Addressing the Strain on Texas Power Grid

Increased use of AI and cryptocurrency operations are expected to place considerable strain on already aging Texas power infrastructure. Adding the extreme heat to the mix, what is being done to address this issue and reduce the potential of blackouts and increased cost to consumers?

Transcription:

Greg Dawley (00:09):

Great, thank you. And just so we are a large panel, let everyone go down the road, introduce themselves as their name and who they work with. I'm Greg Dawley with RBC, and I'm Co-Head of our Public Power group nationally.

 Barry Smitherman (00:21):

Barry Smitherman, Chairman and Co-Founder of The Texas Geothermal Energy Alliance.

Bhala Mehendale (00:26):

Morning everyone, Bhala Mehendale. I am a Senior Vice President at US Bank covering public power and utilities.

John Miller (00:34):

I'm John Miller with BAM Mutual.

Harvey Hall (00:37):

Harvey Hall with Lubbock Power & Light.

Paul Dyson (00:39):

Paul Dyson with S&P Global Ratings.

Greg Dawley (00:41):

So we were talking before the panel. This could easily be three different panel discussions, so it's a survey of the topic, but there's a lot that we can get in this hour and we appreciate everyone's attention. We obviously know that the panel before the interest in the market and the chaos of the muni market the last couple of days certainly took precedent over anything else but we think this was mentioned. This is a sleeping giant topic. This is a topic that's going to impact every aspect of Texas, not just the municipal side, but obviously anyone who lives here and experiences power outages or shortage of power or power price spikes and everything else. And this is while it is a national problem, Texas in particular has some unique aspects that we're going to talk about here. We're going to go through and survey three or four different areas.

(01:28):

One's going to be what is ERCOT, which is the Electrical Reliability Council of Texas. What is it? The history and the purpose. Barry's going to talk about that. Barry used to be the chair of the Texas PUC and has a lot of knowledge in this area. Then we're going to pivot to John Miller. John's going to talk about energy growth forecasts and why that's happening, particularly in Texas with the data centers and other areas. Then we're going to pivot to Harvey Hall, who's the CFO of Lubbock Power and Light, and Harvey's going to talk about what it's like being a muni in ERCOT and why he joined ERCOT in 2023 and other aspects that are going on in the Texas market. We're then going to pivot to Paul Dyson from S&P. Paul's going to talk about how they look at different issuers and different governmental entities in Texas based on this topic, and he's going to talk about their views going forward. We talked Bhala also. Bhala is with US Bank and he is a lender into the renewable side and also the energy side and is going to talk about from the perspective of an investor and a lender, what are some of the challenges in Texas with different policy areas. So I think with that we're going to turn it over to the first section, which is kind of what is, just for a quick, what is ERCOT? What is the energy resources and what are some other aspects of ERCOT? So Barry,

 Barry Smitherman (02:50):

Well good morning. Good to see everyone in some cases, some old and familiar faces, and to be here next to Greg who wants to work for me. And so I'm so happy to see his success and what he has done here in the industry. So ERCOT is very unique in that we're the only intrastate grid ISO independent system operator, RTO, regional transmission operator. We are minimally interconnected with the eastern and western grids and in that particular regard, we're not subject to jurisdiction for prices, but we are subject for reliability. We operate in energy only market. Here in ERCOT, there's a $5,000 price cap. It used to be $9,000, but after winter storm murie, it was reduced down to 5,000. There are various adders that help pay for generation when it comes online during periods of scarcity. To think about this market we dereg did over 20 years ago or restructured it.

(03:57):

So we have generators that are minimally overseen by the PUC, but that's a competitive market. We have retail electric providers that interface with the customer, they bill and collect. If you go to power to choose.org, you can see some 100 plus offerings. They're really two or three big companies like Reliant and TXU that service most of the customers. But it is a competitive market and the part in the middle, the wires company, the TDU, like Enco and CenterPoint remains fully regulated by the PUC. They set their rates that they can then recover from customers or attempt to make it even more complicated. There are four non ERCOT utilities. These reside on the periphery of ERCOT and they have customers in jurisdiction, not just in Texas but in other states. Then there are three non opt-in entities, that's LCRA, San Antonio, CPS and Austin. And then there are some 70 ish co-ops and some 72 ish I think municipal utilities in addition to Austin, San Antonio. So you could spend a lot of time thinking about the structure of the ERCOT market.

Greg Dawley (05:13):

Why don't we talk about the resource mix?

