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Unpriced risk undermined the global economy during the financial crisis of 2008. Today, researchers say unpriced physical climate risk will lead to rapid declines in property values — and point out that this is already happening in some Florida markets. They often compare what’s happening now to the run-up to 2008. If the analogy holds, we will likely see disruption in other related financial structures. In particular, as the physical reality of climate change begins to have an effect on the attractiveness of bonds in risky areas, the ability of local governments to raise money to adapt to rapidly changing climate conditions may be undercut.
But comparing the effect of the 2008 unpriced risk on the municipal bond market with the potential effects of physical climate risk shows the suffering will likely be much greater this time. Today, there’s a direct, rather than indirect, connection between risk and public finance markets.
The solution? Last week, Tom Doe, CEO and founder of Municipal Market Analytics, said cities should act now to raise as much money as possible for adaptation before the municipal bond market starts pricing in physical climate risk. It’s only going to get more expensive later, in his view.
During the 2008 collapse, issuers of municipal bonds suffered. According to the final report on the crisis, New York State was stuck making suddenly skyrocketing interest payments to investors — the rate went from about 3.5% to more than 14% — on $4 billion of its debt. The Port Authority of New York and New Jersey’s interest rate went from 4.3% to 20% in a single week. Investors who had bought municipal bonds in auctions suffered too, because the pool of new buyers dried up very quickly in early 2008.
Since then, the muni market has bounced back in a big way, with professional investment managers urging tax-avoidant retail investors to buy individual bonds through separately managed accounts rather than through a mutual bond fund or an exchange-traded fund. Most people think $500 billion in bond issues is likely in 2025, and the group of buyers has a seemingly unending appetite for what they perceive to be safe and highly liquid investments — essentially the equivalent of money market accounts that promise federal tax-free interest payments.
But the risks now posed by physical climate change to municipal bond issuers and investors are different and likely greater than they were in 2008. The last time around, the municipal bond market suffered because of a domino effect — the insurance companies the issuers were using were exposed to mortgage risk.
According to the Financial Crisis Inquiry Report, so-called “monoline” insurers (writing policies for single financial structures rather than a broad array of products) had gotten into the mortgage-backed securities business, issuing a boatload of guarantees covering more than $250 billion of these structured products. The CEO of one of these monoline businesses, Alan Roseman of ACA, said, “We never expected losses. ... We were providing hedges on market volatility to institutional counterparties.” In other words, ACA believed its risk was limited because it wasn’t directly investing in the underlying assets — that its risk was limited to ups and downs in the market value of the mortgage-backed securities. But when the value of huge numbers of mortgage-backed securities plunged as the credit rating agencies woke up and repriced the risk of the subprime mortgages buried within them, ACA and other insurers were faced with stunning losses.
Those same insurers (MBIA, ACA, Ambac) were then substantially downgraded. And they hadn’t been insuring only mortgage-backed securities — they were also insuring municipal bonds and “auction rate securities” based on those bonds, structures that allowed local governments to borrow money at variable interest rates. When the insurance companies froze up because of the sudden repricing of mortgage-backed securities and their guarantees became worthless, the auction markets froze, as well. As a result, issuers of muni bonds (and investors in them) suffered.
In other words, in 2008, it was risk in a different financial arena — mortgage-backed securities guaranteed by insurance companies — that slopped over and caused problems for municipal bonds. By contrast, when it comes to physical climate change today, the municipal bond market is directly exposed to the central risk: Will the communities that effectively guarantee these bonds continue to be viable? Will these communities be insurable? Will community property values and thus property taxes suddenly decline?
Not only that, the 2008 risk was different because it could be eventually unwound. Property markets could get going again, as they have in spades. This time, deterioration of the underlying asset — the communities themselves — will likely be irreversible. Chronic flooding will not cease on any human-relevant time scale.
