Boone Staples, director of transmission analysis for the engineering and construction group at energy developer Tenaska, has been doing essentially the same job for the last 15 years. And in spite of his tenure, he says he can’t remember a single solar project that hasn’t run into interconnection delays.
“We have projects in the [Midcontinent Independent System Operator] queue that have been there for four and a half years now. In [the Southwest Power Pool]...we’re looking at eight years start to finish on a project. In PJM we have projects that have been there since March 2019 – these projects were shovel ready. They have offtake contracts completed with full permits ready to start construction, just waiting on PJM,” Staples recounts. “Those have been put on pause. With queue reform it looks like they will get kicked out to late 2025, so that’s pretty severe for us.”
Tenaska, Staples says, is ready and willing to participate in interconnection studies and pay for transmission upgrades. And yet the ever-growing queue times, he says, continue to cost the company projects. Power purchase agreement negotiations have fallen apart, and options on land have even expired, as projects wind their way through the lengthy interconnection process – difficulties that can trigger the cancellation of an entire project.
Data from the Lawrence Berkeley National Laboratory show that interconnection queue times have increased dramatically since 2005, when a typical solar project could be built, start to finish, in two years. Today, the average developer can expect to need four years or more to complete a project, according to Joseph Rand, a senior scientific engineering associate tracking interconnection queues at the Lawrence Berkeley Lab.
But it’s not just that navigating the queue takes longer today than in the past decade, Rand says. Projects are also significantly less likely to succeed. Less than a quarter of the projects that enter interconnection queues around the U.S. will make it through to completion. Between the delays and the need for developers to hedge their bets, the U.S. currently has roughly 700 GW of solar, 400 GW of energy storage, and more than 200 GW of wind energy sitting in overflowing interconnection backlogs – just gigawatts shy of what the Biden administration projects is needed to generate 95% carbon-free energy by 2035.
“Our backlogs are indicating that our wind and solar developers are eager to meet that demand,” Rand says, “but that our transmission and interconnection system and procedures are not keeping pace with meeting that demand.”
So how did we get here? After decades of dominating the energy and technology scenes, the U.S., it seems, got complacent. Instead of upgrading the grid and related bureaucratic systems, industry, regulatory and government leaders took a business as usual posture that assumed the nation’s traditional ad hoc, bottom-up approach to energy development would work for renewables, too.
And it did – partially. But the bottlenecks this process creates, experts say, now threatens the nation’s ability to transition to clean energy with the same speed seen in countries with more cohesive regulatory systems.
Legacy transmission
One of the fundamental problems contributing to interconnection backlogs around the nation, Rand says, is the lack of transmission. If you could somehow set all the other issues aside – the rapid pace of the energy transition, the inefficient regulatory system, the labor shortages – the U.S. still wouldn’t have enough transmission to connect all the incoming renewable energy to the grid.
Yet it’s not as though the U.S. just stopped building transmission. According to the latest numbers from JPMorgan Chase, U.S. transmission has continued to grow at a steady – albeit slow – pace of roughly 2% per year.
The problem, according to Liza Reed, electric transmission research manager at the Niskanen Center think tank, isn’t so much a lack of transmission in general, but a lack of specific kinds of transmission needed to facilitate renewable energy generation. Renewable generation, she says, requires long-distance, high-capacity transmission. And to understand why the U.S. hasn’t built that, you have to go way back in the history of the electric grid – long before the energy transition glimmered on the horizon.
Because the U.S. was an early adopter of electricity – and therefore of transmission technology – there was no central plan or vision for a national electric grid when the first lines went up. Instead, Reed says, transmission became a local issue, with utilities and grids and interconnections all scaling from the ground up as the system grew.
“The system built out very slowly, but quite expansively. There is electricity all over the United States now,” Reed says. “And it’s largely been a victim of a successful engineering system that works until it doesn’t.”
