S2E23: With a study finding an enhanced market structure in the West will save billions, California ISO's Mark Rothleder details the incremental approach to moving the region into a more organized market, and maybe one day an RTO.

California ISO's Chief Operating Officer, Mark Rothleder, details a new study finding that an enhanced day-ahead market, or EDAM, encompassing all 38 balancing authorities in the West, would provide billions of dollars in economic savings for consumers. But EDAM is not a Regional Transmission Organization. Utilities would still control their grid systems. The construct lacks the independent grid oversight of an RTO. But Rothleder sees the enhanced market structure as the beginning of an incremental process that may, one day, bring the sprawling interconnect together under an RTO construct. Or maybe not. That would be okay, he says.

But there are active discussions among a range of parties about some form of a regional RTO, he notes. "All these ... different forms of regional opportunities ... are being discussed, and not being pushed by the regulators or the FERC. These conversations are organically happening because the utilities and the regions are seeing the changing system conditions and the need for broader collaboration as a means to enhance reliability, but also unlock, really, the benefits, the economic benefits as the system transitions."

Transcript

EMP S2E21, Mark Rothleder, COO, California Independent System Operator
(edited for clarity)

EMP: Welcome to the Energy Markets Podcast. I’m your host, Bryan Lee, and today we’re talking with Mark Rothleder, Chief Operating Officer with the California Independent System Operator. The Cal ISO was established a little more than two decades ago as part of California’s electricity market restructuring to oversee the state’s grid, as well as the marketplace for sales of bulk, wholesale power. Mark, welcome.

MR: Thank you. Thank you for having me, Bryan.

EMP: We reached out because the ISO recently released a report about the economic savings and efficiencies that consumers in the Western grid could realize, if all 38 balancing authorities participated in what's called a day-ahead market, or as the report calls it an Enhanced Day-Ahead Market or EDAM. The report found if the region went beyond just a real time and balanced market and developed a day-ahead market, that $1.2 billion in economic savings could be realized. That's a big number. Tell us about the report's findings, delve into the numbers, the economic savings, and how those savings are derived and how you structured your analysis.

MR: So, first off, this analysis was performed by Energy Strategies. This was not performed by the California ISO. And that $1.2 billion is the total savings, both operational and what they classify as capacity savings, across a day-ahead market if a day-ahead market was implemented across the entire Western Interconnection. And so if I break down those savings, there's about $540 million of operational savings. And the way operational savings are quantified is basically it’s savings either to load of accessing, being able to access lower-cost supply and/or supply being able to access higher-priced markets and in a way that is not impeded by friction between the areas. And so that operational savings, about $540 million, is what they quantified as those operational benefits – effectively the lower cost to operate the system, serve load across that footprint, versus the existing business-as-usual, where some of that friction gets in the way from efficient dispatch and operations. The second category that they quantify was capacity savings. And they quantified that as about $650 million of potential capacity benefits. And the capacity benefits really involve, my understanding is, the reduction of capacity costs and the capacity needs if you have these 38 balancing areas in the West, instead of having to, on a daily basis, have enough capacity for their own demand, you get the benefit of the diversity of the resources. So, one area may peak at one hour whereas another area may peak at a different hour. And so the simultaneous load is effectively lower than the individual if you aggregate and bring all the individual peak loads at different times together, the amount of capacity needed to meet the simultaneous peak is less. And you can quantify those savings of those diversity benefits. And I think those diversity benefits – those capacity benefits – are also an indication of being able to effectively access capacity across the West and open up the possibility of accessing capacity at a potentially lower cost than you otherwise would have. So those two numbers, $540 and $650 million, put together is a $1.2 billion of total annual savings that they attribute to an extended day-ahead market across the Western footprint.

EMP: I looked into the analysis, there were all kinds of myriad factors that were taken into account by your consultant in terms of developing this report.

MR: They did some initial work or work a couple of years ago – it was called the state-led study. And this was effectively building on that work. Some of the differences that this study work included was they didn't, in the original work, we felt and we wanted to see what the additional benefits were of sharing what we call this imbalance reserve across the system. Imbalance reserve is a reserve that is developing and it really is a reserve to cover effectively uncertainties that can materialize – load being higher, variable resources delivering differently than what you had forecast initially between the day-ahead and real-time market. So they added that into the quantification and the work that they did originally in the state-led study. And the second thing they did was they broke down some of what they thought were going to be some friction or economic barriers from efficient dispatch between the areas. And so they removed what's called hurdle rates that kind of represent some of the economic friction that occurs between areas that they were anticipating would still exist under a day-ahead market alone. And in following the development of the market design, they agreed that maybe studying that and looking at it differently, since we were making some design considerations to eliminate that friction – eliminate those hurdle rates between the areas. They incorporated two additional elements to their study on top of what they had done previously for the state-led study.

