The efforts to lift our power generation and electrical grid into the 21st century is a multipronged effort. It needs a new generation mix of low-carbon sources that include hydro, renewables and nuclear, ways to capture carbon that don’t cost a zillion dollars, and ways to make the grid smart.

But battery and storage technologies have had a hard time keeping up. And they are critical for any success in a carbon-constrained world that uses intermittent sources like solar and wind, or that worries about resilience in the face of natural disasters and malicious attempts at sabotage.

This was pressed home this week by the Department of Energy’s decision to build a multimillion dollar electric grid research complex at the Pacific Northwest National Laboratory. And better, larger batteries are a main component of this research.

Jud Virden, PNNL Associate Lab Director for energy and environment, noted that it took 40 years to get the current lithium-ion batteries to the current state of technology.

We don’t have 40 years to get to the next level. We need do it in 10.

It’s not like we’ve been idle. We just haven’t been wildly successful. Battery technologies do keep getting better. Recently, Jack Goodenough, the inventor of the Li-ion battery, came out with a new fast-charging battery technology using that uses a glass electrode instead of a liquid one, sodium instead of lithium, and may have three times as much energy density as lithium-ion batteries.

And in addition to batteries, we do have other technologies for storing intermittent energy, such thermal energy storage, which allows cooling to be created at night and stored for use the next day during peak times.

At present, the most widely used storage method is pumped hydro storage, which uses surplus electricity to pump water up to a reservoir behind a dam. Later, when demand for energy is high, the stored water is released through turbines in the dam to generate electricity.

Pumped hydro is used in 99% of grid storage today, but there are geologic and environmental constraints on where pumped hydro can be deployed.

Long-duration storage startup Form Energy thought that solving the problem of months-long grid storage would take a decade. But its last year of work advanced faster than expected.

Based on that progress, the team of industry veterans has fast-tracked development and raised a $40 million Series B, co-founder Mateo Jaramillo told Greentech Media. Italian oil and gas major Eni signed on as lead investor, joined by Capricorn Investment Group and most of the existing investors from last year’s $9 million Series A.

Those original investors include some big names, too: Breakthrough Energy Ventures, Prelude Ventures, Macquarie Capital, Saudi Aramco (which didn’t join the Series B), and Massachusetts Institute of Technology offshoot The Engine.

Jaramillo, who previously built Tesla’s energy storage program, teamed up with MIT professor and prolific battery inventor Yet-Ming Chiang and Aquion alum Ted Wiley to found the company last year, with the goal of creating a product to make renewable energy fully dispatchable.

Market for baseload renewables coming soon
Today’s lithium-ion batteries can shift solar power into the evening for a few hours, but they become prohibitively expensive as a tool for weeks or months of guaranteed power delivery. Form Energy tackled that problem in the lab with an aqueous sulfur flow battery chemistry and an undisclosed electrochemical solution.

Meanwhile, the team modeled the economics of a lower-carbon grid to discern where this new type of power plant could go to market, and then performed similar analyses for paying customers.

“It’s gone better than I could have guessed and as well as we could have hoped,” Jaramillo said. “We have gone and had all those conversations with the major industry stakeholders that confirmed this is of interest right now.”

Instead of the initial plan to study the markets and technology for five years and go to market in 10, the analysis showed that an addressable market for “baseload renewables” would arise in the next three to five years, said Jaramillo.

As the behind-the-meter distributed energy storage market continues to mature, a series of factors have propelled residential energy storage systems (RESSs) to the forefront of industry consciousness. These factors include technological progress, legislative and regulatory tailwinds, and new grid challenges associated with intermittent renewable generation.

RESSs can be a highly flexible and valuable resource, improving efficiencies for system owners and the power grid. While residential battery storage has been a growing market in select geographies for several years, the market was primarily driven by early adopters concerned with supporting clean energy or self-sufficiency more than economic self-interest. RESSs were largely regarded by utilities as a niche product for clean energy connoisseurs.

Many utilities see RESSs as a new avenue to improve their services and relationships with customers at a time when new technologies present a real risk of load defection. Utilities around the world recognize these benefits (particularly the ability to reduce congestion on the network and limit the need for peak capacity resources) and have launched programs to deploy RESSs. Utility involvement, cost declines, government incentives, and increased solar photovoltaic (PV) integration are driving increased RESS deployments.

The global RESS market is gaining momentum, with installation growth rates soaring in geographies including Germany, Japan, Australia, and several U.S. states. However, long-standing uncertainties concerning feasible uses and cost-effectiveness remain. As a result, it is vital to support residential utility customers’ ability to tap into RESS value streams that go beyond traditional solar self-consumption. Such support will likely improve the value proposition and increased adoption of RESSs.

