The Utility Power Trip Behind Transmission Network Upgrades — Episode 266 of Local Energy Rules

Gabe Tabak:
Developers really do not like participant funding. They do not like being responsible for, paying for, and then never being reimbursed for, these big grid costs.

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John Farrell:
Who should pay for upgrades to the high voltage transmission system? For years, there were essentially two options. Developers would pay for upgrades needed for a particular project and would get reimbursed by the utility company over time, or developers would pay and try to recoup the upgrade costs from their power sales contracts. Within this messy system, lay an interesting question. If many of these upgrades actually provided benefits to the broader grid, why not socialize the cost?
Joining me in January 2026, Gabe Tabak, assistant general counsel for the American Clean Power Association, walked me through the complexity of transmission upgrades, but also we discussed a new utility-driven approach called self-funding, where utilities look to front load their profits from transmission upgrades by making developers cover the shareholder rate of return upfront, along with the cost of grid upgrade.
I’m John Farrell, director of the Energy Democracy Initiative at the Institute for Local Self-Reliance, and this is Local Energy Rules, a podcast about monopoly power, energy democracy, and how communities can take charge to transform the energy system.
Gabe, welcome to Local Energy Rules.

Gabe Tabak:
Thanks, John. Great to be here.

John Farrell:
So I like to start off by just asking people how they got into the topic or issue or work that they’re doing. So I was curious if you could describe your career path to working on issues of transmission system upgrades. Is this what you dreamed of doing when you were in law school?

Gabe Tabak:
So I actually caught the energy bug before law school. I was a very junior staffer working in the Department of Energy in DC during the Recovery Act days, trying to help folks get a lot of federal money out the door to states and to companies that were trying to do, I guess, what seems now relatively early stage clean tech investments and realized that I really thought I could make a career out of this and talked to other folks who were more senior than me and decided I was going to go to law school specifically to do energy law, which was not the most common pathway, but worked out okay. I wound up working at the general council’s office of one of the big electric grid operators while I was in law school, and then from there to a law firm that specialized in energy, environment, and natural resources law.
And then after a little more than five years, I jumped over to the trade association side of what was then the American Wind Energy Association, the trade association representing the interests of the American wind industry writ large, which after a few years reformed itself as the American Clean Power Association, looking more broadly than just wind with solar and transmission and battery storage as well. And I guess it’ll be almost seven years at AWEA/ACP as we call it. And I should say ACP is a utility-scale supply side organization principally. That means that we work on really big projects that are connected at the transmission level. There’s really cool stuff happening at lower voltage and distribution level areas that I know you have talked about quite a bit on this podcast. Those are great areas, just not what ACP focuses on, which are the really big stuff that plug into the transmission grid.
A lot of the work that the renewable energy industry cares about, some of the major issues there are who has to pay to do the upgrades that are needed when you plug these big wind or solar or storage projects into the grid. Those are sort of crosscutting issues. They’ve evolved a bit in my time there, but remain really salient, figuring out how long it will take you to get a firm estimate of your costs and figuring out how high those costs will go are really make or break questions for getting more clean electrons onto the grid. Maybe should have said at the outset, what I’m discussing on the podcast are views that ACP as an organization has taken publicly in multiple contexts in front of FERC, in front of grid operators, in front of federal courts, but we have a big and diverse membership, so I want to be sure that everything I’m saying here should not be imputed to be the exact view of each and every member company of ACP.

John Farrell:
You’re transitioning perfectly into exactly what I wanted to talk to you about, which is this idea of network upgrade. So this is improvements that have to be made to the large scale high voltage transmission system for these large energy projects to connect to the grid and supply power. Can you give us a little context? How big are we talking when we talk about upgrades? How much do they cost?

