Break out your passport and neck pillow, because Storage Plus is going on the road. Internationally.
Today's column kicks off an effort to check in on each of the top global energy storage markets, to see what's heating up, what's hitting a dead end, and where the savvy storage observer should focus attention going forward.
It's a virtual world tour, in the manner of a virtual power plant: I'll be aggregating resources from a geographically diverse network of assets to deliver insights at the time of peak GTM Squared demand.
I’m not aiming for encyclopedic thoroughness, because nobody reads all the way through encyclopedias. Instead, I’ll focus on what I find most compelling about the region. I'm kicking off with the U.K., where I'll focus on the risks and rewards associated with rapid changes in the power system. You'll find that I’m leaving out a detailed analysis of behind-the-meter storage, because I have yet to find evidence that it’s exciting enough there to justify the effort.
Thus, with imagined wing our swift scene flies, to England and its merry band of batteries.
But first, geography
To understand how energy storage will unfold in the U.K., we must first revisit the basic geography of this island nation.
Shakespeare wrote of "This precious stone set in the silver sea,/ Which serves it in the office of a wall,/ Or as a moat defensive to a house." He might have added that the perimeter of salty water that defended Albion from Saxons and Spanish armadas separates neighboring electrical grids as well.
That matters more and more as the island shifts from thermal generation to intermittent renewables. The coal that fueled Britain’s global empire kept power plants fired up on demand. Soon, the sooty rocks will be gone from the U.K. grid forever, while offshore wind, onshore wind and a smaller amount of solar capacity pick up the slack.
Coal fell to 6.7 percent of electricity generation in 2017, down from 9 percent the year before, according to the fittingly aristocratic Digest of U.K. Energy Statistics (DUKES). Renewables rose to 29.3 percent in 2017, while natural gas supplied 40.4 percent and nuclear delivered 20.8 percent.
Greater variability in generation, within a geographically isolated region — what could go wrong?
Renewables-loving Germany directly abuts nine other countries; chances are someone can take or give surplus power when Germany needs it. But the U.K. only interconnects with Ireland, France and the Netherlands. That means it must look inward to balance the highs and lows of renewable generation and maintain a functional grid.
The rise of the flexibility economy
These changes create both uncertainty and opportunity for the British energy developer.
Uncertainty: The grid doesn’t work the way it did five years ago, and five years from now it will look different too. Developers have to commit capital now not knowing exactly what market conditions will look like in a short time.
Opportunity: If you feel comfortable playing those odds, you can mop up all the money that other people are too confused to make. Doing so will require operational agility, in order to shift between different market products as conditions evolve.
The flexibility required by an increasingly volatile power system rewards flexibility in the minds and assets of energy companies. For a case study of how this dynamic plays out, let’s take a look at U.K. Power Reserve.
This company got started in 2010 with the theory that renewable capacity growth would put a premium on flexible capacity. It responded to that need buy owning and operating gas reciprocating engines, behind the meter or in the distribution networks. UKPR dispatches these small, fast-ramping tools as a geographically distributed power plant.
“We were reinventing what flexible capacity should look like in the U.K. energy market,” head of UKPR Sam Wither told me recently.
The engines range in size from 400 kilowatts to 3.3 megawatts, and can be stacked together at sites. Overall the fleet tallies 533 megawatts in operation, with another 160 megawatts coming online. The network of small, relatively inexpensive assets delivers the capacity of a combined-cycle gas turbine plant, with the added benefit of sitting closer to the sites of consumption.
Next, UKPR bet big on energy storage.
It won 15-year contracts for 120 megawatts in a 2016 capacity auction, due online by 2020. Luckily for the company, it locked in those contracts before the government decreased capacity market compensation for batteries with less than 4 hours of duration.
Construction is underway at three sites in the Midlands that will add up to 60 megawatts. Another 60 megawatts across two to four sites will follow next year. Fluence, the AES/Siemens joint venture, is supplying both tranches with its Advancion storage platform.
For context on the size, the 120-megawatt portfolio exceeds the capacity of all the U.S. front-of-the-meter storage deployed over the last five quarters. Others are building big in the U.K., too: GE is supplying developer Arenko with a 41-megawatt battery plant, and BYD says it has delivered 150 megawatts to the U.K. across various projects and customers.
For UKPR, storage offers another tool to deliver the distributed, fast-responding services the company made its name on. Batteries can respond even faster than reciprocating engines; they can also draw their power from cheap surplus renewables, rather than buying and combusting gas. If there’s a need for long-lasting power, though, the company can switch back to the gas engines; it needn’t spend extra to build longer-lasting batteries.
Lastly, UKPR worked with Fluence to design a battery system capable of doing many different tasks, on the assumption that the menu of market products will morph over the next few years.
“We believe in providing technology that has built-in flexibility, to allow our customers to capture those different revenue streams, in order to provide flexibility in the future,” said Paul McCusker, Fluence’s managing director for U.K. and Ireland, Middle East and Africa. “That’s different from building the smallest, cheapest battery providing a single service.”
That single service model helped grid storage get off the ground; in the U.K. and PJM territory, the play was frequency regulation. But it’s a risky proposition for the U.K. right now, because no one service can cover the cost of storage development, and the typical anchor revenue streams are becoming increasingly competitive.
“The market is not an easy market to enter — you have to have capabilities, both technical and commercial,” Wither said. “There are a lot of energy storage developers that haven’t quite worked out the merchant risk.”
Please sir, I want some more!
To hear the pros talk about it, Britain’s near-term storage revenue options sound rather bleak.
Britain’s power markets are big on merchant risk and light on the sorts of contracted revenue streams that single-handedly pay the bills. Roughly two-thirds of the storage capacity online or under construction is merchant-owned.
Various flavors of frequency response offered a beachhead market for storage, but quickly saturated as developers rushed in.
Storage is allowed to participate in the capacity markets, but they generally can’t provide the revenue needed to make a plant economical.
The U.K. only just began looking at storage for transmission and distribution deferral, to be procured as a service by the system operators. It’s too early to say how lucrative this will be, according to forthcoming research from Wood Mackenzie Power & Renewables, but it could grow to a large market by the mid-2020s.
“It would be a good thing to see a more proactive assessment of how storage can be a more efficient tool, instead of building out certain networks on the transmission and distribution systems,” McCusker said.
Firming and ramp control could become valuable as PV capacity rises and makes summer evening ramps steeper, but there isn’t a market yet for this application, according to WoodMac.
So, where can a storage builder make some money?
A growing number of developers are looking to the balancing market, McCusker said.
This market involves energy trading in close to real time. To succeed there requires a savvy understanding of energy supply and demand and the ability to optimize trading across future, day-ahead, within-day and real-time markets.
“Sophisticated investors and asset owners who actually want that volatility, who are not intimidated by it and have appropriate strategies to embrace it, will do very well,” McCusker said. “This is not a business for a passive asset owner.”
That’s a far cry from a California resource adequacy battery, where the owner hands the keys to the grid operator to dispatch. It may incentivize storage development by companies that already play in gas and wind, expanding their energy portfolio and trading options.
Aggregator Limejump announced in August that it was participating in the balancing mechanism with an aggregated fleet that includes storage; this appears to be the first battery system to do so.
The U.K. balancing mechanism was worth £1.1 billion ($1.45 billion) in 2017, and industry analysts believe that energy storage could access about a third of that. That’s a nice chunk of change already — the U.S. storage market was worth only $302 million in 2017 — but the overall balancing market could double over the coming decade as renewables rush onto the grid.
To make money in U.K. energy storage, then, requires leaving secure revenue in port and sailing straight into the maelstrom of increasingly volatile real-time power markets.