Can Competitive Electricity Markets Deliver Reliable Power?

An expert in electricity markets explains why market price signals alone will struggle to incentivize adequate investment in the flexible electricity resources needed for future grid reliability.

In the 1990’s the process of deregulation – or restructuring – of the U.S. electricity system began, leading to the introduction of competition to an industry that had for a century been dominated by vertically-integrated utility monopolies. Today, competitive markets produce two-thirds of the electricity consumed in the country. Yet concern has grown that these modern markets may not be up to the task of driving the types of investment needed to ensure that an ample and reliable supply of clean electricity will be available in the future.

Kelli Joseph, a senior fellow with the Kleinman Center, offers a deep dive into the theory of competitive electricity markets and the role that market price signals play in driving investment in many parts of the U.S. She explores the need to incentivize investment in flexible resources essential to the reliability of a grid that is increasingly reliant on natural gas and renewable generation, and discusses how electricity markets and policy might meet the challenges of the energy transition.

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.

Nearly three decades ago, the electricity system in the United States began a major transition. Starting in the 1990s, many of the utility monopolies that had dominated the industry for nearly a century were forced to divest of their electric power plants under a process known as “restructuring.” Restructuring had been set in motion by Congress, in an era in which a number of once tightly-controlled industries, including airlines and telephone service were open to unfettered competition with the goal of driving innovation and lowering consumer costs.

Law-makers’ goals for the electricity industry were similar. Competition among many independent generators would drive the traditionally risk-averse sector to explore new technologies and business models. Market forces would be unleashed, creating incentives for investment and ensuring that enough generating capacity would be available to meet demand. Yet the electricity sector has changed in ways that were unforeseen in the 1990s.

Many coal-fired power plants, which were once the staple of the industry, have been replaced by natural gas generators and renewables, both of which operate differently from the resources they replace. This modern resource mix makes management of the grid more complex, and as recent grid outages have shown, can create new challenges.

Critically to our conversation today, the shift in resources calls into question whether existing electricity market structures and the competitive forces unleashed three decades ago are up to the challenge of driving massive investment into new power resources that will deliver ample and reliable electricity supply.

Today’s guest is Kelli Joseph, a Senior Fellow at the Kleinman Center, whose recent work looks at why market price signals alone may not be enough to deliver a reliable electricity future. She’ll walk us through the theory and reality of competitive electricity markets and discuss how markets and policy might meet the challenge of the energy transition. Kelli, welcome back to the podcast.

Kelli Joseph: Hi, Andy. Thank you.

Stone: In the 1990s, the electricity system was restructured in this country. Monopoly, vertically-integrated electric utilities were broken up, and competition amongst generators was introduced. What was the reason for and goal of that process of restructuring?

Joseph: Yes, I think you covered a little bit of it in the intro, and if you recall, some of this came out of the ’70s and ’80s. We were experiencing environments of high inflation. There were new kinds of plants coming on the system. At the time, there were actually some new gas-fired plants, and you had a lot of industry that was really looking for lower-cost electricity production. They were seeing that potentially some of these newer plants were cheaper than what some of the utilities had, and they were paying off some of these longer-term costs over time, these investments. The idea was that by unleashing competition, perhaps there was a way to lower the cost of energy. In addition, part of the impetus was rather than having long-term investments that may or may not be ideal over time, that removing that investment risk from rate-payers was also a driver. So you had private entities that managed that investment risk, removing it from captive consumers. Those were some of the reasons why we look to restructure.

Stone: So broadly in a competitive market, price signals are supposed to drive investment in new generating resources, allowing the industry to achieve what we call “resource adequacy” or “sufficient supply to meet demand.” Explain how price signals would achieve this.

Joseph: Some of the idea, whether it was recognized or not in the early days, the idea really was that electricity markets are just like other commodity markets. In commodity markets in general, a lot of what you’re doing is hedging price risk and hedging delivery risk. As long as you have sufficiently liquid forward markets that you can trade different time horizons up to delivery, and as long as you have an incentive to deliver, it should do sort of the same thing.

