Researchers from Drexel University and Trinity College in Ireland, have created ink for an inkjet printer from a highly conductive type of two-dimensional material called MXene. Recent findings, published in Nature Communications, suggest that the ink can be used to print flexible energy storage components, such as supercapacitors, in any size or shape.

Conductive inks have been around for nearly a decade and they represent a multi-hundred million-dollar market that is expected to grow rapidly into the next decade. It’s already being used to make the radiofrequency identification tags used in highway toll transponders, circuit boards in portable electronics and it lines car windows as embedded radio antennas and to aid defrosting. But for the technology to see broader use, conductive inks need to become more conductive and more easily applied to a range of surfaces.

Yury Gogotsi, Ph.D., Distinguished University and Bach professor in Drexel’s College of Engineering, Department of Materials Science and Engineering, who studies the applications of new materials in technology, suggests that the ink created in Drexel’s Nanomaterials Institute is a significant advancement on both of these fronts.

“So far only limited success has been achieved with conductive inks in both fine-resolution printing and high charge storage devices,” Gogotsi said. “But our findings show that all-MXene printed micro-supercapacitors, made with an advanced inkjet printer, are an order of magnitude greater than existing energy storage devices made from other conductive inks.”

While researchers are steadily figuring out ways to make inks from new, more conductive materials, like nanoparticle silver, graphene and gallium, the challenge remains incorporating them seamlessly into manufacturing processes. Most of these inks can’t be used in a one-step process, according to Babak Anasori, Ph.D., a research assistant professor in Drexel’s department of Materials Science and Engineering and co-author of the MXene ink research.

Renewable energy has come a long way in the last decade and that’s good for all of us. But a successful clean energy market and smart power grid can only go as far as advances in energy storage can take us.

With that in mind, U.S. Sens. Cory Gardner, R-Colo., and Martin Heinrich, D-N.M., introduced legislation Thursday that would expand the investment tax credit (ITC) to include standalone energy storage investments. As it is now, only a small subset of energy storage projects co-located with solar are eligible.

Why does this matter?

First, by making investment in energy storage more attractive it helps to increase the efficiency and decrease the costs of how energy companies generate and deliver electricity for all technologies.

Any energy company — whether powered by solar, wind or gas — can use energy storage to provide electricity more reliably and efficiently for their customers. By storing the electricity that’s generated and saved until it’s needed, energy storage can optimize grid operations. But because only some energy storage projects — those paired with solar — qualify for the tax credit there are limits to innovation in this space.

Members of Congress on both sides of the aisle support an “all of the above” strategy to energy, and the Gardner-Heinrich legislation helps accomplish just that.

Second, the tax credit would spur new investment in energy storage as a rapidly growing clean energy industry that already supports tens of thousands of jobs.

Businesses need policy clarity and certainty before making long-term investment decisions. The demand is already there. Consumers increasingly care about where their electricity comes from. They want clean and affordable energy options. And the power grid needs to be reliable as our economy becomes more electrified and digitalized, with more devices connected and using electricity.

Energy companies can meet this challenging demand with energy storage, but the current tax code is holding them back.

Take, for example, a business planning to spend $100,000 per year over the next 10 years on energy storage development. If that business could access the ITC, it could potentially save $148,000 on its $1 million investment over the life of the project.

Electrical and heat storage using specially nanocoated salt (NCS) could be economically competitive with pumped hydro, SaltX has said, with a large-scale demonstration facility inaugurated in Berlin, Germany.

Headquartered in Sweden, SaltX has been “working with salts for 15 years”, the company’s marketing director Eric Jacobson told Energy-Storage.news today. This specific application for the salt-based energy storage technology has been in development since customers began expressing an interest in seeing it scaled up a couple of years ago, Jacobson said.

Last Thursday, SaltX and its project partner Vattenfall inaugurated the first 10MWh system based on the technology, in Spandau, Berlin. The pilot plant has an output of 0.5MW, Jacobson said, with energy utility Vattenfall installing the system at one of its combined heat and power (CHP) plants, Reuter-C.

