S3E16: FERC Commissioner Mark Christie calls for reevaluation of competitive wholesale power markets after 25 years

Commissioner Mark Christie of the Federal Energy Regulatory Commission has been a prominent advocate of the need to overhaul the competitive market design at the heart of the regional wholesale power markets that have evolved in the U.S. over the past 25 years ("It's time to reconsider single-clearing price mechanisms in U.S. energy markets", Energy Law Journal, May 2, 2023).

The fossil fuel-fired "dispatchable" generation units that Christie sees as crucial to ensuring power grid reliability are retiring faster than passively fueled renewable energy resources can be brought on to replace them. In our discussion, Commissioner Christie makes clear that his top target for reform is capacity markets, not the security-constrained economic dispatch model employing locational marginal pricing, or LMP, in real-time and day-ahead spot markets. LMP is the central design element of all state and regional competitive wholesale power markets in the U.S.

"I think in the real-time energy markets, the real-time energy markets and the use of LMP has saved consumers money by getting economic dispatch, by getting the least-cost unit dispatched. So I think in the real-time energy markets, I think there has been consumer savings," Christie says.

"There's many functions to RTOs and I think that the most important function of all, and the one I think where they’ve provided undisputed benefits, has been to provide a larger balancing authority," he says, adding: "Probably the biggest single benefit of RTOs has been that they've provided a regional system operator, which I think has been of tremendous benefit to reliability and also, I think, to cost savings because they can dispatch cheaper resources across a broader territory."

But Christie, an ardent states rights advocate, does not see FERC's role as ensuring these consumer-friendly regional power markets are ultimately in place everywhere, which former FERC Chairman Pat Wood attempted to do 20 years ago. "How you regulate your utilities is really an individual state decision" to make, and not FERC's, he says, calling Wood's Standard Market Design "massive overreach and an invasion of basically state retail authority."

Nevertheless, Christie says, "I don't think that, frankly, the real-time energy markets, which use LMP, what's called locational marginal pricing, are really the first place we ought to be concerned. I think the real concern and we ought to focus on first is in the capacity markets," Christie elaborated, asserting that capacity markets should be replaced with utility self-supply programs that incorporate integrated resource planning by state regulators. IRP is a central element of standard monopoly utility regulation.

"I think an IRP process – it gets you the best mix of a balanced holistic approach where you can balance all the different resources that you need and try to get them at the best cost to consumers, which is what the goal ought to be," Christie says. "Everything we do as regulators in the energy area has got to be about what's good for consumers. We have to look at what is going to get consumers reliable power at the least cost. And I think everything we do, we’ve got to be asking ourselves, is this the best thing for consumers?"

Transcript

EMP S3E16: Commissioner Mark Christie, Federal Energy Regulatory Commission
(transcript edited for clarity) 

EMP: Welcome to the Energy Markets Podcast. I'm your host, Bryan Lee. Today our guest is Commissioner Mark Christie with the Federal Energy Regulatory Commission. Commissioner Christie, welcome to the podcast.

MC: Thank you, Bryan. Glad to be here.

EMP: We invited you onto the podcast to talk about your electricity market design concerns, but after last Thursday's commission meeting, I thought we should take a moment right off the bat and talk about the transmission interconnection ruling that FERC issued. With thousands of generation projects waiting in a queue to get onto the grid, the order looks to move transmission interconnection from first-filed to first-ready. Are you happy with the outcome in this proceeding?

MC: Yes, I think it's a major step forward in clearing the queues. The problem we've had in the queues is, frankly, we have projects that are ready to go – commercially more advanced, ready to proceed. And then we have in all the queues – all the RTOS – a lot of projects that are frankly speculative, and are there to, first of all take advantage of the studies done by the RTOs and maybe even sell to someone else in a secondary transaction. So there's a lot of speculative projects in there. Everyone knows that. And so the purpose of the interconnection rule that we adopted is to basically do a triage and have the commercially ready projects move forward now – move forward quickly. And the speculative projects, sort of get put behind them. So I think the overall thrust of the rule is very positive. It's going to result in some good progress. It also moves to allowing the transmission providers – which is a term for RTOs or non-RTO transmission owners in the non-RTO states – it directs them to also do studies based on clusters of generator interconnects. And so I think that also will help expedite the process and reduce the study costs and the study time. So overall, I think it's a good step forward and I complimented the chairman, Willie Phillips, for his leadership and, and so I think it's a good, a very good – represents a good step forward.

EMP: If only we could do the same thing with transmission line siting, huh?

MC: Well, transmission line siting is a very different issue. That is an issue which is generally under state authority. I'm a strong advocate of that. I spent 17 years as a state regulator and sat on over a hundred transmission line permitting cases. And I'm a just a very strong believer that the siting of transmission lines and approval of transmission lines – it's much more than just where does it go. A transmission line case, what's called a CPCN – certificate of public convenience and necessity – in my opinion, should involve a lot more than just where you're going to put it. It should also involve a review of the need and a look at alternatives, which may be generation alternatives, may be DR (demand response) alternatives. And so a comprehensive transmission permitting would look at many things. I think that ought to be at the state level. I think state regulators are far more sensitive to their local needs, their local concerns, whether it's potential alternatives or whether it's environmental factors. But having said that, I recognize that Congress did pass – actually, they originally passed it in 2005 in the Energy Policy Act – they passed a backstop siting authority for FERC. And that's really been on the books since 2005. They updated it last year. And so obviously, if it comes to us, you know, I'll carry out the federal law as we're supposed to. But I think transmission siting and permitting ought to be at the state level.

EMP: Let's get to the main reason we invited you onto the podcast, shall we? You've been very prominent in raising your concerns about the auction market design that's prevalent in the regional wholesale power markets in this country. The security-constrained economic dispatch model, as it is called, has been a tremendous success allowing billions of dollars in economic savings for consumers, but you seem to feel that it is inadequate to accommodate a grid that has more passive, intermittent wind and solar energy resources rather than the dispatchable generation resources, like natural gas-fired turbines, which you're also concerned are retiring too rapidly in the midst of this transition that we're under. Why don't you go ahead and elaborate for our listeners?

