The Midwest’s Big Bet on Clean Electricity Transmission

Last year, the Federal Energy Regulatory Commission, or FERC, issued its landmark Order Number 1920 with the goal of spurring the development of long-distance electricity transmission lines in the United States. The order came in response to a challenging reality: the U.S. will need dramatically more transmission to accommodate growing electricity demand and an expanding fleet of clean energy resources. Despite this need, very little regional transmission development has, in fact, taken place over the past decade.

Yet there has been at least one place where grid planning has aggressively moved forward. The Midcontinent Independent System Operator, or MISO, is the electric grid operator for the midwestern U.S. and part of Canada. In December, MISO approved $22 billion dollars’ worth of new transmission projects as the latest step in its ongoing effort to build a clean and reliable grid of the future. 

One of the leaders of that effort is Aubrey Johnson, vice president of system planning and competitive transmission at MISO. He discusses the need behind MISO’s grid expansion efforts and the unique set of challenges involved in getting more than a dozen states, each with their own unique energy policy agendas, to lend their support to these projects. Johnson also explains the range of benefits that the new powerlines will offer and challenges that could lie ahead as the lines move from the planning stage to construction.

Full Transcript

Andy Stone: Welcome to the Energy Policy Now podcast from the Kleinman Center for Energy Policy at the University of Pennsylvania. I’m Andy Stone. Last year, the Federal Energy Regulatory Commission, or FERC, issued its landmark order number 1920 with the goal of spurring the development of long distance electricity transmission lines in the United States. The order came in response to a challenging reality. The US will need dramatically more transmission to accommodate growing electricity demand and an expanding fleet of clean energy resources. Despite this need, very little regional transmission development has, in fact, taken place over the past decade.

Yet there has been at least one place where planning for the future grid has aggressively moved forward. The Midcontinent Independent System Operator, or MISO, is the electric grid operator for the Midwestern US and part of Canada. In December, MISO approved $22 billion worth of new transmission projects as the latest step in its ongoing effort to build a clean and reliable grid of the future.

On the podcast, we’ll be speaking with one of the leaders of that effort. Aubrey Johnson is Vice President of System Planning and Competitive Transmission at MISO. He’ll discuss the need behind MISO’s grid expansion efforts, and the unique set of challenges involved in getting more than a dozen states, each with their own unique energy policy agendas, to lend their support to these projects. He’ll explain the range of benefits that the new power lines will offer, and he’ll tell us about some challenges that could lie ahead as the lines move from the planning stage to construction. Aubrey, welcome to the podcast.

Aubrey Johnson: Thank you, Andy. Thank you for having me here.

Stone: So I imagine that a good number of people who are listening to this podcast may not be that familiar with MISO. Could you introduce the market and its mission to get us started, and your role there?

Johnson: Primarily, our team is really focused on really ensuring that we have appropriate generation. So we have a responsibility for resource adequacy. We have a responsibility for our interconnection queue. And our team does all aspects of transmission planning. So that is reliability type planning, economic and policy type planning, and interregional planning for the MISO region. I also have the responsibility for what we call our sync strategy. As you know, we are within the 15 states here in middle America. And adjacent to us, we have PJM, we have SPP, and other entities that we have to work with to make sure we have the right agreements in place to do our work as well as how we interact and intersect with them as well too. And so I lead our efforts to have the strategy that we have to go along with that.

Finally, I also have responsibility for what we call competitive transmission. And in that regard, we have certain projects that are not awarded to incumbents, and in that regard, we put them out for bid across the MISO footprint as part of these efforts where any cost-share project gets competitively bid if it’s not in a right of first refusal state. So that’s part of my responsibility as well, also.

So that’s primarily what I do. What MISO does is, we are the electric grid operator for 15 states throughout middle America and a portion of Canada, as you indicated. We operate the grid on a daily basis, 24/7, 8760 hours a year, as well as plan, which is part of what my team does. We evaluate all the transmission that gets built in the region. We also provide all of the insight and studies for new generation, the types of network upgrades that are required for generation to come on to the electric grid. And in doing so, you must do no harm. What that means is that any new generation that comes on must make sure that it does not create any harm to the existing grid in that regard. So we do the network upgrades that are required for that.

