How Utilities Evade Grid Regulation — Episode 233 of Local Energy Rules

Claire Wayner:
Particularly now with concerns about rising rates. I do hope that the time is ripe for FERC to start looking at addressing this issue and closing the regulatory gap. Because first and foremost, this is an affordability issue.

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John Farrell:
How big does a loophole have to be in order to drive a transmission line through it? A FERC order 1000, approximately. The battles over clean energy progress at the local level have often been in the news such as utility-funded efforts to slow rooftop solar in California. But utility opposition to large scale clean energy progress has been as significant, even if it’s buried in more obscure regulatory proceedings. It’s all about the same thing: profit.
Over the past 10 years, utilities across the country avoided building large scale regional transmission lines that would’ve provided capacity for new wind and solar projects, and instead poured their money into incremental projects with little regulatory scrutiny.
Joining me in March, 2025, Claire Wayner, a senior associate with RMI’s Carbon-Free Electricity Program, explains the regulatory gap and how utilities built smaller transmission lines close to home and pursuit of profits at the expense of more useful regional transmission capacity that would’ve exposed the utilities to competition and oversight.
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.
Claire, welcome to Local Energy Rules.

Claire Wayner:
Thank you so much for having me. I’m so excited to be here.

John Farrell:
So I always love to ask my guests to give me a little bit of background. How did you come to doing research and writing on transmission regulatory gaps? What got you into this field?

Claire Wayner:
Well, what first got me interested in the energy space was actually birdwatching. I am an avid bird watcher. I started watching birds in middle school and began to notice already trends in bird population declines with rising temperatures and climate change, and so became interested in some of the solutions behind reducing emissions and ultimately protecting bird populations from the impacts of climate change. And came across what a lot of decarbonization studies were showing, which is that we needed more transmission to enable a more efficient energy transition that also helps save consumers money and enhance reliability.
When I joined RMI, my team knew that building more transmission was a critical part of maintaining grid reliability and affordability through the energy transition in the years to come. And I had begun looking at transmission build data for PJM, which is one of our country’s regional transmission organizations in the Mid-Atlantic, and started to notice an interesting and somewhat disturbing trend that, in recent years, utilities in PJM had been investing more money in these local projects. In PJM, they’re called supplemental projects that are not subject to nearly as much regulatory oversight by PJM or by state regulators or by federal regulators.
So utilities have been investing more in these supplemental projects and less in these more efficient regionally planned projects. And so that trend in the data piqued my interest and I started to look more into that issue first in PJM, came out with a blog post on that about two years ago, and then that’s spark my interest in exploring this topic on a national level, which is what informed the release of our report last fall called Mind the Regulatory Gap.
So while the birdwatching and the climate piece got me into this space, as I’ve learned more about transmission and the world of energy, I’ve realized how crosscutting these issues are and how important investing in our grid is in a more efficient way to keep costs low, keep the lights on during extreme weather events and all of these other co-benefits.

John Farrell:
I mean you just did a great job actually there of transitioning and talking about why this issue matters. You talked about affordability, but let’s talk about why this issue is mattering so much right now, which is really getting pretty poor results. So you talked a little bit about PJM in particular, but can you talk about what’s been happening with transmission capacity in the US since the adoption of FERC’s order 1000 nearly 10 years ago, and why does what’s happening with transmission capacity matter in the context of climate change, clean energy deployment, electrification affordability. FERC by the way, is the Federal Energy Regulatory Commission. It usually issues regulations about interstate transmission.

Claire Wayner:
Yeah, I mean, as I alluded to, there have been multiple studies that have come out from academic institutions, from the Department of Energy and various national labs in the US that have shown that an energy transition is most affordable if we’re able to pair these more small scale distributed solutions with broader connectivity across regions.
If it’s windy in one region of the US and not in another, having more connectivity via more regional and interregional transmission can enable sharing of lower cost power. And that’s particularly important in a more decarbonized system. But really regardless across the board modeling has shown that more transmission and regional and inter-regional connectivity can also lower cost for consumers by enabling that sharing of lower cost power. So I think what’s at stake here if we don’t improve our transmission planning processes is we could see continued high prices for consumers.
I’ve seen headlines in the last couple weeks about various states struggling with residential bills rising. And so investing more in our system can definitely pay off in the long term to keep those bills lower. And we’re also looking at a decreased resilience and reliability across the system. Right? Winter storm Uri in Texas is an excellent example of what happens when you don’t have connectivity to other states, right? Texas’ grid is unique in that it is limited to just the state of Texas and they saw terrible results during winter storm Uri. So those sorts of extreme weather events also justify the need for more transmission and illustrate what can happen if you don’t have enough connectivity.