MC: Okay, well, the main purpose of my article really is found in the very end of it.

EMP: You're talking about your Energy Law Journal article (It's time to reconsider single clearing-price mechanisms in U.S. energy markets, May 2, 2013).

MC: Right. Yeah, right. That's what you're referring to, I assume, is the article I wrote for the Energy Law Journal.

EMP: You also testified before Congress, and you've made some comments at commission meetings as well. So . . .

MC: Right. But I was going to say, the article makes the point at the end that I think covers everything that I've said in front of the Senate committee, House committee, and I've said in commission meetings, and that is the focus should always be on what's the most important question of all, and that's whether the consumers – residential, commercial and industrial – are benefiting from pricing mechanisms in our power markets and whether they're getting reliable power or going to get reliable power in the future. Because everything we do ought to be putting consumers first. I think that's absolutely built into the Federal Power Act, which is a consumer protection statute overall. At this point in history, we're now 25 years after what was called deregulation. And deregulation was a lot of things. It was more than just real-time power markets. We should be asking, okay, 25 years later, what parts are working, what parts are not working? And in particular, I like talking about capacity markets. I listened to your interview with Professor Hogan. For him, I have tremendous respect. I've been to his seminars many times. I learned a lot every time I went to one. And Professor Hogan is not a fan at all of capacity markets, as you know, and I think on that issue we probably line up at the same. So there's a lot of aspects to be questioned. I don't think that, frankly, the real-time energy markets, which use LMP, what's called locational marginal pricing, are really the first place we ought to be concerned. I think the real concern and we ought to focus on first is in the capacity markets. And I share, Professor Hogan’s concerns about the problems there. But what we have to ask is, what are the two goals of energy regulation? And I think the two goals are, first of all, get the least cost to the consumer. And secondly, make sure that the consumer is getting reliable power. And I think we have some major problems in both those areas. And particularly in terms of whether we're going to have reliable power supply. If you want to dive into the various aspects there we can we can certainly do that. There are a lot of aspects to this. It's not one single question and so what I wanted to raise in my article, and what I’ve raised in appearances is, let's always be willing to question assumptions, let's always be willing to reevaluate policies that have been in effect, in this case now, for 25 years and not say that we can't question those policies or see whether they're still working. We may decide that certain elements are still working. I think actually, I think LMP – the use of LMP, locational marginal pricing – in the real-time energy markets, there's a very strong case to be made that that is working. I think Bill Hogan is the most effective advocate of it. Then I think when you look at other different types of markets, particularly capacity markets, which by the way does not use LMP. So the arguments for LMP don't even apply in capacity markets. I think we need to be questioning how those markets are designed and whether they're a proper alternative as well. So overall, I think it's always appropriate to be looking to see whether consumers are being served.

EMP: Yeah, I agree with you 100% that we've got a lot of structures in place that were adopted over two decades ago and may be not bearing up under the test of time and we should be revisiting them. What would you like to see FERC do in terms of your concerns about competitive wholesale market design, and the reliability of the grid, given all of the retirements that we're seeing right now that have got alarm bells going at NERC and the regional grid operators?

MC: Yeah, there are alarm bells going off in all the RTOs. And the fundamental problem is whether we're going to have sufficient power supply. ERCOT, as you well know, during Winter Storm Uri, had a shortfall in power supply. That was the main reason that caused almost a weeklong outage and it was catastrophic. ERCOT is an example of an effort to use a real-time energy market as the only market that you're going to use to get your resource adequacy. I have never thought that was the best way to go. And I think that Winter Storm Uri pointed out the problems there. When you're depending on a real-time energy market only you've really set yourself up to have a supply shortfall during emergencies and that's exactly what happened during Uri. But even in the Eastern RTOs where we have capacity markets, we're seeing a tremendous loss of capacity resources and the arithmetic in terms of the capacity that's being lost versus the demand that's going to be there – it’s just not adding up. And so I think you asked the question, what should FERC do first. I think first of all, we have to focus like a laser beam on reliability and I think we are. And we have to be asking whether the reliability construct in the RTOs that are using capacity markets – and that, of course, is PJM, ISO-New England and MISO in particular – is that working? Is that working? And we had a forum on PJM. I was very glad we had a forum on the PJM capacity market specifically, recently, and raised a lot of these questions and I thought that was very appropriate. PJM is now doing what they call a critical issue, fast-track process to propose an alternative design for their capacity market. But I think that's where the focus should be first. You asked what should FERC do first? And I think first and foremost we've got to hone in on reliability. And we’ve got to look at why, in these RTOs that are using capacity markets, why are they losing capacity so rapidly, which is going to threaten reliability in the end? They're telling us; NERC is telling us. So good question, and I think the focus needs to be on reliability. And in particular, looking at whether these capacity markets are still fit for purpose.

EMP: Well, you mentioned Winter Storm Uri and the impact it had the ERCOT grid. You also mentioned that in your Energy Law Journal article. But the market design had nothing to do with that. The postmortem on that deadly outage was that it was the natural gas supply system that froze up in the extremely cold weather – very abnormal for Texas to have weather that cold the way they did. So it was not a market problem. A lot of people seem to point to the ERCOT Winter Storm Uri experience as indicating a problem with markets when it was really the natural gas infrastructure that froze up and the natural gas generators that were unable to operate because of that.

