Good morning, ladies and gentlemen. I have the pleasure of welcoming you to our Q4, 2024, earnings call today in a slightly new setup, as David Forth, our Group CFO, will be making the presentation. I am not sitting in the same room as usually. I am today participating from literally the other end of the world, from New Zealand, where I have been visiting the construction site of what today is our largest EPC project, where we are building a 20 MW power plant in Porto Neo for an external investor. This is why today we have a slightly new format. However, on the proceedings, this will not have an impact. Again, welcome to you. We will today go through the business results, which I will be presenting. David will guide you through the financial results.
We will also compare the actual reported results for the full year against the previously provided guidance. As usual, at the end, we will have time for answering your questions, which you can submit in writing, and please kindly do so. Going through the various segments, starting with electricity generation, which we also refer to as investments, here we had in the fourth quarter two major events. One was the sale of our two operating power plants in Australia with a total installed capacity of 14.5 megawatt peak. These were sold in a transaction together with a project that was still in development, but very close to ready to build, to an Australian investor, a company called Clean Peak.
This transaction was completed at the end of October 2024, which means that until that date, the revenues, but also, when we count our, or add up our produced electricity, the numbers until the end of October are included for those two operating power plants. Also in the fourth quarter, we completed and grid and commissioned our, to-date last, power plant in Romania, which is a 3.2 megawatt peak power plant in Sărulești. At this point in time, we are in the process of completing the construction, and very soon will start the commissioning of three new power plants with a total installed capacity of 5.1 megawatt peak, in Hungary. For the time being, it appears that these will be the last power plants from our development efforts in the Hungarian market, given that going forward it is relatively complicated to obtain grid connection capacity in this market.
Looking at the energy generation, in the fourth quarter of 2024, we generated 23.4 GWh of electricity, which represented a decline of 6.6%. That is mainly driven by the disposal of those two operating power plants in Australia, which, given that they were based in the, well, they're still based in the Southern Hemisphere, had the highest generation during the European winter and the Australian summer. Those two months, November and December, of generation that we were not recording anymore, outweighed the growth from the added capacity in Romania, between the third and the fourth quarter 2023 and the fourth quarter 2024. Looking at 2024 as a whole, we increased the generation by 18.4% to a total of 165.5 GWh , apologies, against the nearly 140 GWh the year before.
Looking at the specific yield, here we also had a decline from 200 kWh per kilowatt peak, recorded in the fourth quarter of 2023, to 173 kWh per kilowatt peak in the fourth quarter of 2024, again, mostly driven by the disposal of the Australian assets because, logically, during summer, with their very high specific production, they were contributing to this number very significantly. Looking at the average realized electricity prices, here we have seen between the third quarter of 2024 and the last quarter, a decline from EUR 173 per MWh to EUR 136. The main driver of this decline were the regulatory changes in Romania, where the power plants that we are still operating under the off-take agreement with Transelectrica became subject to new regulations as of September 1.
Of course, that had a full impact during the fourth quarter, where we are compensated for every MWh with a maximum of EUR 80 per MWh , even if the market price is above that level. If the market price is below EUR 80, we get that price per MWh . That means we are capped at EUR 80. Unfortunately, in addition, we are also not compensated on weekends and public holidays in Romania. Last but not least, we are also hit by negative prices if they occur. This has had a significant drag on our revenue generation from our Romanian portfolio, of course, with the exception of those power plants that have already exited this mechanism by obtaining a license and selling into the ad market in Romania.
As mentioned previously, we are working very hard on moving our remaining portfolio out of that Transelectrica arrangement, obtain the license and start selling into the electricity market. The good news there is that in the fourth quarter, but also in the first quarter 2025 to date, we are realizing significantly higher prices than EUR 80 as market prices have been consistently above EUR 100. On some days, we even generate around EUR 150 per MWh . The next area that we have been discussing and informing you about were planned negative regulatory changes in the Czech Republic. Before they went to the final reading and approval in Czech Parliament, the most drastic parts were removed. They moved to the Senate, and the Senate actually sent the law back to the Czech Parliament for rework.
The last remaining unpleasant part of these new regulations or this new law is a recalculation of the IRR of these power plants that were connected under the original feed-in-tariff regime until 2010. Based on a significant administrative burden that the power plant owners, irrespective of the size of the installation, so it would not only hit the owners of utility-scale power plants like ourselves, but it would also hit owners of relatively small installations as the minimum size was capped at 30 kilowatt peak. Many of these owners are farmers, sometimes schools. This was viewed very negatively by the Senate, leading to the law to be rejected and sent back for rework. We will know in the next couple of days how the Czech Parliament will react to this.
We, of course, hope that they will remove these last remaining problematic parts of the law and approve it without them. In general, looking back, three months ago, we're definitely in a much better position. We have, at the end of the year, as you know, we are also tracking and publishing the ratio between power plants that benefit from a feed-in-tariff regime or a similar support scheme and which part of the portfolio is merchant. Here we have seen a rebalancing. The share of merchant has been reduced due to the disposal of the Australian assets. The 14.5 MW that we disposed of were merchant. The 3.2 MW that we built are also planned to be merchant. That reduced that impact of the disposal. The net effect is that we're currently 51.5% in support schemes with our generation capacity.
