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Vermont’s natural gas company is selling heat pumps and rebranding itself a “thermal service provider.”
On a recent Friday morning, I sat down to watch a webinar about a natural gas utility and unexpectedly found myself glued to the screen.
The video featured Morgan Hood, the new product development manager at a small utility once called Vermont Gas Systems, now known simply as VGS, that serves about 55,000 customers in its titular state. For 80 minutes Hood described how the company was working to reinvent itself as a “thermal solutions provider.” As part of that mission, it had recently started selling and leasing electric heat pump water and space heaters to its customers to help them reduce their gas use.
As a reporter who has covered natural gas utilities’ expansion plans and the industry’s all-out war on electrification, I was stunned. The programs alone were unusual, but what surprised me more was the way Hood talked about them.
“If we want to continue to serve our customers, which we do, significant changes are necessary,” she said, describing a “dramatic shift” in public sentiment toward natural gas in Vermont. “We know we're not going to be expanding our customer base with natural gas customers in the future.”
It’s hard to overstate how different Hood’s tone and message were from that of the average gas utility executive, who tends to highlight their product’s popularity and make a case for its role in a low-carbon future. Consider the remarks of Kim Greene, the CEO of the much larger Southern Company Gas, at a conference I attended in November. “Natural gas is foundational to America's clean energy future," she told an audience of state regulators. Without ever once acknowledging that natural gas contributes to climate change, she went on to describe it as a “magical molecule” that was important to the company’s decarbonization strategy.
When I later probed climate advocates in Vermont about VGS, I learned that many dismiss the company’s image change as greenwashing, or are at least skeptical of its plans. They pointed to a highly contested $165 million pipeline the company recently built, and a controversial plan to replace the fuel in its pipelines with biogas and hydrogen.
But my initial impressions also weren’t unfounded. The company does in fact seem to be unique in the way it has actively started leaning into the shift that science, policy, and economics are all driving toward — a transition to all-electric buildings.
“VGS is among the most progressive gas utilities in the country, there's no question about that,” Ben Walsh, the climate and energy program director at the Vermont Public Interest Research Group, and a longtime critic of VGS, told me.
The company still has a lot to figure out. Hood was remarkably transparent in acknowledging that the new products VGS is offering aren’t nearly as profitable as selling natural gas. But its recent past and its uncertain future make it a revealing case study of the challenges gas companies face in trying to stay viable as they try to decarbonize.
The webinar, titled “A Gas Utility Goes Electric,” was organized by a Portland, Oregon-based advocacy group called Electrify Now. Its co-founder Brian Stewart told me he initially had some reservations about featuring a gas utility in their event series, but he and his partners were impressed with the company’s interest in engaging with an electrification group. They hoped the talk might reveal a model that other utilities could follow — particularly Northwest Natural, their local gas utility in Oregon.
“They're doing the exact opposite of what VGS is at least attempting to do,” Stewart said. “Northwest Natural is still denying the idea that electrification is even better from an emissions standpoint.”
In fact, Northwest Natural is not just denying it — it’s reportedly putting millions of dollars into opposing electrification. In February, the Oregon city of Eugene passed an ordinance banning gas hookups in new residential buildings. Northwest Natural responded by spending more than $900,000 to get a measure to overturn the gas ban on the city’s November ballot, according to campaign finance records reviewed by The Washington Post. And it’s just getting started. The Post obtained audio indicating that the gas industry plans to spend $4 million on the Eugene referendum.
The strategy has been widely adopted by the gas industry. Last year, a utility in Southern California, SoCalGas, was fined $10 million for spending ratepayer funds to fight stronger building efficiency standards that would have reduced natural gas demand. New York Focusreported last week that National Fuel, a gas utility in Western New York, is spending hundreds of thousands of ratepayer dollars to lobby against a statewide push to reduce natural gas use.
VGS, on the other hand, first signaled it was reading the writing on the wall for natural gas in 2019, when it announced a new strategy to eliminate its greenhouse gas emissions by 2050.
That was around the time state leaders were contemplating a new climate law called the Global Warming Solutions Act, which passed the following year. VGS hired a new CEO, Neale Lunderville, who reorganized the company, creating new positions focused on decarbonization, including Hood’s role. Richard Donnelly, who spent a decade working for a nonprofit utility dedicated to energy efficiency joined VGS as its Director of Energy Innovation.
