AECOM and Lockheed Martin have joined forces to build a Battery Energy Storage System (BESS) at Fort Carson, Colorado, using Lockheed Martin’s GridStar Lithium energy storage process.

AECOM officials representing the fully integrated global infrastructure firm said the Fort Carson, Colorado, site would be the largest stand-alone, commercially contracted battery at an army base. The 4.25 MW/8.5 MWh BESS is part of an energy savings performance contract (ESPC) project to reduce Fort Carson’s energy costs and increase its energy resilience.

“During project development, our team surveyed the energy storage industry for the optimum solution for Fort Carson,” Annika Moman, senior vice president of AECOM Power and Energy Services Lead, said. “We decided on Lockheed Martin’s GridStar units due to their unique modular architecture allowing for a flexible design and a reduction in operational risk. Our working partnership with Lockheed was vital to our team and Fort Carson in making this ground-breaking project happen.”

While officials acknowledged the current best primary use-case for the BESS is for demand charge reduction, the system may assume additional missions, such as renewables optimization, frequency and voltage support for Fort Carson’s distribution grid and, potentially, microgrid support.

“Lockheed Martin is pleased to collaborate with AECOM to develop and implement the new military infrastructure that will help Fort Carson increase its resiliency and reduce their electricity costs,” John Battaglini, director with Lockheed Martin Energy, said. “The versatility of energy storage is a key enabler for the military’s aggressive goals of achieving energy resiliency.”

It may not be smooth sailing for Pacific Gas and Electric’s landmark energy storage projects.

Totaling 567 MW, 2,270 MWh, the four projects were hailed as the largest battery storage investment ever proposed when PG&E submitted them for approval at the California Public Utilities Commission (CPUC) in late June. However, comments opposing the projects could slow down their approval and implementation.

Already, the state’s Office of Ratepayer Advocates (ORA) and the Direct Access Customer Coalition (DACC) have filed comments opposing the projects, prompting the CPUC to extend the approval process by at least 120 days. The comments raise questions about whether or not the energy storage projects are needed and whether PG&E’s proposal conforms to the commission’s directives.

The recently-filed comments have had very little public scrutiny, as they were only sent to the relevant parties and have not been posted on the CPUC website.

The cost of reliability

In their comments, the ORA, which is part of the CPUC, argues that the energy storage projects are not needed because the deficiency they are designed to fill will be met with new and planned transmission projects. The ORA claims the projects do not comply with CPUC resolution (E-4909) that authorized PG&E to issue a solicitation for the projects.

The resolution is designed to alleviate the need for an out-of-market contract for Calpine’s Metcalf Energy Center, a 564-MW gas-fired plant in San Jose. Calpine had told the California ISO that it would have to take the plant out of service because it was uneconomic, but the ISO determined the plant is needed, granting a reliability must run (RMR) contract.

In the resolution authorizing the storage projects, the CPUC expressed its concerns about the impact the RMR contracts would have on ratepayers and the lack of competition in the RMR process that can lead to “market distortions and unjust rates for power.”

The commission ordered PG&E to enter into energy storage contracts at “reasonable cost to ratepayers” and to take into consideration the cost and value and the results of previous, similar solicitations. But the ORA argues PG&E did not meet the CPUC’s requirements because the utility did not provide “analysis or explain how the cost of the four energy storage projects are reasonable taking into consideration the cost of the Metcalf RMR contract.” Nor did PG&E compare the four contracts to previous energy storage solicitations, the ORA said.

Costs of the energy storage projects are redacted in the public comments. The comments are not available online because they are not filed with the commission. They are only sent to the relevant parties. By law, the utility is required to respond to comments. The CPUC’s industry division will gather all comments and responses and prepares a draft resolution with its recommendation. The commission then votes on the draft resolution.

In early June, Highview Power announced that it had officially launched its first grid-scale liquid air energy storage (LAES) plant at the Viridor Pilsworth site in Bury, United Kingdom (just outside of Manchester). This five megawatt (MW)/15 megawatt-hour (MWh) facility is on the small side to truly earn the title of grid-scale, but that may be beside the point. The critical issue to consider here is that this new technology may ultimately prove to be a cost-effective long-duration energy storage resource that is – unlike compressed air energy or pumped hydro – geographically independent.

