Rayburn Electric Cooperative broke ground in June on a 570 MW gas plant in Sherman, backed by a $411 million Texas Energy Fund loan at 3 percent, the fund’s seventh generation loan and first to a cooperative.
Rayburn is also putting batteries in members’ houses. Both run on the same logic: Rayburn generates the power and owns the transmission, so it earns on both. An independent power producer earns on energy alone.
On this week’s Energy Capital Podcast, Matt Boms talks with Christian Nagel, senior director of power supply and production at Rayburn.
Home batteries as a transmission asset. Texas allocates transmission costs on four summer peaks, so discharging batteries then cuts Rayburn’s bill, worth more, Nagel says, than the energy.
Telling real load from speculative. Rayburn screened data centers with its own questionnaire before ERCOT standardized one. Abbott’s audit has since pushed ERCOT’s Batch Zero study past April 2027.
Plus: the 12CP fight and what comes after gas.
Whether Rayburn is a model or a special case turns on rules the PUCT has not written.
Chapters
00:00 – Introduction
01:36 – Wind development and the landowner conversation
06:02 – The video that went viral
08:17 – Using your service to open doors
10:23 – The Atlantic Council years
12:19 – Her graduate research on energy and national security
14:44 – From Annapolis to flying Growlers
19:54 – Grounded, and the move to cryptologic warfare
23:59 – Why veterans run down their own service
30:08 – Advice for veterans trying to get into energy
32:56 – How to plug into Project Vanguard
34:49 – Closing thoughts
Resources
People & Organizations
Company & Industry News
Rayburn Energy Station: A Cooperative’s Answer to Texas-Sized Risk
ERCOT aims to complete Texas governor’s data center audit by December
El Paso Electric and Base Power install first home battery under new reliability pilot
Books, Articles & Filings Discussed
Governor Abbott Announces Texas Energy Fund Loan For 570 MW North Texas Natural Gas Power Plant
Rayburn Electric Cooperative Breaks Ground on Rayburn Energy Station II
PUCT Project No. 58000 - Transmission cost allocation and the 12CP proposal
Related Podcasts by Energy Capital
Related Posts by Texas Energy & Power
Transcript
Matt Boms: Welcome, everyone. We’re here today with Christian Nagel. He is Senior Director of Power Supply and Production at Rayburn Electric Cooperative, where he oversees power supply strategy, generation planning, load forecasting, risk management, and participation in ERCOT. Before joining Rayburn, Christian held several trading and management roles at ACES, ultimately serving as Portfolio Director for ERCOT and SPP.
He began his career as a commodities trader and holds a degree in public finance and economics from Indiana University. Christian, thanks so much for joining us today.
Christian Nagel: Yeah. Thanks so much for having me.
Matt Boms: Well, I want to start by giving folks an introduction to Rayburn, and maybe for a listener who has never encountered a generation and transmission cooperative, what is Rayburn and what does it do?
Christian Nagel: Yeah. So we’re a generation and transmission cooperative, and really what that means is collectively with our distribution cooperatives, we are a vertically integrated utility within a mostly deregulated market. What sets us apart, I think, is that structure. And so Rayburn, as the G&T, we’re focused on the wholesale side of things, so we’re going to be managing all the ERCOT exposure for our members, all the power supply for them that’s on the grid scale, of course, and then transmission.
And so our members are then charged with the retail side and the distribution side of things. So collectively, you know, a vertically integrated utility within a deregulated market.
Matt Boms: It’s such an interesting setup, and we’re gonna get into the differences there between a co-op like Rayburn and the other utilities that are not vertically integrated, but we’ll get to that in a second.
For now, I wanted to stick with the Rayburn story and ask you more about Rayburn’s members and how is the membership model there different within a co-op like Rayburn compared to those IOUs that we were talking about?
Christian Nagel: Sure. Yeah. So we’re very community oriented, right? Because the members that we serve live in the communities that we serve.
And so we’re a nonprofit, of course, so all margins that are made, that’s what we call them in the co-op space, are returned to our members ultimately. So really our focus is 100 percent on member services, member benefits. So there’s no equity or no shareholders to be concerned with. So the community aspect is huge.
And, you know, with Rayburn, we do have a very collaborative and great relationship with our distribution co-ops, so I think that really plays well into our ability to be agile, versatile, and innovative at the end of the day.