EMP: In addition to the operational and capacity efficiencies, the report found a day-two market would help increase market entry by renewable energy resources by more than 1,800 gigawatt hours? How much is there on the grid now, renewable energy, and would it double, triple the amount? Put that into perspective for us?

MR: I don't have the west-wide amount of energy in terms of renewable resources. In California alone, we've got probably well over 20 gigawatts or so and you can get more accurate on that. But about 20 gigawatts of renewable resources whether it be wind, solar, geothermal, biogas, biomass. But we have a significant amount of renewable resources relative to our demand. I think what this is indicating is that as the rest of the West decarbonizes, and they're considering adding more renewable resources, I think there's an expectation that the utilization of those renewable resources and the opportunity for increasing those renewable resources across the West increases. Which is consistent with what we've seen in other study work. The extended day-ahead market and effectively doing a regional dispatch allows you to make better utilization of those renewable resources. And in doing so it does support integrating more renewable resources into the system.

EMP: A representative of Western Resource Advocates told Utility Dive that the proposed day-ahead market is a key step toward a regional, organized wholesale energy market that will include decarbonized energy resources and demand-side options. So clearly Western Resource Advocates is on board with this. How is this received in other quarters, in other Western states?

MR: I think a lot of areas are looking at this opportunity and they're considering for their state, or their region, or their utility, options to join more of an organized market. You have to realize that there's now probably about 78% of the West is already in the Western Energy Imbalance Market, being dispatched optimally by the ISO already. So it's not surprising that all those utilities would be interested in considering joining the extended day-ahead-market. And so they see the opportunity, they've seen the benefits of the Western Energy Imbalance Market to the tune of about $3 billion since 2014. And so they're looking to see what do they do next? And the extended day ahead market is the next thing to unlock some additional benefits for consumers across the West. And so it's not surprising that they're doing that. Now, why are they doing that? They're going through their own transitions. And they're retiring resources. Their load profiles are changing just due to changes in their local areas, but also climate change. They are integrating more renewables. And as a result of that, they're looking to see how they can operate better, more efficiently, and they see the EDAM as an opportunity to help them operate in the most efficient way they can.

EMP: Well, help me understand. So you're solely talking about an enhanced day-ahead market. You're not talking about independent control, or management of the 38 different balancing areas?

MR: No, no, no, I'm not. I'm just talking about an incremental step to the extended day-ahead market. It's a logical step. It unlocks, again, that benefit of being able to coordinate in the day-ahead market. What I mean by that is you can make better decisions if you knew what your neighbor had available. You could commit a different set of resources. If you knew that, what those resources’ bid structure were, you'd make better decisions by effectively, like I said earlier, diversifying your imbalance reserve or your uncertainty across the system. And so it's a natural next step. It is not an RTO. And I think the differentiating feature between EDAM and RTO is that the balancing areas maintain control over their systems from a reliability perspective. They maintain that reliability responsibility. They maintain control over the transmission that is in their area. Now, they make it available. They provide transmission to the EDAM, but ultimately they are under control of their transmission. So bigger decisions like transmission planning, infrastructure planning, resource planning, resource adequacy – those types of decisions are maintained locally by the balancing areas and the local utility under an EDAM concept, the extended day-ahead market concept. If you go to an RTO, you then go into that realm of having to turn over transmission for the market control. You then do kind of integrated planning. You probably have some kind of common resource adequacy mechanism across the RTO footprint. You may consider things like capacity markets, long-term capacity markets. So this is an incremental step but it's a step that is differentiated from an RTO.

EMP: That's interesting. Has any region put in place a day-ahead market prior to having an RTO in place?

MR: I'm not aware of that step being taken. This may be unique, but similarly we did the Western Energy Imbalance Market and no one had done a kind of real-time energy imbalance market prior to that. So I think we've demonstrated how a novel approach at looking at these markets can work in different regions. And I think the WEIM has demonstrated that. The EDAM is kind of a natural next step.

EMP: So you say “next step.” You called it “incremental.” So are there talks underway about establishing an RTO or is that still a scarlet letter in the region? 

