Last Thursday, Energy Secretary Chris Wright directed the Federal Energy Regulatory Commission to consider rulemaking to fast-track interconnection for large loads — as long as they agree to be curtailable or colocate with dispatchable generation.

So what does this proposal actually mean for interconnection? 

In this episode, Shayle talks with Allison Clements, former FERC commissioner and current partner with digital infrastructure advisory firm ASG. Allison is also principal of 804 Advisory. Shayle also talks with Tyler Norris, doctoral student at Duke University’s Nicholas School of the Environment. Allison, Tyler, and Shayle cover topics like:

• How the proposal would standardize interconnection procedures for certain large loads, with study periods no longer than 60 days 
• The jurisdictional shift: asserting federal authority over a process traditionally under state purview  
• The types of eligible loads, including traditional data centers as well as ones that colocate with generation, also known as “hybrid facilities”
• The duration of flexibility and whether 2-hour, 4-hour, or longer durations are needed for curtailment
• Whether flexibility resources should be behind-the-meter or front-of-meter
• The potential disadvantages for bring-your-own-supply or bring-your-own-VPP

Resources

• Latitude Media: Wright directs FERC to fast track large load interconnection  
• Latitude Media: How the world’s first flexible AI factory will work in tandem with the grid  
• Latitude Media: OpenAI pushes the White House to invest in the grid to compete with China  
• E3: Demand Response as a Capacity Resource in SPP’s Era of Data Center Growth 
• Canary Media: In a first, a data center is using a big battery to get online faster 

Credits: Hosted by Shayle Kann. Produced and edited by Daniel Woldorff. Original music and engineering by Sean Marquand. Stephen Lacey is our executive editor. 

Catalyst is brought to you by EnergyHub. EnergyHub helps utilities build next-generation virtual power plants that unlock reliable flexibility at every level of the grid. See how EnergyHub helps unlock the power of flexibility at scale, and deliver more value through cross-DER dispatch with their leading Edge DERMS platform, by visiting energyhub.com.

Catalyst is brought to you by Bloom Energy. AI data centers can’t wait years for grid power—and with Bloom Energy’s fuel cells, they don’t have to. Bloom Energy delivers affordable, always-on, ultra-reliable onsite power, built for chipmakers, hyperscalers, and data center leaders looking to power their operations at AI speed. Learn more by visiting BloomEnergy.com.

Transcript

Tag: Latitude Media: covering the new frontiers of the energy transition.

Shayle Kann: I’m Shayle Kann, and this is Catalyst.

Allison Clements: 23 years ago, FERC issued Order 2003 to standardize large generator interconnection. We’ve now had two decades of experience of the problems and the solutions which have been kind of haphazard and piecemeal over time to get at this explosion of requests for supply to interconnect to the system

Shayle Kann: Coming up: Who needs coffee when you’ve got an FERC ANOPR on large load interconnection? 

I’m Shayle Kann. I lead the early stage venture strategy at Energy Impact Partners. Welcome. All right, so this is wonky, but it is super important. We’ve talked innumerable times at this point on this podcast about connecting large loads, particularly data centers, the electricity grid and how that has become the epicenter of a huge challenge both in AI world and in energy world. And just recently the US Secretary of Energy, Chris Wright, wrote a letter on this topic that could have really huge impacts. It’s a letter to FERC, the Federal Energy Regulatory Commission, and it is a combination of asserting FERC authority in a way that has not happened historically over large load interconnection, but also just as a, maybe even more importantly, trying to set a process to get those loads interconnected faster, particularly when they’re combined with generation.