“The creation of that job was a clear signal to me that they were investing in the right things,” Donnelly told me.
VGS rolled out its first electrification program in early 2022, offering customers the option to lease or buy heat pump water heaters. The company was in a fairly unique position to do this, as it already had a sales and leasing program for gas equipment and an in-house team trained to install heating equipment.
Then, a couple of weeks ago, VGS launched an electric space heating program, offering central heat pumps that utilize the same ductwork as a homeowner’s existing furnace. For now, the company is installing these as dual fuel systems, meaning recipients keep their gas furnaces as a back-up source of heat. While heat pumps designed for cold climates don’t require this, they do lose efficiency in the coldest temperatures. Customers can decide when they want the system to switch over to gas, and the company developed a calculator that shows them how much carbon they can save, and what the anticipated costs will be, depending on where they set the switchover point.
The space heating systems are only available to a portion of the company’s customers — about 40% — because most have boilers and radiators with no ductwork. Hood said they hope to offer electric options for those homes in the future.
Dylan Giambatista, director of public affairs for VGS, told me the program is already taking off. Two weeks after it launched, they had well over 100 inquiries, he said. The water heaters, on the other hand, have had a pretty slow start. Only about 6% — or 48 total — of the water heaters the company has installed since January 2022 were heat pumps. “I don't think that folks are yet aware of that technology,” he said. “We expect heat pump water heater use will increase over time as incentives and consumer awareness increase,” he added in an email later.
Electrification isn’t the company’s only strategy to meet Vermont’s emissions goals.
It’s trying to reduce customers’ total energy usage through weatherization and other home efficiency improvements.
It’s also investing in alternative fuels, like renewable natural gas and hydrogen, to pump through its pipelines to any remaining gas customers. Nearly two-thirds of the gas that VGS sells is delivered to commercial and industrial customers, not all of whom may be able to fully electrify their operations. But local climate advocates have a lot of concerns about that aspect of the plan. Renewable natural gas, which typically comes from decomposing waste or dairy manure, is a lot more expensive than fossil gas. There’s also research indicating that it doesn’t necessarily have the climate benefits that proponents claim.
While Walsh, of the Public Interest Research Group, acknowledged how unique VGS’ electrification programs were, he said it's way too early to give the company the benefit of the doubt.
“There are some strategies that a gas utility could implement, that on the surface look good, but ultimately don't serve Vermont,” he said. “I think it's incumbent on all of us that are focused on cutting carbon pollution and cutting energy costs for Vermonters to watchdog their efforts very closely as they unfold.”
Others discount VGS’ heat pump programs because the company also continues to market and sell gas equipment and hook up new gas customers. Annette Smith, who runs a group called Vermonters for a Clean Environment sent me a screenshot of a VGS Facebook ad from May 8 offering people $500 to switch to natural gas.
Jim Dumont, a lawyer who has represented opponents of VGS in regulatory cases and lawsuits for years, said the first thing the company has to do to win public trust is come clean. “They have to tell the public that burning gas to heat your homes is helping push us over the climate cliff,” he told me. “They can sell heat pumps, but it's a competing message.”
VGS doesn’t deny that natural gas contributes to climate change. Lunderville, the CEO, told Vermont officials in a 2021 letter that the company recognizes “that its principal product today — fossil gas — has significant climate impacts.”
But the message stings with irony to Dumont, who has spent the last decade fighting a 41-mile gas pipeline the company built prior to its come-to-Jesus moment. Back in 2013, when VGS was first seeking approval for the pipeline from regulators, it argued that the project would cut energy costs and carbon emissions in the state. Most Vermonters did, and still do, heat their homes with fuel oil, propane, or wood — and gas can be a cleaner and often cheaper option. But opponents argued that cold climate heat pumps that were coming on to the market would be more affordable and effective.
Cold climate heat pumps were still pretty new at the time, and certainly weren’t being adopted in Vermont yet. The idea was sidelined, and while the scale of the pipeline was ultimately reduced, its cost ballooned from $86 million to $165 million. And now that it's completed, VGS is marketing heat pumps.
To Dumont, that’s not only ironic, it’s worrisome. The way gas utilities like VGS pay for big pipeline projects is to recover the costs over decades through customer bills. But if VGS helps people go electric, the residual costs of the pipeline are going to fall on fewer and fewer customers. As VGS leans into electrification, it could also be barreling toward a scenario referred to as the utility death spiral: the cost of gas will increase, driving more people to get off it.