Three weeks after the June launch, Highview announced the hiring of Javier Cavada, who had previously served as President of Finnish energy giant Wärtsilä’s Energy Solutions division and Executive Vice President, as their new CEO. Cavada had overseen impressive growth in that division over the past three years and spent 17 years at Wärtsilä. These two announcements were enough to pique my curiosity, so when I had a chance to interview Cavada as well as Highview’s Director of Business Development, Matthew Barnett, I jumped at it.

Long-term storage technologies have had difficulty gaining market traction

There have been multiple long-duration energy start-ups and a few corporate corpses on the road (flow battery companies Enervault, Imergy, and Vizn – all of whom I have covered in past Forbes pieces – spring to mind) in recent years. There are also only a limited number of flow battery sites in operation.

Meanwhile, pumped hydro storage can deliver both capacity and energy, and represents about 95% of the country’s energy storage. As of 2015, the U.S. Department of Energy estimated that there are 50 projects that could deliver 40,000MW of additional storage capacity. But none have been built recently, and the Sacramento Municipal Utility District recently canceled its 400 MW pumped hydro project citing costs and financial risks. Pumped hydro also requires access to significant quantities of water, elevation, and an enormous amount of environmental permitting to withdraw water and construct reservoirs. So that resource probably won’t be the solution to the long-duration problem.

For its part, conventional compressed air energy storage requires enormous tight caverns – and there are simply not too many of those projects around (exactly two: one in Germany and the other in Alabama).

Lithium-ion: good for capacity and less so for long-term energy storage

Finally, lithium-ion is growing rapidly as a storage medium and is already found in multiple projects supporting renewables, supporting the grid, and displacing conventional resources. It’s a critical player in the storage sandbox. In fact, Pacific Gas & Electric recently requested permission from the California Public Utilities Commission for 568 MW/2270MWh. However, these lithium-ion based projects typically don’t support more than four hours of energy for every MW of capacity installed, so they won’t yet go the distance. I was, therefore, curious to find out why Highview might be different, and why they might succeed where others have encountered difficulties.

Minister for Energy Dr Megan Woods attended an event to officially inaugurate the first grid-scale battery energy storage system in New Zealand, hosted by energy retailer and project owner Mercury Energy.

The project, based around a Tesla Powerpack 2 battery system was revealed to be under development in January this year. Energy-Storage.news reported at the time that the 1MW / 2MWh of Powerpacks is connected to existing pumped hydro facilities in South Auckland and used by Mercury’s R&D centre as part of a trial of scalable grid-connected batteries.

Back in January, Mercury said battery capacity at the installation itself could be added to at a later date, and that the system, with a cost of close to NZ$3 million (US$2.01 million), would trial the redispatch of electricity generated by hydro as well as the possibility of using the Powerpacks in energy trading markets. A Mercury announcement this morning also said the project could be used to investigate the redispatch of geothermal energy.

“We see battery storage as playing an increasingly important role in providing a reliable supply of electricity in New Zealand, as we increase our reliance on wind and solar to generate our electricity,” John Clarke, general manager at grid operator Transpower, said.

“We look forward to continuing to work with Mercury throughout the trial and gather key learnings to enable the transition to New Zealand’s sustainable energy future”.

An energy storage system running on Greensmith’s GEMS software platform has been installed at a natural gas generation facility in Hungary, by Greensmith’s parent company Wärtsilä.

While energy storage with renewables have grabbed the majority of headlines within the industry, batteries have also been used in a handful of locations in combination with fossil fuel generators recently. China is developing or has already developed several, while there are other projects in territories including Australia.

Located in the Hungarian capital, Budapest, Wärtsilä’s latest project was commissioned yesterday and is the first ever energy storage project on which the company has performed an EPC (engineering, procurement and construction) role. It is also the Finnish corporation’s first ‘engines-plus-storage’ installation.