We’ve talked before about co-location of generation and data centers or if they are flexible loads and curtail another thing that we’ve talked about before. So it ties together a bunch of stuff that I’ve been interested in that everybody in the energy world has been monitoring and it’s going to play out pretty quickly because Secretary Wright requested this to be done with an actual order from FERC by April, which is basically lightning speed from a federal regulatory perspective. So we’ll see if that happens, but it’s one of these things that is very, very important for many folks downstream of this on both the energy side and the AI side. But that I think is actually poorly understood other than the headlines. So in order to parse out what’s actually in this letter, in this proposed order, I brought on two folks who are wildly knowledgeable on the subject. One has been on the show before. Tyler Norris. Tyler is a PhD student at Duke University and wrote I think what is now considered to be kind of the seminal paper on data center load flexibility. And the other is Alison Clements. Alison was actually a FERC commissioner from 2020 to 2024, so she has deep experience inside the agency itself. She’s now a partner with Digital Infrastructure advisory firm, ASG, and the principal of 804 Advisory here at Tyler and Allison. Allison Tyler, welcome to you both.

Allison Clements: Thanks for having me. It’s great to be here. 

Tyler Norris: Great to be here, Shayle.

Shayle Kann: Alright. So excited to talk to you about this letter and notice of proposed rulemaking that Secretary of Energy Wright sent out very recently. Alison, I want to start with you since you have the procedural knowledge here. Technically speaking, what is this? What did Secretary Wright send?

Allison Clements: Technically speaking, what Secretary Wright did was use a provision in the Department of Energy Organizing Act, provision 403(b), which is why people are referring to it as the 403(b) letter. He sent a letter to then Chairman Rosner at FERC and all of the commissioners and said, I the Secretary of Energy direct you to consider issuing an advanced notice of proposed rulemaking or an ANOPR around large load interconnections. And it’s a 14 page kind of bare bones document that in the eyes of the secretary constitutes an advanced notice of proposal rulemaking. That’s the process. And now FERC can say, okay, great, we’re going to consider it. And they either move forward and issue the advanced notice of proposed rulemaking, which there has been some public indication already that they are eager to do or they could decide not to issue the rule, but they would have to justify that decision.

Shayle Kann: Historically speaking, when the Secretary of Energy does something like this, would it be common or uncommon for FERC to say, no thank you?

Allison Clements: Well, it hasn’t happened very often. The one time that people remember is under the next provision or the previous provision in that Act 403(a) in 2017, the administration sent over a letter of, with a proposed rulemaking to then chairman Neil Chatterjee and the FERC requesting them to subsidize coal and nuclear plants with some onsite fuel supply benefit. And that FERC unanimously rejected moving forward with that proposal.

Shayle Kann: Okay. So there’s some possibility it doesn’t move forward, but I mean reading the tea leaves, maybe Tyler, you can comment on this because I’ve seen you say it publicly. It seems generally maybe outside of FERC, but in the public domain this has been pretty well received broadly speaking, which I mean I think does run in contrast to, I remember that previous letter about coal, 90 days of storage and so on. So your sense is that the vibes here are good, Tyler,

Tyler Norris: So far, let’s not discount that there will likely be other perspectives that have not yet been represented, but no, look, I think it was very significant that Commissioner Rosner came out of the gates expressing an eagerness to work on the proposal on the other side of the aisle. You had Senator Mike Lee that came out strongly supporting it and a variety of different stakeholder groups that at least I’ve seen and companies that are involved in this space seem to view it generally favorably. I think just to parse out a key distinction, right, there’s this jurisdictional question and on that one I think there’s obviously going to be a variety of perspectives and there will be concerns on the part of, especially of some state commissioners officials and certainly the investor owned utilities, but with respect to the substance, that’s where I’ve seen the most excitement and then we’ll get into it. But in terms of what this would actually do to improve the interconnection process, that’s where I think there’s been the most positive reception.

Shayle Kann: Alright, so let’s dispense with the wonky jurisdictional stuff first. I do think it’s important to talk about, but then we’ll get into the meat of the substance here, which I think is what’s more interesting. But Alison, back to you. What is distinct here about what the Secretary of Energy is proposing in terms of the shifting of power and authority between FERC and states?

