Lillian Federico: I remember one of the big discussions in the ‘80s and ‘90s was the lumpiness of generation.
Demand doesn’t necessarily grow in an even way. Data centers don’t come online incrementally. Industrial manufacturing facilities don’t come online incrementally, and you can’t turn on 10% of a nuclear plant. The plant is either on or it’s not on. Matching the load characteristics of the demand and the supply, that’s what really concerns me. I think that’s going to be the biggest challenge for achieving safety, reliability, a cost that people are willing to accept and meeting the public policy goal of zero carbon emissions.
Teri Viswanath: That’s Lillian Federico, she’s a research director at S&P Global and works with the organization’s regulatory research associates division, the group the closely follows state-level utility rate proceedings. I’m Teri Viswanath, the energy economist at CoBank and your co-host of Power Plays. Lillian is setting up our conversation on rising utility costs that my co-host and colleague, Tamra Reynolds — a managing director here at CoBank — and I want to engage in. Hello Tamra.
Tamra Reynolds: Hey Teri. Looking ahead in 2025, we expect U.S. regulators will once again consider sizeable increases to electricity rates. But just how much additional funding are these utilities seeking, and what will be the impact on consumers?
Lillian weighs in on this and is joined in the rate discussion with her colleague Steve Piper. Steve is also a research director at S&P Global and for many large investor-owned utilities, is the go-to expert on utility integrated resource planning. Here’s their conversation about the recent acceleration in rate filings.
Federico: Clearly, we’ve seen the number of rate cases filed each year on an upswing. Of course it has really accelerated following the COVID pandemic. Just to put some numbers around it, requested increases filed in 2024 — just the first half — were $12.3 billion, which followed 2023, where there was $18.1 billion and 2022 where there were $16.8 billion.
These numbers are pretty astronomical and probably eye-opening to most people, but when you look back to, say, the early 1980s when we had the generation construction boom to meet rising demand, total rate increases requested were about $12 billion in 1980. When you take it on an inflation adjusted basis, the 1980s numbers are really almost double the current levels.
Steve Piper: The inflationary effects have been, I would say relatively modest, but it’s important to point out that we were coming out of a period where there was really very little inflation. People noticed the change from low inflation to more moderate inflation, notwithstanding that maybe rates were lower than they needed to be for a long time, and then now are entering a period where they’re starting to grow.
Reynolds: The job of utility commissioners is to balance affordability with the spending needed to meet electricity demand growth and maintain reliability.
Are they striking the right balance?
Lillian highlights that more than a few jurisdictions might get tougher on utilities, in terms of constraining their rate base as a means to achieve affordability. We asked her whether she was seeing pushback on these rate increase requests.
Federico: Oh yes. There’s definitely a higher degree of pushback. Consumer advocates are much more vocal and outspoken than they were before, and they were never exactly shy and retiring, if you know what I mean. Anecdotally, we are seeing a more intensive review of utility costs across the board. Commissioners are looking more rigorously at all types of expenses, even those that don’t necessarily move the needle much in terms of overall bill impacts. Things like management, incentive comp, and employee benefit costs, corporate travel, lobbying and regulatory expenses to name a few.
Those tend to be politically charged issues, but really at the end of the day, when you look at utilities, whole cost of service, those don’t really move the dial that much. Commissions are also beginning to question certain measures they may have agreed to in order to mitigate regulatory lag such as multi-year rate plans, deferral mechanisms that keep rates low in the near term, but exacerbate future rate hikes, and things like using year end rather than average test year values for things like reliability investment.
Of course, all of this adds up to keeping pressure on authorized ROEs and on regulators to prevent them from rising as quickly as interest rates may have been rising over the most recent couple of years. Lastly, some of the states that implemented retail competition are starting to question the efficacy of competitive markets for generation, and whether the market constructs that have evolved are truly competitive.
I think it more comes down to that companies that have more constructive regulatory environments to start off with, and those that have better relationships with their regulators and customers, even in more restrictive environments, are going to make out better than utilities that don’t.