Delivered for customer ALTEO, a Budapest Stock Exchange-listed developer of energy projects including renewables in Hungary, the plant combines three of Wärtsilä’s W34SG engines with 6MW/4MWh of battery energy storage. Wärtsilä claims the W34SG engines are suitable for delivering both “flexible baseload and peak load” and can support the grid in performing ancillary services applications. The company also said the engines can reach 49% efficiency in five minutes from start up, allowing for faster ramping times than other comparable generators.

The hybrid installation will operate in ‘virtual power plant mode’ to help regulate the grid, providing primary and secondary frequency regulation services. This will allow ALTEO to participate in electricity market opportunities for those services, generating revenues. The Greensmith GEMS platform was used to integrate the systems together, while the platform’s software will control the delivery of ancillary services, while analysing ongoing changes in market conditions and rate structures.

Wärtsilä acquired Greensmith in mid-2017 after a period of the two collaborating on projects. Shortly before that takeover, the Finnish company’s energy solutions director had talked up the potential of the latter’s software platforms in enabling greater integrations of systems, including hybrids.

“Wärtsilä is a global energy systems integrator and in the future we will continue to see more examples of energy storage and sophisticated software controls being paired with power plants, wind, buildings and hydro to create hybrid solutions that cut carbon, lower costs and optimise generation,” the company’s Energy Solutions division business development manager Markus Ehrström said.

Ice storage has largely proven its worth, with projects utilizing cheaper energy to freeze a solution that can be later used for cooling during times of peak demand.

Viking’s test at the Dreisbach Enterprises’ frozen food distribution center showed a significant drop in weekly energy use and an even greater drop in peak refrigeration load.

In a sign of the increasing interest in thermal energy storage, last year, Massachusetts tapped Genbright and Ice Energy for a $1.5 million grant to utilize thermal energy storage at residential sites, and for peak demand reductions. In California, Ice Energy and NRG Energy partnered on 1,800 Ice Bear 30 storage solutions to commercial and industrial buildings in Orange County, Calif., as part of Southern California Edison’s storage procurement efforts.

Viking’s system is a bit different, it says, utilizing a phase change material that it describes as “a substance with
a high latent heat of fusion which remains near a constant temperature while storing and releasing large amounts of energy.”

Transitioning from solid to liquid, Viking says the phase change material “absorbs up to 85% of heat infiltration and maintains more stable temperatures to better protect food product.”

The result at the Dreisbach Enterprises’ frozen food distribution center was a 20% decrease in weekday energy use, which the M&V report said was countered somewhat by a 5% increase in off-peak weekend consumption, in order to fully recharge the TES.

The net result, Viking’s study concluded, was a 13% reduction of energy consumption for the entire facility each week. More importantly, the TES lowered peak refrigeration load by 251 kW, a 29% reduction for 13 hours each day.

The study “demonstrates that cold storage operators can safely reduce energy costs and utilities can significantly lower demand on the electrical grid during peak periods to defer costly infrastructure investments,” Collin Coker, vice president of sales at Viking, said in a statement.

Viking said it is now in talks to deploy additional TES technology Dreisbach Enterprises facilities.

Energy storage is the key to renewables. A decade ago, solar panels could make electricity during the day, which was great. But in most parts of the world, the highest demand for electricity occurs in the late afternoon and early evening — times when solar panels produce little electricity. Wind turbines are wonders of modern engineering but of little use if there is no wind to turn their blades.

Being able to store electricity now for use later is what makes renewable energy capable of providing reliable baseload power at all times of day or night. How long that storage ability lasts is one of the primary ways that energy storage systems are classified. Cost, of course, is another.

It is one thing to store electricity for a few hours; quite another to store it for days or weeks at a time. The ultimate goal of energy storage is systems that can store energy for entire seasons, so Londoners can heat their homes in the winter with electricity stored in the summer.

Batteries today cost around $280 to $350 per kilowatt hour and are just at the threshold of being able to store electricity for several hours or perhaps an entire day. The costs are coming down, with some industry experts predicting prices will fall below $100 per kWh in the future, but that price is still years away. Batteries also have a useful life — typically 20 years. After that, they need to be replaced.

