CNTEE Transelectrica SA (TEL) Earnings Call Transcript & Summary

So welcome to Transelectrica's First Half 2021 Conference Call's Financial Results. First of all, let me take a chance to present the team we assembled on our side. So we have my colleague, [ Anna Ileana Dino ], on the financial side. She has the financial division, accounting taxes, treasury, financial planning, pretty much everything that is important in the company; and myself Adrian Suta, Regulatory Affairs and Acting Investor Relations Officer. So as you know from previous earnings releases and the previous calls, the presentation -- this conference call will consist of 2 parts. In the first part, we'll try to make it very short, concise and to-the-point. We will present the relevant developments in the first half of 2021. And in the second part of the presentation, we will have the Q&A session. We strongly encourage participants to the call to engage in discussions with us. So we -- basically, we take questions during the presentation part of the call as well. Obviously, if you prefer, you can keep the questions and engage in discussions -- in the discussion in the second part of the call, that is the Q&A session. During the presentation part of the call, you can engage in discussion either by jumping in verbally, you can simply jump into the discussion or you can send your questions by text using the chat box provided by Zoom. So that is pretty much the organizational settings for the conference call. We will start by with the first part that is the presentation. We'll go through the slides. Firstly, we will take a look at the operational side of the business. So the demand for electricity in the first half, the production of electricity, the domestic production of electricity and the cross-border flows. What we've seen in the first half is basically a full post-COVID recovery of consumption of electricity in Romania. A full post-COVID recovery -- by full post-COVID recovery, we mean that we have seen a big sizable increase in electricity consumption as compared to last year, but also a slight increase in the demand for electricity as compared to pre-COVID levels, that is 2019. So on a year-over-year basis, the electricity consumption in Romania jumped 7.5% first half 2021 as compared to 2020 too. The most part of this came from the second quarter, obviously, but you need to take into account the base effect of COVID lockdown that was activated last year in mid-March in Romania. So basically, second quarter is plus 20 -- 12% on a year-over-year basis. Both first quarter and second quarter, if we compare the consumption -- the electricity consumption level with 2019, both quarters are up 1-point-something percent. So first half 2021 versus first half 2019, the electricity consumption went up 1-point-something percent. When we talk about the generation of electricity, the domestic production of electricity, we have seen a solid bounce back of production of electricity, especially in the second quarter of 2021. So also in terms of electricity production of national electricity production by power stations, power generation plants that are connected to the Romanian power system, we have seen a full recovery from last year. Just as a reminder, last year, once the COVID lockdown was activated in mid-March, we have seen a steep decline in electricity consumption and a steeper decline in electricity production in domestic electricity production last year. So it seems like generation is back on track. It should basically bounce back to 2019 levels. In terms of cross-border flows, we are back to net export for a change after 1.5 years of net imports. The first quarter of 2021 was still a net import electricity, so we imported more electricity in Romania as compared to the amount of electricity that was exported to neighboring countries. In the second quarter, we had exported electricity. Okay. So now a few words about what happened in terms of financials. So that is the operational background of the first 2 quarters of 2021 as compared to 2020 and the pre-COVID levels in 2019. How has that impacted our financials? So basically, in terms of revenue, obviously, our revenue falls the electricity -- the demand for electricity, the national demand for electricity trend. So against that background, a slightly higher the regulated tariffs for the transmission service. Our revenues went up by 7.7% in the first half 2020 as compared to the first half 2021 versus 2020 on a year-over-year basis. In terms of cost -- well, on the cost side, electricity became quite significantly more expensive as compared to 2020. We have 2 completely different pictures, 2020 versus 2021. In 2020, electricity prices actually went down quite a bit. And this is in complete absolute contrast to what happened in 2021. We still don't see the full magnitude of the increase in electricity prices in the wholesale market in the first half of 2021. As the