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Its electric grid is very dirty.
It’s very hot in Arizona, but no one in charge seems to be very worried about the electricity.
The region’s major utilities — Arizona Public Service, Tucson Electric Company, and the Salt River Project — have all said they’re confident that the lights, and especially the air conditioning, will stay on, even as both temperatures and electricity usage break records. This is in stark contrast to a nearby state, Texas, where record heat has sparked anxiety about reliability and voluntary calls for conserving energy use.
Whether Arizona can transition to a less carbon-intensive grid while maintaining its famed reliability is a test not just for its residents, but also for Arizona’s stubborn rejection of energy deregulation. The state is blessed with abundant renewables potential (it's very, very sunny) and a massive carbon-free source of firm power in the country’s largest nuclear plant, the Palo Verde Generating Station. But it also has a market structure for electricity that typically sees lower renewable production.
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Reliability is quite literally a matter of life and death in Arizona. One paper estimated that the combination of a prolonged blackout (no power for five days) and a heat wave where temperatures were between 90 and 113 degrees (actually slightly cooler than recent temperatures) could result in about 13,000 deaths and more than half of the population needing to go to the emergency room. While this scenario was admittedly extreme, we do have a grim reminder of how dangerous high temperatures can be in Arizona: When people die of heat exposure, they’re often homeless.
Arizona's grid has held up well under this heat wave, though. According to Arizona Public Service, their customers set a record for consumer demand for electricity on Saturday with 8,191 megawatts. The previous record had only been in place for one day; it had been set on Friday. The utility, a subsidiary of Pinnacle West, has over one million customers and services much of the state, splitting the Phoenix area with the cooperative Salt River Project. A spokesperson for Arizona Public Service told me “we continue to have adequate supply and our system is stable," while a Salt River Project spokesperson said that its electricity demand set a record on Monday evening with 7,997 megawatts, after setting records last Friday and Saturday.
Yet Arizona does have one problem with its electricity grid: It's pretty dirty and thus contributing to the reason all those air conditioners need to work so hard. Natural gas remains the state’s biggest source of energy, representing just over 42 percent of its generation last year, and coal still outproduces solar, according to Energy Information Administration data. One bright spot in the grid is nuclear power, which produces just under 30 percent of the state's energy.
The reliability of Arizona’s grid might have less to do with the makeup of its energy grid, though, and more to do with the fact that the state has resisted deregulation, meaning that Arizonans are served by utilities which own or contract electricity generation and are overseen by a state body, the Arizona Corporation Commission. This means planning is a cooperative process between the state and the utilities, as opposed to one governed by a wholesale market for electricity.
Critics of deregulation have argued that market constructs for electricity lead to underinvestment in reliability (like winterization for natural gas, albeit not a huge concern in Arizona) and premature retirement of energy resources, like dispatchable power plants, that can be expensive to run. They’ve also been criticized for not bringing down prices in the way they were promised. While Arizona does have more expensive electricity than Texas, according to the Energy Information Administration, it’s substantially cheaper than California, New York, or New England.
Arizona has been assailed by both environmental groups and activists, who accuse the utilities of dragging their feet or outright obstructing renewables, especially solar, as well as by generation companies (especially those with solar subsidiaries) who wish to compete in a more deregulated market where customers can choose where their electric generation comes from.
Arizona’s major utilities have all committed to decarbonization timelines, ranging from aspirational goals of total decarbonization by 2050 to more detailed targets by 2035, even though state rules mandating decarbonization were shot down in 2022.
That will likely mean more development of solar — despite being very sunny, Arizona’s solar production lags North Carolina, according to the Solar Energy Industries Association — along with battery storage and the continued operation of the Palo Verde Generating Station, the utility-owned 4,000 megawatt nuclear power plant that serves customers in Arizona and three neighboring states, including California and Texas.
If Arizona adds large amounts of solar to the grid, which it's starting to do, it will need to deal with the famous duck curve, the phenomenon where the sun goes down and solar production plummets, but electricity demand stays stubbornly high as air conditioning and appliances are still in use. On Monday, demand peaked in the early evening and, in Phoenix, temperatures hovered at right around 100 degrees at 9 p.m. Arizona's utilities are aware of this issue; along with increased solar installation and investment, there has been increased deployment of battery storage, which can bank the sun’s energy for nighttime use.
Meanwhile Arizona’s combination of high reliability and avoiding deregulation has become something of a point of pride in the state, where some leaders and advocates see it charting a course between the Scylla of Texas and the Charybdis of California, its two wealthy and gargantuan neighbors. When the Wall Street Journal ran a long story entitled “America’s Power Grid Is Increasingly Unreliable” (it featured, of course, California and Texas), Arizona Public Service issued a statement from its chief executive entitled, “’Unreliable grid?’ Not here in Arizona.”
Keeping it that way is a matter of life and death.
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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.