 Barry Smitherman (05:15):

Yeah, good. A little bit about the fuel mix. Interestingly enough, we have about 25% of our fuel mix is wind. Solar is now making up about 10% nuclear as remained static, but it is an ever increasing smaller percentage and then most of the capacity is still natural gas. But to give you the real numbers on wind, we have 40 gigawatts of installed wind that the most of any state, and I think maybe the most of any country right now, 20 years ago it was a rounding era, less than 1%. So now we have 40 gigs on some days, particularly in the spring, we can get up to 70% of our energy from solar and wind. In fact, yesterday morning 80% of all the energy on the grid was wind and solar. Have you had nuclear in there for its contribution? It was almost 90% zero carbon fuel mix at the time and prices were negative.

(06:23):

So this is both a good news and a bad news story. The good news, when the wind blows and the sun shines, it's environmentally good and we have very low prices. When either of those stop, say late in the evening or on a cloudy day, then we have to turn on the fossil units, the dispatchable units to make sure the grid remains reliable and has grid integrity. So the challenge that we're seeing at the capital Greg, and I know we're going to talk a little bit about this, is how do we continue to provide reliable low cost and cleaner energy? One last thing that I'll say, and I know we're going to talk about data centers and the load not long ago ERCOT estimated that the load by 2030 would almost double, it'd be 150 gigawatts from a peak of 85 today. Fortunately, they came back yesterday in a house legislative hearing and said, well, while the TDU have estimated that the load in 2031 will be over 200 gigawatts, over 200 gigawatts, we have haircut that back to 145. That's still an incredible growth trajectory for load in ERCOT in particular. A lot of it's data center, but not all of it. Some of it is what's happening in the oil patch in Midland and the Delaware basin and LNG exporting facilities in a combination of other things, including people just moving here. So I think I'll stop there, Greg.

Greg Dawley (08:00):

One thing, those of us who cover the public power, the sort of power sectors are we rarely see anything in the popular media about us unless things go wrong, like winter storm murie. And so one thing that's really gotten into the public consciousness recently has been this concept of data centers and crypto and this massive demand on energy load. So if you go back 15 years or so back to the financial crisis from the 10 years after that, there was almost no low growth in this country between demand management initiatives and just the ability to kind of manage assets more efficiently in general. There was almost no low growth from the few places in this country that had low growth from 2010 to 2022 was Texas and so consistently one to 3% low growth. But what Barry's talking about here is in low growth that's like 10% a year or more just incredible levels. And we have John Miller who's going to talk a little bit about what's driving these sort of projections and what's going on particularly in Texas in this area.

John Miller (09:06):

So ERCOT is forecasting that annual energy usage in Texas will double over the next five years from 500 gigawatt hours in 2024 to over a million in 2030. That's a pretty huge increase. How many of you think that's likely or even possible? That's what I thought. It seems pretty preposterous on the surface frankly, especially given how much new generation and transmission that that's going to require. But when you look behind the curtain, the forecast is a little fanciful or a little less fanciful. Details show a different story and the demand may in fact be real. So let's start with a few pretty well-known facts first, Texas is growing like crazy. The state added nearly 600,000 new residents in each of the last two years and has increased its population more than any other state for several years. Running Texas is well on the way to becoming the most populous state in the nation, eventually catching up with California.

(10:08):

Second, it's really hot in Texas and occasionally very cold and extreme heat and cold are becoming more common. It's expected by 2036 that the number of days exceeding a hundred degrees on any given day will be four times higher than it was in 1990 third. Texas is considered to be friendly towards business and significantly has average industrial rates that are among the lowest in the country at 6.59 cents compared to say California at 19 cents only New Mexico and Louisiana have meaningfully lower industrial rates than Texas fourth Texas mirrors the national trends in electrification, particularly in the percentage of energy consumed by buildings which is projected to raise to rise to 50%. Transportation or electrification is forecast to increase the demand for electricity by 27% over the next decade. Oil and gas for the owners and the oil patch are changing out the diesel and gas and beginning to run their operations on electricity and of course data and computing where the real story lies.

(11:20):

In 2025, the United States as the largest market for Bitcoin mining. It has a hash rate market share of 36% around the world and much of that is located here in Texas. Bitcoin miners have located in Texas for a variety of reasons, but chiefly because bitcoin mining is very energy intensive, Texas is considered a Goldilocks location because the energy infrastructure allows access to cheap power in a deregulated market. There's a growing mix of resources that are available, particularly wind and solar and the business environment is considered friendly and perhaps even permissive. Crypto miners in Texas will use roughly 25 billion kilowatt hours of electricity in 2025. It's up 60% from 2024 representing 10% of the total electric consumption. In ERCOT crypto mining facilities are known as large flexible loads within ERCOT because the computers did not need to run continuously. The facilities can be dispatched when economic and shut down in times of high electric demand or low generator availability.

