Axiom Energy started in its founder’s Amrit Robbins garage in 2014. Today, the firm has contracts with Whole Foods. The “refrigeration battery” system that the firm boasts is what has made it so attractive.

The technology makes use of pre-existing refrigerators that the clients would already own to implement long-scale thermal energy storage solutions. The system created by Axiom takes excess energy from the fridge to freeze a tank of salt water overnight. Then, later the next day, during electricity hours in the afternoon, the refrigeration battery uses the frozen salt water to provide refrigeration to the units, instead of demanding more energy from the grid. This reduces the need for compressors or condensers.

Robbins is optimistic about the outlook for the firm, specifically because the solution provided to their main target audience: grocery stores. According to Robbins, the margins for these grocery stores are razor thin at around 1.3% on average, meaning they are desperate for any cost saving measures. Moreover, on average they spend three times more on energy per square foot than other retailers. Even a few basis points in savings would be huge. Energy may be the area to target for these savings, especially given the opportunities presented by Axiom.

Up to 60% of energy consumption from typical supermarkets comes from refrigeration expenses, a problem which is heightened by the volatility of energy demand and the high prices that have come to be associated with it. Taking the old refrigeration units and transforming them into intelligent energy storage assets could be the way of the future.

The hype surrounding Axiom comes from the short time it took for the company to go from a start-up, to landing major contracts. The three years taken by the company shines when compared to the sometimes decades-long research and development process undergone by emerging battery and fuel cell chemistry companies. For example, Aquion, Imergy, or Enervault – all of which are now defunct.

The advantages for Axiom are expansive. The ability to use existing infrastructure to innovate solutions saves a ton of money on manufacturing. Moreover, Axiom sells directly to the end consumer, eliminating a middleman. Other battery companies must first sell to battery and energy system integrators.

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Pacific Gas and Electric (PG&E) is inviting businesses and consumers to apply for $240 million in renewable and energy storage incentives through its self-generation incentive program (SGIP) for 2017.

California regulators have directed PG&E and other investor-owned utilities to distribute $566,692,308 designated to the SGIP program through 2019.

The bulk of the money – 79 percent will be used for energy storage incentives. The remaining 21 percent will go to projects that use generation, such as wind turbines, fuel cells and combined heat and power.

PG&E says it will prioritize applications that pair energy storage with renewables.

The SGIP was developed in 2001 by the state legislature and the California Public Utilities Commission (CPUC) to boost renewables and support California’s climate and clean air goals.

This year marks the first time most of the money is designated for energy storage. More than $390 million will go to energy storage projects bigger than 10 kW in size. For smaller, residential-size storage projects, the state allocated $57 million.

Energy storage incentives will vary based on the size of the project and other factors.

For example, the incentive will be 50 cents/watt-hour for projects that do not take the federal investment tax credit (ITC). Residential systems that are 10 kW and smaller will receive the same incentive. For larger energy storage projects that take the ITC, the incentive begins at 36 cents/watt-hour. As funds deplete, the incentive levels go down in 10 cents/watt-hour increments. The money is being alloted in five stages, with the first step opening up May 1.

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Under AB 2514, California’s landmark energy storage law passed in 2013, California’s three Investor-Owned Utilities (“IOUs”) (Southern California Edison (“SCE”), Pacific Gas & Electric (“PG&E”), and San Diego Gas & Electric (“SDG&E”)) are required to install 1,325 MW of energy storage by 2024.^[1] Recent California Public Utilities Commission (“CPUC”) decisionmaking under a later-passed energy storage law, however, has added an additional 500 MW to the IOUs’ procurement obligations.

In 2013, the CPUC broke down AB 2514’s 1,325 MW storage target into three sub-targets, where each IOU must procure a specific amount of transmission-connected, distribution-connected, and behind-the-meter storage resources in a series of biennial procurement cycles through 2020.^[2] The California IOUs have collectively made considerable progress toward these respective energy storage sub-targets, and have even begun procuring energy storage projects outside of the AB 2514 procurement cycles (such as in connection with fulfilling local capacity requirements and (for SCE) in response to the Aliso Canyon gas shortage).^[3]

AB 2868, signed by California Governor Jerry Brown in 2016, requires PG&E, SCE, and SDG&E to propose programs and investments for up to 500 MW of distributed energy storage systems (defined as distribution-connected or behind-the-meter energy storage resources with a useful life of at least 10 years).^[4]  While there is considerable overlap with the types of resources covered by AB 2514, AB 2868’s 500 MW proposal excludes transmission-connected resources is not subject to the 2020 procurement or 2024 installation requirements and various other requirements of the AB 2514 program.

Emboldened by the success of AB 2514, on April 27, 2017, the CPUC ordered the IOUs to incorporate proposals for programs and investments for the full 500 MW of distributed energy storage systems (166.66 MW for each of PG&E, SCE, and SDG&E).^[5] While the CPUC emphasized that the additional 500 MW does not raise AB 2514’s original procurement targets, Commissioner Peterman’s decision directed each IOU to incorporate the applications for AB 2868’s distributed energy storage systems into AB 2514’s existing process for approving the biennial utility procurement plans.^[6]  For practical purposes, the CPUC decision will facilitate the interconnection of an additional 500 MW of energy storage to the California grid, along the same general processes of AB 2514, although the existing limitations on large pumped-hydro, electric-vehicle charging, and gas-to-power storage resources remain in place.

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The biggest criticism of wind and solar energy has long been their variability as sources of energy for the grid. The sun is only out during the day, and the wind doesn’t blow 24/7. They’re not great “baseload” sources of electricity, and their variability can make the rest of the grid harder to manage (see California’s “duck curve”). 