John Farrell:
Can you just talk sort of in general about why we haven’t been getting more transmission? What are utilities building instead of building the kind of regional transmission that would address those issues of reliability and affordability?

Claire Wayner:
This is the paradox that’s at the core of the report that my colleagues and I came out with last fall, and we call it the regulatory gap.
So in the US there are a couple different types of transmission projects. There are local transmission projects which are designed and built by a utility to meet only their needs within their own service territory. And then there are regional and inter-regional transmission projects which are planned by these planning entities like regional transmission organizations, RTOs, and RTOs go and plan more efficient transmission investments that meet their regionwide needs or in the case of interregional could meet needs across multiple regions.
And it’s similar to the national highway system. It would’ve been extremely inefficient and probably impossible for each state to go at it alone and try to build a segment of a highway, right? We needed broader interstate coordination. And so that’s what regional and interregional transmission planners provide is they provide that broader coordination and more efficient effective transmission spending.
However, in recent years as we talk about in our report, we’ve actually seen the opposite trend of what we want to see for reliability and affordability. We’ve seen utilities invest more in these local transmission projects and less in these regional and interregional transmission projects. And the reason for that is what we call a regulatory gap. So in many cases, local transmission projects are not subject to oversight from state or federal regulators. They are not comprehensively studied by a regional planning entity. So in many cases, utilities are able to recover the costs of these local transmission projects without a regulator looking at that project with great scrutiny, whereas regional and inter-regional projects frequently have to undergo review. They are not only planned at the regional level, which is sort of a type of review in and of itself, but they often have to go through more state or federal review than local projects.
If you’re a utility with these incentives in place, if you’re able to earn the same return on your investment on a local project versus a regional project and a local project is subject to less oversight and is perhaps a more trustworthy investment in that you have greater certainty that it’s going to get approved because it isn’t subject to as much oversight, what would you be investing your money in? And so the key component of our report is talking about how utilities are just incentivized to invest in these local projects because of the lack of oversight. And so it’s up to regulators to work to close this regulatory gap.

John Farrell:
I want to ask a just tangent question really quick from my little bit of work on transmission projects. It would seem that even the local projects might have to go through some sort of siting process through a state commission. Is that right? There’s still some activity, but maybe not have to go through regulatory approval for the actual investment itself?

Claire Wayner:
Yes. So local projects do still have to undergo review in some cases, but there are often exemptions in place. So one example is many states, when they’re issuing a permit for transmission projects, and that permit is called a certificate of public convenience and necessity or a CPCN. It’s issued by the Public Utility Commission frequently in many states that require CPCNs, they have a voltage threshold below which transmission projects do not need to get a CPCN.
In some states, the voltage threshold is as high as 345 kilovolts, which is very high to set a voltage threshold. For context, many local projects are being built at 69 kilovolts or 138 kilovolts. And these voltage thresholds were put in place to I think reduce the permitting burden on the PUC, but a result has been that many PUCs are not reviewing projects below that voltage threshold. And so that’s an opportunity for utilities to get projects basically approved with no CPCN review.
Another example is that many states exempt rebuilds of existing infrastructure from getting a CPCN, the justification is that you’re just rebuilding something on an existing right of way, right? Why would you need review? But a lot of these local projects are rebuilds of aging infrastructure, and so they also are exempted from receiving a CPCN.

John Farrell:
It’s so interesting about the voltage threshold too because as I understand it, there’s a pretty significant non-linear payback to higher voltage in terms of your capacity. So if you’re sliding under certain voltage limits to avoid regulatory scrutiny, you may also be dramatically decreasing the amount of capacity you could be adding if you had been willing to build that or if the demand had really indicated you should have built it at a higher capacity.

Claire Wayner:
Absolutely, and that’s a key illustration of why this over-investment or rather increased investment in local transmission could be resulting in highly inefficient outcomes for consumers. Because in states with these voltage thresholds, utilities are incentivized to build below that voltage threshold and that’s resulting in less efficient spending potentially than streamlining it and looking at can we build one more efficient solution at a higher voltage than ten projects at this voltage that just happens to be below the threshold?

