Energy storage could get a big boost if California officials green-light plans by utility Pacific Gas and Electric Co. to move forward with some 567 megawatts of capacity.

Included in the mix is more than 180 MW of lithium-ion battery storage from Elon Musk’s company Tesla. The Tesla-supplied battery array would be owned by PG&E and would offer a 4-hour discharge duration. The other projects would be owned by third parties and operated on behalf of the utility under long-term contracts. All of the projects would be in and around Silicon Valley in the South Bay area.

Once deployed, the storage would sideline three gas-fired power plants—the 605-MW Metcalf Energy Center, the 47-MW Feather River Energy Center, and the 47-MW Yuba City Energy Center—that lack long-term energy supply contracts with utilities. Even without the contracts, the state’s grid operator identified the units as needed for local grid reliability. It, and independent power producer Calpine, which owns the plants, asked federal regulators to label the plants as “must run.” That would let them generate electricity and be paid for it even without firm utility contracts.

Both PG&E and California’s utility regulators object to that idea. They argue that the must-run designation without firm contracts would distort the state’s power market and lead to unfair prices. Backing up their objection, regulators earlier this year directed the utility to seek offers to replace the gas-fired power plants with energy storage.

The utility says that its search prompted more than two dozen storage proposals with 100 variations. PG&E narrowed the list to four, which it presented to state regulators in late June.

One of the projects, Vistra Energy Moss Landing storage project, would be owned by Dynegy Marketing and Trade, a unit of Vistra Energy Corp. The holding company manages more than 40 gigawatts of generating capacity across 12 states. The project would be a transmission-connected, stand-alone lithium-ion battery energy storage resource in Monterey County. The facility, which would feature a 300-MW, 4-hour duration battery array, could enter service in December 2020 under a 20-year contract.

A second project, Hummingbird Energy Storage, would be owned by a unit of esVolta, a new company that is partnering with Oregon-based Powin Energy Corp. and Australia-based Blue Sky Alternative Investments. The Santa Clara County–sited resource would include a 75-MW, 4-hour-duration Li-ion battery array. It also could enter service in December 2020 and would operate under a 15-year contract.

Energy storage experts got to ask what their country could do for them Wednesday.

The House Energy and Commerce Committee convened a hearing on “the role of energy storage in the nation’s electricity system,” which gave industry insiders the rare chance to share what they’ve been thinking before a national audience.

The committee members of both parties generally expressed support for energy storage as a nationally valuable asset to allow better control of the supply and demand of electricity, to avoid more expensive traditional grid upgrades and to provide resilience after cataclysmic events.

“Mr. Chairman, energy storage has the potential to fundamentally transform the way we produce and use electricity in a way that benefits the nation as a whole, but we must be willing to make the necessary commitments and the necessary investments in this technology for it to do so,” said Rep. Bobby Rush of Illinois, a Democrat.

For a young industry that typically talks in state-level goals, but is largely focused in only a handful of states, the event marked a maturation in ambition. The goal: to clarify what a federal energy storage policy should look like.

No unified federal storage policy currently exists, although the oft-cited FERC Order 841 is pushing grid operators to systematically value storage’s unique attributes and allow it to compete in wholesale markets.

Potential congressional action will likely be focused elsewhere. Here are the key ideas proposed at the hearing.

Expand federal research and development funding for energy storage technology

Simply earmarking more money for storage research would be the easiest action for Congress to take.

This appears feasible, even in the current political climate. When the Trump White House proposed slashing the budget for the Department of Energy and ARPA-E, the House responded with more funding.

R&D funding could help bring down costs over the next few decades, but it won’t help the practitioners installing batteries today.

MISO last week outlined the range of stakeholder feedback it has received since revealing its straw proposal for energy storage resources (ESRs) in June.

The RTO’s proposal for complying with FERC Order 841 called for ESRs participating under four modes of commitment: charging, discharging, continuous operations and outage/offline. When in online mode, storage would be treated as must-run resources. (See MISO Offers Straw Storage Proposal to Meet Order 841.)