(12:33):

This flexibility has allowed crypto miners to locate where power is available. Oil and gas companies have long struggled with flaring at their wells. Crypto miners have tapped into this gas to generate electricity to power their supercomputers and capturing waste gas to run generators, protects the environment, repurposes and otherwise stranded energy asset and pairs well with intermittent wind resources. To give you some context why energy is important, one single bitcoin transaction, which takes about 10 minutes, uses roughly the same amount of electricity as a typical household uses in 36 hours or about the same power usage of 26,000 visa charges quite a bit. So LNG changing topics a little bit. Exports grew 450% between 2017 and 2022. The US is now the largest exporter of liquified natural gas in 2023, Texas exported 1.3 billion cubic feet of gas and increase of 237% from 2019 when there were only four trains that were running.

(13:50):

According to the Federal Energy Regulatory Commission. There are currently 22 trains under construction, which are expected to be operational by 2028. So here's a question that I sometimes think that people have a problem with. What is L-N-G? L-N-G is really cold. Natural gas frack natural gas turns into a liquid at minus 259 degrees. One ton of LNG requires roughly 400 megawatts or kilowatt hours of electricity or approximately 10% of the BTU content of the original gas. The new trains are being built with onsite combined cycle gas turbines paired with power purchase agreements for wind to meet the base load continuous requirements of the ification process on another source of demand in 2030, Texas could produce over 50 million tons of green hydrogen through fueling water electrolysis. With renewable power, particularly wind generation, it takes 33 megawatt hours of electricity to produce one ton of hydrogen, 33 times 50 million.

(15:06):

It's a meaningful percentage of the 1 million gigawatt hours of demand that ERCOT is forecasting for 2030. And finally, the real source of growth in the power forecast is from building centers for AI large language models. Historically, datasets were on average a hundred thousand square feet and consumed 30 to 40 megawatts of power on a fairly level continuous basis. Then about 24 months ago, the arms race to build gigantic dinner centers for the new artificial intelligence applications started in earnest. These data centers are being built now all across the country and notably here in Texas are 1 million square feet and at peak power load of 400 to 500 megawatts. But the load is not constant. A 400 megawatt facility might have 20 megawatts of constant demand, but with a flick of a switch 380 megawatts in seconds comes to work to power the computing models of the new AI systems, which in a highly simplified manner search for a while and then think they don't run continuously.

(16:20):

The big five tier one hyperscalers known as mama are indeed in an arms race. Collectively, they accounted for 197 billion of the 430 billion that was spent worldwide on the construction of new data centers in 2024. And it continues. MEDA has announced an investment in AI data centers of 65 billion this year up from 35 billion last year. And not to be outdone, Microsoft has announced that it will spend 80 billion this year and by some estimates, these figures will triple by 2029. These companies and many others are scouring the country looking for pockets of available power, buildable flat land and strong internet conductivity. Last year, 24 new data centers were announced that we'll have a cost of over $1 billion, four of which will exceed $10 billion and five located here in Texas. In addition to all this Oracle in collaboration with OpenAI and SoftBank has launched the Stargate project here in Texas, which will involve an initial $100 billion investment in 10 data centers.

(17:35):

The first step in a $500 billion undertaking to scale AI and cloud computing. Many of these projects are so big that power customarily purchased from the grid is simply not available. Consequently, they're bringing their own. Many of these large projects are partnering with utilities, gas companies and contractors to build bridging generation co-located and dedicated solely to the new data centers. These largely gas-fired combustion turbines are massive in scale, upwards of 1500 megawatts and cost as much as two and a half billion dollars. There are of course lots of issues surrounding how all this gets done, where the equipment and experienced labor will come from to build so much so fast, but nevertheless, there's lots going on. In fact, the DOE released the forecast in December that showed that by 2029 data centers could use as much as 12% of all electricity consumed in the United States. So that's a glimpse into the forecast or the forces rather that are driving demand, which leaves some difficult questions for my fellow panelists in an energy market only, which does not pay for capacity historically, has had very tight reserve margins and provides poor pricing signals for new development. What are the state and ERCOT doing to incentivize new construction? Will there in fact be enough electricity and transmission to meet this projected demand? And particularly for this public power audience, will the new demand pay for itself or will the cost be born generally by the rate payers in Texas?