Matt Boms: Absolutely. And for you personally, how did you end up at Rayburn? Like, I love talking about folks’ origin stories before we get into the energy, the tough energy topics, so-
Christian Nagel: Yeah.
Matt Boms: how did you go from being a commodities trader to finding yourself in this role?
Christian Nagel: I think it definitely was not the trajectory I thought I would take coming out of college. It was actually during the financial collapse of ‘08, ‘09. And really it came down to work ethic and being, you know, a hustler in terms of like showing that I was willing to go a step above everybody else, I think.
So, I started actually with internships just after my senior year of high school in Chicago. And so, you know, when you’re that young and cutting your teeth in that regards, really just efforts most of it, right? Showing dedication. So I would take a 4:45 AM train from Northwest Indiana, where I grew up, around Lake Michigan to Chicago that summer, and I think that’s really what set me above others in terms of especially coming out of a not-so-great financial situation in job market upon graduating high school, rather.
But then what really got me to the energy industry was just the fact that at the time, I was looking to maybe get out of the Chicago market and saw that there were some trading opportunities at ACES, and that’s really what got me into it. So the transition from more speculative trading and commodity trading to really just electricity and pure focus on energy.
And then I just sort of worked my way up from there, became more of a consultant role within ACES, and Rayburn was a client of ours at the time, and so really what led me to Rayburn was Winter Storm Uri. So following that event, got a call from the CEO about his interest in me helping to start a power supply group here at Rayburn, and that’s really my entry into it.
Matt Boms: That’s awesome. And I love what you said at the top because that’s what I tell young people who might be listening to this podcast is, you might be smart, but there’s a lot of smart people out there, and ultimately what separates you is your work ethic and how dedicated you are to your career. So I love that.
That explains where you are today, Christian. So one more question about your background. What did you learn when you were at the trading desk that still shapes the way you evaluate physical assets today?
Christian Nagel: Yeah. I think going back to the prop trading experience I had in Chicago, I always mention that even though it is a little step change, I guess, from where I’m at today, which is very much risk management, risk aversion type of setup with electrical utility, basically, right, a co-op.
But that gave me a great foundation for risk mitigation and really unique understanding of risk. And so when you’re kinda tasked with trading, right, you’re really kind of at the front lines of managing risks, right? You could be, whether you’re a trading desk that’s hour to hour or whether you’re looking longer term, right, you’re focused on kind of the frontline mitigation of risk, and that’s where contingencies happen in the real world.
You’re kind of there to make sure those risks are mitigated right up front.
Matt Boms: Amazing. So you get to Rayburn, and this is a very unique cooperative. My understanding is that Rayburn was created because a group of co-ops decided to challenge what looked like the default path for the industry. Can you talk to us a little bit more about the origin story there, and how does that still show up in the organization?
Christian Nagel: Yeah, I think it boils down to one of the quotes our, CEO always says, which is, “Status quo is not company policy.” And I think status quo, going back well before I was even born in ‘79 when Rayburn was formed by our cooperatives, I think the status quo probably would have been to go down that path, but that wasn’t the choice that the board at the time took.
And so they decided to form Rayburn and really kinda go about it in their own way as opposed to joining that alliance back then.
Matt Boms: And when Rayburn moved from contracting for power to owning major generation assets, what changed strategically? Like, what was behind that change in your mind?
Christian Nagel: Yeah. So it kinda started with our first entry into owning generation.
That was Freestone Energy Center, and that was in 2010 when Rayburn was still, I would say, considered mostly a paper G&T. We basically, even though we’re responsible for the power supply on the wholesale side for our members, we were contracting, you know, multi-year contracts with providers for that requirement service.
And so when we purchased a minority stake in Freestone Energy Center with Calpine, that was sort of our first entry point into it. So that gets us through the decade of the two twenty tens, right? And at that time, you know, ERCOT was putting in a lot of wind, and there was a lot of downward pressure on wholesale pricing, at least the, you know, the marginal pricing.
What Rayburn actually does, even though we’re not in the competitive space of ERCOT, we definitely track what the competitive market’s doing and use that as a benchmark to how well we are doing. And so Rayburn looks at it from the wholesale side, of course. So really we’re looking at all transmission costs and power supply plus our overhead combined.
