The West’s New Electricity Markets

Earlier this year the Southwest Power Pool, the electric grid operator for much of the central United States, expanded into the Western Interconnection, becoming the first Regional Transmission Organization to operate in both the Eastern and Western grids. The move comes as Western utilities seek to address rising electricity demand, the integration of growing amounts of clean energy, and concerns about future grid reliability, challenges that broader regional coordination may help address.

SPP plans to build on that expansion with Markets+, a new regional market initiative scheduled to launch in 2027. Together, these efforts represent one of the most significant pushes yet toward greater electricity market coordination in the American West. They also come as California’s grid operator pursues its own effort to expand regional market participation through its Extended Day-Ahead Market, or EDAM, giving Western utilities multiple paths toward closer regional integration, each with different approaches to governance and market oversight.

On the podcast, SPP Chief Executive Officer Lanny Nickell discusses SPP’s expansion into the West and the development of Markets+. He explains why Western utilities are becoming more interested in regional coordination, the tradeoffs between independence and larger markets, and what these developments may mean for the future of the electric grid in the American West.

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.

A generation ago, much of the U.S. electricity industry was restructured, giving rise to large organized wholesale electricity markets known as regional transmission organizations, or RTOs. Today, these markets coordinate the flow of electricity across much of the eastern United States, Texas, and California. The bulk of the western United States, however, largely took a different path. For a variety of reasons, utilities in much of the West chose to remain outside those organized markets, instead emphasizing local control and autonomy. Yet as the electric grid faces growing challenges from the rise of AI data centers, the need to integrate renewable energy, and concerns about future reliability, some western utilities are re-examining the trade-offs between local autonomy and the benefits of broader regional coordination and joining the larger markets.

On today’s podcast, we’re going to take a look at one of the most significant efforts to expand organized electricity markets into the West, and explore both its goals and its potential limitations with the chief executive officer of the organization leading the effort. Lanny Nickell is CEO of the Southwest Power Pool, one of seven regional grid operators in the U.S. that collectively serve power to roughly two-thirds of the country’s population. On April 1st of this year, SPP expanded beyond its traditional footprint in the Central U.S. into the Western interconnection. Next year, SPP plans to introduce a streamlined version of itself to extend its reach even further. And SPP’s expansion comes as California’s grid operator is pursuing its own effort to expand regional market coordination throughout the West, raising questions around whether a fragmented or unified market is in the region’s future.

Today, we’ll explore why western utilities are increasingly turning toward regional coordination, the different forms that coordination is taking, and what these developments may tell us about the future evolution of the electric grid in the American West. Lanny, welcome to the podcast.

Lanny Nickell: Well, thank you, Andy. It’s good to be here. I appreciate the opportunity to talk about things that we’re excited about doing. We’re very passionate about the services that we provide and I always enjoy talking about those services.

Stone: Well, it’s great to have you here. We’re going to be talking about some major developments in the western electric grid and with SPP. And again, it’s great to have the person heading these developments here on the podcast.

So I wonder if we could start out a bit slowly here with some of the basics. Some of the people listening to this podcast will have a pretty good idea of what an RTO or a regional transmission organization is and does. But to be honest, and quite understandably, many electricity consumers have little idea about the larger market frameworks that their own electricity providers, their utilities, may be a part of, and why. So to get us started, to make sure everyone is on the same page before we go into some of the deeper issues we’ll talk about, could you tell us about SPP, its role as an RTO, and also where it has traditionally operated geographically?

Nickell: Sure. Absolutely happy to do that. As a regional transmission organization, we have many responsibilities. One of the most important responsibilities we have is to work with our members in a coordinated, collaborative fashion, to keep the lights on. It’s all about reliability. Now we try to do that in the most affordable way possible. And in fact, that is essentially what the market function we provide does, is it assures that we can keep the lights on in an affordable way because we’re using the most economic energy available to us.