Gabe Tabak:
That can vary really substantially, but the easy answer is a lot. They can be incredibly high voltage. They can be long distance. They can be high dollar amounts. I believe in one case, the largest I’m aware of is in Southwest Power Pool, a big central region of the country with a grid operator. There was a group of generators who were assigned a 765 kv segment that I think was over 130 miles long a few years back. And these can jump into the tens or even hundreds of millions in some cases. Often those are paid by more than one project, but these are absolutely massive components. And as you can imagine, with that amount of dollars at play, it’s difficult for a developer to know if a project is going to pencil until they have clarity on what upgrades they need to the grid to plug into.
The other thing I should emphasize too is that network upgrades are really just part of the transmission system at the end of the day. They are are parts of the transmission system that are identified through a different process. They’re identified as things that generators have triggered the need for. But once they’re up and running, you can’t distinguish them from the rest of the system. They’re not painted some different color. They’re not operated differently. If it’s a new transmission line, a reconductor transmission line, a new substation, those things are all part of the overall network, hence the network upgrade name. So these big, long distance, expensive upgrades in some cases become part of the overall transmission grid. They just have a different form of attribution in terms of what caused the need for them.

John Farrell:
I suppose that’s really not that much different. I think about sometimes you see a new commercial development, like maybe it’s a new Costco. If the Costco paid to expand the road to the Costco store, once the road is there, it’s a public road, everybody uses it, but it’s just who paid for it when it was initially built.

Gabe Tabak:
Yeah. Although the road analogy is one that gets used sometimes in this space. I think Rob Gramlich at Grid Strategies had a good one that he tends to use, which is that the way the interconnection queue and network upgrades often work is that if a new project wants to connect to the grid, wants to connect to that highway, the next project after you trip over some amount of traffic on that highway has to pay to build an entire new lane to the highway. And we can talk about how whether or not generators get paid back for those investments, but this is pretty clearly a silly way of designing highways is based on the willingness of each town that the highway goes past, being willing and able to put up the money to have an off-ramp and on- ramp to that interstate built there. The interstate highway system we have across the country would look quite different if the exits were determined only by the willingness and ability of communities along the way to fund the on-ramps and off-ramps, which in a simplified version can be what the grid looks like when you’re talking about these upgrades.

John Farrell:
Let’s talk about who has been paying for these kinds of network upgrades. So you have a new wind project or a new solar project. They apply to get in the queue to get connected. They wait a while to get this quote from the utility about how much it’s going to cost, and who’s going to end up paying that cost then that is quoted to that developer or set of developers?

Gabe Tabak:
An excellent question. And before I jump into the payment issues, because as with everything involving payment and large grid matters, there are lots of parties who disagree. So I’ll describe how the payment works and know that there are a range of views on whether this is a good thing or a bad thing, depending on which part of the country you’re in and which side of the equation you might be on.
So the default rule for who pays for these upgrades came to be under order 2003, which was FERC’s last big generator interconnection rulemaking, which came out in 2003, hence the name. And under that rule, the default, this is the thing that FERC determined in regulatory speak was just unreasonable across the whole country, was for a reimbursement method where generators would be studied for what it would cost to safely connect them to the grid. The upgrades would be identified, the generators would sign an agreement to pay for those things, the generators would fund those upgrades upfront, and then once the upgrades were operational, the generators would be reimbursed by the utilities whose system those upgrades were being operated as part of. So generator pays, other customers aren’t on the hook until there actually is something operational on the grid. And then once the generators are up and running, the upgrade is up and running, the utility pays back the generator typically over a 20-year period. And as the utility pays back the cost of those network upgrades, the upgrades become part of the utilities transmission rate base. So that means basically that the generator wears the risk upfront, but overall, as the network grows from a capital perspective, these upgrades are sort of treated as part of the overall grid once they’re operational. Utility customers aren’t on the hook for speculative projects, but they do pay for in-use and useful, to use the regulatory term, parts of the grid.

John Farrell:
Just one quick side question on that. Do you happen to know, when utilities are doing the reimbursement, are these projects being added to the rate base or because they’ve been paid for by someone else and this is like a reimbursement method, does it matter? Does that change how utility might normally have the asset on its books and how it might earn its rate of return through the utility regulators?