MC: Well, your question really presumes a conclusion that – I don't think the facts line up with your conclusion of your question. Yes, winterization was a problem. Yes, a lot of gas generators didn't show up because they were not winterized. And of course in Texas, weatherization has always been for summer, not for winter. But you cannot divorce that from the question of the overall market design. You can't just say, well, market design was not the problem. You know, that's ignoring the elephant in the room. Market design in Texas – in ERCOT, now. We're talking ERCOT – is based on the use of an energy-only market to procure sufficient supply resources to serve consumers at times of peak, and it did not do that. It failed to do that. And you can say, well, if the gas generators had just winterized, it wouldn't have been a problem. The problem is, in an energy-only market which is based on marginal cost alone, where is the money for the capital investment to winterize? Where were the resources that are supposed to be incented to come into the market? Now the advocates of the pure market approach like Professor Hogan – I listened to your interview and Bill's very effective, very articulate – the theory behind an energy-only market getting resources is, well, if you let prices rise, prices will get high enough to incent new generation. Well, when the price is nine thousand dollars a megawatt hour at the peak of Winter Storm Uri, you're not going to get a new generating unit built tomorrow. Just because the price was allowed to rise to nine or ten thousand dollars a megawatt hour. And I think that's the problem with the energy-only market approach. And so the answer in the Eastern RTOs was, we're not we're not going to depend upon an energy-only market to incent new generation and to keep generation in the market. That's too risky. And so the answer in the Eastern RTOs was, let's set up these things called capacity markets. Because they're going to be necessary to provide the capital investment that an energy-only market doesn't provide, which of course dispatches purely on marginal cost. So I disagree with you that ERCOT was nothing more than just, you know, the generators didn't winterize and if they had it would have been fine. I think market design is integral to that question. And I think it goes to the question of where are we getting the capacity resources that are going to be sufficient to keep the lights on? And the problem in the Eastern RTOs is we have capacity markets, but the question is, are they procuring enough resources under their current design, to get enough power to keep the lights on? Let me give an example in PJM. You mentioned Winter Storm Uri. Let’s talk about Winter Storm Elliott last December. So in Winter Storm Elliott, PJM peaked at 131 gigawatts of load – 131 gigs. PJM is projecting that in the next few years, they're going to lose 40 gigawatts of generating capacity. So that is a huge amount compared to, you know, what they had to have last December when they almost went to rolling outages – went to rotating outages. Forty gigawatts is a huge loss of generating capacity. And by the way, I've heard the number may be as high as 50 gigawatts. So you compare that to the 131 gigawatt peak that they had to meet during Elliott, and that is a tremendous loss of resources. And the question is, is there something about the PJM capacity market which is simply not procuring sufficient resources to keep the lights on? This is the question that I've raised. And, one alternative is, of course, the state-regulated IRP model. If you want to talk about that, as an alternative, I’ll be glad to do it. FERC regulates the RTOs and so we're certainly concerned about making sure that the RTOs are procuring sufficient capacity. And I think market design in the RTOs has a tremendous amount to do with reliability. We can't just say, well, just order them to winterize and that'll fix the problem. I think that's just a symptom. It doesn't go to the cause.

EMP: Yeah, I don't argue with you on your last point. But I mean, it was more than just a lack of winterization of the generating units that led to the problem. It was the natural gas infrastructure supply system, as well. As I understand it, the wells were frozen at the wellhead – that there were problems with the pipelines. And that even if a generator had weatherized, they weren't going to get the gas because of all these problems. And, I'm glad you brought up Winter Storm Elliot because PJM managed to maintain reliability during that extreme event, but the utilities to the south had extreme problems and had to do rolling blackouts to maintain reliability. It seems to me that that's an argument in favor of the kind of market approach that has been working the last couple of decades.

MC: No. I don't think it's an argument in favor. I mean, I know what your point of view is, Bryan, you made that clear.

EMP: Oh, no, I don't hide my point of view. That's why I started this podcast.

MC: Right, right. There were problems with gas in North Carolina. The rotating outages you point out were in the Duke territory in North Carolina and it was due to a lack of gas supply. There are problems with gas, no question. Supply is an issue at times of peak. There are problems with all the generating resources, which is why I think that if you want to have a balanced system – and I think that's the real point here. Resource adequacy is about balancing your resources – to use an old cliche about not putting all your eggs in one basket – you have to have a balanced portfolio. You want baseload generation, which is a mix of dispatchable generation. You want renewables. You want some DR – demand response. And on the distribution grid, you want distributed energy resources. So balancing all of that to make sure that you get the best mix at the least cost for consumers is the goal of the whole system. Now which system gets you the better balance? Okay, that's the question here. In a capacity market, the capacity market is not about balancing to get the best mix that's going to keep the lights on. It's a way to get there. It's an administrative construct. It's a way to get there. But is it the best way to get there? My personal view is that the best way to get there and the most intelligent way to get there is with a balanced portfolio where you look at – you have different resources, dispatchable, renewable, and others. And you can balance that and think, okay, what's the best mix to make sure that we have enough capacity when we need it. That we have the power when we need it at the right time. So it really is about what administrative – what regulatory construct – and they're all regulatory constructs. Capacity markets are regulatory constructs. The demand curves are administratively set. The net CONE is administratively set. So given the different regulatory constructs, which one gets you a better-balanced portfolio to make sure that you get through these peak times in these emergencies? That's the real question we're trying to solve.

EMP: You know, I think whether it's Winter Storm Uri or Winter Storm Elliott, or the heat domes that we're seeing across the country right now, it seems clear to me, at any rate, that climate change is increasingly putting stressors on grid operations. I mean, I think this summer is an example of that. The ERCOT grid has been extremely stressed throughout the summer months up until this date, August 1, and so far, they've done well. They've managed to keep the lights on and many seem to give the credit for this to the wind and solar and battery resources that the market construct in ERCOT has provided the economic incentive to build. There weren't mandates for this. They built this based on speculation in the market. And it's working so far.

