peak energy use periods to pump water uphill to the upper reservoir and create a bank of stored hydroelectric energy. That energy would be released to the lower reservoir as needed.

The Water Authority already operates a similar energy storage facility at Lake Hodges with a capacity of 40 MW. 

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The Coachella Valley’s two electric utilities are national leaders in one of the hottest clean-energy technologies, according to a first-of-its-kind report.

The Imperial Irrigation District and Southern California Edison brought more battery storage onto the grid than any other U.S. electric utilities in 2016, according to data compiled by the Smart Electric Power Alliance, which was released this week. The Washington, D.C.-based trade organization surveyed 178 utilities, and found that 43 added storage to their portfolios last year — none more so than Imperial and Edison.

Energy storage is a simple concept: Generate electricity when it’s cheap, and stow those electrons away until you need them. While large-scale batteries are still relatively expensive, they’re becoming increasingly popular among utilities as more solar and wind farms are built. Those renewable energy facilities generate cheap electricity, but only when the sun is shining or the wind blows. That doesn’t always line up with when homes and businesses are using energy — hence the growing interest in batteries.

“The technology is rapidly improving and becoming more economic,” said Brenda Chew, a research analyst at the Smart Electric Power Alliance, whose members include utilities, solar installers and storage companies, among others. “Overall, it’s just seen as an important player for integrating higher levels of renewable (energy).”

The Imperial Irrigation District — which serves 150,000 customers in the Imperial Valley and the eastern Coachella Valley — opened a 30-megawatt battery in El Centro, one of the country’s largest lithium-ion batteries, in October. General Electric and Samsung were among the contractors who worked on the project, which cost $38 million.

District officials have said the battery will make it easier for them to incorporate more solar and wind into their energy mix.

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Every year, the Smart Electric Power Alliance (SEPA) crowns the top U.S. utilities for solar, and with the release of its 10th annual utility market survey, the group has now launched additional rankings for the utilities leading on energy storage.

“One of the reasons we started the utility solar top 10 lists back in 2007 was to highlight the key, but often unrecognized, role utilities were taking in putting new solar on the grid,” explains SEPA President and CEO Julia Hamm. “With utility-scale solar now well established as a mainstream power source, we wanted to similarly recognize utilities’ leadership in realizing the full potential of storage to drive critical system changes that will benefit customers and the grid.”

SEPA explains the top 10 lists are based on data provided by 412 utilities, which together serve more than 90 million customers across the country, and the lists rank the leading U.S. utilities of 2016.

In terms of the most new megawatts of solar added in 2016, Southern California Edison (SCE) ranked No. 1 and Pacific Gas & Electric (PG&E) ranked No. 2 – the same spots the two California utilities had on the first top 10 list in 2007, SEPA notes. However, the group points out that the number of megawatts each added has changed dramatically: SCE jumped from 409 MW in 2007 to 1,648 MW in 2016, while PG&E grew from 144.5 MW to 773 MW.

According to SEPA, the figures needed to make the top 10 list for new solar watts added per customer have also shot up. The City of Palo Alto Utilities ranked No. 5 in 2007 with 20.4 watts per customer; this year, it earned the No. 1 spot with 2,753 watts.

As for energy storage, Imperial Irrigation District (IID), a public power and water utility in Southern California, took the No. 1 spot on the top 10 list of new storage megawatts installed, adding 30 MW of storage in 2016. The Sterling Municipal Light Department, the municipal utility for the small town of Sterling, Mass., led the top 10 energy storage list for new watts per customer, with 533 watts added per customer.

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A bill that recently won state Senate committee approval would make California the first state to require utilities to dole out rebates to customers who install energy storage systems.

The Energy Storage Initiative (SB700) was approved last week by the state’s Senate Energy, Utilities and Communications Committee and is awaiting a full senate vote.

The bill, authored by State Sen. Scott Wiener, a Democrat, would require the electric utilities to provide rebates to their customers by Dec. 1, 2018 for the installation of energy storage systems meeting certain requirements.

SB700 would require utilities to collect up to $166 milliion annually from ratepayers from 2018 through 2027 to fund the Energy Storage Initiative, which would then use the funds to provide rebates to customers who install energy storage systems.

The Energy Storage Initiative bill would also reserve up to 25% of the fees collected by utilities to pay for energy storage systems for low-income residential housing  and disadvantaged communities, and for recruiting and job training for workers in the energy storage systems marketplace.

California leads the country in the deployment of solar power systems. In recent months, utilities have also been rolling out lithium-ion and flow battery storage systems to store more renewable energy for use during peak hours of power consumption.

For example, in January, Southern California Edison (SCE) flipped the switch on the largest lithium-ion battery storage facility in the world — a substation with 80 megawatt hours (MWh) of capacity.

SCE’s power storage facility was followed by others installed by Pacific Gas and Electric (PG&E) and San Diego Gas and Electric (SDG&E).