Gabe Tabak:
I think that, I am not a utility accountant so probably folks who really know the depths of utility accounting procedures and the uniform system of accounts could provide even more detail on this, but in general, once the utility is paying for that on a 20-year schedule, I believe that the share they’ve paid in becomes part of the rate base as the utility pays for it.

John Farrell:
It makes sense because then it’s treated just like any other thing they would’ve invested in.

Gabe Tabak:
Yeah. There’s a certain coherent internal logic to that approach.

John Farrell:
So let me get to kind of what is … So there’s a new idea out there now about how funding might work. I think if I have this right, it’s about, it’s called participant funding. I could try to summarize what I’ve read about it, but I think I’m just going to throw it to you and let you as someone who has probably handled this issue a lot more than me explain how this is different from what we’ve been doing.

Gabe Tabak:
Sure. So I think that it’s worth noting that participant funding actually sort of came into being at the same time as this reimbursement approach, but participant funding is a variation or what’s called sometimes an independent entity variation that is allowed in certain circumstances. It was authorized as that type of exception in order 2003. And the way participant funding works essentially is that in certain regions, and I’ll get to which ones and why, generators pay for these upgrades upfront, and then they are not reimbursed. So generators pay, the cost sits with the generator and the utility never reimburses them. So this is an exception to the rule in Order 2003, which is that generators pay and then get reimbursed, which FERC allowed only in the big grid operator regions, the independent system operators or the regional transmission organizations. So Order 2003 said that generally utilities have to reimburse, but we’re going to allow participant funding because we think that the grid operators are sufficiently independent, that they don’t have the same incentives as vertically integrated utilities might to charge basically independent customers who aren’t affiliated with utility different amounts for these upgrades, essentially that having a independent grid operator would address some of those competitive implications, which enabled this exception.
We’ve now gotten to a point where out of the six FERC jurisdictional grid operators, five of them, the California ISO is the only exception. The other five have all adopted participant funding, which means that the generators are assigned the cost for the upgrades, the generator has to pay for them in their interconnection agreement, and then they become part of the grid, but the generator is never paid back. The flip side of the coin is that because there is no utility reimbursement in most of those cases, and we’ll get to the exception on the exception, because there’s no utility reimbursement in most of those cases, the network upgrades don’t become part of the utility rate base. They’re funded by the generator. The utility’s capital is not involved, so these upgrades are operated along with the rest of the grid, but don’t earn a rate of return for the utility.
Those grid operator regions are so large that in a lot of ways, the exception has sort of swallowed the rule from order 2003. Participant funding is the norm in New England, New York, the PJM interconnection region, Southwest Power Pool, and then MISO we can talk about in a minute as sort of the variation on a variation.

John Farrell:
And if it’s fair to say that no matter if you have participant funding where they’re not reimbursed or the reimbursement model where they do get paid back, it’s still, the cost of that infrastructure is still sort of priced in, in the sense that the generator’s not going to be doing this out of the goodness of their heart. They’re going to have to recover their costs somehow in terms of doing those upgrades. So it’s less about the payments ultimately falling on customers overall and more about sort of the allocation of costs, whether it shows up in the rate base. And I suppose some element, as you talked about before, about who carries the risk for it, because under the reimbursement model, a speculative project, you’re protected from that because you’re not reimbursing until something’s actually built. And similar with the participant one, the customer’s never getting billed specifically for the transmission asset. They would only get billed if that project successfully connects to the grid and then is actually selling energy to presumably to recoup some of its costs.

Gabe Tabak:
Yeah. I think that’s the overall principle here is that the generators need to be able to make their costs and whatever return their investors are expecting and whether they’re going to be reimbursed by the utility or just sort of be stuck with the cost of those upgrades for the duration of the project life, they’ll have to be able to price the energy output either in a PPA or on a merchant basis at a level that lets them recoup those costs.