Viswanath: This is a jurisdiction-by-jurisdiction issue, so what’s happening in California is probably not the same thing that’s happening in Illinois or New Hampshire, but I pressed Lillian for some specifics what she’s seeing.
Federico: You’re seeing places like Maryland where there’s more pushback on ROEs than there was previously, at least on the part of the consumer advocates. In New Jersey it’s a little bit more subtle, I think. New Jersey has used the same 9.6% ROE for all of their utilities for probably seven or eight years now.
We saw Connecticut recently, over the summer, authorized one of the lowest non-punitive ROEs we’ve ever seen. When I say ever, I mean 40 years we’ve been doing this, so all types of inflation and economic climates causing us to actually downgrade our ranking of that regulatory environment. I think it’s pretty much all over the board where you’re starting to see these kind of pressures.
Viswanath: It’s really important that we keep in mind that these new requests for funding are on top of a pretty impressive spending that is already taking place as Lillian and Steve explain.
Federico: RRA did a semi-annual Capex report at the end of October. Based on the 46 electric and gas utilities in our coverage universe, projected Capex for 2024 was $182 billion.
That’s up from $166 billion in 2023 of actual spending and $144 billion of actual spending in 2022. Then through the ‘25, ‘26, ‘27 period, capital spending is going to rise from about $192 billion to $197 billion on an annual basis, just from what these companies are reporting. The drivers, we’re looking at a lot of infrastructure spending, and this is spurred by federal legislation. Also state energy transition plans, it costs money to retire one type of resource and replace it with a new type of resource. Then, of course, demand growth from data centers and hyper-scalers.
Piper: You have to start with the broad lens, kind of the imperative to decarbonize electricity generation, to get the emissions out of traditional generating sources. That’s driving a lot of the deployment that we’re seeing. Something like 60% of all electricity sales are under some form of renewable portfolio standards. Roughly 45% to 50% of electricity sales are subject to some form of carbon tax, whether it’s the Regional Greenhouse Gas Initiative in the northeast, or the Western Climate Initiative in the western states, California, Washington.
That has impacts on both unregulated markets and more traditional markets where long-term planning is handled through, as you indicated, integrated resource planning processes. Getting reduction in carbon emissions is definitely driving just about every IRP.
Reynolds: But wait a minute, the levelized cost of new renewable energy has dramatically fallen over the past decade, right? In fact, utility-scale solar development costs about half what it did back in 2010 and the International Renewable Energy Agency claims that solar in particular is more than 50% cheaper than the lowest cost fossil fuel substitute, even though it’s not dispatchable? So what’s going on here?
Piper: The imperative for decarbonization is driving a lot of innovation in generation. It’s driving costs for new generation lower and lower.
At the end of the day, it still costs money to replace your old generation that’s already been paid for with new generation that has benefits, but those fully loaded costs have to be covered somehow. There isn’t a magic bullet to make the energy transition happen without a structural rise in rates. Then couple that with the prospect of load growth as we’ve discussed, and with some of the other things happening in states that we’ve talked about today. California with its risks associated with grids under, and wildfires and things like that. Getting all the needed upgrades paid for is going to take time.
Viswanath: Tamra, I worked for a power plant developer in the late 90s. As Lillian will explain, that was a time in our industry when a massive wave of private investment was unleashed to take advantage of deregulation. Nearly all of those early merchant developers – Enron comes to mind – are no longer around. That boom-to-bust cycle had a chilling effect on the next new build and replacement cycle. Here’s Lillian on this.
Federico: Once we got out of that late ‘80s, early ‘90s construction boom, when that was over and done with, we had a lull where there wasn’t a lot of demand growth with the specter of retail competition, so we had a lot of deferred investment. During that late ‘90s, early 2000s period, we saw a time where depreciation was actually outstripping Capex, which is something anybody who’s been in the industry for 20 years or less probably finds very hard to believe. Now we have this infrastructure spending that has cropped up again, even before energy transition really took off and even before this new source of demand growth. This was brought on by safety and reliability concerns.