Allison Clements: It’s wonky but fun. She, of course, the Federal Power Act gives FERC the federal regulator jurisdiction over the transmission system, right? The high voltage poles and wires and the wholesale sales of electricity, whereas the states reserve power for generation as well as the distribution system. And there is a little bit of a fuzzy area as relates to whether or not FERC has jurisdiction over the transmission aspects of bundled rates in vertically integrated states. So if you live in a state with a vertically integrated utility, the state commission has jurisdiction over not only your generation charge party, your bill and the distribution portion of your bill, but also the transmission portion of your bill. And FERC has never exercised authority, exercised its authority to take jurisdiction over that piece. The reality is though it’s hard to imagine anything, FERC has jurisdiction over practices affecting transmission rates. It’s hard to imagine anything more directly affecting transmission rates than new loads hooking up to the transmission system and the costs that those loads impose. And so I think the legal arguments are very strong in favor of the Secretary of Energy’s position here and in favor of the position FERC would take, I’m not sure if it’s by tradition, by culture, experience or practice that it actually hasn’t been asserted in the past,

Shayle Kann: But so in practice then, what’s the question at hand here? Say I’m a large load, say I’m a data center or a prospective data center and I want to go get cited in a regulated utility territory is the question who has authority over the tariff that is offered to me or the interconnection queue and how it is managed or what is the actual balance of power That’s in question here.

Allison Clements: There are two parts of that hookup, right? If you’re the data center in Georgia or in Oregon and you go up to hook up to the grid, your utility has authority to take you through that study process and hook you up and tell you what it’s going to cost. But the state has jurisdiction over that decision when you hook up to the grid in vertically integrated states, right? Even if it’s hooking up to the transmission system. Whereas what this large look, this ANOPR is saying is known FERC is going to now have jurisdiction. So FERC could standardize rules for that piece of the hookup across all utilities or some set of principles that these utilities must follow in a way that they have not done before. Sorry, the second piece of the jurisdictional question is who has authority over the sale from the generator to the data center as the retail sale and that piece remains with the states?

Tyler Norris: Yeah, she, I’ll just say as someone who originally came into this as a developer and an analyst, it was always a puzzle to me, right? Why we had standardized interconnection procedures that were promulgated by FERC for generators, but nothing for loads. And setting aside all the concerns around rate regulation or even really anything that happens after you’re already hooked up to the system, but just the process leading up to actually getting connected, it was always a puzzle to me. And of course Allison sort of articulates how it plays out in terms of the legal and jurisdictional dynamics. And of course in the letter itself the secretary references the fact that, look, we’ve had long established standardized generator interconnection procedures and part because FERC recognized that interconnection is inherently part of open access to the transmission system and it sounds like they’re making a similar argument.

Shayle Kann: Okay, so it sounds like, I dunno, the key thing here is if this goes through the just jurisdictional shift, then if a large load wants to interconnect to the transmission system, the utility will still be the one who has to manage that interconnection and introduce the tariff and all that into regulated territory. But the oversight might shift from the state public Utility Commission to FERC if this is true. And that would allow FERC to do something that’s more standardized and sort of national versus it all being piecemeal. That’s basically the gist of it.

Allison Clements: Yeah, that’s right.

Shayle Kann: Okay. Alright. Let’s get to the meat and the substance of what the secretary is actually proposing. Can you just give Allison just a high level overview of the sort of what you view as the key elements of the proposal?

Allison Clements: Absolutely. I mean it’s 14 pages long and when we issued a regional transmission planning rule at FERC last year, it was 1200 pages long. So this is very bare bones, high level conceptual and there’s a lot of devil in the details. But the main things that the rule does is one, it asserts the jurisdiction we just talked about, which has been untested largely. Two, it suggests that loads connecting with new generation together should be studied together, which saves both costs and time. And three, the exciting part that I know Tyler’s going to want to jump in on is that it suggests that if loads are willing to be curtailed, curtailable, if loads will stop when asked stop taking power from the grid, when asked by the grid operator, they should experience accelerated interconnection and that study time should last no longer than 60 days.