But when I talk about keeping the lights on, what does that look like? I like to use the analogy of air traffic controller. If you think about what air traffic controllers do for the airline industry— you know, they don’t own the airports, they don’t own the airplanes, but they make sure that airplanes get from one airport to another reliably. And that’s essentially what we’re doing for the grid that we operate across 14 states today, or at least currently, before we expand it into the West.

So we really are operating across the 14 states right in the middle part of America. Our southern border extends into Texas and into the northwestern part of Louisiana. And then we go all the way up to the Canadian border. The transmission grid that we operate traverses 14 states along the way. So that’s geographic footprint that we operate within. And Job one is keeping the lights on.

But we also provide a market function that assures the cheapest energy available can be delivered reliably to consumers. And that’s the affordability aspect of what we do as a regional transmission organization. We have other responsibilities. We plan the grid, the transmission grid that we operate over. So from an air traffic controller perspective, that’s the airspace. But that transmission grid has to be continuously planned because the grid is continuously changing. As generators are removed from the grid, as generators are added to the grid, as load is added to the grid, these large data centers, for example, are being added nearly all the time. And we have to figure out what the transmission grid is needed to be able to accommodate those future demands. So it’s not only about operating today, but it’s also about operating reliably and affordably in the future.

Stone: So the big news out of SPP this year is its westward expansion. And we’re going to talk about why that’s happening and what it may mean. But first, I want to point out that there are two distinct flavors of this expansion growth in the west. One is the expansion of the RTO itself into the western interconnection. The U.S. grid is divided into East, and the West, and also Texas. Not so much connection between those, but you’re expanding into the West. And that went live on April 1st of this year.

The second is what you call Markets Plus. And that’s scheduled to launch in 2027, and that represents a more limited form of regional coordination, again. And we can get into the details of what that means. But to start us out, what actually changed on the ground when SPP expanded west this year as of April 1st?

Nickell: We essentially took the RTO function that we operate with in the East, and we expanded it into the West. It allowed us to optimize energy flows in real time across the interconnections that separate the Eastern and Western grids. And that’s a big deal. We’re the first RTO to do that and the only RTO to have done that so far. If you consider the fact that we today operate and serve about 56,000 megawatts of peak demand in the Eastern grid, when we expanded west, that allowed us to serve an additional 5,000 megawatts.

So combined, there was about a 10 percent increase in peak demand that was added to our responsibility on April 1st. But more importantly, it establishes that presence in the West that creates a path forward for others who want to experience the value and the benefits of being part of a much larger region.

Stone: Could you tell me a little bit more about what the Western RTO is providing to utilities in that area that they were not receiving or did not have access to before?

Nickell: Primarily, it allows them to partake in our market, the real-time and day-ahead markets that we provide. It gives them access to a broader set of generating resources. And that access not only helps them be more reliable for their customers, but also to have access to cheaper energy if it’s available somewhere else within the footprint.

Also, because of the fact that we are optimizing both the Eastern market, which currently existed, and the new Western market that we’re operating, we’re able to access resources in both interconnections for both sides of the interconnection. Again, that is a huge, huge benefit. It increases resiliency. As you know, when we have winter storms and when we have summer heat waves, those extreme weather patterns don’t always exist across the entire United States. And so it just gives us a broader geographic region with which we can optimize as well and rely upon. If it happens to be really cold in the West and not as cold in the East, that frees up resources that we can deliver across those two interconnections, and vice versa.

In fact, it adds a new time zone. And time zone diversity is an important nuance of this as well. In other words, it’s getting dark first in the East, but it’s still daylight in the West. Well, if the West has a lot of solar resources, that could be helpful to the East as well. In vice versa, in the morning time. The sun is rising first in the East. It’s a single time zone, but there’s an amount of a value associated with that time zone diversity that we can tap into that we weren’t able to previously.

Stone: My understanding has been that there is not a really strong, robust connection between the Western and the Eastern grids. SPP is now spanning those two grids, and you talked about sharing resources. How robust, how much transmission capacity is there, to share electricity produced in the West with the East, for example?