Greg Dawley (19:17):

Thanks, John. That's a lot to digest and it just shows you how big and how varied the demand growth is in Texas. It's not just one area. One of the topics that John brought up was this concept was called lumpy load, which is you have a data center which is sitting there not really running at 20 megawatts and it goes to 400 megawatts suddenly. That's one aspect of it. The other aspect of it is you build something, build a data center, you create infrastructure for it, and then it fails financially and you now have a stranded asset. So Bhala, what you want to talk a little bit about from a lender's perspective, like how you address this concept of the lumpy load versus more traditional growth that we have seen before?

Bhala Mehendale (19:58):

Sure, no happy to. Well, a lot going on obviously in Texas, a lot of demand, a lot of growth, a lot of capital needs, a lot of capital expenditures planned. Hopefully ERCOT is not limping along like the way I've been limping the last few days, but I'm sure we'll be fine. From a lender's perspective, I look at it at two levels. One is the micro level, which is specifically at the issuer level and then at the macro level, what is driving the utility sector here in Texas at the micro level, if you take any borrower or an issuer, a lender, a bond buyer, most of the audience here is going to look for predictability of cashflow. Predictable cashflow is normal, it's boring, but I love it. That's what I want. So how do I get there and how do I look at typically a borrower and the predictability of their cashflow In a high growth environment, unlike most of the other sectors, the utility sector is a high fixed cost sector that's paid for by volumetric rates and that itself is a big disconnect.

(21:16):

You have to develop capital intensive assets to serve an essential commodity or to provide an essential service and recover that over volumetric rates. That's what I call in a banking sense, ALM or asset liability matching. And why am I using a banking term for utility? Well, the asset is the load that the utility has to serve, right? That's their client, the buyer of their product. The liability in my mind is the infrastructure assets that need to be developed to serve that load and you're going to recover those infrastructure assets over volume primarily, essentially. So you want to keep the volume going and that's where the lumpiness, as Greg mentioned, off load presents challenges. What sort of risk management framework is put in place between the buyer and the seller? The seller is the utility, right? The seller of the commodity and the buyer of the commodity.

(22:23):

Is there some cost sharing? Is there some upfront capital cost so that the entire risk of a lumpy load either ramping up or ramping down or even much worse leaving or going away completely is not born by a utility rate base? That could be really small, it could be medium or it could be really large. So if you're talking about 200 megawatts on a 5,000 megawatt peak load system, fair enough, we can probably absorb it. But if you're talking about a couple of hundred megawatts on a utility that has 500 megawatts of load, peak load to begin with, that's a completely different ball game out together. And then the other thing I look for, at least at the micro level, and honestly I don't have an answer to this, I'm not a tech expert, but we've seen this in the technology sector. This is a time in an industry where the tech sector is very, very closely overlapping with the brick and mortar, old boring utility sector.

(23:23):

How is that? The tech curve can be incredibly steep, right? It can be sloping downwards incredibly at a high rate. What do I mean by that? Every new chip that comes out consumes less energy for 3, 4, 5, 7, 8 times the processing power. Is the future demand really going to be there? Perhaps because you probably need a whole lot more data centers even though each individual chip may be a lot more efficient. So at the aggregate level, you still may have a demand increasing, maybe not by as much or maybe by a whole lot more if there's a lot more demand for ai. So that's the tech wildcard or the tech variable at the macro level at Erhart, and I know Barry touched upon some of those points earlier on, clearly the most obvious need for investment is generation transmission, no question about it, but I'll get a little geeky here and talk about ancillary services, which is sort of an often overlooked part of the sector and it's a little important here in Texas.

(24:33):

What do I mean by ancillary services, right? You run generation to supply load because when you flip the switch, you want the light turned on, but you also want the current to flow at a particular voltage. You want the service that you receive in your house at a particular frequency that is ancillary services. It is equally important as the capacity that you have as the transmission that you want to build. And believe it or not, in Texas, the cost of ancillary services can be the same as the cost of energy or even more than the cost of energy. And just by reference, if you look at some of the other RTOs or ISOs in the rest of the country such as pja or miso, about 80% of the wholesale cost, 75, 80% of the wholesale cost is essentially energy. 10% is capacity. There is no capacity here as John pointed out.