It really picked up in the gas industry in 2010, following significant pipeline explosions, such as San Bruno and Aliso Canyon. Then the East Coast blackout in the early 2000s on the electric side. Regulators and companies recognize that in order to ensure grid reliability and safety, they needed to accelerate the replacement cycle. Some of the investment we’ve seen in recent years stems from those occurrences. Looking back to, say 2011, Capex for our group was barely $60 billion. In a sense, we’re now paying the piper for deferred spending in earlier periods.
There is a temptation to scale these initiatives back. But I think that ne just has to take a look at the challenges that the water industry is facing as an object lesson for why that might not be the best course of action.
Reynolds: There was a really interesting part of our conversation with Steve and Lillian that focused on how the changing market structure might affect how agile the industry will be in meeting the growth ahead, as Steve explains here.
Piper: Under the regulated model vertically integrated utilities, which was the norm of course in the 1980s, there was a streamlined process of planning out how to meet that megawatt hour and megawatt demand increase through the addition of new power plants through the optimization of the fleet. The stakeholders were essentially the utilities, the commission, and then of course participation by consumer watchdogs and so forth to ensure that costs were kept in line.
The universe of stakeholders was relatively small in the 1980s. Fast forward to today, we have a much more complex situation with a larger number of stakeholders. Much of the generation in the United States is privately owned, not all of it, but a significant proportion of it with participation with private sources of equity and project management funding to keep those projects maintained and operating.
The wholesale transmission system is still owned by regulated entities but managed by these large regional grid operators that coordinate dispatch of generation across much, much larger areas in the 1980s. Then the distribution systems by and large are still regulated, but this creates a much more complex universe of potential actors in providing new generation. It creates a greater division of responsibility and more confusion potentially about who in the marketplace addresses those future generation needs.
In the modern period, this comes at a fairly perilous time. The energy transition was always understood to pair zero carbon generation with reduced carbon end uses, heat pumps instead of natural gas furnaces, electric vehicles instead of gasoline cars, and on down the line. In addition to these new sources of load growth, we have this anticipation of ever-increasing data center loads to serve consumers that imply a much more robust period of load growth potentially during a time when the means to meet that load growth are more fragmented than ever.
Viswanath: We are waiting for this year’s NERC Long-term Assessment to release, so we can better understand what our nation’s future electricity supply shortfalls might look like. Last year’s headlines were pretty ominous: “Rising peak demand, 83 GW of planned retirements create blackout risks for most of US.”
We know that we need a certain amount of excess capacity in an electric system, but what is that amount? And what is the trade-off? Here’s Lillian to explain.
Federico: The Texas Commission tried to put in mechanisms to ensure that there were sufficient capacity available to meet-- back in those days it was a series of weeks in a row where they had 100-plus temperatures for days on end and they had rolling brownouts and blackouts, and at those temperatures it becomes a danger to life and limb. They had a lot of consultants that came in to give them recommendations about how they could tinker with the system to prevent those brownouts and blackouts from occurring. At the end of the day, what Commissioner Nelson and I talked about was that it becomes a trade-off. How much are you willing to pay for how much reliability?
Do you build a system that will insure you against a 25-year weather event? That could be. These days now, it could be a winter storm, it could be a hurricane, or it could be days on end of record-breaking temperatures. You’re protecting against a 25-year event, a 50-year event, a 100-year event? It’s like buying insurance. How much are you willing to pay to indemnify yourself? How much risk are you willing to take in order to reduce your cost? Those are very difficult questions to answer, and I’m sure those are very personal questions for most people, and it’s difficult for public officials of any kind to strike that right balance.
Reynolds: Consumers across the PJM Interconnection footprint will pay $14.7 billion for capacity in the 2025/26 delivery year, up from $2.2 billion in the last auction. The spike in capacity prices this past summer was driven by power plant retirements, increased load, and new market rules that aim to better reflect risks from extreme weather. In other words, this market appears to be paying a whopping insurance bill to make sure that the generation will be there. We asked Steve about this.