MC: I think, I think the facts in Texas are a little bit different from what you present. They are doing a very good job of keeping the lights on. I give a lot of credit to ERCOT. They're using all the resources at their disposal. They're using wind and solar. They’re using gas. They're using coal and nuclear. I mean, they're using all the resources at their disposal. And that's exactly the way it ought to work. For goodness sake, I hope they continue to keep the lights on and keep the adequate power supply. So I think that again, it illustrates my point that you need a balanced portfolio, and you need to have enough resources of each type to make sure that you have sufficient supply, you know, at these peak times. And you're right, climate change, I think is increasing the amount of these extreme weather events which is an argument for making sure that we have sufficient resources when these weather emergencies happen, whether it's a hot weather summer-peaking event like in Texas right now, or whether it's a cold-weather peaking event like Winter Storm Elliot or Winter Storm Uri, this is the heart of the problem. And by the way, demand is increasing. A lot of the proposals to increase electrification are going to substantially increase load. 

EMP: Especially electric vehicles. 

MC: No, absolutely. I mean, you know, I mentioned the PJM numbers to you and I said, okay, they peaked at 131 gigs during Winter Storm Elliot and they're looking at losing 40-50 gigs, you know in the next few years. Well, that 131 gig peak, if we continue with electrification and let's say you roll out EVs everywhere, the electrification-of-everything movement is going to increase load, it is going to increase it by several orders of – potentially orders of magnitude. So, the need for resources, generating resources, okay, power resources – is on an upward trend. And we're in a Catch 22 in America right now. We have the trend in load with the electrification of everything movement – just EVs alone – is moving the demand curve up. The trend is up, and yet we are losing dispatchable resources that are necessary to meet that load. And we need the dispatchable resources, and wind and solar is a great addition to that. The problem, as I've said in front of the Senate committee, is the problem is not the addition of wind and solar. The problem is the subtraction of dispatchable resources. Because when load is going up, when demand is going up as it is, we have to have even more power supply than we have right now. We need to be adding power supply.

EMP: Yeah, well, I just brought up the Texas example this summer in light of the conversation we should have now about the capacity markets and what do we replace them with? My perception is that the capacity markets are there because the grid operators don't have a construct like Texas, where they allow market signals to drive investment. The prices are capped and it's difficult for a gas-fired generator, as an example, to make the economics work when the scarcity price is missing. And you, I see from your writing, have a concern about scarcity pricing. You have a concern about capacity markets. So what's the alternative? Integrated resource planning? I'm not sure.

MC: One alternative to capacity markets is to allow load-serving utilities to become self-supply. And there are utilities in PJM that have chosen self-supply, which means you're not dependent upon the capacity market. You are base basically doing an IRP process. Yes, I favor an IRP process. I think when you balance the different pros and cons – and you have to balance all the pros and cons – I think that an IRP process, where a state-regulated IRP process where the utility has to go to a state regulator and say, here's the portfolio that we're planning, here's how much of each resource that we're going to have in our portfolio. And consider that in a in a holistic approach and look at what's going to best serve the state's consumers, which is really what this should all be about. I do favor that as the better regulatory construct than a capacity market. But we have capacity markets, and we have to regulate them at FERC. And we have to make sure that they're serving consumers and so the capacity markets themselves are quite varied. They're not identical. Dave Patton, who's the Independent Market Monitor for MISO, for example, has been very clear he doesn't like forward capacity markets. He says he thinks they're a terrible idea. That's a three-year forward capacity market. So you don't have to do a three- or four-year capacity market. You can have a shorter term capacity market. Seasonal or even annual. Bill Hogan, of course, who you had on your podcast recently, he doesn't like capacity markets. His quote on capacity markets is they were quote “the original sin of market design.” So Professor Hogan doesn't like capacity markets. So what are the alternatives? One, of course is to change the details of the capacity market since we have them in different RTOs and try to make them work better. One alternative is to, again, let utilities that are in capacity markets to have an efficient way to choose to be a self-supply. You know, SPP doesn't have a capacity market. You don't have to have a capacity market. And it's not like that every RTO has to have one. So there's a lot of alternatives. But, yes, I think that from an individual state standpoint, I think an IRP process – it gets you the best mix of a balanced holistic approach where you can balance all the different resources that you need and try to get them at the best cost to consumers, which is what the goal ought to be. So, but that's an individual state decision. The point about how you regulate your utilities really is an individual state decision. It's not for FERC to tell them. But I think there's variations even within capacity markets that can be considered.

EMP: A big part of this problem with capacity markets appears to be various state resource decisions, let's call it. Which is another way of talking about state-level subsidies for particular resources. Is that a problem as you see it? I think you mentioned that in your paper. You mentioned the federal subsidies for renewables as being an issue, correct?

MC: You know, it's not a problem in a single-state RTO like New York or California. It's not a problem. Because the single-state RTO is going to reflect its own state's policies and it should. So whatever subsidies New York wants to have, whatever subsidies California wants to have, is really, I would say it's simply reflecting the policy of that state. The problem comes in a multistate RTO like PJM or MISO, where you've got many, many states – you got 13 states plus DC in PJM. You've got a lot of states in MISO. MISO runs from the Canadian border all the way to the Gulf of Mexico. So you've got a lot of divergence, diversity in the different states and the different state laws. Trying to run a market like a capacity market when you have all the different state laws that are affecting that market is the challenge. So that's a political issue much more than it is an economic issue. And, you know, it's interesting I listened to Bill Hogan on your show and Bill says he doesn't like subsidies. He says subsidies are bad. And he obviously prefers a carbon tax as the way to achieve carbon emissions reduction. But states have subsidies and as Bill Hogan says subsidies are bad. They affect the market negatively. Now, again, I don't think in a single-state RTO like New York or California that's necessarily going to be a problem because it's going to reflect their policies anyway. But in the multistate RTOs you’ve got a real problem about how one state's policies are going to affect, you know, the operation of a market that affects another state. And I think that's been the source of a lot of the controversy and increasing challenges in trying to run, certainly, a capacity market in PJM and MISO and in states that have capacity markets.

EMP: Well, you're not suggesting that we shouldn't have the large multistate RTOs, are you?