Finally, we operate a $40 billion electricity market. And then what that means is our member utilities market participants, every day, they come in and provide availability of what’s the next lowest cost megawatt that’s needed to serve the load within the region. There’s roughly 45 million people in the region, 15 states and Canadian province. And that’s who we are at MISO.

Stone: So in December, MISO approved a $22 billion package of new regional electricity transmission projects. And as I mentioned at the very beginning of the podcast, this is a major development that comes at a time when new long distance transmission lines are urgently needed. Can you give us an overview of this plan and how much transmission is going to be built, and where?

Johnson: So yes, you’ve hit the high points. Everyone loves the big number. $21.8 billion is the actual price tag on it. Our board approved that December 12, 2024. This is part of a roughly two and a half year effort to identify the needs that we expect to take place throughout the region over the next 20 years, and to build the transmission necessary to support that. This package of projects includes 24 projects that are spread across what we call our Midwest subregion. So that is from the Dakotas, down through Missouri, up through Michigan, west to Iowa, and obviously Minnesota, Wisconsin and other parts of that as well too. Those projects stretch all across that region.

What this is doing is creating an additional pathway for us to move electricity from the west to the east and from the east to the west, and really driving up more reliability for the region as we prepare for the load growth and some other factors that are impacting what our future will look like.

One of the biggest changes that we’re seeing here is, for the first time, we have increased the nominal voltage. These lines are primarily 765 kV lines. And at that level, that’s one of the highest voltage levels you’ll see in the electric transmission system. And what that does is, it means we’re able to really have more power transfer across those lines that will help also alleviate congestion that might happen on lower subregional lines, and also make the part of our network, the 345 kV network, more reliable, and provide more opportunity for those lines to be lightened up as well, also. So that again, power is going to flow to the place with the least amount of resistance. And again, the bigger lines are going to take up the larger portion of the power transfer that requires across the region.

Stone: So those high voltage lines that you just mentioned, the 765 kV lines, those are really designed to transfer electricity over great distances without losing much energy in the process. Is that right?

Johnson: Absolutely. So again, the higher the voltage level you have, the less losses that you have for the distances covered. And you hit it. That’s exactly what we’re doing.

Stone: So this is interesting. This is called tranche 2.1, of what’s the LRTP portfolio of projects, the Long Range Transmission Project transmission portfolio. Excuse me if I don’t get that exactly right. But this is just one stage of that. There was another group of projects that were approved a couple of years ago. And MISO has quite a bit of experience, because you also did something similar to this back around 2010, 2011. Is that right?

Johnson: You’ve done your homework. So I’ll work our way backwards. In 2011, our board approved 17 projects that were valued at that time at $5.6 billion. That was the first time we have what’s called a multi-value portfolio that was put into service. The last of those 17 projects went into service late last year. We’ll come back to that, because you want to talk about some of the challenges that we’ll have going forward.

Fast-forward, you hit it exactly right. In July of 2022, our board approved 17 projects valued at $10.3 billion. At that time, the largest portfolio transmission projects in the history of United States of America, which also included, within the 10.3 was 1.6 billion of competitive projects. At the time, the largest that we have. As we fast-forward to last year, the board approved the 24 projects valued at $21.8 billion, and banked within that is also roughly $6.3 billion of competitive projects that will be awarded throughout the next year or two as we go to those solicitations. And so we have been at this notion of long range transmission planning for really more than 15 years, when you go back to the origin of the work that we had with the initial NVP.

Stone: So the planning behind these powerline projects is very forward looking, and it’s intended to meet the future needs of the electricity system. Can you talk about the future scenarios that the projects are intended to address?

Johnson: Absolutely. That’s a great term, because what we call these is, we call these futures. Future scenarios, which are a set of assumptions and concepts that we vet with our stakeholder process to identify, again, an area to plan against. For this set of projects, the last several set of projects, we call these future scenarios 1A, 2A and 3A. And in this particular last tranche of projects, we focused on scenario 2A. If you think about it in a simplistic form, that represents a low, medium and high level of load growth. When we began this, really five years ago, 2019, we set our initial set of futures— which were futures one, two and three—we were very genius in our naming. There was a lot of concern that we overestimated what the load growth would be over the next 20 years. As we got into doing this last portfolio, there’s a lot of concern that we’ve underestimated what the load growth would be in the last 20 years.