To solve this challenge, cheap and abundant renewable energy needs to be moved from when it’s produced to when it’s needed. Energy storage is the answer, and it’s becoming big business faster than you might think. 

Energy storage growth

The estimates of energy storage’s growth are incredible. According to GTM Research, energy storage installations in the U.S. totaled 260 MW in 2016 and the industry will grow to 478 MW in 2017 and 2,045 MW in 2021. 

Furthermore, Bloomberg New Energy Finance projects that 25 GW of energy storage will be installed worldwide in the next 12 years from less than 1 GW today. But that’s assuming battery prices fall to $120 per kWh by 2030. 

These are high growth estimates, but they may not be bullish enough. Estimates are that Tesla‘s (NASDAQ:TSLA) costs are already below $190 per kWh and GM has reportedly gotten cell prices as low as $145 per kWh, and prices on the market are already trending lower than industry experts think. 

New, cheaper batteries

Eos Energy, which makes a zinc hybrid cathode Znyth battery, recently announced that it’s taking orders for energy storage systems at $160 per kWh for delivery this year and at $95 per kWh for 2022 shipments. 

This is the lowest price I’ve ever seen quoted, but it’s probably just the beginning. Tesla has been an industry leader so far, and with the company projecting lower costs from the scale of the Gigafactory, it could be below $100 per kWh for utility-scale projects by 2022. The $100 per kWh level would only be a reduction of 12% annually based on costs reported in 2016, which is very manageable for an industry cutting costs rapidly. 

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An Argonne National Laboratory team of researchers has identified one of the major culprits in capacity fade of high-energy lithium-ion batteries. Scientists refer to a battery becoming old is its diminished performance as “capacity fade,” as the amount of charge a battery can supply decreases with repeated use.

When manganese ions (gray) are stripped out of a battery’s cathode (blue), they can react with the battery’s electrolyte near the anode (gold), trapping lithium ions (green/yellow)

Capacity fade is the reason why a cell phone battery that used to last an entire day will, after a couple of years, last perhaps only a few hours.

Researchers at the U.S. Department of Energy’s (DOE) Argonne National Laboratory identified one of the major culprits in capacity fade of high-energy lithium-ion batteries in a paper published in The Journal of the Electrochemical Society.

But what if scientists could reduce this capacity fade, allowing batteries to age more gracefully?

For a lithium-ion battery – the kind that we use in laptops, smartphones, and plug-in hybrid electric vehicles – the capacity of the battery is tied directly to the amount of lithium ions that can be shuttled back and forth between the two terminals of the battery as it is charged and discharged.

This shuttling is enabled by certain transition metal ions, which change oxidation states as lithium ions move in and out of the cathode. However, as the battery is cycled, some of these ions – most notably manganese – get stripped out of the cathode material and end up at the battery’s anode.

Once near the anode, these metal ions interact with a region of the battery called the solid-electrolyte interphase, which forms because of reactions between the highly reactive anode and the liquid electrolyte that carries the lithium ions back and forth. For every electrolyte molecule that reacts and becomes decomposed in a process called reduction, a lithium ion becomes trapped in the interphase. As more and more lithium gets trapped, the capacity of the battery diminishes.

Some molecules in this interphase are incompletely reduced, meaning that they can accept more electrons and tie up even more lithium ions. These molecules are like tinder, awaiting a spark.

When the manganese ions become deposited into this interphase they act like a spark igniting the tinder: these ions are efficient at catalyzing reactions with the incompletely reduced molecules, trapping more lithium ions in the process.

Study coauthor and Argonne scientist Daniel Abraham said, “There’s a strict correlation between the amount of manganese that makes its way to the anode and the amount of lithium that gets trapped. Now that we know the mechanisms behind the trapping of lithium ions and the capacity fade, we can find methods to solve the problem.”

It won’t be a very long spell until the chemistry issues are worked out in battery production. These is more to do in research, but the big clue is in hand. Meanwhile, we’ll just keep on buying, replacing and recycling those batteries.

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Three decades ago when the Energy Storage Association tried to galvanize support it drew 35 people to the room. Last week, at its annual conference in Denver, there were near 2,000.

Sure, they came because battery prices are dropping and energy storage pairs nicely with oh-so-popular solar. But something bigger is afoot here, something the size of the power grid, as Matt Roberts, ESA executive director, conveyed in his opening remarks at the Colorado Convention Center.

Brace yourself for an “intimidating array of new disruptors” on the grid as more of the economy becomes electrified, said Roberts. Running the grid as we do now will get us into trouble. The solution he sees is 35 GW of energy storage by 2025.

Roberts begins his argument for ‘why energy storage’ with robots –– tiny disc-like robots rushing about on a factory floor. Automated and directed by bar codes, they are sorting 200,000 packages a day with little human help. They operate entirely on electricity with an energy charge pegged precisely to the volume and timing of incoming packages. So they never run short on power. Nor is any wasted.

Now scale the factory floor up to a city of the future, Denver for example, and you get a glimpse of why energy storage may be bigger than you think

Denver’s a good setting for this futuristic city because it has a microgrid today, one tied to its transit system, which links to its airport, which of course links to the rest of the world.

So instead of robots on the canvas, imagine electric vehicles and trains. Departing from the microgrid at Denver’s Pena Station, a train ferries cargo and passengers to the airport, where they fly to Los Angeles. Meanwhile, signals are sent ahead so that 177 self-driving electric vehicles – exactly the number needed — are waiting at the LA airport when the passengers arrive. An equally calibrated fleet of trucks pick up the cargo. The vehicles run on batteries pre-charged with enough energy to reach their pre-arranged destinations.

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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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