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Why power lines are harder to build than pipelines
How hard is it to build big clean-energy infrastructure in America? Look at SunZia.
When completed, the more-than-500-mile power line is meant to ferry electricity from a massive new wind farm in New Mexico to the booming power markets of Arizona and California. When finally built, SunZia will be the largest renewable project in the United States, if not the Western Hemisphere.
But as I detail in a recent investigation for Heatmap, it has taken too long — much too long — to build. Nearly two decades have elapsed since a project developer first asked the federal government for permission to build SunZia.
Since it was first proposed, SunZia has endured seemingly endless environmental studies and lawsuits. It has been bought, sold, and bargained over. The end result is that a project first conceived in 2006 — which was expected to operate in 2013 — is now due to open in 2026.
That is a massive problem, because confronting climate change will require the country to build dozens of new long-distance power lines like SunZia. If the United States wants to meet its Paris Agreement goal by 2050, then it will have to triple the size of its power grid in just 26 years, according to Princeton’s Net Zero America study. (That research was led by Jesse Jenkins, who co-hosts Heatmap’s “Shift Key” podcast with me.)
The country is not on track to meet that goal. My story on SunZia set out to determine why.
Here are three major takeaways from my investigation:
At a fundamental level, a power line and a natural gas pipeline aren’t so different: Both move a large amount of energy over a long distance.
Yet it is much easier to build a natural gas pipeline than a transmission line, and they face very different regulatory hurdles in America. When a company proposes a new transmission line, it must get permission from every state whose borders it plans to cross. This can result in an arduous, years-long process of application, study, and approval.
That same obstacle does not hinder gas developers. When a company proposes a new natural gas pipeline, it can get many of its permits handled by a single federal agency, the Federal Energy Regulatory Commission. FERC is a one-stop shop for gas pipeline developers, organizing and granting state-level permits through a streamlined process.
(To be sure, natural gas pipelines sometimes need permits from other federal agencies — such as the Bureau of Land Management — before they can begin construction. But transmission developers need to get permits from those other federal agencies, too.)
But not all of the obstacles are regulatory. Transmission and renewable projects simply look different than pipelines, which can make environmentalists and the public more skeptical of them. Even though pipelines can leak or spill, they can be buried or built closer to the ground than power lines, and therefore pose less of a visual disturbance to the landscape.
In recent years, much of the controversy around SunZia has focused on the San Pedro Valley, a gorgeous desert landscape northeast of Tucson, Arizona. SunZia must pass through the valley to connect to a power station near Phoenix.
Two Native American tribes — the Tohono O'odham Nation and the San Carlos Apache Tribe — sued to block SunZia last year. They argue that the valley has cultural value and must be preserved intact and undiminished.
But the valley is already home to a large natural gas pipeline, mostly — but not entirely — buried underground. (The pipeline is on pylons near Redington, Arizona, where it crosses the San Pedro River.)
In an interview, a leader at the Center for Biological Diversity, an environmentalist group that joined the tribes’ lawsuit, said that SunZia’s proposed power line is problematic in part because it will be so tall.
“There are no 200-foot large power lines going through the San Pedro Valley,” Robin Silver, the leader, told me. “The gas pipeline doesn’t have 200 foot towers.”
If environmentalists focus on a project’s visual prominence, then pipelines will virtually always win out over transmission lines.
A federal judge dismissed the tribes’ lawsuit last month. A representative of the Tohono O'odham Nation did not respond to multiple requests for comment.
In permitting debates, conservationists and clean energy developers can often become enemies. Traditional conservationists seek to slow down the permitting process as much as possible and move a project away from a treasured or sensitive area, while developers and climate hawks want to build clean energy infrastructure quickly and efficiently.
These fights often play out as costly lawsuits over the National Environmental Policy Act, a 1970 law that requires the government to study the environmental impact of every decision that it makes. Advocates and opponents wind up battling in court over whether or not a project’s environmental impact has been sufficiently studied.