And so what the scenarios do is take into account our members plans. It takes into account how we are able to account for load growth. It takes into account how we’re able to account for generational retirement, as well as other factors to develop these scenarios, to give us something to plan against. And ultimately, what we want to do is also test, potentially, against those scenarios, one versus the other, to ensure that the portfolio we develop is what we call a least regrets portfolio. Meaning it can work under multiple cases. So for example, in this particular case, we plan to future 2A, but we also evaluated the benefit-cost metrics against future 1A, to ensure that if the load growth is actually less than what we expect, the portfolio still offers value at that level. And obviously, if load growth is more than what we expect, then we know that the portfolio will be even more value.

Stone: So load growth is a critical issue that you need to address in MISO. That’s very much a national problem or national phenomenon at this point as well, as we’re getting AI data centers and new manufacturing growth. There are also, in MISO, the state policy drivers, particularly policy drivers around clean energy. Could you talk a little bit about that as well? That is a driver of much of the new generation and types of generation that this far-flung transmission will have to accommodate.

Johnson: Absolutely. So if you think about it, there are three states within the MISO footprint that basically have 100% clean energy goals. That would be Minnesota, Illinois and Michigan. What’s unknown is roughly 85% of our footprint has some sort of clean energy goals, some sort of carbon reduction goals, and that’s mainly driven by our member utilities. And so when we think about this, part of what is happening is there’s a change in the resource fleet happening all across America, quite frankly, and very much within the MISO footprint.

And so part of this need is, how do you figure out how best to put that generation, and then how best to get that generation, get that output, that energy, to the places where it’s needed most. And so as we think about this and think about a shift to a more renewable energy, that means that a lot of that’s going to be located on the western part of our footprint, when a lot of our energy usage is on throughout the eastern part of our footprint. So we have to make sure that the infrastructure is there to accommodate that.

Again, think about transmission as similar to the national interstate system and how it’s set up to have us move vehicles, how we move product from one location to the other. Really, that’s the main function of transmission, is to take energy from where it’s produced and deliver it to where it’s needed.

Stone: Now we get to the difficult part. So that the plan has been approved. But as history shows, and I’m sure you’re very familiar with, getting transmission actually built is a much more complicated endeavor. Getting the steel in the ground. And it’s due the multiple reasons, right? It could be that you have different jurisdictions with different perspectives and goals, policy agendas. You also have cost allocation, who’s going to pay for these things. And then you have the siting and all that that goes along, and the permitting. Could you talk a little bit more about the difficulties historically that have created the need for transmission that we’re seeing now?

Johnson: Let me work backwards and say a couple of things. First of all, our board will not approve a transmission package or transmission projects without a known cost allocation for it. So quite frankly, we saw the cost allocation before we ever take the projects to the board for approval. And in this particular case, for these large, long-range transmission projects, they are utilizing a low ratio share cost allocation. So in the Midwest subregion, we built these projects, this $21.8 billion will be paid for by the customers within the Midwest subregion on a low ratio share. What that means is, the more you use, the more the $21.8 billion you pay for.

Stone: And just to jump in here, if I may, just to define cost allocation— and I brought the word up— is how the costs of those transmission lines are distributed amongst the many people and the many different customers in different regions that would be using the lines. Is that correct?

Johnson: That’s correct. And this method is trued up every month. And so every month there’s a slight adjustment as to how much gets paid the next month, because it’s all based upon usage. Again, the more you use, the more you pay for. And again, that ties into the cost allocation principle, which is, a beneficiary pays.

And so that piece, in and of itself, is probably the most complex, most difficult part of developing a transmission portfolio, is determining who’s going to pay for it. The planning is challenging, the siting is challenging, the permitting is challenging. But it all depends upon identifying who’s going to pay for it.

Now I’ve done a pretty good job, I think, about not using acronyms, but I do want to use one here, because I think it’s apropos. One of the biggest challenges you also see with a transmission and transmission projects is this concept of NIMBY. Not In My Backyard. Everybody seems to understand and know the value of transmission, but no one seems to want it in their backyard. And that’s a real issue for really anyone in that particular case. But that is— when we think about all the different factors, the siting becomes the number one factor, also. Because you’ve got to be able to to put these facilities in places, in routes that are cost effective as best they can be. And oftentimes there are challenges with the Department of National Resources, the Forest Service, private landowners. And there can potentially be real fatigue around transmission and transmission development.

