Good morning and welcome to the ENGIE Energía Chile Fourth Quarter 2022 Results Conference Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your telephone keypad. To withdraw your question, please press star then two. Please note this event is being recorded. I would now like to turn the conference over to Eduardo Milligan, CFO. Please go ahead.
Thank you, Pedro. Good afternoon. I'm here with Bernardita Infante, Alison Saffery, who recently joined our Corporate Finance and Investor Relations team, and Marcela Muñoz. Today, we will discuss ECL results for 2022, and we will also share an update on the market evolution for 2023 and the related action plans. Before we jump into the presentation, today we want to recognize the International Women's Day, a global day recognizing the social, economic, cultural, and political achievements of women and to recognize the importance of promoting and taking action all together on gender equality. Now let's start with the presentation.
Today our objective, as I was mentioning before, is to go through 2022 results, but at the same time to provide you an update on the ambitions, action plans, and challenges for the next tw years. We can start directly on page 4. On the left, we are highlighting the main challenges we faced in 2022, which are well-known and explain the results of the year. In relation to financial results, the most important effect is linked to the higher spot prices, which impacted our average supply cost, given the approx 4 terawatt-hour short position ECL had in 2022. On the cash side, besides the lower cash generation, the company also faced the accumulation of approx $300 million of receivables related to the Tariff Stabilization Law.
These, $300 million were not collected and have temporarily increased the company's working capital and short-term debt needs. On the right, we are highlighting what's next and giving some color on these elements for 2023. First, as we mentioned during previous quarters, there is an indexation lag in our regulated PPAs of about 6-8 months. The higher fuel prices in 2022 materialized into higher PPA prices in 2023. This will bring a positive impact on the revenue side, while the average supply cost will be lower because of the other elements we also mention in this page. ECL will have additional renewable generation for around 0.9 TW hour during the year.
On top of that, we'll have additional hedges or backup PPAs for additional 1 TW hour. There is a positive impact coming from lower fuel prices, gas coming from Argentina and the LNG we sourced to replace the foreign LNG cargos that our supplier didn't deliver in 2023. Between all these elements, ECL short position is expected to reduce from the 4 TW hour we had in 2022 to less than 2 TW hour in 2023, which should reduce volatility and risk in case spot prices increase again. Finally, as I mentioned before, the amount of receivables ECL and the other GENCOs accumulated and are not collecting in relation to the PEC and MPC is material.
As of February of this year, as of February of 2023, the amount ECL didn't collect is close to $375 million. We expect to monetize these receivables at face value during 2023 once the final regulations are implemented, and based on recent feedback from authorities, it is foreseen to be ready in the coming days. The banks working on the securitization program will need some weeks to close the transaction. This transaction will be key, as you can imagine, to improve the company's cash position, to continue investing in the new renewable projects that we recently announced for 2023 and 2024. Next, page 5 shows the evolution of ECL's physical sales.
Despite the total sales grew in 3%, the main message in this page is that our long-term portfolio of regulated and unregulated clients provides a stronger stability and predictability. On page 6, we can see the spot price evolution over the last 5 years and how the Chilean system moved from an average $45 megawatt hour in 2020 to $127 per megawatt hour in 2022. Spot prices increased due to the record high fuel prices, mainly coal and gas, the still dry hydrology, and on top of that, the system faced transmission bottlenecks in the southern region, where we have about 6% of our total withdrawals.
This situation triggered an action plan on our side to reduce our short position in the south, we successfully acquired the wind farm in Chiloé, which will bring and will contribute to reducing approx 50% our short exposure in this region. Next page 7 shows the evolution on hydrology, which improved in 2022 compared to 2021, but it was still a dry year. Hydrology in 2022 improved to 86%, and now our focus is how hydrology will evolve for the 2023 to 2024 season and what actions can be taken to mitigate those risks. This means the new hydrology, starting April 2023 will be key for the second half of this year and for the first half of 2024.
On page 8, we can see the unprecedented prices of coal. coal hit all-time highs in 2022. The impact of this international market directly impacted the spot price in Chile. The average price per ton in 2022 reached $314, which can be translated into a production cost of approx $150 per megawatt hour. It is important to highlight the recent evolution on coal prices. As of March of this year, the spot and forward price of coal decreased to around $130 per ton, which is approx 2.5 times lower than the average price of 2022. This morning it's even lower. It's in the $125 range.