Shayle Kann: Can I ask though, before we talk about the tail piece and also the hybrid facility piece, is it not saying overall there should be a faster load interconnection process for these large loads and instead it’s saying only in these circumstances we need to fix the problem for co-located generation and load and we need to introduce a faster process for curtail a load. Is it not like an overarching, we got to connect data centers faster kind of thing?

Allison Clements: It is that I think you see kind of an embracing of the co-location model, but overall it is kind of a cut through the confusion and the uncertainty and hopefully the lack of transparency around how you get hooked up to the grid as new load today in this time where supply is tightening.

Shayle Kann: Maybe that’s the part of the jurisdictional thing. It’s like okay, we need to streamline and standardize this whole process to make it better across the board and then also specifically let’s do something new with regard to facilities that are co-located with generation or that can be curtail.

Allison Clements: That’s right. I mean if you think back 23 years ago, 25 years ago when FERC issued order 2003 to standardize large generator interconnection, we’ve now had since that time, two decades of experience of the problems and the changes and the solutions which have been kind of haphazard and piecemeal over time to get at this explosion of requests for supply to interconnect to the system. And now you have an administration saying whether or not you like it, we’re going to assert this jurisdiction that we’re confident that for cas and we’re going to not put us on a track for the next 10 years to face similar problems.

Shayle Kann: Okay. Tyler, I want to ask you first, you’re the curtailable load guy, but before we talk about the curtailable load stuff, I am interested in the second thing that Allison said is in there, which is what is called the letter hybrid facilities, right? That’s the co-located Generation plus load. And my read of it is that part of what they’re doing here is saying, look, in a default scenario, you submit a load interconnection request, you submit a generation interconnection request, those two things are considered independently and it’s not really unified. So this tries to unify them and say consider ’em together. But beyond that, these things are kind of intertwined because generation might be the mechanism if it’s behind the meter, it might be the mechanism to be curtail. So as you think about the big picture world of data centers and their energy provision, where does generation fit in your mental framework?

Tyler Norris: Yeah, maybe it’s worth just stating very clearly upfront that I think one of the things that has been revealed over the past year based on this co-location docket in PJM and other considerations and other jurisdictions is that we really have an antiquated load interconnection study process and study criteria because as you said, it’s really divided from the generation side. And so this has very significant consequences if you are talking about co-located generation and load. Because what you might have going on is that a generator can be essentially offsetting the withdrawal from the grid from a given load during the most stress period, which is what the utilities are actually studying to determine your network upgrades. And so if they don’t consider the ability of that onsite generator to offset your withdrawal, you may be much more likely to trigger the need for major network upgrades.

And of course that’s more expensive and it can take multiple years. So that’s sort of part of the delay. I guess to your broader question there, I mean I suppose it’s no secret that the preferred option for flexibility or we could say curtail ability on the part of these large loads is either onsite generation or storage. I do think we’ve heard a lot about the generation option and we hadn’t really seen large scale battery storage deals just until the past few weeks. I think the first one that I noticed that was in the public domain was from Iron Mountain, which announced that they were going to size battery storage, two hour battery storage at a hundred percent of their facility in New Jersey. And then the same in Virginia. And then just last week we saw the significant announcement from caliber and aligned data centers that will do also a two hour battery for a new data center in the Pacific Northwest. And that specifically they said it was helping to accelerate its interconnection on the order of years. So even just this, I mean it sounds very simple in a sense just like instead of studying them separately, study them together. But that would be a very significant development I think in the way we do load planning and could mitigate the need for substantial amount of upgrades and accelerate the interconnection process.