You also then get into, really, some of the permitting that actually goes along with the siting. River crossings. Those can be things that really increase cost and create delays in actual building. And so it’s all extremely complex. But it all starts with the original planning and the cost allocation, to be able to move those things forward.

Stone: MISO engaged in 300 meetings with various stakeholders on this latest tranche of the transmission portfolio. I want to ask you, who were some of the key stakeholders that you and others from MISO met with in these meetings, and how did you navigate all those different perspectives in pushing for this portfolio?

Johnson: So I’ve got a little term that I stole from my daughters, which is “carefully and systematically”. You know, when we think about this— and not to get too deep into MISO— we have a stakeholder process, and there are 11 different sectors. And if you can imagine, those sectors have very different perspectives. And so everything we’re doing is really trying to work and move folks as close to we can as a center.

You know, these meetings took place in a myriad of different ways. We had large workshops, four or five, six-hour workshops, that were solely designed to talk about the portfolio itself. We’d have meetings and participate in what we call our Planning Advisory Council, where we would speak to the issues that were currently underway and how the process and how the progress was going with the portfolio. We’d meet with state regulators, we’d meet with energy agencies at states, we’d meet with environmental groups, we’d meet with industry groups all along the way. We’d meet with our member utilities who have a part in this and how this is going to impact their systems, you know? So that’s a whole landscape of what’s there.

Some of our senior leaders would meet with governors to inform them, as well. And so ultimately, all of this is trying to build as much consensus and as much support for the portfolio as you possibly can. You will not get all parties to be involved. You will not get all parties to support it. But our goal is to drive such that the preponderance of the folks within the community are essentially supportive of the outcome that we’re working on to develop the portfolio.

Stone: Well, one of the interesting things that MISO has done as well is is the process it’s used to actually understand the benefits of these power lines. And I would imagine— I was obviously not in any of these meetings. But I would imagine that a lot of the discussion in those meetings was an understanding of the broader benefits that the lines can bring. And MISO has estimated the benefits for the transmission projects over the coming 20 years to be as high as more than $3 for every dollar invested. And it’s interesting, these benefits are defined across a range of, I believe, nine categories— the most, I guess, important, being reliability, avoided costs, and decarbonization. Could you talk about these benefits and their importance in explaining, again, on the larger scale, the benefits of the projects, in getting broad buy-in and agreement to move forward.

Johnson: So, you said a couple of different things, and I’ll work backwards from that. There are nine benefits. And not to nerd out too much. I’ll just share with you. They are mitigation and reliability issues, reduced risk from extreme weather impacts, avoided capacity costs, capacity savings from reduced losses, avoided transmission investment, congestion and fuel savings, energy savings from reduced losses, reduced transmission outage cost, and decarbonization.

And so working backwards, I’ll say, for example, not all states have decarbonization goals. And so if you’re not a state that has that as a core value, then perhaps that benefit does not necessarily serve your need. And the fact that we capitalize that and we monetize that, some states will take exception to that and not see that as real value. So those are some of the challenges that you’ll see as we think through these things.

The mitigation reliability issues. Really, what that is basically saying is having this additional infrastructure gives our operators another tool in the toolbox. And so what that means is, when we do have reliability problems, when we do have potential issues, these facilities, these transmission lines, potentially help us avoid having load shed. We’ve never said that you’d actually shed load. What we’re saying is, if you did have to do that, this is what the value of those are. And so that, in and of itself, is one of the first times anyone has actually tried to put a value on reliability. You know, ultimately, reduced risk from extreme weather impacts. We’re able to, through some of the scenarios and through some of the analysis that we’ve done figure out how this infrastructure can help mitigate future weather impacts based upon leveraging what has happened in the past.

And so you’ve hit a key component, Andy, which is— another part of the challenge is getting general consensus on what the benefits are, and then ultimately being able to monetize them so you can compare them to the overall cost. The big thing is that people think about and see and know that there is cost. The part that’s difficult is you don’t see the deduct on your bill or the benefit, and so what’s lost often is recognizing what you would have to pay if, in fact, this infrastructure was not put in place.