“Is the public going to be asked to bail out the company, or will the company be responsible for its own bad judgment and will its sole shareholder have to swallow the loss?” Dumont asked. “If there are no consequences for making a bad investment, then effectively it's not a regulated utility, it's effectively a taxpayer-funded business.”
This is a problem that all gas utilities are facing or will likely face, whether or not they embrace a transition to electric buildings. Mike Henchen, a principle in the carbon-free buildings program at RMI, a national nonprofit, said this was “the elephant in the room” around the country.
“How to deal with all the customers hooked up to this fossil fuel system looms large on the horizon,” he said. “There's not going to be an easy way to tackle that.”
I reached out to Énergir, the Canadian company that owns VGS, to find out whether it had any concerns about VGS’ financial future. “Énergir has always believed in the complementarity of different energy solutions and in accelerating electrification where it makes sense,” Éric Lachance, president and CEO of Énergir said by email, adding that “Énergir strongly supports VGS’s approach.”
Though heat pumps aren’t as profitable as natural gas, the company does see opportunities for growth. It can sell and lease the water heaters to residents outside its existing customer base. It’s also exploring the potential to build and manage geothermal heating networks, where entire neighborhoods could be heated by underground pipes carrying nothing but water.
“The market opportunity is huge,” said Donnelly, the Director of Energy Innovation. For now, the company is primarily limited by staffing, and is being careful not to create more demand than it can fulfill. He estimated VGS was looking at “hundreds of installs over the next couple of years and growing that part of our business quite rapidly, hopefully, within the next five years.”
VGS also sees potential for these programs to become more profitable thanks to a law passed by the state legislature earlier this month called the Affordable Heat Act that directs the state’s utility regulators to design a clean heat standard. The company could eventually earn credits for its electrification programs and sell them to other fuel providers in the state that need to comply with the standard.
As policy and technology continue to evolve, it makes sense that VGS doesn’t know exactly what the future holds. But faced with similar uncertainty, most gas utilities have responded by putting their heads in the sand or fighting tooth and nail against change.
What makes VGS remarkable is that it’s at least trying to find its place in a post-gas world.
Editor’s note: A previous version of this article understated the length of a VGS pipeline. It is 41 miles, not 27 miles. The article has been corrected. We regret the error.
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Ecolectro, a maker of electrolyzers, has a new manufacturing deal with Re:Build.
By all outward appearances, the green hydrogen industry is in a state of arrested development. The hype cycle of project announcements stemming from Biden-era policies crashed after those policies took too long to implement. A number of high profile clean hydrogen projects have fallen apart since the start of the year, and deep uncertainty remains about whether the Trump administration will go to bat for the industry or further cripple it.
The picture may not be as bleak as it seems, however. On Wednesday, the green hydrogen startup Ecolectro, which has been quietly developing its technology for more than a decade, came out with a new plan to bring the tech to market. The company announced a partnership with Re:Build Manufacturing, a sort of manufacturing incubator that helps startups optimize their products for U.S. fabrication, to build their first units, design their assembly lines, and eventually begin producing at a commercial scale in a Re:Build-owned factory.
“It is a lot for a startup to create a massive manufacturing facility that’s going to cost hundreds of millions of dollars when they’re pre-revenue,” Jon Gordon, Ecolectro’s chief commercial officer, told me. This contract manufacturing partnership with Re:Build is “massive,” he said, because it means Ecolectro doesn’t have to take on lots of debt to scale. (The companies did not disclose the size of the contract.)
The company expects to begin producing its first electrolyzer units — devices that split water into hydrogen and oxygen using electricity — at Re:Build’s industrial design and fabrication site in Rochester, New York, later this year. If all goes well, it will move production to Re:Build’s high-volume manufacturing facility in New Kensington, Pennsylvania next year.
The number one obstacle to scaling up the production and use of cleaner hydrogen, which could help cut emissions from fertilizer, aviation, steelmaking, and other heavy industries, is the high cost of producing it. Under the Biden administration, Congress passed a suite of policies designed to kick-start the industry, including an $8 billion grant program and a lucrative new tax credit. But Biden only got a small fraction of the grant money out the door, and did not finalize the rules for claiming the tax credit until January. Now, the Trump administration is considering terminating its agreements with some of the grant recipients, and Republicans in Congress might change or kill the tax credit.