MC: Well, I'm pointing out the challenges in trying to operate a market system in a multistate RTO when you have different states with very radically different policies and those policies are affecting the markets that affect all the states. Look, again, to repeat what I've said before, the decision whether to go in an RTO, the decision on under what conditions to go in an RTO, is ultimately a matter of state policy. Those states made that decision. I was a state regulator in a state for 17 years that made the decision to go into PJM. That was a decision Virginia made just as every other state in PJM has made that decision. That's their decision to make. It's not for me to say they should not be in or they should be in. That's for each state – the policymakers in each state to decide. Right now, the states that are in PJM chose to be there and they're trying to defend their interests while they're in there. 

EMP: Professor Hogan, when he was on the podcast, talked about my experience when I was at FERC. The chairman at the time, Pat Wood, was trying a top-down approach to require large regional marketplaces all across the country and you, in your writing, were clear on your view of that. Professor Hogan called Standard Market Design “successful market design.” He says it’s the only way that we're going to get to a clean-energy transition is if we have this market design. You called SMD “misbegotten” and have raised concerns about this market design going forward. And as part of your argument, in the paper, you talked about rates being higher in the states that restructured. You talked about “persuasive evidence that deregulation provided no real cost savings for consumers. Indeed, empirical data suggests that it has actually made power more costly for consumers in deregulated states.” Do you want to elaborate on that for us?

MC: Yeah, well, you throw a lot in there. So let me just go back and start at the beginning of your question. And you brought up Standard Market Design. Standard Market Design was a proposal by FERC. Standard Market Design was proposed by FERC back in the early 2000s. I think it was 2002. And basically, what it was, was an effort by FERC to force every utility in the country to join an RTO – a federally regulated RTO. And, as you might imagine, that did provoke a firestorm of opposition and state regulators – of which I was one at the time – were strongly opposed to it because we felt it was a massive overreach and an invasion of basically state retail authority. And, as you pointed out earlier, the Federal Power Act, in the interview with Bill Hogan, the Federal Power Act, basically draws a dichotomy between federal wholesale regulation and state retail regulation. And it's an appropriate dichotomy, I think, absolutely. The feds ought to be regulating wholesale transactions, interstate wholesale transactions, and the states ought to be regulating retail rates, because those are what affect consumers in their monthly bills. So the standard market design proposal, which was pulled in 2005 after a lot of criticism and opposition – and again, state regulators led the charge – I thought it was appropriately pulled. So now we're in a situation where states decide whether to join RTOs and that's the way it should be. One of my first cases I ever sat on as a Virginia regulator was whether to allow our two largest utilities to join PJM. We agreed to do that and to let them join. But that's a state decision and what FERC was trying to do with Standard Market Design was to force that decision on all utilities and it got a lot of opposition, as you're well aware, and I'm sure you well remember. So that's one issue. Now the second issue is about whether deregulation has worked for consumers. And the facts are, uncomfortable facts for some people, but the facts are that if you look at rates in the non-RTO states and you look at rates in the RTO states, the rates in the non-RTO states are generally equal to or lower than the rates in the RTO states. Now, there are outliers, because there's always outliers, but generally speaking, if you look at the data, you look at the actual facts, rates in the non-RTO states were lower at the time and they're still lower. So the question becomes, okay, did deregulation not save consumers money? Well, first of all, what do you mean by deregulation? If you mean simply joining an RTO, which is one aspect of deregulation, that wouldn't necessarily save consumers money. It might. I actually think that in the real-time energy markets, and this is where I would agree with you and I would agree with Bill Hogan, I think in the real-time energy markets, the real-time energy markets and the use of LMP has saved consumers money by getting economic dispatch, by getting the least-cost unit dispatched. So I think in the real-time energy markets, I think there has been consumer savings. The question becomes in a vertically integrated state, the savings have also been there as well because the real driver since 2005, okay, the real driver of lower prices, both in the in the real-time energy markets where the last unit to clear is usually a gas peaker, and in the IRP vertically integrated states, gas is still setting the price. So in both the RTOs and the non-RTOs over the last 20 years, it's really been gas that’s been setting the price. Now you pay for it differently. You pay for it through LMP, you know, being the gas peaker that sets the last unit to clear. In the non-RTO states, you pay for it through your fuel factor where your utilities that are using gas-fired generation have to come in on an annual basis and asked to collect for their gas-supply costs. So you pay for it. You just pay for it in different ways. But there is no question that if you look at the data, and you ask the question, did deregulation save consumers costs? I think the evidence is overwhelmingly it did not – not relative to the comparison to the non-RTO states that did not deregulate. Now, let me say this about deregulation. There are a lot of different models of deregulation. It's not one uniform model. There were states that went to full retail choice. There were states that retained a monopoly – a single provider for their retail rates. Virginia is an example that. And so there's a lot of ways to quote/unquote deregulate. Was joining an RTO deregulation will not if you not necessarily if you kept your vertically integrated utilities on a cost-of-service model. So the question about whether deregulation, you know, you first you have to define what exactly is it? There's a lot of proxies you can use for it. But to answer your overall question, I think the data is undisputable. Its absolutely indisputable that it did not save consumers versus an alternative model. For example, the states that didn't do it. I think that data is pretty clear. Now whether it saves money against the model that they would have stayed in. I think that's a good question. That's a hypothetical question because they didn't stay in the model. But you can't say that, well, joining an RTO and deregulating saves you money versus the states that did not do it. You just can't do that because the facts don't show that at all.

EMP: I would disagree with you on that. I think the . . .

MC: On the facts? On the facts?

EMP: No, I disagree with you on your interpretation of the facts. 

MC: The facts are that the rates in the non-RTO states are simply lower generally than the rates in the RTO states.