Issuers are not being penalized — yet — for the physical climate risk facing their communities, according to Tom Doe’s conversation with Will Compernolle on the latter’s Simply Put podcast last week. “This risk is not being priced in,” Doe said. “There’s no evidence of that right now. And in addition, the rating agencies have not reflected [physical risk] in their letter scoring of credit risk … so there is not a ratings penalty right now. There’s not a pricing penalty.”
Doe’s suggestion is that local governments may want to get out there and raise as much money as they can for adaptation. “State and local governments who are in harm’s way that need to do this can go to the market right now, and investors are not penalizing them. The market is not. So this is essentially cheap money if they issue [bonds] for these projects today,” Doe said.
That’s one way of looking at the situation. Public money for adaptation is cheap, there’s a lot of it potentially available, and it is much less expensive to raise that money now than it will be once the credit rating agencies and the investors start pricing in physical risk and demanding higher interest payments in exchange for the use of their cash.
It’s a race against time: Eventually, as in 2008, the mispriced risk will be correctly assessed. This time, unlike the last crisis, the harm to the underlying assets will be permanent.
A version of this article originally appeared in the author’s newsletter, Moving Day, and has been repurposed for Heatmap.
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New tariffs and price floors for imported polysilicon aim to protect U.S. producers from Chinese competition.
Almost exactly a month after President Donald Trump’s landmark tax law effectively eliminated a key incentive for solar developers to buy panels made in America, his administration is throwing a lifeline to manufacturers behind the nation’s fastest-growing and quickest-to-deploy source of electricity.
On Thursday afternoon, after the markets closed, the White House announced new tariffs and minimum import prices for imported polysilicon as part of an effort to prop up the domestic supply chain for the primary ingredient in semiconductors and solar panels.
The levies come in response to complaints from polysilicon makers that the dearth of U.S. factories demanding solar-grade polysilicon made it difficult to compete with Chinese giants who benefit from selling both the solar- and microchip-grade versions of the ultra-pure industrial material derived from quartz and sand. The companies made the petition under Section 232 of the Trade Expansion Act of 1962, which gives the White House the power to restrict imports and charge tariffs on imports that demonstrably impair national security.
The Trump administration will impose a 15% tariff on all imports and set baseline prices at which the levies would apply for each component in the solar supply chain. Polysilicon will have a minimum import price of $20 per kilogram. Wafers, the ultra-thin slice of crystalline silicon that acts as the foundation of a photovoltaic cell, and ingots, the silicon material before it’s sliced, will start at $100 per kilogram. Cells, the tiny silicon-based devices that absorb photons from sunlight and break away electrons that generate electrical currents, will have a minimum price of $0.22 per watt. Modules, the completed panels, are $0.38 a watt.
The majority of U.S. solar factories simply assemble wafers and cells into modules, leaving them reliant on imports. But the policy won’t hit all at once. The Commerce Department is giving companies 120 days before the restrictions kick in.
The agency will also set up an incentive program that allows manufacturers that make large capital investments in the U.S. to avoid the worst of the levies. Jeffrey Kessler, the Under Secretary of Commerce in charge of executing on 232 cases, pushed for the provision as a bid to avoid what happened when Europe attempted to protect its own solar manufacturers by setting a minimum import price meant to keep Chinese companies from flooding the market. That policy ended up subsidizing the very Chinese parent companies putting market domination ahead of profits back home.
Avoiding that outcome is tricky under any circumstances. China and the U.S. don’t have a tax treaty, which makes it difficult for American authorities to confirm a company’s ownership structure. The surest way to seal off the U.S. market is with 100% tariffs such as those imposed on Chinese electric vehicles.
In this case, the Commerce Department decided to allow companies with active plans to onshore the solar supply chain to apply for an exemption from the new trade rules. Ahead of the announcement, sources familiar with the talks listed South Korean giant Qcells, which just opened the nation’s largest integrated solar factory in Georgia, as one obvious example of a company that would pass muster.
