Photon Energy N.V. (PEN) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen. My name is Georg Hotar. I'm the CEO of Photon Energy Group. To my right is David Forth, our Group CFO. And I would like to welcome you to today's presentation of Photon Energy Group's Q3 financial results. We reported -- we published the report last night. And today, we will run you through the business results, looking at the key segments of our group. David will run you through the financial results, and provide you with an update on our guidance for this financial year. And as usual, at the end, we will be available for questions and answers, which we kindly ask you to provide in writing, and we will get to that at the end of today's call. So jumping right into the business results and the key segment, which is investments, which covers our portfolio of photovoltaic power plants. We managed in the third quarter to commission 2 more power plants in Romania in total, which includes a 7.5 megawatt plant in a location called Faget. In this location, this is actually already our third power plant. And in addition, we managed to -- after the end of the quarter, commissioned Sarulesti, which was the last power plant where we started construction towards the end of 2023, and the commissioning process has been extended. So, that we managed to commission in early October. And also quite significantly and importantly, we also commissioned in the third quarter, our first behind-the-meter PPA project, in this case in Hungary, where we signed a 20-year PPA with an automotive supplier company. The installed capacity there is 0.66 megawatt peak. So it is, in the context of our portfolio, at the smaller end, but it is definitely for us a major milestone going forward as we expect more of these projects to be realized in the region with multiple and different corporate offtakers. Just after the end of the third quarter, in early October, we signed. And later in October, we completed our first major divestment from IPP portfolio. And that was the sale of our 2 operating power plants in Australia, with a total installed capacity of 14.5 megawatts. In addition, we sold 1 project, a hybrid project that, that was still under development, very close to the ready-to-build stage. So, we sold these 3 assets as a package to a local IPP in Australia called CleanPeak, and that transaction closed at the end of October. So it is not included in the Q3 results, but will then be visible in the Q4 results. In terms of the operating performance of our power plants, in the third quarter, we managed, on-a year-to-year basis, to increase our generation by over 12% to 55.3 gigawatt hours. And on a year-to-date basis, growth was even more significant by 23% to 142 gigawatt hours. In terms of specific yield, in the third quarter, we were 3% below last year's number. And the main reason for that was the unfavorable weather in September, where major parts of the CEE region were exposed to several days of heavy rainfall leading to floods, which I'm sure most of you are aware. So, those several days basically dented what was until then a very good performance for the quarter. In terms of electricity prices -- and if you look at the chart on the right-hand side, you can see that throughout 2024, our average revenue per megawatt hour. And here, I have to also explain that this number in the case of our portfolio consists of all the support schemes at all different levels that we have, plus the merchant exposure. So it is a number that, of course, makes sense to calculate, but it's driven by multiple factors. So, this number includes the very high feed-in-tariff that we have still in the Czech Republic, the feed-in-tariff that we have in Slovakia, which is still close to EUR 300. But it also uses merchant -- our merchant projects, which at times realized low prices. So it's a weighted average. You can see that for most of the year, this number has been going up. However, after the end of the third quarter in October, we have seen a significant drop. And that is the result of a regulatory change in Romania, which we have already announced to the market, which applies to the testing period. So, just a brief introduction. The way it works is that when we commission a power plant in Romania, there is still a process. That means we connect to the grid and we start injecting electricity. There is still a process taking a few months in order to get all the documents that we need to file for the generation license with the Romanian regulator, which then in turn has around -- has up to 90 days to issue a license. So, there is an interim period in which until we get the license, until which we cannot sell that electricity into the market. And in 2021, I believe a law was introduced which mandated Transelectrica, the Romanian TSO, to offer a buyout option, obviously, a market access opportunity in the form of a PPA to these power plants that are in the process from commissioning to obtaining the license. And the compensation until this regulatory change was -- the price we were receiving was the 90-day daily average of the remaining baseload price, which over the year, and particularly during the summer months has been increasing. So at a low point in April, we were obtaining EUR 63. I think it was the lowest point for the 90-day average. And then in July, early August, we reached almost EUR 130. So basically, that number -- that price per megawatt hour was doubled in the period. And effective October 1st, this has been changed. First, there has been a cap introduced of EUR 80 per megawatt hour. And then subsequently, that has also been cut further in the sense that supplies to the grid on weekends and public holidays are not compensated. So as a result, in October, our average price for electricity delivered to the grid was EUR 53. So this is, of course, a rather unpleasant change and it also has had an impact on our forecast and ultimately, guidance for the rest of the year. I mean, it's not the only reason, but it is definitely a contributing factor. On the other hand, what is important to bear in mind is that the impact is on the period until we obtain the license. In the old system, in the old regime where we were benefiting from this 90-day trailing average, we were essentially incentivized to stay in the system for as long as possible. So the maximum period was 2 years. This has also now been adjusted and shortened depending on the size of the power plant. But we are incentivized to stay in this regime for as long as possible. So when these changes came on the horizon, we decided to accelerate the process on the power plants that we already commissioned in '23 and early '24 to obtain the license. So on the first power plant, we already switched successfully from this Transelectrica PPA to selling into the market. We believe that 1 or 2 additional power plants will follow suit until the end of the year. And the rest of the power plants that we invested in, what we refer to as the first batch, the first 8 power plants with 31.5 megawatt peak, that they will all be in this market regime based on a license by the end of the first quarter, benefiting from what we believe to be now a situation where the market price of electricity is increasing again. So as we speak, the German baseload price or the future price for baseload in Germany for 2025 is hitting EUR 100. What we've also observed now, again, looking at futures prices is that the gap between the German futures price and the futures price for Hungary and Romania, which used to be around EUR 10 has now widened to EUR 20. So the baseload future for Hungary and Romania for next year actually stands at EUR 120. So, I think from what we can observe now in the market, the expectation is that energy prices are increasing again. So, that means that once we get out of this testing period and again, we are now incentivized to shorten it as much as possible. And we will also do this on the power plants that we commissioned this year, so that our -- so that the impact of this change in the conditions of the Transelectrica offtake will impact our financials for the shortest possible time. And then we should be able to realize higher prices based on the market level. Still, of course, working with the possibility of locking in fixed prices on the basis of PPAs, it's