EMP: Yeah, and I'm not disputing that fact. And as you noted a minute ago, they were generally lower than the states that restructured to begin with. The reason they restructured was because they had various factors at play that was causing them to have higher costs than these other states. And just to make a snapshot-in-time comparison doesn't really give you the kind of data you need to make an evaluation as to whether or not consumers have benefited. The model that I think really captures the benefits that consumers have seen is the one that Phil O'Connor, the late Phil O'Connor, the former Illinois regulator, did, in which you look at the prices over time, you adjust them for inflation. And if you do that, and this has been done several times. We first did it when I was at Exelon over a decade ago. Routinely this model in which you look at the prices over time has shown that prices in the states that have restructured have either been stable or declined, whereas the prices in the monopoly-regulated states have increased over time. And that I think is more important than a static snapshot-in-time comparison of rates, which I don't think gives you a good view of what's happened over time.

MC: Well, you can look at the rates in 2004 when a lot of states were deregulated, and you can look at the states in 2014. You can look at the rates today. And you'll see at any given point in time that the rates were lower in the non-RTO states. And so the argument that, well, the consumer in the deregulated states is better off than the consumer in the vertically integrated states, the ones that kept traditional state regulation, the facts just don't show that. And what they show is that the rates are still lower. They were lower 20 years ago. In fact, one of the reasons – I was asked one time, why don't you think the states didn't deregulate? I think the answer is that they didn't see a problem because their rates were already lower than the national average or any other benchmark you want to use. The question about the rates, of course, is you have to say what your benchmark is. And I think you could say maybe there's a study that shows that in a state that deregulated and let's say went to a restructured model that compared to a hypothetical baseline of what would have happened if it had not, you can say, well, gee, we're better than the hypothetical baseline of what would have happened if we had not deregulated and say, so, therefore, that shows cost savings. And that's one point of comparison. But if you're comparing it to states that did not deregulate you don't win because the rates are still lower in those non-deregulated states.

EMP: We'll probably have to agree to disagree on that one. I mean, you look at Texas and you look at Pennsylvania, both of those states had rates that were above the national average before restructuring. And now after restructuring, their rates are much less than the national average. And, you know, even if a state had, let's say, 10 cents a kilowatt-hour rate in 2001, if it's still 10 cents today, on an inflation-adjusted basis that's a price decrease. And so I really think you can't make this static comparison. You have to look at how rates were affected over time to really get a look at how restructuring helped or didn't help. And, you know, and I think, you know, carrying on that over-time demonstration, it shows the impact of wholesale competition on retail rates, it doesn't show that retail restructuring has really benefited consumers, outside of Texas anyway, because of the market structure.

MC: Thank you very much. You just made my case because you said retail – it hasn't passed over into retail rates, but you know, that's what consumers actually pay, Bryan. They pay a retail rate. 

EMP: No, I didn't say it hasn't transferred over into retail rates. I said the wholesale savings have transferred into retail rates, and consumers have benefited from the wholesale markets. But outside of Texas, we've not gotten the retail competition structure right in order to really get the benefits that we could have.

MC: So you think the Texas ERCOT structure is the right model? 

EMP: I do. 

MC: Okay, well, I think there's a lot of people who disagree with you on that. 

EMP: Oh, I’m aware of that, yeah. 

MC: Yeah. And, but I'm glad you've shown your cards. You think the Texas energy-only market is the best way to regulate utilities and deliver to consumers the lowest cost and reliability. And I think Winter Storm Uri showed reliability is a huge issue in trying to achieve reliability with an energy-only market because you don't get the investment and . . .

EMP: I'm sorry, I don't mean to interrupt you but when you make a point and then move on to another point, it's difficult for me to get back to the point. 

MC: Okay.

EMP: And, you know, Winter Storm Uri and Winter Storm Elliot both had outages and one was in a restructured market, and the other was in the monopoly-regulated – traditional monopoly-regulated market. They both had outages and I don't think the market design really has all that much correlation to climate change-induced outages on the grid.

MC: I think market design has everything to do with the issue you're talking about. So when you have an outage, for example, like in North Carolina, okay, in Duke’s territory, which is a vertically integrated, state-regulated utility. The answer when one of your utilities comes up short and has to do rotating outages, as a state regulator, you have authority over that utility. So you can immediately call that utility in and work to correct what caused the lack of resources and do your own investigation. And that's the advantage of state regulation. Because Duke has, just like every load-serving entity in a vertically integrated state, has what's called an obligation to serve. They have a legal obligation to serve their consumers and that's the way it ought to be. In an energy-only market situation like Texas, if you come up short on power supply, there's no one really that the Texas regulators, the Texas Public Utility Commission, can point to and say, okay, you’ve got to go out and buy more power because it's not a vertically integrated, state-regulated system. It’s depending purely on the energy-only market. But I respect your view if you think that an energy-only market a la ERCOT with no price caps is the best way to go. You know, you probably agree with Professor Hogan on that. And I would respectfully disagree. I think that an energy-only market with no price caps is not going to serve consumers in the long run. I don't think it's going to be good for consumers in terms of the prices they pay. And I don't think it's going to be good for consumers in terms of the reliability of their power service. So we will definitely disagree on that. I don't think your model of ERCOT I don't think is the ideal model for to follow.

EMP: I respect your opinion. And I just, I just do disagree. I think if Texas had never restructured and Winter Storm Uri had come along, there still would have been the outages that we saw a couple of years ago.

MC: I don't think you can say that because if Texas hadn't restructured – if let's say Texas had stayed on a vertically integrated model, they may well have procured the resources because they would have paid for them through rate base. And they may well have procured the resources that were necessary to get them through Winter Storm Uri. But of course, that's a hypothetical and that's why I can pose that hypothetical. And you can say it's a hypothetical, but you pose the hypothetical and say well, it would have happened anyway. I don't think you can say that at all. They may well have procured the resources they needed to get through Winter Storm Uri. 

EMP: We are talking about hypotheticals. So would you prefer that we had never restructured? That we'd stayed with the traditional monopoly regulatory system?