Even though the scale of the grid grew, regulation of the grid remained – and remains to this day – a primarily local concern. Sure, the Federal Energy Regulatory Commission has some limited authority over transmission, but permitting is still managed at the state level, where each state sets its own rules and priorities.
“I’d describe transmission as a federalism mismatch – the law has not kept up with the regional and national impact that the grid has,” Reed says. “The necessity of sharing power, planning together and having an established set of criteria – none of that has been federalized or standardized, even as the impact of our power systems are seen on a broader scale.”
Now that this system is in place, it’s difficult to go back in and assign oversight of transmission to a federal authority, because the states interpret that as an attempt to seize their authority, Reed says. And to complicate matters, states have generally tasked their public utility commissions with regulating for the least-cost option within a relatively short planning period, such as 10 years.
“Even though transmission is a small percentage of the cost of electricity and the transition toward electrification ... it is visually the biggest, so it becomes an avatar for ‘what are we paying for,’” Reed says. “You need a single transmission line for a lot of other projects, but that transmission line has a dollar sign next to it and it’s large.”
That means, Reed says, that it’s much easier for a PUC to approve a new gas plant, which can be constructed near existing transmission, than to approve the construction of a high-capacity transmission line that will unlock a swatch of wind or solar projects, which much be located where the natural resources exist.
Bhaskar Ray, vice president of interconnection and development engineering for energy developer Qcells USA Corp., has observed that this dynamic can manifest in ways that resemble the NIMBY – or "not in my back yard" – phenomenon. But the reality, he says, is much more complicated, with each state looking out for its own interests.
“Whenever you try to build a new line between states, the states start playing politics and saying why should we build a line through Arizona when California gets all the benefits, and vice versa,” Ray says. “That kind of game has got to stop.”
Systemic delays
The energy transition began with this groundwork for delays already in place. At first, only a couple renewable projects came online at any given time, so utilities and regional transmission organizations had no trouble keeping pace, recalls Dave Gahl, executive director of the Solar and Storage Industries Institute. But then a handful of projects turned into hundreds, and the influx caught many entities flat-footed, Gahl says.
It wasn’t just that the needed transmission didn’t exist, Gahl says – many transmission authorities failed to allocate an appropriate number of staff to the interconnection process, and existing processes and procedures were woefully inadequate to the task of processing hundreds of requests all at once.
Take the interconnection process itself for example. Regional transmission organizations, generally, do not share enough information publicly for a developer to easily identify the best, most cost effective locations to connect to the grid, Gahl says. So developers have to apply for interconnection with incomplete information – and may learn during the study process that a project will be financially or technically infeasible.
This process has also forced developers, in some cases, to apply for interconnection as a sort of exploratory exercise to identify the best locations to connect to the grid, and therefore to construct projects. But these exploratory efforts take time and resources to study just like any other project – and add to the overwhelming surge of projects waiting for attention from an RTO or utility.
“You want to build the project, but you don’t know where to put it and the only way to get the information is to put in an application,” Gahl says. “Seems to me there is a better process.”
The queue system further exacerbates this dynamic, Staples says, by assigning projects priority status according to when they enter the queue on a first-come, first serve basis. As queue lengths began to expand with growing numbers of projects seeking information on the grid, developers began to submit their interconnection requests earlier and earlier in the development process in an effort to essentially hold their place in line, Staples says. This meant projects began to enter the queue before offtakers or property rights had been secured in some cases – further holding up the process, which in many regions still does not allow a project to jump ahead if the applications ahead of it aren’t prepared to begin the study process.
These early-stage projects, which some have complained are essentially speculative, have drawn numerous complaints and triggered some RTOs to take steps that make it harder to enter and remain in the queue – to the frustration of renewable energy developers.
“Maybe there are some people who carpet bomb the queues with speculative projects, but I think in general they appear to be speculative because people know it’s going to take five years to get through the process, so you have to do that early on,” Staples says. “It would be unwise to fully develop your site prior to entering a queue that you have no certainty on getting through, especially because so many things can change in five years. In a sense, every project is speculative until it can get through the queue process.”
