When we decided to throw an event titled "Energy Storage Versus Natural Gas," it was bound to include some provocation.
The attendees rose to the spirit of the event. There were consistently robust conversations on stage, as experts grappled with a future that is very much still undecided. Some of the most insightful comments I heard pushed back against the very framing of the conversation.
In this week's column, I'll share what I learned at the show by engaging with the foremost critiques.
Catch the full sessions in high-definition video right here.
It’s not either/or
Perhaps no strong dichotomy survives in reality.
I heard from several observers that the "storage versus gas" framing setup contrived tension that doesn’t reflect reality.
I’d note that we have seen discrete cases where a specific gas plant would have been approved by regulators, if not for the pesky rise of energy storage. The emergence of the storage alternative forced a reevaluation of the Puente plant, leading to a determination that the full gas plant would not be needed after all.
Glendale, too, put its $500 million gas peaker on hold to explore distributed energy options. First Solar nabbed a contract for peak power that gas plant developers had competed for.
In these specific examples, storage and gas really did engage in zero-sum competition. But these cases number in the handful. Storage plus gas has a much wider potential, at least in the short term.
Newly minted GE Storage CEO Rob Morgan said it best in his interview Monday: “It’s an ‘and’ conversation for us, not an ‘or’ conversation.”
When I digitally polled the crowd at the end of the day, more than 80 percent said they were more confident that storage and gas would play together well, rather than either one dominating on its own.
Storage and fast-ramping gas deliver different flavors of flexibility. That’s a useful narrative for a legacy turbine manufacturer like GE, but we also heard this message from Kelly Speakes-Backman, CEO of the Energy Storage Association. She advocates a big-tent approach to storage, and thus shies away from the radical statements that energy storage will make gas peaking assets obsolete.
"We see storage as the central hub of all the other generation resources," she said, reframing the bare-knuckled storage versus gas brawl I had anticipated moderating.
That's politically savvy, as storage has so far avoided making enemies the way distributed solar did in the early years. There’s also a good grid efficiency argument for slapping batteries onto gas peakers (although I’d like to see what happens to carbon intensity when you use storage to extend the lives of peakers rather than replace them).
Currently, we don't have enough evidence to frame the trend as storage taking over natural gas; nobody thinks that will happen en masse, unless we get to very high decarbonization goals, or very low storage prices.
Instead, the inquiry I'll be investigating is where will storage will excel in providing valuable flexibility to the grid, and where will gas stay strong? It's more about spheres of influence than total domination.
What do you even mean by "peaker"?
Let’s be clear: Not all peakers are the same.
When we talk about storage displacing peakers, we typically refer to combustion turbines, which represent 109 gigawatts of capacity nationwide.
Even combustion turbines (CTs) look different from one another: Aeroderivatives have a faster response time, while frame turbines take longer to warm up and must run longer to justify the startup burn.
Reciprocating engines get up to speed in a couple of minutes, making them the closest to storage’s blink-of-an-eye response time. Meanwhile, New York City still calls on 60-year-old steamer plants for peak power, undercutting its goals for both equity and decarbonization.
The type of peaking resource matters a lot for storage’s prospects of replacing it. As a general rule, the longer it takes to start up and the longer it has to run to be economical, the more competitive storage will be.
Some utilities are proposing reciprocating engines as a more flexible capacity resource, even if they cost more than CTs. That logic could work in storage's favor, if utilities are open to the technology.
Siting concerns and fuel supply play a significant role here as well. In highly populated areas, permitting gas turbines may be prohibitively difficult. In some areas, natural gas is abundant and cheap; in others political opposition to pipelines, heating use during cold snaps or massive gas leaks limit the availability for peak power.
Dialing in on the particular differences between these assets will be crucial as storage developers pick their battles.
It’s not just gas and storage
Along those lines, the singular focus on gas and storage leaves out the rest of the interwoven participants on the electrical grid. The rise of solar and wind power and the retirement of uneconomical coal and nuclear plants all mix in a bubbling cauldron of grid trends.
Much has been written elsewhere about how the rise of intermittent generation increases the value for fast-ramping capacity, but demand-side tools have a major role to play too.
Grid planners traditionally make a (frequently inflated) projection of load growth, determine what new assets will be needed to meet that demand and propose to build them.
Distributed resources create a different possibility: to predict peak load, reduce it with customer-sited devices, and build out the remainder of what’s needed on the utility side of the meter.
The actual business models to make that happen are still coalescing, as are utilities' trust in a network of third-party devices. But this vision offers a complement to the story of gas and storage duking it out to meet the grid's peaks.
Don’t generalize from California
If both storage and gas won, California lost.
The state that did so much to kick off the storage industry drew scorn from many a panelist as a spendthrift willing to invest considerable taxpayer dollars in advanced technology and still end up paying more for electricity than almost anyone else.
There’s no arguing about those prices. But the approach does get the job done, in its own way.
“Certainly California has shown you can buy your way into lower-cost renewables over the last decade,” said Abraham Silverman, NRG’s vice president for regulatory affairs group and deputy general counsel. “They’ve driven that cost curve down. They can do the same thing on the battery side.”
Silverman’s broader point was that mandates might achieve near-term policy goals, but they don’t produce sustainable, efficient systems the way pricing the need in a competitive market does.
That market logic takes on a note of moral urgency in the face of global climate change.
“The great challenge for those of us who care about climate change is to deploy our capital in the way that gets the biggest carbon bang for the buck,” Silverman said.
Arizona could become the new ideal role model, if it succeeds in spurring storage with an energy reform that shies away from state mandates and climate mitigation goals. Regulated utilities there have already moved on storage projects simply because they made better financial sense than the conventional alternative.
California energy insiders might counter that waiting around for years-long wholesale market revisions doesn’t get much bang, even if it saves on the buck.
The problem with the Adam Smithian ideal is that U.S. power markets are highly fractured, messy things, and saying that they should price the value of flexibility is very different from deploying flexible assets now and showing the world that they work.
If California hadn't done that, we probably wouldn't be having this conversation in the first place.
