C (4:12)

Thanks for having me. It's great to be here.

E (4:14)

Great to be here.

B (4:14)

SHIELD all right. So excited to talk to you about this letter and notice of proposed rulemaking that Secretary of Energy. Right. Sent out very recently. Alison, I want to start with you since you have the procedural knowledge here. Like, tactically speaking, what is this? What did Secretary Wright send?

C (4:34)

Technically speaking, what Secretary Wright did was use a provision in the Department of Energy Organizing act, provision 403, which is why people are referring it as the 403 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 advance notice of proposed rulemaking or an anopr around large load interconnections. And it's a 14 page kind of bare bones document that that in the eyes of the Secretary constitutes an advanced notice of proposed 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.

B (5:30)

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

C (5:38)

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. 403A In 2017, the administration sent over a letter with a proposed rulemaking to then chair Chadnil Chatterjee and the FERC requesting them to subsidize coal and nuclear plants with small, some, you know, on site fuel supply benefit and that FERC unanimously rejected moving forward with that proposal.

B (6:10)

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 with 90 days of storage and so on. So your sense is that the vibes here are good?

E (6:33)

Tyler, 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, 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, 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 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 I know we'll get into it. But in terms of what this would actually do to sort of improve the interconnection process, that's where I think there's been the most positive reception.

B (7:38)

All right, so let's dispense with the wonky jurisdictional stuff first because 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?

C (7:57)

It's wonky, but fun. Shel. 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 part of 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 fercca's 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 been asserted in the past, but.

B (9:23)

So in practice, then, is what's the question at hand here? Say I'm a large load. Say I'm a data center or a, you know, 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, that is offered to me or the interconnection queue and how it is managed? Or like, what is the actual balance of power that's in question here?

C (9:51)

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, even if it's hooking up to the transmission system. Whereas what this anopr is saying is 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. 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.

E (10:46)

Yeah, Shayan, I'll just say, as someone who originally came into this as a developer and an analyst, it was always a puzzle to me 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, Alison sort of articulates how it plays out in terms of the legal and jurisdictional dynamics. But I think. And of course, in the letter itself, the Secretary references the fact that, look, we've had long established standardized generator interconnection procedures, in 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.

B (11:45)

Okay, so it sounds like the. I don't know. The key thing here is if this goes through the 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.

C (12:15)

Yeah, that's right.

B (12:16)

Okay. All right, let's get to the meat and the substance of what the Secretary is actually proposing. Can you just give Alison just a high level overview of the sort of what you view as the key elements of the proposal?

C (12:30)

Absolutely. I mean, it's 14 pages long. And, you know, 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 what 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. Three, and 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.

B (13:19)

Can I ask, though, before we talk about the curtailable piece and even. 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 curtailable load. Is it not like an overarching, we got to connect data centers faster kind of thing?

C (13:45)

It is that I think you see kind of an embracing of the colocation model. But overall it is kind of a, 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 and.

B (14:05)

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 curtailable.

C (14:21)

That's right. I mean, if you think back, you know, 23 years ago, 25 years ago, when FERC issued Order 2003 to standardize large generator interconnection, we've now had, you know, 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, you know, whether or not you like it, we're going to assert this jurisdiction that we're confident that FERC has and we're going to not put us on a track for the next 10 years to face similar problems.

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B (16:37)

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 the, what is called in 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 like in, 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 them together. But beyond that, you know, 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 curtailable. So as you think about the big picture world of data centers and their energy provision, where does generation fit in in your mental framework?

E (17:29)

Yeah, maybe it's worth just stating very clearly up front that one of the things that has been revealed over the past year based on this colocation docket in PJM and other considerations in 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 on site 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. And I guess to your sort of broader question there, I mean, I Suppose it's no secret that the preferred option for flexibility, or we could say curtailability on the part of these large loads is either on site 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 do, they were going to size battery storage, two hour battery storage, 100% of their facility in New Jersey and then the same in Virginia. And then just last week we saw the significant announcement from Calibrant and Align data centers that will do also a 2 hour battery for a new data center in the Pacific Northwest and that specifically they said it was helping to accelerate its interconnection by on the order of years. So this 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.

B (19:49)

How much visibility, I mean you mentioned those, all those projects are two hour batteries. And one thing that's not clear to me in this FERC order or just in, 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, 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 like you know, over the course of a year, how much do you require in order to maintain like system level resource adequacy? But as we 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 like how often are we going to need more and what's going to dictate that?

E (20:41)

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 kind of six hour range is sort of the sweet spot when you just kind of look at most of these periods of system stress. And so even with a two hour battery, right, if it's sized at 100% of your nameplate 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 like 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 E3 and they used Southwest Power Pool as the market and they looked at four hour duration. I think it was eight or ten hour duration from either a battery or whatever the onsite option was. And what they found is that even with four hours, you end up with what we called an effective load carrying capability in many cases 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 ELCC value that can come from even relatively short duration batteries 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. 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 you know, usually you can't actually get more than a certain number of hours of 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 like one of the most interesting, I think debates right now is like, do you really need to spec to 40 hours? Even if you do, in terms of like the size of the gensets, 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 like a two to six or sort of eight hour solution?

