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Building new capacity isn’t always as straightforward as it sounds.
When you think of companies whose valuations are soaring due to artificial intelligence, the ones that come to mind first are probably the chip designer Nvidia, whose shares are up 180% this year, or Elon Musk’s xAI, which its investors recently valued at $50 billion.
But aside from those, some of the best performing companies of this year have been those that own or supply equipment for the power plants that generate the energy to run all that AI infrastructure in the first place.
GE Vernova’s gas turbine orders have almost doubled so far this year, chief executive Scott Strazik said in an October earnings call; since then, the company has secured orders for another nearly 9 gigawatts’ worth of turbines in the U.S., the company said in an investor presentation Tuesday. “I can’t think of a time that the gas business has had more fun than they’re having right now,” Strazik told investors. The company’s stock is up almost 150% from the end of 2023.
Vistra, which owns over 40,000 megawatts of generation assets, including around 6,500 megawatts of nuclear power plants and more than two dozen gas-fired power plants, is planning on developing 2,000 megawatts of natural gas capacity, its chief executive Jim Burke said in November; its share price is up 272% for the year. The utility Entergy, which last week signed a deal with Meta to power a planned data center in northeastern Louisiana, is up 45%. Compare those impressive results to the S&P 500, which is up a healthy but comparatively modest 27% on the year.
Much of that enthusiasm comes from huge expected increases in energy demand. Grid Strategies, an energy policy consulting firm, last week updated its forecast for energy demand growth over the next five years, raising it from an increase of 39 gigawatts as of the end of 2023 to a rise of 128 gigawatts. That works out to annual projected growth of around 3%, compared to less than 1% annual growth in the first two decades of this century.
Where will all that additional energy come from? “Quite frankly, in the next five years, we’re going to see a lot of new gas turbines being built,” Cy McGeady, a fellow at the Center for Strategic and International Studies, told me, adding that the “prospects are good for a natural gas boom.”
The data centers that are driving renewable demand tend to require a constant flow of energy at all times — except when their power demands surge — while renewables are intermittent and may be far away from planned load growth. While so-called hyperscalers such as Amazon, Meta, and Google have made deals to support the development of 24/7 clean power sources like nuclear, the most optimistic time frame for any of these new developments to start producing power is sometime in the early 2030s.
Rob Gramlich, the president of Grid Strategies, told me the technology companies generating all this demand growth typically want it satisfied with renewables, but “they really need transmission in order to do that.”
“If everyone had done this 10 years ago, we could have connected a lot of generation a lot quicker. It could have been a lot cleaner generation mix,” Gramlich told me. Now, though, even if a utility wants to build solar, wind, and storage that can provide power at costs comparable to new gas, “it’s only available as an option if you build the grid infrastructure ahead of time,” he said.
McGeady agrees. “It’s the only path forward,” he said of natural gas. “Nobody is willing to not build the next data center because of inability to access renewables.”
But therein lies the difficulty: While natural gas plants are not as transmission-dependent as renewables, some analysts worry that even gas generators won’t be able to respond quickly enough to the increase in demand.
“When we look at the hot spots of Data Center development, in the U.S. and around the world, we see a significant overlap with regions that have favorable policy support for natural gas,” Morgan Stanley analysts wrote in a note to clients. And yet, “there will in our view be a significant shortfall in available U.S. power grid access relative to the magnitude of new data centers needed to ‘absorb’ the AI equipment purchases over the next several years, with the bottleneck becoming apparent in mid-to-late 2025,” the analysts wrote.
The utilities in these areas — places like Georgia, Arizona, and North Carolina — are indeed building new natural gas capacity. In other places where the laws and regulations aren’t as favorable to gas development, however, analysts expect to see more data centers sited at existing power plants. Some of those may be powered by fossil fuels, as in the case of a New Jersey facility recently taken over by the cloud computing company Core Weave, while others may wind up taking zero-carbon power off the grid, as Amazon attempted to do with the Susquehanna nuclear station in Pennsylvania.
Building new natural gas capacity is more difficult in the PJM Interconnection, the country’s largest electricity market, which spans the Eastern Seaboard and a large chunk of the Midwest. Its leadership is hoping high prices can lure new gas generation, but the complexity and uncertainty of the system’s reward structure for companies that agree to supply failsafe capacity has hindered the massive new investment PJM says it needs.
Some clean energy advocates argue that utilities are being short-sighted in their plans to develop new gas resources that could be around for decades — well past corporate, state, or national goals for electric system decarbonization.