(25:26):

And the nce five or 10% is really ancillary services. It flips on its head in Texas. Why so? Well, you need all of the above generation assets. If you look at the chart of the energy mix, it's all of the above, but it's equally important to look at energy mix at a point in time as it is to look at it over an entire year because the sun doesn't shine 24 hours of the day. You still need ancillary services, hence the Texas Energy Fund and hence the 5 billion pool to provide peakers. Of course you want peakers to provide energy, but the hidden message, maybe hidden is not the right word, but the additional message from that fund is essentially we want to make sure the grid is stable and reliable. And then lastly, but not least, where am I going with all this? In my mind, regardless of at the macro level or the micro level, there are two fundamental parameters.

(26:25):

When you're providing an essential service that you should never, ever violate, what are those two? In my mind, it's really affordability and the reliability. And I know Barry touched upon this a little bit. Whatever you do at the micro level and at the macro level, can you provide affordable service in a reliable manner? Because guess what? You don't want your team coming to you and saying, dad, why is the power out? And try telling your teen, Hey, I dunno, there's something funky going on with the ancillary services and your child is going to go, what? So I think you always have to think about affordability and reliability and that's what you always have to focus on regardless of whether you're looking at the ERCOT level or you're really looking at your local utility level.

Greg Dawley (27:12):

Thanks Bhala. We're going to move over to Harvey now and talk about the perspective of being a municipal utility in the ERCOT system. And the bulk of the utilities in ERCOT are privately owned corporations, massive places, Encore, CenterPoint, those type of large entities. But we also have very large unis like CPS, energy and LCRA, Lubbock and Garland that are in the system. Why don't you talk about, you just joined ERCOT recently. Why don't you talk about why that happened and some of the dynamics you view being a Muni utility.

Harvey Hall (27:43):

Excellent. So in April of 24, Lubbock Power and Light completed its eight year journey from going from Southwest public Southwest Power Pool into ERCOT. And that transition that entailed over $300 million worth of generation transmission assets to be able to connect into that grid. It was a long road and it was strewn with potholes along the way. It was very difficult. We did make that journey. We did it for a number of reasons, but I'll just step back and give you a two second background for LP and L. So Lubbock Power and Light is the third largest municipality in the state of Texas. We're department of the city of Lubbock. We're located about 375 miles that way or about six hours drive. Or if you drive like somebody in Lubbock, that's about four or five hours, they do drive that fast. And you'll notice that on that prior map that was up there for ERCOT, you'll notice that we are in west Texas where Lubbock is located.

(28:46):

It's right on the seam of SPP in ERCOT. So back in 2010, we served our 110,000 meters or 400 megawatts of load primarily with three aging thermal units or national gas units and a large long-term purchase power agreement that was going to expire in 2019. So 2010 started a journey for LP and L to be able to discover how are we going to take care of our customers? How are we going to serve them? Are we going to build a brand new gas plant all for ourselves? Are we going to acquire assets? Are we going to enter into a tolling agreement, another utility, or are we going to solve or mix into that Another long-term purchase power agreement being an SPP. And I think Bhala said it really well and that is SPP is a capacity market. The consequence, it's nice in one respect. The other part that's not nice is you got to pay for it and it's expensive.

(29:49):

So we were looking at our options at about that time and then along came a blessing. We like to refer to it as the competitive renewable energy zone CREs. And that was the effort to build 3,500 miles of transmission lines to connect all the renewable resource in the panhandle in west Texas to the metroplex area. This for Lubbock power and Light crater and opportunity because those lines, those transmission lines came right past Lubbock. And then everybody staring at those lines said, well, why don't we join ERCOT? Why don't we look for a market solution to this rather than saddle our rate payers with either an expensive long-term contract or the burden of paying the debt on a $700 million a year, a $700 million gas project to serve all of our needs? And that began the process. And so the CREs projects came online in 2013. By 2015, Lubbock Power and Light had made officially the move that they want to join ERCOT.

(30:53):

So started the petition to the Texas PUC and finally in March of 2018, the PUC granted or approved the entry of the move for LP and L to move into ERCOT. That triggered off the over $300 million of investments in our transmission assets to connect into the grid were prior to rez. That wasn't even really a realistic option. We went ahead and we made that move. The city council also made another decision and that was that LP and L would no longer be a provider of energy to our customers. This responsibility would be turned over to the retail electric providers and the ERCOT system to be able to provide that energy and we would get out of that business. So that entailed a couple different things that entailed that we would restructure all of our rates and everything else to look like to become a transmission district transmission distribution utility. So we are a TDU, so just know that the TDU is out there. There's actually a municipal one. We're not nearly as big as the others, but we are. We're on that list.