price rally began basically in June, prices were higher in terms of an average electricity price on the spot market as compared to 2020. So prices stepped up quite significantly, but we have witnessed, over the last 1.5 months, a significant additional increase in electricity prices that we estimate is about to stabilize the new higher level. So why is electricity price important for Transelectrica? As you know, we have to go shopping for electricity in the open market. We have to buy electricity to make [indiscernible] of electricity -- to buy electricity, to cover our grid losses position. So basically, a small, tiny percentage of the electricity that builds on the grid at the injection points is lost during the transmission of electricity. It's a technical topic. It's a technical thing. So basically, electricity, a small portion, a small percentage of electricity that gets on the grid is lost in the form of heat. Basically, it's the wire, the cables -- the electrical cables that heat up, and approximately 2.5% as an multiannual average is lost in the transmission process. In terms of percentage, the percentage within our cost base, well, grid losses account for quite a significant portion. In physical volumes, we talk about 2-point-something percent. This year was 2.67%. First half of the year, 2.67%. But in terms of the amount of the spending we do in the electricity market to purchase electricity maybe to cover losses is quite significant. So this basically was the major cost driver in 2021, especially in the first quarter, when we operated against an operational background that led to a significant increase in the technical grid loss factor. So in terms of physical volumes, we recorded significantly higher electricity volume in terms of losses as compared to 2020. As an overall assessment of grid losses in 2021 first half as compared to last year, last year we had less electricity flowing through the transmission grid and a significantly lower grid loss factor. If you combine this to physical factors with the fact that electricity prices were significantly lower last year, that obviously leads to a significantly lower overall cost for the electricity we purchased in the market covered with losses. That happened in 2020. In 2021, we had more electricity flowing through our grids, so more volume transmitting our transmission network. We had a significantly higher loss factor. And I will explain a little bit later why the loss factor was higher in 2021 as compared to 2020. And if you combine those 2 factors that lead to a significantly higher volume of electricity, we had to purchase in the market with a significantly increased price of electricity in the wholesale market, giving you the picture. In our cost base, that delivered quite a punch in 2021. In terms of the operational background that led to a significantly higher grid loss factor, let me just show you a couple of slides. On the left-hand side of this slide, you can see the red color direct arrows that basically show the hypothetical flow of electricity within the transmission network, the Romanian transmission network, that leads to an increase in the technical loss factor. Basically, the longer the network distance electricity has to travel from the point where it is generated at the power stations, at the power plants to the point where it is taken off the grid for consumption or at the cross-border of [indiscernible] points for export, you have higher transmission losses. The higher -- the longer the distance, the higher the losses. The shorter the network distance, the lower the losses. It's as simple as that. On the left-hand side, you can see exports of electricity from Romania to Ukraine, from Romania to Hungary and imports of electricity from Serbia and Bulgaria. I think we've mentioned previously during the conference calls that the vast majority of the electric -- the Romanian domestic generation fleet is concentrated in the lower part, in the southern part of Romania. So we have hydroelectricity heavily concentrated in the southern part of the Danube River on running water, and also we have a significant hydroelectricity generation capacity installed on domestic rivers other than the Danube. Also, we have the coal generation fleet operated by [ Oltenia ] that is also in the southern part of Romania. We have gas-fired power plants operated by OMV Petrom, and that's also in the southeast part of Romania. We have 2 new nuclear reactors operated by [ Clar Electrica ], also in the southern part of the country. And during the last 7, 8 years, we have seen a massive increase in wind turbine capacities being installed primarily, like 90% of the total national wind turbine fleet is concentrated within Dobrudja area that is on the Black Sea shore. We currently don't have anything offshore in the Black Sea, but we do have a significant level of wind turbine generation -- onshore generation very close to the Black Sea