the market in Romania, but also the wider region is still emerging. But in Romania recently, over the last couple of months, the number of announced PPA transactions between renewable assets and corporate offtakers has been increasing. So, there is a market emerging and this is something that we are looking at closely. But for the time being, we will be selling on a merchant basis into a market that sees rising energy prices. And when we take the EUR 120 baseload future for next year and adjust for the profile -- the production profile of our PV plants, we get to a revenue level that is above what we need in terms of levelized cost of -- above our levelized cost of energy, which covers all the costs, including the cost of capital. So from that point of view, I think the environment is a positive one. This change is, of course, negative. And here in the first quarter and probably the first half of next year, we will see an impact against our goals. But it is time and probably also volume limited. The second regulatory topic that has emerged relates to the Czech Republic where -- and this is happening on a, more or less, regular basis. The Czech state has woken up with the idea of limiting the support of renewable assets and has in an effort to fill holes in the budget for 2025 to reduce the support for renewables. The main target is solar. However, the measures that I will be explaining in a minute are, at the moment, aimed at all renewable sources in the Czech Republic. And here, it's important to bear in mind that while the installed wind capacity in the Czech Republic is low, for example, in comparison to Poland, there's a very significant installed base of biogas generation and hydro also plays quite a significant role. So at the moment, it's aimed at all of these types of generation assets. And the 2 main measures that are currently in parliament being discussed are that in hours where on the day-ahead market in the Czech Republic, there would be negative prices on the basis of the day-ahead auction. No support would be paid to these renewable assets. So just to put it in the context, what we have seen in recent years in some other countries has been that -- and that includes also Hungary for a contract for difference arrangements, but it has also happened in the Netherlands to our knowledge that after a certain number -- a cumulative number of hours with negative prices. So in the case of Hungary, but also in the case of Netherlands, it's 6 hours. So if there's more than 6 hours of negative prices, there would be no support paid out. So in the Czech Republic, this would be much more radical. So for each hour of negative prices, no support paid out. Of course, this is a retroactive measure. And the second measure relates to a topic that we all believed to have been closed a couple of years ago with the notification of the -- it's actually the ex-post notification, I think about 4 years or 5 years ago by the EU Commission of the support scheme provided to renewable energy assets in 2008, '09 and '10, which stipulated a range of acceptable IRR rates. And back then, the Czech authorities also checked based on financial data collected from solar energy power plant operators. We also provided our data back then, and we have established that essentially the sector is below the threshold. So essentially, there's no overcompensation in the Czech solar sector. So, this topic has now been reopened again. The proposed measures, I think it's very obvious to everyone looking at it have been come up very much at the last moment. So, there's a lot of implications and repercussions that obviously were not thought through. What it means if other renewable energy sources get affected by this? The threshold has been set at 30-kilowatt peak. So, obviously, all installations down to 30-kilowatt peak would be affected by this, where many of these small installations are owned by public sector bodies by farmers. So it's a very wide-reaching damage. There is a significant lobbying effort from investors -- from the solar association, from investors, including ourselves. And as we've also announced, we have together with one Austrian and one German-based investor, sent a so-called trigger letter or notice of dispute to the Czech state on the basis of these discussed measures. And here, I think it's important to bear in mind that we do not only have access to the Energy Charter Treaty, but we have structured our investments from Switzerland through a Swiss subholding. So, we also benefit from the Swiss-Czech bilateral investment treaty, which probably at the end of the day provides even stronger coverage than the Energy Charter Treaty. Here, I would also like to add that our investments in Hungary and Romania are structured in exactly the same way. After our experience 15 years ago with the retroactive measures here in the Czech Republic, the first wave, we have learned the lesson and structured ourselves or our investments accordingly. So, we believe that the final vote in parliament is a matter of a few days. And after that, it will go to the Senate, which, if these measures are passed, there may still be some common -- maybe we'll find common sense in the Senate. But it is not off the table. I think the solar association has managed to corral a lot of support from various types of stakeholders. So, I think at the moment, probably it's a 50-50, whether these measures will go through or not, but we'll know in the next couple of days. Related to that, speaking about our Czech portfolio, based on the parameters between the feed-in-tariff and the green bonus, which represents the subsidy element, where the difference between those 2 numbers is less than EUR 40 per megawatt hour. We have decided to switch back into the green bonus scheme for next year. We switched back 2 years ago. We are switching now back into the green bonus, and we'll be selling electricity in the market because we believe we'll be able to generate more than those EUR 40 in 2025. Moving on, we have -- you can see our engineering revenues where you see the split between internal and external. So, internal are the revenues that are generated from the construction of assets for our IPP portfolio, whereas you can see, particularly in the third and fourth -- sorry, in the third quarter last year, but also in the beginning of this year, we had quite a lot of internal work. You can see that in the second and third quarter, the external EPC has become more dominant. However -- and we see continued growth in the C&I, not as fast as we were hoping for, but still very dynamic and very much encouraged by the pipeline that's building up for 2025. On the other hand, in terms of utility scale, external EPC, we have seen certain delays. And I think David will refer to that in more detail when he will discuss our guidance for 2024. These projects very often suffer from delays because of delayed development or delays in financial close. The important thing is those projects that we were including in our budget for this year, we haven't lost, but they have shifted in time. So, we expect them to -- we expect to sign them either before the end of this year or in Q1. And we should see them in our financial results next year, both in terms of revenues and margin contribution. Moving on to New Energy. Here, the picture is as expected. So, I think this is something we have already discussed before that the first and the fourth quarter would be the strongest in terms of revenues and the second and the third would be lower. However, also here, we have seen some regulatory changes, which are little bit too technical to go into detail at this point. But it is basically -- they have -- came into effect on September 1. They have reduced the capacity of the customers that are providing demand side response services through our aggregation groups to PSE. So, basically, they have been -- the conditions have been changed. As a result, we have sold some of our capacity obligations in the secondary market. And the same is also happening for the fourth quarter. And as a result, our annual revenues will be lower than what we anticipated at the beginning of the year. Having said that, however, is that we have been able to sell those obligations at conditions that have left our gross profit largely intact. So the top line will