“It’s been known for a while that you can store energy in salt, and there’s been two problems with doing that,” Jacobson said.

“First, the salt is highly corrosive so the application itself has been really expensive because you need special material as the salt starts to corrode the metal and eventually it will be destroyed. Secondly, when you are discharging this thermal battery the salt content has agglomerated, started to lump together. So after 60 cycles you lose the properties of the salt and it starts to not be so efficient.”

Claiming to have solved this problem by applying a proprietary material – patented as far back as 2013 – as a nanocoating to salt crystals, which prevents this corrosion and the agglomeration, Jacobson said that it will require tanks of inexpensive metal to store the material, without the need for pressurisation inside. SaltX claims this will make the technology easier to scale up to larger and larger capacities of storage.

“We use a technology where, it’s similar to an engine and a fuel tank, so the salt is the fuel and it’s really easy to scale this tank up and then we have a reactor or engine where we can take out the energy or the power.

“Whether we want 10MWh or 100MWh of storage, that’s not a big deal for us. That’s one of our advantages.”

Energy storage has been described as the Swiss Army knife of the electric industry. Others call it the killer app of the smart grid, or they say it is the empowering technology. Whatever it is called, energy storage has proven to be a valuable multifaceted technology.

The Port of Los Angeles is installing an ABB flywheel energy storage system as part of a new microgrid. In northern England, near Manchester, the world’s first grid-scale 5-MW/15-MWh liquid-air energy storage (LAES) project was completed. In addition, GE has developed a grid-scale energy storage system, called the Reservoir, with black-start capability. And Southern California Edison, working with Fluence, is installing one of the world’s largest lithium-ion (Li-ion) battery-based energy storage systems, to improve the reliability and environmental goals of a gas-fired combined-cycle power plant.

Energy geeks are excited about the growing list of cutting-edge energy storage systems, and it is getting longer every day. Modern energy storage apparatuses are versatile, supplying power from a few kilowatts to multiple megawatts. They can supply this energy for a short time to many megawatt-hours.

When combined with other technologies, energy storage systems add value to the total system. Distributed energy resource (DER) systems with energy storage extends grid reliability to both sides of the meter. Paired with renewable energy generation, the technology makes the renewable’s electricity dispatchable. Used with demand management systems, peak loads are shifted. And, when merged with aging infrastructure, energy storage improves performance and extends the service life of equipment.

Changing Role

As the Smart Electric Power Alliance stated, “The role of energy storage can be summed up in two words: grid empowerment.” Fortunately, regulators, utilities and grid operators are beginning to see the significant role in the electrical T&D systems. According to a National Renewable Energy Laboratory (NREL) report on energy storage, understanding the economic influences, market issues and regulatory factors are critical. NREL went on to say reduced costs and improved characteristics have seen energy storage taking a larger role in the marketplace.

Elon Musk has stated that Tesla’s (NASDAQ:TSLA) energy storage business will be as large as its car business in the long term.1 ARK’s research shows that foregoing planned gas peaker plants and replacing them with utility scale energy storage could generate roughly $10 billion in revenues per year, more than six times Tesla’s $1.5 billion utility energy storage revenue in 2018. As battery costs continue to fall during the next five to ten years, the global addressable market for utility energy storage should expand to $800 billion.

Last July, California utility PG&E proposed four energy storage projects to replace natural gas plants in the South Bay.2 Two of these projects are the largest utility energy storage projects ever proposed – 1,200MWh and 730MWh – dwarfing the current record holder, Tesla’s 129MWh battery in Australia. As battery costs continue to fall, utility energy storage will begin to compete with existing natural gas peaker plants, reaching a price point that will motivate utilities to shut down underutilized plants.