Solar manufacturers applauded the move. “Today’s decision from the White House balances the reality of where America’'s solar energy manufacturing is today while advancing our collective ambition to onshore the entire supply chain from polysilicon to finished panels in the U.S.,” Andy Park, the global CEO of Qcells, said in an emailed statement. “American solar manufacturers are ready to rise to the occasion.”
The trade action “creates a market where wafer and cell manufacturing can happen in the United States, and companies can go fully vertically integrated,” Nick Iacovella, the executive vice president of the Coalition for a Prosperous America, a bipartisan trade association that represents manufacturing companies at every stage of the polysilicon supply chain, told Heatmap.
“What this does is cement a key input in the supply chain that’s critical not just for chips, but for the most efficient, best-performing solar modules,” he said. “We shore up our chip supply chain at a time when there is a greater urgency to derisk from China invading Taiwan — and also during a time when the AI data center boom is driving massive demand for new energy generation, with solar driving a lot of the new capacity coming onto the grid.”
The levies come a week after the Federal Communications Commission banned the use of new types of foreign-made inverters, the equipment needed to patch solar panels onto the grid. Analysts said the ban would have a limited effect on the solar industry, since it allows for the current models on the market to be sold. The purpose of that policy is to prop up domestic factories at a moment when Europe, despite its struggle to reindustrialize, is experiencing an inverter manufacturing boom.
Despite those intentions, multiple industry sources who spoke on condition of anonymity told Heatmap that trade restrictions alone would likely prove insufficient to prop up a domestic solar supply chain at the scale needed to minimize imports.
The latest data from the Rhodium Group found that new U.S. investments in solar factories peaked from the second half of 2022 through the first quarter of 2025. During that time, as Emily reported in May, the announced projects averaged more than $2 billion per quarter. At least 30 new utility-scale solar factories opened across the U.S. just last year.
Since then, development has plummeted. Investment in new solar factories announced fell to about $350 million in the first quarter of 2026, a drop of more than 80%.
By raising the price of panels overall, the Commerce Department is providing a particular boon to America’s leading solar manufacturer, First Solar. While the Phoenix-based panel-maker’s thin-film cell technology doesn’t use polysilicon, the price hike from the tariffs will give the company an edge by allowing the company to either raise its prices to match new industry-wide benefits or undercut its competitors. Investors in the company told Heatmap its recent bookings average sales of about $0.36 per watt.
Another clear winner is T1 Energy, which Roth analysts say “would eventually be a beneficiary once it ramps up its U.S. cell manufacturing, which is now expected to come online” next year. The company’s share price spiked more than 10% in after-hours trading, while First Solar was up more than 8%.
“There are a lot of people in the administration who support solar,” Iacovella said. “They just don’t want a bunch of Chinese solar panels.”
Still, he added, “this is all about the chip supply chain.” While the benefits to solar are welcome, “this is a two-for-one.”
The Trump administration has signed a deal with RWE, a German developer, to cancel more than 3 gigawatts of offshore wind near New York and New Jersey.
This is an edition of Heatmap Daily, an evening review of the day’s news written by our executive editor. Sign up for it here.
There goes another one. The German energy developer RWE has signed a $1.2 billion deal with the Trump administration to give up its claims to develop offshore wind farms in New York, California, and Louisiana. The Trump administration has now bought out 12 offshore wind leases, paying energy developers $3.93 billion for the privilege of not developing renewable energy along the American coastline.
Today’s is the largest payout yet — and fittingly so, I suppose, because it is among the most damaging. As part of the deal, RWE abandoned its plans to build a more than 3-gigawatt offshore wind farm in the New York Bight. When RWE first leased that site in 2022, it paid $1.1 billion for it — the biggest offshore wind lease auction ever held in the United States.
RWE promised that the resulting facility, dubbed Community Offshore Wind, would generate 700 jobs and $3 billion in local economic activity. It would have been close enough to New Jersey and New York that its power could have flowed to either state, although no final power contract was ever signed. Now all of that is kaput.