So what the idea in electricity was, you’d have this symbiotic investment. You’d have generators that would potentially see high prices, respond, potentially build new plants. You’d also have consumers who would be exposed to these really high prices. In the electricity markets, these are called “scarcity prices,” so these are prices when demand is really, really high, and you’re dispatching the most expensive resources; or when grid operators are losing access to what are called “operating reserves.” These are critical resources that are needed, held in reserve to ensure that grid operators can maintain grid reliability.

At the highest demand time, or when these reserves are declining, you have really, really high prices called “scarcity prices.” The idea was consumers would see these really high prices at these times, and they would have an incentive to hedge against those prices. They wouldn’t want to be exposed to those prices, and they would find a competitive retail supplier or a load-serving entity, somebody to manage that price risk for them. The way that they would manage that price risk is by entering into long-term contracts with generators.

So generators either would enter because they see a really high price signal, or they would have an incentive to enter into a long-term contract through one of these LSEs or retail energy providers. All of that was supposed to be the mechanism for incentivizing entry, for ensuring that you’d have delivery at the time that you need it. You’d have enough generation resources as long as everyone was exposed to those prices, and as long as those prices were high enough. The prices would be the mechanism to make sure that you had the right amount of generation resources at the time that you needed them. That was what was supposed to happen.

Stone: I want to ask you in a moment how that actually turned out in the early days of the industry, but before that, I just want to point out something here that I think is pretty important to latch onto. These price signals into the market were, in essence, going to be a substitute for the coordinated, vertically integrated resource planning that the monopoly utilities had engaged in to ensure reliability over time. This was all going to fall on the markets. Is that right?

Joseph: Yes, that’s right. There was some concern at restructuring that you’re losing this vertically-integrated coordination efficiency, but moving to the market where you’d have investment efficiencies. You’d have production efficiencies. There would be other kinds of efficiencies that you had, but we lost this coordination efficiency. There were some people who were thinking about that, writing about that, concerned about that, but overall the idea that we would have other kinds of efficiency that would be better in the long run, that was kind of the idea, that as long as the prices were supposed to be enough to manage through that.

Stone: Competitive markets got off to a bit of a rough start. I’m thinking here about the 2000, 2001 California electricity crisis that drove Pacific Gas and Electric to bankruptcy and made Enron a household name. Besides that — that was obviously a very early example — but what generally was the early experience with competitive markets? Did they work and deliver ample low-cost, reliable electricity?

Joseph: For the most part, yes. We did have situations like in California. Some of that was related to the market design itself in California, which soon after restructuring, redid how they thought about things in California. But over time, yes and no, right? There were challenges with relying on prices alone to manage to have sufficient generation resources to meet reliability standards. That was one piece.

The second is that there really wasn’t sufficient bilateral contracting, so you didn’t see a lot of sufficient amounts of this voluntary hedging that was envisioned. And there were lots of reasons for that. Economists point to particularly a couple of ideas. The one that we’ve talked about for a really long time is this idea of what’s called “missing money.”

There are lots of reasons why the prices weren’t enough, and those include things like: If you enter into a long-term contract, you run the risk that that contract becomes more expensive than what you could purchase in the wholesale spot market, where you actually have the delivery. So you run the risk that you’re in this more expensive contract, so people didn’t necessarily have an incentive to enter into those as much as we thought or as much as what was the thinking.

You also had the risk that generators didn’t really want to be in these long-term contracts that might be lower priced over time than what they could earn in the spot market. In addition to this idea of having utilities divest generation, in a lot of places where we introduced electricity deregulation and restructuring, we introduced retail choice. So this meant that consumers could switch electricity providers. That also made it difficult for some of these load-serving entities to enter into long-term contracts, because they never knew how many customers they’d actually have and how expensive those contracts might end up being.

And then the final reason that a lot of economists point to is the idea that at the end of the day, consumers are not exposed to any of these real-time prices. They really never have been. They aren’t exposed to these prices, so at the end of the day, you’ll always have insufficient amounts of contracting, insufficient amounts of generation because there’s really no incentive to go out and do this hedge.