The corresponding 14.5 are merchant assets. Essentially, we are hovering around the 50/50 mark in terms of the balance in our portfolio. For 2025, we have again switched out our Czech portfolio from the fixed feed-in-tariff system into the so-called green bonus system. Just to explain, once a year, we can decide, latest by the 30th of November, whether in the upcoming year we want to be paid a fixed feed-in-tariff or go into the green bonus, which is a lower amount. The difference is determined by the future electricity prices. There is a relatively complex formula. That difference for 2025 ended up being around EUR 42.
It has been our belief, and looking at the futures prices and the pricing curve, for 2025 and beyond, we came to the conclusion that we will be able to generate more than EUR 42 in the day-ahead market selling that electricity. We made this decision to switch. We have structured it within the group in such a way that between the various SPVs that own our Czech power plants and our energy trading arm for the energy trading, we have set a fixed PPA price that is slightly above those EUR 42. The price risk or the risk of that bet that we have taken that energy prices in the market will be higher is borne by our energy trading arm. Of course, from a group point of view, we have taken the market price risk.
We believe that this was the right decision. Again, looking at prices that have been realizing since the beginning of the year, which were above EUR 100, but also looking now at the monthly futures prices for 2025, we believe that we will end up quite materially above those EUR 42 on average. Last but definitely not least, we have had our first, I would say, our first unpleasant surprise in terms of the regulatory regime in Hungary, which to date has been a market that has been very stable in this respect.
On the last day of January, when the Hungarian regulator should have announced the indexation of the feed-in-tariff for the year 2025, which is based on a formula that is the average consumer price index in Hungary for the previous year, in this case 2024, that's actually an average of the monthly numbers minus 1%, which would have ended up being 2.7%. On that day, when they should have officially announced it for 2025, the announcement was actually that the indexation for CAT projects, which in our case affects 33.6 megawatt peak of our portfolio of slightly above 50 MW in Hungary, are affected by this. Indexation is frozen for the next five years unless inflation exceeds 6% in a given year. This is something that is surprising. It's, of course, unpleasant.
It comes on the back of indexation of 16.6% for the year 2024. It means, after the very high inflation in Hungary in the year 2023, we've seen a significant increase of the feed-in-tariff, significantly higher above what we had in our business plan when we were building the plants six, seven years ago. It put us on a significantly higher trajectory. From that point of view, it was quite surprising that this change or this freeze happened, now one year later. It is what it is. We're still generating, even without indexation, around EUR 115 per MWh from these assets. It's a price that still maintains very good economics of the projects. Clearly, this kind of instability is something that came as a surprise.
Again, to date, we have actually experienced Hungary to be the most stable country in the region from a regulatory point of view. We do hope that it's a one-off, and there will be not more of these surprises. The impact is reasonably modest in terms of our annual revenue generation. However, it has had an impact on the value of our portfolio, which, of course, has gone up in our regulation models. It could have been revalued by another more than EUR 2 million without this change in indexation. There has been a value impact for sure. It's not dramatic, but it has happened. Looking at other business segments, we have our engineering. What we're seeing here are external revenues.
You can see that we have seen growth compared to the previous year. In Q4 2024, we generated EUR 5.5 million against EUR 2.4 million in the corresponding quarter. Already the second and the third quarter of 2024 showed higher revenues than in the previous years, even if the previous year, even if you do not see it in this chart. This is mainly driven by growing CMI business in Australia, growing CMI business in the Czech Republic, and of course, the revenues generated from the construction of the 20 MW power plant in New Zealand. In new energy, as you can see, we have had, as predicted, and I think that we have communicated and explained that in detail throughout 2024. We have had a strong fourth quarter after very strong Q1 and weaker Q2, Q3.
This is simply due to the fact that the prices for DSR services contracted with PSE in the auctions that led to our contracting were the highest in Q1 and in Q4, but lower in Q2 and Q3. The fact that Q4 would be stronger than the previous two quarters was expected, and it was nearly on par with the first quarter. It was lower than the first quarter due to some regulatory changes in the capacity market, which are too complex to explain in detail now, that has had an impact. As you can see, the impact was, compared to Q1, around 9% of revenues. As you'll be able to see later, new energy was a very positive contributor to our consolidated results.
We have O&M revenues, where again, here we're showing revenues coming from external business, means from external customers. As you are aware, we are taking care of our own power plants. This growth curve that you see here corresponds also with the growing number of contracts. What we do see, however, is a certain delay between contract signing and when we take over power plants under our management. This explains why we have signed over 1 GW, but only around 750 MW are under active management and active O&M and generating revenues for us. However, the dynamics of signing up new contracts and also then with a certain delay, taking over power plants is accelerating. Continued positive growth is expected in the next couple of quarters.