Since the start of the year, a $500 million fuel plant in upstate New York, a $400 million manufacturing facility in Michigan, and a $500 million green steel factory in Mississippi, have been cancelled or indefinitely delayed.
The outlook is particularly bad for hydrogen made from water and electricity, often called “green” hydrogen, according to a recent BloombergNEF analysis. Trump’s tariffs could increase the cost of green hydrogen by 14%, or $1 per kilogram, based on tariff announcements as of April 8. More than 70% of the clean hydrogen volumes coming online between now and 2030 are what’s known as “blue” hydrogen, made using natural gas, with carbon capture to eliminate climate pollution. “Blue hydrogen has more demand than green hydrogen, not just because it’s cheaper to produce, but also because there’s a lot less uncertainty around it,” BloombergNEF analyst Payal Kaur said during a presentation at the research firm’s recent summit in New York City. Blue hydrogen companies can take advantage of a tax credit for carbon capture, which Congress is much less likely to scrap than the hydrogen tax credit.
Gordon is intimately familiar with hydrogen’s cost impediments. He came to Ecolectro after four years as co-founder of Universal Hydrogen, a startup building hydrogen-powered planes that shut down last summer after burning through its cash and failing to raise more. By the end, Gordon had become a hydrogen skeptic, he told me. The company had customers interested in its planes, but clean hydrogen fuel was too expensive at $15 to $20 per kilogram. It needed to come in under $2.50 to compete with jet fuel. “Regional aviation customers weren’t going to spend 10 times the ticket price just to fly zero emissions,” he said. “It wasn’t clear to me, and I don’t think it was clear to our prospective investors, how the cost of hydrogen was going to be reduced.” Now, he’s convinced that Ecolectro’s new chemistry is the answer.
Ecolectro started in a lab at Cornell University, where its cofounder and chief science officer Kristina Hugar was doing her PhD research. Hugar developed a new material, a polymer “anion exchange membrane,” that had potential to significantly lower the cost of electrolyzers. Many of the companies making electrolyzers use designs that require expensive and supply-constrained metals like iridium and titanium. Hugar’s membrane makes it possible to use low-cost nickel and steel instead.
The company’s “stack,” the sandwich of an anode, membrane, and cathode that makes up the core of the electrolyzer, costs at least 50% less than the “proton exchange membrane” versions on the market today, according to Gordon. In lab tests, it has achieved more than 70% efficiency, meaning that more than 70% of the electrical energy going into the system is converted into usable chemical energy stored in hydrogen. The industry average is around 61%, according to the Department of Energy.
In addition to using cheaper materials, the company is focused on building electrolyzers that customers can install on-site to eliminate the cost of transporting the fuel. Its first customer was Liberty New York Gas, a natural gas company in Massena, New York, which installed a small, 10-kilowatt electrolyzer in a shipping container directly outside its office as part of a pilot project. Like many natural gas companies, Liberty is testing blending small amounts of hydrogen into its system — in this case, directly into the heating systems it uses in the office building — to evaluate it as an option for lowering emissions across its customer base. The equipment draws electricity from the local electric grid, which, in that region, mostly comes from low-cost hydroelectric power plants.
Taking into account the expected manufacturing cost for a commercial-scale electrolyzer, Ecolectro says that a project paying the same low price for water and power as Liberty would be able to produce hydrogen for less than $2.50 per kilogram — even without subsidies. Through its partnership with Re:Build, the company will produce electrolyzers in the 250- to 500-kilowatt range, as well as in the 1- to 5-megawatt range. It will be announcing a larger 250-kilowatt pilot project later this year, Gordon said.
All of this sounded promising, but what I really wanted to know is who Ecolectro thought its customers were going to be. Demand for clean hydrogen, or the lack thereof, is perhaps the biggest challenge the industry faces to scaling, after cost. Of the roughly 13 million to 15 million tons of clean hydrogen production announced to come online between now and 2030, companies only have offtake agreements for about 2.5 million tons, according to Kaur of BNEF. Most of those agreements are also non-binding, meaning they may not even happen.
Gordon tied companies’ struggle with offtake to their business models of building big, expensive, facilities in remote areas, meaning the hydrogen has to be transported long distances to customers. He said that when he was with Universal Hydrogen, he tried negotiating offtake agreements with some of these big projects, but they were asking customers to commit to 20-year contracts — and to figure out the delivery on their own.
