Flow batteries have made strides recently in bringing down costs and improving efficiencies, but they are going to have a tough time competing with the entrenched market leader: lithium-ion batteries.

More than half of the 1,280 MWh of worldwide battery installations on the power grid since 2010 have been li-ion batteries, according to Department of Energy data. Looking at just 2015 and 2016, that share rises to 60%. In the United States, li-ion has an even bigger market share at 78% since 2010 and 97% since 2015.

By comparison, sodium-based batteries comprise about 30% of the worldwide grid storage market and flow batteries just 7%.

But it seems that just about every other week, researchers announce advances they say will make flow batteries cheaper, safer and more competitive when stacked up against li-ion batteries.

Theoretically flow batteries would be the logical choice for utility-scale grid applications. Flow batteries exchange negatively and positively charged fluids to produce electrical current. There is also relatively little degradation of the fluids, giving them longer charge-discharge cycles and longer life spans. They can also be scaled to match growing needs relatively by increasing the amount of fluid in the tanks.

But some of the disadvantages for flow batteries include expensive fluids that are also corrosive or toxic, and the balance of system costs are relatively high along with the parasitic (on-site) load needed to power the pumps.

The market leader in flow battery chemistry is vanadium, but researchers are working on other chemistries to bring down costs and improve the safety and environmental profile of flow batteries.

Just last month, researchers at Harvard University said they had developed an aqueous organic and organometallic redox flow battery that uses a neutral, non-corrosive liquid. And researchers at the universities of Michigan and Utah last month said they have found a way using computer modeling to devise a flow battery anolyte that is 1,000 times more stable than existing compounds.

Researchers are also tweaking less exotic compounds, such as derivatives of a chemical based on vitamin B2, in an effort to improve flow battery chemistry.

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With the ability to control generation and load, storage becomes one of the most critical assets in the utility portfolio. The results of incorrectly assembling disparate components from multiple vendors into a single solution could result in potentially dangerous and expensive failures.  As the industry begins to scale and multi-megawatt sites are deployed in just a few short months—expertise in software, system integration, design, construction, grid integration and ongoing management and maintenance are the critical factors for success. 

Download this complimentary white paper today to learn about best practices in designing and deploying the next-generation of intelligent energy storage solutions.

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Massachusetts in 2015 announced a $10 million Energy Storage Initiative (ESI) to expand the state’s energy storage industry and infrastructure.

In the first phase, the Department of Energy Resources (DOER) conducted and produced a study, State of Charge, which found that the state could support as much as 600 MW of energy storage. The solicitation is the second phase of the ESI program, and it is designed to demonstrate the viability of storage in the state’s grid.

In addition, a bill signed into law in August set in motion the process for Massachusetts to adopt an energy storage mandate, making it the only the third state in the nation to do so.

The Massachusetts DOER is now crafting specific energy storage targets that are expected to be completed by July 2017 and could take effect as soon as January 2020.

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It is not only the grid that is changing. Buildings are also changing how they use energy. Some are generating energy with wind or solar power and many are engaged in energy management programs.

All those functions increase the complexity of energy flows and require sophisticated technology to ensure reliability and efficiency.

The demonstration project is funded with about $1 million from the Department of Energy and corporate sponsors. The corporate partners in the project are FirstEnergy, Eaton, Siemens and Johnson Controls.

Simulated tests of energy control and flows will be conducted by the NASA Glenn Research Center.

The project aims to develop and showcase means of incorporating smart building technologies with conventional, solar and wind power while using batteries for backup power and to meet peak demand and store non-peak energy.

“What we’re doing is kind of preparing these campuses to be these living labs for these concepts,” Alexis Abramson, director of the Great Lakes Energy Institute at Case Western, told The Toledo Blade.

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As president Trump’s administration prepare to levy tax cut reforms, other Congressional lawmakers are taking a different tack. 

Several bills that would bolster energy storage are waiting in the wings this congressional season, signaling the growing significance of the resource. 

“At this stage there are a lot of moving parts, but we expect multiple pieces of legislation related to storage and taxes to be introduced,” Matt Roberts, executive director of the Energy Storage Association said.

Chief among those bills could be one that failed to make it through the last congressional session, but will likely be re-introduced in the current session.

Sen. Martin Heinrich (D-NM) said he plans to re-introduce legislation in the current congressional session that would provide an investment tax credit for energy storage. He first introduced the tax credit in 2016, but it failed to pass out of committee. 

The Energy Storage Tax Incentive and Deployment Act, which Heinrich’s office said will be introduced “in the near future,” would provide the same investment tax credit (ITC) for commercial energy storage installations as is currently available for solar energy in section 48 of the Internal Revenue Service code.

All forms of storage technology, from flywheels and batteries to pumped hydro and thermal energy, would qualify for the credit as long as they have at least 5 kWh of capacity. Qualifying projects could be consumer-owned, grid-connected, or off-grid.

The proposed legislation, co-sponsored with Dean Heller (R-NV), would also extend the ITC to residential applications of at least 3 kWh, but would apply only to battery storage systems.

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Federal regulators continue to explore how electric storage can participate in wholesale markets, and have directed the Midcontinent ISO to file tariff changes. The commission denied IPL’s petition on two of three points, also declining to find the grid operator’s tariff unjust and unreasonable with respect to the current dispatch protocols for regulation service.