be reduced. There is a somewhat negative impact on the gross profit on its aggregation activity, but less significant than at the top line. Moving on to operations and maintenance, and our technology distribution business. So O&M, as you can see, has a growing trend. And in our quarterly report, you'll see a more significant -- a more detailed breakdown. The O&M is, still in terms of our group revenues, a relatively small activity. However, the dynamics that we have been experiencing this year and that we expect to continue in the next quarters and even years is a very positive one. We are, at this point, the only O&M provider for solar power plants that covers the entire region or at least the 5 markets where we are present in the CEE region. So while we have competitors in each of these markets separately, there's no other O&M provider that covers the whole region. And this footprint is increasingly very beneficial in our efforts to win additional business from, I would say, highly recognized investors into PV assets in the region that invest across multiple markets. So, we have now had several times positive outcomes in winning a customer in one country and then being invited and having, I would say, an elevated chance of winning business in another country. So, we have now a couple of cases where we won a customer in Poland and have signed or, I would say, on good track on signing business with them in Hungary and Romania where they are building new power plants. So this regional cross-selling and leveraging, and growing these relationships is something that we expect to continue driving our business forward. At the same time, we're still winning business from local investors in PV assets. So, we believe that in terms of megawatts, we will see continued increase in this business line. As storage is becoming more and more important and batteries are being either retrofitted or installed -- newly installed on newly built renewable assets, but also the increased use in behind-the-meter installations is something that is also pushing us into -- or getting us to focus on providing O&M services for battery storage systems, which not only consist of a battery, but also inverters where the know-how and experience we have built up through our subsidiary, Photon Energy Cardio, which is specialized on inverters comes in handy. So, we will expand our service offering to include storage as well, which is another growth vector. So, O&M is definitely something that will continue growing and will also financially contribute more significantly both in terms of revenues, but the fact that there is a significant operating leverage in this business also in terms of EBITDA over the next couple of quarters and years. So, this is definitely an area that what 2024 so far has been providing good news. Our PV component trading business is an area that after having been a significant contributor to our revenues and EBITDA in 2022 has since then been on a continuous slide as a result of lower volumes, both for modules, inverters and also batteries. But also, as you're probably all aware, prices for modules and inverters and batteries have been on a sliding slope since the end of 2022. So the market has been in a situation of massive oversupply for all these components since early 2023, and that oversupply is in the entire supply chain. We have -- and we see a lot of companies involved in the distribution business suffering from overstocking, which is essentially the value of that stock is falling on a weekly, daily and I think the days when, actually, almost on an hourly basis. So, this is something we have avoided. We have had a significant stockpile of batteries at the end of 2022, early '23, where we have now been able to sell off more than 85% of that initial stockpile, with relatively limited impact on our financials. At the beginning of October, we have onboarded a new team that joined us from another company that's fully focused on components distribution. And this team has significantly expanded the footprint. So while under former leadership, the focus was very much the Czech and Slovak markets with some limited activities in the other countries where we are present in the region, we now have a team that covers essentially the whole European market ranging from Benelux, all the way to the Caucasus. So the numbers you see here, we believe that in Q4, we will show in terms of revenues, market improvement. But our expectation is as well that in 2025, this business line will again be contributing significantly to our revenues, but also to our EBITDA. So as you can see, the revenue mix comparing the first 9 months of 2024 [Technical Difficulty] only slightly where technology, because of the trends that I just described has lost its significance. Energy generation has -- as revenues have recovered, has grown in importance. Of course, energy generation providing the largest EBITDA contribution and New Energy essentially has remained stable, providing a bit more than 1/3 of our revenues. And as you can see, energy generation and New Energy are the parts that have been contributing positively. O&M -- and here it's important to note that these EBITDA margins relate to the external business. So if we include the internal business, O&M is actually positive. But as I mentioned before, technology, we expect next year to be a contributor again. And in the case of engineering, which covers the construction of behind-the-meter in the Czech -- well, here in Central, Eastern Europe, Australia, but also EPC for external parties, where again, I also don't want to fail to mention our 21-megawatt EPC project in New Zealand, which is moving ahead in its implementation. We have seen business that we expected to happen this year shift into next year. And so there, again, as well, we expect a positive turnaround. And with that, I would like to hand over to David to walk you through our financial results.

Thank you, Georg. So financial results. If we look at the income statement, we've had a strong third quarter. Our revenues slightly up from -- on a year ago, but EBITDA up significantly. Within our business, we've had good contribution, as Georg has been saying from electricity generation, but we've also managed to land some good results from the other parts of our business. And importantly, once again, as Georg has pointed out, we've shifted the percentage part of our business away from the technology, which has been volatile, quite a challenge and replaced it with engineering and capacity markets. In the engineering, we haven't managed to land all of the contracts that we'd hope to at this time, but we're certainly still confident that this is more about delays in concluding contracts rather than us being priced out of the market or anything like that. Within the EBITDA for the quarter, we have got -- we've landed EUR 3.8 million. In terms of the 9 months, we've almost doubled our result with EBITDA of nearly EUR 10 million. This tracks through into total comprehensive income for Q3 of EUR 1 million. And we've benefited from the revaluation impact of when we bring a new asset into commission. What happens there is it's in work in progress until it's commissioned. When it's commissioned, we're able to look at its forward value and that adds to our total comprehensive income for that period. So all in all, a strong third quarter. As you'll see, that won't continue entirely into the next quarter, but we are in a good shape there. In terms of the balance sheet, our fixed assets -- fixed assets are reduced because of our plan to dispose of the Australian power plants and one of the development projects there. This means from an accounting point of view, we should reclassify those assets. Had we not reclassified them, fixed assets would have been at the same level -- at the same total level as they were before the classification. In terms of current assets, they've increased for the same reason. It's simply a movement out of long term into short term. Our equity is down because of the continuing loss in total for the business. However, our equity ratio, which is the important thing for the bond covenant remains sufficiently above the covenant with a value of 26.8% for the September revenues. In terms of our long-term liabilities, these are also reduced because of that