There are also concerns that utilities, instead of fully introducing retail choice, had kept this utility default supply. So you can choose your own supplier, but you don’t have to. You can stay with the utility. So for lots of reasons, economists point to this “missing money” idea. In addition to those early challenges that we saw for some of the reasons that I highlighted, we also knew that there were challenges with what’s called “price formation” in the wholesale power markets.

We also have concerns about market power now, as a result of having introduced competition in places where you don’t necessarily have a lot of generators, or you don’t have a lot of transmission. And you have certain generators that could have market power, so when you get to these periods where these really high scarcity prices matter, it’s also a time where it’s really hard to distinguish between those who are exercising market power and real scarcity.

Stone: Market power being manipulation of the market, right?

Joseph: Yes, it wasn’t clear if those were prices that somebody was taking advantage of being able to set, or if those were true scarcity prices. So we put price caps in place to mitigate that risk, but that also means that the price isn’t as high as it would be, in addition to these consumers not really being exposed to scarcity prices. But I’ll also say, taken to the extreme, the idea is if consumers don’t sign up for the right kinds of contracts or don’t pick the right LSE that comes with the right amount of generation resources, some economists point to this as a challenge, but let’s think about the implications.

So the challenges — well, you can’t really just isolate the handful of load-serving entities or retail electricity providers that didn’t bring the right contracts or didn’t have the right kinds of generation when we needed it. You can’t isolate and just shed load for those entities, so people point to that and say, “Well, that’s another reason why there’s a lack of incentive. Nobody is really ever exposed to what could happen.” But let’s think about that. That raises, I think, some pretty serious equity concerns if the idea is expose consumers to real-time prices in order to ensure that they hedge appropriately, choose the right LSE, and make sure their lights stay on.

It’s also not really how we work. We don’t shed load like that. We don’t target just a handful of LSEs. And even if individual consumers did have their own backup and supply and chose an LSE to mitigate only some of their electricity, even at the distribution level, we shed load at the feeder level, not at the circuit level. So there were a lot of challenges from the beginning, I think, that weren’t fully recognized.

Stone: So Kelli, I want to take a moment for a definition here. You mentioned a moment ago the term load shed, or shedding load. And that’s when the grid operator very deliberately cuts off electricity supply to a certain region, a certain group of customers, particularly when demand may be very high and the grid is under high stress. And the grid operator does that to reduce stress on the grid and prevent a larger blackout from happening. But, you know, it’s interesting what you also just said about equity. Basically, if you’re exposing consumers to price signals and those price signals go very high, the implication there is that only people who can afford those high prices would at times of scarcity actually be able to afford electricity, right?

Joseph: Yes, taken to the extreme, I think that is part of it. Those who value electricity at these really, really high-priced hours, where price is the signal, it’s a mechanism for allocative efficiency, allocating scarce resources. At the time when prices are very, very high, if you value electricity, you keep consuming, even if the price is very high, or you manage to find an LSE that hedged that appropriately for you, or you have your own backup power, instead of entering into some hedging contract. There are all kinds of ways to think about how that could work, but I think at the end of the day, it does raise some pretty serious equity concerns.

Stone: So broadly, there are a couple of issues that you pointed out in the market. One is that generators and electric utilities weren’t engaging in enough long-term contracting to create assurances of future revenue flows. And second, they were turning to the spot markets, but as you said, if you have market power, and you need mechanisms to actually protect against that market power, which are price caps, then you don’t get the full price to signal new entry into the market, new investment in generation.

So I believe at this point some of the markets turn to some other options to address that missing money problem. What were some of those solutions that they looked into that persist today?

Joseph: Yes, and actually before I talk about some of the solutions that we put in place to fix this missing money solution, I’ll just add that in addition to missing money, we talk a lot today about what’s called “missing markets.” I mentioned how commodity markets are supposed to work, right? You have sufficiently liquid markets all the way up to delivery. They can be really long-term. They can be shorter-term, and they can be in real-time, but the incentive is that you have prices and sufficiently liquid trading to ensure that you have some mechanism for delivery.