The fourth quarter of last year was very important from the point of view of our technology division, which is our distribution arm for modules, inverters, and batteries. As you can see, after, and I think we have also discussed it in previous calls, after a record year 2022, we have had a very tough 2023 and an even tougher 2024. There is a lot of consolidation happening in the distribution market in Europe. We have brought in a new team at the beginning of the fourth quarter, which has hit the ground running. I think the best evidence is the very significant increase of revenues from this business segment in the fourth quarter. If we compare it to the second quarter, we grew from EUR 2.2 million to EUR 5.2 million, despite the fact that we had Christmas season.
Typically, the last two weeks of the year, there is nothing going on. Of course, October was very much a period where this new team was in the run-up phase. We do see a lot of potential for pre-technology to yet again become a significant contributor both to our top line, but also EBITDA this year and beyond. We have really made, I think, in terms of cyclicality, a well-timed move to strengthen our activities in this field while a lot of the other players are retrenching and in some cases, in actually increasing number of cases, even disappearing from the market.
Comparing the revenue mix between the years 2023 and 2024, you can see that new energy in both years was the most significant contributor in terms of revenues, followed by our energy generation. Engineering managed to increase its share. Technology, that means components distribution, has retrenched its share in 2024, which, again, just comes back to what I said before. We expect to grow again in 2025. We believe that we're working very hard that in all these business segments, we can show a positive development. As you are aware, in various business lines, in various business lines, we have differing gross profit and EBITDA margins. Clearly, the most significant contributor is our energy generation, with an EBITDA margin of close to 83%, followed by new energy, which had an EBITDA margin of around 14%.
In the other business lines, because these are consolidated numbers, group internal revenues play a significant role. This is why these negative numbers need to be taken the way they're presented here. That means where intergroup revenues are stripped out, with a certain pinch of salt. In the case of O&M, where you see a very significantly negative EBITDA margin, it is important to bear in mind that for 2024, the non-consolidated revenues of the business line were more than twice as large. That means that the group internal revenues were more than 50% of the revenues of this business line. In this presentation, we took out the revenues, however, not the costs, particularly not the fixed costs, which are a significant feature of this business line.
In this case, the numbers look significantly worse than in reality they are. Essentially, this number of EUR 1.8 million minus is the cost of operating our own power plants. The same applies to engineering, where, of course, we're also building for our own power plants and technology, which also acts as a procurement arm for the construction for our own portfolio, but also for third-party EPC. Of course, these activities also generate a margin, which is stripped out in this presentation. Good. With this, I would like to hand over to David to guide you through our financial results.
Thank you, Georg. Good morning, everybody. I press the button to move to the side. Yeah. We start out with the profit results. A very good quarter, revenues more than doubling.
This has come through very well from, as Georg has said, we've got a higher electricity generation, which comes in very well. Other revenues also sharply increased. This is coming on from several areas, new energy being one of them, and also this new team in technology. At the moment, they've been clearing some stock, but they've also managed to write some very good contracts. We do expect this to be a stronger and, importantly, a profitable contributor during the rest of the year. When we get down to the EBITDA level, the result is still negative. We were hoping that we would have a positive EBITDA in the fourth quarter. Some things did not go our way. We had to reverse the profit, the gain that we booked on this Polish project.
We do expect that, the reason for reversing it was because we had to postpone the completion of the contract. We still do expect that contract to complete. Obviously, we had to reverse the gain that we'd taken earlier in the year. We have balanced that to some extent with the sale of another development project in the past where some milestones were achieved, and this produced some income for us. We also had some unexpected, one-off costs during the quarter, which meant that we ended up with this negative EBITDA, pretty much in line with the results of the previous period. Getting to the EBIT level, we did make a loss or we made a book loss on the sale of our Australian projects.
Although, of course, these projects generated EUR 6 million of cash and also took us out of the least profitable part of our generation portfolio because Australian prices are much lower than the European prices. Into the cost side, raw material costs obviously increasing. This is actually quite important because in the engineering activity, we have spent money bringing things in for third-party customers. We've bid them, but in some cases, because there are contractual payments, we're not managed to take them sale yet, but we have got the costs. Also, our other expenses have increased. This is partly the way we account for these things. Inside it, inside other costs are the costs of contractors working on engineering projects. In our third, in when we build for ourselves, it ends up in our balance sheet.
When we build for a third-party customer, the cost goes through this line of other costs. This is not a story entirely about increases in overheads and other expenses. It also carries costs which are, in fact, direct costs to our business. Going forward, we might choose to show this analysis in a better way because as our third-party EPC business grows, it will mean that we'll have increasing direct costs, which will be related to the increasing revenues. In terms of the technology, as we've said, very exciting news actually after four quarters of poor performance in technology. We've now hired a different team. We've widened the markets that they go into. We've increased the volume significantly. Although the results were not profitable in the fourth quarter, they joined halfway through the quarter.
They've cleared a sink overhang, which was a problem in our balance sheet. And they've got some, I think we're going to see some really exciting results from that new team going forward. Into the rest of it, I think we have revalued some of our portfolio, which helps with total comprehensive income. The quarter, not quite as successful as we'd hoped. We'd hoped that we'd make a positive EBITDA, but with the strong revenues, it's really a promising result. In terms of the overall year result, we're talking quarter here, of course. Revenues up 26%. Electricity generation, 15%, even with the setbacks that we've seen in Romania and so on. A very pleasing result in the other side, 31% up on previous year. That's the profit and loss side. We go now to the balance sheet.