MR: There's, there's conversations being had. People are talking about unlocking value, increasing reliability. So there are discussions that are taking place. I wouldn't say that they're at the point where those decisions are being made. I think they're looking at the EDAM as a natural next step. And before they go on to consider an RTO, they'd like to see how this plays out. Like I said, the RTO is a much bigger decision to be made. And, there's a lot more things to consider if you're going to take that step. We may get there across the West. But my feeling is that the roadway to an RTO at least goes through an extended day-ahead market. And for some, the extended day-ahead market may be as far as some utilities will be able to go. And that's perfectly okay. And we are designing it to be something that people can be in, and if that is as far as they feel like they can go, we are prepared to support that and the design is intended to do that.

EMP: Twenty years ago, 20-plus years ago, I was at FERC in the media relations office when the commission was trying to pass a rule called Standard Market Design. This region, especially the Pacific Northwest, was what I would call a hotbed of opposition to this top-down approach to RTO development across the country. And you know, SMD went away. But part of the problem was trying to push grid regionalization in the wake of the Western Energy Crisis. Are there still lingering concerns from that, all that time ago?

MR: Yeah, I mean, people's memories are long and certainly there are lingering effects of people have concerns about organized markets – what the implications are, the design of them. But I think those concerns are offset by the interests of a more reliable, coordinated operation across the West. And you can see that in various forums. You see the West getting together and parts developing a regional resource adequacy program through the Western Power Pool. There's efforts underway there. There's efforts to look at organized markets and RTO potential by certain states. There are utilities that are getting together, like you said, talking about or discussing the longer-term opportunities for RTO. And then you've got things like the EDAM design and offerings that are developing. Again, all these are different forms of regional opportunities that are being discussed, and not being pushed by the regulators or the FERC. These conversations are organically happening because the utilities and the regions are seeing the changing system conditions and the need for broader collaboration as a means to enhance reliability, but also unlock, really, the benefits, the economic benefits as the system transitions.

EMP: Well, it's quite a change of heart from 20-plus years ago when there was a lot of pushback. What do you account for the change? You know, it didn't happen overnight. It took a couple of decades. Is it basically the need to integrate a whole lot more renewables and rely less on centralized stations?

MR: I think that's a big element of it. I think there's realization that this transition is only midway into the change. So you've got a major shift in types of resources across the West. So regions that have traditionally been rich with supply and dispatchable supply, or baseload supply, they're probably seeing some of their baseload supply setting up for retirement. They're seeing the drivers to renewable resources, whether it be RPS policy or just natural economics driving you to renewable resources occurring. And, and even the Northwest is, with their rich supply of hydro flexibility, they're seeing the value, the potential value of those resources. And so I think both load and supply are coming together and realizing that there is real value in this collaboration. And some of the concerns of the past are starting to not completely go away but maybe fade away or be addressed more explicitly through some of the market designs.

EMP: I sent you before we got together today a news item about 30-plus organizations that wrote to DOE Secretary Granholm, and asked that as the Energy Department considers all of these funding opportunities that are going to be available through the Inflation Reduction Act and the infrastructure bill, that they take into account actually doing – it seemed to me – I interpreted it as they wanted more of a top-down approach. They wanted DOE to direct and guide and encourage more of the RTO development in regions like yours. How do you look at the IRA and the infrastructure bill? How is it going to change things?

MR: Let’s probably unpack that question a little bit. In terms of the IRA, I think it just is another accelerant to the transition. I think it will drive additional renewable resources. It will drive this transition to a low-carbon grid, which it is intended to do. And it will probably help fund some of – not just the resources, but also some of the transmission development that's needed to support that transition across the West. I think if you're going to build transmission to integrate these renewables, getting them from supply centers to load centers, what you want to have is an efficient marketplace to also operate that system so that that supply can get to demand and deliver the benefits to not just one state but the entire region. And I think the linkage between what IRA is doing and what the broader consideration or interest in markets is, like I said, if you're building this transmission, you want to make the most efficient use out of that transmission that you can. In both new transmission and existing transmission. And I think the market – an EDAM market, or an RTO – really help drive you to making the most efficient operational use of those assets that you can. And so I think the natural progression is that this transition is underway. It's going to be accelerated with the IRA. And now you really want the most efficient marketplace to complement those types of decisions.

EMP: You’re a career California ISO employee. Have you been with the ISO since the very beginning or shortly thereafter?

MR: I was there. I've been here since the very beginning and before the beginning. I helped start up the ISO.

