Power Without the Panic

Intro (00:00):
Welcome to the Power Bytes Podcast, brought to you by Caterpillar Electric Power with your host, John Thomas. Each month we deliver the latest insights, trends, and cutting-edge tools to keep you ahead in the dynamic energy industry. Whether you're streamlining operations, embracing new technologies, or staying informed, Power Bytes is your go-to source. Join us as we explore innovation shaping the future and the resources you need to succeed. Welcome to Power Bytes, where energy meets innovation.

John Thomas (00:28):
Welcome listeners. On this episode of the Power Bytes Podcast, we're going to be talking about the energy landscape in Europe and what is pushing organizations in that area of the world to rethink risk – or mitigate risk. And today, we are joined by Tobias Wedemeier. And Tobias, how are you today?

Tobias Wedemeier (00:48):
Hi, John. I'm doing great. Thank you for having me here.

John Thomas (00:52):
As we get started here, just tell us a little bit about your background and a little bit about yourself.

Tobias Wedemeier (00:56):
I am leading the business development for Caterpillar Power division across Europe and Eurasia. I have had multiple job roles from R&D, in service, project management, product manager. And since about four years [ago], I'm in sales and now in business development. And [I've been] with Caterpillar about one decade.

John Thomas (01:17):
Tobias, for our listeners, where are you located? Where [are] your offices located today?

Tobias Wedemeier (01:22):
I'm located in the Manheim facility in the South of Germany. It's where we have production, R&D, and service for our gas product lines: the CG132, CG170B, and CG260 units. These are gensets from 400 kW up to 4.5 MW.

John Thomas (01:43):
Once again, thanks for joining us. I'm excited to talk a little bit today about the energy landscape in Europe. Could you tell us a little bit about some of the key issues in Europe's electricity landscape today that are fundamentally different compared to just a few years ago?

Tobias Wedemeier (01:58):
I would say a few years ago, the electricity production landscape in Europe was mostly conventional power plants, and it was just a [tiny bit] of variable renewables being served into the grid. In 2024 or 2025, we nearly achieved 50% renewable electricity penetration into the grid, and this has changed a lot [about] how we see electricity in Europe – how we see power in Europe. And you can say that there are about four trends. I touched on the variable renewables; that's a trend of the changing power generation, which is having a huge impact. But also on the power consumer side, we see three different trends, and they are just picking up right now. One is electrification of transportation. Then we have electrification of the heating sector, which is picking up quite faster now than the [unintelligible] vehicles because of the governmental subsidies of heat pumps for private households and also the goal of the district heating to be decarbonized until 2045.

(03:06):
Just to give you an understanding of the size, the German district heating needs to decarbonize 450,000 TWh [terawatt hours] per year until 2045. These are huge numbers! And the third trend is the data center trend, which is not at the beginning, so we are right in the middle of that right now. We can see that the urban areas where most of the data centers are located have [soaked] up all the grid capacity [that] was available, and we are getting more and more grid congestion. In the main capital cities – like Paris, London, Dublin, Frankfurt, Milan – we are facing a lot of permits pending to get DCs [data centers] on grid. And because of the grid congestion, there's delay in those permits, and we are facing more and more “island mode” requests for those data centers.

John Thomas (03:59):
You described a challenge there in the data center space, if I'm hearing you correctly, right? It's very similar to what we're seeing in North America. It's taking more time to get those data centers tied to the grid, and so therefore a lot of them are going [into] what we would call “island mode” (as you said), which means they're off-grid. They're not connected to the grid, so they're actually functioning without grid power. But as you think of those other three trends that you mentioned, what are some of the challenges of those trends?

Tobias Wedemeier (04:24):
Basically, it's that they all work together into the “wrong” direction. If we see the demand of electric vehicles or the electricity demands of heat pump for district heating or for private households, they all require the same huge amount of peak electricity during times when the production trend of the variable renewables is at its lowest production. One example in the summertime is: all day you have a lot of PV [photovoltaic] production, and then in the evening when people come home, they start charging their electric vehicle, they are starting the air conditioning, and then the sun is down. You can do a daily shift there with battery systems, for example. A much bigger problem is when you look at the wintertime. In the wintertime, you have lower PV production, much lower (like only one-quarter or one-tenth). Sometimes you have dark doldrums where you have two or three weeks [of] very little wind, or very little PV, and then you still need to heat up your home.