shore, but onshore in line. So this type of energy flow pattern as displayed in the left-hand side of this slide, the red colored areas will lead to a significant -- to higher grid loss factor because it basically leads to longer network distances, electricity travels from generation side to consumption points or to cross-border [ effect ] points. On the contrary, on the right-hand side of this slide, you can see a grid flow pattern that is transmission losses-friendly. That basically leads to lower technical loss factors in the grid, in the transmission grid, imports from Ukraine, imports from Hungary and exports to -- on the southwestern border to Serbia and Bulgaria. Why are imports from Hungary and Ukraine transmissional-losses-friendly to Romania? So basically, it's explained as follows. We don't have a lot of -- we don't have a significant level of the Romanian generation of electricity, significant level of production capacity installed in the upper part of Romania. So in terms of grid losses, the injections of electricity or basically electricity coming from Ukraine and Hungary is beneficial in terms of transmission with loss factor because electricity travels shortened network distance, Romania network distance, from the import points to consumption points. Similarly, exports to Bulgaria and Serbia are beneficial in terms of Romanian transmission grid losses. As electricity generated in Romania mostly, as I've mentioned, electricity is primarily generated in the southern part of Romania makes -- electricity makes a quick exit to Serbia or to Bulgaria. So the Romanian network distance -- electricity travel is rather short. It's a small distance, very short distance, electricity travels. So what happened in 2021 was more like the left-hand-side pattern and what happened in 2020 last year was more like the map and the arrows shown on the right-hand side of this slide. So in 2021, the grid flow pattern was intensive in terms of losses or transmission losses, whereas in 2020, we had a grid flow pattern that was more friendly in terms of transmission losses. In terms of prices, prices went up, as I mentioned, so that combined with the fact that in 2021, we were more exposed in our purchase mix. We purchased electricity in the open market. We purchased by [ forward ], by long-term contracts. We purchased electricity on spot markets, day-ahead market and the intraday market, with any mismatches between the actual consumption of electricity, the actual level of losses, the actual amount, as indicated by meter readings. And the amount already contracted either long term or spot, day-ahead or intraday is automatically settled in the balancing market. So as compared to the last year, our purchase mix was quite a bit more exposed to spot market and to higher prices, obviously, as prices went up significantly on the spot market. Just to show you a bit of detail, to shed some color, some additional color on the grid losses topic. Just to show the hourly profile of our grid losses in the transmission network, as indicated by meter readings, it looks a bit like this. If you've ever been in a hospital, or you've seen a movie with a scene that was shot in a hospital, this looks like the pause or something like that. So it's not very stable, it's not flat, obviously. It's anything but flat. So it goes up and down, it has swings up and down. What you see here, blue-colored is the actual level of losses based on hourly meter readings. And the gray color is basically base load. It's the purchases of electricity we've made to cover transmission losses in the long-term market. So those are forward contracts. And the remainder is coverage by purchases of electricity in the day-ahead and intraday market with any residual amounts being settled on the balanced market. Well, in terms of net profit, it's slightly below last year. So it's something like 10% lower than 2020 first half. The main driver behind the decrease in net income is -- comes from the regulated -- our core network business from transmission. EBITDA deteriorated quite a bit. Obviously, that was mostly, primarily driven by higher operating costs, and by operating costs, I primarily referred to the cost of grid losses. So basically, grid losses was the main factor behind the increase in OpEx in first half 2021. And also the main factor behind the deterioration of EBITDA, EBIT and so on and so forth, it was cascaded down to the net income. In terms of pass-through operations, we still have profits. We still have profits in first half of 2021 as compared to 2020. It's slightly lower on a year-over-year basis. The novelty, I might say, in 2021 was that we gained -- we have a temporary gain from the balancing market, from the energy component of the balancing market, which will be offset during 2022 or 2023, or a combination of 2022 and 2023, by tariff reduction. That will be -- the sell process, this whole offsetting of temporary gains is a