John Farrell:
You’ve already described the sort of loophole in the FERC order for order 1000 about these local projects versus regional projects. So in the report – reminding people, it’s called Mind the Regulatory Gap, which by the way, I absolutely love the title – a big fan of puns and double meaning at the Institute for Local Self-Reliance. But you note that a lot of the problem about this kind of loophole is due to the sort of split jurisdiction over transmission lines and that FERC and the states are sharing some authority here. Can you talk about or maybe provide some examples of how this split in authority causes problems for accountability, such as how rates of return are set for utilities when they build transmission?

Claire Wayner:
So I already described how for states, often they are not reviewing these projects through the permitting through the CPCN process because of voltage thresholds or rebuild exemptions. So if the projects aren’t getting a permit at the state level, you would think, well, maybe through the rate making process when a regulator needs to come in and say, these costs were prudent and necessary, these projects are going to get reviewed.
Now, in most cases in the US transmission rates are set by FERC, not by state PUCs because transmission is considered interstate commerce, right? Exchange of electrons across borders. And so FERC in their right making structures however, often uses what’s known as formula rate-making, which involves approving an initial formula for how a utilities rate is set. And then once that formula is approved, the utility just submits annual refreshed inputs to that formula saying, here’s how much we spent in this year, here’s how much we’re going to spend.
And then FERC importantly in the formula rate, making structure presumes prudence. So what that means is they automatically assume that the cost incurred are necessary to be reimbursed unless a third party intervenor comes in and questions why utilities input is this dollar amount.
And so what frequently happens in these formula rate cases can be very dense and difficult to understand and can require a lot of manpower to intervene. And so state PUCs or state consumer advocates often don’t have the resources to be intervening regularly in FERC formula rate cases. And so what often happens is formula rates at FERC turn into essentially a rubber stamp process where utilities can submit whatever annual inputs they would like to submit, and FERC just approves them because again, prudence is presumed. And so the issue with formula rates and local projects is if the local project didn’t have to receive a CPCN at the state level, and then it’s going to FERC for ratemaking, and FERC is saying, yes, we’re presuming prudence on all of these local transmission costs, these were prudently incurred, and if no one’s intervening in that case, then that rate gets automatically approved and sent back to the states to figure out how to recoup that money from ratepayers.
And so on the ratemaking side, we often don’t have oversight of these local projects either. And that layered jurisdiction, as you said, creates a lot of challenges too for states because they again don’t have that ratemaking authority. Maybe they aren’t granting a CPCN and a lot of these local projects, I’ll also note, can span state boundaries. And so even if a state is granting a CPCN, it could find itself in a situation where it’s dependent on other states’ decisions as well on the local project. And so that interstate dynamic also makes it difficult, and it’s why in our paper we ultimately recommend that FERC address this issue first at the regional planning level, which is what a lot of state level stakeholders who we interviewed for the paper noted that again, this is not something that you can just solve at an individual state by state level.

John Farrell:
You mentioned that the formula rates, there’s a presumption of prudence, which is not just a fun word to throw off here, but actually has legal significance. Does that also mean that if you were the third party to intervene and say, oh, this transmission line really wasn’t a prudent investment and here’s our receipts for that, is the burden of proof on the intervenor to then show that that’s the case? It’s not like I can go there and say, no, actually make Excel energy show its receipts or PSEG show its receipts. It’s actually I have to have the evidence to convince FERC that their formula rate is not appropriate in this case.

Claire Wayner:
Yes, you’re absolutely right. The burden of proof is on the intervenor. And this gets to a key issue in ratemaking in general, which is the concept of information asymmetry. So these intervenors are only able to prove imprudence based on information on the investment that the utility has revealed, but often intervenors find themselves in an information asymmetry where utilities may have more information on the cost of the project that they have chosen not to share. And so that can make proving imprudence particularly difficult.

John Farrell:
I don’t know if they don’t share it or maybe they share it and they say it’s proprietary. That’s my favorite one.

Claire Wayner:
Yeah, redacted information is very common in these local transmission processes, either redacted information or just very, very simplified information that makes it really difficult to make a case about prudence

John Farrell:
Every once in a while on energy Twitter or Blue Sky or wherever we live now, I think it’s Simon Mahan is probably my favorite, but he’ll post some of the documents from some of these discussions and it’s just mostly black boxes overall of the kinds of things with a few prepositional phrases that are still available for viewing. So I think a good highlight in pictures of what we’re talking about.

