Hello, everyone. Now it's 12:00 P.M. sharp, so, it's the official starting time for the presentation. But as usual, I propose we wait a couple of minutes or even more than that, like five minutes, to allow more people to connect to the call. Our proposal is to actually start the presentation, start the call at five minutes past 12:00 P.M. Thank you. And one more thing, if you don't mind, can I get a quick confirmation that both audio and visual are okay, and you can see, you both hear me and see the cover page of the presentation? Yes, it's fine. Okay, thanks. Now, it's five minutes past 12:00 P.M. I think that was sufficient time allowance for other people to connect to the call, so we propose to start the conference call. Ladies and gentlemen, let us just greet you. Good afternoon, and welcome to Transelectrica's analyst call covering our first half 2026 financial results. Joining today's call from Transelectrica are my colleague, Ana Iuliana Dinu, she's the Head of the Financial Division, and myself, Adrian Suta, Head of Energy Regulatory Affairs, and currently, also acting as Investor Relations Officer. Before we begin, a few housekeeping remarks and rules as usual. Today's call will include two main sections. The first section is a presentation on our end for the first half results, covering a number of topics. I'm just going to go through them. We are going to touch on key highlights, financial performance, and underlying drivers. Grid losses. We will be diving into grid losses and cost dynamics. We will be also discussing pass-through operations, and finally, the final chapter of the presentation, investments. The second part of the presentation is dedicated to a Q&A session. In terms of housekeeping, we would kindly ask you to keep your microphones muted during the presentation part of the call, unless you would like to ask a question or make a comment while the presentation is unfolding. Questions are welcome at any point during the presentation, so feel free either to jump in verbally while the presentation is being delivered, or simply drop your questions in the chat box. Both options are perfectly fine for us. Depending on the question and the flow of the presentation, we may address it immediately once we receive it, upon receipt. We will pause the presentation and discuss the question at hand, o r we may allow the questions to accumulate, to stack up, and address them together during the dedicated Q&A session at the end of the call. The default language setting of the call is English. But as an exception, if all participants are Romanian speaking, we can switch to Romanian. Otherwise, we will obviously stick to English and continue using English language for the remaining part of the presentation. Before we proceed, may I kindly ask any non-Romanian-speaking participants to identify themselves. We are making this call in order to identify the proper way to set the language setting for the call going forward, beyond this point. I can see at least one name that does not resemble, does not seem to fit into the profile of a Romanian name. Please do let us know, make us aware that you are connected to the call and you are non-Romanian-speaking persons, so we do not switch to Romanian and we stick to English for the remaining part of the presentation. I was actually referring to, I see a name, [Karen Johansson], that does not seem to be a Romanian name, so please, Mr. [Johansson], please let us know if you are a Romanian-speaking person or a non-Romanian-speaking person, so we can properly define the language setting of the call from this point forward. Okay. In the absence of any input from your side, from your end, in terms of preferred language setting, I think it is safe to continue in English. As far as there is also a possibility that other non-Romanian-speaking persons might join the call at a later stage of the presentation. We will keep English as the standard language setting for the call. Okay. Next, I am just going to shuffle through the slides now. We will start by providing the major highlights, what happened in the first half of 2026. In a nutshell, we will try to be as short, as concise as possible and put the spotlight on the most relevant developments in the first half of 2026. Just as a reminder, we usually split the P&L discussion into two separate sections: the profit-allowed operations, what we commonly refer to as core operations, and the pass-through section of our P&L. With one specific remark that the pass-through section is a sort of conceptual reference to this section of our P&L, as non-zero financial results within this particular section of our P&L are possible. But the underlying regulatory principle that defines the regulatory regime is that over the course of time, over a multi-year framework, any gains or losses incurred in one financial year tend to be evened out using regulatory defined ex post correction mechanism. There are true-up mechanism embedded into the current target setting regulation by the Romanian regulators that enable any deviation from financial neutrality principle within an annual financial exercise to be compensated, to be neutralized, to be offset over the next years. Starting with the core operations part of the profit- allowed operation, the main highlights are the following. We have a