Emerging RESS Virtual Power Plants

For residential utility customers, aggregation through a virtual power plant (VPP) is a foundation for unlocking RESS potential to provide grid services. As energy markets evolve toward a greater dependence on distributed energy resources (DERs), strategies to generate more value from smaller, cleaner, and smarter systems are being designed and implemented — including the use of aggregation and VPPs. VPPs transform previously passive consumers into dynamic prosumers that can deliver services customized to their own needs while delivering services to the grid.

At the same time, utility DER management systems (DERMSs) are being designed, piloted, and closely examined for their potential to provide localized grid services. These systems are employed by utilities to control the same DER assets as prosumers, regardless of whether they own the systems or not. Although demand-side VPPs and supply-side DERMSs are closely related, their integration into a common solution set is yet to be fully realized.

On Thursday, Hawaiian Electric issued a long-awaited request for proposals for about 900 megawatts of renewable energy and energy storage projects. It’s the utility’s second major round of contracts in the past year seeking to marry variable solar and wind power with the capacity and flexibility of batteries.

But the Variable Renewable Dispatchable Generation and Energy Storage RFPs that opened on Thursday are a bit more complicated than their headline figures — seeking “technologies equal to 594 megawatts of solar for Oahu, 135 megawatts for Maui and up to 203 megawatts for Hawaii Island” — might indicate.

Unlike its first massive solar-storage procurement in January, HECO’s new RFPs are broken into a number of specific projects and specific needs across its three islands, with a mix of different technologies required. This complexity comes from the fact that these RFPs have been structured to help replace two big fossil-fuel-fired power plants to close in the next five years — the AES Hawaii coal-fired power plant that serves about one-sixth of Oahu’s peak demand, set to retire in 2022, and the oil-fired Kahului plant on Maui, set to close in 2024.

This impending loss of two big spinning generators has pushed HECO and regulators to approve a mix-and-match of technology combination to replace them. That will make them hard to compare directly to HECO’s first round of procurements, as well as the utility-scale solar-plus-storage bids on the mainland.

Developers winning HECO’s first-round RFP in January shocked the industry with prices ranging from 12 cents per kilowatt-hour to a record-breaking 8 cents per kilowatt-hour, as compared to average Hawaiian solar-storage project prices of 11 cents per kilowatt-hour in 2017 and 13.9 cents per kilowatt-hour in 2016.

They also came with some novel structures, such as PPAs that replaced payments based on energy deliveries to lump sums based on net energy potential and availability, to ensure greater dispatchability for critical hours of the day, Ravi Manghani, head of solar research for Wood Mackenzie Power & Renewables, noted.

But “the Phase 2 RFP takes a more technically advanced approach toward resource planning,” Manghani stated in a July GTM Squared article in July, soon after HECO submitted its plan to the Hawaii Public Utilities Commission.

PowerGen Renewable Energy, a leading player in Sub-Saharan Africa’s fledgling, but fast growing markets for microgrids, minigrids and micro-utilities, acquired the Tanzanian microgrid assets of another emerging market leader, Rafiki Power, aka E.ON Off-Grid Solutions.

The acquisition furthers PowerGen Renewable Energy’s goal of creating micro-utilities, entities that sell small amounts of local electricity, often generated from microgrids or minigrids.

The deal indicates that the Sub-Saharan microgrid and minigrid market is moving into a new phase of evolution.

“This deal is a great opportunity for PowerGen to build on its existing momentum and give us more leverage to show investors, governments, and donors that minigrids are an excellent solution to the energy access challenges facing Africa…By bringing clean, reliable power to communities who previously lacked electricity, PowerGen minigrids open up an enormous range of new economic activity while improving quality of life and health,” PowerGen Renewable Energy CEO Sam Slaughter told Microgrid Knowledge.

The acquisition will bring PowerGen Renewable Energy’s micro-utility customer base to over 50,000 in four Sub-Saharan countries, adding momentum to growth of micro-utilities across the African continent, added Benson Kbiti, communications director for international, non-profit sustainable energy advocacy Power for All.

“Governments in Africa now realize providing energy access and low-cost power for productive uses to the communities is core to powering rural economies and creating a foundation for economic development. Microgrids are a key tool to do this,” Kbiti said.

The SolarLEAF eliminates the need for specialized installers and strict siting requirements. This simplicity enables solar installers and developers to expand their customer base and grow their business by delivering a scalable, cost-effective storage solution that can easily be installed anywhere.

