The Texan grid operator, ERCOT, has come under the spotlight for its efficient processes for connecting new solar, storage and other renewable energy projects. Grid reform expert Tyler Norris talks to Ben Willis about whether the rest of the US can follow ERCOT’s example in the quest to ease growing bottlenecks.
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Against the backdrop of growing interconnection bottlenecks in the US, Texas’s grid operator ERCOT is bucking the trend. While new solar, wind and storage projects in the US can typically expect to wait three-plus years for a grid interconnection, under the ERCOT system, average interconnection times are less than two.
As a result, between 2021 and 2023, ERCOT connected at least twice as much new capacity than the PJM system area, the largest in the US.
ERCOT operates what’s known as a ‘connect and manage’ system for new interconnections, requiring only minimal up-front consideration of a project’s impact on the transmission network. Any grid bottlenecks caused by a new generator are dealt with post-interconnection through curtailment and redispatch measures.
Outside the ERCOT area, the prevailing approach is so-called ‘invest and connect’, under which a proposed generator is studied for its ability to deliver to the grid under various stressed conditions. This allows it to be designated as a capacity resource and thus eligible for capacity compensation but involves a lengthy up-front study process that often results in costly grid upgrades before the interconnection can be secured.
This is a somewhat simplified characterisation of a complex and nuanced picture but, in a nutshell, explains why ERCOT is stealing a march on the rest of the US in expediting generator interconnections.
Unsurprisingly, it’s also why the ERCOT process has found itself at the centre of debate about ongoing interconnection reform in the US, with many asking whether its lighter-touch study process could be the key to unlocking the issue that is now the number one reason cited by developers in the US for solar projects being abandoned.
Someone who has considered the question of interconnection reform perhaps more than most is Tyler Norris. As a former executive at the US-based renewables developer Cypress Creek, Norris was exposed to the frustrations of the grid interconnection process through his work developing solar projects in the US southeast.
His experiences grappling with the grid operator Duke Energy over its decision to freeze a large pipeline of solar projects due to bottleneck issues led Norris to take a professional interest in interconnection reform and, eventually, a PhD on the subject at Duke University’s Nicholas School of the Environment, which he is now working towards.
He has written a number of influential grid reform papers, including one last year exploring what the rest of the US could learn from ERCOT’s connect and manage approach [1].
For Norris, aside from the sheer volume of new projects under development as the US experiences an IRA-fuelled renewables gold rush, the number one factor behind the current interconnection bottleneck is the way the US system has been designed.
“You could think about these queue meltdowns as primarily driven by the growing number of interconnection requests as the cost of renewables has come down,” Norris says. “But more fundamentally, you can understand it as intrinsically linked to the way that we’ve designed the resource adequacy framework outside of ERCOT and the decision to link interconnection service to capacity eligibility. Because that really is the fundamental linkage here that’s driving the need for such rigorous studies and then the cost allocation around them, which then is the primary driver of cascading queue exits and long delays in completing studies.”
NRIS and ERIS
Broadly, new generators in the US have two interconnection options. Network Resource Interconnection Service (NRIS) embodies the ‘invest and connect’ approach outlined above, where the promise of capacity compensation is balanced out by the likelihood of front-loaded network upgrade costs and, certainly at the moment, a lengthy wait for an interconnection.
The other is Energy Resource Interconnection Service (ERIS), where the proposed generator is not expected to offer full deliverability at peak loads. This means it is less likely than with NRIS to require network upgrades up-front but will be ineligible for capacity compensation and faces the risk of curtailment during stressed grid conditions.
At the moment, outside of ERCOT, most generators seeking an interconnection are doing so under NRIS. In ERCOT, there is no NRIS option as it is an energy-only market in which generators are all treated in essence as ERIS.
Generators receive generally quicker interconnections with fewer upgrade costs but receive no capacity compensation and bear greater curtailment risk (though given the statistics on the pace of new capacity additions in ERCOT it is a risk many developers are clearly willing to take).