That’s not what happened with SunZia. Some environmentalists and traditional conservation groups, such as the Audubon Society, now praise SunZia’s process.
It wasn’t always that way. During the early 2010s, SunZia’s proposal to cross the Rio Grande in New Mexico was just as controversial as its San Pedro Valley route. The project’s developer wanted to build power lines near a site where tens of thousands of migratory birds, including sandhill cranes, spend the winter.
That changed after the Defense Department forced a major rethink of the line in 2018. Soon after that, Pattern Energy, a San Francisco-based energy developer, took over the project.
Pattern took a different approach than its predecessor and partnered with environmental groups to learn how it could build the power line in the least intrusive way.
It conducted original research on how sandhill cranes fly, and — based on that research — moved the power line to the place where it would interfere with birds the least. It also purchased and donated an old farm property and the accompanying water rights so a wildlife refuge could rebuild habitat for the birds.
Pattern also agreed to illuminate the transmission line with an experimental infrared system to make it more visible to birds.
These changes, which also allowed Pattern to avoid a Defense Department site, were so extensive that it had to apply for a new federal permit.
“Pattern being a company that was willing to have discussions with us in good faith — and that conversation happening before the re-permitting process — was, I think, really important,” Jon Hayes, a wildlife biologist and the executive director of Audubon Southwest, told me.
This collaborative relationship was possible in part because it was facilitated by Senator Martin Heinrich, a Democrat who represents New Mexico.
Heinrich, a climate hawk and the son of a utility worker, had long championed the SunZia project. So when the project ran into obstacles, he pushed the developer, environmentalists, and the Pentagon to negotiate over a better solution. His office remained deeply involved in the process throughout the 2010s, ultimately helping to broker an agreement over the Rio Grande that all parties supported.
“I firmly believe that when we work together, we can build big things in this country,” Heinrich told me in a statement.
Silver, the Center for Biological Diversity leader, told me that Heinrich’s involvement is the principal reason why SunZia has been praised in New Mexico but criticized in Arizona.
The Grand Canyon State doesn’t have elected officials who were willing to get involved in SunZia and push for a mutually beneficial solution, he said. (For much of the 2010s, Republicans held both of the state’s Senate seats.)
But a project’s ultimate success cannot rest on the quality or curiosity of its senators. Martin Heinrich, as a climate solution, doesn’t scale, and not every clean energy project will have a federal chaperone.
What’s more, America’s existing permitting system — which is channeled through its adversarial legal system — practically discourages cooperation. It pushes developers and their opponents to pursue aggressive and expensive legal campaigns against each other. These campaigns burn huge amounts of time and millions of dollars in legal fees — money that could be spent on decarbonizing the economy.
In order to meet America’s climate goals, developers must build dozens of projects like SunZia, all around the country, in the years to come. That will not happen under today’s permitting system. The country needs something better.
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Rob and Jesse quiz Mark Rothleder, chief operations officer at the California Independent System Operator.
So far on Shift Key Summer School we’ve covered how electricity gets made and how it gets sold. But none of that matters without the grid, which is how that electricity gets to you, the consumer. Who actually keeps the grid running? And what decisions did they make an hour ago, a day ago, a week ago, five years ago to make sure that it would still be running right this second?
This week on Shift Key, Rob and Jesse chat with Mark Rothleder, senior vice president and chief operating officer of the California Independent System Operator, which manages about 80% of the state’s electricity flow. As the longest-serving employee at CAISO , he’s full of institutional knowledge. How does he manage the resource mix throughout the day? What happens in a blackout? And how do you pronounce CAISO in the first place?
Shift Key is hosted by Jesse Jenkins, a professor of energy systems engineering at Princeton University, and Robinson Meyer, Heatmap’s executive editor.
Subscribe to “Shift Key” and find this episode on Apple Podcasts, Spotify, Amazon, YouTube, or wherever you get your podcasts.