If coal remains at such levels, will have a direct positive impact in spot prices in most of the second half of 2023. We need to consider in the equation that most generation companies are consuming during the first half of 2023, the expensive coal that was bought during the second half of 2022. To give you some color, at $130 per ton, the production cost with coal power plants should decrease to the $60-$70 per megawatt hour range. Now let's continue and move please to page 9, in which we show the evolution on the availability of coal power plants in Chile.
The message of this page is that the system has less room for forced outages, and this puts additional pressure for the operation. Let's go to next page 10 and discuss about natural gas role, which as coal, is a key fuel for the Chilean system. The graph on top shows the evolution of international LNG prices. We can see the all-time highs in 2022 due to the Russia-Ukraine conflict and its impact in the supply-demand balance. LNG, as you can see in the graph, reached $40- $50 per million Btu, which made impossible to buy LNG in the spot market. At $40 per million Btu, the production cost with a combined cycle using natural gas is close to $300 per megawatt hour.
The graph below shows the LNG sourced through firm long-term contracts and the natural gas coming from Argentina. Let's start with the natural gas from Argentina. These volumes imported through the center region have been key for the system and firm volumes have been committed until May 2023, while interruptible volumes could be expected during the winter to then come back on a firm basis starting October. On the LNG side, as you know, we have two long-term contracts for a total volume of 23 TBtu per year.
One of these contracts was confirmed by our supplier for about 10 TB Btu, while the second contract with a volume of about 13 TB Btu was not confirmed, and therefore we were not able to add this LNG volume to the annual delivery program in GNL Mejillones. As a consequence, ECL is exercising its rights under the contract and the applicable law to seek redress from the supplier. We have confidence in our case, and we are engaged in continuous efforts to mitigate the impact of the non-delivery of these cargoes. In this regard, we have secured around 14 terabyte Btu of replacement LNG in the ordinary course of business, and we continue to assess all reasonable options.
The purchase of these 14 TBtu, together with other actions, has been key to reduce our short exposure in 2023 and now expected to be less than 2 TW-hours during the year. Next page 11 shows an update on the hedges or backup PPAs signed with other generation companies. This page shows an additional volume of backup PPAs signed for 2023 and 2024. In summary, we have additional 1 TW-hour in 2023 compared to 2022, and this is why I was mentioning that the short position is decreasing in 2023 by 50% compared to previous year. As you can see in the graph, the volume of backup PPAs or hedges remains stable until 2027.
In between, as we have explained before, we will continue analyzing additional hedges in case these are interesting for the portfolio. Page 12 shows a graph with the energy sources and average supply cost for the portfolio. As mentioned on the bottom, the average supply cost should reduce in the future as a result of the investment in renewables to replace spot purchases. We're not yet there, but we have a clear goal with this plan. On next page 13, we present the classic supply-demand curve for the overall portfolio for year 2022. Below the graph, we can see the total sales of 12 TWh, and then how demand is met with the different sources, starting in yellow with the renewables, to end on the right side of the graph with the less efficient coal power plants.
As I mentioned before, the short position in 2022 was 4 TW hour, then 2 TW hour were supplied through hedges, and the other 50% with ECL's own generation, of which 1.2 TW hour were supplied through renewables. This portion should continue to increase in 2023, helping to reduce the short position below 2 TW hour. The continuous and dotted lines above basically show how the average PPA monoprice price increased in 2022 because of the indexation formulas. The increase on the average supply cost was almost twice the increase in the PPA prices. As I explained before, this is explained by the higher spot prices, and also because of the indexation lag in regulated PPAs, which will be up to date in 2023.
Now I will hand over to Bernardita to continue with the detailed financial reports.
Thank you, Eduardo, good afternoon to everyone. Let's go to slide 14 to give a closer look at 2022 results. Eduardo has already gone through the reasons behind the 40% EBITDA decline we suffered in 2022. Revenues increased 30% due to the increase in energy prices explained by inflation and higher fuel prices, and a 3% increase in physical energy sales, mainly to mining companies. However, costs grew further as price indexation in our PPAs reflect the increase in fuel prices with a six to eight-month lag. Our own generation became more expensive and spot prices also increased. To meet our sales commitments in 2022, we bought roughly 1/3 of total volumes from the spot market.