“They’re used to building gas plants more so than they’re used to building other things. It reflects a lack of creativity on their part,” Michelle Solomon, a senior policy analyst at Energy Innovation, told me.
But until the system for building and paying for transmission can be reformed to clarify who pays for what and what transmission can be built where — as federal regulators and Congress are trying to do — utilities will likely default to what they know best.
“The difficulty of building transmission certainly can constrain utilities’ ability to serve new load, and it can constrain the ability to serve the load with clean generation,” Gramlich told me.
Chris Seiple, Wood Mackenzie’s vice president of energy transition and power and renewables, echoed Gramlich’s thought in a note from October. “The constraint is not the demand for renewables,” he wrote, “but the ability to get through permitting, interconnection, and building out the transmission system accordingly.”
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A conversation with Scott Cockerham of Latham and Watkins.
This week’s conversation is with Scott Cockerham, a partner with the law firm Latham and Watkins whose expertise I sought to help me best understand the Treasury Department’s recent guidance on the federal solar and wind tax credits. We focused on something you’ve probably been thinking about a lot: how to qualify for the “start construction” part of the new tax regime, which is the primary hurdle for anyone still in the thicket of a fight with local opposition.
The following is our chat lightly edited for clarity. Enjoy.
So can you explain what we’re looking at here with the guidance and its approach to what it considers the beginning of construction?
One of the reasons for the guidance was a distinction in the final version of the bill that treated wind and solar differently for purposes of tax credit phase-outs. They landed on those types of assets being placed in service by the end of 2027, or construction having to begin within 12 months of enactment – by July 4th, 2026. But as part of the final package, the Trump administration promised the House Freedom Caucus members they would tighten up what it means to ‘start construction’ for solar and wind assets in particular.
In terms of changes, probably the biggest difference is that for projects over 1.5 megawatts of output, you can no longer use a “5% safe harbor” to qualify projects. The 5% safe harbor was a construct in prior start of construction guidance saying you could begin construction by incurring 5% of your project cost. That will no longer be available for larger projects. Residential projects and other smaller solar projects will still have that available to them. But that is probably the biggest change.
The other avenue to start construction is called the “physical work test,” which requires the commencement of physical work of a significant nature. The work can either be performed on-site or it can be performed off-site by a vendor. The new guidance largely parrotted those rules from prior guidance and in many cases transferred the concepts word-for-word. So on the physical work side, not much changed.
Significantly, there’s another aspect of these rules that say you have to continue work once you start. It’s like asking if you really ran a race if you didn’t keep going to the finish line. Helpfully, the new guidance retains an old rule saying that you’re assumed to have worked continuously if you place in service within four calendar years after the year work began. So if you begin in 2025 you have until the end of 2029 to place in service without having to prove continuous work. There had been rumors about that four-year window being shortened, so the fact that it was retained is very helpful to project pipelines.
The other major point I’d highlight is that the effective date of the new guidance is September 2. There’s still a limited window between now and then to continue to access the old rules. This also provides greater certainty for developers who attempted to start construction under the old rules after July 4, 2025. They can be confident that what they did still works assuming it was consistent with the prior guidance.
On the construction start – what kinds of projects would’ve maybe opted to use the 5% cost metric before?
Generally speaking it has mostly been distributed generation and residential solar projects. On the utility scale side it had recently tended to be projects buying domestic modules where there might have been an angle to access the domestic content tax credit bonus as well.
For larger projects, the 5% test can be quite expensive. If you’re a 200-megawatt project, 5% of your project is not nothing – that actually can be quite high. I would say probably the majority of utility scale projects in recent years had relied on the manufacturing of transformers as the primary strategy.
So now that option is not available to utility scale projects anymore?
The domestic content bonus is still available, but prior to September 2 you can procure modules for a large project and potentially both begin construction and qualify for the domestic content bonus at the same time. Beginning September 2 the module procurement wouldn’t help that same project begin construction.
Okay, so help me understand what kinds of work will developers need to do in order to pass the physical work test here?
A lot of it is market-driven by preferences from tax equity investors and tax credit buyers and their tax counsel. Over the last 8 years or so transformer manufacturing has become quite popular. I expect that to continue to be an avenue people will pursue. Another avenue we see quite often is on-site physical work, so for a wind project for example that can involve digging foundations for your wind turbines, covering them with concrete slabs, and doing work for something called string roads – roads that go between your turbines primarily for operations and maintenance. On the solar side, it would be similar kinds of on-site work: foundation work, road work, driving piles, putting things up at the site.