stronger year-on-year core profitability, and we refer to EBITDA that was up 32%, which was mainly driven by higher cross-border congestion income, +74%. It was 74% up congestion income in the first half 2026 as compared to the previous year. This was actually the same main driver in both quarters of 2026, both in first and second quarter. In terms of tariffs, tariff revenues also remained stronger year-on-year. The higher tariff level, up by approximately 11%, more than compensated for a 2% reduction in billed volumes over the first half. The volume effect became more visible in the second quarter of 2026, when tariff volumes were approximately 5% below year-on-year, after being broadly flat in the first quarter of 2026. Actually, after a strong year-on-year increase in the first months of 2026 in January, tariff volumes in the next five months, February to June, have declined at a more pronounced pace in the second quarter, in April, May, and June specifically, with prosumer self-consumption, so it is basically behind the meter rooftop photovoltaic electricity production that is used on site behind the meter, as the most likely driver, as rooftop PV capacities are continuing the upward trend. In terms of grid losses, grid losses costs increased year-on-year, reflecting both a higher physical loss factor and higher average purchase price from the open market. The first half loss factor was 2.49%. Just a reminder, the loss factor is calculated by dividing the actual energy volume that is lost during the transmission process, divided by the total energy intake throughout the analyzed period. The 2.49% loss factor for the entire first half of 2026 compares with the 2.14% in the first half of 2026, w hile the cross-market average purchase price increased in 2026 by approximately 14%. These higher costs were compensated at the level of core operations by stronger tariff and stronger congestion revenues. Now, making the transition to the pass-through operation side of the slide, the first half generated a gain of approximately RON 85 million, which the year-on-year improvement concentrated in the second quarter. Importantly, this does not reflect a significant quarter-on-quarter change in the underlying 2026 performance, but rather, a base effect from the second quarter of 2025. More specifically, June 2025 saw a sharp increase in balancing capacity procurement cost as balancing capacity prices surged. This was driven particularly by strong demand from downward regulation back in 2025 against a background of significant energy surplus in the system associated with abundant photovoltaic and hydro generation last year. The stronger year-on-year result in the second quarter of 2026 should therefore be viewed primarily as a normalization against the unusually weak comparison base back in June 2025, rather than a material change in the underlying trend between the first and second quarters of 2026. The current first half pass-through gain, RON 85 million, substantially offsets the sizable regulatory backlog of approximately RON 100 million accumulated over the past two years, 2024 and 2025, that we need to recover. One worth mentioning thing is that the next tariff review is scheduled for 1st of October 2026, and based on the current cost and revenue trajectory, a tariff reduction is expected in order to bring pass-through revenues more closely in line with actual costs. Actually, the second quarter of 2026 is expected to fully bridge the remaining gap between the recovery backlog of RON 100 million and the gain that was earned in the first half of 2026. So, at nine months 2026, we expect the backlog of RON 100 million to be fully recovered. As a remark, there was a change in regulation under the new regulatory calendar. Tariff reviews will take place every six months, starting 1st of October 2026, and with regular reviews on 1st of April and 1st of October. Now, moving to the next slide. We will be diving into the structure of revenues. Total operating revenues increased by approximately 11% on year-over-year basis to around RON 3.25 billion. Now, looking specifically at profit-allowed operations, revenues increased by approximately 19% to RON 1.37 billion. The main drivers are transmission tariff revenue increased by approximately 8% to around RON 1 billion. The approximately 11% increase in the tariff more than offset the 2.3% decline in bill volumes. Cross-border congestion revenues increased by approximately 74% in the first half of 2026 to around RON 263 million, remaining the most important positive driver of core profitability. Transelectrica also recorded additional revenues from emergency energy assistance provided to neighboring countries. As a reminder, balancing capacity and balancing energy are pass-through activities and are neutral for Transelectrica over time, although their settlement mechanisms differ. Balancing energy is settled dynamically through the balancing market and imbalance pricing. Balancing capacity, by contrast, is recovered through a regulated tariff based on forward-looking assumptions for procurement costs, reserve volumes, and tariff volumes. Deviations between actual outcomes and tariff assumptions therefore generate temporary regulatory gains or losses that are subsequently corrected through tariff adjustments over the next years. With