“Missing markets” refers to the fact that there are pieces in that assumption of how electricity markets would work that are also missing. So in addition to missing money, where you have price formation challenges, you have consumers not fully exposed to these prices, you have insufficient contracting as a result, and insufficient revenues. You also have what are called “missing markets.”

So these are missing markets for risk. We don’t have mechanisms to manage some of the risks involved with trading, either over the longer term or over the shorter term. One of the things that we saw recently in Texas was that in Texas you actually did have full retail choice. You did what’s called an “energy-only market.” So they didn’t actually go in and make some of the same fixes that some of the other markets did. And even with these really, really high prices, it still wasn’t enough to ensure that you had sufficient generation.

Some of the reasoning around that is there are missing markets for risks. There is insufficient trading. There’s insufficient liquidity. There’s nobody to really manage the risk of, let’s say a generator not performing, but an LSE still being required to deliver power. Or if consumers don’t receive power, who bears the risk of what happens? We don’t really have good markets for that.

So when we were initially thinking about just the missing money problem, one of the ways that we thought about fixing that is through what are called “capacity markets.” So capacity markets serve to be an additional revenue stream because generators can’t rely solely on energy and ancillary service prices alone in electricity markets to not only recoup their operating costs, but to recoup their investment costs. So we’ve set up capacity markets as a fix to that missing money problem.

And then, even in the energy-only markets like Texas, we’ve had to put what’s called an “operating reserve demand curve.” This is a mechanism that is kind of like a price-adder, whenever you have operating reserves declining. I talked in the beginning about the scarcity price signal and making sure that you have a high enough scarcity price, especially in an energy-only market is really important, so you have a calculation that determines, as operating reserves decline, what is the probability of load shed starting to increase?

So you have a defined adder that’s basically put on a wholesale energy price as a mechanism to ensure revenue sufficiency for generation resources and an incentive to come in. Those are two mechanisms to fix, the capacity markets and then what we call an ORDC.

Stone: There’s another interesting point that you’ve pointed out in some of your writing, and that is the issue of fungibility of electrons or electricity. At the time of restructuring in the 1990s, there wasn’t really this focus on clean energy. You had primarily coal. You had some natural gas. You had nuclear. But all those electrons were kind of the same. There wasn’t an environmental element, really, to that. And they were all also dispatchable. I wonder if you could explain how that issue of fungibility was important to the market and start to talk us through why that fungibility is no longer so apparent?

Joseph: Again, also going back to the idea of electricity in a commodity market, in commodity markets, again, all that matters is delivery. So the idea in electricity is that it really doesn’t matter the type of generation resource that it’s delivering. It really only matters that energy is delivered.

I think in systems that are made up mostly of fossil assets, it’s relatively true that they’re similar enough, and they’re dispatchable enough so that when you’re in real-time power system operations where, as I mentioned earlier, good operators have to have access to operating reserves, they also have to have access to resources that can quickly come on. If you lose one resource, you can quickly dispatch another resource.

And in addition to providing energy, these resources are providing very critical reliability services. Operating reserves is one type of a critical reliability service or an ancillary service. When you have systems made up of mostly fossil assets, as long as you plan for a total amount of megawatts, plus some reserve margin, that’s usually enough to make sure that you’re going to meet what you need for resource adequacy, and you’re going to meet what you need in real-time operations for operating reliability.

When you start to have systems that are made up of mostly renewables, and we’re starting to see this now, right as we move through and as the resource mix is changing, it’s not necessarily the case that every type of asset is similar enough. They’re not equally dispatchable, and they may or may not be able to provide some of these services in real-time operations that are critical for reliability, especially when you get to systems where you have variable renewable resources. You have energy-limited storage resources, and you have fuel-limited natural gas resources.