Nickell: It’s not a lot. And so I view this as really more of a strategic opportunity. Just over the last two months, we’ve already seen those interconnections being fully utilized. And that tells me that there’s an opportunity to expand the transfer capability across those interconnections, because I think that would unlock a tremendous amount of value.

But now that we have the market, what that does is it sends that price signal and it just increases the transparency behind that strategic opportunity. To me, that’s a tremendous, tremendous strategic opportunity in front of us. We’re already utilizing it to the extent we can. I think there’s a lot more out there that we can utilize.

Stone: Okay, so we’ve just talked about your expansion of the RTO into the West. As we mentioned earlier, there’s also another expansion or a new development for 2027. That’s what’s called Markets Plus. Tell us what Markets Plus is. I kind of characterize it simplistically as a slimmed down RTO. It’s not exactly that, but tell us what it is. And what problem is it designed to solve, in particular, as an alternative to full membership in an RTO?

Nickell: So, Markets Plus allows the utilities to take advantage of the markets that we already operate today as an RTO. What it doesn’t do is it doesn’t provide the transmission planning function that an RTO provides, nor are we currently anticipating consolidating what is referred to as “balancing authorities” that exist today. So, those utilities will maintain a lot of their autonomy, their control of their assets, but rely upon our market structure to optimize the use of their assets.

If you think about what we provide today as an RTO, just to give you something to compare against— in 2025, we provided about $4.7 billion of savings to the consumers across our 14-state region in the RTO. $4.7 billion of value. $2.8 billion of that value was contributed by the market function. The real time and the day ahead market. So, a significant portion of the value of regionalization that an RTO provides is derived from the market aspects. And I think that’s largely why a lot of these utilities, they want to at least start by being part of that function that provides the most value. And then, you know, we’ll see what happens next.

Stone: So, those savings, again, come from the fact that a utility in any given area can access the cheapest generation at any time, even if it’s not in their footprint. And with Markets Plus, to make sure I understand here, and to kind of restate what you said, they will still have access to electricity generated in utility regions other than their own. But they will maintain their own independence in terms of planning the grid and the grid reliability functions that the full RTO would take over.

Nickell: That’s right.

Stone: So, for decades, the West has largely avoided the organized markets like RTOs, like SPP, that developed, again, in SPP and PJM here where I am in the East, New England, California, et cetera. And I want to ask why the Western utilities took a different path, and to what extent did the fact that the West is unique in terms of it having many public and federal power bodies, cooperatives, and even a lot of still vertically integrated utilities. How is that mix unique and how did that define how they thought about membership in larger markets?

Nickell: It’s interesting how the East and the West have evolved differently over the years. And I know that even though not much has happened in the West related to the evolution of markets, or even RTOs for that matter, there have been efforts in the past that have considered starting up those kinds of services— centralized, regionalized type services that have been considered in the past. And for whatever reason, the autonomy, the control was valued more than the value of regionalization.

Having said that, grid conditions are changing dramatically. And in fact, I’ve said over the last couple years several times— just about everywhere I go— that we are dealing with a pace of change now that we’ve not seen before. And I’ve been in this industry now for 34 years, 29 at SPP, and I’ve not seen the rate of change we’re seeing now ever in my career. And so I think those changing and rapidly changing conditions— it’s not just the pace of change, it’s the magnitude of change. I think that’s causing people to rethink what they need for their utility. And in the West, they’re starting to realize, and they have been realizing over the last couple of years, that there’s a tremendous need for coming together, working together, collaborating to try to improve their reliability position and to try to achieve as much value as they can.

So I think it’s just those changing conditions. And if you wonder what those are, we’ve seen a tremendous transition from thermal generation or carbon-producing generation to renewables and carbon-free generation. So that transition has created more stresses on the grid. And then you add on top of that the current administration’s focus on developing AI. And the data center growth is occurring faster than I think the utility industry can keep up with, at least under their traditional approach.