“Right now, where we see the industry is that people want less hydrogen than that,” he said. “So we make it much easier for the customer to adopt by leasing them this unit. They don’t have to pay some enormous capex, and then it’s on site and it’s producing a fair amount of hydrogen for them to engage in pilot studies of blending, or refining, or whatever they’re going to use it for.”
He expects most of the demand to come from industrial customers that already use hydrogen, like fertilizer companies and refineries, that want to switch to a cleaner version of the fuel, or hydrogen-curious companies that want to experiment with blending it into their natural gas burners to reduce their emissions. Demand will also be geographically-limited to places like New York, Washington State, and Texas, that have low-cost electricity available, he said. “I think the opportunity is big, and it’s here, but only if you’re using a product like ours.”
On coal mines, Energy Star, and the EV tax credit
Current conditions: Storms continue to roll through North Texas today, where a home caught fire from a lightning strike earlier this week • Warm, dry days ahead may hinder hotshot crews’ attempts to contain the 1,500-acre Sawlog fire, burning about 40 miles west of Butte, Montana• Severe thunderstorms could move through Rome today on the first day of the papal conclave.
The International Energy Agency published its annual Global Methane Tracker report on Wednesday morning, finding that over 120 million tons of the potent greenhouse gas were emitted by oil, gas, and coal in 2024, close to the record high in 2019. In particular, the research found that coal mines were the second-largest energy sector methane emitter after oil, at 40 million tons — about equivalent to India’s annual carbon dioxide emissions. Abandoned coal mines alone emitted nearly 5 million tons of methane, more than abandoned oil and gas wells at 3 million tons.
“Coal, one of the biggest methane culprits, is still being ignored,” Sabina Assan, the methane analyst at the energy think tank Ember, said in a statement. “There are cost-effective technologies available today, so this is a low-hanging fruit of tackling methane.” Per the IEA report, about 70% of all annual methane emissions from the energy sector “could be avoided with existing technologies,” and “a significant share of abatement measures could pay for themselves within a year.” Around 35 million tons of total methane emissions from fossil fuels “could be avoided at no net cost, based on average energy prices in 2024,” the report goes on. Read the full findings here.
Opportunities to reduce methane emissions in the energy sector, 2024
IEA
The Environmental Protection Agency told staff this week that the division that oversees the Energy Star efficiency certification program for home appliances will be eliminated as part of the Trump administration’s ongoing cuts and reorganization, The Washington Post reports. The Energy Star program, which was created under President George H.W. Bush, has, in the past three decades, helped Americans save more than $500 billion in energy costs by directing them to more efficient appliances, as well as prevented an estimated 4 billion metric tons of greenhouse gas from entering the atmosphere since 1992, according to the government’s numbers. Almost 90% of Americans recognize its blue logo on sight, per The New York Times.
President Trump, however, has taken a personal interest in what he believes are poorly performing shower heads, dishwashers, and other appliances (although, as we’ve fact-checked here at Heatmap, many of his opinions on the issue are outdated or misplaced). In a letter on Tuesday, a large coalition of industry groups including the Air-Conditioning, Heating, and Refrigeration Institute, the Association of Home Appliance Manufacturers, and the U.S. Chamber of Commerce wrote to EPA Administrator Lee Zeldin in defense of Energy Star, arguing it is “an example of an effective non-regulatory program and partnership between the government and the private sector. Eliminating it will not serve the American people.”
House Speaker Mike Johnson suggested that the electric vehicle tax credit may be on its last legs, according to an interview he gave Bloomberg on Tuesday. “I think there is a better chance we kill it than save it,” Johnson said. “But we’ll see how it comes out.” He estimated that House Republicans would reveal their plan for the tax credits later this week. Still, as Bloomberg notes, a potential hangup may be that “many EV factories have been built or are under construction in GOP districts.”
As we’ve covered at Heatmap, President Trump flirted with ending the $7,500 tax credit for EVs throughout his campaign, a move that would mark “a significant setback to the American auto industry’s attempts to make the transition to electric vehicles,” my colleague Robinson Meyer writes. That holds true for all EV makers, including Tesla, the world’s most valuable auto company. However, its CEO, Elon Musk — who holds an influential position within the government — has said he supports the end of the tax credit “because Tesla has more experience building EVs than any other company, [and] it would suffer least from the subsidy’s disappearance.”