reclassification and current ones increased. Our trade payables in the period increased, which is being balanced to some extent by our reduction in inventories because, of course, we managed to clear some of our batteries. Thank you. In terms of cash flow, within the quarter, we have a negative cash position. That's partly because we've invested. We're continuing to build some of that, spend money on our power plants and also because we've repaid some of our loans and obviously, there's interest cost in there. So, our net cash position decreases to EUR 7.5 million. In terms of the cash flow for the whole 9-month period, we started out with EUR 6 million of cash. We generated EUR 13.5 million of operating cash flow inwards. We invested EUR 7.5 million during the period, and we've got the interest costs going out, bringing us to a September end cash position of EUR 7.5 million. In other words, an improvement during the 3 quarters of the period. Thank you for that. I want to turn now to the guidance where, obviously, there will be disappointment that we've had to reduce our guidance. In terms of the revenue guidance, it's now clear that we'll come in at the lower end of our guidance with a revenue of EUR 90 million for the full year. This has mostly come about due to delays in commissioning of the Romanian assets and our expectations for the outcome of these regulatory changes in the fourth quarter. I think more importantly, we had to take the EBITDA guidance down. So far in the 9 months, we've achieved 62% of our original guidance number, but we are not expecting the same strength in that fourth quarter. The reason for this is that our energy generation is going to be lower than we'd expected it to be. And our capacity market contracts are not delivering as much as we had originally expected, again, partly due to changes in regulations. But I think most importantly, we were expecting before the end of the year to have landed some significant engineering contracts and especially, utility-scale contracts. And although we've not lost those contracts, as Georg said earlier, they can take longer to land than one would hope. Certainly, we were hoping to be able to announce some significant contracts in the areas of tens of thousands of megawatts. And this is also matched by us not delivering as much as we'd hoped in the technology side. We started the year with a battery overhang. We've managed to clear that overhang virtually during the period. The prices have not come in at the levels that we were expecting. However, we've taken steps to deal with that. We've changed the leadership of that operation. And the new team that we've got, in particular, they've got a much wider geographical market and we're already seeing some good results, but it won't be sufficient in '24 to deliver that guidance. So, that's our position. Obviously, it's disappointing to us. We really had expected in the last months of this year to be able to land 1 or 2 of those larger contracts.

Okay. Thank you, David. So now we're getting to the Q&A, where I will start with questions that were sent to us beforehand. And then we will go through those questions that have been asked, that you have provided in writing. So the first question is, does the reduction of support for PV on the Romanian market change Photon's approach to developing business in this country, which means the construction of new power plants? You have about 200 megawatts in Romanian projects at various stages of preparation, about 20% of our pipeline. So, these changes that I described before in detail are, of course, unfortunate and a nuisance. On the other hand, it is -- at least not -- I mean, the revenues are not 0. So, I mentioned that this Transelectrica arrangement was based on the law passed in 2021. Until then, essentially in this gap between commissioning and obtaining the license, renewable energy sources in Romania were receiving 0. And so clearly, this 90-day average has been very beneficial, particularly in the second and the third quarter. These changes now are, of course, a significant setback, but at least these power plants still generate revenues in this interim period. So for us, the big issue in Romania and when we moved from building power plants in Hungary to Romania, we learned in some cases, the hard way, that Romania is in many aspects in terms of red tape, a lot more complicated than Hungary. So, Hungary is actually one of the most -- probably the best run country in relation to renewables as far as we have experienced it. So, Romania is definitely more difficult. These changes happen very quickly. So it is an environment that has definitely its drawbacks. On the other hand, it is a country that needs renewable energy. It is at a geographic crossroads. It is now also in a situation where it is supplying electricity into Ukraine. So the economy is growing. It is becoming increasingly a target of FDI. So, I think that the macro picture for Romania is definitely a positive one. I think what is just as important is what we discussed already previously is that now energy storage is starting to play a bigger and bigger role, and that we are trying to hybridize as many of these projects we have in our pipeline, even after they've been built. So, that is something we are looking into on our already existing assets and those that we are just about to start construction on, but also in our pipeline. So, this for us is almost a more important question. So it's -- definitely, these changes may have an impact on our final decision whether to keep or sell Ciupercenii, our large project in Romania, where there are some discussions ongoing. It may lead to a reduced appetite to add significantly more to what we have already committed to and where we are at the final stages of securing the long-term project financing. So, yes, it may have an impact, but it does not mean that we will discontinue our efforts in the Romanian market. As I mentioned, energy storage is a big topic given the grid constraints in Romania, and we see a lot of opportunities there. What I would like to point out is one of the areas that for us next year will be very important is ancillary services within the New Energy business line where we will -- next year, we will start providing these services in Poland, most likely as the first aggregator for this type of system services, but also the Czech Republic and Hungary. And we will also start the process for the Romanian market, where we see significant need going forward and a lot of potential in flexibility aggregation. So, Romania will definitely become -- will definitely remain a core market for us. Yes, those changes may have an impact on how many megawatts we ultimately put into our portfolio. The next question is, could I ask for a broader comment on possible further negative legal changes towards limiting renewable support on the markets where Photon operates, (Czech Republic)? Well, I hope I've been able to comment on that. I think we will know more in the next couple of days where the Czech situation is going. Essentially, since the very beginning, since after we commissioned our power plants in the Czech Republic, there have been retroactive actions taken by the Czech state. During the last one, a couple of years ago, the promise was, this was it. No more until the end of the feed-in-tariff period. Here we go again. So it is something we have to get used to. I think what the good thing is that our industry is in a much better position to fight back, I mean, to lobby, to provide arguments and win arguments. In addition, the Czech Republic, of course, this effort now is in a difficult spot because it is running behind the renewable energy generation goals. So basically, cutting support for old assets in a situation where not -- the speed of building new capacity is not happening fast enough, of course, paints a very, very strange picture, particularly towards stakeholders outside the Czech Republic, whether that's the EU Commission or multilateral financial institutions. So the list is very long. And this also gives us hope that ultimately, the combined pressure will be such that this will not get adopted. Next question is the debt-to-equity ratio deteriorating due to the sale of the Australian assets. So, I think I would like to point out that the transaction, the sale