One of the things that is more difficult about the physical work test as opposed to the 5% test is that it is subjective. I always tell people that more work is always better. In the first instance it’s likely up to whatever your financing party thinks is enough and that’s going to be a project-specific determination, typically.
Okay, and how much will permitting be a factor in passing the physical work test?
It depends. It can certainly affect on-site work if you don’t have access to the site yet. That is obviously problematic.
But it wouldn’t prevent you from doing an off-site physical work strategy. That would involve procuring a non-inventory item like a transformer for the project. So there are still different things you can do depending on the facts.
What’s your ultimate takeaway on the Treasury guidance overall?
It certainly makes beginning construction on wind and solar more difficult, but I think the overall reaction that I and others in the market have mostly had is that the guidance came out much better than people feared. There were a lot of rumors going around about things that could have been really problematic, but for the most part, other than the 5% test option going away, the sense is that not a whole lot changed. This is a positive result on the development side.
And more of the week’s most important news around renewable energy conflicts.
1. Carroll County, Arkansas – The head of an influential national right-wing advocacy group is now targeting a wind project in Arkansas, seeking federal intervention to block something that looked like it would be built.
2. Suffolk County, New York – EPA Administrator Lee Zeldin this week endorsed efforts by activists on Long Island to oppose energy storage in their neighborhoods.
3. Multiple counties, Indiana – This has been a very bad week for renewables in the Sooner state.
4. Brunswick County, North Carolina – Duke Energy is pouring cold water on anyone still interested in developing offshore wind off the coast of North Carolina.
5. Bell County, Texas – We have a solar transmission stand-off brewing in Texas, of all places.
Is there going to be a flight out of Nevada?
Donald Trump’s renewables permitting freeze is prompting solar companies to find an escape hatch from Nevada.
As I previously reported, the Interior Department has all but halted new approvals for solar and wind projects on federal lands. It was entirely unclear how that would affect transmission out west, including in the solar-friendly Nevada desert where major lines were in progress to help power both communities and a growing number of data centers. Shortly after the pause, I took notice of the fact that regulators quietly delayed the timetable by at least two weeks for a key line – the northern portion of NV Energy’s Greenlink project – that had been expected to connect to a litany of solar facilities. Interior told me it still planned to complete the project in September, but it also confirmed that projects specifically necessary for connecting solar onto the grid would face “enhanced” reviews.
Well, we have the latest update in this saga. It turns out NV Energy has actually been beseeching the Federal Energy Regulatory Commission to let solar projects previously planned for Greenlink bail from the interconnection queue without penalty. And the solar industry is now backing them up.
In a July 28 filing submitted after Interior began politically reviewing all renewables projects, NV Energy requested FERC provide a short-term penalty waiver to companies who may elect to leave the interconnection queue because their projects are no longer viable. Typically, companies are subject to financial penalties for withdrawals from the queue, a policy intended to keep developers from hogging a place in line with a risky project they might never build. Now, at least in the eyes of this key power company, it seems Trump’s pause has made that the case for far too many projects.
“It is important that non-viable projects be terminated or withdrawn so that the queue and any required restudies be updated as quickly as possible,” stated the filing, which was first reported by Utility Dive earlier this week. NV Energy also believes there is concern customers may seek to have their deals for power expected from these projects terminated under “force majeure" clauses, and so “the purpose of this waiver request is thus to both clear the queue to the extent possible and avoid unneeded disputes.”
On Monday, the Solar Energy Industries Association endorsed the request in a filing to the commission made in partnership with regional renewable trade group Interwest Energy Alliance. The support statement referenced both the recent de facto repeal of IRA credits as well as the permitting freeze, stating it now “appears that federal agency review staff are unsure how to proceed on solar projects.” This even includes projects on private lands, a concern first raised by Nevada Gov. Joe Lombardo, a Republican, after the permitting freeze came into effect.
The groups all but stated they anticipate companies will pull the plug on solar projects in Nevada, proclaiming that by granting the waiver, “it will encourage projects facing uncertainty due to recent legislation and federal action to exit the process sooner and without penalty, creating more certainty for the remaining projects.”
How this reads to me: Energy developers are understandably trying to figure out how to skate away from this increasingly risky situation as cleanly as they can. It’s anybody’s guess if FERC is willing to show lenience toward these developers.