What does that translate into in terms of a wholesale rate to our members, right? And then we take that wholesale rate, and we compare it to, you know, what is the average, like, 12-month Oncor rate, for instance. That’s the competitive spa— you know, area of North Texas. And so that difference between what the retail rate is and what our wholesale price is essentially what our members have to work with to remain competitive. Right?
And so you’re looking at a timeframe where there was downward pressure on pricing in the 2010s with a lot of renewables coming onto the system. Really outside of 2011, there were not very many blips in terms of severe weather. Of course, you’re gonna get the occasional hot summer or occasional winter storm, but really nothing to speak of in that pretty much decade between 2011 and Winter Storm Uri.
Really in the late 2010s is kind of what got us away from, I guess, the paper G&T model because we started to see that headroom shrink in what I was talking about between the wholesale price and the retail price. So basically that wiggle room that our members had to work with on the retail side started to shrink down.
So that’s when Rayburn start- decided to kind of go about it independently in terms of our power supply. We got out of those four requirements contracts, and then we started to manage our own supply. Now, getting back to your question about when did we decide to go from more contracted power to own generation, really that was Winter Storm Uri, right?
Because ultimately, we decided after Winter Storm Uri that the best way to kind of be in more control of your destiny is to actually have steel on the ground that you can control as opposed to leaning more on the market. So that’s really the difference in when we went from more of a, I know that’s long-winded, but paper G&T to contract, mostly contract only to an actual strategy change to owning our own generation.
Matt Boms: It’s a great answer. And for a lot of guests that we’ve had on this podcast, Winter Storm Uri was really a line in the sand, and there’s a pre- and a post-Uri. It’s really interesting hearing that from co-op and how that changed your perspective as far as steel on the ground within your territory. I wanted to ask you about the member model because as someone who runs a trade association, I can relate to having a lot of different members and a lot of different cooks in the kitchen.
How do you get all four member cooperatives to agree on different strategic decisions that you make? Some of them have different load shapes or maybe different views in the strategy that Rayburn should be adopting. So what does that process look like? That sounds like a really complicated and difficult job.
Christian Nagel: It can be. I will say we do only have four members, so that is something that is going for us. It really comes back to the way we set up our tariff with them. So we actually have a subscription-based model on power supply for our members, meaning that our members are allowed to basically come up with, in conjunction with us, a bespoke or customized power supply plan.
Of course, when it comes to the larger transactions that we’ve done and actual long-term investments, such as acquiring or building a power plant, that’s when it certainly becomes more of a challenge if we don’t have unanimous board support. But technically, as long as Rayburn has 100 percent backing by whether it’s one, two, or all four members on long-term investments, we can go ahead and move forward with those power supply acquisitions or development projects.
As it turns out, all the members were in unison when it came to Rayburn Energy Station and wanting to move forward with the acquisition of that following Winter Storm Uri.
Matt Boms: That’s great. And does the model mean that you can move faster than other utilities, or does the consensus become a limiting factor for the decisions that you’re making?
Christian Nagel: So far, it hasn’t been a challenge for us, right? I think we’ve been agile. I think, you know, I’ll speak to how quickly we did do the Rayburn Energy Station, the former Panda Power Plant up in Sherman acquisition. I mean, we were competing with a lot of private equity firms, right? And I’m not sure who all the suitors were for that plant, but certainly the fact that the cooperative pursuing that, you know, was able to stand up against those private equity firms and come out on top, I think speaks to how well we’re able to sort of get our ducks in a row at the time and come up with a great strategy in terms of how we went about the bidding process.
I’ll speak to the, it’s kind of the agility side and how quickly we move. Really, it’s what, you know, we- surprised we got this far into the podcast without mentioning data centers, but obviously there’s quite a bit of change happening right now as it relates to the data center front. But I can say that we’ve been working with several data centers and their consultants and, you know, they speak extremely highly of the way that we approach things as a cooperative, as opposed to, I think, a more rigid approach in terms of deregulated part, simply because it’s kind of all under one roof, right?
You’ve got the interconnecting entities, Rayburn, the power supply provider would be Rayburn, and the transmission provider would be Rayburn. So all that under one roof, and the fact that we, I guess, are a little bit, you know, quite a bit smaller than like an Oncor, very member-oriented in the way we approach our business is really, I think, what sets us apart, allows us to move much more quickly.
I think, you know, we’re definitely, again, oriented to be able to stop, get on the phone at a moment’s notice with these types of customers and members, and I think that’s really what sets us apart from the other models.