And so those conditions are just causing a lot of utilities to rethink how they do things. Even in the East, we’re hearing about some utilities that are expressing a desire to reevaluate whether they want to be in an RTO. I mean, we see that and we hear it. It’s not that that’s the right decision, but they’re just questioning what’s best for our future given these rapidly changing conditions. Conversely, in the West, those same utilities are realizing, “Man, we need to be part of something bigger. That’s how we’re going to survive this rapid change that we’re all experiencing.”

Stone: You’ve mentioned that you’ve got AI data centers driving the demand. You have some new manufacturing. You have the integration of renewables. And you mentioned that a little bit earlier with solar. It also applies to wind. I mean, to make these intermittent resources really work, you want to be able to spread them around and access them from all over your grid to make sure you’ve got access to where the sun is shining. And correct me if I’ve got this stat wrong. But I think SPP, the traditional Eastern SPP, at peak wind times, you’re getting about 60% of your electricity or energy from wind. Is that correct?

Nickell: We’ve actually seen moments in time where over 90% of our energy needs were being served by renewables, which— the bulk of that is for SPP in the East is wind. And actually, over the course of a year, wind is the number one supplier of energy for our 14-state region in the East.

I don’t think that would have ever been possible without a regional institution in place to make sure that the grid was developed such that we can accommodate those kinds of penetrations at times that are tremendous. But other times, we’ve seen times when wind practically didn’t show up at all. And so balancing that across a larger footprint is possible, but it wouldn’t be possible in a much more smaller area.

And so that just shows what can happen when you’re able to collaborate across a bigger footprint. You can rely on other resources. When the wind doesn’t show up, we have a tremendous amount of gas. And that gas fleet can move fast. And that’s a tremendous advantage that we have.

Stone: I want to ask about SPP’s vision for the West. Markets Plus, do you view that as a sort of a midway point for utilities that may be RTO-curious, if we want to put in those terms, but not fully willing to commit to give up autonomy in certain ways today? Do you see that as a steppingstone towards that?

Nickell: It certainly could be. What we’re trying to do is give the utilities choices. If the utilities step into Markets Plus, and they enjoy the experience and appreciate the value that’s provided with that service and then they want to take the next step, we’re willing to accommodate that. The last thing we want to do is force somebody to do something they don’t want to do. That’s not desirable. That’s not an outcome that SPP would promote.

On the other hand, we have the capability to provide the services that they need. And I think Markets Plus is a start for some of those. And we’ll see where they go next. But certainly, we’re able to transition to the fuller RTO footprint when they’re ready to do so.

Stone: The West is an interesting place. We already talked about this interesting mix of different types of utilities that operate there. But we haven’t talked yet about the fact that there is an alternative to Markets Plus that is already in place. And it’s called the Extended Day Ahead Market, or EDAM for short. And it’s run by California’s electricity market operator, California ISO, which in turn has been running an even more limited real-time market that dates back to 2014.

SPP has presented itself as, if I understand this correctly, an alternative to EDAM, with the key difference being the way the markets are governed. EDAM is tied to California’s ISO, as I mentioned. And California ISO’s board is actually appointed by the governor of California. So there’s a tight connection with California there that is notable as the market expands beyond the California borders. SPP and Markets Plus do not have governance structures that are rooted in any single given state. So I wonder if you could tell me about the fundamental governance difference here. And from your view, as the person who’s leading SPP, why SPP’s independence may be attractive to Western utilities who are looking to join a coordinated market.

Nickell: Well, they’ve actually already experienced the governance model that we have offered in the West. And in fact, they worked with us to tweak the model that we already have decades of experience operating under in the East. And the Western utilities appreciated the opportunity to tweak it in a way that met their unique needs and their structures. It’s still very independent. And we have decades of experience operating under that independent structure.