that said, let's move to slide six and deep dive into costs. Operating costs within profit-allowed operations increased by approximately 11% year-on-year to around RON 824 million. The main driver was, again, grid losses. The gross cost of energy purchase for grid losses increased by approximately RON 68 million or 24% year-on-year. Now, it's usual to distinguish the gross purchase cost shown in the chart from the net economic cost of grid losses. Transelectrica may sell excess energy purchases back into the market. After deducting this sales income, the net cost of grid losses in the first half of 2026 was actually a bit higher than presented in the chart. It was RON 75 million higher year-on-year. Now, moving further to deep dive into grid losses. The first half grid loss factor, if we look at the left side of the slide, we see some percentages there. The first half grid losses factor was 2.49%. That compares with 2.14% in the first half of 2025. The loss factor improved slightly during the second quarter of 2026, declining from 2.6% in the first quarter to 2.36% in the second quarter. However, the aggregate loss factor for the first half or the first six months of 2026 is still well below the regulatory cap, which was set by the regulators of 2.26% for the entire 2026 year. As noted previously, during previous presentations, on different occasions, this cap is an annual average and should not be applied mechanically to individual fractions of the year, quarters or half yearly. The first half result, therefore, does not, by itself, determine the full year regulatory outcome. In volume terms, grid intake during the first half was approximately 20.76 TWh, and grid offtake approximately 20.24 TWh, resulting in grid losses of around 0.52 TWh in absolute terms. Now, going to the midsection of the slide, we will take a look at purchase prices. Starting from top to bottom, the average forward market price was approximately RON 560/MWh, which is up 17% year-on-year. Now, moving down to the average day-ahead market price, it was approximately RON 645/MWh, broadly flat year-over-year. The average balancing market price, we don't have a specific chart or dedicated chart for that. You see in the base section of the middle section of the slide, we see the average balancing market price was approximately RON 926/MWh, which is down with around 4% compared to previous year. Now, moving to the right-hand side section of this slide. Across all procurement markets, the weighted average acquisition price was approximately RON 651/MWh, which is around 14% higher year-on-year. Now, looking at the donut, or the pie, or the donut charts on the top right section of this slide. The procurement mix was also shifted compared with the first half of 2026. Approximately 50% of total grid losses volume were purchased on forward markets, 37% on spot markets, and 12% on the balancing market, c ompared with 62%, 30%, and 8% respectively, one year earlier. Now, going beyond what is being provided in terms of data and trends on this slide. As a relevant post-reporting period development, Transelectrica had contracted a total of 60- MW base load profile for grid losses coverage for the whole year, from 1st of January to 31st of December, w hich was built up from volumes contracted with several suppliers in the wholesale market. But following the activation of force majeure by Nuclearelectrica, as they were forced to shut down both nuclear reactors at the power plant Cernavodă, c ontractual delivery of 30 MW representing 1/2, 50%, of the total contracted base load in our grid losses energy portfolio, has been temporarily suspended for the period between 13th of August and the end of August, so basically 19 days. The resulting 30- MW shortfall will most likely need to be replaced through purchases on the spot market, temporarily increasing Transelectrica's exposure to spot electricity prices for grid losses procurement during the contract suspension period. At this stage, however, we do not see a significant risk that the other suppliers covering the remaining 30 MW of the contracted base load will invoke force majeure or otherwise fail to meet their contractual delivery commitments. But once again, this is the situation 13 August onward. This doesn't affect the first half of 2026. Now, moving to the next slide, when we deep dive into EBITDA formation. EBITDA from profit- allowed operation increased by approximately 30% year-on-year, from around RON 410 million to around RON 541 million. The main positive driver was a strong increase in cross-border connection revenues. Higher transmission tariff revenues were also contributed and compensated for the high grid losses cost. Pass-through operations contributed a +RON 85 million in the first half, compared with approximately RON 46 million in the first half of 2026. As a result, reported EBITDA for the company increased by approximately 37%, from RON 456 million to RON 626 million. The second quarter confirmed the underlying trends. The profit- allowed EBITDA increased by approximately 32% year-on-year, while total reporting EBITDA increased more strongly due to negative pass-through contribution of the weak comparison base back in the second quarter of 2026. Now, we move further to net income decomposition. So, at net income level, net income