(05:27):
District heating needs to run, you still need to charge your electric vehicle, and of course [you] have the regular energy demand, which we have seen the last few decades. And then prices are skyrocketing. These effects are fundamentally changing the way electricity is priced in Europe. While in the past you had more steady, predictable pricing all over the years and in the next years to come, we [now] see that the price volatility is increasing drastically. In 10 to 20% of the hours of the year, you can have the cost of 50, 70% for the complete year. We see that the prices are “sparking.” And on the other hand, you can even have times of really low electricity prices, where you feed basically from the national grid, from renewable cheap production, to your energy demand. And then you pay very little, and it isn't worthwhile to produce your own energy because you get [such] cheap energy from the grid.

John Thomas (06:29):
You mentioned a couple of times there, Tobias, that there were energy-cost challenges. For the folks that might be unaware (in Europe or from other parts of the world), what are some of the primary drivers – in your mind – that [are] driving energy costs today in Europe?

Tobias Wedemeier (06:44):
Of course, the cost of the fossil fuels is rising up, then the variable renewables are producing really cheap electricity, but the infrastructure and the flexibility is not there. The base taxation of utilities for increasing the flexibility and increasing the infrastructure is driving up the costs by quite a significant margin. And then the governments all over Europe are [now] planning and got a green light from the European Union to establish new subsidies to back up the variable renewables. Just as an example, to illustrate that and make it a little bit more tangible: when we are going towards 80, 90, 100% of the electricity in Europe [being] generated by renewable energies, especially variable renewable energies, we need to have a backup for those in case of a dark doldrum. A dark doldrum in Europe happens every year, quite often.

(07:47):
Some are two years long, and studies show that every second year they are three weeks long. In this time, we would need a reserve of basically 50 to 100 TWh of electricity. How much backup do we have right now? It's [only] a few percentage [points] of that. We are talking about a tennis ball, which we have right now in our hand, but we are really looking for a basketball to solve the problem – to play the game.

John Thomas (08:12):
And when you say backup energy, for those that aren't familiar – you're backing up renewables. You're talking about backing them up with maybe traditional gensets that are dependent on fossil fuels like gas, natural gas, or diesel, correct?

Tobias Wedemeier (08:25):
That's one option. We have different [kinds] of backups. The daily backup is probably mostly driven by battery systems. They can do the daily shift. They are expensive in deployment, they don't produce electricity, but they can make the daily shift between high-variable renewable times and low-variable renewable times. Talking about gas-fired power plants in general (like gas gensets or gas turbines), they become basically the one and only technical solution for seasonal backup – like the dark doldrum, which I talked about. You have to imagine the capacity [that] you need to save seasonal backup in batteries would be equivalent to 700 million to 1.4 billion electric cars in Europe. Right now, we have 300 million cars in Europe. And I think every European citizen would agree that we don't want to have three to four times as many cars in Europe than we have right now, yeah?

(09:25):
We can see that the electrical storage is not there. Same is true for the hydro pumped storage. There, we would need to flood the Alps with water. The only technical, feasible solution would be flexible gas-fired power plants. They don't have to run only on natural gas. They can run on biomethane, which is CO₂ (mostly CO₂ nitro). They will be running on hydrogen as well, so they can also participate [in helping] our customers be more sustainable.

John Thomas (09:57):
You've alluded to customers attempting to reduce their emissions (or meet their environmental goals or sustainability goals), and you've alluded to that through the discussions on electrification of transportation and the use of heat pumps. As you're talking to customers that are attempting to attack that emissions or sustainability [issue] head on…Can you give us some examples of what some of your customers are doing to achieve goals in that area in Europe?

Tobias Wedemeier (10:28):
These four trends, which I was touching on right before, are mainly driven to decarbonize the transportation and the district heating sector, for example. And we have a really nice example from a district heating company, which is also a customer who had a good way to solve this. They were not only thinking of replacing their current natural resource fuel-fired district heating assets with electrical heat pumps to become more sustainable, but they also combined it to be more flexible in the future with [combined heat and power] CHP power plants from us. The concept is that you have, for the gross of the heat [that] you are serving into the district heating, the heat pump, which is very good and running in the springtime, summertime, and autumn time when it has a high [coefficient of performance] COP factor. A COP factor means that you can serve 1 kWh of electricity and get a certain amount – usually it's 4 or 5 kW – of heating out of it.

(11:38):
This works really nice in spring, autumn, and summertime. And then in the wintertime when the environmental temperature becomes really low, the COP factor of the heat pump goes also down to 1.2 or even 1.15. So you nearly have a one to two or 1.5 ratio [of] how you are trading off the electricity to the heat. And what we just discussed is that during these dark doldrums in the wintertime, electricity becomes really expensive. It accounts for the vast majority of the money spent all over the year. So here, our CHP power plants come in very handy. Because with the CHP power plant, you can produce heat for the district heating while also producing a lot of electricity on your own cost of the gas, which is not rising that much during those dark-doldrum times.