Fixed assets decreased, I'm sorry, because we disposed of the Australian assets. Current assets stable. This is mostly because we cleared out these inventories. We managed to clear nearly EUR 8 billion of inventories. Obviously, our trade and other receivables increased. This is partly because we have a larger business now, especially in the trading side, and we do have to wait to get paid for those. In equity, we are down, due to the negative results of the operations. The adjusted equity ratio, which is very important to us and to our investors, goes down to 25.7%. As Georg has said, these changes in Hungary, which are regulatory changes, do contribute quite considerably to that.
Why they contribute in something, why they contribute to the results in 2024 to something that happens in 2025 is because we've had to take down part of our, of the carrying value of, of our Hungarian power plants to reflect the lower future income, which, which they're likely to receive. The impact on equity of this was EUR 2.3 million. If we apply that to the calculation, our equity ratio would have been 26.5%. This is important because the bond, the bond prospectus, the arrangements which the bond are issued under, allow a carve-out for changes in our valuations caused by government interventions and regulatory changes. Of course, we don't stop, we don't stop reporting the adjusted equity ratio, but I think it is an important difference. If government does something that affects our equity, then it affects our ratio plainly.
In terms of our long-term liabilities, we, of course, made our normal repayments and so on. We, by disposing of those Australian assets, reduced our debts by EUR 4.7 million. In terms of current liabilities, we increased trade payables by EUR 7.5 million. Quite a lot of this comes from the third-party EPC business where there's a lag between when work is done for us and when we pay for it because we pay for it when our client pays for it. The other thing in there is we've reclassified one of our loans from long-term to current liabilities. Moving on to the cash situation. Our operating cash flow in the quarter was positive. We improved our investment cash flow because we sold the Australian assets.
In terms of financial, this is the reduction of those debts. In terms of the full year, because obviously we're looking balance sheet, cash has increased from EUR 5.8 million to EUR 8.4 million. At the end of the discussion about the results, of course, we do need to talk about guidance. We guided at the start of our actual results are EUR 89.2 million for the year. We had guided between EUR 90 million and EUR 100 million, so we're quite close to achieving that. In terms of the EBITDA, our EBITDA preliminary unwanted EBITDA is EUR 8.7 million. This is 12.7% lower than the guidance that we've given of EUR 10 million. At the time we gave that guidance, we did expect to be able to maintain the fourth quarter in a break-even situation for our EBITDA.
In fact, we lost EUR 1.1 million. That is partly because of having to reverse the gain that we had taken earlier on our Polish, on our, on the Polish project that we are selling. And partly because we had some restructuring and severance costs coming out of the business, in particular out of the restructuring of the technology business. Then, we took the opportunity to go through some of the old balance sheet positions, and that produced a further write-off. We will give guidance for 2025 when we publish the first quarter 2025 results. I think it is important to say in the guidance that when we went into 2024, we were expecting to land more third-party EPC contracts than we, in fact, managed to. This does not mean that we, that we have left this business.
In fact, we are quite close to closing some negotiations in that because third-party EPC remains an important part of our plans. That would be the end of the guidance. This takes us to the interesting parts of the presentation. Questions coming in. Back to you, Georg, I think.
Thank you, David. We have received a fair amount of questions, which I have been going through. Some refer to the same topics, but I will try to go through them as they came in. The first question relates to the strategy for 2021 to 2024 that we published back in 2021, where we set ourselves a couple of goals. The one that is being highlighted here is we had a goal of building 600 MW for our own portfolio until the end of 2024.
Yes, we stand at 129. We were too optimistic. The question is how we did on other metrics. The one metric we have hit is the one GW in O&M, at least we have it signed. That's a metric we hit on power plants being built. Of course, we're not even close to that, and there are multiple explanations. One is clearly that developing the projects, and our model has always been to develop either fully in-house or in cooperation with others. Back in 2021, some of the roadblocks, like for example in Hungary, that from a certain point onwards, no new capacity was available or in the auctions that were conducted, grid connection times were 28 and 30.
For example, just to pick one market, but also in other markets, development projects became a lot more complicated. That clearly extended the timelines; that did not help. After the boom in prices in 2022, as you are surely aware, there was a very significant retrenchment in energy prices in 2023, pretty much wiping out the economics or making, I mean, after a lot of interest by lenders and various parties in this industry, the exact opposite happened. In parallel, we have seen the emergence of the Duck Curve, which has even turned into Canyon Curve, meaning that during prices of high solar generation, particularly during the summer and on weekends, even in spring and autumn, we see extended periods of negative hours.
That means that the output of these solar plants has very low and in some cases zero value, further impacting the economics of power plants. I mean, these are clearly all factors that have come together that in this form were not foreseeable in 2021 when we published this plan. As a result, deploying significant amounts of capital into PV-only projects has become a very complicated exercise. It is based on multiple factors. Of course, for us, in building our IPP portfolio, access to project financing on attractive terms, in terms of interest rates, which by the way, in this period also went up significantly, and at interesting leverage ratios, is paramount. Based on those other factors I mentioned, that has become raising project that for PV-only, so without storage.
