Karen Wayland: I'm really concerned about the ability of small utilities to make the necessary investments in a modern grid. There's a clear connection between upgrading equipment on the grid and the experience that a customer has. We have to make sure that as we get this growing convergence of electricity with the transportation system, with the communication system, that everyone has access to this modern grid and that we're not leaving parts of the country behind.
Teri Viswanath: That’s Karen Wayland, and amongst the many hats she wears, CEO of GridWise Alliance is one of them. Hello, I’m Teri Viswanath, the energy economist at CoBank and your co-host of Power Plays. This month, my colleague and co-host Tamra Reynolds and I wanted to explore why it’s so challenging to build transmission lines in the U.S. And, what can be done about it. Hey Tamra.
Tamra Reynolds: Hey Teri. There was a funny headline I recall seeing some time ago, “The Best Time to Plan Transmission Was 15 Years Ago. The Second-Best Time Is Now.” I think it sums up the general feeling that planning and beginning to build the future grid probably should already be happening. And yet, we find ourselves with a backlog of new generation projects queuing in every ISO in the country. There’s no doubt there is a need for reform, but a lurking problem driving interconnection delays is the lack of transmission. And there are mounting costs associated with the growing transmission congestion we see occurring on the grid.
We asked Natalie Smith, president at GridLiance, a NextEra Energy Company about this. GridLiance owns over 700 miles of transmission lines in three RTOs: SPP, MISO and CAISO.
Natalie Smith: The last wave of major U.S. transmission development ended about 10 years ago. And the transmission system is running out of spare capacity, contributing to increased grid congestion, which ultimately leads to higher electricity prices for consumers. Cost to consumers from congestion on the U.S. power grid more than doubled to an estimated $13.3 billion in 2021 from the year prior, and could keep rising until transmission capacity is built or upgraded.
Viswanath: Natalie’s statement is interesting to me because we know that more than 95% of queued ISO capacity is zero-carbon energy, with solar and battery storage representing about 80% of the new projects added just last year. So just how big is the transmission need for all of these new renewables? We asked Rob Chapman, the senior vice president of energy delivery and customer solutions at EPRI that particular question and here’s what he had to say.
Rob Chapman: When we talk about that level of renewable development today, people think it's significant, and it is, but it amounts to only 17% of the total capacity of the U.S. electric system. We have a significant additional amount to build if we're going to really achieve decarbonization of the energy system going forward. To give you an idea of that, over the next 25 years, on the renewable front, if we are to achieve that decarbonization the EPRI monitoring shows, we're going to have to expand anywhere from 4X to 20X.
Now the reason it goes from 4X to 20X, if we take other technologies off the table, whether it be advanced nuclear, whether it be carbon capture and sequestration, so that we can keep some level of fossil in the mix, that's when the equation becomes much more challenging. The renewable bill becomes much more greater and by extension, the transmission bill becomes much greater. So really understanding what that profile of the energy system is going to look like is key to defining what transmission requirements are.
Reynolds: Rob’s projections are based on growing renewables from a baseline of 20% of the current generation mix to something larger. A key consideration for those projections is the fact that solar panels and wind turbines are often located far from where retired coal and nuclear plants were sited, which were generally fairly close to load centers. So, there is a challenge to meet existing load with renewables but that’s not all.
Chapman: Remember if we're going to achieve decarbonization, it's not just in the energy system, it's economy-wide. When you think about load growth going forward, utility load growth has been by and large flat over the past 20 years. In fact, you heard for a while there was, they called it the death spiral, where utilities, the load growth was going to continue almost to decline and really create an issue in terms of the utility business model, how they earn money to support development of the system. Now what we're seeing is we're talking about 60% growth in electric load and a 40% increase in demand over the next 25 years.
Viswanath: There’s also an important climate nuance, on how that future load profile will look and what that means for regional transmission needs.
Chapman: What we're realizing is that as demand increases significantly during extreme weather events, people begin to use their appliances, their devices to heat or cool their homes. Demand increases, but we have this overload of the transmission capacity that we have. So we need a significant extension of what we call interstate transmission capacity. One region suffering a significant event, how do they leverage another region's capabilities in order to balance that going forward?
Reynolds: So, we can probably agree that there is a need for building transmission but how long will it take? Once again, this is Karen Wayland.
Wayland: There is no average for a transmission line from conception and engineering design to actually breaking ground and then finishing it, but we're talking probably not less than a decade for a new transmission line, and sometimes up to 15 years. We could get a big renewable, say, a solar project from design and permitting all the way through to being connected to a transmission line in three years or less.