Matt Boms: No question. And we’re gonna get to data centers. Don’t worry. We- I got a bunch of questions on data centers and large loads for you.
When you’re planning the trade-off between near-term affordability and long-term reliability, can you walk us through what that looks like just from a day-to-day standpoint in how you make those decisions?
Christian Nagel: It’s definitely a huge trade-off, right? And you’re seeing sort of a disconnect happen right now in what’s happening since summer of 2023, right?
We’re setting record after record in the ERCOT market load records as we speak this summer with how hot it is. And you’re not seeing that materializing pricing, right? So you make a long-term decision to invest more and having steel in the ground, you’re definitely gonna have to make sure that you’re poised to mitigate years where that is more of a challenge, and the spot market is obviously where you’d like to be in situations like that.
That’s also the benefit of having newer technology, relatively newer technology, and really dispatchable power. You can call on that power when you really need it. But then you can also lean more on the spot market during times when there’s a lot of renewable penetration, ‘cause we continue to see that grow.
I know I mentioned wind when I was talking more about our power supply strategy shifts, but obviously solar is now the new thing in town, and then you’ve got also the amount of batteries that are on the system. So all those things working in conjunction together have really suppressed the price volatility in the markets.
The strategy still for us, looking long term, understanding that there’s gonna be ebbs and flows, and it’s not always gonna be our preference to have our own generation actually online around the clock to fill our load. And that’s where the- I think that it dovetails well with the energy-only market in ERCOT.
Matt Boms: It absolutely does. Well, let’s start getting into data centers. I wanna start with the load forecasting question because in light of Governor Abbott’s audit of data centers that has recently come down, I wanna ask you from the utility perspective, how much confidence can any utility place in a 10-year load forecast today, given all the fluctuations and all the changes that we’re seeing almost on a daily basis?
Christian Nagel: Yeah. The data centers just turned this whole world upside down in terms of load forecasting. I try to focus more on what we have direct control over and manage around that. So certainly when I’m looking at our data center queue, I’m able to have much more insight into what’s real versus what’s not, right?
When I look at that globally across ERCOT, you know, you can tend to get a little bit biased, right? Because I don’t know exactly once the Batch Zero process finally moves forward, what that number’s ultimately gonna look like. But I do know that for us, it’s looking very likely that we’re gonna see at least a doubling, if not a tripling of our actual peak load.
And then of course, I hadn’t touched on this yet, but we’re basically 90 percent residential in the makeup of our current membership, right? So because of that, there’s a lot of weather sensitivity, risk mitigation that we have to put into place. But the load factor of our actual load is low, relatively, because of how much weather sensitivity plays a part.
We don’t have a ton of base load, industrial or large commercial right now. The data center influx is really going to change that quite a bit for us. And so I think it comes down to what we can control, following along with sort of the goalposts as they move within the regulatory framework, and then just managing around that.
Matt Boms: Sure. And I think the utilities themselves have their own goalposts, right? So does Rayburn have its own criteria of, like, what makes large load real enough for you to plan around?
Christian Nagel: We’ve actually- We’re a little bit, in front of this. It’s becoming a lot more standardized now, but our engineering and transmission team, because of the, ultimately the interconnecting end, you know, from day one kind of had a questionnaire that they’ve used to kind of vet the veracity of these data centers from day one. And we’re very risk-averse, right?
We wanna make sure that these data centers, as they approach us, we’re definitely open to serving them, but we wanna make sure that they’re not gonna do any harm to our existing membership, right? Which again, is largely residential. So that questionnaire and that process really was our first way to vet how serious the data center was.
And it did come down to certain things like, have they actually gotten an engineering design done? Do they actually know, have they secured equipment? What type of equipment have they secured? Are they willing to upfront pay for the interconnection studies, right? Because really how our model works on the interconnection side, which I don’t think is that different from others, we’re not gonna float that risk on our balance sheet.
So we’re gonna make them pay for the interconnection studies. We’re gonna make them, once we get to the point of procuring long lead time items and the supply chain criticality there, we make them post financial security to that level so that as we’re going through the interconnection process from point A to point Z, we’re not at any time really holding the bag on any of that risk.
Matt Boms: Mm-hmm.
So on that question, like neither you or I have any skin in the game on this, and I’m just wondering if we play the devil’s advocate here, is there a way that these data centers could help lower costs for your customers? Is there a universe where that’s possible?