This is something that is only now starting to happen. It definitely has become a lot, a lot harder. We clearly had a slow development in our pipeline, but of course, also these changed circumstances led us to significantly reduce the speed of our deployment. Having said that, we are still working on building some additional power plants in Romania. We are building the 5 MW in Hungary, where we are planning to add more in Romania over the next 18 months. I would say the goals for PV-only are definitely a lot smaller. Going forward, there may be some additional investments into C&I projects based on a power purchase agreement, with an offtake, as we piloted in Hungary last year with our 658 kilowatt peak pilot project, supplying a factory in Hungary.
We're working on the investment case of battery systems in both utility scale settings, but also behind the meters. We will be directing our investment flows or our CapEx into hardware or to hard assets, clearly more and more into other areas than purely solar. There is a question, another question relating to Thornton Water and PFAS. I will try to answer them later, together, and I will now try to work through the questions relating to our energy activities and then finish off with Thornton Water. The next question is, will we switch to green bonus and market price in 2025 for a 24-Czech portfolio? I think we have answered that. I can confirm this is the case.
The next question relates to the sale, sale of our 20 MW project in Poland, in a transaction with a large, German-based investor, which we have published. The reason is simply that the development steps to get the project ready to build, which is a precondition to closing of the transaction, have been achieved in 2024. We are convinced that this will be the case in 2025. This transaction is coming live. Just its conclusion has been postponed. There are other questions relating to our bond, which I will also then aggregate and answer in one go. The next question is asking for a more detailed explanation about the situation in Romania where two of our power plants stopped, had to stop production, due to problems with the TSO.
These two power plants, affected by this decision by the TSO, are power plants with a grid connection capacity above 5 MW, which means that they are so-called dispatchable power plants, where we had to install and have to use a special SCADA system that gives the TSO direct access to these power plants and allows them to dispatch these power plants, switch them off in case there's too much electricity in the grid, for example, say in stress events. Both these power plants are still in the testing period. When we in the past referred to this arrangement with the TSO about the offtake until we get the license, basically what happens between the commissioning and the moment when we get the license, we are in a so-called testing period.
Which means that if the power plant is smaller than 5 MW, then this testing process is still in the hands of the DSO. That means that the regional distribution company, if it is above 5 MW, it is actually both the DSO and the TSO. What seems to have happened in the case of these two power plants, as we found out, we are finally the only ones in Romania, the communication between the DSO and the TSO over the last two years when PV power plants were commissioned and added to the grid has been not as efficient and not as streamlined as one would expect. This has led to certain discrepancies where the TSO at some point has woken up and instructed the DSO that they want to do some additional tests.
In the meantime, until they are concluded, these power plants need to be switched off. We are working very hard on resolving it, but this is not a long-term problem in the sense that these power plants would not be allowed to operate going forward. During this testing period, the TSO has decided to take the step. Our team is working in overdrive to resolve this. Our expectation is that in both power plants, this issue should be resolved within the next two months, as information stands today. The next question is whether we were unlucky as a company to invest in Hungary and Romania with negative, were negative changes impacted Thornton revenues, and or whether such negative changes happen in entire Europe.
If we talk about whether Europe is a good place for investments and whether Africa is different in this matter, I think we've been in this business now for a very long period of time. In year three of our operation, we were hit by these significant retroactive changes in the Czech Republic back in 2010, through the introduction of a 26% levy on our revenues. This was a really earth-shattering experience for us. Since then we've seen various types of changes, changes of law or changes of regulations, sometimes tax changes, essentially, but all aimed at reducing the revenues and the returns of solar investors in many countries. It's also not only linked to Central and Eastern Europe.
Back in 2010, the Czech Republic was the first, but a week later, Spain also introduced very high retroactive changes leading to lawsuits and arbitrations that are still ongoing, as we speak. After that, we had Italy, we had changes in France, in Belgium, but of course also pretty much, well, almost all countries in the CE region that had introduced a support scheme. It was Slovakia, it was Bulgaria, it was Romania during its first wave, 2013, 2014. We've seen those in some other countries. The question is always how brutal and devastating these measures are. Similar things have happened in countries outside Europe, where incentive schemes were in place. It's not only a European problem.
In general, the hope and expectation is that if we sell into the market, that means we're not drawing any funds, any public funds, whether that is through an investment subsidy or an operating subsidy in the form of a feed-in-tariff or a contract for difference, that interference by the state would not be so significant. As we can see, this is also happening in some countries. For example, this change in Romania where the TSO all of a sudden, obviously after September 1, is paying us a capped price because the role of the TSO in this, during this, and this is also my understanding of the regulation on which this is based, is providing a market access service. Essentially, they are, instead of, they're fulfilling the role of an energy trader.
Once we have a license, we worked with energy traders to sell our electricity in the market. The TSO's role is pretty much similar to that in this interim period. You know, essentially overnight changing the rules that a significant part of the production is not compensated at all and the rest has a cap. Even if the market price is EUR 200, we only get EUR 80. The whole revenue model is not based on any kind of public support. It's, of course, very damaging, in my view, also unlawful. Maybe at some point in the future we will also take action against that. Now is not a very good moment for that, as we still want to connect more power plants in Romania.