I think they appreciate the fact that— and they’ve seen this. Over the last couple of years, they’ve actually been operating under that structure as they’ve helped us design a market for the West, by the West, and in the West. They’ve already experienced it. And what they like is the fact that they have a voice that matters. We have an independent— it’s called MIP. Market Independent Panel, or something like that.

Stone: A lot of acronyms in this industry. It’s hard to keep them all straight in names, right? They’re all technical.

Nickell: Yep. So we do have a panel that is independent. Fully independent. And every decision that the stakeholders make around design and around governance and other policy issues that are important related to Markets Plus, those decisions will ultimately have to be approved by the independent panel. It is truly independent. It’s not picked by one state. It’s not picked by one entity. It’s not picked by a group of like-minded entities. That panel is nominated by a nominating committee that is balanced. But ultimately, those participants on that independent panel are independent.

And so they like that. They like the fact that they know that it’s a structure they can trust. It’s a structure that they can be involved in. It’s a structure that allows their voice to be heard. And they can influence policy development in a way that matters to them and to their customers. So I think that’s largely why a lot of these utilities have picked SPP’s Markets Plus, is because of that unique governance design that we have decades of experience operating with them.

Stone: I also want to give EDAM its share, in California ISO. And to be fair, EDAM is marketing itself based on a long history of efficiently running energy and balance markets, a real-time market outside of California. The Western Energy Imbalance Market is that market that goes back to 2014 that California ISO has been running. And in the complex electricity industry, that track record is clearly quite valuable.

Second and very important, there’s a process underway to create a fully independent governance structure for EDAM. The process is called the West Wide Governance Pathway Initiative, or WWGPI— another one of these industry acronyms, right? And the fruit of that effort is going to be the Regional Organization for Western Energy, or ROWE, that is an extended day-ahead market that is scheduled to go alive in two years in 2028.

That brings me to the next question. If you are a believer in the power, the capability, and the advantages of a large market, larger being better, do we need to have two separate market structures developing in the western United States, one based on California’s model and one on SPP? Is that ideal or not? What’s your perspective? What are your thoughts on this concern?

Nickell: Well, Andy, it’s a great question and it’s a question that’s been debated for several months now. And I will say that I appreciate the efforts that Cal ISO and their participants have made to try to improve the governance for the purposes of EDAM. And I think that’s great. I think it’s commendable.

I will say this, that the fact that they did that proves the value of having multiple markets competing with each other. Because when you have that competition in place, it motivates those market operators to get better. Without that competition, I would argue that there’s less incentive. There’s less motivation to improve and to get better. I think that’s a perfect example of what competition between at least two market operators can do. We’re motivated. We’re incentivized. Look, if we don’t get better, people don’t want to be part of us. And I mean, that’s just the bottom line. And I think that’s a perfect example of why competition matters.

Would a single market across the West be the right answer? There’s a potential that it could optimize value for certain parts of that market, but I don’t think it can meet the needs of every participant the way those individual participants need to be met. It’s hard to do. It’s hard for every individual participants to feel like their needs are being met by a single utility or a single operator across a large footprint.

Those are the things that they have to weigh. And I think providing utilities options is a big deal. The question is, what’s the right number of options? And in the east, there are five regional transmission organizations or independent system operators in the Eastern interconnection. In the west, I think there’s room for at least two. And currently, those two are Cal ISO and SPP. Those are the options. And I think utilities deserve to have a choice. And I think they need to be able to make a choice that meets the needs of their customers.

They’re the ones responsible for serving their customers. They have to do their evaluations as to which design, which governance model, which operator provides customer service. All of those things matter to them, and they need to have options. And that’s why I think it’s important to recognize the value of optionality. And I think that’s better than having just one market operator trying to meet the needs of everybody in an equitable fashion.

Stone: Let me ask you, if I may, another question here about governance. And you had mentioned a little bit earlier in our conversation that the western utilities are increasingly interested in joining these larger coordinated markets, while in the east there has been some pushback against the markets in certain areas. And we’ve seen these growing debates here, particularly in the East, that some of the states in particular feel that what the markets may be doing don’t necessarily align with state policy priorities. For example, in areas such as clean energy promotion and things like that.

