All the talk in the electric utility industry these days seems to be about battery storage, but there are other ways to save generated electricity for later. 

With more demanding state renewable portfolio standards, the finalization of the EPA's Clean Power Plan and utilities increasingly turning to renewables as a least-cost option, grid operators are likely to need more and bigger storage options by the mid-2020s, if not before. 

“The excitement in the market now is around the policies we have in place, which very specifically exclude big pumped hydro applications,” explained California Energy Storage Alliance (CESA) Sr. Advisor Mark Higgins, the VP/COO at Strategen Consulting. “Those policies were designed to create a diversity of technologies. Bulk storage would work against that.”

But, Higgins said, by around 2024, when California gets to about 40% renewables, there will be a real need to shift excess renewable energy supplies from the middle of the day to the late afternoon and evening. “That will require storage resources that can handle big amounts of energy over long periods of time.”

Higgins expects California regulators to again take the lead, as they did with the AB 2514 policy now driving battery technology growth, and put in place incentives for long duration storage technologies.

Pumped hydro promises big capacity

Pumped hydro storage (PSH) uses energy to move water from a lower reservoir to a higher reservoir where it can, at need, be released. The energy is recaptured as hydroelectric power as the water flows back to the lower reservoir.

“Pumped hydro's sweet spot is bulk energy shifting,” Higgins said. “But there are not many good sites left, upfront capital costs are high and policy support is limited." Such obstacles have limited excitement about pumped hydro's growth.

Duke Energy, however, says it is excited about pumped hydro, according to Spokesperson Lisa Parrish, because its quick start up time provides flexibility the utility needs. “Pumped storage functions like a giant water battery…At a moment’s notice, the stored water can be used to meet peak demand.”

The potential of Califonia’s Bison Peak 1 and 2 PSH Projects excites Alton Energy President Ed Duggan. Eagle Crest’s Eagle Mountain PSH Project was green-lighted first by the Federal Energy Regulatory Commission (FERC), in hopes of helping fill the gap left by the shuttering of the San Onofre Nuclear Generating Station. But Duggan believes the combined 2,000 MW capacity of the Bison projects will have more benefits if he can get a green light from FERC.

“Bison 1 and 2 meet three crucial criteria,” he explained. “First, they are strategically located at an intersection point of the California grid and some of the biggest utility-scale wind and solar installations already online.”

He was describing the nearly 1,200 MW of photovoltaic solar in the Antelope Valley and the over 5,000 MW of wind capacity in the Tehachapi Mountains that form the Valley’s north boundary.

“Second, the Bison projects have a larger elevation differential than other proposed pumped storage projects,” Duggan said. Competitors include the privately funded Lake Elsinore project, the Sacramento Municipal Utility District’s Iowa Hills project, EDF’s Swan Lake project, and smaller ones proposed by the San Diego Water Authority.

“The greater elevation differential would allow Bison Peak to supply more power faster with less water,” Duggan explained.

Finally, he said, Bison Peak’s bulk storage would be geographically available through the Southern California Edison and Pacific Gas and Electric transmission systems to the Los Angeles and San Francisco region load centers.

Duggan believes the state will need at least 10 GW and possibly as much as 50 GW of bulk storage like PSH to meet the state’s targeted 80% reduction in greenhouse gases by 2050.

Take the ARES train

But the bulk storage may not all come from PSH, according to Advanced Rail Energy Storage (ARES) North America VP Francesca Cava.

“We are like pumped hydro but without the constraints of water,” Cava said. “And we estimate ARES requires about half the capital expenditure.”

ARES would use energy to do with box cars on a rail line what PSH does with water – push them up an incline so they can be released to generate electricity with their downhill momentum. The concept has been proven with a “peer-reviewed, patented” demonstration project in which ARES has moved a 6.5 ton rail car up a 15-inch gauge track with Tehachapi Mountain wind energy, according to the company.

It is a gravitational technology but an intriguing if fairly simple concept, Higgins said. “The questions are: What are the applications? And how cost effective is it versus something else?”

ARES will soon begin providing more answers, Cava said. They expect to be granted a Bureau of Land Management permit by the end of this year for a selected Nevada site and they expect to have an operational 50 MW project selling into the California grid’s ancillary services market via the Valley Electric Association cooperative utility by the end of 2017.

It will have a 78.3% round trip efficiency, a 34 second full charge to full discharge response, and a 40-year system life. Ultimately, the ARES team believes, projects with multiple, side-by-side lines can provide up to 3 GW of storage over a 24 hour duration. 