After 17 years in this industry, you know, I think we've seen a lot of these things happening and they are unpleasant. Whether Africa is different is really hard to tell. I mean, our experience is limited. Our focus now is on South Africa. Given that the market is in significant need of electricity, I believe that the risk of anything that would damage the development and construction of generation capacity in South Africa is relatively low at this point in time. Of course, nothing can be excluded. Yeah. Good. The next. Okay. I'll move to a question about technology. What margins do we expect from selling components in 2025? In general, the gross profit margin on components distribution is somewhere in the region between 7%-10%, depending on, and it also changes during the year.
But where inverters are more on the lower end of this range, maybe even closer to five. I would say that the whole kind of is five to ten. Some items are closer to five. On batteries and inverters, and modules, we're probably closer to ten. That is the gross profit margin from which of course we have to deduct our operating costs. This is in comparison to other business lines, a low margin business. On the other hand, if things go well, volumes can be significant. The bottom line contribution would still be very material. The next question is how O&M services differ from asset under management.
Because in the quarterly report we introduced an additional, we were splitting it up in the past between O&M and Cardio, which is our subsidiary that takes care of and services central inverters. We added a third category, which is assets under management. That is linked to a new service, which is asset management for PV power plant owners, which is a service that we have actually started based on demand from customers who have approached us, for example, in Hungary where we already have two such contracts. The latest signing, you could read in our press release, I think two weeks ago, where we signed an asset management contract for 100 MW with EDPR. There essentially we reacted to the demand of our customers for whom we're providing also O&M.
Essentially, the fact that we do the asset management, not only the O&M, but also the asset management for our own power plants in that country, clearly signals to our customers that we know how to do it. We were asked and approached to do so. It is as opposed to O&M where our technicians have to go and work in the field. Of course, there is also some work related to asset management. It is largely administrative work, and this includes, you know, many tasks of regulatory nature, making sure that the power plants are insured. Essentially, we do all the work that is necessary for the power plant owners in that given country, just as we are doing it for ourselves and for our own power plants.
From that point of view, the contribution margin, because we have very little in terms of third-party costs, is quite significant. The revenues per MW are not too far behind the revenues for O&M. It is a very nice and profitable addition to our service mix. We have been holding back with offering this as a service, because in some countries, most notably Poland, a lot of the tenders for O&M service providers are conducted by the asset managers of power plant owners. We did not want to be seen to be competing with essentially people running tenders for O&M services.
This still remains a concern of ours in relation to the Polish market, but in Hungary and potentially also Romania where we believe that we have above average knowledge in navigating the regulatory situation and understand what needs to be done for asset management, we are open to take on these assignments as well. They are a very important and stabilizing element for our O&M activities. It is a bit more profitable than the O&M itself. If we had to decide between 100 MW of asset management and 100 MW of O&M, we would most likely still decide for the asset management. Next question relates to our margin in O&M in Hungary, that it is the most profitable market and that we are still working on improving the profitability in the other markets.
Yes, the situation has not changed. Actually, Hungary has had a really, Hungarian operations had a really good year, with an EBITDA margin of over 30%, which is really an amazing number. Based on the contracts that we have signed, that we may still sign, we believe 2025 will be even again significantly better. We are in different stages of the development curve because Hungary we started about eight years ago, Romania in earnest really only two years ago. Poland is also still at the beginning of its development, having started O&M there about three years ago. This is very important, as opposed to all the other markets in the region where we did not own it for our own power plants. We do not own any power plants in Poland. We really started it from scratch.
Prices, Poland is a very competitive market. The prices we can charge for O&M are quite significantly lower than in the other countries. That means also that the break-even point required is a much higher MW number than in the other countries. The Czech Republic is growing steadily every year. We're adding a few more MW. We'll also be adding in Slovakia now. What we're waiting for there is for a new boom in building, particularly utility-scale power plants, to restart. We believe that at least in the Czech market that will be the case finally in 2025, which means by end of 2025, early next year, we'll be able to start growing the MW in the Czech Republic again as well. The Czech Republic is mildly profitable.
In Romania and Poland, we are working hard on achieving the EBITDA break-even this year. As we continue growing our business, the picture will of course improve. Just a second. Let's quickly look at the question about the guidance on '25, 2025 CapEx. While we have never given a guidance on capital expenditure, clearly we have, you know, finite resources and we will definitely be directing them to the most profitable uses. We will see whether, when we, as David mentioned, after, as part of the Q1 result publication, we will be providing guidance on revenues and EBITDA as we did in previous years, whether that will also include the guidance of CapEx. We will take it up as a point to consider.
There is a question about the measurable benefits of becoming the first energy aggregator in Poland. This is a very important point. The market for system services, or also referred to as ancillary services, means short-term, or getting a shorter-term flexibility than what we have contracted with the Polish TSO through the capacity market by providing DSR where the response time is in several hours. Ancillary services is a matter of minutes. This market only started in earnest in Poland in mid-June 2024 in a somewhat peculiar way where flexible assets from partially or fully state-owned Polish energy companies were included and nobody else was given access.
