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More Californians have searched for news about “floods” in 2023 than “wildfires,” which seems in keeping with this summer’s series of out-of-left-field climate disasters. The worst smoke pollution hit … the East Coast. The deadliest wildfire in modern U.S. history leveled … a former wetland in Hawaii. Naturally a hurriquake in Los Angeles and catastrophic flooding in Palm Springs would come next?
But California’s reputation as the land of drought and fire has obscured the fact that extreme flooding is the other player in the state’s deadly climatological triumvirate. From the atmospheric rivers this winter, which caused some 500 mudslides and inflicted as much as $1 billion in damage, to Hurricane Hilary dumping record-breaking rains over the southwestern United States this weekend, floods are understandably top-of-mind (especially with a relatedly somewhat slow start to the state’s fire season).
Here’s what you need to know about the future of extreme floods in the Golden State:
Former Hurricane Hilary was the first tropical storm to make landfall in California in 84 years, easily snapping the practically nonexistent late August daily rainfall records around L.A. In fact, hurricanes making landfall in the lower lefthand corner of the U.S. is so rare that there isn’t actually much of a data record for scientists to use as a point of comparison, Inside Climate News reports — which makes forming future projections and establishing links to climate change actually rather difficult.
What we do know is this: California has largely avoided hurricanes in the past due to the generally cold waters off its coast, which NBC News describes as acting as a sort of “shield” for the state. Hurricanes get their strength and moisture by forming over warm waters, and the eastern Pacific has historically been as much as 9 degrees cooler than the same latitude in the Gulf of Mexico.
But California’s shield has a crack. July was the hottest recorded month on planet Earth and the waters Hilary passed over on its journey north were 4 degrees warmer than usual, the Los Angeles Times explains. Sure enough, research shows that hurricane landfalls in the eastern Pacific could increase dramatically along with global and oceanic warming — bringing more rain and floods along with them.
There are certain conditions that made Hilary particularly unusual, however: A heat dome that formed over the central United States, for example, helped tug the storm directly over California, as opposed to a more typical path of a hurricane or tropical storm being pushed out to sea by easterly winds off the continent. So while hurricanes might be more intense and wet in the future, they won’t necessarily continue to make it over to California the way Hilary has.
Yes, to some extent. In addition to greenhouse gas emissions making the oceans warmer, the weather pattern called El Niño is likely responsible for some of the warming of the waters off of Baja California, which intensified Hurricane Hilary. But again, there were also unique conditions that contributed to Hilary’s unusual path over the southwestern United States, including the prevailing wind patterns. Strong El Niño years, as a result, don’t necessarily mean more hurricanes for Southern California.
El Niños have tended to bring higher winter rainfalls to Southern California, though that is also not necessarily a guarantee. NOAA’s outlook for the coming winter doesn’t currently show above-average precipitation expected for the state. Some El Niño years are actually drier than average, which goes to show that “El Niño is just one hand on the atmospheric steering wheel,” Weather Underground writes.
California isn’t a land of droughts or floods — it’s a land of both. A better way to think about the future of weather in the state is as one of extremes.
That’s because, “[i]n a seeming paradox, drought and flooding are two sides of one coin,” Governing explains. “A warmer atmosphere can hold more water, and higher temperatures cause more water on the Earth’s surface to evaporate. This can result in bigger rainstorms.”
The good news is, most of California is now free of drought conditions and this year’s fire season has been quieter because of all the wet vegetation. But while Tropical Storm Hilary apparently only inflicted minor damage and no known deaths this weekend, floods have been a devastating fixture of life in the Golden State before and they will be again.
As Yale Climate Solutions warned earlier this year, “Given the increased risk [due to climate change], it is more likely than not that many of you reading this will see a California megaflood costing tens of billions in your lifetime.”
California doesn’t need 40 days and nights of rain to experience its worst-case flood event, researchers have found. If a 30-day rainstorm similar to one that hit the then-unpopulous state in 1862 were to strike again today, it could potentially be a $1 trillion disaster — “larger than any in world history” — UCLA’s “ARkStorm 2.0” scenario modeling found last year.
“Every major population center in California would get hit at once — probably parts of Nevada and other adjacent states, too,” Daniel Swain, a UCLA climate scientist and co-author of the paper, said in a statement at the time.
Unlike a tropical storm, which passes in a number of days, the ARkStorm flood event would last a month in the form of sequential atmospheric rivers, like the kind that battered the state this past winter. The link between climate change and heavy precipitation is well understood, and the researchers found that “climate change has already doubled the likelihood of such an extreme storm scenario,” with “further large increases in ‘megastorm’ risk … likely with each additional degree of global warming this century.”
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At this point, I think it’s clear that AI data centers are unpopular.
You probably know it, at least. I was preparing talk about data center opposition on a podcast today and I took the opportunity to dive back into our data, so I certainly know it. At this point, we’ve written about results from our polling that show Americans overwhelmingly oppose local data center construction, that majorities of Americans now support a national data center moratorium, and that the only group of Americans who feels more optimistic than pessimistic about artificial intelligence is … men older than 65 years old.