increased to approximately RON 356 million in the first half of 2026, c ompared with RON 256 million in the first half of 2026, representing an increase of approximately 39%. The main driver was the stronger EBITDA generated by profit-allowed operations, particularly the increase in cross-border congestion revenues. The positive contribution from pass-through operation also supported the year-on-year improvement. EBIT increased to approximately RON 427 million, while earnings before tax reached approximately RON 438 million. Looking specifically at the second quarter, net income was approximately RON 153 million, compared with RON 99 million in the second quarter of 2026. Now, going further and moving to investments delivery in the first half of 2026. Approximately RON 262 million of new investment contracts were signed, that you see on the top section of this slide. In the middle section, approximately RON 306 million were added to construction work in progress. And approximately, moving further down to the base section of this slide, approximately RON 44 million of assets were commissioned and transferred from construction work in progress to fixed assets. Among the more significant items delivered or progressed during the period were two motor reactive power compensation units for voltage regulation, and also, grid connection works for new renewable generation, and also, the modernization of the substation at Isaccea. Major contracted projects also include the modernization of a substation at Medgidia Sud, a cloud communication network and telecom solution for the emergency dispatch center, and also, an autotransformer for the Midia substation. So, now, just to conclude before switching to the Q&A session, just to wrap it up quickly, so c ore regulated operations remain quite strong, with profit- allowed EBITDA increasing by approximately 32% year-on-year. Cross-border congestion income remained the main positive earnings driver, increasing by approximately 74% against last year. High tariff revenues compensated for both lower tile volumes and higher grid losses costs, and pass-through operations generated an approximately RON 85 million first half gain, substantially offsetting the recovery backlog accumulated in 2024 and, more importantly, in 2025. The next tariff review for ancillary services tariff is scheduled for 1st of October 2026, with a tariff reduction expected to realign revenues with actual pass-through costs. Reported EBITDA increased by approximately 37% and net income by approximately 39% year-on-year. So, basically, I think, we pretty much covered the key points of the presentation of the financial performance and the underlying operation and the market developments during the first half of 2026. Thank you for your attention to the first section of the presentation today, of the call today, the presentation, and we will now open the floor for questions. I am just going to quickly check for a text box so I can see if anyone dropped questions there. I do not see any questions dropped in the text box. I see one raised hand, so, Irina Răilean, please shoot. Ask your question. Hello, thank you for taking my questions. I have several questions regarding different, I think, important topics. The first one is regarding the system services. We kind of expected a rather positive tariff adjustment starting October, but things changed. If you could detail a bit, this means that you will recover in the third quarter the remaining backlog, the whole one, and should we expect, in this case, a significant positive EBIT for zero profit segment in Q3? Am I right in this case? Why the tariffs will decrease? I mean, will the costs also decrease? Do you expect this? Why the regulators may decide to reduce the tariffs? Yeah. In terms of ancillary services tariff, the pass-through section of our P&L account, what I mentioned is that we are currently generating more revenue based on the tariff that was approved by the regulators at the beginning of 2026. We are steadily progressively recovering the backlog originating in 2024 and 2025. In the first half of 2026, a good fraction, the majority, the bulk of that backlog has already been offset in the first six months. So, it is 80. What is the remaining figure for 30 June? For the third quarter, July to September, the remaining backlog to be bridged, so the remaining gap between the entire backlog, the full amount of the backlog to be recovered and the amount that we have already recovered in the first six months, is the difference between RON 100 million, the full backlog, and the RON 85 million profit that we earned, the RON 85 million we gained in the first six months. Based on the current revenues and cost trajectory, we expect the recovery of the backlog to continue in July, August, and September. By the end of September, we expect the full amount of the recovery backlog to be fully offset. The difference between the full backlog of RON 100 million and the RON 85 million, we have already recovered is RON 15 million. We estimate that this particular amount will be fully covered in July, August, and September. So, basically, the underlying rationale is that if we keep the tariff in place from the 1st of October forward, we will be generating additional profits in the fourth quarter of 2026. The tariff needs