regulatory process that is closely monitored by our electricity regulator in Romania. So basically, that was what happened in 2021. I tried to be concise and to-the-point and to concentrate on the most relevant developments in 2021 as compared to last year. In terms of the investment delivered in 2021 first half, we have quite an increase, quite a bit of new contracts signed for the construction of new lines and refurbishment of existing substations within our grid. Capital expenditure in first half was RON 262 million. In terms of the amount of commissioned assets, the number is not spectacular, it is RON 63 million, out of which regulatory asset-based investments only account for RON 50 million. But we do have some important investment projects that are in their final stage and are about to be completed in the second part of this year or in the first part of next year. As you know, we regulator -- the national regulator for electricity in Romania provides an extra 6 months for electricity networks to complete investment projects after the implicit deadline. So if you have an investment commitment amounted to EUR 100 million for 2021, the regulator allows an expansion in the deadline of 6 months. So the aftermath for the investment plan approved by the regulator for 2021 will be done at the end of June 2022. In terms of investment, I think it's worth mentioning that as a very recent development that we have started towards, we have signed the execution contracts, the construction works for -- and the delivery of equipment for one important internal new line that is Gutinas-Smardan. That is particularly important transmission infrastructure project as it is a European project of common interest as it has a significant contribution both to the integration of renewable sources in the Romanian electricity system and to -- and also a significant contribution to an increase in cross-border transmission capacity. And also as a recent development, Transelectrica has put together a plan, shortlist set of 20 essential projects. Most of the 20 projects -- these 20 projects that we have discussions with the government officials from the Ministry of Energy and the General Secretariat of the Romanian government. To speed up, to streamline the damaging process and also the procurement rules applied for this shortlist of 20 essential -- nationally essential projects. Most of this list, most of the 20 investment items were already captured under the -- our grid development master plan that was approved by the regulator last year. But we do have some additional items there inside the short list of 2020 investment items. We have some rewirings, a number of, I think, it's 3 or 4 important rewiring of existing transmission routes -- of existing transmission lines. We need to replace the current wiring and install higher-capacity wiring and also a cluster project, which is to be defined. Aimed at safely integrated significantly additional renewable capacity, we're mainly targeting offshore capacity. So mostly wind generation capacity that we estimate is going to be installed over the next years up to 2030. So we do have in mind to plan on increasing in our network's ability to convey electricity to this -- that will be generated onshore and offshore in Dobrudja area in the southeastern part of Romania as additional investments on top of the investment plan of the 10-year grid master plan that has already been approved by the Romanian national regulator for electricity and gas. We don't have this current -- at the current stage, we don't have actual numbers, euro numbers in terms of how much will it cost us to deploy this new investment items over the next years. Most likely, the new investment projects that we will be conducting and carrying out will be commissioned -- completed and commissioned beyond the current regulatory cycle that ends 2024. So these new investment items are most likely going to become operational or could be commissioned in the next regulatory period -- in the next tariff regulatory period. So there is not really a significant potential going forward to -- for the remaining years of the current tariff cycle that ends 2024 to review the current investment planning that was approved by the regulator in 2020 as the new investment items will most likely be completed in the next -- within the next cycle, the next 5-year cycle, 2025 to 2029. But what we would like to stress and highlight is that, currently, we are gaining investment momentum. And the actual output of the investment process, the actual results, the new line, deploying new lines and rewiring existing lines -- results with pop up -- will show up in the next years. So basically, that concludes the first part of the presentation, of the conference call, the presentation from our side. And I think we're ready to jump into the second part of the conference call, that is the Q&A session. So let's get on it. You have the floor.

