First-of-its-kind rail energy storage project targets role in CAISO ancillary services market
A California startup is targeting ancillary services as the use for the grid-scale rail storage project
The newest entrant into the energy storage market bears a passing resemblance to cutting edge 19th century technology.
It is a rail car with no passengers or freight that goes nowhere. But if the California company working on this technology is right, its rail cars could make big inroads in the energy storage market.
At heart, though, the concept is simple. Electricity powers an electric motor in a locomotive that hauls a heavy load up hill. Sitting at the top of the hill, the rail cars store energy. When the energy is needed, the cars are released to roll down hill and the electric motor runs in reverse to generate electricity.
The company, ARES, is a start-up based in Santa Barbara that is named after its technology, Advanced Rail Energy Storage.
Any resemblance to 19th century rail technology belies the high tech workings of the system and the fact that ARES holds three patents for its technology.
The same electro-mechanical principle that powers the ARES system supplies the regenerative braking power in electric vehicles like a Toyota Prius or in wayside regenerative braking systems such as the one being installed on the metropolitan Philadelphia commuter rail line: When an induction motor that powers a train or car is reversed, it produces electricity.
ARES now hopes to put those principles to work in Nevada where it just won approval from the Bureau of Land Management for its first commercial project.
ARES wants to lay a nearly 5.5 mile track up an 8 degree slope, gaining about 2,000 feet top to bottom. ARES would then put up to seven 8,600-ton trains on the track with each train comprising two locomotives and four rail cars. The entire system, including substation and control systems, would occupy about 43 acres of public land near Pahrump in Clark and Nye Counties.
ARES is partnering with Valley Electric Association, an electric cooperative based in Pahrump, which will provide interconnection with California, where ARES plans to sell ancillary services such as frequency regulation to the California ISO (CAISO). ARES hopes to begin construction in late 2017 or early 2018 with operations starting early in 2019.
One of the striking things about the ARES project is its size: 50 MW of power capacity and 12.5 MWh of energy. That would be large for a battery storage project, but for ARES, it is on the low side. “Fifty megawatts doesn’t get us to economies of scale,” CEO James Kelly said. “We are more efficient as we get larger.”
Kelly said ARES projects can be sized anywhere from 50 MW to 1 GW. “If we had a 500 MW project, we could double the capacity and it would only increase capital costs by 20%,” he said.
For the Nevada project, it turned out that size does matter. Even though California has a mandate to add 1.3 GW of storage by 2020, so far most of that capacity has been contracted through smaller power purchase agreements. That pushed ARES’ project out of the RFO process and into the merchant market.
That also presents challenges when it comes to financing, at least using capital markets and traditional project finance mechanisms.
Basing a merchant project on arbitrage opportunities – buying (charging) low cost power and selling (discharging) higher cost power – can be a risky business. It has scuttled more than one pumped storage hydro project.
Kelly said the Nevada project is not going to rely on arbitrage to earn a return on capital. He also said the project is not going to be financed in the capital markets. Instead, it will be financed through a combination of “high net worth individuals and family offices.”
He puts the total capital costs at “a little under $55 million” and said about 60% of the funds have been raised so far and hopes to secure the remaining funds in the next few months.
Instead of arbitrage, the Nevada project will bid into the CAISO ancillary services market, responding to the signals the grid operator sends every four seconds to help balance supply and demand. In that scenario, Kelly said multiple trains could be moving up or down (charging or discharging) hundreds of times a day in response to the ISO’s needs.
Kelly also said that the economics of the Nevada project will be aided by recent pricing trends at CAISO, which has been seeing negative pricing from over generation from wind power at night and from solar power in the morning. Under those circumstances, the ARES project could be paid to take power off the grid, Kelly said.
Kelly sees the responsiveness of the ARES system as one of its chief benefits. It can go from full discharge to full charge in 10 seconds. Rail storage also does not have life cycle limits that batteries do. “There is zero degradation,” he said.
Kelly touts other benefits of rail storage over battery storage, particularly regarding some of the chemicals used in batteries. They can be toxic, difficult or dangerous to handle, costly to dispose of and mining them can cause environmental damage.
But the fair comparison is not with batteries, he said, but with pumped storage, and there also Kelly said rail storage has advantages, namely, a smaller footprint, less environmental damage, higher reliability, faster ramp rates and lower capital and operation costs.
Chris Robinson, a research associate at Lux Research, estimates that costs for the Nevada project are $4,400/kWh and $1,100/kW. Cost comparisons with pumped hydro are difficult, he said, because there are so few projects and not many data points.
Comparing the Nevada project with a large battery system, such as 8 MW, 32 MWh system built by Southern California Edison at a cost of $53 million shows that the battery project is more costly per unit of power, $6,600/kW, but cheaper per unit of storage, at just over $1,600/kWh, Robinson said. Those comparisons also highlight the fact that the costs of storage systems is often a function of how the system is be configured and used.
A Deloitte analysis put the cost of lithium-ion batteries at $1,000/kW to $2,000/kW, the cost of compressed air storage at $1,600/kW to $2,200/kW, pumped hydro storage at $1,200/kW to $2,100/kW, and flywheel storage at $2,100/kW to $2,600/kW.
ARES is developing a project at the small end of its economic scale to keep a lid on the amount of funding that has to be raised, but Kelly said the economics can be improved by increasing the scale of projects.
Despite the fact that many components of the ARES system are based on technology that has been in use for well over a century, the commercial success of the project is still not guaranteed. That success will likely have more to do with the economics of the power markets than the viability of the technology. But Kelly said there is a great deal of interest in the potential of rail storage.
ARES is in discussions with some of the largest utilities in the country and is working with the Electric Power Research Institute on funding for a demonstration project, which could come together in the next couple of months, Kelly said. He also said he has had discussions with interested companies in Australia, Belgium, China and Switzerland.
ARES is also working on new software and designs that would allow a rail storage system to operate on much steeper slopes for shorter distances. That would more easily allow the technology to be sited in more densely populated regions of the country. And, Kelly said, with increased scale rail storage could be used for load shifting.
For now, however, ARES seems to be on the cutting edge of an old technology made new. “I can’t find anyone else doing something like this. It is pretty unique,” said Lux's Robinson. It's a fact Kelly acknowledges: “We control rail-based energy storage right now.”
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