EMP: You’ve seen a wealth of change. You weathered the 2000-2001 hair-on-fire emergency. Now you've got wildfires and you've got an incredibly changing resource mix. How are y'all doing with that? Do you need therapy? (laughter) Just a joke, just a joke.

MR: Look, in such a fast-changing, transitioning system, you tend to be a little late in responding to that transition. And you throw in there the fact that climate change is increasing demands across the system, and you realize that you’ve got to take faster, larger actions to keep up with the change, whether it be resource mix change, or load growth, or frankly the combination. And I think we are in the middle of adjusting the pace of responding to that change. And you see it now. I mean, we've added a significant amount of new capacity over the last couple of years. The California Public Utilities Commission has authorized significantly new levels of procurement. Their Integrated Resource Plan is indicating even larger amounts of resource needs and growth to transition. And we are in that process of that change. And we, as the system operator, while we are not responsible for setting the pace and setting the course of the resource mix change, we are responding to make sure that we can operate the grid and the resources that are available to us in the most effective way. One of the success stories in the last couple of years is that we went from probably about 200 to 400 megawatts of storage, battery storage, to now well over 4,400 megawatts of storage for our lithium-ion battery storage. And we're seeing it effectively doing what you'd want it to do. We've now got a large amount of renewable clean resources that are producing in the middle of the day. Sometimes in the surplus. Take that surplus, charge up batteries to the point where, when you're in that evening load pool for three or four hours, we're discharging those batteries and effectively adding 3000, 4000 megawatts of now supply injected right when and where you need it is a real success story. And that is both the combination of the state taking action to authorize new procurement and us, as the operator, adapting the systems to operate those new resources the best way we can

EMP: Well, you took me where I was going go next, which is storage. There's an ongoing debate. Are we trying to transition too quickly? Or, there a lot of voices out there saying we're transitioning too quickly, and we're not going to have the 24/7 fossil fuel-fired resources we need to balance the grid in a future clean-energy grid. But batteries are rapidly developing. You're already seeing an impact. And we haven't even got EVs totally saturated yet, which is a whole ‘nother resource for you, right? Vehicle-to-grid?

MR: Yeah. So depending on which way you want to go, I mean, yes, we talked about the batteries. I think one of the benefits of doing this transition is that you then can leverage a clean grid for decarbonizing other sectors. And you see that. You see the electric vehicle mobility sector accelerating its pace of change. If you didn't have a companion grid that was decarbonizing, you may be just charging with higher-emitting resources. So you've got to do this kind of sequentially and in an organized way. And to your point, now if you add a lot of electric vehicles, in part it's going to add load to the system. But if you can do some of the vehicle – managing when vehicles are charging or even yet, have them deliver energy back to the grid, vehicle-to-grid – now you have a new resource at your disposal to take care of some of these needle conditions, tight-supply conditions, and it becomes a new resource for you. So that's where the symbiosis of decarbonizing one sector and then leveraging another sector and having additional resources at your disposal is really kind of the future. It will benefit both sectors ultimately.

EMP: I brought up the storage because that's kind of the answer to a more decentralized grid, more distributed generation resources. Are you having difficulties in terms of operating the grid? Because there's not enough natural gas-fired peakers and backup generation?

MR: I wouldn't say we're having difficulty because we don't have enough gas-fired generation. I think we're having difficulties in these extreme weather conditions that basically stretch the entire resource mix, not just gas resources. That takes really a new paradigm of planning to make sure that you're taking these additional uncertainties and these additional risk factors into your planning process. It used to be that you would do loss-of-load probability analysis, do statistical analysis of what your risk profile is and try to shoot for less than a one-in-ten event loss-of-load probability. But all these measures or mechanisms assume that you have a known set of distributions of load, you know your patterns of generation outages and availability. And a lot of those things are changing. Load, the load profiles are changing. With  climate change, we're seeing the extreme weather conditions and extreme load conditions happening more frequently. So we have to adjust our assumptions, our input assumptions, if we're going to get the right answer out. The resource mix is changing. So the variable resources have their own uncertainty profiles. Those need to be better factored into these analytical approaches. Until then, until we catch up on the input assumptions, we're going to probably have to carry additional capacity to cover these uncertainties. And that's what's happening now. We've got some mechanisms for trying to achieve one-in-ten loss-of-load probability. But then knowing that some of these extremes, whether it be wildfire conditions or extreme heat conditions, kind of can put you outside of those study conditions. The state of California has set up a strategic reserve to cover those events. And that will help us through the transition. Eventually those will be probably migrated to other things like distributed energy resources or demand-relief programs as a measure. You already see some of that develop. But in the meantime, we may have to keep some of the resources that were expected to retire a bit longer to allow for a smoother, reliable transition.