to be, once we fully recover the backlog, the recovery backlog from the last two years, 2025 and 2024, the net recovery amount, the tariff should be realigned with the actual costs. In 2026, the tariff provided significantly more revenue as compared to the actual expenditure incurred by Transelectrica when purchasing ancillary services in the balancing capacity markets. Keeping the tariff in place makes sense up to the point in time where the full backlog amount is eventually recovered, and that we expect to happen by the end of September or even sooner. But beyond the 1st of October, keeping the same tariff in place that generates significant profits on a monthly basis doesn't make sense, because t he underlying rationale is for the tariff in place to help us recover the backlog from 2025 and 2024, and then, the tariff should be perfectly realigned with the actual costs. This kind of implicitly means that costs have decreased in Q3 compared to last year, which was a quite different quarter, let's say, third quarter. Yes. Actual costs are lower than what happened in 2025. In 2024, 2025, we had a surge. Price was soaring. Starting May, June, and July, market participants took full advantage of some balancing capacity market structural, you know, not failures, but we do not really have significant competition for some particular products in this market. Market participants took full advantage and prices, the bids they placed in the balancing capacity markets, the prices rocketed through the roof. That happened last year in May, June, and July mostly, and that was the reason why costs were significantly increased in 2025. Now, the tariff was increased. The prices cooled off in 2026. The current tariff that is in place today helped us already recover a significant percentage of the overall recovery backlog coming from 2025. At the end of September, we estimate that this recovery of the backlog will be fully finalized. So, it does not make sense. To keep the tariffs high. To keep the tariffs at the same level that provides significant monthly gains. Okay. Thank you. In terms of grid losses, for the whole year, to meet the regulatory cap, Transelectrica needs to keep the grid losses at around 2% for the second half of the year. Is that doable from what you know about the technical parameters and what could happen in the second half of the year? If not, if this target is not achievable, what then will happen at the next tariff revision? Well, your calculation is correct. In order to balance the first half with the second half, in order to contain grid losses percentage within the regulatory cap that was set for 2026, the second half should land somewhere around 2%. That's not really impossible statistically, but I would say, it is rather unlikely and basically out of Transelectrica's control. There is little thing the TSO, the operator of the national transmission grid, that can be done in order to say we have, m aybe not full control, but no significant level of control of the loss factor and the loss volume. It very much depends on factors that are completely outside the TSO's control. It very much depends on the structure of production. Also, it very much depends on meteorological condition, on the level of precipitation in summer, autumn, and winter. It also is very much dependent on the structure of cross-border electricity flow. So, it's not something that we can control. We can only look back at previous years. Based on statistics, it is possible, theoretically possible, it's not something that we exclude, we rule out that the second half of 2026 might be able to fully balance the high grid losses factor number in the first half, but I would assume it is something that we should rely on as base scenario. The most likely outcome of 2026 is that the actual full year grid loss percentage number will be above the regulated target or grid loss. What will this imply for the tariff set next year? Or how will this? There will be no positive correction in terms of grid losses. That is the outcome, or that is the result of exceeding the regulatory cap. Neither regarding prices? I mean, one factor is quantities, but what about prices? In terms of prices, prior experience shows us that in terms of pricing, based on the current regulatory regime, in terms of limiting not only volumes but also prices, we usually rank below the average of the Romanian electricity network operators. That is the benchmark that the regulator uses. We usually outperform the other distribution operators in Romania, so not really a big concern in terms of prices, but there is a significant probability, there is a significant likelihood that in terms of physical loss factor, that we probably land, at the end of the year, somewhere above the regulatory cap. But this means that also no negative correction. This will not negatively impact tariffs. No negative. Just no positive adjustment. No positive adjustment, no negative adjustment. Okay, thank you. Expenditure that is above the regulatory cap, so unrecovered expenditure. Unrecovered. All right. Regarding this first measure by Nuclearelectrica, what is the difference between the spot price and the contracted price for these 19 days? I know we can talk only about the next probably two or three days, because the price is volatile, but w hat do you