Swiss startup Energy Vault has a different idea. According to Quartz, it plans to construct energy storage systems that use concrete blocks. A 400′ tall crane with 6 arms uses excess electricity to power electric motors that lift and stack concrete cylinders weighing 35 metric tons each all around it. Later, the crane lowers them back to the ground, generating electricity during the descent. Think of it as a regenerative braking system that operates vertically rather than horizontally. The current cost of an Energy Vault system is around $150 per kWh.

Minister for Energy Dr Megan Woods attended an event to officially inaugurate the first grid-scale battery energy storage system in New Zealand, hosted by energy retailer and project owner Mercury Energy.

The project, based around a Tesla Powerpack 2 battery system was revealed to be under development in January this year. Energy-Storage.news reported at the time that the 1MW / 2MWh of Powerpacks is connected to existing pumped hydro facilities in South Auckland and used by Mercury’s R&D centre as part of a trial of scalable grid-connected batteries.

Back in January, Mercury said battery capacity at the installation itself could be added to at a later date, and that the system, with a cost of close to NZ$3 million (US$2.01 million), would trial the redispatch of electricity generated by hydro as well as the possibility of using the Powerpacks in energy trading markets. A Mercury announcement this morning also said the project could be used to investigate the redispatch of geothermal energy.

“We see battery storage as playing an increasingly important role in providing a reliable supply of electricity in New Zealand, as we increase our reliance on wind and solar to generate our electricity,” John Clarke, general manager at grid operator Transpower, said.

“We look forward to continuing to work with Mercury throughout the trial and gather key learnings to enable the transition to New Zealand’s sustainable energy future”.

Energy industry experts speaking at the MEGA Symposium in Baltimore, Maryland, on August 21 agreed that storage is becoming more important to the overall mix of U.S. power sources. They also said utility-scale storage solutions remain “years away,” even as technology advancements in battery systems occur more rapidly.

Panelists at the session entitled “The Transformation of the Power Industry and the Role of Energy Storage,” representing utility, finance, research, and coal industry interests, said storage has proved its mettle when it comes to energy, but there is no “one-size-fits-all” solution when it comes to deploying storage assets across the power grid.

“Energy storage can transform how we make, move, and sell electricity across the grid,” said Steve Baxley, manager for renewables, storage, and distributed generation for Southern Co. “It can transform the whole marketplace. It’s a capacity resource, a flexibility resource, and reliability and resiliency resource, and a voltage and power quality resource. But there are a lot of emerging questions in this field. How do we implement [storage]? How do we interconnect to the grid?”

The experts said storage is valuable to provide backup power and balance intermittent sources of power on the grid, such as solar and wind. They also said it’s not a substitute for baseload power during extreme events such as the “bomb cyclone” that hit much of the eastern U.S. in early 2018, bringing frigid temperatures and icy precipitation.

“During the bomb cyclone, coal provided about 55% of the generation across six [independent systems operators],” said Peter Balash, senior economist for the Department of Energy’s (DOE’s) National Energy Technology Laboratory (NETL). “Without coal, we would have had a [power] shortfall in PJM,” the regional transmission organization (RTO) that serves all or part of 13 midwestern and eastern states. “The second largest [amount of generation] came from fuel oil. Constraints in the pipeline system led to price spikes in natural gas,” and those constraints also meant the supply of gas could not keep up with demand, particularly in the Northeast.

“Increases in power prices during the event offset the lower price of natural gas,” Balash said, noting the extreme weather event showed how generators don’t want to rely on just one energy source to maintain reliability and resilience on the grid. He said that while energy storage facilities often are located near major population centers, “less than 40% of [those] are capable of producing more than 1 MWh of power”—not nearly enough to keep up with the demand for heat during the January event, or the polar vortex event that struck much of the same area in 2014.

Deck Slone, senior vice president of strategy and public policy for Arch Coal, noted the U.S. coal fleet has lost “about 30% of its generation capacity” over the past decade, which he said puts baseload power at risk. “It’s going to take a while to get to large-scale energy storage,” to a level that could begin to replace the lost capacity, he said.