You can also add the show’s RSS feed to your podcast app to follow us directly.
Here is an excerpt from our conversation:
Jesse Jenkins: To make this a little bit more concrete, walk through how you’re orchestrating the generation fleet. What is the typical mix of resources that you’re calling on at different times of day, on a typical California day. Let’s start at 8:00 a.m. and, you know, move through the day.
Mark Rothleder: So if it’s like today, it’s a moderate summer day, there would be in the. There would be some thermal resources, gas resources that would already be on, probably near their minimum load, which is probably about 30%, 40% of their full operating capability. And they would be sitting there waiting for dispatch instructions as the load increased.
And I talk about the morning because people start turning lights on. This is when the load starts to increase, in that morning hour. So to balance the system as that load increases relatively quickly, you’re going to have a combination of probably solar starting to come up and produce, naturally, because the sun is coming out. You may have a little bit of wind production starting to increase because the wind’s starting to blow because the temperatures and the system are driving that wind. If that’s not enough energy, we’re dispatching probably thermal resources, probably doing some exchanges through the Western Energy Imbalance Market with the neighbors.
And then you get to about probably 9 o’clock, 10 o’clock ,and things stabilize. And then what ends up happening, at least in our system, is you start to see solar production continue to go up, but the load is not increasing. It’s kind of flattened out. We start to probably see some backing off of thermal resources that were brought up during that morning load pull. And now we’re starting to back off on those, and maybe even getting to the point where surplus energy in the middle of the day — we’re exchanging and maybe exporting some of our energy to our neighbors because we have surplus. We’re probably starting to see batteries charge up in the middle of the day because now we’ve got this cheap energy. And this is going to probably go on until about 4 o’clock, 5 o’clock in the afternoon, when the traditional peak of the day is, and this is when the highest gross load is.
And then we start to see another dynamic happen, and that is, at least in our system, the sun starts to set and then the solar production starts to decrease. What’s interesting about that is, as the solar production decreases, it happens over about a three-, four-hour period, and it’s a relatively fast ramp out of those solar resources. The load is not dropping. And in fact, if you think about —
Jenkins: It’s rising often, right?
Rothleder: It’s actually still rising because some of the load that was previously served by behind the meter rooftop solar, that load is also coming back on the system because the solar production is decreasing. So again, to rebalance the system and keep that balanced and straight, we have to start ramping up a couple things. We start to turn, maybe, what was exports around, and we start importing energy from our neighbors. We start discharging the batteries that we just charged up earlier. And to the extent we still need other energy, we probably have a combination of thermal gas resources that we’re bringing them off their minimum load, dispatching them up during the day, and probably some hydro resources that are able to be dispatched during the day.
Between 6 p.m. and 7 p.m. we hit what we call our net peak. We call it net peak because it’s the gross load minus wind and solar production. And that tends to be the most critical time when we need — since the ramp out of wind and solar, more solar, that kind of is the highest where we need other resources to be available and dispatched. And so once we get through that net peak, come around 6:30, 7 o’clock, things just start to gradually turn around. And then we’re ramping out over the rest of the day the thermal resources, the interchange, and the hydro resources that we previously dispatched up to get to that net peak. And this all starts over again the next morning.
Mentioned:
Jesse’s slides on long-run equilibrium and electricity markets
Shift Key Summer School episodes 1, 2, 3, and 4
Also on Shift Key: Spain’s Blackout and the Miracle of the Modern Power Grid
This episode of Shift Key is sponsored by …
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Music for Shift Key is by Adam Kromelow.
An agreement to privatize Minnesota Power has activists activated both for and against.
For almost as long as utilities have existed, they have attracted suspicion. They enjoy local monopolies over transmission (and, in some places, generation). They charge regulated prices for electricity and make their money through engaging in capital investments with a regulated rate of return. They don’t face competition. Consumer advocates habitually suspect utilities of padding out their investments and of maintaining excessive — if not corrupt — proximity to the regulators and politicians designated to oversee them, suspicions that have proved correct over and over again.