One criticism that has been levelled at the ERCOT approach is that it doesn’t allow for effective transmission planning in the way the methodical NRIS/invest and connect approach does, where network upgrades are driven by the projects seeking interconnection. But Norris points out that as long as it’s paired with proactive transmission – the ‘manage’ part of connect and manage – the ERCOT approach should in theory lead to a more efficient process over the long term.
“There’s very wide consensus now among the vast majority of experts and market participants and a lot of regulators that proactive transmission planning is much more efficient than doing reactionary, one-off incremental network upgrades in response to generator interconnection,” Norris explains.
“There are a lot of reasons for this, but the simplest is just that on an incremental basis, you might have to do an upgrade to a certain transmission line in response to a generator interconnection request. And you do all that work, but then the next year, another project comes along and you have to go out and upgrade the line again, whereas if you had some foresight, you would have right-sized the upgrade from the beginning. And you save a lot of costs and time and effort.”
Nonetheless, Norris says it is important to recognise the “limitations” of ERCOT’s transmission planning processes, which have in the past received criticism for allowing congestion levels to creep up. A 2023 report by advocacy group Americans for a Clean Energy Grid highlighted a “doubling” of congestion on the ERCOT grid from 2020 to 2021, resulting in an estimated US$2.8 billion worth of lost energy due to transmission overcrowding.
But Norris believes these deficiencies are not unique to ERCOT’s connect and manage approach but rather a consequence of wider inadequacies in transmission planning and cost allocation processes across other jurisdictions.
“There is nothing inherent in the connect and manage approach that necessarily results in a deficient transmission planning process,” he says. “That’s a shared issue.”
The key issue Norris highlights is that, generally, jurisdictions haven’t considered the cost and benefits of transmission investments over a sufficiently long period of time and across a necessarily broad enough array of different upgrade options to lead to optimal outcomes. “That, I think most fundamentally, is the deficiency [in transmission planning processes], and it hasn’t been just a deficiency in ERCOT.”
Indeed, Norris points to a growing body of evidence and opinion suggesting proactive transmission planning combined with a connect and manage approach is the “ideal” from an economic efficiency standpoint, with the act of getting projects connected becoming itself a key part of the process for stress-testing the grid and identifying congestion points.
“The process of getting projects online and interconnected becomes a central form of market price discovery that then you feed into your cost benefit analysis for your proactive transmission planning, Norris explains.
“Because what you’re looking for, obviously, are the upgrades with the highest reliability and economic benefit. And the way that you know what’s going to provide a particular highest economic benefit is going to be based on where the most significant pockets of congestion have emerged, based on the interconnection of resources.”
Interconnection reform
With the benefits of the ERCOT approach clear, the question then becomes whether there is anything the rest of the US can take from it. Given the fundamentals of the US interconnection service structure, Norris thinks a wholesale shift to an ERIS/energy-only model outside ERCOT is unlikely.
In any case, he also believes characterising the debate over interconnection reform as “ERCOT versus non-ERCOT” is overly simplistic, highlighting opportunities for other jurisdictions to achieve more flexibility in their interconnection processes without “going full energy-only”.
“The challenge outside ERCOT is there’s no expectation that those markets are going to go energy-only and so the question is, how do you incorporate more flexible interconnection service options, while still having this kind of resource adequacy construct?”
Moves are to some extent afoot to answer that question, with the Federal Energy Regulatory Commission (FERC) last year publishing Order 2023, a major rule aimed at addressing queue backlogs. A central proposal of Order 2023 was for transmission operators to speed up interconnection queue processing by shifting to a cluster-based approach for studying new interconnections rather than doing them individually. The US Department of Energy has also taken steps to address the issue, with an interconnection roadmap published in April this year setting out a range of measures for speeding up transmission queues. A further major piece in the jigsaw was another FERC rule, Order 1920, published in May this year, which set out new expectations for how transmission operators should plan and fund network upgrades over the long term.
Norris says all these measures are “positive”. Given time to bed in, he believes the DOEs measures and those in FERC Order 2023 are likely to have a “significant impact on the ability to interconnect more projects in the near to medium term”. Order 1920 by its very nature is a longer-term reform package so is only likely bear fruit over a longer timeframe, but to a significant extent puts in place some of the proactive transmission measures Norris described earlier as the key ingredients of a successful connect and manage model. Having said that, as we explore on p.21, there are questions over whether Order 1920 will survive a number of legal challenges already being mounted against it.