of our Australian assets occurred in the fourth quarter and is, therefore, not included in the Q3 results, so including our equity ratio. The next question. And that's already a question that was posted here is how is the company going to handle long-term liabilities, amongst others, EUR 80 million of bonds and EUR 80 million of loans? So the EUR 80 million of loans with the exception of a few million euros that are working capital financing in our components distribution business are project financing loans, means these loans are provided by the financing bank directly to the project companies that own the power plants in our portfolio. And all these loans are provided on a non-recourse basis. That means we as the equity sponsor are not liable for this. So, we're not guaranteeing these loans. So, they're basically ring-fenced. But they are sized and dimensioned in such a way that they can be repaid by the cash flows from those power plants. And here, I would like to point out that on all these financings, our assets are that we are current, that we are repaying according to schedule. And so at this point in time, there's no information that would suggest otherwise in the near or more distant future that these loans could not be serviced from the cash flows generated by these PV assets. So, this is something that as a group and leaving aside any additional financing of that sort, project financing we may take on, this will -- you'll see this over time reduce in size. The other exception is the EUR 5 million that we have drawn from the EBRD financing. So, we have so far drawn EUR 5 million out of EUR 15 million, and that is a holding level -- this is holding level guaranteed. But in combination, both the working capital and this financing are below EUR 10 million. And then, of course, we have the bond, which is debt at the holding level. And our bonds are repayable at the end of November 2027, so pretty much exactly 3 years from now. And this is, of course, something that we will need to start working on how to refinance those -- this bond liability. However, the 3 years is a relatively long time, which doesn't mean we don't have it on our radar, but we believe that in about 12 months from now is the right moment to start building the strategy for that repayment. So clearly, we will not address this 3 months before the due date. And clearly, a core part of our strategy to develop a plan for the refinancing and financing of that repayment is linked to what we expect to be improved numbers next year. The next question relates to obviously bonds. Is the market wrong? Bonds reached as low as 30% of normal value. Investing in bonds give 300% return in 3 years, additional 20% per year. Is the company going to default? Well, of course, we're limited to how we say and what we can say. So on the 23rd of November, which this time I think is a Saturday, is the next coupon date. And I think what we can say here and now is that, that coupon will get paid. And I think you have also seen in the presentation that our cash position has remained stable over the last 12 months. And so we don't -- so if there were any issues, we would be on the fiduciary and legal duty to report, and we haven't done so and don't expect to do so. Will the change in regulation in Romania require a revaluation of assets there? Which is a good and fair question. Here, I would like to just spend 2 or 3 sentences on how we value those projects. We are using a discounted cash flow over the expected lifetime of these PV assets, which at this point in time is 25 years. And of course, a lot of factors go into that cash flow model. So, we know our investment costs at the beginning. We have a good idea -- well, in some cases, where we have the financing at the beginning -- the project financing at the beginning and all the parameters, in some cases, the project financing happens later. But of course, the key input factors are generation volumes, prices and of course, the discount rate, which is primarily a function of interest rates, the credit margin for the project financing and also the debt-to-equity ratio. So, quite a few moving items. As I explained before, the impact of this change is temporary in some cases, I mean, from now or from the moment when these changes, particularly the non-compensation of weekends and public holidays came to effect kind of further reducing the expected maximum, which was -- so the EUR 80, now with the winter months, we believe we would have been quite close to pretty much in every production hour because prices are well above that level at this point in time and probably will be during the winter season having taken -- given that weekends and public holidays have been carved out, of course, worsen the picture. But it is temporary. As I said before, we are accelerating obtaining the licenses on all the power plants that we have in our portfolio. We believe and hope that on those power plants that, for example, we recently commissioned, we can keep the time from commissioning to obtain the license to more or less 9 months or let's say in the range of 9 months to 12 months. Since we commissioned our first power plant, where this took very long, there's a lot of lessons learned on our side, but also on the side of the TSO who mostly provides the documents we need. And so this -- we expect to shorten. So it is a temporary thing, which, of course, does have its impact in the '24 -- sorry, in a 25-year cash flow model, but not a devastating one. So it definitely hurts short term. But in terms of value, while it has an impact, changes in the other parameters like the discount rates, and we've seen interest rates falling over the last couple of months. Now, we're seeing energy prices going up. And I believe that these 2 trends, low interest rates leading to lower discount rate and high energy prices will easily compensate the impact of this temporary impact from these changes in terms of value. But we will do that valuation. We will conduct this valuation exercise at the end of the year. So clearly, quite a few input factors can change. But as we're standing, as of today, I believe this is not -- it will not have a massive impact. The next question is what does reduction of the compensation IRR range, 6.3% to 8.4% exactly mean for current prices for 1 megawatt hour in Czech, around EUR 640 per megawatt hour? How low it may go down after changes? Can you count on compensation from the Czech government? How likely is it to get one, if this risk will be fulfilled? Well, this is a really tough one. So, this IRR range of 6.3% to 8.4% is, well, this -- I hinted at the beginning. What happened in the Czech Republic was that the original support scheme that was applicable until 2010, so there was a law passed in 2006, applicable until 2010, was never notified to the EU. And while there have been different views, legal views, the EU Commission is of the opinion that the feed-in-tariff is state support, state aid, which needs to be notified to and approved by the EU Commission. And the Czech government never did that. And actually, when they were looking throughout the 2010s, so somewhere in the middle of the decade for ways how to reduce our support further, they started actually playing the state aid card. The Czech state went to the EU Commission and he said, oops, we forgot to notify this. Maybe you want to review this in the hope that the EU Commission would say, oh, yes. And so you can't continue paying that any further. That was a serious attempt. In the end, thank God, it did not go down this track, although at some point, it looked quite serious. But a notification process was then started, and I don't know from the top of my head, it was in 2016 or '17. And at the end of this, for the various types of renewables in the Czech Republic, IRR ranges or acceptable ranges were established. So basically, 6.3% to 8.4% for solar, where essentially it says that if -- and this is on a sector-wide basis, so not for individual power plants, but sector-wide. So basically, it was if the sector is compensated at over 8.4% IRR, then the support can be cut to bring it back to 8.4%. The 6.3% is meaningful because there was also a provision that if power plants in the Czech Republic are below 6.3%, they may be exempt from the solar levy or solar tax. It was quoted by the Czech