And one of the questions is, as you expand SPP, the utilities are the major stakeholders who have the say in the stakeholder process there, similar to what we’re seeing here in the East. What has SPP learned or what has SPP put in place to ensure that the state voices are heard, taken into account, and actionable in that market, when those states may feel that the markets are going in a direction that maybe do not align with those states’ own policy objectives?

Nickell: Andy, I’m glad you asked that question and I’m very happy to answer it, because I think we have a tremendously well-functioning example that we can talk about in SPP’s RTO footprint. What we do, I think, that’s different than most other RTOs and ISOs, is we actually give the state’s authority over certain policy decisions that need to be made.

So we call that the regional state committee in SPP. Every state that operates within our footprint has the opportunity to designate a commissioner from each of the state commissions to sit on that committee. And they specifically have authority for SPP to file tariff changes related to issues around resource adequacy and around cost allocation for transmission expansion.

Those are the primary authorities they have. There’s some other authorities that I won’t go into, but those are the primary ones and those matter. Those matter for consumers. Resource adequacy is a big deal. We have to have a reliable set of resources that we can count on to serve demand at all times. And the states have a huge voice in that in SPP. Not only do they have a voice, but they have authority to direct SPP to make changes to our program.

Same thing with cost allocation for transmission. You know, transmission is an asset that costs a lot of money, but it’s very valuable in unlocking deliverability of resources and energy to places that wouldn’t otherwise have access. And how do consumers pay for that? Well, that decision rests in the hands of the state commissioners in our RTO.

Stone: So the states can make filings on the market directly with FERC. Does that go through a process within SPP, a stakeholder process?

Nickell: It does. Yeah, it does. And by the way, the term “market” gets used a little loosely. When I talk about the rights of the regulators, it’s primarily around our function as an RTO. Our regulators don’t make decisions around market design, the design of the real-time and day-ahead markets. They have responsibility primarily for what you might consider as planning functions, planning for resources and planning for cost to be allocated for transmission upgrades. And so I just want to make sure that that was clear.

But stakeholders get a chance to weigh in on those issues that are that are being developed and being addressed. And the board also has the option of creating its own proposed filing in those areas. So far, every time the regulator community has made a decision on a certain resource adequacy or cost allocation policy, the board has agreed. And we’ve made a single filing supported by both the independent board and the regional state committee. But they have the option. If the board wants to take a different approach, the board could direct staff to file a competing proposal to FERC.

Stone: Let me bring up one other concern that’s surrounded the Western expansion of SPP. And it’s not unique to SPP, but it has come up in this context. And FERC has actually raised this concern even when it approved the RTO expansion. And that’s the issue of seams. And seams are the borders between one market and another market, or one market and a neighboring utility, what have you. And seams become an issue—and I’ll ask you to kind of go into more detail.

But my basic understanding is, a seam creates an issue when you’re trying to share electricity freely and efficiently over a wide area. If you have these borders, the seams are kind of like a customs booth or something like that, where it just kind of gums up the transfer from one border into the next. So tell us about the seams issues, the extent to which these common markets, such as RTO West and Markets Plus may solve that issue. But also where you’ve got the California ISO border in the future, that can also create a bigger issue. Tell us about seams.

Nickell: Yeah. So the way we think about seams are these are areas where energy flow faces friction. Within a market, the friction is for the most part eradicated. But across the seam between two markets, there’s a friction. Some people might refer to it as a hurdle or a barrier. And ideally, seams agreements can be established between those two market operators such that the friction is either removed or at least reduced. That’s the idea. That’s the ideal way to deal with a seam. And I think we’ve largely done that in the East.

And I’ll give you some examples of why I say that. I remember during Winter Storm Fern earlier this year, SPP had excess energy and delivered about 3000 megawatts to MISO. And that kept them from having to interrupt load or interrupt service to certain consumers within their footprint. They were really tight on energy supply, at least during the early part of that winter storm. And we had excess and were able to quickly generate and deliver that energy to them that kept them from having to interrupt consumption.