John Farrell:
Just out of curiosity, you mentioned before, ACP obviously is a diverse member organization, so there may be divergent views. I’m kind of curious, do you find that your members have a preference? If they had to choose, if they had the choice, would they prefer the reimbursement method or do they find at this point … I guess I just look at it as like, wow, you talked about tens or hundreds of millions of dollars for these upgrades. That seems like a lot to keep on your own books if there was a way to offload it by getting reimbursed by the utility as opposed to doing it through a PPA, but maybe this is just bean counting stuff and it doesn’t really matter. Does your organization have a particular perspective on that?

Gabe Tabak:
Speaking as a generalization, because again, I think there’s a diversity of views, there’s a diversity of risk appetites among generation developers and diversity of sizes and access to capital. But I think most developers who I’ve discussed this with would prefer the reimbursement approach because it means that a significant cost will eventually come back to them in an assured way, not just whatever the, particularly if they’re a merchant project, whatever the market bears in terms of the output of the project.
And then also just as an acknowledgement that when you build big high voltage upgrades in particular, those transmission assets benefits are not cabin just to the generator that might have been the initial cause for that upgrade being built. But if you add that lane to the highway, if you add a new substation or reconductor a line to accommodate a new generator, everybody who uses that transmission line, everybody who uses that highway derives some benefit.
And I think the preference that I’ve heard from a lot of folks in the developer community is that the reimbursement approach is a way to make sure that rate payers aren’t on the hook for, as you said, speculative projects because they don’t start reimbursing until they’re up and running, but it does acknowledge sort of the fundamental truth of multiple benefits from big high voltage grid assets getting added to the shared transmission grid.

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John Farrell:
We’re going to take a short break. When we come back, I ask Gabe to explain in more detail how self-funding relates to utility profits. We also do a full comparison of the three network upgrade methods, participant funding, reimbursement, and self-funding. And I ask how the self-funding approach fits into the broader issue of planning a transmission system that both anticipates and cost effectively meets grid needs. You’re listening to a Local Energy Rules podcast with Gabe Tabak, Assistant General Counsel for the American Clean Power Association.
Hey, thanks for listening to Local Energy Rules. We’re so glad you’re here. If you like what you’ve heard, please help other folks find us by giving the show a rating and review on Apple Podcasts or Spotify, five stars if you think we’ve earned it. As a bonus, I’ll gladly read your review aloud on the show if it includes an energy related joke or pun. Now back to the program.

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John Farrell:
So now there’s this new concept of self-funding, and that’s how I came across this issue, reading an article I think that you were quoted in or mentioned, or that ACP was mentioned in late last year. Could you talk a little bit about what self-funding means and how it’s related to the concept of participant funding?

Gabe Tabak:
Sure. Again, to be clear, developers really do not like participant funding. They do not like being responsible for paying for and then never being reimbursed for these big grid costs. But an element there in most regions is, again, that developers funding upgrades under participant funding. When they don’t receive reimbursement, that means that there is no utility rate of return on those upgrades. The generators just pay for it, and that’s that. They have to finance on their own.
Self-funding is the idea of basically allowing the utility to unilaterally determine that rather than having the generator, under participant funding, pay for the upgrade and weather the costs for the life of it, the utility will instead come and say that it wants to fund the upgrade and the generator that wants to be able to use it then needs to pay the utility both for the capital cost of the upgrade itself, as well as the utilities rate of return for usually a 20-year asset life or something like that.
And utility returns on equity are … They vary around the country, but those are in the ballpark of 10%. There’s a very convoluted backstory for how self-funding came to be, involving a number of zigzagging FERP decisions that went one way and then the other, and as well as several federal court decisions that ran in different directions. But where things stand today is that self-funding is allowed for the upgrades associated with new generation in the MISO region, and it’s become, I think, fairly common, if not universal, but fairly common for utilities to opt to use it there. And then there are a number of regions where there are open proceedings at FERC waiting to find out if self-funding will be allowed there.

John Farrell:
And it sounds to me … So if I had to compare the reimbursement model to the self-funding model, the reimbursement model, the generator is getting paid back over time. I think you said over 20 years perhaps. So if the utility is sort of capitalizing that project or making investments and getting to add it to their rate base, they’re doing so incrementally. And so the returns that they might be earning are sort of out in the future. This one sounds like essentially you’re collecting everything upfront on a fairly expensive project. You’re getting the capital cost and you’re getting your rate of return all at once. Am I getting that right?