(32:05):

And so we made that move. Finally in 2023, we switched. We made the final integration of all of our load into ERCOT and then in April of 24 we turned over all of our customers to retail electric providers. This accomplished for us a couple of things that we had set out and one was we wanted to wanted introduce customer choice for our customers. That took a very long and extensive, and it's its own story about the communication with your customers who are just used to a utility taking care of that to a retail electric provider, a large communication effort, but they've got that choice. So we've got 65 reps that compete in our territory and give our customers choice. They have experienced slightly lower rates, maybe not as much as they had hoped, but they are, but they are more flexible. That's the benefit to the customers.

(32:58):

The benefit to LP and L was that we could now focus on a new future and that is being a transmission distribution utility. And the other part of it too was much less risk. And this is going to become one of two themes I think for Munis that you're going to hear risk. It's about risk and looking long range for where you're going to head. That's going to be a constant theme. So when you're looking at municipals, the municipals are going to be looking on how to manage risk, whether it be purchase power risk by building generation units, getting out of that business like we did and then looking long range. How are you going to solve all these problems for a long-term future, much longer term future. It's like obviously on the finance side of it, you're going to be looking minute by minute.

(33:44):

As you look at what's going on over the last few days, our range starts to look five years and out. That's where we're headed. So it's a very different perspective. So just know that the culture that you're dealing with with a municipal is going to be quite different than the way that you look at it, just a different perspective. And so for us it also meant sloughing off that risk meant credit rating upgrades. So after our move into retail retail market in April, we got three credit rating upgrades. We got it from S&P, we got it from Fitch and from Moody's, our credit ratings upgraded. And really the main factor was that is that we are no longer in the power market and subject to subject to that financial risk, which is substantial and quite volatile. So we are just really another toll booth along the way of the Great Electric Highway across Texas, and that's kind of a nice place to be, especially from a business model and reliability.

(34:40):

We remain very financially strong and we're in a great spot to be in. So our mantra is it's less about and very volatile times. It's less about knowing what's right over the horizon than it is about being prepared for whatever comes to the horizon. We're prepared to meet that challenge and that's part of that longer term view and it's also about managing risk. So for us, our next challenge in front of us is what we're going to refer to our own project is the west side transmission loop. And that talks about the congestion that is becoming a bigger and bigger issue in West Texas from a transmission standpoint. And it's about how do you get those, it's almost like Kress 2.0 only going north south as opposed to coming to the metroplex. How do you get those renewable resources from the panhandle, southwest Oklahoma? How do you get that down to the Permian Basin and over to New Mexico?

(35:31):

So there's a lot of work going on in SBP territory and as we look out our window, we can see those lines going up and that work starting as it is, but that congestion affects us. And so we are in the process of building what's going to end up being anywhere from a hundred to a $200 million west side transmission loop about a little over 30 miles of 345 kv transmission lines, double circuit to provide that reliability and manage that congestion. That will become an issue in 2027. So why the long range of between a hundred and 200 million? We may be partnering with another utility to help us build that and share those assets or we may choose to go that alone. And that's another flexibility that comes up about municipal utilities. And that is we do have access to low cost financing in spite of what's happened in the last few days, but we will go that direction.

(36:27):

And the other part of his future growth, we have a lot of, as John really talked about really well, and that is we have AI and we have data centers knocking at our door all the time. We also look at how to manage that cost and the risk associated with what he called what I'll refer to as stranded assets. And I think that's what you were talking about, the stranded cost. If somebody wants you to build 300 megawatts worth of infrastructure, are they going to be around to cover that? So we have ways that we manage that. We'd love to talk about that. We have a bright future. The city's grown from 225,000 to 300,000 over the last 25 years. Student body at Texas Tech. Any red Raiders? Oh my gosh, it's quiet. Okay, I'll drop that one. There's one over there. Thank you for raising your hand. So the student body there has gone from 25,000 to 42,000, so a lot of growth, a lot of residential, and we're preparing for that future, but I just want to hand off that theme of it's about risk management and it's about thinking long-term and that's the perspective you're going to continue to get from municipalities. And with that, I'll hand it over to you, sir.