Environmental groups have joined this chorus, accusing utilities of slow-walking the energy transition and preferring investments in new, large gas plants and local transmission as opposed to renewables, demand response, and energy efficiency.
Add private equity to the mix and you have a recipe for the kind of controversy playing out in Minnesota over the proposed acquisition of the northern Minnesota utility Minnesota Power by Global Infrastructure Partners, an infrastructure investment firm acquired by BlackRock, and the Canada Pension Plan Investment Board, the investment manager for Canadian retirement savings.
The deal has attracted activist opposition from environmental groups like the Sierra Club, consumer watchdogs in Minnesota, as well as national policy groups critical of both utilities and private equity. It’s also happening in a moment when utility ratemaking has come under increasing scrutiny on account of rising electricity prices.
Utilities across the countries have requested $29 billion of dollars in rate increases so far this year, according to PowerLines, the electricity policy research group, while as of May, retail electricity prices were climbing at twice the rate of inflation. Utilities earn regulated rates of return on capital projects, and with data centers and artificial intelligence driving up demand for new electricity, investors are eyeing utilities as potential cash cows. The Dow Jones Utilities index has even slightly outperformed the market so far this year.
Global Infrastructure Partners announced that it had agreed to buy the northern Minnesota utility Minnesota Power’s parent company, Allete, for over $6 billion million last May, and the deal has been working its way through the utilities regulatory process ever since. In July, the Minnesota Department of Commerce reached a settlement with the company and its potential buyers that, among other provisions, agreed to a rate freeze and a reduction in the return on capital investment the new owners will be to earn.
While the companies were able to win the support of one part of the Minnesota governmental apparatus, another one harshly condemned the deal. Following the settlement announcement, administrative law judge Megan McKenzie recommended that the Minnesota Public Utilities Commission ultimately reject the deal. The judge’s recommendation is non-binding, but it is a comprehensive review of the evidence and arguments made by supporters and opponents of the deal that could have sway over the commission’s final decision.
The judge’s recommendation largely echoed the case advocates had been making against the merger. The opinion was laced with criticisms of private equity as such, arguing that the new owners would “pursue profit in excess of public markets through company control.” Ultimately, McKenzie concluded that “this transaction carries real and significant costs and risks to Minnesota ratepayers and few, if any, benefits. Accordingly, the proposed Acquisition is not in the public interest.”
The Minnesota Public Utilities Commission is expected to make a final decision in September. In the meantime, advocates on either side are continuing to press their arguments.
Citing the administrative law judge, Karlee Weinman, a research and communications manager at the Energy and Policy Institute, a frequent critic of utilities, told me that the advocate objections to the deal were twofold: One, that Minnesota Power might not be able (or willing) to finance its capital needs; and two, that as a private company, it will no longer be required to file documents with the Securities and Exchange Commission, removing a lever for ratepayer advocates.
The “layer of transparency” provided by SEC filings “is something that consumer advocates are finding valuable to help inform both their understanding of the utility and their advocacy on behalf of ratepayers,” Weinman told me. Or as a coalition of public interest groups argued more formally in a utility commission filing, “privatization of ALLETE and the discontinuation of ALLETE’s SEC reporting obligations would significantly reduce information about ALLETE that is available to the Commission and Minnesota ratepayers.”
Going private “would make it more difficult for Minnesota regulators like our commission to monitor the board’s decisions and hold the company accountable to state law, but also to the public,” Jenna Yeakle, a campaign manager at the Sierra Club and resident of Duluth, told me.
“We do not have a choice where our electricity comes from,” she said. “We are the most impacted by Minnesota Power’s choices and the decisions made at the state and federal level when it comes to our electrical utility, because we don’t get a choice in the matter.”