At a July 12 Market Subcommittee meeting, MISO said that stakeholders have stressed the importance of coordination with distribution system providers and expressed concern that requiring hourly offers might limit storage’s flexibility. Others reminded the RTO that storage resources are not generation and said they should not be bound to a must-offer requirement. Some said storage should be treated like load-modifying resources while others said storage should be restricted to the ancillary services market, despite FERC’s requirement that it be allowed to provide capacity and energy.

Stakeholders asked how hybrid storage-and-renewable formats will fit under the proposal and requested optimized pumping and withdrawal options for pumped storage facilities. MISO dismissed the latter as beyond the scope of Order 841 but said it will meet with market participants to discuss ways to fully incorporate pumped storage into the market.

MISO Director of Market Design Kevin Vannoy said the RTO would return in August with more detail around the proposal and examples of how storage will function under the model. It will focus examples on non-market services, storage modeling, metering, commitment and dispatch rules, Vannoy said. Market clearing prices or LMPs will set emergency pricing for injecting and withdrawing during maximum generation events.

“There might be restoration payments when energy storage resources provide black start restoration from an event,” he added.

MISO also said it will rely on its existing ramp performance measures — excessive and deficient energy flagging and deployment failure penalties — to evaluate storage performance.

Vannoy said he’s gotten at least two requests for private meetings with MISO staff to discuss the straw proposal. While MISO isn’t opposed to setting up one-on-one meetings, he said, staff are busy working on Order 841 compliance and have limited time. He also said it may be best to raise storage issues and suggestions in public meetings.

“We’re not necessarily looking to facilitate private discussions,” Vannoy said, urging stakeholders to bring their storage questions and recommendations to the Resource Adequacy, Market and Reliability subcommittees.

Redox flow energy storage systems, earmarked by Navigant Research to be one of the fastest growing electrochemical storage technology sets over the next decade, are being deployed in recent or upcoming projects by Cellcube Energy Storage Systems and Redflow.

Cellcube is the continuation of the line of energy storage systems dubbed VFB (‘vanadium flow battery’) and produced originally by Gildemeister Energy Storage. The German company’s VFB assets were acquired by Canada’s Stina Resources Group and the company changed its name to Cellcube Energy Storage Systems.

As previously noted, taking on a product with a history of testing early market appetite for long duration storage systems, Cellcube is targeting a level of vertical integration in its supply chain. Earlier this month the company also acquired Pure Vanadium Corp, a research and technology company licensed to produce vanadium electrolytes.

Last Monday, Cellcube announced the delivery of its first energy storage system in Germany, followed two days later by the announcement of an installation in New York. This morning, the company also said it has delivered a system to the University of Calgary, Alberta, Canada.

EnerPrax (‘Energy storage in practice’) is a proof of concept project in Germany, conducted by municipal utility Gelsenwasser at Saerbeck Bioenergy Park, a Smart City pilot. The site will test an unspecified number of Cellcube energy storage systems supplied through Cellcube’s local subsidiary Enerox. They will act as eight-hour storage units to provide baseload energy, stabilising the grid and shifting energy production to meet demand.

The arrival of a VFB at the University of Calgary this week is in order to advance research in vanadium and vanadium electrolyte production. In a recent interview, Navigant Research analyst Ian McClenny said that while flow energy storage is expected to grow its share of the stationary storage market significantly over the next 10 years, improvements in components and raw materials are still desirable. Cellcube said in a release that the electrolyte is typically around 30% to 40% of the total cost of the battery.

In New York, two Cellcube systems are being installed at the offices of electric power line contractor O’Connell Electric. Again, while sizing of the units was not disclosed, Cellcube said the batteries will be integrated into a solar-plus-storage microgrid that could lower onsite electricity costs by as much as 40%.

Because renewable energy supplies in the Middle East are intermittent, viable storage solutions are needed in the region to ensure long-term success and broad adoption. The Middle East has set robust sustainable energy goals, so battery storage is the next step to increase reliability of energy supply and infuse the ability to store excess energy when demand for power is low. Batteries also reduce carbon dioxide emissions and can respond nearly instantaneously to increased grid demand, unlike fossil-fuel plants, which can take up to a few hours to reach peak. Battery storage technologies in the Middle East can enable widespread integration of renewables, unlock grid flexibility, and bolster grid reliability.