Stone: Well, again, I would imagine it’s an issue, and maybe an industrial customer might be very interested in this. You know, you’ve got these upfront costs, which will be passed on to rate payers. But in return, as you mentioned, you’ve got these longer term costs that don’t necessarily show up on the bill, but are very critical to take into account as well.

Johnson: Yes.

Stone: Okay, so I want to bring up another major issue. Again, this is not isolated to MISO. It’s a national problem. But a month ago, this podcast highlighted a recent report from the grid’s reliability regulator, NERC, and it pointed out that in much of the country, electricity generating supply is struggling to keep up with growing electricity demand. NERC highlighted MISO as the market where these concerns are currently most urgent, and the risk that reliable grid operation may not be assured is potentially the greatest. To what extent might the transmission projects that we’ve been talking about here today address MISO’s electricity supply concerns, or are these concerns being addressed through other means?

Johnson: So, I think a couple of different things. And first and foremost, we’ve done a lot on—  what you’re speaking to is resource adequacy. And really, the NERC report, our own reports looking at our assessment say that we could have a capacity deficit as early as the next planning year, a 2.7 gigawatt capacity deficit. In the simplest forms, load is increasing, and more generation is retiring at a faster rate than generation is coming online. And so when we think about the resource needs that we have— we recently did our regional resource assessment. That was completed late last year. And that assessment basically says for the MISO region to meet its goals over the next 20 years, we should have approximately 20 gigawatts of new resources come on every year.

Stone: Resources being generation.

Johnson: New generation. Exactly. I’ve done a pretty good job about not using acronyms, I think. But there are some things that I think are just consistent with how we speak in this game, if you will, in this industry. And I keep forgetting that not everyone will understand resources or generation et cetera, along those lines. But we need more generation to come online than we’re seeing. In 2024, we had roughly six gigawatts of generation to come online.

So let me say how that all ties back in together. One of the real challenges with what we’re seeing is, as new generation tries to come online, one of the real barriers to that is the network upgrade cost. So when a new generator tries to attach to the grid, it has to perform network upgrades to ensure that, again, there’s no harm done to the existing grid. Part of the challenge that you have is, your network upgrades, those costs increase if there’s not sufficient backbone transmission to actually help carry the generation output, the energy, where it’s needed. And when you lag behind in so far as having the backbone transmission, that means that two things are going to happen with new generation. Either it’s not going to be delivered, so you have more congestion costs, or the network upgrades are at a point where the project may or may not be profitable, and/or if it is a self bill, you’ll have a higher cost for that self bill.

So these lines, in and of themselves, I believe, if my memory serves me correctly, will enable, potentially, 118 gigawatts, 120 gigawatts of new resources. I’ll have to double check that 100%. But that’s a significant impact, seeing how right now, our peak capacity on our system is roughly 127 gigawatts. So these lines are potentially able to help us double the capacity output that would take place over the MISO system.

And so going forward, looking at what our energy needs are in 2042, we expect to have roughly 400 gigawatts of new resources available to serve that need. So when we think about the NERC report, the simple answer is, there’s more generation going offline. Load is increasing, and both of those things are happening faster than new generations coming online. These lines will help facilitate the delivery of energy for the new generation that’s being built to meet those needs.

Stone: As we’ve talked a few minutes ago, the current transmission portfolio that we’ve been talking about is the latest in a line of these developments from MISO. And there is more to come. So we’re at tranche 2.1. There may be a tranche 2.2, and then tranches three and four that will come after that. And those are interesting, three and four, because those will connect the southern part of MISO, which is actually not included in the transmission that we’ve been talking about. Can you tell us about the next steps and the goal of bringing the southern part of MISO into all this as well?

Johnson: What we’re undertaking right now is we are in the process of updating, revamping our futures. The futures basically lay out the scenarios that we will actually plan to. And so we mentioned that earlier. That work is is beginning to get underway, beginning to get into the stakeholder process, as early as next month. And so we will spend the balance of this year trying to complete that work, and then moving beyond that, creating the models that will be needed to support the studies that will come going forward.

As we think about the way we frame this, part of what we did with this last look was that there’s potentially more transmission and more generation that’s needed to meet the needs in the Midwest subregion. And so in order to continue to move these things more expeditiously, we decided to look at this in multi phases. And so that’s how you’re hearing the discussion about our tranche 2.1, which we completed, and our tranche 2.2 which will be on the horizon.