EMP: Yeah, well, it sounds to me like you've confirmed my suspicion, which is that some folks are looking at all of the problems we're having because of the rapid climate change we're undergoing, putting all these stressors on the grid, and they're blaming renewable energy market entry on that rather than the increased complications of operating a grid in a warming world.

MR: Yeah, I agree. And I mean, our feeling is, this is not the time to slow down. This is the time to really accelerate and be more deliberate about those changing resources. Bring on new resource capacity that can do the things you need to do, but it's still clean, whether it be batteries or geothermal. There's a lot of new mechanisms that are developing and we need to exercise those new mechanisms for not only clean, variable resources, but also clean, firm dispatchable resources. It's going to take some combination of both dispatchable, firm-dispatchable resources as well as the traditional renewable resources to get through this transition. And we're learning as we go. But we are demonstrating how this can be done.

EMP: It's an amazing high-wire act to keep exactly at 60 hertz over such a large distance. I want to talk about distributed energy resources and demand response. The small incremental type of capacity and resource additions that are not attractive to necessarily a utility which needs a larger-scale investment. Have we done enough to integrate those resources? You know, we clearly don't have yet retail load responding to market price signals, do we?

MR: You're seeing a little bit of it. We've got some distributed energy resources, demand response, that is responding to market signals, actually participating in the wholesale market. But I would I say it's not nearly enough. And it's not really fully utilizing the opportunity out there. So I think that is a work in progress, but it's a real area of opportunity. In my view, having the demand being able to respond automatically to price signals is probably the most effective way to get to scale. Trying to ask a human to do something, to change their thermostat, or do something – while we've demonstrated we can do that – we really believe that it's more effective to have prices-to-devices and let the devices automatically respond to those signals. You get much better fidelity, you get much better responsiveness. And you probably, if you do it right, and you put in the right incentives, you probably get to scale better than what you can through some kind of manual demand-response mechanism. So, I think it's part of the solution. It's not the whole solution, but it is part of the solution. And this is, again, as you decarbonize in other sectors, you should also think about how to integrate and make those other new participants, new load participants, part of the solution, having them either charge at different times or if they're talking about heat load, and heat pumps, how do you manage those in a way that doesn't undermine their utility to the consumer, but allows them to, in aggregate, really provide some additional tools to temper the demand when needed.

EMP: Yeah, we've had an explosion in artificial intelligence developments, I think, in recent years, and I guess that AI could go a long way towards getting us to a set-it-and-forget-it state?

MR: Absolutely. It's a matter of really putting the effort now to do that, send the right signals, send the right investment signals and kind of integrate it into the utility and dispatch process. 

EMP: Well, let's change gears a lot because we've got a topical news item that's really important, I think, to the industry. And that was the attack in North Carolina, where somebody took out transformers and whatever else with a gun attack. There must be a whole lot going on right now between Homeland Security and FBI and NERC and you guys in terms of – I guess what I'm asking is, are we going to see a lot more hardening of the system? Jon Wellinghoff was on TV today saying, you know, we need to build barriers so that that sort of thing can’t happen.

MR: I think this hardening effort has been in the mix for several years. And it will continue, whether it's hardening for these types of vandalism or attacks on the system, or whether it be just cybersecurity types of things, or as a result of weather events. So there's several things that are driving this need to harden the system and make it more resilient. And I think you're just going to continue to see those types of things occur. I can't speak specifically about the North Carolina event. But we've experienced our own events. They've been part of the public discussion a few years ago, and there is hardening that results from that.

EMP: Yeah, you mentioned cybersecurity. I wanted to bring that up in terms of our prior discussion about set-it-and-forget-it and, you know, intelligent devices and that sort of thing. Cybersecurity is a big concern in terms of that when you've got all of these multiplicity of devices connected to the Web. I guess people are working on that, right?

MR: They're working on both the AI front and to making sure that the protocols and the mechanisms for those devices are as secure as possible and don't create a new threat vector. So that's part of doing it – not just do doing it to achieve the demand-response objective, but doing it in a way that also is secure overall.

EMP: Well, Mark Rothleder, chief operating officer with the California Independent System Operator. Thank you very much.

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