state of 20% of the feed-in-tariff. So if you're below, you can ask for it to be exempted. But essentially, the most important one is the 8.4%. There were sector-wide calculations for power plants connected in 2007, '08, '09 and '10. And essentially, for all these years, the numbers that the energy -- the state energy agency calculated were within that range and well below the 8.4%. So, I think around 7% for the 2010 vintage power plants. So, now they have pulled this card again quite nonsensically. They're suggesting that now there will be individual checks so that basically they would go and then calculate the IRR for individual power plants to essentially go after individual power plant owners. How that should work in reality is very difficult to imagine. However, I mean, if you -- once you understand the dynamics of a discounted threshold calculation and when you do the IRR, I mean, if you, on a project go from, for example, 8% to 7% and 6%, the change in cash flows is very, very significant. And I'm just talking about the mathematical exercise. And by the way, this is also the argument that the solar association investors are -- I mean, it's important to bear in mind, we are dealing at the moment with politicians and of various types from the ministries to members of parliament, who, to put it bluntly, particularly in the Czech Republic, have no clue how this works. So when they explained what it means to go from 8% to 7% of IRR, what impact that it actually has and particularly once you are, let's say, 70%, 75% through a 20-year feed-in-tariff. So if you want to, at this point in time in year 15, adjust from a maximum of 8.4% or 8% to 7%, essentially, what you have to do in the 5 last years would be quite radical and mathematically speaking. The problem is that the average Czech bureaucrat and politician doesn't -- for them going from 8% to 7%, not much, right? But in reality, of course, the impact will be significant. So from what we see and also the solar association in these discussions with the various politicians, they are surprised. And then after we explained to them, they seem to start to understand that this is a significant thing. So coming back to our chances, I think it would very much depend on how large the group is. I mean, what we know is after the initial measures in 2010, we were originally part of a group of investors that sued the Czech state. We had to drop out because at that moment in time, we were not yet a Dutch company. But of course, we've been following what has happened afterwards. And there are some investors that have successful, that have won arbitration against the Czech Republic. So the Czech Republic is due to pay an amount, which is well over EUR 100 million as compensation to investors that were harmed by the measures in 2010. The award is final. I mean, it has been a very long and expensive dance and going -- involving the Swiss court. So not only the arbitration tribunals, but the Czech Republic really pulled all the tricks to extend. But now it's -- the award is final, but it hasn't been paid yet. So, arbitration is clearly something where, I would say, on the basis of our 15 megawatts, the cost benefit analysis is probably stacked against us. On the other hand, together with those other 2 investors with whom we have now sent the trigger letter, we are well above 100 megawatts. And given that a significant part of assets in the Czech Republic are held by non-Czech investors, that group could be larger. So, I think once there's a sufficiently large group, the economics make more sense. I mean, this is -- what has also changed in the last couple of years, there are also certain rules we can take within the EU. So, there are also certain pathways how to sue in such a situation at the European Court of Justice and believe it or not, even at the court for human rights. So, this is something, to be honest, that we have not -- we haven't gotten any detailed legal advice on yet, but there are multiple routes. And I mean, what the Czech government is trying to do here is definitely awkward in the context of the push to increase the installed capacity of renewables and also storage going forward. So, I hope they will not get adopted, and we don't have to sue and we don't have to find out how long it will take. But definitely, the remedy from taking a country to arbitration takes a long time. The next question is, in the report, you mentioned that there are some possibilities to fight against recent change in Romania and that effects of some actions, which the company has already taken will be visible at the end of Q1 2025. Can you please provide better insight into this matter? Well, I think I mentioned before. So, what we published is our current expectation of how much of our generation capacity will be selling into the market and will be out of the Transelectrica mechanism. And why only 44% of the plants? I think we're talking capacity -- total storage capacity because these are power plants where we already have all the documents are required to file for the license. As I said, it takes a few months before we get -- and the key document, the last document is called the conformity certificate, which we get from the TSO, and it can take anywhere between 4 months and 8 months. On the first power plant, it was even longer than that. These times are getting shorter now. And then we could go to the regulator, ANRE. We request the license, and they have up to 90 days. So this is where, I mentioned before, 9 months to 12 months. So we stop. Once it was clear that we will have to move out, and let's not forget our very first power plant was commissioned in March 2023. So basically, the second anniversary is in March '25. So, they have been operating for a longer period of time. Those power plants that we connected in 2024, so earlier this year, are still in the process of obtaining that conformity certificate. But essentially now, we are trying to shorten the period as much as possible. So, we wanted to provide visibility over the next 2 quarters. So, this is where we are relatively certain to the extent that we have published how much we expect to be selling into the market. And of course, other power plants will follow during 2025, and our goal is to make that as fast as possible. So questions then. So, bond buybacks, EUR 5 million investment in buybacks of bonds at current prices would reduce interest payment by EUR 1 million per year and cancels EUR 15 million outstanding debt, thus also improve covenant KPIs significantly. Has management considered buybacks on a longer scale? And has management seized the opportunity of the last trading weeks? To this, I would answer that we are aware of the situation in relation to our bonds and also the mechanics. And it is definitely something that we are evaluating. But we have it on the radar, but we cannot comment about specific actions taken in relation to this situation. In case bond buybacks are not considered, what is the strategy on refinancing the outstanding bond in 3 years, considering the mediocre financial performance and unsecure regulatory environment of the PV portfolio? Well, I mentioned -- as I mentioned before, of course, we are aware of the due date of our bond. And our focus at the moment is to make sure that after we have now seen a recovery compared to '23, make sure that 2025 will be the best possible continuation of that trend. And we believe that any strategy or any steps taken towards refinancing that bond at the end of 2027 will be based on our full-year results 2025, ultimately also '26. But this is -- basically, our energy is now going into setting the stage for that. And I believe we have enough opportunities available to show continued improvement in '25 and beyond. And at the end of the day, any refinancing or other financing that we will need in the second half of '27 will be based on '25 and most importantly, '26 results. So, making sure that they are the best possible is now our key focus. And in relation to the regulatory environment, well, it's obviously something that we cannot completely avoid. And as you can see, it's popping up in different ways and forms across the region, across certain segments. And this is simply part of the game. And here, I think it's also important that we are geographically diversified, which, of