So, there really is a mismatch between the time it takes to build new transmission lines and the time it takes to build new generation capacity. Then you add in what developers are experiencing right now with escalating costs for all materials, not just grid components, escalating wages, and rising interest rates. It really is a squeeze on the ability to move these projects fast. Supply chain constraints also for grid components is increasingly acute.
Viswanath: And there are other really important obstacles to getting transmission built.
Chapman: We know that we can build a transmission line that today is technically viable and economically feasible. But the third aspect that many love to overlook is this notion of what's really achievable, and achievable from a societal perspective.
In the '50s, we had two power plants in the U.S. that were 500 megawatts and greater. Twenty years later, in the '70s, we had 120 of those power plants. What changed in that era when we went from, I'll say, localized electricity solutions to more regional solutions with the scaling of power plants, is we had the opportunity to enable affordability.
The consumer had a direct cause and effect in that case. I see transmission lines, I see generation plants sprouting, but that is enabling affordability to me, and it's enabling me to make additional decisions that benefit me directly. The U.S. consumer was very into accepting because they ultimately saw an improved quality of life in the '60s and '70s.
When you get into the 2000s, there was a jump onto what I'll call the green energy transition, where consumers once again said, "Hey, it's important that we begin to transition to renewables."
The bottom line today is the value proposition from a consumer perspective isn't as tangible as what it used to be back in the '60s when they saw some benefit in terms of additional comfort in their home, or in the 2000s where it was being driven as, "Hey, we can adopt renewables. They're going to be less expensive than what you currently have today. It's going to contribute to a green energy revolution."
The consumers are in the mix of this. They're looking at affordability, they're looking at the aesthetics, and they're looking at what's the value to me specifically when I see an expanded transmission line. They're not necessarily being able to connect those dots, which is what's making this so difficult.
Reynolds: There is a related topic of cost allocation. This is sort of the ‘elephant in the room’ issue that has to be tackled head on.
Chapman: That’s where it becomes challenging when you have multiple stakeholders involved in the interstate aspect of transmission. Cost allocation is a big part of that decision process, and a state will look at their benefits and assess whether or not that transmission line is providing them the level of benefits that they expect in order to impact their consumers in terms of any sort of rate increases.
Using Kansas as an example, significant amount of wind. They benefit from it within Kansas, but why should we, in essence, accept the development of transmission corridors across our state to enable a neighboring state?
There's got to be some economic value that makes sense for them in order to do that. That's really what's challenging many of the interstate lines today. When I mentioned resiliency previously and the need to really develop our interstate lines more specifically, it is to leverage those areas that are rich in a certain resource and help to support the others.
From an economic perspective, unless you make it worth my while, I can't see the value in doing that going forward. Unless there is some forcing function that looks at a different reliability standard, that looks at resiliency, that looks at different value streams that need to be taken into consideration in order to support that construction that might benefit Kansas consumers, it's going to be difficult to do.
Viswanath: Natalie Smith from GridLiance had an interesting take on cost share from a uniquely co-op perspective.
Smith: RTOs cannot see co-op assets that are not part of the grid that they manage. We call that holes in the Swiss cheese. If these RTO solutions do not involve cooperative assets, the cooperative is paying 100% for the assets that are not in the RTO, plus a share of the cost of any new transmission that is part of the RTO. It's layered on, double paying, and adding assets to the grid can allow projects to solve system needs. This can lower costs for everyone--co-op members and neighboring utilities.
Viswanath: So, part of the cost allocation arbitration might come from being part of an RTO. But getting transmission built is so important that we might see FERC weigh in as well.
Reynolds: That’s right, we had an interesting conversation on a previous podcast episode with Neil Chatterjee about this topic. And, transmission reform is considered a key policy development needed to unleash gigawatts of renewables onto the U.S. power grid. So can our federal regulator sort out cost allocation?
Chapman: That's really the role that we see FERC potentially playing if they could get in and play that arbitrator, but we really need to assess the value streams that would originate from the development of that transmission system. Can't just be based upon, "Hey, we're going to bring this cheap energy in and that's the value." There's got to be other value streams that are connected into that.
We're beginning to see FERC trying to play a greater role in terms of being able to resolve these differences amongst the states for interstate transmission. I think that's going to be important for playing the arbiter in that case, but we're also seeing some federal incentives that can help try to advance the financial or the cost allocation process.
Viswanath: Coming back to those mounting generation queues, Rob also weighed in on other ways FERC can help sort this out.
Chapman: I think it's going to take regulatory and policy push to get things moving forward. We're seeing a little bit of activity in this area.
One of the areas the Federal Power Authority has the ability to establish what they call national interests of electric transmission corridors. That's going to be very important to speed the siting and the permitting of various sites around the nation. That's looked at from an energy security perspective and the reliability resiliency aspect. To the extent that the FPA can really begin to drive some speed around siting permitting, that's going to be critical.