Paul Dyson (37:37):

Sure. So I'm here to give the credit perspective on what all this growth in Texas means for utilities S&P Global ratings maintains ratings on 25 not-for-profit electric utilities across ERCOT. And the median rating right now is right in the middle of the A category as we heard from others. And Harvey, one of the key challenges for electric utilities in the state in ERCOT is dealing with the grid's limited connectivity to other grids in states because during periods when demand approaches available supply either for one utility or ERCOT wide over reliance on real-time ERCOT market purchases could expose the utility to high energy prices and or energy price volatility sometimes for an extended period of time. And we all know that financial volatility is negative for credit quality. So for utilities that are experiencing growing loads from a credit perspective, if we look favorably on those that are forward-looking and proactive, just like Harvey was saying, when it comes to power supply planning and that has to do whether it be for building generation or buying generation, winter storm murie provided some very available lessons here, additive extreme level and many of the electric utilities rate in ERCOT are dealing with growing loads and have already or are planning to significantly increase contracted or own power supply to meet this growth.

(39:03):

I think it would be best to go through a couple of examples to illustrate how this relates to credit quality and just go through a couple examples to see what happened. One of the utilities you rate is a generation and transmission cooperative in northeast Texas called Rayburn Country Electric Cooperative. That cooperative experienced 900 million in unbudgeted costs as a result of winter storm Yuri in 2021, where peak demand was 40% above projected load for an extended period of time and that caused it to be 55% short on energy. Since Rayburn was not able to pay its large ERCOT bill on time, the rating fell to as low as triple C until they were able to successfully securitize the costs and pay ERCOT. At which point we raised the rating up to triple B minus a couple years later. In June, 2023, Rayburn acquired a very large natural gas fired plant called the Panda Sherman Power Plant, and we raised the rating one notch because of that to triple B and we cited reduced operating and financial risks giving significantly lower exposure to volatile energy prices associated with historical short-term market power purchases and likely improved reliability.

(40:22):

The acquired gas plant put Rayburn in a more comfortable surplus position where it could take advantage of wholesale energy sales and meet its expected heavy load growth from its distribution cooperative members that it serves. Another example is CPS energy in San Antonio, which is a AA minus credit that has taken significant actions to bolster its power supply given extremely strong growth in the expectation that this growth will continue for the foreseeable future. CPS energy is experiencing residential growth of about 30,000 new accounts per year. That's basically like adding a new city every year. In May of last year, CPS energy acquired four large gas fired plants that were already running so existing generation in south Texas and the total megawatts was about 1700 according to management's analysis. Purchase of these plants provided significant cost savings versus other options that were including building new assets. Also, it reduced construction and inflation risks and enhances overall system reliability.

(41:32):

We said in our rating report that we believe these recent additions significantly reduced exposure to high ERCOT market prices and also increased potential opportunities to take advantage of the wholesale market. The acquisition also puts CPS energy in an even greater forecast surplus position versus its peak demand and they now have total resources of about 9,500 megawatts. And of that 9,500, about 8,000 is firm generation, not intermittent renewables. And so that 8,000 is available to meet their peak demand of about 5,800. So quite a comfortable cushion and good reserve margin. But keep in mind that buying major generation plants like those that San Antonio did, CPS energy as well as Rayburn is not for every utility. Some of the smaller, less sophisticated utilities out there that lack plant operating experience might be better suited entering into purchase power agreements. It really depends on the situation. Sometimes when you acquire a gas plant, you're able to also bring on the staff that is actually running the plant. So that might be one exception, but either way, from credit perspective, we look at management teams that are proactive forward looking because that is much more supportive for credit quality. And it's not just generation planning, it's also having sufficient transmission capacity to bring in the energy to meet growing load because that's the other huge piece of the puzzle and that outline has to come first.

Greg Dawley (43:10):

Paul, thanks. We have about five minutes left. I want to cover two topics from the panel. Maybe we have time for a question or two. One is Barry, you over at the Capitol yesterday. You're going today, what's going on with Texas in terms of energy legislation?

 Barry Smitherman (43:23):

Quite a bit, actually. This is really the third session post winter storm murie that electricity and power generation remains a topic in the 23 session. They created the Texas Energy Fund, which has been referred to already that was voted on by the voters of Texas, $10 billion, five of which has been appropriated for low interest loans for thermal dispatchable generation. So we'll see how that develops going forward. There's supposedly another 5 billion of appropriation to top that up to 10. And it's just a question of who remains in the fund, how quickly they can get their units built and operating perhaps equally important. There's a gigantic transmission project that's going forward. Transmission can be a substitute for generation in many ways. Harvey, my colleagues and I at the PUC we're the architects of the crest, so you're welcome for that investment that was made in the panhandle of Texas, which would not have been made but forres, now we're looking at something that's really CREs 2.O.