course, means the larger number of countries where you're active, the bigger the risk that you get hit by some regulatory changes. But when I go back in history to our beginnings, where we were only in the Czech Republic and then we had this massive retroactive change at the end of '22, that is something that, of course, is a massive blow, which is very hard to overcome back then. Once you are in multiple countries, typically, these regulatory changes don't happen everywhere at the same time. So it's easier to absorb them. And as we grow our services, which are not exposed to this risk, we also believe that the potential risk or the potential of a regulatory change to threaten us fundamentally will also diminish. The next question is negative profitability in the trading business. Does management consider a sale/closure of the technology trading business, considering the negative margins, which are unacceptable in a trading type business? So, well, I think I've spoken about it before. We have actually done exactly the opposite. We have changed management. We brought a team with a completely new approach to the segment. And I mean, consciously knowing that this is, at this point in time, looking around, looking at the situation, other distribution companies or companies involved in distribution, whether that's their core business or it is part of a wider activity in the solar space are in serious trouble. So, this is the step we've taken that means taking on an experienced team that I'm very happy to say in those 6 weeks that have been on board have hit the ground running and expanded our geographic reach, our customer base, have taken that step consciously. And we believe that there will be in the next couple of months and quarters, definitely a lot of consolidation. So, we'll see some other distribution companies probably falling to the wayside. We also expect consolidation among the manufacturers, whether that's modules or inverters and batteries as well. And the last 18 months has pretty much been marked by a collapse of traditional distribution rules. So today, everybody sells everything and basically, it's more about trading than a standard distribution. So, what we do expect is that once there will be consolidation across the entire value chain, that we will go to a more structured market. And what we can say is with this new team, we have newly engaged with the key suppliers of all these type of components. And we are working now very closely with a much larger group of Tier 1 suppliers for modules, batteries and inverters. And we see this approach working. It's early days after 6 weeks, but we've done exactly the opposite. So, we're trying to do things better. And I think at a time where looking at the numbers, you may come to the conclusion that you suggested here, but we believe that our decision to step on the gas is actually the right one, and we are quite encouraged by the results and what is possible next year and beyond. So the next question relates to South Africa. What is the time horizon for projects run in cooperation with RayGen 250 megawatts in South Africa? It is already in early development, but time shows that it is too early even to assess whether this project will be finalized successfully. How shares in this project look like? You reported 250 megawatts. I guess it will be not a part of Photon Energy portfolio. Will it? As far as I remember, there were some other parties involved. Can you please elaborate on that? Is it your plan for not defaulting? Okay. Well, I don't know how these 2 things are connected. But referring to the last sentence -- but I will give a slightly wider context to South Africa because this is relatively new. We started our activities very, very low-ball 2.5 years ago, initially focusing on C&I projects with the initial goal to build for our portfolio. We have changed that, and we're actually sourcing projects and then selling them at a ready-to-build stage through funds that are investing into this behind-the-meter installation. So, we basically find a customer, sign up the PPA and then together with an EPC contract, we sell them on. We've done it now a few times, quite nicely profitable. So from this point of view, our activities in South Africa at a low level, but they are self-financing. We are involved in developing a utility-scale power plant that is in a tender for a PPA with the City of Cape Town, which we believe to conclude before the end of the year. So if we succeed there, we'll have created value. And of course, we have the RayGen project. So, we've identified a location. What we can say? Early development in this case means we have requested grid connection. We've paid the grid connection fee or the valuation fee. And here, again, as well, we expect -- we are very certain or relatively certain that we will get the grid capacity needed. We hope to get official notification unless there's a delay. I think the deadline is before the end of this year. We have optioned the land, and we have started the process of environmental impact assessment. So it is relatively early. But on the other hand, if we have the land, if we have the grid capacity and EIA on the way, we are on a reasonably good track. Yes, I think what we can confirm is that it's unlikely that we will be the investor building such a large plant. But we believe that on the back of our experience developing a RayGen project in Australia, we can replicate it in other countries. And clearly, South Africa is a test case. It's also important to bear in mind that there are 6 operating CSP plants in South Africa. So, concentrated solar is not new. And there are investors -- infrastructure investors that own these power plants, and they are aware of what we're doing. They are aware of the RayGen technology. And I think I would stop by saying there are talks. So clearly, we see an environment where there's enough land, there's enough -- the energy need is there, there's enough sun. And there are banks able and willing to finance renewable projects, but there are also equity sponsors that are experienced in this space. So, a combination that looks quite good. And developing projects in South Africa is from what we've seen so far, quite a lot cheaper than in Australia or even Europe. So from that point of view, this is something that we believe is worth pursuing. We believe that the South African market is worth pursuing and that we have found a way how to generate results with limited risk exposure. So at this point, we're not considering or we're not building any assets that will hold long term. We are developing. And it looks like we found the niches where we can make a return that we can reinvest and build our presence there. Negative profitability in the O&M business. From our private equity activities, we know the profitability of the O&M PV business in general is very low, negative. What is the plan of the management looking forward? And what EBITDA margins does management expect to generate with this segment? So, well, the EBITDA margins that we had in the presentation refer to external business. Here, it's important to bear in mind that we also service our power plants and the fixed costs between those are shared. So, O&M is a business that requires scale because there are certain fixed costs in terms of the back office, in terms of sales. And then, of course, the key resource is the time of technicians. And if you manage -- consider any country, if you manage to grow it in such a way that you have your technicians building close to the power plants that they service, you reduce the time they spend on the road and maximize the time they spend on power plants, and that is what primarily generates revenues. So, you need to grow it. And of course, we are reporting the entire segment. But if I were to walk you through the profitability of the various countries, then I think it's -- we can say that the most profitable country at this point is Hungary, where we have a combination of a not so big country, healthy prices for O&M and already a critical mass of asset base, which we expect to continue growing. And in the Czech Republic, we've been doing this for 15 years, so in Slovakia. We are in Poland. And in Romania, we are still in the start-up phase. And, for example, if I have to describe Poland, we're in a situation