Gabe Tabak:
Well, there are what are termed facility service agreements. The generator basically has to fund an account that pays the utility over time, but when you include a 10% rate of return over a 20-year lifespan, that dramatically increases the amount that the generator has to pay versus in most cases, financing itself. Or at least I shouldn’t oversimplify that. I think there could be some circumstances where depending on the availability of capital and the terms to a particular generator, it could actually make sense to go to the utility for financing for the upgrades, but what self-funding does is it removes the choice for them so that where self-funding is opted for and a generator, I’d say often grudgingly, goes along with it, they have to provide enough funding upfront as well as security for the 20-year life. So it ties up more capital and it also increases uncertainty because the utility ROE can change.
If the utility goes to a regulator, gets a higher rate of return, then the amount that the generator has to pay upfront may itself change based on the rate of return that’s being put in there. So there’s both the significantly increased cost, which 10% return over 20 years, estimates that generators have put in front of FERC to make a case on this issue have indicated that can be as much as doubling on a pure dollar for dollar basis over 20 years. It could be … If you account for net present value where the value of a future dollar is discounted relative to one today, then it could be something closer to the 30 to 50% mark. But when you’re talking about tens or hundreds of millions of dollars in upgrades, that can be a pretty significant increase, plus the increase in uncertainty. It may not be a fixed cost. And with the security requirements, it may tie up more capital for longer than what otherwise have been the case.

John Farrell:
Yeah. Okay. So we’re talking about more money upfront because we’re talking about including the utility’s return in that and more uncertainty because you don’t necessarily know what that rate of return will be over 20 years because the PUC gets a rate case, they have another chance to evaluate, it could go up it could go down.

Gabe Tabak:
Yeah. And those are all elements that make self-funding really problematic for developers who really … Ideally, they would love very fast decisions on network upgrades, figuring out what is going to be needed. They would like affordable network upgrades that don’t come up with insanely expensive upgrades, but above all is certainty. They need to know when they’re going to get decisions, they need to know what it’ll cost, and they need that not to change. And I think that self-funding has really been problematic on all of those.

John Farrell:
I liked how you described that. Fast and affordable would be great. Certainty is probably even more important if you can’t get the first two. And I’ve heard, I think many people who follow energy issues at all know that fast is not generally associated with getting a grid interconnection.

Gabe Tabak:
Yes, it’s big infrastructure. It takes a long time. And in terms of other things that are also are well known in energy circles, not to be fast, but for somewhat related reasons, building new transmission, also not fast. And network upgrades at the end of the day are just transmission. We’ve just sort of created a parallel process for building and paying for transmission that, again, comes back to the willingness to pay of individual generators, which is not an ideal way to run a large, multi-state, high voltage grid that everybody uses and everybody benefits from.

John Farrell:
I want to come back to that question in just a second about how this fits into the bigger transmission planning issue. I want to just get it really clear for myself about the sort of reimbursement method, the participant model, and the self-funding. So I’m going to run through this and see if this makes sense.
So let’s say you have a network upgrade, a transmission line that we’re building, and we’ll say for the sake of simplicity, it costs $100, which boy, that would be amazing if you could make any upgrade for a hundred bucks, right? So I’m obviously orders of magnitude off, but just for simplicity.

Gabe Tabak:
To add a few zeros in real life. Right. Yeah. Right.

John Farrell:
So as a $100 upgrade, under the reimbursement model, the developer, the project developer pays that $100 upfront. They build the asset, they connect their project, they get paid back over time by the utility. And then I’m going to use these numbers that you gave when you were talking about the net present value of the utilities rate of return. You said it was like 30 to 50% higher. So I’m just going to say somewhere between $30 and $50 is the return that that utility is going to earn on that hundred bucks, but they’re going to collect it from rate payers as they pay out the reimbursement to the developer. So all of the risk associated with any kind of like adjustment over time is between the utility and the regulator and the customer. It’s kind of off the books and out of not part of the concern for the developer.
So that would be the reimbursement model.