Christian Nagel: Yeah. I think, again, the what we can control is our tariff and the way we do rate design around these data centers.
We’re still working through that because, again, the rules are being set, and we have to make sure that we’re playing within those guardrails of how that’s gonna work. But in how we’ve structured these agreements up front, just us in a bubble, it should lower our members’ rates, or at least, I guess, stave off any increase in rates, so to say.
Now, what we can’t control, but we certainly are following along with, is, you know, kinda what’s happening on the regulatory front. So a big thing right now has been the transmission cost allocation approach that the PUCT and the legislature is trying to really undertake right now with the stakeholders.
So we’re definitely really keen on what’s happening there because that’s ultimately gonna decide, I think, how that approach is set, this large influx of load. Like, how does it actually impact the current ratepayer in Texas?
Matt Boms: Absolutely. I’m so happy you raised that rulemaking because it’s something I’ve been thinking a lot about, and to the extent that these data centers are flexible, and there’s a question mark there, you would want them to help out when we have some grid stress in Texas.
And for whatever faults there are in 4CP, and there are many faults with 4CP, it’s still the most effective form of demand response we have, right, as of today. So my concern is, if you just look at it from, like, a grid reliability standpoint, do you wanna remove the most effective tool that you have in the shed if you’re putting that flexibility at risk and saying, you know, maybe it’s not worth it for a data center to move to their backup power, right?
If we’re saying that there’s gonna be some minimum demand charges, the rule is still evolving. We don’t know what the final rule is gonna look like. But I guess this is an open question for you, Christian, as far as where is the balance? Like, you want these data centers to bring their own backup power and hopefully provide some flexibility to the grid.
That’s the ultimate goal here.
Christian Nagel: Right. It’s a very complex problem to solve, so I’ll put that out there up front, right? Because you have the enormous amount of investment that it’s gonna take to interconnect these data centers on one side. As you said, you want to have an incentive for demand response or some sort of grid flexibility, load flexibility to be there such that they are not adding to the stress of the grid at the most critical times, at least one for one.
But at the same time, if you go down that path and you think about what that actually does to private investment, right? If you’re backfilling everything you’re adding with required generation, you know, how does that impact downstreams the investment? And especially in the energy-only market where there’s not a capacity payment stream for private investment to have.
So that’s sort of like it’s a double-edged sword, right? Because you solve one problem and it’s kinda like a whack-a-mole. You solve one problem and then all of a sudden another problem’s gonna pop up. So it’s very complex problem to solve. I think load flexibility is key though, because we’re not gonna be able to snap our fingers and just add...
Let’s say we add 100 GW of load in the next five years, six years. I’m just throwing that number out there. There’s no way you’re gonna add 100 GW of supply within that same timeframe, right? You’re seeing what turbine lead times are from the major OEMs of these, gas turbines. And again, there’s also downstream effects to having a concentration in gas like that you can’t solve at all with simply a supply.
So I think load flexibility is key. I mean, we’re following along with some of the technologies that are happening in load flexibility. Emerald AI is a startup you may have heard of and some of the listeners may have heard of, but certainly they’re able to demonstrate some load shifting, and I hope that there’s further advances in that sort of technology because I do think that’ll really help bridge the gap.
Matt Boms: I agree with you, and we could spend another hour on data centers, so I’ll move off of it. But I agree with your main point, and you don’t want either extreme, right? So you don’t want all of these data centers just powering themselves essentially and not connecting to the grid, because then they’re not paying for the grid that we already have.
But then you don’t want the other extreme, which is none of them have backup power, and then none of them are flexible when we need them to be. So the idea is to get somewhere in the middle of those two. But I think probably neither of us has the solution, and we also don’t have the crystal ball ‘cause, you know, a year from now, who knows what the policy will look like.
This is all kind of unraveling in front of our eyes.
Christian Nagel: Yeah. It’s a very fluid situation. I think-
Matt Boms: Yeah...
Christian Nagel: obviously uncertainty’s a huge disruptor of progress, but I also understand that, again, I can’t speak to how important it is that from a policy standpoint, things get done right, because otherwise I think most people are in the policy front are focused on the impacts to the ratepayers.
And so I think that the pause here is, certainly warranted given the implications of the infrastructure build-out, and if it’s not done right and the incentives aren’t done right, then what the downstream impacts would be to the actual ratepayer in Texas.