But FERC did say the tariff “unnecessarily restricts competition” by preventing storage from providing all the services that they are technically capable of providing. The order calls in the grid operator to explore the participation of all forms of storage, “regardless of the technology, in all MISO markets that they are technically capable of participating in, taking into account their unique physical and operational characteristics.”

IPL filed its complaint in October, complaining the MISO tariff was unjust in how it treated storage, in particular
the utility’s grid-scale lithium ion Harding Street Station Battery Energy Storage System. The 20 MW, 20 MWh project went into service in May, but the company has complained that while the batteries are valuable, there is no regulatory path for IPL to get paid.

You can read more of Utility Dive’s coverage about the project, and how IPL is seeking to revise storage tariffs, here. The utility knew the grid rules were not favorable for battery storage back in 2009 when it began developing plans for the project, but it was hopeful that those issues would be addressed.

“We thought we would be able to tweak the regulations, but that didn’t happen,” Lin Franks, senior strategist for RTO, FERC and compliance Initiatives at IPL, told Utility Dive at the time. 

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Trump’s infrastructure wish list includes many provisions observers would expect — the document is heavy on the bridges and road projects he promised throughout the campaign would create jobs for Americans. 

Those in the utility industry who hoped that affinity for big infrastructure projects would translate into power sector programs may take heart in the document released by McClatchy on Tuesday. Just how the Trump administration plans to encourage the projects remains unclear, but it could give an indication of the White House’s priorities.

Of the 50 infrastructure projects, seven focus on the electricity sector:

• #9: The Plains and Eastern transmission lines, which aim to move wind power from the Oklahoma panhandle to load centers in Tennessee;
• #12: Hydroelectric Plants operated by the U.S. Army Corps of Engineers, many of which are slated for upgrades;
• #16: The TransWest Express Transmission line, which would deliver renewable energy produced in Wyoming to load centers in California, Nevada and Arizona;
• #17: The Chokecherry and Sierra Madre wind projects, an up-to 3,000 MW wind energy project in Wyoming;
• #20: The Atlantic Coast Pipeline, a multi-utility project that would transport gas from West Virginia down through North Carolina;
• #21: The Champlain Hudson Power Express, a hydropower project that could bring up to 1,000 MW of clean power to the New York metro, and;
• #49: Energy Storage and Grid Modernization in California, which highlights the mitigation efforts taken during the Aliso Canyon natural gas shortage.

It’s not clear whether the document is a draft or finalized edition, nor whether it has been submitted to congressional lawmakers. But according to McClatchy, the National Governors’ Association asked state governments for input on an infrastructure program list for the transition team last month, and that list is nearly identical to the one compiled by the White House. 

Though the NGA list was preliminary, the association’s letter to state governments pledged “there will be a more formal process for states to submit information” once Trump takes office. 

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The pumped storage project being considered by San Diego could power more than 300,000 homes, while also helping add renewable energy to the grid in times of high demand. The project would also enhance the city’s efforts to run on 100% renewable energy by 2035. The Water Authority and the City of San Diego have a preliminary permit from the Federal Energy Regulatory Commission, allowing the agencies to pursue the development near the San Vicente Reservoir.

“When we filled San Vicente Reservoir last summer, we filled it with more than just water – we filled it with huge potential for energy benefits,” Mark Muir, chair of the Water Authority Board of Directors, said in a statement last week. “Given this new potential for energy from a recently expanded water resource, it’s only prudent to continue to research the potential benefits to our region’s ratepayers.”

The project calls for creating a small reservoir above the existing San Vicente Reservoir, and a tunnel system and underground powerhouse to connect the two reservoirs. According to the city, the powerhouse would contain four 125 MW reversible pump-turbines to move water to the upper reservoir or generating power as it flows down during peak demand. In off-peak hours, water will be pumped into the upper reservoir, the city said in a description. 

Letters of interest are due Feb. 15. An estimated value on the project is not available yet, but further details on the solicitation can be found on the Water Authority’s contracting opportunities page here. 

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Energy storage is having an identity crisis in wholesale markets, and federal regulators are trying to fix it.

The question is simple: how do you define energy storage? For system operators, the answer is varied since storage can be categorized as generation, load or both.

To solve the conundrum, the Federal Energy Regulatory Commission opened a rulemaking for the nation’s six grid operators in order to make a place for energy storage in the markets.

As storage becomes cost-effective it can provide a litany of grid services and help alleviate concerns over the intermittency of renewable energy.

With that in mind, FERC opened a proceeding with a Notice of Proposed Rulemaking that will amend its regulations to “to remove barriers to the participation of electric storage resources and distributed energy resource (DER) aggregations in the capacity, energy, and ancillary service markets.”

Wholesale electric markets were not designed to consider energy storage, but the FERC proceeding “might solve that problem,” Shayle Kann, senior vice president at GTM Research said at at a recent storage summit.

“The rules may not create the economic case,” he said. “But the potential is there to open the markets.”

The new tariffs must accomplish two things, according to the NOPR.

First, they must establish market rules that recognize “the physical and operational characteristics of electric storage resources” and allow them to participate in the wholesale electricity markets.

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