(12:30):
You're covering up for the high expenses of the heat pump with a CHP power plant; you're covering up for the low COP factor during low ambient temperatures. And then the CHP pays off much faster than a heat pump. The financial roadmap becomes much more attractive. Just to give you a rough understanding, a heat pump has a payback period between three and 10 years, always depending on the heat revenue, on the cost of the electricity, and so on. And CHP power plant has normally, in Germany, a payback period between two and four years. You can free up more cash flow. And then when we look now from the short-term future to the midterm future, you can also run this CHP power plant with biomethane to make it more sustainable, to have less CO₂ emissions, and also mix in hydrogen if you like to. And during all of the year, you can participate in ancillary services in the spot market and actually have additional revenue streams.

(13:32):
What our customer is doing, he's not only making his heat production more flexible, but he's also adding additional revenue streams like energy as a service to his portfolio with those CHP power plants. And last but not least, it's important to also decouple the electricity production and the heat production. He did this with a large heat storage, so he can run the CHP power plant, for example, for high spot market prices or for ancillary services, earn a lot of money – sometimes peak prices of up to €1,000 per megawatt hour. And while the heat demand is maybe not that much during those times, he can store the generated heat in the heat storage. And the advantage of the heat storage compared to an electrical battery system storage is that it's much, much cheaper from a CapEx standpoint.

John Thomas (14:26):
So they can use the combined heat and power (or CHP) genset to produce the electricity when they need it but take that excess heat off of the product and store it until they need it, instead of assuming they had to use it at the same time. That's a super cool approach to that. You mentioned energy as a service – another way that a customer could make some financial gain off of this type of solution. Give us an example of what you mean when you say energy as a service.

Tobias Wedemeier (14:57):
You can buy energy as a service from a PPA [power purchase agreement] provider, yeah? You are not only looking at the pure energy [that] you need to produce to sell it in the market or to provide your own energy needs, but you also provide services related to energy, which is stabilizing the grid, backing up renewable energy in the capacity market, and really [helping] the electrical infrastructure to sustain in the future.

John Thomas (15:35):
One of the things that I mentioned at the opening of the episode today, Tobias, is de-risking – or managing, mitigating, eliminating risk. I did some research, and we are hearing a lot about that concept in the European energy market. Can you tell us, when we hear that, what kinds of things are they referring to?

Tobias Wedemeier (15:56):
We have a very stable grid and high availability of the grid – natural gas grid as well as the electrical grid. So it's not about having energy, it's more about de-risking the cost and also about solving the problem of congestion grid, if you want to expand the production of the company, your business, and you need more energy for your company. Looking at the cost, you can have different ways. You can have daily trade-offs of the daily cost swings of electricity. And you can also have seasonal de-risking of your energy demand or the energy production – which you are committing to your customers if you're, for example, a utility. This example, which I just mentioned from the utility, which is not only deploying a heat pump but also CHP power plant, this is a good example for de-risking [seasonally], in the wintertime.

(16:57):
Another example would be from a food industry customer, which we had, who is looking to produce steam for his food production. And running the CHP the last 10, 20 years worked out fine, but then he recognized that the duct curve, which is lowering the prices during the day, is decreasing the electricity price he can get selling the electricity produced from the CHP – so much so that it's not worthwhile to run the CHP anymore. What he did was reducing the size of the CHPs, installing [a] battery system to decouple…as well as the district heating sample before…to decouple, this time, steam production and electricity production and save (with battery systems) the electricity produced during the steam production, to store them and wait for the daily two times of high electricity prices and serve them then to the national grid – and sell them to the grid. In this case, he de-risks the daily risk of fluctuation of electricity prices. And also what [comes in very] handy is that he can charge his batteries as well if the electricity price become negative.

John Thomas (18:22):
Is there a different approach if it's a seasonal cost challenge – or seasonal cost difference – or is the approach similar?

Tobias Wedemeier (18:28):
The seasonal de-risking is the most difficult one, because when you deploy either storages of heat or electricity and you don't use them that much but you use [them only] a few times per year, the CapEx becomes so […] dominating that it's not worthwhile doing it. So to back up, [for] seasonal de-risking, you need large storage of fuels (which is basically there with our natural gas grid in Europe), and you need flexible, cost-effective power generation, for example, with the gas-fired power plants, which we have. Right now, there is not a good alternative to that.