MC: Not necessarily. Again, I think every state had to make their own decision. Every state had to determine what was good for them. That's a very good question as it's like going back and saying, okay, what went wrong? What went right? That's why I think that after 25 years, it's appropriate to take stock and say, what has gone right? What has gone wrong? What can be fixed? One thing I think that's been very positive that came out of the restructuring era of the late ‘90s and early 2000s is there's many functions to RTOs and I think that the most important function of all, and the one I think where they’ve provided undisputed benefits, has been to provide a larger balancing authority. And we haven’t even talked about that. RTOs are balancing authorities. And by balancing authority, I mean this is the system operator and what RTOs have provided has been a balancing authority that covers broader territories than in the old system where it was simply the utility itself was the system operator. And so I think probably the biggest single benefit of RTOs has been that they've provided a regional system operator, which I think has been of tremendous benefit to reliability and also, I think, to cost savings because they can dispatch cheaper resources across a broader territory. So, in answer to your question, I think that was one aspect of, if you want to call it restructuring, which was the move to the broader balancing authorities, where I think there's been an undisputed benefit. And as we look on a going-forward basis of, you know, what should happen next, I think that – you look at the different things RTOs do. First and foremost, they’re a balancing authority. And I think that's been an undisputed positive aspect. So you say would you go back and undo at all? No, I think the balancing authority part's been very successful. By extending the dispatch across a broader area, which I think has been both positive for reliability as well as potentially economic efficiency, as well. And then you tie that to the real-time energy markets, and I think that does make sense. And this is why in my article and publicly I don't say – I'm not really raising that much of a question about – in fact, I think the real-time energy markets, I think, really go well with the regional balancing authority. And they come in different forms. Bill Hogan made the point in your podcast that California is little bit different. They dispatch 15 minutes ahead. They plan 15 minutes ahead, so it's close to a real-time market. Pretty close. But you can you can sort of refer to it that way. That's been a benefit. I think where things got off the, you know, the most vulnerable – and again, it's the whole heart of my article – it's about what are we looking at first, I think that in those RTOs that said, well, we need to find the missing money, the missing money for capital investment. So we're going to set up these things called capacity markets to provide the quote-unquote missing money. And I think that's where things sort of went off in a direction. And again, there's been a lot of – Bill Hogan himself says those are the original sin of market design. And so I think that's where the focus ought to be in looking back and taking restocking and say, okay, what was done right what was not done right? What tweaks should we make? But in answer your question, no, I don't I don't want to repeal it all, because I think the balancing authority function is has worked quite well and has been a tremendous benefit.

EMP: Yeah, and we see that in the West where there's growing momentum to get this single-price clearing market design in place to help the region accommodate the many renewable energy resources that are coming online there. You don't argue with the use of the single-price clearing market model in the real-time market, but you don't like it in the day ahead market?

MC: No, I think LMP – okay, let's differentiate. LMP is what's being used in the real-time and the day-ahead markets which is locational marginal pricing and I'm not going to repeat everything that Bill said on your show, because he went into it quite well, he's a very effective explainer, a great professor. I think in the real-time markets LMP is a better version of a single-clearing price mechanism. Let's remember LMP is one version of a single-clearing price. And I think it's the most effective because it's very granular and it goes right down to the to the injection point, to the node. So you get good price signals. I think that's an argument in favor of it. And so, but also remember that LMP is not even being used in capacity markets. So that’s important too. You’re not even getting the benefit of the granular price signals. You know, I think in the West, you mentioned the West. What I've said in the West when I go out there and I talk to regulators, a lot and other interested parties in the West is, first of all, whether you decide to join an RTO is your decision. It's not for FERC to order you to do it. It's your decision. You’ve got to make that decision based on what's best for you. And as you make the decision, don't look at RTO versus non-RTO as like one – it's just a dichotomy that's like you're all in for everything or you're an island unto yourself. There are different varieties of ways to proceed. And you start, of course, with, in my opinion, the most important function of all for an RTO and that is the balancing authority function. You can go into it for the balancing authority function and get the benefit of that and go into it one step further, which is a real-time energy market or, of course, they already have a WEEM, Western Energy Imbalance Market, which is a 15-minute market. And so you can pick and choose that parts of the RTO construct that work for you. And it doesn't have to be an all-or-nothing approach.

EMP: My question was, do you oppose using the LMP pricing model for the day-ahead market, as well as the real-time market?

MC: No if you use it for the real-time you can use it for the day ahead. I think that makes sense. 

EMP: Can we talk a little bit about your experience as a state regulator, you were on the Virginia Corporation Commission for 17 years. What was your first year on the Virginia Commission?

MC: My first year? It was 2004.

EMP: 2004. Around that time, there was legislation that rolled back Virginia's move to a retail competitive design. And I guess you were part of that debate at that time?

MC: Yes. Yes. Yes. 

EMP: You were part of the part of the argument: We need to walk away from this after what we saw happen in California.