The upward trend of renewables has brought unlikely bedfellows to alternative energy discussions. Particularly, the falling costs of solar photovoltaic (PV) power has ushered in a new era in which countries are increasing their renewable commitments to the Paris Agreement reached at COP21. Middle East countries, too, are beginning to diversify their energy sources, which seems contradictory to a region that is one of the world’s leading oil and gas producers. Yet the Middle East’s oil producers have set ambitious targets to add solar and wind capacities to their power mix in order to free up more crude for export. Specifically, the UAE aims to produce nearly half of its electricity through renewables by 2050, while Saudi Vision 2030 includes a target of 9.5 gigawatts by 2050. Battery storage will be a crucial element toward this regional shift to renewables.

Saudi Arabia, the world’s largest oil exporter, will tender around 3.25 Gigawatts of solar projects and around 800MW of wind this year, as it looks to produce 9.5GW of power through renewable sources by 2023. The UAE, the second-biggest Arabian Gulf economy, currently derives around 98% of its energy needs from gas. It has set a target to meet 44% of its energy needs from renewables, 38% from gas, 12% from fossil fuels, and the remainder from nuclear sources.

Why Battery Storage is Essential to a Middle East Shift to Renewables

Renewable energy sources like the sun and wind are affected by location, weather, and time of day. Thus, renewable energy generation creates a variable supply of energy. That’s where battery storage comes in.

The electricity grid is a complex system in which power supply and demand must be equal at any given moment. Constant adjustments to the supply are needed for predictable changes in demand, such as the daily patterns of human activity as well as unexpected changes from equipment overloads and storms. Energy storage plays an important role in this balancing act and helps to create a more flexible and reliable grid system. When used for energy storage, batteries can be located nearly anywhere convenient for distribution, such as a battery facility located near consumers to provide power stability, or end-use, like batteries in electric vehicles.

California’s carbon emissions are down 13 percent from their peak in 2004, according to new data released this week by the California Air Resources Board. You can thank Arnold Schwarzenegger.

Back when the Predator and Jingle All the Way star was California’s governor in 2006, he signed into law State Assembly Bill 32, requiring that the state reign in its greenhouse gas emissions back to their 1990 levels by 2020.

Based on the new analysis by the state’s Air Resources Board, California succeeded in that target back in 2016: the total for carbon emissions in 1990 was about 431 million metric tons, and it’s come back down to 429 million metric tons in 2016.

Schwarzenegger suggested on Twitter, Wednesday, that other states should follow their lead.

The next step, according to a statement from California’s current governor, Edmund G. Brown Jr., “is for California to cut emissions below 1990 levels by 2030 — a heroic and very ambitious goal.”

Specifically, the state is shooting to reduce emissions to below 40 percent of their 1990 levels by 2030 — as mandated by a more recent piece of legislation, Senate Bill 32, signed into law in September of 2016.

Their plan for making these reductions has always been complicated — very, very multi-pronged affair. In addition to a typical carbon-tax and a Cap-and-Trade Program, the state has its Renewables Portfolio Standard, the Advanced Clean Cars Program, the Low Carbon Fuel Standard and other super-specific and highly targeted programs: the Short-Lived Climate Pollutants Strategy, the Sustainable Communities Strategy and the Sustainable Freight Action Plan, etc.

There’s clearly been some notable successes from all these: Thanks to the Low Carbon Fuel Standard, for example, a record number of vehicles in the state run on biofuels, totalling 1.5 billion gallons-worth in 2016. And incentive programs have grown the solar electricity sector by 33 percent in 2016. But, some independent policy makers are skeptical of the dent all this effort is actually making.

Star-shaped gold nanoparticles, coated with a semiconductor, can produce hydrogen from water over four times more efficiently than other methods — opening the door to improved storage of solar energy and other advances that could boost renewable energy use and combat climate change, according to Rutgers University-New Brunswick researchers.