So I got curious: Given all that, who actually supports AI data centers?
One question from our recent Heatmap Pro poll, conducted by Embold Research, helps give us a sense. This is the profile of someone our data says would support a data center built in their local area:
A few facets stand out. These data center YIMBYs are more likely to be men, and more likely to be 2024 Trump voters, but they’re not locked into one age demographic or voting cohort. A third are Harris supporters, and roughly a third are women. Data center YIMBYs are more likely to be older than 50, but the majority isn’t overwhelming.
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Perhaps more surprising: The group has many more people who voted third-party in the 2024 election (8%) than the general population (just under 2%), although that response could also include people who didn’t vote. (Alas, the data can’t quite confirm how many in this group are libertarian.)
What’s perhaps most interesting: This group overwhelmingly believes that artificial intelligence will make their lives better. And in heartening news for climate advocates, they are even more likely to support a given data center project if it is powered by renewables.
I was going to joke that the profile is essentially a newly retired engineering dad — except that, to my surprise, these data center YIMBYs are far less gender imbalanced than the American engineering profession. (They’re also less gender-imbalanced than American Tesla owners.) So I’ll leave it at that.
Five takeaways from the latest Lazard Levelized Cost of Energy report.
It’s all getting more expensive.
That’s the conclusion of the investment bank Lazard’s latest report on the levelized cost of energy, one of the most closely watched and cited energy reports of the year.
Levelized cost of energy measures the dollars per megawatt-hour a power plant needs to earn in revenue to break even over the course of its lifetime in present-value terms.
What makes LCOE so alluring is that it’s a way to compare any type of generator, whether it requires a large upfront investment but has few operating costs, like a utility-scale solar project, or whether its expenses are largely fuel costs incurred in the future, like a combined cycle natural gas plant. This is also why LCOE has its critics, who point out that a solar panel that only runs during certain times of day has a different value to the electricity system than a natural gas plant that can ramp up and down quickly or a nuclear plant that provides steady baseload power.
Anyway, here’s what we can learn from this year’s Lazard report.
Curves that were once gently sloping downward are starting to look like incipient U’s. While longterm LCOE falls are still dramatic and impressive for some technologies — utility solar has fallen from $359 per megawatt-hour in 2009 to $69 in 2026 — the short term rises are worrisome. That $69 per megawatt hour represents a nearly 10% increase from 2025, when utility-scale solar had a LCOE of $58. And it’s not just renewables — the LCOE for a combined cycle natural gas plant rose from $78 per megawatt-hour to $90 in the past year. Gas plant LCOE got as low as $60 in 2021. That’s a 50% price hike in just five years.
Lazard attributed the increase in solar and wind LCOE to “higher capital costs, sustained interest rates, tariff pass-through and supply chain repricing.” These technologies are also the most “sensitive” to subsidies by way of the tax code, with federal tax tax credits taking the low end cost of utility solar to as low as $16 per megawatt hour. To the extent those tax credits are no longer available or weren’t accessible due to strict eligibility rules, that could be a source of future upward pressure on costs.
That being said, renewables “maintain their relative cost advantage despite facing the same cost pressures affecting the rest of the generation stack,” the Lazard analysts concluded.
Natural gas, meanwhile, is seeing prices spiral upward on huge and growing customer demand.
“Continuous upward revisions to demand projections have driven a sharp increase in announced new-build gas generation despite a 15-year high LCOE and historically long development lead times,” according to Lazard.
The report hints at what LCOE is not always able to capture, namely that generators like gas have attributes besides low cost that make them attractive. “New gas combined cycle plants offer the lowest-cost dispatchable power in high-demand and low-cost-gas environments,” the analysts point out.
Anyone building a new combined cycle gas plant, however, will have to deal with the high cost and low availability for turbines, which is “extending development timelines well beyond historical norms.” That provides an opening for renewables that can be deployed quickly and cheaply, like solar and accompanied by battery storage.
In 2019, the low end of LCOE for onshore end was $28 per megawatt-hour, according to Lazard’s figures, and the high end was $54. In 2026, however, the low end costs sits a bit higher at $37 per megawatt-hour, but the high end cost rose to $99. There’s a similar story for utility solar: in 2019, the spread between low and high was a snug $8 per megawatt-hour, while this year it’s ballooned to $58.
The broadening range is “likely reflecting that some project developers have been better able to mitigate broader cost pressures across supply chain and project-level economics than others,” the Lazard analysts wrote.
The Lazard report doesn’t just look at the discounted cost of individual generators over their lifetimes. It also tries to figure how much they cost on certain grids. One way of doing this is to look at what Lazard calls the “cost of firming intermittency” or “levelized firming costs.” This is essentially looking at what it costs to bring solar, solar and storage, and wind and storage onto actual grids considering their ability to perform when the grid is most stressed.