The chart below compares the cost of electricity from natural gas peaker plants to the cost of electricity from battery-based energy storage, with two scenarios highlighted. The brown circle illustrates the scenario we face today: the average natural gas peaker plant is utilized ~10% of the time in the U.S. resulting in a levelized electricity cost of ~$0.14/kWh.3 The red lines show ARK’s forecast: utility energy storage battery costs should drop from $400/kWh to $150/kWh in the next five years, which results in an electricity cost of ~$0.09/kWh, undercutting the cost of natural gas plants that operate 25% of the time or less.

Pumping and storing water from lower to higher elevations and then releasing it to drive turbine generators is one of the oldest, most efficient and widely used means of generating baseload electricity known. An Australian National University (ANU) research team found no less than 530,000 potential short-term, off-river pumped-hydro energy storage sites worldwide that could be used to support low-cost, renewable energy zones and power grids. “Pumped hydro accounts for 97 percent of energy storage worldwide, has a typical lifetime of 50 years and is the lowest cost large-scale energy-storage technology available,” pointed out Bin Lu, a project team member and PhD candidate at the ANU Research School of Electrical, Energy and Materials Engineering (RSEEME).

Another promising large-scale energy storage technology recently emerged in news reports, one that, akin to pumped hydro, is based on fundamental principles of Newtonian physics taught to undergraduate college students. About an hour’s drive south of Milan, Italy, Energy Vault intends to use cranes to lift 35-metric ton bricks from ground level to build a tower, then release the stored potential energy by lowering them again to drive turbine generators.

In a third instance, Highview Power is out to prove that its liquid air energy storage systems (LAES) can provide gigawatt-hours (GWh) worth of cheap, highly efficient energy storage for five-10 hours per day. “At giga-scale, energy storage resources paired with renewables are equivalent in performance to—and could replace—thermal and nuclear baseload in addition to supporting the electricity transmission and distribution systems while providing additional security of supply,” according to the company.

Cheap, reliable pumped hydro energy storage sites abound
An untold wealth of cheap, efficient pumped hydro energy storage sites exist worldwide, sites that could be linked with solar or wind power systems to create emissions-free electricity grids, according to the ANU’s latest, most ambitious, audit. The findings run contrary to conventional wisdom.

Legislation recently introduced in the U.S. House that would expand the federal solar investment tax credit (ITC) to energy storage technologies has gained the backing of major trade groups representing the solar, hydropower, and wind sectors.

The Energy Storage Tax Incentive and Deployment Act (H.R. 2096), introduced on April 4 by Reps. Mike Doyle (D-Pa.), Earl Blumenauer (D-Ore.), and Linda Sanchez (D-Calif.), would amend Section 48 and 25D of the Internal Revenue Code to add all forms of energy storage of more than 5 kWh, including batteries, compressed air, pumped hydropower, hydrogen storage (including hydrolysis), thermal energy storage, regenerative fuel cells, flywheels, capacitors, superconducting magnets, and others. The measure matches legislation introduced last year in the House and Senate (S. 1868 and H.R. 4649). While both measures were referred to committees, they were never heard.

Under current law, energy storage can only qualify for the ITC when integrated with ITC-eligible solar resources under a narrow set of conditions and subject to recapture risks. But according to the Energy Storage Association, these conditions “create tremendous uncertainty for investors.”

The group argues that numerous energy technologies—fuel cells, solar power, microturbines, and combined heat and power—can access the ITC, but that the narrow application of energy storage allowed by IRS rules prevents non-ITC-eligible resources (such as wind and natural gas) from deriving the same investment benefit as solar power. “Clarifying eligibility of the ITC for energy storage will create a level playing field across electric grid technologies, improve business certainty, and allow energy storage to pair with any type of generation asset. Doing so will enhance grid efficiency and resilience while creating more jobs and capital formation,” it said on April 4.