Gabe Tabak:
The only qualifier to add there is that the developer does have to worry about it when they’re actually funding and paying for the construction of that upgrade. But then once it’s operational, there’s sort of the shift. So the generator pays for it while it’s being built, and then it sort of transitions with that reimbursement to being treated as part of the overall transmission grid, like any other transmission line or substation.

John Farrell:
Yes, I appreciate that. So then there’s the participant model. The participant model is the developer just pays the hundred bucks and the consumer sees that $100 somewhere in the agreement that is generally, that might show up if it’s a merchant plant and how much they sell are willing to sell their power for. It might be if they have a power purchase agreement in the rate that they’re agreed to sell power in, but it’s sort of priced into that agreement in some way is how the developer is recovering it. So developer really carries even, I would say probably even more of the risk, because now they have a performance risk of can they actually produce the energy to earn the money to pay back the cost under the participant model?

Gabe Tabak:
Yeah. With a participant funding model, generators do have certainty. It just means that they know that they, as part of that certainty, they know they will not be getting any money back for funding it. So if they have to find out they have to pay $100 in this instance, yes, they just have to make sure that whatever they’re going to write into a PPA if they have a long-term off-taker or price their power at, if it’s a merchant plant, needs to be able to, over the life of the generator, recoup the cost for that upgrade.

John Farrell:
And presumably, and we know in that case, the utility at least is not earning a return. Maybe their developer has to price the risk of carrying that cost somewhere in their product, and so there’s some kind of earnings there, but ultimately the utility is not earning its rate of return on this because they’re not paying for anything as part of this network upgrade.

Gabe Tabak:
So the utility doesn’t earn a return. The network upgrades do get included as part of the overall transmission system for operations and maintenance, which is the operational expenses for utilities, which historically do not result in a rate of return. So the utilities do make sure that the towers for the transmission line are in good repair and make sure that nothing is going to be falling apart for those upgrades, they just don’t get to include it in their profit making part of their capital rate base.

John Farrell:
And then under this new-ish self-funding model, which is basically the utility decides unilaterally, I’m paying for this upgrade or the developer’s paying me for this upgrade and they’re including my rate of returns. And now the developer’s paying directly to the utility, not the $100 for the project, but the $130 to $150 that also includes the utilities return requirements. It may be over time, it could be upfront, but that ultimately the developer is essentially paying all of that out of pocket to the utility.

Gabe Tabak:
It’s typically over time. I think generators, again, if they want cost certainty, they would be happier paying a large dollar sum that included a rate of return upfront and being done with it rather than having it spaced out with the associated security requirements. So yeah, the typical formulation is that the utility will fund it and sets a schedule for repayment, and then the generator has to repay it over the, again, usually something like 20 years that covers not just the cost of construction for it, but also the rate of return for the utility and providing that capital upfront.

John Farrell:
So I want to come back to the topic you mentioned previously about sort of the larger transmission system planning. So I’ve had other guests on the show, Ari Pesco, Shelly Welton, Claire Weiner, who have all said in one way or another that the transmission planning process is sort of broken in one way or another. In terms of both how we develop the regional plans that are for how we’re going to expand the system, but then also how the execution of those plans plays out in terms of how utilities put their thumb on the scale about what gets built. How does this issue about how we do reimbursement or participant funding or self-funding fit into that? What are some of the things that ACP looks at when you think about how we can do this, how we could handle the idea of upgrading the transmission system to bring on affordable clean power more effectively?