Piper: PJM is another really good example. It’s the largest single wholesale managed grid in the United States. I want to say if it’s not, it’s pretty close. It’s a bit of a tale of two extremes where for a period of time we had low wholesale prices, we had fairly abundant assessments of available capacity, especially coming out of those states where new green build has been very high, a lot of wind generation coming in, solar generation coming in. The market signals were reflecting really low prices then in those capacity auctions. Low wholesale prices, low capacity prices affecting revenues to generators really represented a signal, as you said, for private capital, especially to sit it out.
Not a lot of return to be gained by additional investments in those markets. Ever since about 2018 or so, we’ve had a pretty big lull in that PJM region in investment in new conventional generation that can provide reliable dispatchable capacity. At the same time, PJM is the grid manager who’s looking at the actual contributions of intermittent resources – what does wind really contribute to critical hours? What does solar really contribute to critical hours? Increasingly then, what does natural gas generation contribute as well when gas supply arrangements and the impact of extreme weather is taken into account?
They really took a holistic view of it and I think made an effort to say if we reassess how much reliability contribution we get from all of these resources, how does that reset our bid stack against our demand curve in the context of the auction process? They made some changes, and we then went to another extreme where once that re-estimation was done, PJM looked significantly tighter from a resource perspective, from a reserve margin perspective. Prices went much, much higher — higher than they had ever cleared in PJM’s auction process.
You can argue on the one hand that this is a more appropriate signal for reliable capacity to be added. It’s a way to jump-start the financial participation, the capital markets participation in PJM’s market and ensure that the right types of capacity are being brought, but as we led off the top of the call, when you go from an environment of low capacity prices year after year, to now a much stronger price signal on the end user side, that’s a bit of sticker shock.
Viswanath: Sticking with our topic on who is going to pay the bill, I couldn’t resist asking Lillian about the developments in Ohio. AEP Ohio asked its regulator to approve a settlement agreement that sets terms and conditions for connecting data centers to the grid.
Federico: These data centers are the industrial customers of the 21st century. I was expecting states to look at it in the same way as they would have looked at a new steel plant opening in Pennsylvania or a new auto plant opening in Michigan, that this is good for economic development.
Yes, it does mean some costs and burdens on the electric system, but it’s baseload capacity that would then be there to serve the grid and that would benefit other customers. Then of course, the way vertically integrated rates were structured, these large industrial customers have historically subsidized the small C&I customers and the residential customers in terms of the fact that the way rates are structured, the utility earns a much higher rate of return on the industrial customer usage than they do on the electric and small C&I customer usage. This was all aside from any kind of tax benefit or anything else that just the overall economy and the state would benefit from.
But now I hear a lot of these things, not just Ohio or Maryland, the consumer advocate has expressed concern about the governor’s empathy for data centers and what is this going to cost regulated ratepayers, because they’re seeing it as we’re building transmission just to serve this particular customer, and they’re causing the cost, so they should pay the cost. That goes against what the philosophy has always been. I’m just wondering if we are going to see something of a change in what the regulatory compact means.
Piper: Just to follow on those points. Ohio is part of PJM. It’s one of those restructured states where the promise of restructuring was to really capture cost efficiencies going forward, so from about 2000 forward. You can argue about how ultimately successful it has been, but to the degree that it has been successful in bringing private investment into generations so that rate payers maybe pay less, bringing more competition and wholesale markets, and really keeping a lid on costs, that’s actually created a situation where this new environment of load growth, instead of creating the situation that Lillian described for classic regulation, now it’s a zero sum game, where new load, even though it’s data center load and base load, really competes for that generation on cost and has this potential to raise prices for all the stakeholders, all the end users. The dynamic from the traditional regulatory environment has been in many ways reversed.
Reynolds: E3 just released analysis on the customer impacts of continued data center growth in Virginia. They concluded that the pace and scale of infrastructure development — as well as secondary impacts such as increasing tightness in energy and capacity markets — is likely to lead to upward pressure on rates for all ratepayers in the near to medium term. So, this conversation on how electricity rates can appropriately apportion costs is a timely one.
Viswanath: That’s right. I do hope all of you have enjoyed this conversation and will join us in the new year, when we discuss broadband data analytics driving operational and financial success. I hope you’ll join us then.
Reynolds: And thanks again for joining us this year, we’ll see you in the new year! Bye for now.