Reynolds: In our discussion with Natalie, Karen and Rob, it became increasingly clear what a monumental task it would be to build all the new transmission that is required. According to NREL, at the upper end of the nation’s requirement, 91,000 miles of new transmission might be needed by 2035. Last year, about 700 miles of transmission were completed in the U.S., down from 1,400 miles the previous year. Using these estimates, it’s clear we are not going to arrive at NREL’s estimate.
Viswanath: I know…which is why I hit the panic button in our interviews with Rob and Karen, and asked about a Plan B.
Chapman: To the extent that transmission expansion is limited, then a few things that we really do have to focus on. One is existing corridors that we have where the siting, the permitting, the lines are there. How do we maximize the capacity in those corridors?
I mentioned some of the things around advanced conductors and what we call grid enhancing technologies, whether that be power flow devices or dynamic line ratings that help to increase the capacity based upon the certain characteristics of the load that's going through. That's one, obviously very important. Let's take advantage of what we have today and maximize it.
Technology optionality needs to be a key part of what we're doing as we look at this. When I say technology optionality, I'm thinking about not only from an energy supplies perspective, whether that be advanced nuclear, whether it be CCUS—carbon capture and storage—but it also needs to be technology optionality at the customer level.
We know that electrification, or achieving economy-wide decarbonization, requires a significant amount of electrification of end-use. In fact, we're seeing that when we look at this, I mentioned the load growth previously 60% load growth, 40% peak demand growth but we're talking about even in the next five, six years, we expect flexible load to go from about 80 gigawatts today to about 250 gigawatts.
These distributed energy resources have a key role in helping to support the energy transition in the grid of the future. So how do we leverage these?
The last thing a potential customer of our system wants to hear is it's going to be years before we can provide you that load. We see utilities right now taking advantage of what I'll call demand response, being able to manage their peak loads by leveraging flexible resources and that opportunity is only going to grow in the future.
Viswanath: Karen emphasizes a similar approach.
Wayland: I don't think it's a plan B. I think it's a parallel plan. Plan B means that you're moving away from plan A, and plan A I think is building new transmission. But in parallel, we also have to pursue the increase of transmission capacity on existing lines.
In terms of increasing transmission capacity for existing lines, what we need to do is allow transmission owners to consider and install grid-enhancing technologies like dynamic line reading and power optimization that allow grid operators to better manage the flows of electricity through the existing transmission lines to increase the efficiency and increase the visibility so that you actually are increasing capacity at the same time and lowering costs.
We need to look at reconductoring. Can we increase the voltage of the lines that are in existing rights of ways? We're going to have to deploy more storage at the transmission level. That storage gives grid operators a lot of flexibility in terms of providing ancillary services to the bulk power system to maintain power quality but also to alleviate transmission constraints. That's going to happen at the transmission level. Then I think that we need to be more smart about looking at priorities for that new transmission. Where can we make better regional interconnections? Those shorter lines that are really connecting adjacent areas will have a better possibility of being constructed in the short term.
Reynolds: Another part of Karen’s “play the best hand you can with the cards you’re dealt” advice really speaks to beefing up our distribution systems.
Wayland: We do need to do grid upgrades that increase the carrying capacity of the distribution system, just like we can do with grid enhancing technologies on the transmission system, but look for more localized resources. How do we use distributed energy resources to provide more power and more grid services on the distribution system while those grid operators of the distribution lines are waiting for electricity to be delivered through the transmission system? That's the kind of suite of solutions that will get us through the period until we can get a significant amount of new transmission built.
In fact, that's what FERC Order 2222 is designed to do, how a suite of distributed energy resources aggregated can provide power and grid services in the bulk power system, as well as providing more flexibility for grid operators at the distribution level for meeting and controlling the needs of the grid to their customers at the distribution level.
We have to pursue both in parallel. It can't be one or the other. The difficulty I think right now is that so much of the conversation is happening about how do we accelerate the build-out of new transmission. Even if we could build out all the new transmission we need, I don't think that gives us the flexibility and the needs that the grid operators have in order to meet the growing electric demand that we're going to see across the country.
I will add that there's a real resilience need to look locally for resources. You've got to give grid operators options to make sure that the lights stay on and we can power critical services, even if their connection to the bulk power system goes down for some reason. There is such a strong resilience and security need to make sure that you can find electricity and grid resources locally as well as off the bulk power system that again, it isn't a plan A or plan B, we have to do it all together.
Viswanath: Ok, you know that I couldn’t just let Karen off the hook after making that statement. So, I asked for more details on what we need to do at the distribution level, and here’s what she had to say.
