2018 is looking like the year the energy storage industry makes good on its promise to replace gas peaking-power plants. But it will have to answer a few tough questions first.
Industry discussions, naturally, have centered on the upside: deliver peak power without the air pollution or carbon emissions, avoid the stranded-asset problem, make money through other grid services when a gas peaker would sit idle.
That pitch has inched toward reality in a few cases. NRG’s 262-megawatt Puente plant looks almost certainly dead -- Southern California Edison’s redo of the procurement for that local capacity requirement axed the plant in favor of preferred resources like storage. Regulators just ordered PG&E to solicit new storage resources to replace three gas plants that have fallen on hard economic times.
In Michigan, solar advocates are pushing the issue further by demanding an entirely non-dispatchable portfolio of solar and wind instead of a gas plant.
These efforts represent the culmination of years of work by clean energy professionals and advocates to get their solutions ready for primetime. But the moves also portend significant shifts for how the grid operates, and could produce unanticipated complications if they're not duly considered.
In this week’s Storage Plus, we’ll examine some questions that states and utilities need to ask before they take the plunge and start swapping out gas plants.
Do batteries compete economically with peakers?
The short answer is they don't just yet --mostly.
The first cases of batteries challenging peakers occurred in California, which has regulatory drivers to deploy storage and reduce carbon emissions. These announcements wouldn't be happening if storage was mindblowingly more expensive, but so far it hasn't had to prove itself without the assistance of policy support.
"The fact that this is happening in California should be your first clue as to whether economics will factor into this at all," said Stephen Brick, a veteran energy developer, independent consultant and senior adviser to the Clean Air Task Force.
The exact price differential between storage and gas peakers is hard to pin down because actual storage prices are hard to come by. The industry keeps those locked away from the public domain. But we got a new data point in the Xcel solicitation I wrote about last week.
This all-source bidding included the most competitive pricing to date for storage in a number of configurations. The median price for standalone storage was $11.30/kilowatt-month. The median combustion turbine clocked in at $4.80/kilowatt-month.
That puts storage at roughly 2.4 times the price of a gas peaker for 2023 deployment. And that's based on aggressive bidding as developers jockey to nab a high-profile early deployment, rather than actual prices in real contracts.
That said, the California Public Utilities Commission expressed confidence last week that PG&E could save ratepayers money by procuring new storage rather than awarding existing gas plants must-run status. They have more insight into pricing structures than the public does.
And even if it's hard to see a cost advantage right at this moment, it's important to make grid investments with an eye to the future, said Ravi Manghani, energy storage director at GTM Research.
"Where storage may look more appealing is when you think about where natural-gas prices or capacity utilization will be -- not today, but down the road," he said. "In an environment with many negative-price hours, you're in a much better position as the storage asset owner than peaker plant operator."
What can gas plants do that batteries can't?
"Gas turbines are not restricted to 4 hours; they could operate 24/7 if they had to," Manghani said. "What happens when the grid needs 10 or 12 hours of operation? You're probably not going to rely on that storage."
Four-hour duration batteries have become standard as prices dropped in the last couple of years. The industry, though, is already moving ahead to longer durations.
"Now we’re starting to see storage roll out 10 hours," said Kelly Speakes-Backman, CEO of the Energy Storage Association.
The Xcel solicitation included several at that level, although those are years away from actual deployment, should they be chosen. Closer to reality, National Grid is working with NextEra on a 5-megawatt, 8-hour battery for Long Island, and with Tesla for a 6-megawatt, 8-hour system on Nantucket. A battalion of long-duration lithium-ion alternatives are fighting their way to market for such roles as well.
Supposing storage becomes cost-effective at longer durations, it still has to charge up from somewhere.
"Storage has a doubly hard role in markets without a mandate, because you've got to build the storage, and then you've got to buy the power for the storage," Brick said.
Let's say the hottest day of the year hits, and there's a gas peaker and an 8-hour battery responding to the need. If the system demand stays high for more than 8 hours, the battery would stop delivering power, then have to charge up on expensive peak power while the gas plant chugs along normally. That's a big difference.
This downside for storage would be mitigated by broader changes in the grid to reduce the stress of peak periods. Those efforts take a lot longer to deploy than batteries.
Are batteries as reliable as gas plants?
That limited runtime hits storage on the reliability front, but it factors into a broader conversation about balancing cost versus reliability.
Those instances where a peaker would deliver a few more hours of capacity than a battery add incremental degrees of reliability. If the batteries are cost-competitive and it's possible to obtain power elsewhere in those long peaks, the system could end up working just fine. It introduces some risk, though -- and "the public is notoriously intolerant of outages," Brick said.
On the other hand, distributed energy storage offers a reliability benefit by avoiding the single point of failure posed by a large power plant.
"You can have batteries closer to load so you’re less reliant on the journey the electricity has to travel to be delivered to the end users," Speakes-Backman said. Coupling them with solar provides even greater resilience in a scenario where transmission lines go down.
Storage and peakers have different strengths when it comes to evaluating reliability. The challenge for storage is overcoming the bias toward the familiar solution.
"There are still events where something breaks down," Manghani said. Polar vortices appear; gas lines explode. "To point out that reliability is an issue only for storage, wind and solar is being overly skeptical when you're giving a pass to traditional forms of generation."
Is storage ready to knock out bulk-power gas plants?
Notable in the PG&E decision was the assumption that storage could replace not just peakers but the 580-megawatt Metcalf combined-cycle gas turbine (CCGT) plant.
In the land of the duck curve, it's not right to call that a baseload plant. It ramps down when solar production ramps up, but regularly fires at full capacity to meet the evening peaks.
Taking out such an asset and replacing it with storage might meet the narrowly defined local reliability needs, but it also affects the broader California energy system in ways that are not entirely clear.
For one thing, the plant produces a lot more power than a typical peaker. The prospect of its removal rang some alarm bells for Wade Schauer, research director at Wood Mackenzie's Americas Power & Renewables team.
"If we get a 110-degree day in August 2019 and there are rolling blackouts because the batteries ran out of juice after 4 hours and we needed them for another 8 hours, maybe the CPUC would rethink getting rid of gas-fired generators," he told me. "Until then, that seems to be the objective the state legislature and the CPUC are after."
At play here is a dynamic where the plants are poised to shut down based on a cost-benefit calculus for PG&E ratepayers, but the closure will affect the California grid more broadly. It could raise the CAISO energy price year-round, which would affect customers in other utility districts too.
Storage companies have been publicly targeting gas peakers for some time now, but the replacement of the CCGT plant came as a surprise.
"I hesitate to make any sort of statement with a lot of confidence because I’m still trying to figure out that play," Speakes-Backman said of the storage versus combined cycle dynamic.
So that's a whole new area of market research that needs to happen.
Is this just a California thing?
In 2018, it's predominantly a California story. But that's exactly how solar kicked off a decade ago, Manghani noted: with strong incentives and procurement targets in California.
The trend seems to be catching on elsewhere. The Xcel bids are promising for storage in Colorado; Tucson Electric Power set a groundbreaking storage and solar PPA with no government incentives to speak of; New York has ramped up support for storage and explicitly called out old, urban peakers as something it wants to replace.
"We’re starting to see non-California utilities pivot toward storage with or without renewables as a peaker-like asset, which gives me pause as to whether it's only a California story," Manghani said. "Probably it's the beginning of something much bigger."
Outside of California's strong supports, the additional revenue streams will become more central to the business case. Transmission and distribution value can help seal the deal, as can ancillary services.
Brick, the former developer, cautioned against putting too much hope in the ancillary services market to make storage pencil out.