We can talk about all of that. We have talked a little bit before about some of those limitations with those types of assets, but this becomes, I think, harder to have the idea that electricity as a commodity when we don’t necessarily have sufficient forward-trading. We don’t necessarily have sufficient mechanisms to mitigate some of the risk associated with trading and delivery, and especially when you need to make sure that you have the kinds of assets that can produce at all times, whether that’s to provide energy, whether that’s to meet supply/demand balancing, ensuring that good operators can meet frequency, maintain voltage stability, and ensuring that they have access to operating reserves at all times. So I think those are some of the challenges as we are moving through the transition, and as we are thinking about prices and what prices can and can’t do to manage through some of that.    

Stone: It’s interesting what you’re saying here because when you’re talking about fungibility, you’re talking about are these energy electrons? Are they balancing electrons, you know, ancillary services? And those are all very different services. Now we’re at a point here where the markets have to solve for all of these problems, right? And that relays an increasing challenge as we have more natural gas on the grid, and we’ve got natural gas supply constraints or concerns that were demonstrated in Winter Storm Uri in Texas a few years ago, and more recently in Winter Storm Elliott. So the markets have to solve for all this, right? That’s a lot to put on a price signal.


Joseph: Yes, but I think there are a couple of pieces to pull out of that. The first is that, yes, part of what I’m suggesting is that as we move through the transition, as the resource mix changes, and it has always been the case that we need very specific kinds of ancillary services in order to enable the reliable delivery of electricity.

Stone: And explain for us just a moment what “ancillary services,” are, for those who may not be totally familiar.

Joseph: This is what I talked about a little bit earlier, but these are essential reliability services. These are really critical services that, for a long time, fossil resources have just provided. As we move through the transition, these are things like balancing energy, so these are resources, as I’ve explained it, that are quick-start, fast-ramping, that can quickly come on and provide energy when renewables aren’t producing. Or these are resources that enable grid operators to meet reliability standards, mandatory and enforceable reliability standards, holding things like operating reserves — essentially the resources that are needed to ensure frequency regulation and voltage stability, and to prevent a network collapse or a blackout.

So we’ve always needed resources like that, but fossil resources, as I mentioned, because they’re kind of all similar enough, dispatchable enough. As long as you had enough resources, even if you didn’t have one producing at the moment, there was another similar enough resource that you could dispatch to come on. Now that the resource mix is changing, as we have not just variable renewable generation, but we have energy-limited storage resources and fuel-limited gas resources, ensuring that we have resources that can meet these critical ancillary services, critical essential reliability services, becomes more challenging.

As we’re thinking about relying on prices, it’s not just that any resource that can provide energy is sufficient. It has to be a very specific kind of resource that can meet very specific kinds of grid reliability services. I think one of the big challenges as we move forward, and I talked about this a little bit before, but we have increasing interdependency between the natural gas sector and the electricity sector. These are sectors that are planned separately, that are operated separately, that are regulated separately, but we need to make sure that we have a natural gas system that is capable of supporting the electric system throughout the transition. And what we see in the winter, this is where the fuel-limited piece of natural gas generation comes in. So as natural gas competes for heating, the ability of natural gas generators to provide those services is limited in the winter. And part of the concern is that as we move, especially over the next ten years through the transition, and especially as we have heating electrification goals and transportation electrification goals, some of the current summer-peaking systems are transitioning into winter-peaking systems. So some of these challenges just become exacerbated, and we want to make sure that policymakers understand what’s needed today to meet reliability, and then what is necessary in the future to meet reliability in a fully decarbonized system.

I think looking to a price signal to manage that complexity and to manage these regulatory silos, these jurisdictional silos across industries, across thinking about who is studying various decarbonization targets, versus who has grid reliability responsibilities. These are policy challenges. These are regulatory challenges. These are not necessarily challenges that market prices alone can solve.

Stone: And just to kind of state that back to you, so basically twenty or thirty years ago, when most of the resources were dispatchable, electrons were pretty interchangeable, there wasn’t such a need to specifically incentivize investment in these new types of flexible resources that are going to provide these ancillary services that you just talked about. Today, though, we’ve got a natural gas system with its fuel supply concerns. We’ve got variable, renewable energy resources like wind and solar. They are very different. So I guess the next question is: What specifically are the types of resources that we need to balance out resources in the modern context?