Matt Boms: Yeah. Absolutely. Well, let’s talk distributed resources.
I know you mentioned that Rayburn is predominantly residential. I wanna know what value Rayburn sees in DERs for its residential customers, and how can that become a meaningful portfolio resource for y’all?
Christian Nagel: Yes. We’ve been going down this path for about three and a half years now in DERs. I will say the adoption rate has not taken off the way I thought it would, but we’ve learned a lot along the way, and I think it’s hitting a critical point, as I mentioned before, with the amount of load growth that we’re seeing actually hit not just Texas, but the entire US as a whole. There’s not a one solution fits all, right?
There’s no one panacea that’s gonna solve this entire problem. So DERs, I think, are in a good position right now to actually increase their adoption rate. Also, to mention, I think one of the other hurdles with DERs was just how expensive they were relative to grid scale technologies. And with how much those have gone up in cost, it’s certainly starting to converge on a good opportunity for DERs.
So Rayburn actually started with, I would say, low-hanging fruit here. Again, it makes sense. Don’t solve all the world’s problems on the first crack, right? But we started off with home standby units because a lot of these home standby units were installed following Winter Storm Uri, and really the work from home aspect that we saw following, COVID in our service territory.
So we knew of thousands of Generacs and other types of home standby units that were installed. So that was sort of our first entry point into it. I guess I would say, you know, one of our members here, Farmers Electric, they’ve been very pivotal in us investing in DERs and going down this path, so we certainly wouldn’t be to where we are today without their dedication to it.
They’ve had a thermostat program, Nest thermostat program for time, I guess, preceding this three-year time right now, just kind of spelled out. But that’s more passive, right? Really focused on more home, all home solutions is kind of our next strategy. So we started off with Generacs in that program, and ultimately it ended up being during the summer of 2023, so that was not a bad time to start because you saw high energy prices.
You know, what we found with home generators, they’re very dispatchable, but they also have a very high marginal fuel cost, right? Because you’re not talking about grid scale fuel, you’re talking about residential distribution level fuel costs. The marginal cost is high, but that gets back to our business model as a essentially a vertically integrated utility.
We’re able to see the benefits not just from the energy side, we’re able to see the benefits on really the most valuable aspect of DER right now, at least in my view, which is on the transmission cost side. So we’re able to deploy these assets during the peak times for coincident peak, which, you know, is evidently on its way toward the 12CP.
And so that strategy has worked out well for us. The end of last year, we started to look more at batteries, and we were kind of looking for our entry point there. We’ve talked with a lot of the major battery manufacturers, and we still have discussions going on with them, but we started to focus in with our member Farmers on Base Power.
And so we did launch a program with Base Power at the beginning of the year, and it’s so far been a huge success for us. Because of the fact that we are in the non-competitive areas, we had to structure it slightly differently than how Base Power is normal business model works. That’s a good benefit for us, right?
Because that allows Rayburn and our members to be more in the driver’s seat. It also allows for us to divest of any of the installation and maintenance and that side of thing, because that’s something that Base Power still wears the hat on. The batteries are much more deployable, I would say, from a utility perspective and from a grid solutions perspective so far than what we found the home standby units to be.
Matt Boms: And really a disrupting technology because they’re also working with El Paso Electric and have found success with this model specifically, right? In the vertically integrated utilities, it tends to work out really well. In the competitive areas as well, it’s just a different business model like you mentioned.
Where do you see that moving forward, Christian? Like, over the next few years, considering all the load growth that’s coming, do you see that DERs could help defer more transmission and distribution, especially distribution costs, right? Because a lot of this is, I imagine, translating into distribution savings for Rayburn, right?
If you know that a substation will be overloaded in the next five years, then maybe DERs could help with some of that stress.
Christian Nagel: Yeah, they certainly could. I hadn’t mentioned this yet, and I’m surprised I haven’t gotten to it, but with how fast we are growing just organically, we know we mentioned data centers and how much that’s certainly gonna change our world.
We’ve been at sort of the forefront of some of the most aggressive organic growth, I would say, across the country here in Rayburn, in our territory. Just for some perspective, the last nine years, 2017 through 2025, we’ve had a aggregate growth rate of almost 60 percent across our membership.