The Joint Committee on Taxation in 2017 suggested that storage eligibility for the ITC could create a tax expenditure of about $300 million over 10 years. The Section 48 ITC, which applies to “business investment energy storage,” is scheduled to begin phasing down from 30% in December 2019 to 26% in 2020, 22% in 2021, and 10% from the beginning of 2022. The Section 25D ITC, which applies to residential storage and is currently 30% in 2019, will fully phase out in 2022.

In an April 9 letter, nine environmental, citizen, and trade groups—including from nearly all renewable power sectors—urged House leaders to include the bill in energy tax extenders legislation. “H.R. 2096 would resolve the uncertainty facing companies who seek to utilize the ITC for energy storage, spurring greater investment and creating jobs while extending the benefits of energy storage deployment among a wider diversity of technologies and industries. Those deployments in turn will accelerate the transition to clean energy and position the U.S. as a global leader in energy storage technology,” they said.

A large-scale energy storage project to be built in Texas will take advantage of the system’s flexibility to deliver multiple services, as opportunities grow in the state’s Electricity Reliability Council of Texas (ERCOT) market.

Independent power producer (IPP) GlidePath Power has contracted Oregon-headquartered Powin Energy to construct a 10MW / 10MWh energy storage system (ESS) utilising lithium iron phosphate (LFP) battery technology at an as-yet unspecified location in the ERCOT service area.

A GlidePath representative told Energy-Storage.news that the project “has the potential to be co-located” with renewable energy facilities, in a state where there is a large installed capacity of wind energy and a growing interest in solar. The company was tight-lipped on revealing which applications the system will serve but instead issued a general statement on various opportunities within ERCOT.

“ERCOT is a highly competitive market with room for multiple technologies to participate in providing energy, ancillary service and reliability functions,” the GlidePath spokesman said.

“GlidePath is excited to enter this market with an energy storage system that will demonstrate great value to ERCOT consumers in a market projecting historically low planning reserve margins.”

Going forward, demand for electricity is rising rapidly in Texas, while GlidePath quoted figures to Energy-Storage.news from ERCOT’s preliminary assessment for total resource capacity in the 2019 summer season that show a planning reserve margin of just 7.4% with “total resource capacity being extremely narrow”, the spokesman said.

As well as this shortfall in planned reserve capacity which ESS could help bridge, ERCOT is seeking ways to add dispatchable energy storage markets, in common with other RTOs and ISOs around America. The ERCOT grid is not interconnected with the rest of the US’ electricity networks and does not fall under the jurisdiction of the Federal Energy Regulatory Commission (FERC) Order 841, instructing network operators to incorporate energy storage into wholesale markets.

Elon Musk has stated that Tesla’s (NASDAQ:TSLA) energy storage business will be as large as its car business in the long term.1 ARK’s research shows that foregoing planned gas peaker plants and replacing them with utility scale energy storage could generate roughly $10 billion in revenues per year, more than six times Tesla’s $1.5 billion utility energy storage revenue in 2018. As battery costs continue to fall during the next five to ten years, the global addressable market for utility energy storage should expand to $800 billion.

Last July, California utility PG&E proposed four energy storage projects to replace natural gas plants in the South Bay.2 Two of these projects are the largest utility energy storage projects ever proposed – 1,200MWh and 730MWh – dwarfing the current record holder, Tesla’s 129MWh battery in Australia. As battery costs continue to fall, utility energy storage will begin to compete with existing natural gas peaker plants, reaching a price point that will motivate utilities to shut down underutilized plants.

The chart below compares the cost of electricity from natural gas peaker plants to the cost of electricity from battery-based energy storage, with two scenarios highlighted. The brown circle illustrates the scenario we face today: the average natural gas peaker plant is utilized ~10% of the time in the U.S. resulting in a levelized electricity cost of ~$0.14/kWh.3 The red lines show ARK’s forecast: utility energy storage battery costs should drop from $400/kWh to $150/kWh in the next five years, which results in an electricity cost of ~$0.09/kWh, undercutting the cost of natural gas plants that operate 25% of the time or less.