Shayle Kann: How much visibility, I mean you mentioned all those projects are two hour batteries and one thing that’s not clear to me in this FERC order or just in general is how much visibility we have, and maybe this is going to be locationally specific, but how much visibility we have into the required duration of flexibility at any given time. I know there’s a high level, you’ve done a bunch of great work on this Tyler, on over the course of a year. How much do you require in order to maintain system level resource adequacy? But as start to think about is what’s going to sit behind the meter exclusively going to be generation or is it going to be storage or something else? How often does a two hour battery do the trick basically and how often are we going to need more and what’s going to dictate that?

Tyler Norris: Yeah, no look, this is one of the questions. I mean I think it’s widely recognized that in the vast majority of events that you’re talking about that the two to six hour range is sort of the sweet spot when you just look at most of these periods of system stress. And so even with a two hour battery, if it’s size at a hundred percent of your name plate and the goal is to reduce your draw by 50%, well that becomes a two hour battery, sorry, a four hour battery and then you can sort of adjust it thereafter. So we should also recognize a two hour battery can become a longer duration battery if you’re using it for less than your nameplate. But I would point there’s another study that just came out a few weeks ago, it was by E three and they use Southwest Power Pool as the market and they looked at four hour duration, I think it was eight or 10 hour duration from either a battery or whatever the onsite option was.

And I mean what they found is that even with four hours you end up with what we’d call an effective load carrying capability in many cases like above 50%, which is actually pretty close to the ELCC of some generated options or even longer duration storage options. So I think there is substantial there ELCC value that can come from even relatively short duration batteries. And in a lot of cases, again, especially if you’re not trying to go all the way to zero, but one of the bigger questions that arises is if you’re trying to spec this data center to be able to ride through some massive grid outage where you’re talking about over 24 hours or even out to 48 hours, of course you can’t do that with a battery. And this has become a very interesting conversation around these kind of events because first off, if these are transmission interconnected loads, you think about what type of event you’d be talking about, you’d have an outage of more than 24 to 48 hours.

I mean, what we’re really talking about is an event on par with the largest blackouts that have ever occurred in US history that literally led to the formation of nerc. And so obviously they’re extremely unlikely. It’s not to say that they can never happen, but the other thing you start to think about what is going to happen during such a historic event and the assumption that you are going to be prioritized to get diesel shipped to your data center as opposed to all the other competing needs including serious emergency and life-threatening situations. I think that’s been an assumption that might not necessarily hold. And usually you can’t actually get more than a certain number of hours a diesel on site and storage. And if you go beyond a certain volume, I mean it actually becomes a little bit dangerous and there’s a lot of concern about that. So yeah, this is one of the most interesting, I think debates right now is do you really need to spec to 48 hours even if you do in terms of the size of the gen sets, can you actually get that much fuel on site or can you expect it to be delivered or is it sufficient to go with something that’s a two to six or eight hour solution?

Shayle Kann: There’s two pieces here that I think are connected to each other but also are distinct that I always find people conflate, which is using some onsite asset, could be a battery, could be a generator, could be curtail load as a mechanism to get interconnected faster. And that’s sort of the crux of what this FERC directive is all about. And then there’s what are you using for backup power, which is what you were just talking about. And you theoretically can use some of the same asset battery in particular has a role to play potentially in both, but you can easily imagine that there are distinct things and distinct assets. I mean currently that’s how it is, right? The diesel generator is just a backup asset and it probably does not has runtime limits, they’re going to keep it from operating too much. So depending on the amount of curtailment you need to do that just might not work for it anyway. So I dunno, I feel like I want to be careful not to consider those two things the same thing. Does that make sense?