By the same token, in Winter Storm Uri, back in February of 2021, we were importing about 14% of our demand at times from other parts of the country. And that wouldn’t have happened without a seams agreement being in place that allowed for that frictionless delivery of emergency energy.

Stone: Say between SPP and ERCOT at that time, right?

Nickell: Well, at that time, we were receiving from as far away as PJM. PJM and MISO both were delivering emergency energy to us. And so that was because we had a seams agreement in place. We think we can do the same thing in the West. Is it going to be perfect? Probably not. But at least we can establish the types of procedures that are needed to assure that both markets can reliably serve their customers. And we think we can do it in a way that will allow for economic trade between the two markets.

The other thing I’ll say, though, is because of the nature of the way that the EDM and Markets Plus markets are being structured, the fact that there is still a lot of autonomy in place between the utilities that will be operating in either of those two, there’s still going to be a lot of seams, regardless of whether those utilities are in California’s EDM or SPP’s Markets Plus. It’s only when you get a true single balancing authority RTO structure that you eliminate a lot of those intra-utility or inter-utility seams. But we can manage those. I truly believe we can manage those much like we’ve managed seams in the East. We’ve shown success at being able to do that, and I think we can do it in the West.

Stone: Are there particular challenges or hurdles to getting these seams issues to these agreements written? I mean, if it’s so simple, it sounds like it wouldn’t be an issue. But again, FERC pointed out that these issues still remain open and SPP is going to have to address them.

Nickell: Yeah. Well, and to me, the biggest issue or the biggest inhibitor to establishing a properly functioning seams agreement is when the two parties don’t come to the table.

Stone: And why would they not?

Nickell: Who knows? There could be reasons why one of the two parties either doesn’t want to come to the table or may not necessarily want to achieve an agreement that best meets the needs of both parties.

Stone: Would that be maintaining the independence that we talked about earlier?

Nickell: It could be that certain participants are wanting different outcomes. That’s a challenge when you’re trying to represent multiple parties in a seams negotiation. And maybe part of those participants want something and the other part doesn’t. You know, for example, SPP will have 11 utilities that will be participating in Markets Plus. But what if six of them want one solution and the other five want a different solution? And same thing with California. What if one of their utilities wants this and the other utility wants that? How does California, or how does Cal ISO negotiate under those circumstances?

So those do create challenges. But the bottom line is, get everybody together. Come to the table, try to find ways to meet in the middle. That’s how you move forward. And it’s taken time in the East. I’m not going to say it was easy. It wasn’t. But I think if the tone at the top is right, I think that makes a huge difference. And it creates a path forward for people to want to come to terms, to want to discuss how to get something done that meets the needs of most parties in the middle. And so that’s a challenge, but it’s certainly possible.

Stone: Let me ask you one question I probably should have asked much earlier in this conversation. That’s just to help people visualize what’s going on. So the West is really big. A lot of states. You know, briefly, can you give me an idea of what actual territories are covered? I think we talked about the Western RTO, but maybe make that a little bit more clear. And also with Markets Plus. And what is covered by the California affiliated market as well. How much of the West is in play at this point? What is still outside of these markets?

Nickell: So when we expanded our RTO into the West, we basically added three new states within which we would be operating. And that was Colorado, primarily, and then Utah and parts of Arizona. So those were the three new states. So now we serve 17 states with the RTO, or at least operate within 17 states as the RTO. With Markets Plus, you know, I don’t have an exact list of all the different states, but I know the Pacific Northwest.

Stone: So it’s really extended way out.

Nickell: It has. Yeah. I mean, we would be operating in certain parts of Oregon, Washington, Idaho. That’s primarily the Pacific Northwest area. And then, of course, the desert Southwest. Arizona, much of Arizona would be participating in Markets Plus. And then even more of Colorado. A public service company of Colorado is wanting and has received approval to participate in Markets Plus. So our footprint would be pretty expansive in that regard once that happens.