These aren’t small distribution co-ops to begin with, right? These are 500 to 600 MW peaking distribution co-ops. So that amount of growth, you mean a CAGR of 5.5 to 6 percent on average across that entire timeframe, you know, that in and of itself has had us— you know, led us to down a path of just constant substation adds and adding resiliency to the distribution system and to the transmission system within what we can control.
So it hasn’t quite yet translated into any sort of direct investment savings and upgrade savings like that. But I will say that with how quickly we’re seeing Base Power scale the program that we’re in, success story for me really looks like that scaling of that continuing within Farmers Electric and then we, you know, adding that to other distribution co-ops that we serve.
That in and of itself, that peaks shaving attribute and really that shorter duration battery deployment to kind of complement the more resilient, longer duration, more dispatchable technologies that we’ve current already invested on the utility scale side, I think that’s really gonna help us be a lot more diversified and a lot more versatile.
Matt Boms: Yeah, certainly for a vertically integrated utility, it makes a ton of sense because all the incentives are aligned there, right? Like it’s a no-brainer. It’s a little harder in the areas that are competitive and you don’t have utilities that are vertically integrated. That’s for another podcast, but it’s just good to hear that Rayburn is moving forward with these technologies, and ultimately it’s just about saving money for your members, so that’s great to hear.
Christian Nagel: Yeah. And again, the scalability’s been huge because ultimately the DERs, they’re just one home at a time, right? At least from our perspective. But the way that we— that Base Power and Farmers have worked together to, scale these at the distribution level’s been really quite impressive. And when you look about it— when you think about it over a timeline of otherwise choosing utility scale batteries, at the rate they’re going, by the time you get through the study process, the interconnection study process, you order the equipment, transformers, things that are multi-year lead times, I mean, I honestly think we’re gonna be scaling at, a comparative rate.
Then you add to it, like, you mentioned, that the vertically integrated benefit of transmission cost savings, it’s a, it’s a no-brainer to continue to scale that program for us.
Matt Boms: Yeah. If you add up all the megawatts, it’s pretty astounding what’s going on in Texas right now, right? And it’s easy to see in 5 to 10 years every home or business having battery attached to it, right?
So it’s pretty cool. I agree with you. It’s fun to see all this stuff getting deployed so quickly, especially in our state, ‘cause we’re just like, we’re known for speed. We do things quicker than other parts of the country. Well, I wanna talk Texas Energy Fund before we wrap up, because this was obviously a huge piece of legislation that passed back in 2023.
I know that Rayburn has been involved in the TEF, so I just wanted to give you a chance to talk about that and tell us what you’re building in Rayburn as part of the Texas Energy Fund.
Christian Nagel: Yeah. It starts a lot with our acquisition of Rayburn Energy Station. I know I mentioned that before, but I’ll maybe go a little bit deeper into that before getting to the new development project.
But so following Winter Storm Uri, we really took a strategic look at how we approach power supply. When I came on board in the summer of 2021, we just started looking at more dispatchable resources, and really, again, stealing the ground, being more in the driver’s seat of our power supply. And we looked at what types of resources performed well during Uri.
I know a lot of gas generation did not. A lot of that was due to, you know, improper potentially winterization, but a lot of it was just the actual gas supply itself. But Panda Sherman performed extremely well during Uri, and so when that came on the market at the end of 2022, we jumped on it. Again, it was a very competitive process with other private equity suitors. But we ultimately landed that and closed on that deal the first half of 2023, which was, you know, in hindsight, extremely well-timed with the summer we had that year.
But with how fast we’re growing organically, we had to start looking already, even after that major acquisition, right? It’s a 750 MW combined cycle. We already had to start looking ahead to what’s the next thing for us to do. And around that exact same time, right, they introduced that Texas Energy Fund in the legislature.
So we started on that process. We looked at what sort of technologies are deployable today, right? Number one, our board and Rayburn still were desiring a longer duration, more resilient types of technologies. And so that’s when we continued to focus on natural gas. But we had already a couple combined cycles where there were partial owner or fully owning in Rayburn Energy Station.
So we looked at diversifying, and so we came up with the solution of these Siemens SGT-800s. And so these are quick start, simple cycle gas turbines. A lot of synergies with RES today because it’s, first of all, it’s an add-on to the same site, so a lot of the infrastructure’s already in place at Rayburn Energy Station.