I would kindly ask you to introduce yourself. Most likely, we discussed previously, we know each other, we were properly introduced with most of you, but I would kindly ask you to introduce yourself and then ask your questions. The floor is yours. Just let me check the chat box. Okay, we have 3 questions, but we will give priority to those of you who are still connected to the call and want to ask questions. Otherwise, we will take the 3 questions that we see in the chat box. Okay. So I get it that we will take the questions that were inputted in the conference call chat box. The first question is, can you provide an estimate for transmission volumes full year 2021? Well, it's a bit hard to predict accurately what will happen in the remaining months of this year. But based on the first 6 months, where we saw an increase in electricity consumption as compared to pre-COVID levels, that is as compared to 2019 of 1-point-something percent, we estimate that the full year 2021 will close at approximately 1% higher as compared to 2019. On the other hand, it is worth mentioning that in 2021, part of the increase in electricity demand was driven by the fact that starting February until mid-June, the average outside temperatures were significantly lower as compared to multiannual averages. So part of the increase in electricity consumption was due to weather conditions -- to a weather pattern that is not really in line with the multi-annual -- from the multi-annual pattern. Basically, it was a bit colder this year, February to June. So quite a bit of first half of 2021 as compared to last year's, also as compared to 2019. So partly, the increase in electricity consumption in 2021 as compared to 2019 of 1-point-something percent was due to weather conditions. But still overall 2021, full year 2021, we see a slight increase in electricity consumption and also transmission volumes as compared to 2019. Second question is, we've heard you talking about an acceleration of investment. Will you be renegotiating the investment plan with the regulator? What is the potential impact on the regulatory asset base? I think I have covered that 5 minutes ago. So we do plan on accelerating the investment plan, but most likely -- as you know, transmission project, transmission infrastructure takes quite a bit of time to plan, to design, to actually execute, to test and commission. So in order to complete the transmission project, especially if we talk about new infrastructure being deployed with [ permitting ], procurement and so on and so forth, like a new line when we deploy a new line, even if it's perfectly planned design and flawlessly executed, it still takes a significant amount of time to complete. So if we're talking of new investment items that were not part of initial plan that we agreed upon with the regulator, it still takes a few years or maybe even more than a few years to complete. So basically, that leads to a situation where new investment items -- obviously, we will discuss those with the regulator. And we are positive, 100% sure that the regulator will accept this additional amount of the investment for the transmission network. This will reflect in the next regulatory cycle in 2025 to 2029, the next 5-year regulatory cycle. The new investment items we have in mind will be surely discussed, will be defined in a detailed technical manner over the next period. And most likely, the output of this addition to the investment plan will generate significant additional CapEx over the next years, but in terms of commission, the complete project and commissioned assets as it's commissioned assets, commission projects that adds to the regulatory asset base. As a reminder, the regulatory asset base only takes additional investment upon completion. It doesn't take CapEx as it stands. It takes CapEx once the project is currently commissioned, is fully operational and those like. So the answer is, we do have all intention, a strong intention to accelerate the investment plan to deploy new lines and rewire existing transmission routes. In terms of renegotiating the existing 2020 to 2025 investment plan with the regulator, it is rather unlikely for that plan to be revised by the regulator as in terms of commissioning with the new additional projects that will most likely happen beyond the end of the current planning cycle. And in terms of impact on the regulatory asset base, no immediate impact. Obviously, we will negotiate with the regulator a new investment plan for the next 5-year regulatory period, 2025 to 2029, when we get closer to 2025. That is in 2024. So it will have a positive impact on the regulatory asset base, no question about that. But in terms of revising the current planning that is approved by the regulator in 2020 to 2024, rather unlikely to happen. And final third question is, the personnel expenses seem to be below budgeted levels for 2021. What are your estimates for full year 2021? The most reliable guidance for personnel expenses for 2021 is the approved budget. So we recommend you to take that into consideration. The number -- the overall cost -- the overall personnel costs as approved by the shareholders, the company in the annual budget are -- they are still the most reliable number. Despite the fact that in the first half of 2021, the numbers seem to be slightly below the budget. So I think that is -- we pretty much covered the questions that we see in the conference chat box. If you have additional questions, please let us know or input the questions into the web conference chat box, and we'll take those.