Tyler Norris: That makes complete sense. And yeah, the diesel’s meant for right absolute worst case scenario, emergency purposes. And so my sense is that all of those two hour battery storage deals that we just mentioned at data centers, they still have gen sets likely diesel for those longer duration emergency events. And they’re not at all mutually exclusive. And in fact it may be that predominantly we see that kind of arrangement going forward where we do have battery storage

Allison Clements: At a high level, if you’re going to stop taking energy off the grid as a large load customer, you can curtail and just stop. You can go to your backup diesel gen sets or your gas RICE sets which are emerging, but you can face limitations in either case, you can decrease the intensity of your compute, your guess in the past have talked about companies trying to do that. You can transfer your compute, you’ve had other guests on your show trying to talk about that, right? Or you could have a third party curtailment on your behalf, some sort of contract, whether it be the virtual power plant or otherwise that would provide their decreased stress on the grid. And I think the kind of service of curtailment service and where it’s coming from and the kind whether it’s energy, whether you’re offering capacity curtailment and for how long and how you’re getting paid, those are all really important details that haven’t been defined anywhere. And so when you think about the bucket of issues that are going to arise in this proceeding, those are some that rise to the top for me.

Shayle Kann: Yeah. I’m curious to get both of your take on this. I’ve been starting to conceptualize little bit of a framework in my head for data center flexibility or large load flexibility in general, which is like a resource curve sort of. It’s a little different from your traditional oil resource curve kind of thing. But as you said, Alison, there’s a bunch of things you can do. And the way I think about it is the X axis is how much flexibility you can deliver, how much capacity I guess, or hours, times megawatts probably. And then the y axis is cost basically. And in principle, your lowest cost thing to do, assuming you can stay within your customer SLAs is just load flexibility straight up. It’s managing compute differently, either shifting geographically or shifting temporally, but there’s only so much you can do of that. It’s going to be limited.

So it’s low end of the resource curve but not that wide on the chart. And then you start moving up the chart and you get batteries in generators and all this other stuff. And I guess the question Allison, is do you think that FERC in this proceeding will, is FERC going to be in the position to have to sort of distinguish amongst the mechanisms to get to curtailment or flexibility and offer ELCC type metrics for them and things like that and then define all those rules? Are they going to leave that to the utilities and say, look, utility, you define what curtailment looks like, what curtail load looks like, but if there is a curtail load in your territory, then you need to run this procedure to get it interconnected?

Allison Clements: Yeah, I mean I’ll give you within the FERC box answer and then maybe the political context in which this conversation is taking place and what that means for it within the FERC box answer, it is rare that FERC regulates down to that level of specificity. I mean you have seen on the supply side capacity accreditation methodology and come in from the various RTOs for example. And FERC largely defers subject to any potentially discriminatory impacts. So historically the agency has also really been kind of a thousand flowers blooming type place and been, ever since standard market design failed in 2000, the agency has been really skittish about requiring standardized anything across the board. It often does principles satisfy these six principles or when you’re thinking about the types of flexibility, ensure that you value this and this. So my instinct without getting into the politics is they’re not going to get that specific on first take.

And then you layer on the fact that the 403(b) letter from Secretary Wright suggested this should be done by April, so it’s the end of October. An ANOPR means you’re going to take comments on an ANOPR, then write an ANOPR, then take comments on an ANOPR, then issue a rule that would be rocket speed in FERC world. So I think there’s no way they can get to that level of specificity on so many of the details of these questions. And that’s my biggest concern here. We don’t want something rushed that ends up failing to really take advantage of the opportunity that these flexibility alternatives provide and incentivize ’em in a way that works for the providers.

Tyler Norris: And maybe I’ll just dive in there for a second because I think one of the good news stories is that we actually arguably have a little bit of precedent for this type of what we might call quasi firm service. It was really more meant for generators and it’s actually called conditional firm transmission service. It’s really, to my knowledge, hardly ever been used outside some cases in the Pacific Northwest. It was actually a service, I think it was created in the late two thousands. And the whole idea was where you couldn’t get fully firm transmission service and you didn’t want to go fully non firm. Could you get something that was conditional firm? And actually I should shout out to Rob Graham because I think he was actually representing the American Wind Association at the time after he had less fur to get this done. And so one of the big debates in that proceeding became can the transmission provider define a certain number of hours that would be needed over the course of a year that you could curtail such that you could qualify for this conditional firm service?