Control systems can speak the same, so our operators in the control room don’t have to learn new control systems. So a lot of those things really made sense for us to pursue this type of technology. Now comes the question of, is it feasible from a financial and rates stabilization side of things? And that’s really where the Texas Energy Fund fit into it.
So obviously, 3 percent rate on up to 60 percent of the cost of the project was huge. Initially, Rayburn actually had to work with the legislature to get some changes made to the way we were able to finance it. Really, that taking a step back, what that means, cooperatives, we finance it 100 percent with debt, right?
But the way the structure was at the time, the seniority of the Texas Energy Fund note had to be higher than supplemental debt we had to raise. So what we did was we worked with the legislature to allow for that to be all secured under our entire system, basically on even foot. Pari passu is the term for that.
I didn’t know that I would become fluent in Latin when I went down the endeavor of, working on this project, but you know, that’s the way things go. But we worked with PUCT, the consultants that they hired, and it was a two-year diligence project on this. We closed on the loan in June of this year.
Obviously, there’s going to be a lot of regulatory requirements when you’re getting a government loan. I think that’s a positive for the PUCT and for the state. It really was a rigorous process and very well vetted from the side of the PUCT and their consultants that they used to go through that diligence process.
So, you know, at the end of the day, I think that we’ll, we’re, you know, a 20-year note, 3 percent is really gonna end up, you know, putting us in a good position going forward with this project. So all in all, time will tell exactly how successful that project will be, but I certainly think we’re off to a good start just with the financing itself.
Matt Boms: Yeah, it sounds like it’s not a question of whether it will be successful, it’s just how successful will it be. And the criticism I remember back during that legislative session was that the barrier to more dispatchable generation was not necessarily a lack of access to capital in ERCOT. It was more supply chain issues, which I think are still true today.
But I can see how this is different because from the co-op perspective, the access to low interest capital was a really key, part of the decision for y’all, right? So it works a lot differently than in the competitive parts of Texas where these are just private investors coming to build their own gas plants.
So obviously they’ve got plenty of low interest capital that that’s not necessarily the barrier to growth.
Christian Nagel: Yeah. And honestly, we have a pretty low access to capital too. We’re investment grade rating. But I definitely s— the Texas Energy Fund in hindsight looking, it’s certainly more geared towards a util— a vertically integrated utility type model, and that’s why it fit us so well.
A lot of the IPPs, they look at returns on capital differently than we do. It’s just a different structure altogether. Again, we are looking for something that was dispatchable, something that looking ahead at our modeling and the way we perceive risk over here, looking for something that would stabilize and even lower our rate projections into the future.
From that perspective, the 3 percent note dovetailed with the lower cost of capital we had on the other 40 percent, and all in all, it really was
Matt Boms: I think a really exciting time for Rayburn, given all the different strategy decisions that you’ve walked us through today, Christian. Before we wrap it up, I wanna just hear your thoughts on where you go from here in an era of unprecedented load growth.
We talked about data centers. Where do you see Rayburn’s future, and what will be success for you over the next several years?
Christian Nagel: I think our main focus is still gonna be on member services, member benefits, and low stable rates. That’s really what’s driving us. We’re already looking ahead at next steps as it terms for power supply, whether that’s gonna be joint ventures with some of these data centers, and we’re certainly having discussions there on some opportunities.
Again, we’re mainly focused on what’s gonna add the most value for Rayburn, divesting ourselves from being tied to any type of technology. Again, we’re, gonna do what makes sense for us, what makes sense for our members, and what leads to the lowest rate possible for our members, but also understanding that with that, you have to have reliable solutions.
So we’re following along with a lot of the newer technologies. We’re not ready to dive in on them yet, SMRs, things like that. But I do think that what I mentioned earlier about there’s no one panacea to solve this load growth problem that we have, or I see it as an opportunity, honestly. You’re gonna have to look at all the above options.
You’re gonna have to be innovative, which is one of our core values, so that’s certainly something we’re gonna continue to march toward. And you have to look at, you know, what’s gonna ultimately lead to the most reliable low-cost power for our members long into the future.
Matt Boms: Absolutely. Well, huge credit to you and the leadership team at Rayburn.
It sounds like following Winter Storm Uri, you really took matters into your own hands and started building your own generation and coming up with new solutions to a really complicated problem. So just congrats and wishing you all the success moving forward.
Christian Nagel: Yeah. So thanks so much for having me on, Matt.
It really was a pleasure.