“Pumped hydro can be very large but so can ARES,” Cava said. “And twice the capacity is not twice the cost so it scales relatively economically.”

The case for CAES

There are only two operating utility-scale Compressed Air Energy Storage (CAES) facilities in the world, though others in the U.S., the UK, and Europe are in various stages of development. The 290 MW, four hour full-output Huntorf facility in Germany went into service in 1978. The 110 MW, 26-hour full-output McIntosh facility in Alabama went into service in 1991.

At both sites, energy is used to compress air into underground salt caverns. When that air is released, on demand, it turns generators that send electricity back to the grid.

CAES makes sense when there is a need for a long duration response of between 8 hours and 26 hours, Higgins said, because the cost is largely upfront. Compared to the linear cost of increasing batteries’ storage volume, it is not very expensive to expand a CAES facility's capacity.

“But,” he added, “it is not often you find a good storage site with all the advantages of the one in Utah being proposed for development by Burbank Water and Power (BWP) and its partners in the Pathfinder group. There is an underground salt cavern that happens to be next to a major transmission line and near sites of thermal plants scheduled to be shuttered.”

“Geology is the biggest hurdle for CAES,” acknowledged BWP Power Resources Manager Lincoln Bleveans. “But another company has already proven the viability of this geology by storing natural gas liquids there.”

BWP estimates it could build “about 90 caverns, each about the size and shape of the Empire State Building” in the underground salt deposits at Delta, Utah, Bleveans said.

Around 2010, BWP began to realize California’s renewables mandate was eventually going to increase. Talk was emerging about over-generation and the increasing need for stored energy to meet an increasing late-afternoon, post-solar-availability peak.

Bleveans and his team began more seriously considering the storage site near the Intermountain Power Project (IPP), from which the municipal utility already bought a small share of the facility’s 1,900 MW of coal-generated electricity. Adding to the site's appeal was that most of the IPP’s generation was already being sent along existing transmission to Southern California region munis.

BWP also discovered Pathfinder Wind Energy was beginning the process of developing up to 3 GW of Wyoming wind and investigating ways to deliver the electricity it could generate to West Coast load centers.

Soon BWP also discovered the Transwest Express, Gateway, and Zephyr high capacity transmission systems to be in development. All could potentially pickup Wyoming and other High Plains wind-generated electricity and deliver it to the storage site for later deliervy, on demand, to Western and Southwestern loads.

BWP, Pathfinder, equipment provider Dresser-Rand, transmission builder Duke-ATC, and technology supplier ABB recently won preliminary approval for a $628 Department of Energy loan guarantee that would allow them to develop a 300 MW pilot project at the Delta site, Bleveans said.

“CAES is very geology specific. It lives and dies on geology,” Bleveans repeated. “We are in due diligence mode. We are peeling the onion. And we haven’t cried yet. But we are still peeling the onion and trying to figure out if it is the right thing for our utility.”

Bleveans declined to provide cost information but the current facilities are averaging $1,600 per kW to $2,200 per kW, according to Energy Storage Update. The report puts PHS at $1,200 per kW to $2,100 per kW, lithium-ion batteries at $1,000 per kW to $2,000 per kW, and flywheel storage at $2,100 per kW to $2,600 per kW.

Flywheels struggle on cost

Though cost would appear an obstacle for flywheels, they can be cost effective when they are cycled frequently, Higgins said. “It is like a giant spring. Energy is used to wind it up and energy is released when it unwinds.”

But charge-discharge cycling doesn’t cause the same wear-and-tear in flywheels as it does in the chemistry of batteries, so performance degrades less.

“Flywheels are a short-duration, high-power resource,” Higgins said. “They are most cost-effective for fast response ancillary grid services.”

The PJM Interconnection and New York’s grid operator are both using 20 MW Beacon Power flywheels for frequency regulation, Higgins added.

But lithium ion battery storage seems to be most grid operators' preference in recent ancillary services contract bidding, verifying flywheel technology's lack of cost competitiveness as reflected in the Energy Storage Update cost information cited above.

Flywheels have, however, found some success in support of electric trains. “Flywheels can quickly deliver a lot of load as a fast train draws power to leave the station,” Higgins explained. “That avoids any strain on the grid from a sudden increased power demand.”