see until now? Is there a big difference between spot price that you will need to buy electricity at and the contracted price? Okay. I will just go through some supporting slides we prepared for this presentation, just to give you some insight into the grid losses hourly profile, monthly profile, and purchase prices. Let me just check if this is the right. Yeah, this is right. This slide shows you the first half of 2026, January to June, hourly average profiles for grid losses in terms of megawatt hour losses, in terms of volumes. As you can see, the blue line shows you hourly averages per each month. The grid losses amount per each hour within each month is different across the 24 hours of the day. It actually mirrors the overall demand for electricity at system level, at national system level. You see, we have smaller grid losses amounts, grid losses volumes, during the night, and we have usually a morning peak and an evening peak. That follows the shape or the profile of general electricity consumption nationwide at system level. The dotted yellow line shows you the average price in the day-ahead market. All of this is the ahead market data. No, sorry, this is quantitative data. This is the losses volume profile, hourly profile. At the base of each monthly chart, you can see our 60-MW base load stack of long-term contracts. Half of that, if we consider first the base one between zero and 30 MW, the other suppliers within our grid losses coverage acquisition portfolio, purchase portfolio, purchase contracts to cover grid losses, and the more transparent, the more translated band that is on top of the base one corresponds to Nuclearelectrica. What basically means is that we will not be having, starting 13th of August until 31st of August, so 19 days, a suspension of Nuclearelectrica's commercial contractual obligation to delivery of electricity at the contractual price. Means that we are currently paying Nuclearelectrica roughly EUR 100 and something per megawatt hour, and we will have to replace that in the open spot market. In terms of what is the potential impact of this, of course, we cannot really provide an accurate ex ante determination of this impact, but we can do a rough calculation. We have 19 days between 13th of August and 31st of August, when the contract with Nuclearelectrica is suspended due to force majeure. We have 19 days multiplied by 24 hours a day, multiplied by 30 MW that was suspended, and we have to multiply by the difference between spot price and contractual price. Let us just imagine what a reasonable assumption for average daily spot price will be between 13th of August and the end of August, 31st of August. If we look at average monthly prices, we see January, EUR 140 per, n o, sorry, l et us just go to prices now. Prices. January, EUR 150/MWh as an average price. February, EUR 99/MWh, roughly EUR 100/MWh. March, April, May, June, July. Let us look at August. We have partial data covering the first 14 days of August. These are data that were retrieved from the European ENTSO-E Transparency Platform, the day-ahead market prices. We are currently looking at EUR 150/MWh. Let us just, I don't know, assume that day-ahead prices will increase further to an average of EUR 200/MWh, or EUR 250/MWh, let us say. We paid Nuclearelectrica EUR 100/MWh. So, the premium we will be paying due to our additional exposure to spot prices will be the difference between, let us say, EUR 250/MWh and EUR 100/MWh. So, EUR 150/MWh as a premium we will have to pay during the suspension of the contract. I understand. The underlying volume is 30 MW multiplied by 19 days, multiplied by 24 hours. So, in the end, it comes down, if we perform this calculation, the maximum, let's say, impact will be EUR 2 million. Maybe less. It very much depends on the assumption we use in this rough calculation, simplified calculation we are doing right now. We are anticipating the future evolution of the prices until the end of August, between 13th of August and 31st of August. But you can look at the bottom right section of this slide, just below the monthly chart for August. We also have daily prices for the 13th of August and the 14th of August, that is today. These two days correspond to days where we have absolutely no nuclear generation injected in the system. The prices didn't rocket to above EUR 200/MWh. In the previous calculation we performed live here, we used an assumption of EUR 250/MWh until the end of August. Yeah. It all resulted in just EUR 2 million as an additional total cost due to the premium between the Nuclearelectrica contractual price and potentially higher spot price of EUR 250/MWh. Thank you. Thank you for the detailed calculations. One more question regarding the current energy crisis in Romania. How is this impacting Transelectrica in terms of, I do not know, you may know better, grid losses, interconnection revenues? What else should be taken into account when thinking about how the company is impacted? Well, I think we have to split this in direct impact and indirect impact. Obviously, direct impact on Transelectrica, we can look at grid losses. I think we pretty much covered this topic. Obviously, if we consider also voluntary consumption reductions by populations and businesses, that will obviously have an impact in terms of lower tariff