where we are now -- we have signed over 400 megawatts, so actually closer to 450 megawatts. But we have so far only taken over 180 megawatts. That number will grow towards 200 megawatts by the end of this year. And we expect the large asset to be taking over and under our management in Q1 next year. However, that contract for that 1 megawatt -- 100 megawatt was signed already at the end of '23. So, there's been a significant delay in the commissioning beyond our control. So, you will have this lag. Of course, the costs we already had. But coming back to the EBITDA margin, for me, from our point of view, the target EBITDA margin for an O&M business once it grows to critical scale is about 20%, where I would say in the case of Hungary, we are more or less there. In the case of other countries, we are still in that process of getting to the EBITDA breakeven. I'm talking about Poland and Romania now. But the path towards that is already clear. And the target, in my view, is definitely around 20%. And if we manage to further grow our scale -- I mentioned adding O&M for batteries. So, I think if we can, through specialization, have more pricing power because unfortunately, solar O&M in some countries is taken as a commodity. We would argue it's not. But very often, there is pricing pressure. But if we basically -- and I think we have quite a few things to offer and battery O&M is definitely one of them to generate sufficient revenues per power plant or per installation. I believe that there's potential for even higher EBITDA margin. And the beauty of O&M is that you have typically sticky contracts. And of course, the capital employed is very low. So, I think we do understand where we need to get. And as I mentioned before, that regional footprint and strategy is paying dividends, and we're seeing this more and more pretty much every month. Will energy storage projects be built within the existing PV portfolio or as separate independent projects? What are the economics roughly of the battery project in the core markets of the company; Poland, Hungary and Romania? So the answer to the first part is both. So, we are looking at adding batteries to existing power plants, even the old ones, but some recently commissioned and some that we are planning to start building. So the issue is that we need to change the grid connection conditions. And if we want to use batteries to the fullest, we need to increase the download capacity. So, a typical PV plant has a lot of upload capacity to supply electricity to the grid, typically megawatts. And then it is download capacity, which is typically very small. So essentially, just to draw electricity essentially at night time to keep the basic systems running, the security system, communication systems. And that's typically 20 kilowatts, 30 kilowatts at most. So if you add a battery, then that -- you would be very much restricted in providing and fully using the battery in terms of drawing electricity from the grid where you could upload, but not download. And when you think of ancillary services, you want to be able to do both. So basically, we have to go back to the -- and we're doing this at the moment for 2 existing power plants in Hungary. We have actually been working on this. Our team has been working on this for pretty much a year, and it is quite a tedious exercise. And so it's almost as if you ask for new grid capacity and maybe even more complicated. So yes, we are working on this in Hungary. In Romania, we're looking at how it can be done. In our Czech portfolio, we are, at the same time, looking at developing storage only or maybe in some cases, we may even want to acquire one. In terms of the economics, this is something where we have a -- I would say, one of our key assets is a team that really understands what goes into -- what you need to consider in a battery investment. And that is both in terms of the technology to choose, how to operate those batteries, but also then what is the value, how do you assess the value or the revenue potential, the revenue stack of a battery in various types of settings, whether that's battery only, whether it's part of a PV plant or maybe even behind the meter. So, this is something we can -- I mean, I can't give you now the exact numbers. At the moment, what I can say is at the moment in terms of prices for ancillary services, Poland is extremely attractive because the prices are very high. The market started in mid-June last year and prices are very high. We are in pole position, and I think I cannot mention it often enough. We are in pole position to be the first aggregator for ancillary services in Poland. We were the first one certified by URE. We have the regulator. Of course, in the meantime, a few others have also been certified. But in terms of actually then taking the next steps of integration with PSE, the Polish TSO and having the first asset that we'll be using to provide ancillary services certified, I believe we are ahead of so far everyone else. So, what we're looking at is -- and what very -- what gives us -- we see as very positive is that there will be a period of time, whether it is 1 month or a couple of months before competition moves in. And there's quite a lot of flexible assets in the Polish market, and these are, in some cases, batteries, but it can be biogas. It can be other sources that want to participate in this market. And we believe that we will have a window of opportunity where we are the first and only aggregator. And this is where a lot of our focus is going now to actually grab that market, to make sure that even when competition moves in and 2 years, 3 years, 4 years from now, we will still be the most important player. And in Romania, so if you compare the prices for ancillary services, Poland is the highest, followed by Romania and then Hungary below that. And ancillary services in the Czech Republic are actually the cheapest. Well -- so maybe 2 more questions. One question is, could you please explain the position; liquid assets with restriction on disposition? This is very easy. These are reserve accounts that within the project financing arrangements, we have with our project financiers that we have to create reserve accounts. The most important one, the so-called debt service reserve account. So basically, we are, in most cases, repaying these financings on a quarterly basis. Typically, these are amortized structures. So basically, part of it is repayment, part of it is interest for the previous quarter. And in order to make sure that if there is a shortfall in generation or delay in receiving revenues, these payments to the financing bank can be met. We have to set aside. And what typically happens at the beginning of the financing or we have to basically take excess cash flow from the project in the first 1, 2 years, 3 years, 4 years and set them aside to have money ready. Typically, it is somewhere between 3 months and 6 months of debt service. So, basically, what we have to repay in a quarter or 2 quarters has to sit in a separate bank account. We cannot access that money. So, we cannot work with it. So it's restricted. Our access is restricted. In our case, it adds up to a few million euros. Very last question. What are the current market valuation ranges of 1 megawatt PV connection to the grid in 2024? And what would be a valuation range of 1 megawatt peak in Stage 4. Well, this really depends by market. I think what we can say is what we've observed is that over the last 6 months to 12 months, the value or the prices of project rights have been going down in the markets where we operate. I would say somewhere between 20% and 30%, 40% in some cases, depending on what type of projects they are and again, market by market. And the reasons for that are multiple. But now, with the very low CapEx based on the low module prices, low interest rates and growing energy prices, I would expect that we'll see a recovery in project values. Again, there we are probably depending on market, somewhere between EUR 80,000. In some cases, probably something closer to EUR 150,000 per megawatt peak. So unfortunately, we cannot answer all the questions. We will try to address them in a different forum later. And so I would like to thank you very much for your attention today, and I wish you a very nice rest of the day. Thank you.