Storing the sun

Molten salt storage from the sun’s heat is just beginning to demonstrate its viability at U.S. solar power plants. Abengoa Solar’s 280 MW Solana parabolic trough solar power plant in the Arizona desert has proven it can provide Arizona Public Service with up to six hours of full capacity generation after dark or at other times when there is inadequate sun.

SolarReserve’s Crescent Dunes solar power tower, due online in October, will raise the bar by providing NV Energy with ten hours of stored 110 MW generation. Its system drives molten salts up to the top of a 540 foot tower and into a 100 foot tall receiver, where they are heated by the sun to 1050 degrees Fahrenheit. They then flow into a 3.6 million gallon hot tank.

At the utility’s need, the hot salts are released to flow past a closed water system in a heat exchanger where they transfer half their heat to boil the water. The steam drives a 110 MW turbine to generate electricity and is largely recaptured. The molten salts flow, at 550 degrees Fahrenheit, to the “cold” tank to await another cycle.

The price of these “solar thermal” technologies includes the cost of both generation and storage. SolarReserve’s power purchase agreement with NV Energy set the price of its output at $0.132 per kWh.

Recently, photovoltaic (PV) solar projects that generate power from the sun’s light have been bidding for utility contracts at and below $0.05 per kWh, pushing concentrating solar power projects like Solana and Crescent Dunes out of the market.

But PV solar can only be stored in batteries or other technologies that hold electricity. They are more expensive, less efficient, and less scalable than molten salts, according to SolarReserve CEO Kevin Smith. With renewables mandates rising, utilities will soon see the value of stored solar heat to meet an increasing late afternoon-early evening peak in demand, he said. As Utility Dive has reported, storage capabilities could prove to be the savior for large CSP projects in the coming years.

The coolest tech: Ice storage

Ice Energy and CALMAC provide thermal storage at the opposite end of the temperature spectrum from solar power plant developers.

Both companies are leaders in shifting the energy used to cool buildings from when the day is hottest, demand on the grid is highest, and electricity is most expensive, to the cooler night when demand is low and abundant, wind-generated electricity can be bought from most grid systems at very low prices.

Both companies’ devices attach to building air conditioning (A/C) units. They freeze water at night so when cooling is needed the next day, the draw from the A/C is sharply reduced.

CALMAC’s business model focuses on building owners, winning customers by simply cutting their electricity bills. The technology can have a huge impact, especially where high demand charges from peaking A/C use can be controlled.

Ice Energy partners with utilities. Though already widely used across the U.S., its Ice Bear product got its biggest recognition yet by winning 16 contracts for 26 MW of distributed and behind-the-meter storage in the Southern California Edison (SCE) 2014 local capacity requirement (LCR) bidding.

By allowing the utility to control if and when the Ice Bear is used, the technology acts as a demand response resource, Higgins said. SCE expects to eventually be able to cut its peak load, when necessary, by 95% of the contracted 26 MW with the flip of a control switch, according to Ice Energy.

Building cooling is unaffected, but if SCE throws the switch, the cooling would be coming from wind energy-generated power, which helps the utility meet its renewables mandate. That electricity would also be lower priced.

BWP, Glendale Water & Power, Redding Electric Utility, and Riverside Public Utilities also employ the Ice Energy technology, according to Energy Storage Update.

Ice Energy’s business is expanding quickly, reported Chief Information Officer Chris B. Tillotson. It already has 12MW installed and 30MW contracted for and it is working on a development pipeline of over 100 MW. It is also readying an Ice Cub residential product, which should hit the market in time to be an early player in the aggregated distributed energy resources markets being developed in California and New York.

The best tech depends on location

“We believe this is the only non-battery distributed storage technology,” Tillotson said, taking the cooling technology out of competition with the bulk providers.

For all the gravity-driven bulk storage technologies, Higgins said, “the question is whether the final engineering costs make it cost-effective.”

“We are comparable to pumped hydro but it is easier to locate and build an ARES project, way easier because pumped hydro depends on water,” Cava said. “We need land and a mild grade but we have found at least 27 sites just in the state of California.”

I don’t want to say PHS, ARES, or CAES is better, Bleveans said. CAES seems to have great potential if you have the right geology. LA DWP’s Castaic PHS facility proves the right geology and topography can make that a terrific solution. And with the right conditions, an ARES project might be good, too.

"At the scale of bulk storage," Bleveans explained, “you have to be agnostic about technology because the technology has to be driven by site conditions.”