Yotta has accelerated fundraising efforts in pursuit of Series A equity financing, which will be used to advance beta testing into commercialization, including bankability study and UL certification. “With the tremendous market opportunities we are seeing, it makes sense for us to ramp up our fundraising efforts so we’re in a solid position to respond as the market continues to gain speed,” said Yotta CEO Omeed Badkoobeh.

In addition to its fundraising success, Yotta has tapped Phil Gilchrist, formerly of SunPower, as the company’s Director of Mechanical Design Engineering and Jeff Williams, formerly of Draker, as Director of Electrical Engineering.

Williams, who has served Yotta as an advisor, officially joined the Yotta team this spring. He has over 30 years of electrical engineering experience and 10 years in the solar and power industries. Williams has a master’s degree in Electrical Engineering from Texas A&M University.

Joining Yotta in 2019, Gilchrist brings over 30 years of industry experience to the management team. He spent several years working at the director level at SunPower and graduated from the University of Texas at Austin with a degree in Mechanical Engineering.

It created a market that demands and allows for value stacking.

Today’s energy storage technology can help power the country more efficiently and sustainably, and it’s getting better all the time. However, this resource’s greatest strength—the ability to both take in and let out energy rapidly—can be complicated to properly value. It’s also been a bit of a headache to equitably work into the country’s many mechanisms governing electricity generation and transmission.

Having an energy storage system provide just one service can be expensive, and it’s a big waste of potential. Enter Massachusetts, where the stars have aligned and the full potential of energy storage may soon be on display, providing not one or two services, but seven or eight with a single project.

What’s so great about Massachusetts?
For one, it’s part of a deregulated wholesale energy market. Independent System Operators (ISOs) and Regional Transmission Operators (RTOs) oversee the nation’s most competitive energy markets, which serve two-thirds of the U.S. population. In February 2018, the Federal Energy Regulatory Commission (FERC) issued its landmark Order 841, which required the removal of barriers to the participation of energy storage in the capacity, energy, and ancillary services markets operated by ISOs and RTOs. ISO New England was quick to respond, thanks to a unanimous agreement between the ISO and the New England Power Pool (NEPOOL), the market’s stakeholder organization.

Another boost came from The Solar Massachusetts Renewable Target (SMART) program, which began accepting applications in November 2018. It added a financial incentive to integrate and operate energy storage alongside solar, creating a market ripe for storage developers with the means to pursue multiple revenue streams. However, it raised the question of ownership of capacity rights. A compromise that let storage developers maintain capacity rights was a major development coming out of the Massachusetts Department of Energy Resources (DOER) and the Department of Public Utilities (DPU).

What does it take to value stack?
Simply put, it takes a lot of work. Advanced control software is key to providing multiple services, including wholesale market services (capacity, reserves, energy, frequency regulation) and retail services such as peak shaving, distribution utility demand response, and installed capacity charge reduction. While providing all these services, advanced software also needs to manage compliance with incentive programs such as the federal investment tax credit (ITC) and, in the case of Massachusetts, compliance with its SMART program and storage adder.

Associate Professor, Aaron Marshall, is working towards developing a stable, reliable, cost-effective redox flow battery alternative to the traditional Lithium-ion (Li-ion). He is developing redox flow batteries that promise to act as a viable energy storage system.

According to Marshall, most of the electricity is not used during daylight hours. Thus, a reliable, stable way of storing energy is required.

The energy stored in Li-ion batteries interacts with and absorb into the solid electrodes. This causes physical changes in electrodes, i.e., electrodes expand and contract during the charging and discharging process. The continuous changing of the physical structure in a Li-ion battery, in the end, destroys the electrodes, to the point where they can’t absorb as much energy.

After some time you might probably charge your battery to half and, because it’s not effectively recyclable, the average consumer replaces the battery.

Unlike conventional Li-ion battery, the redox flow batteries don’t change. Instead, the system uses tanks of liquid, made up of metals dissolved in a solution, which is charged and discharged. Also, redox flow batteries don’t lose charging capacity over time because the solution doesn’t wear.

Marshall said, “This makes redox flow batteries sound very attractive, but there are challenges to making it a viable option. One challenge to redox flow batteries at this stage is how slow the battery can be charged and discharged. To release a comparable amount of power as Li-ion batteries, the flow battery electrodes need to be big – impractically big.”

“We are working towards developing a more viable system. If we can halve the size of the electrodes by doubling the speed of the reaction, then we can reduce the cost. If we can make a cheaper system that is comparable in price to a Li-ion battery, but lasts at least twice as long and is more stable, wouldn’t that be attractive?”