And of course there was significant pushback from the transmission providers and they said it’s too hard to offer a certain number of hours a year. So instead we’re just going to tell you what the system conditions would be when curtailment would be likely to occur. And so that sort of gave an out. But I think that really the holy grail here that we’re sort of talking about is it has to be bounded flexibility or bounded curtailment in terms of defined maximum number of hours in a year. And then something with respect to the duration of the events. And if you look at, for example, like Google’s comments in the PJ M, this big process, they have this critical issue fast path process trying to figure all this out. They say, look, we might be willing to actually participate in the demand response program. It’s just that right now it’s unbounded, right?

So there’s just no limit on the number of hours that could occur. And so that I think is where we’re getting at. And by the way, there are other models to look at too. The UK has this whole curtail connections program and they actually remarkably, if they end up curtailing either the generator to the load more than what they’re sort of guarantee says that they actually compensate the customer. I don’t know that we’re going to get to that extent in this kind of program offering, but at minimum it would seem to make sense that we have that as a voluntary option for the flexible loads that are able and willing to use it.

Allison Clements: Another thing that comes to mind that you didn’t mention yet is we’ve talked a little bit about behind the meter and what the hybrid facilities might look like, but we also want to make sure that front of the meter opportunities to provide this type of support don’t get left out of the conversation. I heard someone say at a conference yesterday, behind the meter in front of the meter is going to evolve into around the meter right close to the meter. And I think that’s a concept that we need to be careful doesn’t get lost. So if you have four example front of meter storage solution that might be able to provide curtail ability close to, but not behind the same point of interconnection as a new large load, that this proceeding contemplate those opportunities as well

Shayle Kann: And that within the way that the letter is written, would when they talk about hybrid facilities, are they talking about exclusively behind the meter, exclusively onsite or potentially near site in the same zone or whatever? Is it clear,

Allison Clements: I read it to say withdrawal and injection behind the same point? It doesn’t suggest elimination of other opportunities, it just doesn’t speak to them. What do you think Tyler?

Tyler Norris: I don’t think they went into that level of specificity, but for example, with what Southwest Power Pool is proposing, I think the metric they use, we’d have to check the final version, but I think it was like it needs to be within two substations of you is if you’re going to be somewhat co-located or have certain benefits from an associated generator with the load. So I think there’s a lot of opportunity to get creative there. And one of the things I just want to say about this almost inevitable proceeding that seems to be about happen is that look, even if it doesn’t lead to a final rule, and even if there are such significant concerns about the jurisdictional dynamics that FERC doesn’t want to go there, and by the way, I want to respect that there are some legitimate jurisdictional concerns. I want to respect this. I think just the substance that this will hopefully elicit in terms of how to make this kind of service work is going to be incredibly valuable. And even if it doesn’t lead to a final federal rule that existing jurisdictions can sort of take that content and take that back to their IS ORTO or at the state level to hopefully get these kind of offerings in place.

Allison Clements: Yeah, that’s a great point. And there’s a lot in the negative bucket. There’s lots of positives and opportunity here. This is a giant problem, this is a path forward. Let’s not let perfect be the enemy the good, let’s make progress. There’s lots of concern about independence of the commission, about jurisdiction, et cetera, et cetera. That must be acknowledged as we go down this path.

Shayle Kann: Tyler, I guess I’m curious to get your take on this flexibility resource curve. Not necessarily the concept specifically, but the basket of things that will be available to provide curtail ability. And in your mind, I guess the question is, is the right approach in your mind to say you need to be able to provide X hours of flexibility with the Y duration events or whatever and then let the market figure out how much of that is going to be generation storage and load flexibility? Or does it make sense to actually, I don’t want to say put your thumb on the scale, but try to dictate a little bit how much of what gets implemented there?