As we look at our southern footprint, the reality of it is, is there’s been a significant increase in the transmission that is being built in the South region over the last few cycles, planning cycles. It just hasn’t been transmission that has been broadly shared and paid for on a regional or subregional basis, which is what that is. That transmission has been built— in the South has been mainly focused on load growth, and not necessarily some of the multi level benefits that we looked at in the Midwest subregion.

And so there are discussions. We are engaged with those member utilities and regulators, to think, about what are the things that they do have a view on that they would like to proactively pursue, and how that might look. And I would say to you, I think that long range transmission planning in the South region, what we talked about is a tranche three— I expect that look different than what we have done in the Midwest. I don’t have a clear vision today of what that is. I just understand that some of the drivers in need and interest of that region are different than what we’ve seen in the Midwest subregion.

And then finally, we talk about a tranche four, which is expanding the ability for energy to flow between our two subregions, which today is contractually limited by some agreements that we put in place with what we call the joint parties. And so ultimately, we’re thinking about, how do we have increased power transfer between those subregions, which is super important as we get into emergency conditions.

Stone: And those subregions, just to define for listeners what they are, that’s actually mostly Louisiana. Is that correct?

Johnson: The Southern region, which came along and joined MISO in 2013, consists of Texas— a portion of Texas, East Texas, which is in part of the Eastern interconnect, Louisiana, the city of New Orleans, Mississippi and Arkansas.

Stone: So we’ve been talking about all these tranches in these projects. I also wanted to point out one other thing, that MISO and most of the markets also have an annual planning process. MISO’s is called the MTEP, and that is generally for the more localized planning. I think, to go back to the very intro of this podcast, FERC, I believe, really has targeted those annual planning processes with its order 1920, which is looking for a more forward-looking, scenario-based kind of planning process that we’ve been talking about that MISO has been engaged in. Can you talk a little bit about that annual planning process, related to what we’re seeing here in the bigger transmission projects we’ve been talking about?

Johnson: You had it right. So MISO has the MISO transmission expansion plan. We’ve been keeping records on that since 2003, when we formalized that. And that is actually what our board of directors approved. That typically has been primarily local reliability projects, generator interconnection projects, potentially market-participant-funded projects. Again, projects that are looking at a more current, three-to-five-year need. It is what we would call, for lack of better term, our everyday local planning. And so that piece has been there.

We do some other things that have been forward looking that we’ve recently got approved— was our joint targeted interconnection queue study, which also look forward to create an interconnection zone and provide transmission projects in advance of that, that will serve to address what we call effective systems upgrade needs, as anybody that wanted to locate there to build generation. So it brought more clarity. It will bring more clarity to new generation projects that happen in that generation zone.

What order 1920 is looking to do is to press the organized markets. There are seven organized electricity markets in North America. And it is an effort to have those areas do more long-term regional planning. Something that looks out over a 20 to 40 year view, and to have those be part of the overall planning process. And part of that effort is to say, if we take a longer, more holistic look at planning transmission, can we also potentially reduce the overall cost of transmission? Because we are building things ahead of time, rather than just as needed. That’s really the underpinning of what order 1920 is attempting to do. And it has leveraged several of these, the types of processes we’ve used, and said that those are things that, essentially, those other organized regions should be replicating as best for their particular region.

Stone: I want to dive down the rabbit hole just one more minute on this one. We’ve been talking about what’s known as regional transmission development here today. And that’s transmission development within these markets, the seven different markets you’re talking about in this case, specifically within MISO. Early in our conversation, you also mentioned that one of your responsibilities is the seams of MISO with its neighbors, such as PJM, which I’m in here in Philadelphia, to your east, SPP to your West. And that type of transmission that would cross into these different areas would be inter-regional transmission. Can you talk about regional relative to inter-regional, and why the inter-regional is also something that needs to be thought about more in the future?

Johnson: So when we really talk about regional transmission, it will intersperse a little bit of our previous question. The MTEP work typically is looking at within the specific planning area for our member utilities, what we would call a load serving entity. They are the entity that’s responsible for electricity being delivered to that end use customer, their customer.