Only then at some point kind of the gates were opened for others to apply and start the process of becoming an aggregator, get connected to the systems of PSE for the provision of these services. This is a relatively long process. One of them was to be recognized by the Polish regulator URE as an energy aggregator according to energy law. Here we're the first. Today we found that they're not the only ones anymore. The real test is starting operations in terms of providing ancillary services here. In this forum I, I don't want to, I mean, not publicly yet commenting on when we expect to start the services. What I can say is that we have credible information that other companies that are working on the same are behind us.
It appears not just by a few days or weeks, but it looks like a few months. Our assumption at the moment is that we will be the first aggregator for flexible assets to provide ancillary services to the Polish TSO outside the universe of assets owned by fully or partially state-owned energy companies in Poland. This is really important because there are a lot of flexible assets already. Of course, as battery projects are being developed and realized, the number and volume will grow very fast. The way we see it is that we will have a window of opportunity as the first and only, for a while, aggregator of flexibility for ancillary services.
It is pretty much at this point in time, it's pretty much top priority within our group to make maximum use of this pole position or, or head start if you wish. From that point of view, it is a very important driver for our business in Poland, in the Polish energy market, but also for our business by new energy. We are, and I think we've mentioned that we are also working on starting ancillary services in Hungary and the Czech Republic. In both markets, it will happen after Poland. The situation is different because in both these other markets, there are already existing players active. That means we are, if you wish, latecomers. I think we have a very clear idea where we will have an edge over those existing players.
In Poland, we simply will be the first in a completely new market. I think it is obvious, looking at the Polish energy sector, that more and more flexibility will be needed. This is also best evidenced by an additional option that the Polish TSO has announced recently for additional capacity still for this year. As the energy mix is changing and baseload generation will be disappearing from the grid, flexibility will be important. The volume of flexibility that the TSOs will be contracting across the region and across the markets where we operate will continue growing.
Being first, capturing that window of opportunity and establishing, and if I may say so, contracting as much of the flexible assets that, as many of the flexible assets, as much of the capacity that is available in the market, ahead of our competition, that means putting us on the trajectory of, of, market leadership hopefully for a long time into the future is invaluable. As I mentioned before, the number one priority for us at this point in time. On that basis, I will gravitate back to some questions that relate to our bond, where one question asked starts with the question on a statement that we repurchased EUR 465,000 of nominal value of our green bond in the fourth quarter. This is evident from the numbers, and I can confirm that.
Clearly, given that they are still trading at a significant discount to the market value, this is a value-creating move for us. Of course, it is driven by our free liquidity to do so. I mean, against the total volume of the green bond, these are relatively small amounts. We have done it, we have reported it, we may do so in the future. I think the more important question is there are several questions relating to the refinancing of our bond or basically how we want to deal with the repayment of the due date of our bond, which is in November 2027. That means by now already in less than three years. I think specific steps will definitely only start in 2026.
The basis for that has to be significantly improved results in 2025. Our focus at this point is to materially improve our financial results in 2025, have a solid outlook on a solid basis for strong, even stronger numbers in 2026. That will set the framework for our actions and the path we will choose to come to successful refinancing, repayment, or a combination of our green bond. It is clear in our mind, it is not like we know to have this. The better numbers, the wider our options. This is why a solid improvement in our financial performance in 2025 is now our focus. This is definitely key to having multiple options open to deal with this refinancing need at the end of 2027.
There was also a question on our ability to pay some recruitments. This is something we cannot comment. I would refer to over 10 years of history of us as a bond issuer. This would lead me to the questions related to our water division, in particular PFAS. One of those questions related to PFAS in water also referred to Australia. I'll start with that part. The sale of our Australian power plants in the fourth quarter clearly presented the reduction of our capital employed in Australia. We still have our engineering business in Australia. We're still involved in the development of projects. Of course, we are in the process of developing and growing our water and irrigation business here.
This is something we still have. There are of course some strategic considerations in relation to how we want to develop our activities in Australia. By default, also in New Zealand, where we are in the process of commissioning the 20 MW plant for our customer during the second quarter of this year. There are multiple options available to us, but specifically in relation to our water and irrigation business and the particular focus on PFAS, Australia remains a prime market for these activities. There was a question about the Department of Defense. I think the best way of putting it is, Australia's Department of Defense is a relatively slow-moving organization, which we have also experienced during the pilot project itself. There is definitely the need to clean up a lot of sites.
We are still involved in discussions about certain technical and scientific aspects and of the conclusions of our tests where the Department of Defense is extremely diligent and working with a wide group of external experts. This is a process that, I'm also sometimes amazed why certain things take so long, but it is what it is. What I can say at this point is that we have very good traction with other parties in Australia that have more or less the same problem, that means contaminated site, PFAS contaminated sites. That goes across civil airports, that goes across firefighting organizations, but also industrial companies that have been using PFAS chemicals or have been involved in their production.