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John Farrell:
We are going to take a short break. When we come back, I ask Claire about a particularly egregious example of shooting the regulatory gap in New Jersey, why FERC has taken so long to respond, and she explains how a “regional first approach” to planning could close the loopholes. You are listening to a local Energy Rules podcast with Claire Weiner, a senior associate with RMI’s Carbon-Free Electricity Program.
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John Farrell:
One of the things that I thought was lovely and actually caught my eye about your report was that Canary Media did an article about it and gave an overview of the findings and of the issues in it. And in that article there was an example of a transmission line built by New Jersey based utility, PSE&G. I thought it actually was a pretty good example of how in terms of this regulatory gap, could you just talk through how that proposal was designed and how it ended up in that regulatory gap?

Claire Wayner:
Yeah, so in New Jersey, New Jersey is actually one of the few states in the US that does not require CPCNs at all on a state level for transmission projects. So transmission projects in New Jersey in terms of a permitting side, like from the land use side, have to get approval at the township level. And then I think there is a process to appeal it to the New Jersey Board of Public Utilities. That’s their PUC at the state level, if there are any siting and permitting issues at the local level. But typically the PPU is not issuing permits for transmission lines in the state. And so what ended up happening with this PSE&G line was FERC staff did discover that there were imprudent components of this local project investment, that the utilities had proposed or described higher costs than what the project actually entailed.

John Farrell:
And I thought the example was fairly colorful in the sense that they were saying essentially, we’re rebuilding a line and we’re going to have to replace all these concrete footings. And it was something like an order of magnitude more replacements in the bid or in the description of the project that actually needed to happen. If I remember correctly?

Claire Wayner:
What is particularly illustrative about that example to me is that someone actually caught that. And the concern with this regulatory gap is that a lot more of these local projects could be suffering from that same degree of inflation, but again, because they aren’t receiving adequate review, it’s very difficult to determine whether those figures are being inflated by utilities. So often people ask, well, how much more money are we spending than we should be spending on this regulatory gap? And my answer is always, the problem is that we don’t know. In the case of this PSE&G project, someone did catch that over inflation. There’ve been a couple other examples. There’s a case study on a project from New England in our paper as well, but by and large, my broader concern is that this sort of scrutiny is not happening with most local transmission projects.

John Farrell:
So Ari Pesco from the Harvard Electricity Law Initiative was on Local Energy Rules in 2022 to talk about his research on what he called the utility transmission syndicate. And I’ll have a link to that podcast in the show notes. And he talked about how utilities exert their power over this regional planning process, in particular. It seems like your work is building on that or is complementary to his assessment with some very specific recommendations, which is lovely. Why do you think though, that it’s taking so long to get an effective response from federal and state regulators? I mean, this loophole in the FERC order 1000 has been present for a decade. Why do you think it’s taking so long for them to try to solve this, to close that loophole?

Claire Wayner:
I think one thing that you just alluded to is sometimes it takes a couple years to see a trend emerge in the data, right? So when order 1000 was enacted, maybe it would’ve been difficult at that time to point to the loophole and be like, this trend is going to happen, right? But a decade plus later we have the body of evidence illustrating that this is an important issue.
FERC held a technical conference on this issue back in 2022. So I do think it has been gaining traction in recent years. I think there’s been a number of factors. I mean, so at the state level, I think many states have been sounding the alarm, but as state regulators noted in interviews for our report, the vast majority of them have felt like this issue needs to be addressed federally or regionally through FERC. So at the regional planning entity level, because again, a lot of these projects do span state boundaries and do need that regional level planning review.
Then FERC actually did start to take some steps to increase local project review and scrutiny and also better co-optimize local and regional planning through a process called ‘right-sizing’, which looks at the ability of local projects to be adjusted in size, adjusted upward in size to also address regional needs. So those right-sizing provisions and local project transparency provisions were included in order 1920 and affirmed in order 1920A both last year. So that is a sign that again, FERC is starting to think about solutions in this space.
There was a complaint filed by various consumer groups at FERC at the end of last year, and there are comments due in that docket in around late March 2025. So I think that this issue is continuing to gain traction. I think FERC just in recent years has demonstrated different priorities through interconnection reform with order 2023, and again, the vast majority of 1920 focused on long-term planning. But I think particularly now with concerns about rising rates and affordability, I do hope that the time is ripe for FERC to start looking at addressing this issue and closing the regulatory gap. Because first and foremost, this is an affordability issue.

John Farrell:
In your report. Claire, what do you recommend for fixing the regulatory gap and how do you see those recommendations resulting in more transmission capacity at a more reasonable price?