And so if you look at these different 15 states and the different utilities that make it up, typically, they’re all bringing their plans to us. We’re doing our screening and evaluation and other studies with that as well, too. And those things wrap up into a our annual MTEP, our annual planning process, which is actually an 18-month planning process. When we talk about regional transmission planning, that is something that MISO leads and steps away from what our local utilities are actually doing, looking at those scenarios, engaging stakeholders, developing those scenarios, identifying a portfolio that serves the region, testing those projects and doing benefit cost analysis, doing a business case to justify it. That’s how we get to regional projects.

Inter-regional projects, start looking at those connections. How do we make sure—because we’re all part of this eastern interconnect. North America has, essentially, three electricity grids. The Eastern Interconnect, the Western Interconnect, and the Electric Reliability Council of Texas, ERCOT, which is also its own one of those organized markets. So Texas has its own grid.

And so when we think about the Eastern Interconnect, and we think about our neighbors and PJM and SPP and some of these other areas that we are connected to, we want to look and make sure that there are sufficient ties across our quote, unquote “seams”, that facilitate electric power transfer and also minimize congestion. So what that allows you to do is, although everyone has to serve their own specific needs, we’re also always trying to have the lowest cost electricity serve those needs. And in times of challenge, we want to be able to move power, if it’s available, to other places where it’s needed.

And so when we go back to, for example, winter storm Uri, a few years ago, PJM actually had power available. And they were able to move roughly 14 gigawatts into MISO, which then was able to move roughly seven gigawatts into SPP. And so where we were having challenges and extreme cold in the MISO and SPP system, PJM was warmer and had availability and was able to move. Those things are able to happen because there’s transfer capability within the region. Those things are able to happen because there’s sufficient ties within the region. And so when we’re looking at inter-regional planning, we want to make sure we’re coordinating. We want to make sure that our systems aren’t having a negative impact on one another. And we want to look at trying to identify projects that further help the regions operate well together, and further help enable the existing electricity markets in those various regions.

Stone: Recently, a number of large-scale transmission development portfolios have been approved in markets other than MISO. Obviously this is really good news. Nonetheless, MISO has quite a lot of experience. And I wonder if there are any particular lessons that you think might be helpful to other regions or at the national level in moving regional transmission development forward. Again, based upon the MISO experience.

Johnson: I thought often that really it is— if you think about a three legged stool, there’s some things that have to happen before you be able to do long term planning like this. First and foremost, the leadership of the RTO has to be fully invested, fully forward. Because this is a challenging, arduous process. And there are a lot of factors involved, and this gets a lot of attention. So the lead organization has to be prepared for that.

You have to have regulators, especially when you have a multi-state region like most of these organized markets. They have to be a core set of regulators that are supportive, believe in this concept, believe in the process, who will also bring along other regulators to support it.

Finally, you have to have, as we call them, load serving entities, transmission owners, that are also bought in and are thinking about not just their system, but the entire system, and recognizing that they may have to make adjustments as to what they might want to build to make sure that it all connects and works holistically across the whole region. Those are three necessary components, and having a lot of engagement in those areas is really, really important.

I think the other thing that’s really, really important is understanding that the most challenging part of any part of this is the cost allocation. My engineers and folks on my team hate it when I say that, right? Because the actual technical planning is not trivial. But more importantly, or more challenging, really, becomes who’s going to pay for. Because that’s important, if you’re going to do something that impacts multiple states, multiple entities that are part of this overall process. And when you really talk about regional planning, you’re really talking multi-state. And that means that the more people who are engaged, the more people are there, the more challenging it is.

And then finally, I do think you’ve got to be able to call balls and strikes. I joke that, you know, as we go through this, the only thing that— it’s disappointing a little bit to do all this work and think that nobody likes you in that process. Because ultimately, for all intents and purposes, there’s an element of the art of compromise for this. Nobody gets everything that they want. And you have to have the capacity to be able to call balls and strikes and direct the portfolio forward, because ultimately, there are no easy decisions in that process, but decisions have to be made.

Stone: And now the process for MISO is to get these planned transmission projects actually built. Right?

Johnson: Yes, sir.

Stone: Aubrey, thank you very much for talking.

Johnson: It’s been just a pleasure to spend this time with you. I appreciate it very much.