volumes for Transelectrica, but that is only marginally significantly lower than the impact on grid losses that we have covered earlier. These are basically the direct impact on Transelectrica's financials during 2026. In terms of potential activation of the special measures that have been approved by the Romanian government by issuing two government ordinances last week, if the national dispatch centers increases the amount of reserves, obviously, there will be some additional costs in August to be able to safely handle this situation from a system operations point of view, but we do not estimate significant additional cost if needed. Then, if we switch to cross-border capacity and in the sequence of emergency measures that have been recently approved by the government, Transelectrica, under certain very specifically defined conditions, is able to both limit the amount of cross-border capacity, export capacity from Romania to neighboring countries, and u nder tighter and heavier energy stress, we are also able to cancel capacity that was already allocated to market traders to export electricity from Romania to the neighboring countries. That will obviously lead to a reduction in cross-border congestion income, but we do not estimate that to be material, to be significant, and to have a sizable impact on 2026 financials. Okay. Thank you. Regarding the investments, the CapEx, I saw quite low commissioning in the first half of the year, although, you seem to have signed some contracts or new agreements regarding CapEx. If you can make a bit short update regarding the key large projects that will be commissioned this year and will impact the regulated asset base starting January next year. What can we expect there? We expect the second half of the year to add significantly more CapEx and finalized assets, as compared to the first half of the year. I do not have accurate estimation for the second half of the year at my fingertips, but definitely, it will be better than the first half of the year. I might be mistaken, but I think this is actually a historical pattern. If we look at past years, I think the biggest amounts of commissioned assets and capital expenditure happen in the second half of the year. I am not able to provide a full year estimation in terms of total capital expenditure and total amount of asset commissions at this point in time. Will it at least outpace the regulated amortization? For 2026, the regulated depreciation is definitely higher than just estimating 2026 in terms of 44 asset commission in the first half multiplied by two. The order of magnitude of the annual regulatory depreciation, I think, stands below RON 250 million. Okay. What else should we take into account when thinking about how the tariffs might evolve next year? We talked today about grid losses, that we cannot expect a positive correction. In terms of regulated asset base, we can probably estimate a decrease in the regulated asset base just because depreciation outpaces possible commissioning of assets. What other adjustments or corrections do you expect or do you see up to this date regarding the regulated revenues and tariff revision? Well, for the tariff review for the next year, for 2027, we need to take into account that a couple of things will happen. We have that special regulatory account for the extremely high gap between the actual price we paid for electricity for grid losses in 2022 during the energy crisis and the revenue allowance we had embedded into the transmission tariff in that particular year. But that is gradually phasing out. It is being phased out. So, we have increasingly smaller amounts to recover from 2022 to 2024. It was a bigger period, an extended period, but most of that regulatory account backlog to be recovered originates in 2022. So, this is an element that we should consider in estimating 2027. Do you have the amount of approximately how much you will recover, or do you expect to recover next year? I don't have the exact amount at my fingertips, but it would be significantly lower than the amount that was incorporated in 2026 transmission tariff. On the other hand, we have significant negative corrections coming from 2025, mostly from grid losses. We had a grid losses revenue allowance embedded into the regulated income approved by ANRE that was higher than the actual grid losses cost that we actually incurred in 2025. So, we will be having significant negative corrections from 2025, combined with descending amounts of grid losses recovery backlog from 2022. Our best estimate now for 2027 is that the tariff will basically remain roughly flat, maybe a bit higher, maybe a bit increased as compared to 2026. Maybe, perfectly flat or maybe even a bit lower than 2026 due to these reasons. Okay. Thank you. Understand. I think the baseline scenario should be that the tariffs for 2027, the transmission tariff is, I think, a flat assumption is the best baseline scenario. Single digit, up to 10%, up to 5%, maybe around plus, minus. I think that range of ±1 0% is too large. Right. Actually, I think, the range of ± 5% is also too large. Okay. I understand. Thank you very much for your answers. You are welcome. Anyone else who has questions related to what has been presented during the presentation part today, or something that you would like to deep dive