Tyler Norris: Yeah, no, and actually our research lab at Duke University has been because we are remodeling the bulk power system. And so ultimately you want it to be as sort of generalizable as possible so that you can sort of represent any load that is utilizing this type of flexibility for all these purposes. And so you want to kind of parameterize it and make those parameters as generalizable as possible. Also because then we can actually create a market where a variety of different options can compete either onsite or even to some extent offsite. I mean this gets even more interesting and complex when you start to think about these large loads potentially procuring the flexibility from other loads in the same balancing authority. The kind of simplest version of it’s just for capacity, just resource adequacy. But then if you’re actually talking about to sort of mitigate transmission congestion, think about the electrical proximity of those customers and how you do that study. I think that’s the very advanced version. I hope we can get there, but at minimum let’s get it in place for those that are doing it behind the meter and whether it’s load shifting, actually shifting around the computational workloads or it’s battery storage or it’s generation or even just reducing operation. I think there are cases where just from a planning perspective, you wouldn’t assume that a new load is going to be drawing at its max pull during certain types of weather conditions.

Shayle Kann: Is there a risk that this actually, I mean we’ve just seen the emergence of some of these first, the bring your own VPP type of thing, which is not on site but is near sight. Is there a risk that this process actually disadvantages that stuff in its nascency?

Allison Clements: Yes. There’s always a risk. And to add to Tyler’s previous response, which I totally agree with, the other nice thing about not getting that specific about technologies is that it’s legitimate under the Federal Power Act, which is FERC’s guiding principle, right? And so to the extent that there are attempts to do things like take away the opportunity for bring your own virtual power plant, bring-your-own supply in other ways that doesn’t satisfy the non-discrimination requirements under the statute. So to my mind, we need to make sure there are guardrails in place to protect for that purpose.

Tyler Norris: And I’ll just say too, this is so different from the way we do air connection studies right now, where the way it works right now is you’re basically looking at these steady state fixed snapshots of the system, like single points in time and you might do a winter case, a summer case, and maybe one during the shoulder months, but it is just a single fix point in time. Whereas what we’re talking about is extending that out, maybe not all the way to 87 60, but at least maybe to a thousand hours in the year. And there are a few, I think, existing transmission providers that could perform that kind of study. But we’re going to have to just get better and more advanced at doing this. And so I think part of this frankly is we just need to train more people on how to do this kind of more advanced study and I’m hopeful that this proceeding will sort of shine a spotlight on those needs and capabilities so that we can sort of promulgate it more broadly.

Shayle Kann: Alright, so wrapping it up, I want to talk about what comes next. Allison, you mentioned the timeline. So this is also supposed to happen, there’s supposed to be a final order by April. Is that a firm deadline of any sort? Can FERC just take longer if they need to because that is remarkably fast. I’m remembering how long it took to do I various other FERC orders historically.

Allison Clements: Yeah, it took us four years to issue from a nopa to final rule, the regional transmission planning Order 1920, and then there was an order on rehearing 1920A and then 1920B. It’s not realistic. What authority does the Secretary of Energy have in that case? The bully pulpit, political pressure. But I think when that letter came out, there were a lot of FERC staffers who were thinking, oh no, my Thanksgiving and holiday plans. So I think you have to imagine that if the commission is showing good progress, that that is a satisfactory place to be, but we will see what happens on that friend.

Shayle Kann: All right. Well, thank you so much for both of you for taking the time and walking me through this. This is going to be something to monitor closely over the next few months, so we’ll have you back on when we know what’s what, but appreciate the time.

Allison Clements: Sounds great.

Tyler Norris: Thanks so much, Shayle.

Shayle Kann: Alison Clements served as FERC commissioner from 2020 to 2024 and is now a partner with Digital Infrastructure Advisory Firm ASG and the principal of 804 Advisory. Tyler Norris is a PhD student at the Duke University’s Nicholas School of the Environment. This show is a production of Latitude Media. You can head over to latitude media.com for links to today’s topics. Latitude is supported by Prelude Ventures. This episode was produced by Daniel Woldorff. Mixing and theme song by Sean Marquard. Stephen Lacey is our executive editor. I’m Shayle Kann, and this is Catalyst.

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