One of the main objectives of our business strategy for the years to come is to close this gap and reduce our exposure to the spot market on the cost side. In addition to one-off items related to the discount on the sale of PEC 1 receivables, we reported an impairment resulting from the annual impairment test, which showed that the discounted value of future cash flows of the company, basically due to the thermal fleet, resulted to be lower than the book value. The after-tax effect of this impairment was $325 million. The company reported an after-tax loss of $52 million, excluding the one-off effects. This impairment has no effect on cash flows, but will cause a reduction in future depreciation, while increasing net income and return on equity.
On slide 15, we see the evolution of EBITDA with positive impacts from average realized prices reflecting inflation and higher fuel prices, an increase in spot sales from some of our companies, Eolica Monterrey, CTA, and Solar Los Loros. The negatives that we have already discussed were mainly related to higher fuel costs and our short position, meaning higher purchases from the spot market at higher prices. All this, EBITDA was just $189 million in 2022. Slide 16 is a graphic explanation of the evolution of our net results affected by the 40% EBITDA decline, $11 million interest expense from the discount on sales of accounts receivable related to the Price Stabilization Law, and the $325 million impact of the impairment we just explained.
The end result was $389 million net loss in 2022. In the following slide on page 17, we can clearly see the reasons behind the steep increase in our net debt in 2022. Net debt virtually doubled, reaching $1.6 billion, excluding $190 million of financial leases related to very long long-term land lease contracts. By far, the main causes for the net debt increase were the investment in renewables, which reached $389 million, including the debt assumed on the acquisition of the San Pedro wind farms in Chiloé, and the almost $300 million buildup of accounts receivable related to the Price Stabilization Law.
This chart allows us to clearly see the tremendous impact of the Price Stabilization Law, not only in terms of direct interest costs, but also in terms of the deterioration in leverage and liquidity ratios and financial cost of the additional debt we have had to take. In next place, given the steep increase in fuel prices and our decision to increase coal stocks given the uncertainties regarding fuel supply in the second half of 2022, we reported negative cash from operations. This should reverse in 2023 as fuel prices and stocks normalize and energy prices start reflecting the past fuel price increase.
In the next slide, number 18, we see the effects of a steep increase in net debt, about half of which consists of short-term debt with our local relationship banks and the other half of five-year green loans taken with Scotiabank and Banco Santander. This last loan was used for the financing of the wind farms in the south of Chile and for the full prepayment of the debt that came with these assets. For 2023, we have three main objectives related to our debt profile. First, to reduce net debt to EBITDA through EBITDA recovery and by maintaining relatively flat net debt levels despite the financing of our capital expenditures in renewable transmission projects.
Second, to secure funding for the construction of the Lomas de Taltal wind farm and the BESS Coya storage projects, whose objectives are to reduce our costs, our exposure to the spot market, and curtailment and intermittence risks associated to PV plants in the future. Third, to extend the maturity profile of our debt. As Eduardo will explain later, our net debt should not increase significantly in 2023, thanks to the true sale of certificates related to the Price Stabilization Law, which should bring about $400 million in cash resources in 2023 and compensate for the debt increase to finance our CapEx. Far, our ratings have been confirmed at triple B with stable outlook as the rating agencies consider the current situation as temporary, and they give great value to the strategic importance of ENGIE Chile to the ENGIE Group.
I'll leave you with Eduardo, who will brief us on the recent events, actions planned for 2023, and key takeaways.
Thank you, Norita. The actions mentioned on page 19 are key to explain why we expect an improvement in ECL's operational performance. On top, we just highlight the context, which is also helping lower coal and LNG prices should reduce pressure on spot prices. But then on the controllable actions that are on our hands, we secured 34 TBtu of LNG for 2023 and implemented in parallel a tolling agreement with third parties' CCGTs. Then we rescheduled the maintenance of IEM coal power plant, and we'll keep a high availability on the other thermal power plants of our portfolio. Third, we secured additional backup PPAs for 2023, increasing the total hedges to 3.2 TW hour that are equivalent to 27%-30% of our total contracted PPAs.