Stone: I have a couple of final questions for you here. And one of the questions that’s obviously on top of everybody’s mind we’ve talked about a little bit earlier. And that is this AI data center load. Again, I’m here in the East, and we are really dealing with this in a big way, particularly in PJM. Other markets as well. And a lot of governance discussions going on. Stakeholder discussions are going on about how to deal with that. Tell me about the AI challenge in SPP. How big is it? Where is it? How quickly is it coming on? And, you know, how much strain is it putting on the system? And what are you doing about it?

Nickell: We are planning for a lot of this load to materialize over the next 10 years. Our transmission plan is currently forecasting— or at least the models that we’re using in our transmission planning process currently contains forecast that would see our load, our current peak demand, doubling in 10 years.

Stone: Wow.

Nickell: So like I said, we’re at 56,000 megawatts now, peak demand. We could easily see that increase to about 110,000 megawatts over 10 years.

Stone: That’s astounding.

Nickell: Now, not all of that load that’s in the forecast is AI data center load. Some of that’s manufacturing. Some of it’s electrification. We actually have quite a bit of oil and gas in our footprint. The Permian basin and the Bakkens, to the north part of our footprint, represent a lot of load that wants to electrify. And so that’s part of it.

But still it’s a huge challenge. I mean, doubling your peak demand in 10 years is unheard of. We’ve never planned for that kind of load growth ever. And so it is going to require a tremendous amount of transmission investment. We’ve already approved roughly $10 billion worth of transmission investment just because of that load growth. And we expect there to be more.

Stone: To accommodate that future load growth.

Nickell: Yep. We’ve also done some pretty cool things on a policy front. FERC, our commission, the Federal Energy Regulatory Commission, has approved some of these changes and has been really complimentary of our innovative thought process. To be able to accommodate these large loads, we actually have a process that allows us to study the impact of those loads connecting to the grid. And if they want to bring generation with them in a co-located fashion, we can do not only the load interconnection study, but also the generator interconnection study in 90 days or less. Not only is that innovative, but that’s really, really fast. So it helps facilitate the speed to power mission that the current administration has. And a lot of our customers in states want to see as well. That’s just an example of some of the really remarkable things that we are beginning to do. And we have FERC’s approval of those policies. And they’re very excited about that as well.

We also just got approval, in fact, a couple of days ago, for our conditional high impact large load service. We call that CHILS. And it allows these large loads or data centers to connect. And as long as they bring generation with them, we can connect them immediately, as opposed to having to wait for the transmission network to be built out, as long as they’re willing to be curtailable. And so, again, we’re just trying to provide options. We’re trying to give them as many options as possible.

Stone: So they’re bringing their own generation and-or they’re curtailable?

Nickell: To receive the CHILS service, they would have to bring their own generation with them. But they wouldn’t be dependent on future transmission upgrades, which could take years to put into place. As long as they’re willing to be curtailable.

Stone: So, let me ask you the final question here. And I’m going to put you on the spot. But you’re the CEO, and you’re the head of the organization that’s making these changes in the West. So, I want to ask you if you could tell us what the West is going to look like 10 years from now. Do you see a single integrated market, two robust RTOs, some mix of EDAM and Markets Plus with full RTO membership? What’s the vision? What’s the ideal? And what do you think the reality will look like?

Nickell: In 10 years, I absolutely believe that there will be at least two well-functioning markets. And I think we will see our RTO continue to expand, but I at a minimum think there will be at least two well-functioning markets, at least two.

Stone: Full RTO markets, or a combination of the day-ahead?

Nickell: I think it’d be a combination. I think it’d be a combination of expansion of the RTO markets as well as the coexistence of real-time and day-ahead markets in the West.

Stone: Lanny, thank you very much for talking.

Nickell: You bet. Thank you, Andy. It’s a pleasure to talk to you.