This measure tries to refine LCOE to give a sense of how various forms of energy generation compare to gas plants in real world circumstances, not just as a financial construct. This is not a perfect, real-world comparison — gas capacity needs to be “firmed” as well, as it’s not always entirely available at times of peak need — but at least it gives an idea of how these resources actually function in a real-world grid.
Even with firming costs, “renewables remain broadly cost-competitive,” the report concludes.
Not surprisingly, some of the most dramatic costs are in America’s most troubled electricity market, PJM Interconnection. The unsubsidized cost of firming intermittency for solar and storage is $167 per megawatt-hour, compared to $150 in Texas or $115 in California. That’s also compared to a $129 per megawatt-hour at the high end for conventional combined cycle gas plants in PJM.
PJM is notorious for its inability to bring on new resources quickly and its strict standards for accrediting the contribution of storage and renewables to grid stability.
While the Lazard authors explicitly caution that it doesn’t measure what the“total system costs are for 1 MWh of incremental electricity” and can’t say “the optimal mix of renewables, conventional generation and storage,” it does conclude that “firming costs and dispatchability are increasingly critical for comparing resources on a more complex grid.”
In short, no matter what ends up on the grid, grid planners will have to think carefully about how to make sure it’s reliable and works in concert with what’s already there.
Timber companies think of them as pests, but new research indicates that stands of the slender tree can act as barriers against raging flames.
Colorado’s Aspen Acres Fire is named after a quiet RV campground located high in the San Isabel Mountains, about a five-hour drive due southeast of the state’s better-known Aspen. Both places, however, are named after the iconic deciduous tree known for its golden leaves in the fall. While the start of monsoon season may yet prevent the Aspen Acres Fire — the seventh-largest in Colorado’s history — from joining Utah’s Babylon Fire as the second 100,000-acre “megafire” of the season, the conflagration has been aided in its rampage not by aspens, but rather by dead, downed, and blighted ponderosa pines, spruce, and Douglas firs. The wildfire has now burned over 98,000 acres and nearly 300 homes, and is only 36% contained due to steep terrain that has hampered firefighting efforts, along with extreme drought conditions and beetle infestations that have greatly degraded the forest health of the region.
But what about its aspens? Though the extent of the damage at the campground remains unknown, according to a recent study of Populus tremuloides, Colorado’s iconic golden trees could be one of the keys to more wildfire-resistant forests in the future.
Flavie Pelletier, a recent PhD graduate of McGill University’s Natural Resource Sciences program, told me she first became interested in aspens while working as a tree planter in British Columbia. “The historical assumption on aspen is that stands are very good at stopping fire progression. But the paradox is that if you take an aspen by itself, it’s going to burn at high severity,” Pelletier, who published her findings in Forest Ecology and Management, told me.
By creating near-real-time maps of fires using satellites and comparing them against the Canadian Forest Service’s newly available maps of dominant tree species in the boreal, Pelletier and her colleagues discovered that aspen were almost two and a half times more common at the perimeter of a burned area than inside it. The finding suggests that despite the flammability of a single aspen with its thin bark, stands of aspen act as a kind of barrier when wildfire ran up against them, likely because they lack the flammable resins of conifers and their high foliage helps force running crown fires back toward the ground. Pine and spruce, by contrast, showed a near-zero or even negative effect.
When aspen stands did burn, Pelletier found they did so more slowly: A tree cover of 50% aspen burned at about 224 hectares per day, compared to 717 hectares per day in areas where aspen made up less than 10% of the cover. That’s the equivalent of about 1,000 FIFA-regulation soccer pitches per day in places where aspen are sparser — like Aspen Acres.
Even more surprising, though, was that the pattern held true in the early season, when the trees are still twiggy and have yet to grow their moisture-filled leaves, and despite the severity of fire weather. “Aspen still showed resilience even when the fire weather was very intense, [like in 2023, when] we had all the fires,” Pelletier said.
But she was also the first to admit that seasons are getting more extreme, and that there’s no guarantee the pattern will hold for the next 10 or 20 years.
Pelletier was reluctant to make a policy recommendation based on her research, noting that she’s not a forest manager. But in Alberta and British Columbia, timber companies spray hundreds of thousands of acres of timber with glyphosate, an herbicide, to kill off aspens because the trees outcompete the more commercially valuable conifers. Her findings are “a big argument to stop the spreading of herbicides because you’re increasing the risk of fire in your forest by removing aspen,” Pelletier said.
Despite her hesitation, Pelletier is explicit in her paper about one thing: that aspens “should be encouraged — specifically around key landscape positions, such as population centers” — given that they are a proven means of hardening the wildland-urban interface against wildfires. It might be too late for the idyllically named Aspen Acres, of course; any of the aspens that once drew tourists to the area are likely now ash.
But this not be Colorado’s last fire, either.