Claire Wayner:
I would say the biggest reform that I would love to see happen is expanding on the right-sizing provisions in 1920 and requiring all regional planning entities to do what we call in the report ‘regional first planning’, which would require examining local and regional needs simultaneously, identifying more efficient regional projects to meet those needs simultaneously, and then allowing for local projects to get built only to meet remaining needs. Because right now the hierarchy of transmission planning in the US is very much local-first, regional kind of cleans up some of the remaining needs.
And so we’d like to see that hierarchy flip and prioritize more efficient regional planning over this local planning. I think there are other steps that state and federal regulators can do. So FERC can look at reforming its formula ratemaking process to enhance scrutiny for projects that have not received adequate review at the state or regional level. So if a project hasn’t received a CPCN from a state regulator, that project should not be presumed prudent through the formula rate making process. And I think it’s just a matter of adjusting those incentives to incentivize an easier rate making process for projects that have been planned regionally and have been scrutinized at the state level. So that’s another example of reforms that FERC could do. FERC could look at adjusting the ROE, the return on equity, for local projects, adjusting it downward because local projects are often lower risk.
And then at the state level, states I think can double down and take a look at if they do have a CPCN process, what is their voltage threshold? Is it too high? Are they seeing a lot of transmission get built below that voltage threshold? Should they consider adjusting the voltage threshold downward or somehow introducing maybe a lighter lift permitting process for projects that maybe don’t require that level of scrutiny of a large greenfield line. Maybe it’s a rebuild and a lower voltage asset, but still ensuring that they are getting some sort of review by the PUC. So those are just a sampling of the recommendations in the report. We have a couple others in there as well, but I think the key theme from the report is we need action from state regulators and from federal regulators and action at the state, regional and federal levels to fully close this gap.

John Farrell:
Shelly Welton joined me on the podcast last September to talk about a report that she wrote for the Hamilton Project advocating for an independent federal planning authority. It would essentially provide a blueprint or default regional transmission plan for utilities to follow. Is that idea compatible with your recommendations and either way, what do you think of that idea that someone like DOE, for example, I think she mentioned could do this, would sort of develop a default plan of regional transmission buildout and that would drop into these regional transmission organizations or regional planning processes as the default being developed sort of independently from the utilities that as we know, have these mixed incentives in terms of what they want to build?

Claire Wayner:
I think that idea is definitely in line with our regional first planning recommendation in our report. In our report, we still kind of preserve the regional planning landscape in the US, but just recommend that the regional planning become more rigorous and robust and fully include consideration of local projects and right-sizing.
And Shelly Walton’s idea it sounds like builds on that and looks at more of a national planning view, which I think the US could really benefit from. Today in the US we are not seeing much of any investment in inter-regional transmission, which has significant potential to reduce costs for ratepayers. And that’s due to a number of different factors. And I think higher level bird’s eye view planning can help to overcome a lot of those factors. And then for regional planning entities that are not RTOs, so in non-RTO regions of the US, we really haven’t seen regional transmission planning happen in an effective manner. By and large utilities are the ones doing the planning there without that regional level review for more efficient planning. And so I also think that this idea of regional-first planning can be particularly effective and result in significant cost reductions in these non-RTO regions as well.

John Farrell:
This is a little bit outside my knowledge area, so just going to ask the question I need to, which is, so take the Southeast, which does not have an RTO, their sort of ‘regional plan’, and I’m putting that in air quotes, is someone don’t described it as the sum of the individual utility transmission plans, right? There’s not really any kind of significant coordination going on to say, oh, if we built a transmission line across these three states, it could meet all of these local needs at the same time.

Claire Wayner:
Exactly. The regional plan in these non RTO areas is effectively just the local utility plan stapled together. And that isn’t to say that in non-RTO areas we haven’t seen regional transmission build happen. We’ve seen some merchant projects in the west that have spanned utility footprints, but those have been again proposed by utilities. And really that narrative has been controlled by utilities. And I think it’s important to have an independent planner perspective to look at cost savings across different utility footprints and just get at that more efficient planning outcome.

John Farrell:
I know it wasn’t really part of the scope of your research, but how do you think grid enhancing technologies or distributed energy could help, if at all, do you think there’s a way that they could somehow provide a competitive check? I’m just sort of intrigued. You mentioned earlier, for example, one of the things FERC could do with their formula rates. You said, oh, they could maybe have a lower return on equity, lower return on investment for those local lines relative to the regional ones. And as we’ve seen, money definitely does motivate utility behavior. Is this another way that that could somehow work? And I have to confess, I haven’t really mapped out in my head how it would work. So if that’s your answer too, that’s totally fair.