from the financial statements that were posted on our website this morning? We are waiting for questions. One more from my side, if I may. I just wanted to, I remembered to ask about these strategic projects that you have with under Black Sea Cable connecting with Georgia and the other one connecting Black Sea with Hungary. There are two separate projects that I see. Those are two separate companies, joint ventures. I would like to ask you about if you have any updates and also what will be, or what is the practice in the industry in terms of monetization of these kind of projects? Will they fall under the regulated asset base? How will they be regulated and monetized? Those specific questions are very valid. We do not have answers to those questions at this particular time. Currently, both cross-border projects, and by both, I refer to the Black Sea crossing, connecting Romania to Georgia, but we also have a wider project, which is named the Green Energy Corridor. We might have heard of that one also. That is a wider project that connects the South Caucasus region, the Caspian Sea region, with Central Europe, and it implies building a massive transmission corridor asset spanning from Azerbaijan to Hungary, and also crossing Georgia, also Black Sea crossing, and with a landing point in Romania, and the continuation of the infrastructure of this corridor from Romania to Hungary. That is a bigger, wider project. Those projects are currently being evaluated in terms of market benefits and costs, the ratio of benefits to cost at European level. The Black Sea Submarine Cable connecting Romania to Georgia is a bit more advanced as compared to the wider, larger project, but both are still under consideration. No final investment decision has been made, and obviously, one key element or key factor into building the architecture of the project is defining how the project will be financed, and h ow the project will be regulated in terms of how costs will be recovered. There are basically two options, maybe a third one as well. The first option is for the whole project to be accommodated under a full regulated regime. But if we look at the magnitude, the size of the CapEx requirement to implement this project, deploy this massive transmission corridor, it stands at above EUR 10 billion, spanning across Azerbaijan, Georgia, Black Sea, Romania, and Hungary. Not only Romania, obviously. But I think it's safe to assume that the magnitude of funding required to implement this project is a bit outside the TSOs link, you know, t he Hungarian TSO, the Romanian TSO, the Georgian TSO, and the Azeri TSO. I think it's safe to say that this is something that goes beyond their capacity to fund such project. Also, I think, also, the national regulators in the four countries, the two Caucasus countries and the two European countries, Romania and Hungary, will probably be a bit reluctant to accommodate this massive infrastructure project under a full regulated regime, as that regime will involve putting a lot of pressure on national transmission tariff in each country. So, there is a second option to accommodate such project. It's commonly referred as commercial model or merchant model, and that basically involves that no CapEx will be added to the regulated asset base of national TSOs hosting the project. Instead, it will be a fully private investment that will not be putting upward pressure on tariffs at all, and the investor will be recovering the capital they will invest by simply wheeling electricity, by buying and selling electricity at a higher price, buying low price in Caucasus and selling higher price in Europe, or just by collecting the cross-border capacity income, the cross-border congestion capacity income. That is the option that is probably going to be preferred by all national energy regulators across all the Green Energy Corridor geographical scope, Hungary, Romania, Georgia, and Azerbaijan. And there is also a third option that is basically a combination of mix of regulated and merchant. This is something that is currently being explored, is being thoroughly examined to strike the balance, to find the right balance between a regulated regime and a fully merchant or a commercial regime. It's still work in progress. All the options are still on the table, are being thoroughly analyzed. The project has not advanced so far to a point where this particular aspect, this particular very important topic of the project, how it will be accommodated in terms of business model and cost recovery model, will be eventually defined. Thank you. You are welcome. If in case you have any further questions, any additional questions, just shoot them and we will try to answer them as concisely and as to the point as possible. If no further questions from your end, we would like to thank you once again for taking time to participate to Transelectrica's half-yearly analyst call, and good luck to you all. I am sure you have a very busy period compiling information and numbers coming from several different multiple companies within the energy sector. The next quarterly analyst call is scheduled mid-November. So, once again, thank you for the interest in Transelectrica's financial results. Good luck. You have a very busy period and see you soon at mid-November for the third quarter release.