Gabe Tabak:
Yeah, great question. And yes, transmission planning and transmission cost allocation on the other side of the coin have been pretty problematic and slowly improving, I hope, but behind where they need to be areas of the electric grid and associated policy. I think that the interconnection process and network upgrades are really sort of the genesis of all the problems here and participant funding and self-funding have just layered upon that original piece because the idea of treating transmission assets differently simply because they were initially identified for generators really gets away from what a lot of grid planners and some of the folks you’ve had as guests have noted are the multiple benefits that large, high voltage, long distance transmission provides to everybody who uses it. And I should be clear here that generators absolutely do use and benefit from large high voltage transmission assets and developer members are not opposed to paying their fair share. But what has been deeply inefficient is essentially having a parallel transmission planning process that runs based on the willingness to pay of particular generators rather than putting the anticipated needs for new generation alongside reliability needs, alongside economic benefits to all customers from being able to access cheaper generation, these days from the needs of new large loads interconnect to the grid, all of these are benefits and have beneficiaries that will be directly impacted by the ways we plan transmission, and it’s far more efficient to do that holistically than it is to do it on the piecemeal approach. And network upgrades and fiscal funding, self-funding, those are very much the symptoms of a piecemeal approach.

John Farrell:
I’m kind of curious because I’m thinking about, okay, so let’s say the planning process, let’s just wave a magic wand and say the planning process is really good now. It’s doing a comprehensive look at a region. It’s not biased toward any one particular utility company or their self-interest. It’s really focused on where are cost-effective interregional connections, where cost-effective places to do new generation. Let’s say you’re a developer and darn it, the place where you wanted to build your project where you’ve already got some land rights and whatever is not part of that plan, what would happen in that situation? Is there still going to be sort of a right to self-fund or like to … Or sorry, not self-fund, but would there still be a right for a developer to come and say, “Hey, this is not part of your regional plan, but we still think that this would work here and we are willing to pay for an upgrade.”
Or would the idea be more the planning process is really robust and lots of new capacity would be opened up through that. And so people will have ample opportunities and we would sort of limit network upgrades to being those that were done through a really good planning process. I know that’s kind of hard. I’m asking you a tough question here because we obviously know that the planning process has never been done this well. So maybe that’s a little unfair, but yet I will pose it to you anyway.

Gabe Tabak:
Yeah. I mean, I think that the general thesis for a lot of folks in the generation development community is that a more robust and proactive and holistic transmission planning process would drive down the cost and probably average voltage level of network upgrades. If we’re building transmission based on sort of all of the anticipated needs well in advance and looking at how everybody would benefit from it, the overall thesis has been that would gravitate towards building a bigger, better transmission grid, which wouldn’t result in generators being assigned 765 kV elements that are 130 miles long. They would be assigned shorter and lower voltage elements that enable a particular location to plug into that larger backbone grid.

John Farrell:
Alright, that makes a lot of sense. So if I dare go back into the road analogy, you have a robust socialized investment in the transmission system. And by socialized, I just mean paid for by customers broadly for the broad benefits. And so it is no longer as expensive. You’re not building lanes of interstate highway in order to bring your project online. You really are just being able to build a small on- ramp or something like that instead.

Gabe Tabak:
Yeah. I think that’s the general thesis is that you’re not essentially subsidizing that new lane of the highway based solely on the one small town that you’re treating as the cause for that new on- ramp. That small town might pay for a share of highway expansion, but the toll that everybody who uses that highway pays helps fund it as well. And that sort of acknowledges the real truth of highways, electric grids, which is that everybody who uses them benefits from them in some way. And the cost allocation has been the source of many, many fights at regulators and in courts in terms of folks claiming that they are being assigned costs for benefits they don’t receive. I don’t want to pretend any of this stuff is easy, simply that it is equally inaccurate in the other direction to pretend that nobody benefits from high voltage upgrades that generators are paying for.

John Farrell:
And in terms of like the current state of play, you gave an overview about where self-funding is permitted right now in MISO and that there’s some other proceedings. It sounds like from the news about this, that the Federal Energy Regulatory Commission, FERC, intends that projects would have a choice about whether to fund themselves or to ask the utility to do the self-funding of upgrades, but that some utilities have filed a lawsuit to actually stop that ruling. So I’m kind of curious, what’s the status of that dispute? What are you seeing as the likely outcome here? Is it that FERC might make a ruling and roll back the MISO unilateral decision making power of utilities here, or we’re going to see this expand in other places?