B (23:43)

There's like two things, two pieces here that I think are connected to each other but, but also are distinct that I always find people conflate which is using some on site asset. Could be a battery, could be a generator, could be curtailable 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 the what are you using for backup power? Which is what you were just talking about, right? And you theoretically can use the same, some of the same asset battery in particular has like a role to play potentially in both. But you can easily imagine that they are distinct things and distinct assets. I mean currently that's how it is, right? Like the diesel generator is just a backup asset and it probably doesn't. It has runtime limits, they're going to keep it from, you know, operating too much. So depending on the amount of curtailment you need to do like that just might not work for it anyway. So I don't know, I feel like I want to be careful not to consider those two things the same thing. Does that make sense?

E (24:48)

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 those two hour battery storage deals that we just mentioned at data centers, they still have gensets 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.

C (25:17)

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, which your guests 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. 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 decreased stress on the grid. I think these, 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. 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.

B (26:19)

Yeah, I'm curious to get both of your take on this. I've been starting to conceptualize a 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 like oil resource curve kind of thing. But as you said Allison, there's a bunch of things you can do. And the way I think about it is the, the X axis is how much flexibility you can deliver, how much capacity, I guess, or like hours times megawatts probably. And then the Y axis is cost basically. And you know, 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 temporarily. 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 and 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 these resources, 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, you know, utility, you define what curtailment looks like, what curtailable load looks like. But if there is a curtailable load in your territory, then you need to run this procedure to get it interconnected?

C (27:56)

Yeah, I mean, I'll give you the within kind of the FERC box answer and then maybe the political context in which this conversation is taking place and what that means for it and within the political the FERC box answer. It is rare that FERC regulates down to that level of specificity. Right. 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. 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's 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, this, and this. 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 letter from Secretary Wright suggested this should be done by April. So it's the end of October. An A NOPR means you're going to take comments on an A nopr, then write a nopr, then take comments on a nopr, then issue a rule that would be rocket speed in fork 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 them in a way that works for the providers.

E (29:41)

Yeah, 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 2000s 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? Actually, I should shout out to Rob Gramlich because I think he was actually representing the American Wind association at the time after he had left FERC 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 be curtailable 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, what the system conditions would be when curtailment would be likely to occur. And so that sort of gave an out. But I think 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 like Defined maximum number of hours in a year and then something with respect to like the duration of the events. And if you look at for example like Google's comments in the pjm, 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. 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 curtailable connections program and they actually remarkably, if they end up curtailing either the generator or the load more than what they're guaranteed, 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. Right. 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.

C (32:10)

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, you know, 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 a, for example front of meter storage solution that might be able to provide curtailability close to but not behind the same point of interconnection as a new large load, that this proceeding contemplate those opportunities as well.

B (32:49)

And that within the, the way that the letter is written would like. When they talk about hybrid facilities, are they talking about exclusively behind the meter, exclusively on site or potentially near site, you know, like in the same zone or whatever? Is it clear?

C (33:06)

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

E (33:17)

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, it's sort of like 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 other thing I just want to say about this almost inevitable proceeding that seems to be about to 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, that existing jurisdictions can sort of take that content and take that back to their isrto or at the state level to hopefully get these kind of offerings in place.

C (34:22)

Yeah, that's a great point. And I don't want, you know, 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 of the good. Let's make progress. You know, 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.

B (34:44)

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 curtailability. And in your mind is the right, I guess the question 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, well, 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.

E (35:25)

Yeah, no, and actually our research lab at Duke University has been, because we're modeling 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, right, where a variety of different options can compete either on site or even to some extent off site. 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 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 yeah, whether it's load shifting, actually shifting around the computational workloads, or it's battery storage or its 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.

B (36:54)

Is there a risk that this actually, I mean, you know, we've just seen the emergence of some of these first, like, like the, the bring your own VPP type of thing. Right. Which is not on site but is near site. Is there a risk that this process actually disadvantages that stuff in its decency?

C (37:13)

Yes, there's always a risk. I mean, you know, 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. 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. To my mind, we need to make sure there are guardrails in place to protect for that purpose.

E (37:50)

Yeah, and I'll just say too, this is so different from the way we do kind of interconnection 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 like a winter case, a summer case, and maybe one during the shoulder months. But it is just a single fixed point in time, whereas what we're talking about is extending that out maybe not all the way to 8760, but at least maybe to like 1000 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 like, 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.

B (38:46)

All right, so wrapping it up, I want to talk about what comes next. Alison, you mentioned the timeline. So this is all supposed to happen. There's supposed to be, like, 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, like, I don't know, various other FERC orders.

C (39:07)

Historically, yeah, it took us four years to issue from anoper to final rule. The transmission Regional Transmission Planning Order 1920. Then there was an order on rehearing 1920 A and then 1920, 1920 B. 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, 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 front.

B (39:48)

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.

C (40:00)

Sounds great.

E (40:01)

Thanks so much. Fayol.

B (40:04)

Allison Clements served as FERC commissioner from 2020 to 2024 and is now a partner with digital infrastructure advisory firm Asgard and the principal of 804 Advisory. Tyler Norris is a PhD student at the Duke University Nicholas School of the Environment. This show is a production of Latitude Media. You can head over to latitudemedia.com for links to today's topics. Latitude is supported by Prelude Ventures. This episode was produced by Daniel Waldorf. Mixing and theme song by Sean Marquand. Stephen Lacy is our Executive Editor. I'm Shayl Kant and this is Catalyst.