This is Cosmina Ivana from Swiss Capital. Can you hear me?

Yes. Cosmina, we can hear you loud and clear.

Okay. So it seems that the huge position of gains recorded on the Technological Systems Services segment started to be reversed in Q2. What should we expect for the next 2 quarters given the surging prices on the power market? Could we expect that at least half of about 100 million over recovery position as of June could be reversed this year and not next year?

Yes, there are 2 options for 2 scenarios. The current situation is as follows. We have a backlog of approximately 100 million to be reversed by tariff reduction at the end of February this year. As you mentioned, the regulator has already cut the balancing capacity tariff at first of March this year. And the clawback setting, the clawback plan, as designed by the regulator, basically says half of that 100 million is to be offset to this -- to the tariff cut they already operated starting 1st of March, and half of that 100 million will be offset next year in 2022. What really happened, what actually happened starting 1st of March is that we have March, we have April, we have May, we have June, we have July. So 1st of March to date, I think we are kind of breaking even. So basically, according to the regulator's plan, we were supposed to incur 47 million loss March to December. And now our interim results after -- let me count once more.

After 3 months it's only [indiscernible] million.

5 months. So 5 months out of 10 months, we're breaking even instead of incurring losses. So it's obviously that we are off track. So the initial -- things don't go according to the regulator's plan. So that is basically due to -- the reason is twofold. We've made cheaper purchases of balancing capacity products in the open market. The prices at which we purchased balancing capacity, the technological system services, as we call them, but in fact there are balancing services, balancing capacity services. Standby services were a bit cheaper than expected. Another interesting thing is that we haven't really seen a reflection of the surging electricity prices in the spot market. We haven't really seen a reflection of that massive increase in price for electricity in the balancing capacity, in the, certainly, the standby service. So those 2 products, electricity and standby service seem to not be strongly correlated, seem to be uncorrelated actually. So what will happen over the next months is either we will begin to see some reflection of the increase in electricity prices also in the balancing capacity service prices or at least to some extent, and that will lead to increased costs for us. We might also see an intervention by the regulator. The regulation in place allows the regulator to step in and operate second reduction of the tariff. If things don't go according to plan after 3 or 4 months, I think, according to the regulation in place, the regulator can analyze the data and if they come to the conclusion that things are offtrack, they can take measures to bring things back on track. And that basically means to supply additional tariff reduction. If that happens, it might happen at 1st of September or 1st of October. Starting November, I think it's too late for that to happen. We'll have to wait and see the regulator -- we regularly provide -- we feed the regulator databases with all our purchases of balancing standby capacity. They are doing their calculations. They are doing their assessments, their analysis. We bet they are doing that. And we still have to wait and see if they actually want to apply an additional reduction of the tariff for balancing standby capacity services. Otherwise, if that doesn't happen, we could either witness a reflection of the increase in electricity prices and also in the capacity -- in the balancing capacity services, and that will naturally lead to an increase in our cost base, and we'll speed up the process of the clawback. If that doesn't happen at the end of the year, we will be significantly offtrack as compared to the regulator's plan of offsetting the 100 million in 2 rounds. If at the end of the year, we will be significantly offtrack, with no additional tariff cut by the regulator by the end of the year, we will see most likely this offsetting process -- this clawback process being postponed for 2023. In 2022, according to the initial plan by the regulator, we already have 50 million. So half of the 100 million, 50 million amount to be clawed back by the regulator according to the initial plan in 2022. So the part that seems to be offtrack in 2021, if nothing happens, nothing spectacular or significant difference happen by the end of the year, either in terms of the regulators stepping in and then applying an additional tariff cut or the balancing capacity service is starting to become more expensive during the next months, the offsetting process, the clawback process will be postponed to 2023.

Okay. And now regarding the grid losses purchases on the power market, do you have a target to acquire the power needed for covering these losses, mostly from the forward market? Because in the past, you had like 50% of exposure on the long-term contract market. Now we have 34%. I mean it's pretty worse given the current context of surging spot power prices. Don't you have the target to reach at least 50% of the needed quantities? I mean...

I personally think that 60% is too much. I'm not...

50%, 50%, not 60%. 50%, half of it, half of it.