Constellation Energy Corp. held its quarterly earnings call on Tuesday, announcing that its operating revenue rose more than 10% in the first three months of the year compared to 2024, beating expectations. Shares climbed 12% after the call, with Chief Executive Officer Joe Dominguez confirming that Constellation’s pending purchase of natural gas and geothermal energy firm Calpine is on track to be completed by the end of the year, and that the nuclear power utility is “working hard to meet the power needs of customers nationwide, including powering the new AI products that Americans increasingly are using in their daily lives and that businesses and government are using to provide better products and services.”
But as my colleague Matthew Zeitlin reported, Dominguez also threw some “lukewarm water on the most aggressive load growth projections,” telling investors that “it’s not hard to conclude that the headlines are inflated.” As Matthew points out, Dominguez also has some reason to downplay expectations, including that “there needs to be massive investment in new power plants,” which could affect the value of Constellation’s existing generation fleet.
The Rockefeller Foundation aims to phase out 60 coal-fired power plants by 2030 by using revenue from carbon credits to cover the costs of closures, the Financial Times reports. The team working on the initiative has identified 1,000 plants in developing countries that would be eligible for the program under its methodology.
Rob and Jesse go deep on the electricity machine.
Last week, more than 50 million people across mainland Spain and Portugal suffered a blackout that lasted more than 10 hours and shuttered stores, halted trains, and dealt more than $1 billion in economic damage. At least eight deaths have been attributed to the power outage.
Almost immediately, some commentators blamed the blackout on the large share of renewables on the Iberian peninsula’s power grid. Are they right? How does the number of big, heavy, spinning objects on the grid affect grid operators’ ability to keep the lights on?
On this week’s episode of Shift Key, Jesse and Rob dive into what may have caused the Iberian blackout — as well as how grid operators manage supply and demand, voltage and frequency, and renewables and thermal resources, and operate the continent-spanning machine that is the power grid. Shift Key is hosted by Robinson Meyer, the founding executive editor of Heatmap, and Jesse Jenkins, a professor of energy systems engineering at Princeton University.
Subscribe to “Shift Key” and find this episode on Apple Podcasts, Spotify, Amazon, or wherever you get your podcasts.
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Here is an excerpt from our conversation:
Robinson Meyer: So a number of people started saying, oh, this was actually caused because there wasn’t enough inertia on the grid — that Spain kind of flew too close to the sun, let’s say, and had too many instantaneous resources that are metered by inverters and not by these large mechanical generators attached to its grid. Some issue happened and it wasn’t able to maintain the frequency of its grid as needed. How likely do you think that is?
Jesse Jenkins: So I don’t think it’s plausible as the precipitating event, the initial thing that started to drive the grid towards collapse. I would say it did contribute once the Iberian grid disconnected from France.
So let me break that down: When Spain and Portugal are connected to the rest of the continental European grid, there’s an enormous amount of inertia in that system because it doesn’t actually matter what’s going on just in Spain. They’re connected to this continen- scale grid, and so as the frequency drops there, it drops a little bit in France, and it drops a little bit in Latvia and all the generators across Europe are contributing to that balance. So there was a surplus of inertia across Europe at the time.
Once the system in Iberia disconnected from France, though, now it’s operating on its own as an actual island, and there it has very little inertia because the system operator only scheduled a couple thousand megawatts of conventional thermal units of gas power plants and nuclear. And so it had a very high penetration on the peninsula of non-inertia-based resources like solar and wind. And so whatever is happening up to that point, once the grid disconnected, it certainly lacked enough inertia to recover at that point from the kind of cascading events. But it doesn’t seem like a lack of inertia contributed to the initial precipitating event.
Something — we don’t know what yet — caused two generators to simultaneously disconnect. And we know that we’ve observed oscillation in the frequency, meaning something happened to disturb the frequency in Spain before all this happened. And we don’t know exactly what that disturbance was.
There could have been a lot of different things. It could have been a sudden surge of wind or solar generation. That’s possible. It could have been something going wrong with the control system that manages the automatic response to changes in frequency — they were measuring the wrong thing, and they started to speed up or slow down, or something went wrong. That happened in the past, in the case of a generator in Florida that turned on and tried to synchronize with the grid and got its controls wrong, and that causes caused oscillations of the frequency that propagated all through the Eastern Interconnection — as far away as North Dakota, which is like 2,000 miles away, you know? So these things happen. Sometimes thermal generators screw up.
Music for Shift Key is by Adam Kromelow.