Claire Wayner:
Yes. I mean, I think there’s research showing reasons why utilities are not investing as much in these more efficient or innovative solutions that you mentioned, like grid enhancing technologies or distributed energy resources. I think from the transmission side, especially with grid enhancing technologies, that’s where the importance of an independent planner comes in because they can do that fact check, do that work to identify on the system where grid enhancing technologies can be deployed to maximize cost savings for consumers. And they can provide that, again, third party perspective to result in grid enhancing technologies getting built rather than maybe solely relying on utilities to be identifying those opportunities. And obviously that study process needs to be done in collaboration with utilities because utilities do know their system best at the end of the day, they know about any reliability violations, but an independent planner is critical to provide that third party lens.
And then I think distributed energy resources can also really come into play on the local transmission side of things if maybe the right solution isn’t necessarily to be enhancing transmission in this one area, but maybe it is instead more cost effective to be building more distributed energy resources. And so that’s where I think it’s important to be ultimately co-optimizing how we study generation and transmission in our planning exercises. So co-optimizing at the regional transmission planner, co-optimizing in states that do integrated resource plans or IRPs looking at a compliment of solutions across the spectrum rather than maybe just narrowing in on one type of investment.

John Farrell:
Is there anything in your report, Claire, that you feel like I didn’t ask you about that you really wanted to make sure that you’d be able to share?

Claire Wayner:
No, I am just glad that I think through this conversation, the theme of affordability has really come up here. And I think for me, what I’ve learned most from this research, from getting the report out there is how lucrative transmission investments can be for utilities and how critical it is for consumers and affordability, especially at this time when we’re seeing rates rising to make sure that our transmission investments are most effective. And I think what I hope that people listening to this conversation take away is, not all transmission is bad. We need more regional and inter-regional transmission to reduce costs for consumers. Often I’ll see people point to the price tag of a single transmission line and talk about that in the context of affordability. So for a most affordable outcome, we are going to need more efficient regional and regionally planned transmission, but right now our incentives are set up to result in an unaffordable outcome for consumers. And that’s kind of the key hook I think for many regulators here around closing the regulatory gap.

John Farrell:
Claire, what happens next? How might FERC or state regulators take up your recommendations or are there already proceedings in place or taking place where folks who are interested in this issue can either follow along or potentially intervene if they’re interested in helping to close this regulatory gap?

Claire Wayner:
So at the federal level, I did mention there was a consumer complaint filed at FERC back at the end of 2024, and comments are due in that docket EL25-44, March 20th, 2025. And so if listeners are listening to this after that date, I would check in the near term on that docket at FERC, and we’ll see if FERC takes action on this.
I think individual planning regions and states within those regions can continue to bring complaints to FERC about how local transmission is planned within their region or about the FERC formula rate process. So that’s another opportunity through the 206 complaint option at FERC, for example, section 206 of the Federal Power Act.
And then at the individual state level, as I mentioned earlier, state PUCs can again revisit their CPCN permitting authority for transmission and make sure that their regulations are not allowing significant investment by their utilities below, for instance, a voltage threshold or rebuilding existing infrastructure. So it could just be a matter of first looking at your spending trends in your state and understanding what have utilities been investing in, and have those investment trends been driven by regulatory gaps perhaps in your CPCN processes.

John Farrell:
Well, Claire, thank you so much for your work in documenting this regulatory gap, but also for coming on to Local Energy Rules to talk about it. I just find it so helpful to understand the scope of the challenge that we have in front of us, which is a lot of capacity that’s needed in order to balance a clean energy transition, but also a real opportunity around affordability as well.

Claire Wayner:
Yeah, thank you so much for having me.

John Farrell:
Thank you so much for listening to this episode of Local Energy Rules with Claire Wayner, a senior associate with RMI’s Carbon-Free Electricity Program, where we discussed the major regulatory gap in transmission capacity planning.

On the show page, look for a link to Claire’s report from RMI and the Canary Media news coverage that first caught my attention. We’ll also link to two related podcasts mentioned in the show, with Ari Peskoe about the utility transmission syndicate (episode 149), and with Shelley Welton, about how we can crash the utility’s transmission planning party (episode 219). For a deeper dive, also check out ILSR’s report Upcharge, which explores the entire ecosystem of monopoly power that allows utilities to slow climate progress, overcharge customers, and favor their shareholders.

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.