Efforts by some independent system operators to create “clusters” of projects for simultaneous studies have helped make it easier to get through the queue, Staples says. But the clusters have come with their own unique challenges. The large number of projects initially assigned to each cluster means the first series of studies completed tend not to be particularly meaningful or useful, he says. As more projects drop out and the cluster group becomes smaller, the studies become increasingly specific – but after a certain point, each time a project drops out of the cluster, it triggers the need to revisit and revise completed studies. Cost estimates derived from what are supposed to be late-stage studies can still prove highly volatile.
“It’s still taking five years,” Staples says, “but I don’t see how MISO for example would process that many hundreds of requests in a serial fashion, so it seems essential to have a cluster process.”
Emerging solutions
As complicated as untangling the queue backlog may sound, there is some good news, according to Rob Gramlich, president of Grid Strategies and co-founder of both Americans for a Clean Energy Grid and the WATT Coalition: fixing the interconnection process is currently among FERC’s top priorities.
At the top of the to-do list, Gramlich says, is sorting out a regional transmission planning process so that in the future transmission is built where it’s needed, and not just where it’s the cheapest or easiest. FERC issued a proposed rule on the subject in April.
Also near the top of the list of needs, he says, is restructuring the interconnection process itself.
“The RTOs are faced with massive lists of generators in the queue, and a dysfunctional process where if one project drops out then others need to be restudied,” Gramlich says. “So the amount of restudy and churn in the queue with projects coming in and out is really unmanageable right now.”
The solution to the problem is two-fold, Gramlich says. Transmission managers must make more information publicly available about their systems so that developers don’t need to apply for interconnection just to determine whether a project is viable. Then, RTOs and generators must be bound by reciprocal expectations that make it harder to miss study deadlines and to drop out of the queue without penalty.
FERC initiated a second round of transmission rulemaking in June that takes aim at these issues. The interconnection reform package FERC envisions includes implementing a first-ready, first-served model, penalties for transmission planners who miss study deadlines, and calls for the adoption of new technologies that would speed the interconnection process.
That last piece, Gramlich says, is an oft-forgotten, but important potential solution to interconnection gridlock. Energy storage, for example, could function as a transmission asset, allowing grid operators more flexibility in how they connect renewables to the grid. Other technologies such as power flow control and optimization software could further enhance RTOs’ ability to accommodate more renewable energy on the grid without extensive transmission upgrades.
“Unfortunately it’s going to take some time,” Gramlich says. “There’s not a magic wand here to eliminate the problem immediately. We’re going to have to build our way out of it, and work our way through the queues, sorting the projects and meeting the timelines – and that takes time.”
So in the meanwhile, some developers have considered taking things into their own hands. Qcells, according to Ray, has begun doing internal studies to locate the project sites with the best transmission resources and shortest interconnection queues.
“That is a strategy we are doing and seeing some degree of success, where we are sailing to the finish line,” Ray says. “But not all developers have the in-house technical capabilities to accomplish that amount of study to understand where we have to go.”
Qcells has also entertained the prospect of entering the transmission business itself by building the transmission projects it needs to complete its generation projects, and then selling that transmission capacity to other developers.
“Developers like NextEra have already gotten into building merchant transmission, and third-party transmission is very much welcomed,” Ray says. “If there are FERC incentives to get into the transmission construction business, we’ll consider it.”
Even with industry and regulators working toward solutions, Rand still believes it could take several years to work through interconnection and transmission backlogs and get the energy transition in full swing. But there’s still reason for optimism, he says.
“Can we hit 100% clean energy by 2035? I get less and less optimistic every year and that’s sad,” he says. “But I will say that – this is a back of the envelope calculation – but we estimated that if all the capacity currently in queue today, wind, solar and storage, if we built that by 2030, we would hit 80% clean electricity share. And that’s factoring for load growth... The transition is right at our fingertips, but to realize it we need to reform our interconnection and transmission processes.”