Building market demand
Nevertheless, Norris believes market demand could start to build on various fronts for more jurisdictions to introduce greater flexibility to their interconnection processes, along the lines of ERCOT.
One important driver is the fact that the effective load carrying capability (ELCC) of renewable energy sources such as solar is declining as more comes online and as system peaks shift from summer to winter in some markets. In PJM, for example, the ELCC rating for solar mounted on trackers was recently cut from 55% to 14%.
“When your capacity value drops that low for any given generator, the value of NRIS also drops substantially, because your expected revenue from being a capacity resource declines,” Norris explains. “So for a growing number of especially solar generators in more markets, the value of NRIS and deliverability will decline and they may see more advantage in going energy-only to avoid network upgrades and get connected more quickly.”
A further driver is the growing popularity of hybrid facilities, where the coupling of, say, solar with storage allows the facility to mitigate its curtailment rate with the storage element and also qualify for meaningful capacity compensation without necessarily needing large network upgrades.
Yet another key catalyst is the fact that slow interconnection affects the demand side – the big consumers of power such as industry and, in particular, data centres – as well as the generators. Given that such entities are big businesses in highly competitive industries such as artificial intelligence, pressure for more efficient and flexible interconnection process is likely to grow if they are unable to secure a firm NRIS interconnection due to bottle[1]necks and upgrade requirements.
“They’re in a bigger race to interconnect as fast as possible to beat out their competition [but] may be facing substantial time periods before they can interconnect as a firm load with fully non-interruptible service,” says Norris. “And so what we’re seeing and hearing is that there is a growing number of large customers exploring this exact same topic of flexible interconnection service that would allow them to connect more quickly, if they’re willing potentially to be curtailed under certain contingency scenarios.”
The question now is “when and if these drivers will lead to the creation and implementation of more viable flexible interconnection service options”, Norris says, both for generation and load.
The implementation of Order 2023 should help build demand for greater flexibility as the industry witnesses the realities of a shift to cluster-based interconnection studies.
“There’s a likelihood that we’ll see regulators and utilities and system operators wanting to go that direction too because, especially for the loads, they’re going to realise that if they don’t figure out a way to provide faster interconnection then they may lose out on those economic development opportunities,” Norris adds.
FERC appears to be taking notice by hosting an interconnection workshop in September with an emphasis on ‘connect and manage’, where Norris will testify.
The big prize would be if the implementation of attractive alternatives to the prevailing invest and connect option most projects are pursuing created a virtuous circle that in turn helped alleviate pressures in the system overall, ultimately breaking the logjam. “If we can create a more attractive energy-only option, we may reduce burden on the studies and the clusters,” Norris says.
“By removing the projects that are able and willing to go energy-only, you might make the whole system more efficient. And, almost ironically, you might get capacity resources online more quickly than if you’re trying to study everything as a capacity resource or for deliverability.
“There’s this aspect of the way this whole system has been set up that can almost be characterised as a type of tragedy of the commons where every agent is incentivised on the margin to pursue deliverability. But if everyone is pursuing deliverability you just you end up with massive upgrades and collapsing interconnection queues.”
Clearly, it is a system that is ripe for reform. As things stand, there is little sign of the pipeline of projects coming forward in the US diminishing – quite the opposite, in fact. The ERCOT model is not without its flaws but has important lessons that other transmission operators can draw on as they seek less cumbersome and costly interconnection routes for generators. Importantly, momentum is building in all quarters for change. It now seems more a case of when than if that change will come.
To learn more about how best to work through a challenging grid environment, read yesterday’s coverage of the US’ grid landscape here; to see how recent FERC decisions could affect the US grids’ legal landscape, read our coverage here.
References
[1] Norris, T.H., ‘Beyond FERC Order 2023 – considerations on deep interconnection reform’, https://nicholasinstitute.duke.edu/sites/default/files/publications/beyond-ferc-order-2023-considerations-deep-interconnection-reform.pdf