John Thomas (19:10):
You've given us some great examples of some customers that have employed a couple of different approaches and how that's worked out for them, so that was really good to hear. We would all love to say that every time that we try to do something, it goes to plan [laughs], but it doesn't usually work that way, right? Tell us about where you've seen some customers underestimate the risk and fall short, and what was the impact on that – on them or on their business?

Tobias Wedemeier (19:37):
What I have seen is that…a few of the companies, they didn't adapt that much to the new energy landscape, and they were planning like companies did 10 or 20 years ago. I would say they were more one-dimensionally solving their own energy problem, trying to secure energy futures for long-term, paying additional money, and this way they cannot participate in the low electricity times. They were planning for a long-term, in the future if you install a new energy asset, it can…PV can operate for 20, 25 years, CHP power plants can operate for 20 years. But then you are depending on this one single asset, and you are depending on all the constraints [that come with] it. And those customers who are more flexible, who have different energy-producing assets, can react much faster and easier for that and compensate [for] that a lot.

John Thomas (20:45):
I'm going to shift gears just a little bit and ask you some questions about…How are regulations permitting local grid rules? How do those vary across Europe, and how are they impacting what customers are doing to solve their energy problems?

Tobias Wedemeier (21:03):
The framework for the European grid code is pretty much the same in every country. They can adapt it to their own needs, which some countries do. We have one common grid code with different requirements within this grid code. We have about the same spark spread. “Spark spread” is basically the difference between the gas price and the electricity price in your market. So the bigger the difference is, the more profitable become gas-fired power plants, and the smaller [the difference] is, the less profitable are gas-fired power plants. What really differs [are] the governmental subsidies. And these are either pushing some specific technologies – and [this puts] other technologies in a disadvantage, or they run out. In some instances, it's not [financially] sustainable to run those assets anymore. So it becomes much more difficult for those companies to have a profitable production or operation of their company.

John Thomas (22:27):
What role do you believe the utilities could play? What could they do, or what are they doing, when it comes to helping reduce that risk of energy costs and the congestion on the grid?

Tobias Wedemeier (22:39):
I think the utilities are – or should be – at the forefront of this reducing/de-risking of the energy sector, helping the large energy-consuming companies in their region to prepare for the future. They can either do this by doing PPAs, they can speed up the process, [or] they can provide reliable energy for those companies. And I think they have a key role for Europe to solve this energy challenge.

John Thomas (23:12):
As you think about everything that we've talked [about] today, if you were sitting down and talking to a customer who was bringing some of these challenges to your desk, how would you consult with them? What would you recommend to them as they look at what they should be doing for their energy strategy in the years to come?

Tobias Wedemeier (23:30):
There isn't a [one-size-fits-all] answer to that. You really need to understand the energy need. Is it thermal or electrical? Is it seasonal? Is it constant? Is it flexible? And all that stuff. But most of the time, it boils down to: you need either a competent partner to help you solve it…because most of our customers, energy is not their core business. It's a necessary need or a challenge they need to solve. They need expertise to understand it and also to understand all the possibilities. Caterpillar is constantly developing new products, new technologies, to solve the energy needs of our customers. They need to get help, get consulting. We can help there. We are happy to do that. And then in the end, it boils down to not [putting] all your eggs into one basket and [hoping] that it was the right choice, but [instead] to diversify and be flexible. Because who knew how the world would look in 2026 five years ago or 10 years ago!

(24:47):
And we don't know how it will look like in five years or in 10 years. But the investments, what you are doing now, they’re going to last for the next 10, 20 years. And it's always good to be flexible, and we are providing some really nice products for that. I mentioned before that, for example, our CHP or tri-generation power plants can operate with different fuels – renewable fuels as well – so you don't have only the fast payback, but also the long-term sustainability. And then you can combine those technologies with storage systems. If it's a heat storage, which we have talked about, or the electricity storage, to make it more flexible and decouple your energy production. And then of course, we talked about grid code. It's very important to have those assets grid-connected so you can have additional revenue streams as energy as a service, for good stability, capacity market, ancillary services. And then that would be revenue streams on top of your base case of your energy need where [and] why you deploy those assets.

John Thomas (26:00):
I love that concept because then you're getting your initial investment in the energy assets that you need to meet your immediate need, but you can find a way to employ them to actually generate some revenue, ultimately reducing your energy costs over time. Well, Tobias, thank you for this conversation. Hopefully, our listeners have enjoyed your expertise and learning about the landscape in Europe today. Thank you again for your time. I want to also say to our listeners, thanks for listening. We hope you hear us again soon.

Outro (26:31):
Thanks for tuning in to the Power Bytes Podcast. If you enjoyed the show, head on over to cat.com and check out Electric Power for more exciting content. Let's power tomorrow together.