The California Public Utilities Commission (CPUC) ordered SCE, PG&E and SDG&E to solicit more utility-scale energy storage systems. In all, the CPUC is requiring the utilities to meet a target of 1,325MW (1.3 gigawatts) of additional power storage by 2020.

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Investor-owned energy company National Grid, responsible for electricity and gas delivery in New York, Massachusetts and Long Island, will build a 5MW / 40MWh energy storage facility in Long Island with NextEra Energy.

A 50/50 joint venture between National Grid subsidiary National Grid Generation Ventures and NextEra Energy subsidiary Long Island Energy Storage Holdings will own and operate the battery energy storage system (BESS), on vacant land leased from National Grid. The joint venture company is called East Hampton Energy Storage Center (EHESC).

Located near a high voltage substation operated by the Long Island Power Authority (LIPA) – the non-profit which owns the retail transmission and distribution electric grids on the island – the facility will deliver stored energy to the substation in East Hampton.

The project came about after LIPA offered a request for proposals (RfP) for “sufficient local resources to meet expected peak load requirements on the South Fork (of Long Island)”. According to documents submitted by National Grid to the State of New York Public Service Commission (NYPSC), the BESS will help meet peak load in what is a “highly constrained” area of Long Island.

LIPA selected the East Hampton battery project to provide local power production resources and transmission support to the substation. Under the RfP, the system, which will operate under a power purchase agreement (PPA) for 20 years, must be operational by 2018.

In January, state governor Andrew Cuomo approved the nearby 90MW offshore South Fork Windfarm. Once the wind farm is built, the battery facility will be used to absorb excess wind power generation, in addition to its role in supporting existing infrastructure, enabling constant energy output from the windfarm to the grid.

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Developer Anesco has continued to rack up utility-scale storage work after agreeing to retrofit 10 of Ancala Partner’s PV arrays in the UK with battery units.

With a combined capacity of 12MWh, the batteries will be used to provide grid balancing and frequency response services to National Grid through upcoming tenders, although specific mechanisms – such as EFR or demand turn-up – were not disclosed.

Lee Mellor, director at Ancala Partners, said the addition of battery storage units was a “great example” of how the firm could add value for investors through “proactive management of assets”.

Mellor’s view defies other investors who have previously been pessimistic about the present investment opportunity for utility-scale battery storage retrofits, considering the technology to be too nascent and revenue streams too few to be currently bankable.

Nevertheless, Anesco executive chairman Steve Shine said it was an “exciting time” for the UK’s domestic battery storage sector.

Earlier this month Anesco announced a landmark deal with “technology-driven utility” LimeJump under which it will deploy 185MW of battery storage capability by the end of 2018.

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RICHMOND, Calif., and LOS GATOS, Calif., April 25, 2017 /PRNewswire/ — Axiom Exergy has completed the first installation of its thermal energy storage solution, the Refrigeration Battery at a Whole Foods Market store in Los Altos, California. The project successfully demonstrates the viability and potential of their energy storage solution by shifting up to 1040 kWh of electricity load at the facility for up to 10 hours a day over the course of several months. Without any changes to staff behavior or daily operations, the pilot demonstrated consistent, daily electricity load-shifting by offsetting electricity used by refrigeration compressors and condensers to off-peak times of day. Additionally, Whole Foods Market facility managers now receive real-time information about the system’s performance via Axiom’s integrated cloud monitoring platform including enterprise-level monitoring and analytics, historical data and real-time KPIs like kWh shifted, peak kW reduced, and battery charge level.

“We are proud to be leading our industry by being the first to use such an innovative technology to shift our large refrigeration-based energy loads to off-peak hours,” said Tristam Coffin, Director of Sustainability & Facilities at Whole Foods Market. “Whole Foods has a reputation for piloting and implementing sustainable solutions that also improve facility operations. This pilot is consistent with these efforts. We are excited to be part of Axiom’s groundbreaking solution.”

Refrigeration represents up to 55 percent of an average supermarket’s electricity consumption. Research shows that by shifting electricity demand to off-peak hours, supermarket owners can take advantage of lower night-time rates to reduce a store’s expensive on-peak electricity demand by up to 40 percent.

“The Refrigeration Battery is no longer a concept, it is a commercial reality,” said Amrit Robbins, President and co-founder of Axiom Exergy. “We are gratified that Whole Foods Market is serving as an example of how to implement scalable and low-risk energy storage options. By deploying the Refrigeration Battery, businesses can convert power-hungry refrigeration systems into intelligent assets that can respond dynamically to the needs of the facility and the grid operator, taking into account energy prices, weather patterns, and grid programs like demand response.”

The Refrigeration Battery was installed at the Los Altos Whole Foods Market as a passive retrofit without modification of the existing refrigeration system or reprogramming of controls. The Axiom System Integrator was sited in the facility’s mechanical room adjacent to the compressor racks and the Thermal Storage Tanks were placed in the loading dock area behind the store.

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