Unions, on the other hand, often play well with utilities, using their regulated status to ensure good jobs for their members. Construction unions especially are big fans of big capital projects, which means more construction jobs.
One of those unions is the LIUNA Minnesota & North Dakota, an affiliate of the Laborers' International Union of North America, the construction workers union. “We just want the utility to work, the utility works well for us, they use union labor, they build projects, they create jobs,” Kevin Pranis, its marketing manager, told me.
Pranis was especially skeptical of opponents’ arguments that changing the investor in an investor-owned utility would make a huge difference in terms of how it conducted itself in front of the Public Utilities Commission. “There’s this bizarre fan fiction that has developed around publicly traded stocks, that somehow they are transparent,” he said. Corporate filings rarely, if ever have the kind of information ratepayers and their advocates need in rate cases, Pranis argued.
“The Securities Exchange Commission doesn’t care about ratepayers. The New York Stock Exchange doesn’t care about ratepayers. Those regulations don’t serve ratepayers in any way. They serve investors to know what you’re investing in.”
The environmental arguments also go in the other direction. One supporter of the deal, former Loans Program Office chief Jigar Shah, wrote in Utility Dive that “to fully decarbonize its electricity sales and keep pace with rising demand, Minnesota Power must navigate an increasingly complex and capital-intensive landscape.”
“What Minnesota Power needs is long-term vision and stable capital,” he continued, which is “precisely what this private investment offers. That’s the only way to do the big things required to serve its communities, especially when federal energy rhetoric doesn’t always align with real on-the-ground needs.”
Minnesota law mandates that the state reach 100% carbon-free electricity by 2040, which supporters of the deal have said justifies allowing Minnesota Power to be owned by deep-pocketed investors.
Two clean energy groups, the Center for Energy and Environment and Clean Energy Economy Minnesota, wrote in a filing that meeting that goal would require “significant and unprecedented investment,” and that “although the exact investment levels needed may be uncertain or disputed by parties, the scope of investment needed is clear, and the Acquisition makes that level of capital available to Minnesota Power today.”
LIUNA pressed the point more forcefully in another filing, arguing that opponents of the deal “have dangerously underestimated the threat posed by a lack of ready capital to undertake historic investments,” and that they were “whistling past the graveyard.”
Minnesota Power and its proposed buyers, for their part, have argued in a that Allete requires “more than $1 billion in new equity to fund its expected investment requirements over the next five years,” including to comply with the emissions requirements, and pointed out that “in the Company’s 75-year history in publicly traded markets, the Company has raised $1.3 billion in equity.”
Judge McKenzie disagreed in her opinion, arguing that capital commitments weren’t enforceable and echoing the public interest groups in saying that Minnesota Power had told its investors that it was able to access capital markets when it needed to. The company and its investors have argued this was conditional on its ability to find a buyer, and that “further analysis to identify its approach to comply with the Carbon Free Standard” showed the investment need.
Judge McKenzie also got to the heart of recent debates around data centers and grid management, arguing that the planned investments in new generation and transmission weren’t truly necessary to meet the legally mandated emissions standard. “ALLETE could reduce capital needs by making greater use of power purchase agreements (PPAs) to reduce capital spending on self-built generation. Greater use of demand response, energy efficiency measures, and grid-enhancing technologies could also reduce the need for capital spending on generation,” she wrote.
Ultimately, how Minnesota Power conducts itself — the projects it engages in, the rates it charges consumers and industrial customers — will be up to the Minnesota Public Utilities Commission and the state legislature, whether it’s owned by public investors or infrastructure and pension funds.
“None of those changes will affect the Commission’s authority, process, or obligation to regulate Minnesota Power’s actions,” the two clean energy groups wrote in a filing. Utility regulation will continue to be a challenge, but the investors may not matter as much as the utility.
The Berkeley-based startup has a chemical refining method it hopes can integrate with other existing recycling operations.