Wayland: I do want to start with AMI because I believe that advanced metering infrastructure is one of the basic building blocks for a modern grid and for allowing for the kinds of functions that we want that grid to provide going forward.
When you think about what grid operators need, as we start to see increased deployment of electric vehicles with their sudden pull of electricity or distributed energy resources like solar with a cloud passing by, you are going to need a lot more very localized, grid-edge controls of power quality.
The most advanced meters that we have today can do that in a way that old meters can't do it. Then we talk about the kinds of information that a utility can use from the data that's produced. Things like managed charging, things like sending time of use price signals to a customer. Things like really understanding granular electricity usage for forecasting and planning. All those things are enabled when we allow for full deployment of advanced meters.
Reynolds: Karen brings the conversation full circle, going back to Rob’s point about how electric consumers need to understand the value in the infrastructure being developed. This is a refresh around the 1950s customer who could clearly see the economic benefits of a reliable and affordable grid.
Wayland: We do, and in order for us to consider that, the full system, transmission and distribution, we need to bring the customers, fully integrate them into the grid. Because that's where a lot of the local resources are going to come from, is behind the meter. You have to start with the meter and then work out across the distribution system, and then also look at integrated planning between the distribution and transmission systems so that you can make sure that you can operate the grid in this coordinated fashion. That's only going to happen if we join the planning processes at the transmission level with the planning processes at the distribution level.
Viswanath: But once again this brings up important cost considerations.
Wayland: The investments that have to be made aren't just hardware. They're also the software data analytics and cloud storage that go along with the increasingly digitized hardware. We have to think differently. That increasingly digitized hardware and grid equipment looks and acts differently than what used to get deployed on the grid, and the lifespan of the equipment is likely going to change. Where we used to plan for, say, infrastructure that lasted 30-plus years, we are now looking at infrastructure. Some of the components may last 10 years before they become outdated.
We also need to think about the attached costs of the software and the data analytics that have to go along with modernizing the grid. We typically have separated out the software and data analytics as operational costs, not the capital investments that get made. But you can't separate them anymore because you can't really truly operate an advanced meter or a synchrophasor or a sensor that you put on a line to monitor temperature if you can't also utilize the data. When there are criticisms about utilities not using the data that they're generating from all of this new equipment, part of it is that they may not have the workforce that have the skills to do that and they may not actually have the ability to recover costs for the work that has to be done to crunch all that data and turn it into actionable information.
Reynolds: So, if we consider the building blocks for the grid of the future, the consumer has an important role, or as Rob and Karen might say, ‘parallel’ role to play.
Wayland: Let's take something like FERC Order 2222 that's going to allow customers with distributed energy resources to access the bulk power markets. That's an emerging market that will allow customers to be compensated for providing energy back to the system. If a customer is connected to a grid that doesn't have the necessary technologies to allow that aggregation, to allow the controls to get into the wholesale markets, then the customer can't take advantage of this emerging market. We really need to find a way to make sure that the smaller utilities, which cover a significant portion of this country, can modernize their grid at the same rate as it's happening elsewhere in the country.
There's a clear connection between upgrading equipment on the grid and the experience that a customer has in being plugged into the grid. We have to make sure that as we get this growing convergence of electricity with the transportation system, with the communication system, that everyone has access to this modern grid and that we're not leaving parts of the country behind.
Chapman: Just to summarize, in the event, the transmission can't be built and yet we think of renewables as being a significant contributor of decarbonized economy going forward, then we have to look at the localized solutions. We have plants that exist today. How do we expand the technologies that we know are low carbon or can be low carbon in the future?
Then how do we take advantage of customer-sided distributed energy resources to support this phenomenal growth that's going to go on in the industry? Those are the near term. Of course, then I mentioned taking advantage of existing right of ways today and expanding the capacity in those areas. It's really a threefold area to help get us to where we need to be in the event we can't get the level of transmission that's necessary.
If we can't do that affordably or reliably and resilient, we're missing what the consumers are really looking for. You really can't have one without the other if we're going to meet consumer needs going forward. I think that that's really important to overlay. Decarbonization has to be affordable, has to be reliable, and has to be resilient to bring consumers along with this energy transition.
Reynolds: This conversation provided an important perspective of just how much new transmission will be required, how quickly it might get built and the parallel need for a build-out at the distribution and consumer end. I do hope all of you have enjoyed the conversation with us.
Viswanath: And, that you will download our next podcast in October, when we talk about the interconnection between Big Data and Big Power. CoBank’s Jeff Johnston will join us for that conversation, along with the CEO of Northern Virginia Electric Cooperative. See you then!