(44:31):

It's called the Permian Basin Reliability Plan. It'll be either 345 KV or 765 KV transmission from the basin into the at 35 corridor. Price tag on that is about $15 billion. There's a phase two and three which expands east, north and south into all of ERCOT. That is going to cost 33 billion. So Texas is taking steps, Greg, on both the generation and transmission side to bring assets online in order to meet this incredible growth. At the same time, there is some, I'll call it not favorable legislation against renewables over at the capitol and against batteries, and we'll have to see how that all sorts itself out.

Greg Dawley (45:20):

Last thing, Barry, you had mentioned geothermal because this is a technology that's not really been used in Texas very much, but it's more common on the west coast.

 Barry Smitherman (45:28):

Yeah, we're beginning to see great progress with geothermal. It's a really simple concept. We drill a hole down the hot rock and we flow water across it to make steam. We bring it up and drive a turbine to make electricity. In fact, Austin Energy has announced a five megawatt project that they'll be doing in East Texas drilling down to about 13,000 feet generating steam to make electricity. That's an exciting development. We're also seeing geothermal technologies being used as underground storage. So think about the opposite of pumped hydro or compressed air storage. We can compress water underground, use the qualities of the earth to add pressure, turn it on during periods of electricity, scarcity, run it through a Peloton turbine to make electricity. So there's a lot of developments going on. It's included in some of the energy objectives of Trump administration. It is consistent, of course, with drill, baby drill. So we think the future really is quite bright for the geothermal industry.

Greg Dawley (46:31):

All right. Any questions from the audience at all?

Audience Member 1 (46:38):

One question mic. How impactful do you see anyone from the panel power storage, battery storage being in terms of controlling the cost and meeting the demand for energy?

 Barry Smitherman (46:57):

Yeah, I hit that real quick. So there's about 14 gigs of battery storage and ERCOT right now. There's another 10 or so in the interconnection queue. So people are excited and optimistic about batteries. Unfortunately, there's some legislation percolating around which would require them to permit and do a number of other things, which could affect their ability to locate just about everywhere they want to. We still need to get past this point of the discharge only being 4, 5, 6, 7 hours. We need to get to the point where we can discharge over a day, two days, three days before it really solves the problem of storing winded solar and releasing it when those two generation resources are not available.

Greg Dawley (47:42):

Any other questions?

Audience Member 2 (47:52):

Thank you. Harvey and Paul, you did speak a lot about different risks being factored in, and I know that in Texas there's a lot of climate risk, like extreme heat, winter storms, and it's projected to even increase. So how is climate race being affected in grid planning and infrastructure resilience?

Greg Dawley (48:13):

Yeah, want that question is a question about climate change. I'm trying to,

Audience Member 2 (48:25):

How is we are experiencing a lot of extreme heat and winter storms and it's projected to increase, right? So I'm just trying to understand it is putting a lot of strain on an already stressed system. So how is it being factored in planning?

Greg Dawley (48:42):

So I think it's a question about the extreme weather on the transmission in the energy system. So Harvey, you want to take that?

Harvey Hall (48:49):

Sure. I think it's a great question and that is how does climate achievement affect it? And I think even John mentioned that the average temperature expected the, from 1990 all the way up until what we're going to be looking at is going to be going up. So more volatile, I guess I use the word volatile. So fluctuating temperatures. So what's normal, what becomes a normal pattern? There's now becoming a new normal for that. And I think it just stresses the need for, and one of the biggest consumption consumers of, and even in data centers is going to be HVAC. So heating, ventilation and air conditioning. So that's going to be a big use. So you need to have the resources to do that. You need to have the transmission resources to do that. Heat causes heat reduces the capacity carrying capacity for transmission lines. So there's only so much you can carry.

(49:42):

So there is some constraint on that. I think you just have to look at those factors. As an electric utility, we have to look at reliability and the ability to meet that need. So I think in the planning of it, I think you take that into consideration in your capacity. And these projects that they're looking at, they do look at that on the finance side, we see the numbers that come across, but on the engineering side, they're into those level of details and how to be able to make sure you can meet that load at whatever it is. Because understand an infrastructure, electric infrastructure is sized to the greatest possible usage and not to the average usage. So you've got to take into consideration of those types of fluctuations. But great question.

Greg Dawley (50:22):

So as I said at the beginning, we only actually got through half of our pre-prepared topics. This is a very complex interwoven area to discuss and so I appreciate our panelists here today joining us. And thanks for everyone for attending. We appreciate it. Thanks to the Bond Buyer