In the eyes of some critics, RWE had overpaid for that lease — and in that context, the Trump administration has I suppose done the German developer a favor, bailing them out from a bad investment in a legally dubious manner. (New York’s attorney general is suing to block a similar payout to Total Energies.)
But even beyond that context, there remains one big problem with these deals — an issue even more glaring now than when Trump started targeting wind projects last year. It is that the United States — and especially the Northeast, and especially New York — needs as much electricity as it can get right now. The Trump administration is striving to bring new power demand online in the form of data centers, but cutting off new sources of generation if they fail to meet its aesthetic standards.
Anticipating this sensitivity, RWE’s press statement announcing the deal goes on to list major energy projects that it’s committed to in the United States. These projects all involve, coincidentally (or not), fossil fuels: They include a $900 million stake in a Louisiana liquified natural gas export terminal and a $300 million reservation for new natural gas turbines. (RWE implies, but doesn’t say outright, that it will build 15 natural gas peaker plants with these turbines.) When we asked for more details about these projects, and whether we should anticipate anything new, RWE immediately got back to us: “We are unable to discuss further details on the investments.”
Yet as RWE well knows, these projects won’t help solve a coming energy shortage in New York or New England. For one, the Louisiana LNG export terminal is, well, an export terminal: It will help move energy out of the country, not generate more of it at home. Those exports might boost Americans’ fortunes in a vague, long-term, balance-of-payments way, but they won’t keep a lid on anyone’s power bills (which, by the way, just hit an all-time high). More importantly, the 15 peaker plants that RWE cites are largely going to be built … in other regions of the country. If the lights go out on Houston Street, a new gas plant in Houston can’t help.
Americans paid $217 on average for electricity last month, according to Heatmap and MIT’s Electricity Price Hub.
July is typically the season of high electricity bills, and this year is no exception.
Nationally, the average electricity bill spiked to $217, an all-time high, according to new data from Heatmap and MIT’s Electricity Price Hub. That’s up from $177 in June, and $215 last July. Meanwhile, electricity rates were 19 cents per kilowatt-hour, virtually unchanged from June and slightly higher than July of last year.
Throughout the country, many ratepayers are seeing higher costs and charges in the portion of their bill covering the cost of power generation.
Once again, some of the most notable electricity price and bill trends were seen in the mid-Atlantic region, the heart of the data center boom and the anchor area of the PJM Interconnection. The region also includes Virginia, where Florida utility and energy developer NextEra is attempting to acquire the commonwealth’s dominant utility, Dominion.
In July, Dominion customers saw typical generation charges rise to $155 a month, up from $124 a year ago. Overall bills for Dominion customers were about $259 this past month.
The higher bills are in part due to the “fuel charge rider” that went into effect this past month to help recover about $1 billion in additional generation costs claimed by the utility. Those charges stem in part from higher fuel costs this past winter, when natural gas prices spiked to their highest level since the winter of 2022-23, Dominion officials said in a filing to the state’s utilities regulator. The MIT researchers estimate that the fuel charge added around $53 to July bills, up $12 from July of last year.
In neighboring Delaware, bills were $216 a month in July, a record high, while prices were around 19 cents per kilowatt-hour. Customers of the state’s main utility, Delmarva Power, saw a near 20% hike in the supply charge in their standard service offerings, as prices rose from around 16 cents per kilowatt-hour from last year.
The Delaware Public Service Commission voted at the beginning of last month to allow an interim rate increase of about $3 per month for the typical customer, which went into effect July 9. Soon after, Delaware Governor Matt Meyer signed a law giving the state’s regulators more discretion to reject putting certain utility costs into the rate base and thus limit subsequent price hikes requested by utilities. The governor’s office described the law as a mechanism “to prioritize prudent spending over unchecked cost recovery.”