Joseph: Yes, I do want to make one point. Part of the reason why electricity market prices alone have not been enough and why we’ve needed to put fixes and needed to focus on various market gaps and these missing money and missing market problems is because it isn’t the case that we’ve been able to use a price alone to get the kinds of resources that are needed to meet reliability standards and reliability targets. That’s why we’ve had to put lots of fixes.

So I want to make it clear that it isn’t the case that a price alone has been able to do this all along, but it’s becoming very clear that a price alone will be challenged as we move through the transition. From my perspective, a successful transition requires resources that provide these very specific grid reliability services in very specific locations, while also meeting policy targets. As I keep saying, I want to make sure that policies that are intended to meet climate targets also meet system reliability needs.

It’s not that we don’t have the possibility of having resources that can do this, it’s just that we need really focused policy and very targeted incentives towards the kinds of resources that can do that. For example, things like hydrogen or geothermal or advanced nuclear, long-duration storage over a multi-day capability of storage, bioenergy or even our remaining fossil assets with some abatement technology. But what we have to recognize is that even as more batteries are coming online and providing some of the services that gas assets can provide, we are still going to need some gas assets until some of these technologies that I mentioned are commercially available. That’s part of the challenge.

Stone: It’s interesting, Kelli, the International Renewable Energy Agency, also known as IRENA, has proposed a solution to the problem we’re talking about right here. The solution is what it calls a “dual-procurement model,” where you have actually one market for bulk renewable power, and you have a second market for the flexible resources that will be needed, I assume, to balance out those bulk electricity sources. Would that model work here in the United States potentially?

Joseph: A hybrid model, where you recognize that what’s driving new entry is not necessarily prices, but policy and system planning needs, I think is something that we should be talking about in the United States. We are not having some of those conversations, I think, because we’re still looking at the existing market designs that we have, and again, focusing on what’s the gap or the market failure? What do we need to price a little bit better to solve?

I think that there is room for a discussion about these new market designs. And it’s not just IRENA, there are a lot of studies that are out there looking at the possibility of having some kind of a hybrid market design, where you clearly separate the short-term market price signal, so the short-term dispatch and daily power system operations, which is fantastic, great, enables least-cost generation dispatch within reliability system security constraints. It does that fantastically. My concern is that we are relying only on those sort-term price signals to be the long-term investment signal for the kinds of resources that are needed to meet both policy targets and system reliability needs.

I think that we should be talking about other kinds of market designs, perhaps a hybrid market design. Another option is to think about having some kind of a competitive procurement for strategic reserves. These would be resources that are not dispatched daily. They’re only there and only used in times of really significant system stress, but we are sure that they have the gas that they need or that the battery is fully charged. Or perhaps in California, they’re using some aggregated demand response in order to meet those needs, as well.

So there are ways to think about having some kind of a strategic reserve as a market mechanism, as well. One of the things that I’ve also been talking about is potentially having some kind of regional procurement for some of these assets. So I think that there are ways to think about where we can go from here in order to get the kinds of reliability services we need and meet policy targets that don’t require us to just rely on short-term market price signals to be the long-term investment signal.

Stone: I just want to point out something here. You mentioned the California market a minute ago. I also want to point out that some of the other markets, the RTOs which we really haven’t spoken much about yet specifically, PJM here in the Eastern United States, ERCOT. They have made some moves to address this challenge. There’s a lot of criticism that they haven’t moved enough, but can you tell us briefly what they have been trying so far?

Joseph: One of the things that is pretty common across a lot of markets today, as I mentioned, when we think about resource adequacy, and we think about operating reliability, the two components of what makes up grid reliability, when we look at, as I said, resource adequacy studies when you have a mostly fossil-based system, it’s just about having enough resources. But when you have a system made up of mostly renewables, energy-limited storage and fuel-limited gas, you need to make sure you have resources that are available to produce energy. So that gets into operating reliability.