Gabe Tabak:
That’s a great question. And I think only FERC knows what it’s going to do here, but the proceeding you’re alluding to is one that FERC issued in 2024, which again, this issue has zigzagged all over the place with different formulations of FERC commissioners and different judicial panels and federal courts coming out different directions on it. But the most recent substantive action that FERC took was in 2024, they found that four grid operator regions, MISO, SPP, PJM, and ISO New England had language in their tariffs, their market rules that appeared to allow self-funding, which for terms transmission owner initial funding is the technical term of art for it. And this order was termed a show cause, which said to those four grid operators essentially, “Tell us why we shouldn’t find that it’s unjust and unreasonable for utilities in your regions to be able to opt for self-funding, transmission owner initial funding.”
MISO is the region that has been most used in. PJM is in a weird posture because the PJM transmission owners sought the ability to add it and there is still an open hearing that has been rolled into the show cause so they can sort of do it while the hearing is pending, but it could also be unwound. And then Southwest Power Pool has some language that appears to allow it, but FERC rejected the ability to come up with a standardized contract for generators to repay, which means that if utilities there want to use it, they need to come up with a bespoke agreement with generators. And it’s hardly been used at all in ISO New England. This appeared to be tariff language that almost nobody was using. So a real range there, MISO again has the most developed and most common use of this.
And the show cause order was fully briefed as of late 2024. I think the last, there were a few filings in early 2025, but the composition of FERC has completely changed. Not a single commissioner who voted on that show cause is still there. And we haven’t seen any activity from the current FERC composition on this issue at all. So the proceeding is still open. I think that they will act on it eventually because in addition to an open hearing, they also have a remand from the DC Circuit regarding the status of self-funding in MISO in particular. So between the proceedings that FERC opened itself and what the court sent to it, they will have to deal with this eventually, and they seem to sort of have collapsed this into a one really big interrelated proceeding hitting four regions, but we don’t know what they’ll come out with and when.
And the last item, some of the transmission owners did try and sue FERC over the show cause order. FERC prevailed in getting that suit dismissed in the Eighth Circuit Court of Appeals, contending that basically it was premature because the show cause order was the tell us why we shouldn’t do this declaration to the grid operators and the utilities, but it did not come up with any final requirements that bound anybody to do it. So FERC made that case to the court and the court said, “Utilities, you’re here too early,” but I fully expect that if and when FERC were to finalize the show cause, this will be back in federal court once again.

John Farrell:
Wow. Gabe, thanks so much for joining me to talk about this really complicated issue and correcting all of my attempted road analogies about this so that people hopefully can get a better understanding of how this works. I know it’s complex, but it feels really important in the context of how we do transmission planning and paying for our transmission system. So I appreciate you coming to try to decomplicate this for me.

Gabe Tabak:
Absolutely. And John, really appreciate the work you’re doing in terms of shedding light into some areas of electric policy that are not commonly understood. And network upgrades are, again, sort of wonky, sort of in the weeds, but it’s impossible to bring big wind and solar and battery projects online unless they can figure out what they’re going to have to pay and to who to connect to the transmission grid.

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John Farrell:
Thank you so much for listening to this episode of Local Energy Rules with Gabe Tabak, assistant general counsel for the American Clean Power Association, about
On the show page, look for links to a news article with an overview of the issue and a commentary from Harvard Law Professor Ari Pesco about the self-serving nature of utility self-funding. We’ll also have links to three great related Local Energy Rules podcasts, including episode 149 with Ari Pesco about the utility transmission syndicate, episode 219 with Shelly Welton about solutions to the problems of utility manipulation of transmission planning, and episode 233 with Claire Weiner about the loopholes in approving utility built transmission upgrades.
Local Energy Rules is produced by myself and Ingrid Behrsin with editing provided by audio engineer Drew Birschbach. Tune back into Local Energy Rules every two weeks to hear how we can take on concentrated power to transform the energy system. Until next time, keep your energy local and thanks for listening.