Last but not least, also, waste management, because the legislation in relation to cleaning leachates, that means water runoff from waste dumps, has become very strict. They will become even stricter now, in the next couple of weeks in Australia. That water also needs to be cleaned. What I'd like to say in the context of this is that while, of course, for us, our proprietary technology for in situ groundwater remediation is important and something that sets us ahead and apart from our potential competition, we are not approaching the market and customers as a single trip pony, where we say, "This is our technology.
This is what you have to use, whatever your circumstances, even if something else would work better. We have also developed filtration units to be applied for pump and treat when we talk about cleaning groundwater. It can of course also be applied to cleaning industrial water that is, that contains PFAS. On that front, we have had our first very important marketing success where in Q4 we have delivered one such unit to an industrial company in the CE region that had elevated PFAS levels. That plant is already, it is a filtration unit that filters PFAS out of processed water, which then gets reused in the industrial process. That is already up and running and performing as expected.
We are setting ourselves up as a company that can, that will tackle a PFAS contamination problem, with the most sensible, technical approach. We are increasing the options that we have available ourselves. Our crown jewel is definitely the groundwater remediation. Here I would also like to add that we are working on an approach to cleaning soil, remediating PFAS, PFAS soil, in cooperation with the University of New South Wales in Australia, also in cooperation with the Australian Department of Defense. That scientific dialogue we are having with them also extends to a cooperation on the national soil remediation, which is probably as a topic, even more important and bigger globally than groundwater remediation. We are working on a solution there as well.
That will also be tested either with Defense or one other organization in Australia. Moving to Europe, over the last 18 to 24 months, maybe now that you've been following us and you heard us talking about PFAS, maybe you've also been able to see that media coverage about PFAS and PFAS contamination has increased significantly. The level of awareness across the European countries is growing out almost, I have to say, exponentially. It started with a very extensive piece by Le Monde and Süddeutsche Zeitung, and other media about two years ago, including an interactive map of confirmed and suspected PFAS contaminated sites across Europe.
Now we see that the New Year Commission has put fighting against the dangers of PFAS chemicals by limiting their production and their use, but also encouraging the cleanup. Maybe in the not-too-distant future, there may also be some subsidies in this area. It is a high priority that the new limit set by the World Health Organization. The pressure is increasing, the awareness is increasing. This we believe will also lead to more business for us. We are still in the process of this. This is really new, and it is not like there are hundreds and thousands of remediation jobs that have been awarded. It is really new, and there is a lot of effort going into finding workable solutions.
I think that we are in a very, very good spot to benefit from what is now happening, which will still leave us with the U.S. as a market, which is by far the largest. What I can say is that we are looking for the right entry point for a company our size into that market, looking at opportunities in the public sector, but potentially also the private sector. Clearly the focus is now on Australia and Europe to win larger commercial deals, prove to ourselves, but also to our investors that we can generate revenues from activities related to PFAS remediation. I do believe and hope that we have been able to answer all the questions. Will there still be a QFC one that I have omitted and that you want to tackle?
I think we've covered most of them except for the Africa.
Yes. Let me, please let me also answer that one. As you've seen from our release, we are developing, among other, besides other projects, a large project based on the region technology in South Africa. The status there is that we have secured the land. We have started the process of preparing an environmental impact assessment study, which is mandatory for a project of that size. We have essentially been granted grid capacity. What it means is that if we complete the steps that are prescribed in the process, we can secure 250 MW of grid capacity for this region project.
This starts with paying a certain fee, providing technical data, and also securing offtake, at least in the form of letters of intent, which will then lead to design works being commenced by ESKOM, the grid operator, and ultimately will lead to 250 MW of grid capacity. It is in our control from this point onwards. We believe that by year end 2026, based on our information we have, we will be able to get the project to the ready-to-build phase, which means it will be fully permitted. Of course, this is only part of the story. What is also important is to find off-takers for electricity, to find project financiers. We also need to sort out engineering questions in cooperation with Renergen, possibly also SLB, which is a major shareholder and technology partner of Renergen.
We need to bring on board also equity investors. This is just as important. This is the process that we have now started in earnest. That also has to happen to get to what we refer to as financial close, for which the permitting is of course an important element, but by far not the only one. Our goal is to work towards a financial close situation at the end of 2026. We should not forget we are talking about a still new technology in a new market. However, our project is attracting a lot of attention from what I would call the right organizations and the right people. This will be important, is a very important project for us.
Let me also add that we are also working on and developing other types of projects in the South African market. Some of it is our C&I projects, but also PV utility scale where we have a 12 MW project in the city of Cape Town. With this project, we're participating in an RFQ for a 20-year power purchase agreement with the city of Cape Town, which has again been delayed, not due to our fault. The tip of the iceberg and the most important one is definitely our Renergen project, but we also, I would say, are quite successfully developing traditional PV projects and creating value for the company and also positive cash flow. The South African market for us is working well. Good.
If there are no more questions, I would like to thank you for your attention and also for your participation in the Q&A session. We are looking forward to welcoming you to our next earnings call, which will be after the publication of our Q1 results. This is also the moment that we will be providing you the time for the financial year 2025. Thank you very much for your attention. We wish you a good day.