One of the things that most markets are doing is looking at how they evaluate the availability of generation resources in their resource adequacy models. These are new, what’s called “capacity accreditation mechanisms” to say, “Are you a resource that could be available at all times in real-time power markets, or perhaps not?” So one of the mechanisms is to kind of rethink how we do capacity accreditation as we’re studying and looking at what’s likely to be available in real-time system operations.

Other mechanisms, as I mentioned, are sort of looking at either some kind of strategic reserves — Texas has looked at that; California has looked at that — or having in Texas rethinking putting some kind of mandatory contracting to make sure that you have the resources that you need in real-time power system operations.

Stone: A few minutes ago, you also mentioned the role of policymakers. I want to take a moment here to reference a recording that you and I did back in November on this very topic of policy. At that time, you talked about the fact that some states are aggressively backing the development of renewable energy, yet at the same time, they’re failing to support some of the accompanying infrastructure resources that will be needed in coming years to accommodate and ensure the reliability of variable renewable energy resources. How might state clean energy policies, though well intentioned, present challenges to electricity system reliability?

Joseph: The way that I think about this is — and one of the big challenges in the US — is that the entities that are responsible for setting decarbonization targets at either the state or federal level are not the entities that have grid reliability responsibilities. This is an enormous policy gap. So ensuring that we have decarbonization targets, whether that be for bringing on renewable resources, or whether that’s electrifying heating or electrifying transportation, recognizing that we have to make sure that grid reliability is supported throughout the transition.

I keep saying this, but today that means that as we’re bringing on more battery resources, also making sure that we have a natural gas system that is capable of supporting the electricity system. And then what I would like to see is states work with these reliability entities as they’re setting their decarbonization policies and think about the kinds of resources that can replace natural gas. As I mentioned, these are the kinds of resources that I walk through, things like advanced nuclear, long-duration storage, hydrogen. But some of these resources need associated infrastructure in order to be able to scale and deploy. What I’d like to see is states work with the RTOs, work with the reliability coordinators. Not all parts of the country have RTOs, but all parts of the country have reliability coordinators. Having states use their regional system planning capability to inform their policy choices and help direct and target IRA incentives towards the kinds of technologies that can solve these needs, that can be both clean and flexible and provide reliability services.

Stone: So just to wrap up, are there any final comments here? Do you think we’re going to get the market changes that we’re looking for? What’s the role of pricing going forward?

Joseph: One of the things that I point out, from my perspective, reliably transitioning the electric sector is a moon shot mission. I have referenced an economist by the name of Mariana Mazzucato quite a bit in some of the work that I’ve done. But I like to point out that markets are always incomplete. They’re always imperfect, and constantly focusing now only on the market gaps that we have to fix or the market failures that need to be addressed in order to get back to just relying on prices alone, I think is limiting. It’s not recognizing the full role that government policy plays in the sector and that is needed in the sector, especially as we move forward.

We have to make sure that we have the kinds of resources that meet policy targets and meet grid reliability needs in a sector that has jurisdictional silos, regulatory silos, has interdependent sectors that aren’t planned, operated, or regulated together. These are big challenges, and these are not something that market prices alone can solve. So there is a role for policy in the sector, beyond just fixing gaps. There’s a role for policy in targeting and focusing investment on the kinds of resources that can enable the reliable transition of the sector.

Stone: Kelli, thanks for talking.

Joseph: Thanks, Andy.

Stone: Today’s guest has been Kelli Joseph, a Senior Fellow at the Kleinman Center for Energy Policy.


Kelli Joseph

Senior Fellow, Kleinman Center
Kelli Joseph is a Kleinman Center Senior Fellow. She works at the intersection of policy and markets, with a focus on transitioning the electricity sector to support a decarbonized, climate resilient economy.

Andy Stone

Energy Policy Now Host and Producer
Andy Stone is producer and host of Energy Policy Now, the Kleinman Center’s podcast series. He previously worked in business planning with PJM Interconnection and was a senior energy reporter at Forbes Magazine.