Critical minerals are essential to the world’s most powerful clean energy technologies, from batteries and electric vehicles to power lines, wind turbines, and solar panels. But the vast majority of the U.S. mineral supply comes from countries such as China, putting supply chains for a whole host of decarbonization technologies at geopolitical and economic risk.
Recycling minerals domestically would go a long way toward solving this problem, which is exactly what ChemFinity, a new startup spun out of the University of California, Berkeley, is trying to do. The company claims its critical mineral recovery system will be three times cheaper, 99% cleaner, and 10 times faster than existing approaches found in the mining and recycling industries. And it just got its first big boost of investor confidence, raising a $7 million seed round led by the climate tech firms At One Ventures and Overture Ventures.
“We basically act like a black box where recyclers or scrap yards or even other refiners can send their feedstock to us,” Adam Uliana, ChemFinity’s co-founder and CEO, told me. “We act like a black box that spits out pure metal.”
It works like this: After a customer sends ChemFinity its feedstock — anything from a circuit board to a catalytic converter to recently mined metal ore will do — the material goes into a chemical solution that dissolves the metals to be recovered, separating them from the solid feedstock. That liquid is then pumped through ChemFinity’s sorbent filters, which capture target minerals “like metal-selective Brita filters.”
The core breakthrough is a new polymer used in these filters that Uliana and his co-founder designed while PhD students in Chemical Engineering at Berkeley. The novel material is made of innumerable mineral-trapping pores smaller than the width of a hair, making it “so porous that 1 gram of the material — like a spoonful of the material — can have the same surface area internally as that of a football field,” Uliana told me. This allows the filters to capture an astonishing amount of metal using very little polymer.
Crucially, the pores are customized for each specific mineral. “You can tune the size of these pores, the shapes of these pores, the chemistries of these pores, and it basically acts like a cage, or like an atomic catcher’s mitt, just for that individual metal,” Uliana explained. After that atomic mitt traps the minerals, a proprietary liquid solution flows through the mineral-filled polymer, stripping off the minerals so that they can be recovered. The company can then reuse the porous sorbent without performance loss.
Uliana told me this method is orders of magnitude more efficient than what exists on the market today — even when compared to the most successful and innovative startups in the space such as Redwood Materials, which recycles lithium-ion battery minerals. That’s because refining typically requires more than a dozen steps and extremely high temperatures, as systems remove impurities one by one, gradually concentrating a mineral until it’s pure enough for commercial viability.
ChemFinity’s process, on the other hand, operates at room temperature. And because its filter is so selective, there are far fewer steps overall. “If we’re able to successfully scale this, it’s really unprecedented unit economics,” Uliana said. He sees potential for other companies like Redwood to adopt the startup’s refining technology as part of a larger operation.
But that’s a ways down the road. ChemFinity isn’t prioritizing battery recycling to begin with, instead focusing on recovering and refining precious metals such as gold, silver, and platinum. These minerals are all over the e-waste from consumer electronics —- things like circuit boards, connectors, memory chips, capacitors, and switches all contain precious metals.
They’re a good group of minerals to go to market with, Uliana explained, both because they’re expensive and difficult to purify. “These metals have extremely high value. So you don’t necessarily need to be quite as large-scale as if you were recovering copper from a copper tailing,” he told me. The flip side, though, is “that these are some of the hardest minerals to separate.” So if ChemFinity proves capable of refining these at scale, it will be a pivotal proof point as the startup looks to apply its process to more than 20 critical minerals across the periodic table.
With this first influx of funding, the company is looking to scale production of its novel sorbent material from a few kilograms to about 100 kilograms per day as it sets up initial pilots. And while ChemFinity’s first customers could range from manufacturers of clean tech to metal traders and jewelers, the company says its materials breakthrough could have applications in an even wider array of sectors, from wastewater treatment to carbon capture and petrochemical processing.
Because if ChemFinity has, as Uliana told me, truly created the “that perfect cage, just for one mineral at a time,” there really is a world of opportunity out there.