BOSTON — Clean energy storage could get a boost under grid resiliency legislation approved by the Massachusetts House of Representatives on Thursday.

Among other things, H.4739 instructs the Department of Energy Resources to study the feasibility of mobile battery storage systems. Such systems could take the place of downed substations in an emergency, said Rep. Thomas A. Golden Jr., D-Middlesex, chairman of the Joint Committee on Energy, Telecommunications, and Energy.

Around 450,000 households lost power during coastal storms in March, Golden said from the floor, highlighting the need for Massachusetts to “move into the future.”

Energy storage can shave peak power demand, relieve congestion on the grid, save money, and help reduce emissions, Golden said.

The House bill creates an Energy Storage Innovation Research Institute, and establishes a Center for Clean Transportation to conduct research and development.

On the resiliency side, it creates new requirements for utilities to assess and improve their transmission and distribution systems.

The utilities would have to submit annual reports including “heat maps” that show areas of load and congestion on the grid. Additionally, they would be urged to solicit competitive bids for “non-wires alternatives” — such as storage or demand response — when their lines need upgrades.

Grid resiliency means hardening regional power systems in the face of extreme weather or natural disasters, and such efforts must focus on “prevention, survivability, and recovery,” according to the Electric Power Research Institute.

The Baker administration in December awarded $20 million to help kick-start energy storage in Massachusetts.

The University of Massachusetts Amherst received one of the largest awards, $1.14 million, to install a lithium ion battery system in its energy supply system. Separately, Holyoke Gas & Electric built the state’s largest utility-scale storage system at its Mount Tom Solar plant.

Nationwide, the energy storage industry hopes to deploy 35 gigawatts of capacity by 2035.

Falling solar panel prices coupled with favorable national and state policies are giving energy storage technologies the jolt they need to electrify the market place. The latest such example is Pacific Gas & Electric that wants to install four battery projects totaling 2,270 megawatts.

Energy storage could be anything from shaving peak load to storing and injecting wind and solar electrons onto the grid.

“Energy storage plays an increasingly important role in California’s clean energy future, and while it has been a part of PG&E’s power mix for decades – starting with the Helms Pumped Storage Plant in the 1980’s – recent decreases in battery prices are enabling energy storage to become a competitive alternative to traditional solutions,” said Roy Kuga, vice president, grid integration and innovation, PG&E, in a release. 

“As a result, we believe that battery energy storage will be even more significant in enhancing overall grid reliability, integrating renewables, and helping customers save energy and money,” he added.

If the projects are approved by the California Public Utility Commission, the first of them will come online in 2019 while the others would follow a year later. California’s Independent System Operator is incorporating energy storage into mix of generation assets, as PG&E Corp., Sempra Energy and Edison International must collectively buy 1,325 megawatts of energy storage by 2020.

As for Pacific Gas & Electric, it would be replacing three natural gas-fired power plants owned by Calpine Corp. The utility picked three projects: 1,540 megawatts, 385.5 megawatts and 182.5 megawatts. It would also own one such project by itself, totaling 750 megawatts. The 1,540 project would be owned by Texas-based Vistra Energy and run by its Dynergy Marketing and Trade, which is different from the utility company Dynegy.

The Possibilities

The Brattle Group issued a study earlier this year that said energy storage markets could grow to as much as 50,000 megawatts over a decade if cost continue to fall and if federal policies that promoting the technology take root. Those policies must also be matched at the state level, it says.

Halfway through 2018 and large-scale battery storage in the UK has reached over 450MW installed capacity, with around 250MW being completed this year alone. This is made up of projects bigger than 1MW, including larger behind-the-meter projects that have begun to emerge.

The past few weeks have seen a flurry of activity with supply contracts being awarded, projects changing hands as well as those being completed. With sites under construction from the likes of Centrica, Anesco and Ørsted, and when projects from UK Power Reserve recently awarded to Fluence are factored in, it seems very like that the capacity installed in 2018 could reach over 500MW.

Uncertainty continues from the top