MC: Well, here's what we what we said. When I say “we,” I mean, my commission, the Virginia Commission. So, Virginia passed a full deregulation law in 1998. And it was a go-all-the-way law. It was going to go to retail choice as well as participate in the wholesale markets. The Legislature capped the rates because they were afraid of an immediate big jump in in rates that would be paid by retail consumers. So they put a five-year cap on rates and then they ended up extending it. And so, so here's what happened. So we started in 1998. We go through retail choice, we wanted to see if retail competition would develop. And then, by 2006 retail competition had utterly failed in Virginia. No one signed up for it. No one wanted it. Consumers simply stuck with the default carrier. And so retail competition – it didn't stop working, it never worked at all. And so we were approaching the second expiration of the rate cap law, which was going to free rates to rise. And what happened, in Maryland, right next door, they had done the same type of law as Virginia did. And their rate cap had expired. And they had an immediate, like 70% to 80% jump in electric rates. And it had a fierce political blowback, as you can imagine, when consumers all of a sudden find out that their power bills have gone up 70%-80%. And there was a fierce political blowback and I think some politicians lost their jobs in elections, maybe even I think a governor maybe. So we, as the state corporation commission of Virginia, we were watching that and we were monitoring that. And so we wrote a letter to the Virginia Legislature in September 2006. And we told the Legislature that what happened in Maryland is entirely likely to happen in Virginia when our rate caps come off. Because we have not developed a competitive market in Virginia for retail rates. We have serious questions about what's going to happen to rates in Virginia. And we pointed out, next door in Maryland, here's what happened when they took their rate caps off and we're taking our rate caps off next year under your law. So we sent that letter to our Legislature. We didn't tell them what to do, because we don't tell our Legislature what to do. But we told them the facts. We told them what had happened in Maryland. And we told them this was likely to happen in Virginia when our rate caps came off. Well, about a third of the Virginia Legislature reads the Washington Post newspaper because they live in Northern Virginia and they already knew what happened in Maryland because they had been reading about it in The Washington Post and in the Washington TV stations. So they were already very well aware of what had happened in Maryland. And basically, our legislature came back in January of 2007 and said we need to reregulate. And that's what they did. They passed a law which stopped the move towards retail competition and restructuring and they passed a law that kept units in rate base so that Dominion and AEP and our utilities would have sufficient resources. Effectively they passed a law that at the time it was called the Reregulation Act, which went back to Virginia as a vertically integrated, state-regulated IRP model, although we were still in PJM. We didn't pull out of PJM. They didn't say pull out of PJM. So they, the Legislature said, we'll stay in the RTO, but we're going to be on a vertically integrated, state-regulated model. So that's the history of how Virginia got to a sort of a you might even call it a hybrid approach. We were in PJM. But we kept the vertically integrated model with utilities owning units in rate base so they would be there for reliability purposes.

EMP: The Legislature wasn't done after that. A few years after that the Legislature amended the Corporation Commission's authority to review the rates of the state's utilities. Am I describing this accurately?

MC: No, you're describing it accurate – well, that's a very broad generalization but it's a fairly accurate generalization. What happened in Virginia over the 17 years I was there was the Legislature, largely at the behest of our largest utility, Dominion, frequently would pass laws that restricted the authority of the Commission to regulate – would try to put in provisions that limited our discretion, for example, in setting something as important as return on equity. And so effectively what you saw was, you know, was a number of laws, which, you know, I didn't think at the time were in the public interest. I still don't. But our Legislature chose to pass them and that's what legislatures do. That restricted our ability to regulate and, and so yeah, that happened several times.

EMP: I guess there was a more recent legislative action that helped undo some of that and has restored some of the authority to the commission.

MC: Yeah, they passed that, I think, last year. Obviously, I was at FERC. And so I wasn't part of that. I'm not totally up on it. But I think that – look, one of the arguments made against state-regulated, vertically integrated systems is that utilities have a lot of power in the state legislatures and they’ll lobby to get, you know, they’ll engage basically in rent-seeking through legislation. And I think that's absolutely accurate. And that's absolutely a legitimate fear. You're going to get rent-seeking in any regulatory construct that you pick. You know, I made the point in the article quoting from Bryan Cranston in the movie “Argo” – we're looking for the best bad option. When we're looking at regulation of utilities, we're looking for the best bad option. There are no perfect options. There are no options where you can say this does everything. This gives us reliability, perfect reliability, and it gives us lowest cost to consumers. Those are the goals. But there are flaws in every regulatory construct. I taught at UVA law school for many years, and I would teach cost-of-service regulation as part of my class on regulatory policy. And I would make the point, look, I can sit here for this whole class – I taught a class that was two hours – I said I can sit here for this whole class and I can give you all the problems with cost-of-service regulation. There are a lot of flaws in cost-of-service regulation. One of them is the opportunity for rent-seeking certainly because utilities can go lobby legislatures and they're very good at that. And if they don't like what the commission is doing, they can go lobby and try to get a different outcome. And that – I would be totally naive to say that doesn't happen. Of course it happens. But there are flaws in the constructs that have been pushed since deregulation as well. And if there's one big takeaway, I hope, people take from my article is there are flaws in all these constructs. There are flaws in any construct you want to you want to pick. You want to pick Texas as your model, energy-only, okay fine. There are other models – capacity markets, combined with real-time energy markets, like in the eastern RTOs – that's a construct. There's the state-regulated, vertically integrated construct, that's a construct. All of them have flaws. All of them you have to make tradeoffs. All right, that's one of Bill Hogan’s favorite terms, tradeoffs. You have to make tradeoffs in each one. What tradeoffs are you making? That is the way you really debate these issues is you acknowledge upfront and you're honest about what are the tradeoffs that you're making when you pick a regulatory model. Because they all involve tradeoffs, and certainly state-regulated, vertically integrated monopoly, which I was part of for 17 years, I mean, as a regulator, there are there are big flaws in that, clearly. There are efficiency losses in that. But I think on balance, because you have to balance the reliability need, you know, I think on balance, that is probably about the least-bad option, because they all have flaws.

EMP: Well, you've been very generous with your time and I'm grateful that you came on the podcast to share your views with our listeners. I don't know if there's anything else you'd like to bring up for the good of the order before we adjourn here?

MC: I just want to finish with the same thing I started with and that is I want to reiterate what I said at the beginning. I want to reiterate what I said in my law review article that prompted you to call me. Everything we do as regulators in the energy area has got to be about what's good for consumers. We have to look at what is going to get consumers the reliable power at the least cost. And I think everything we do, we’ve got to be asking ourselves, is this the best thing for consumers? I think that's what's built into the Federal Power Act appropriately. And I think also just in a general sense, that's what as a regulator – you asked about my time on the Virginia Commission – 17 years – that was always our first goal, what is best for consumers? What is best for consumers? And we always have to be doing that and we and we shouldn't be doing that at FERC as well. And that's what I think that's what the overall goal is.

EMP: Commissioner Mark Christie of the Federal Energy Regulatory Commission, thank you very much.

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