Fourth, in 2023, we have additional 0.9 TWh renewable generation coming from the recently commissioned plants and the recently acquired wind farm in the south. Finally, the development of additional renewables continued, and we approved the construction of two additional projects, a 342 MW wind farm in the north and a 638 MWh storage solution to be added to our existing solar plant, Coya, in the north. The first project should be ready by the end of 2024 and the storage by the end of 2023. With all these actions, the spot exposure should be reduced to less than 2 TWh in 2023 compared to the 4 TWh we had in 2022. This new context and action plans should be reflected in higher margins.
On page 20, we are presenting the evolution on renewables, the committed CapEx for 2023 and 2024, and the additional projects that are under development for the next phase. As of December 2022, we already added 0.8 GW of renewables to the portfolio, and we have additional 0.5 GW under construction to be added in the next 24 months. Next, page 21 presents the detailed CapEx by type of projects. Besides the renewables, we are also investing in new transmission projects which contribute with a stable and regulated cash flow. The detailed contribution of those regulated projects can be seen in section 2.2 of the presentation. Now, page 22 is providing some guidance for 2023 and 2024.
The graph shows the expected EBITDA, CapEx and net debt EBITDA evolution considering the updated fuel prices and the actions we presented in previous pages. The list of variables affecting EBITDA are mainly related to lower spot prices and improvement on ECL's share position, while the actions on net debt are mainly focused on the monetization of the PEC receivables and the financing of the additional CapEx, which will bring additional cash flows very fast. That will not allow a fast decrease in the leverage ratio. On page 23, we're just adding some details on these actions on the operational side. On the right side, the two transactions we are working on to monetize the PEC receivables, releasing $30 million-plus of cash sources in 2023.
The $400 million super green 10-year loan we're structuring with the IFC to re-profile a portion of the short-term debt and to finance the CapEx needs for the next two years. Now to end the presentation, we are summarizing the main key takeaways on page 24. First, it is key to rebalance our portfolio by adding renewables, additional hedges, LNG generation, and keep a high availability of our power plants. Second and third, on the investment plan, we have launched new investments for 2023 and 2024. We need to continue investing in more renewables and adding other complementary solutions like storage to our existing solar plants to increase our generation in non-solar hours. This will be key in this system.
Finally, to improve liquidity, will be key to complete the monetization of the PEC receivables, which is underway, together with the $400 million super green loan with IFC. With this summary, we end our presentation today, and we are ready for your questions. Thank you for your attendance.
We will now begin the question-and-answer session. To ask a question, you may press star, then one on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the key. To withdraw your question, please press star then two. Once again, that was star then one to ask a question. At this time, we will pause momentarily to assemble our roster. Our first question comes from Ezequiel Fernandez of Balanz. Please go ahead.
Good morning, everybody. This is Ezequiel Fernandez from Balanz. Thank you for the materials and the presentation. Very complete as always. I have three questions I would like to go, one by one, if you do not mind. The first one is related to LNG. You mentioned that you already procured most of the volumes that were canceled. I wanted to know if you could provide us with an idea about, in terms of dollars per MMBtu, what was the cost of these spot terms, I guess. A sub question this, if you could share with us, how is it going, I guess, the arbitration procedure for the vessels cancellation?
How long would it take to, you know, resolve this, and if we should expect a compensation that would be in line with the quantities of energy and the cost difference between the contract term and the cost of energy actually procured?
Okay. Hello Ezequiel. Thank you. Thank you for your questions. Let me start with the first one. In terms of the LNG. The LNG we sourced during the first, let's say quarter of this year. As we mentioned today, we already sourced 24 TBtu of LNG for 2023, which represent at least 2.5 TW hour of production coming from LNG. This volume include a firm LNG contract and the LNG we sourced in the local international market during the first quarter. The price at which we sourced this LNG during the first quarter is basically 100% linked to the evolution on the TTF marker during this period, which goes into the $15-$20 per million BTU range.
If you multiply this amount by seven, you can have a good proxy of the production cost in megawatt-hour in our CCGTs. That's on the first one. Basically, at this stage, I can't comment more on the status of this process. Based on the confidentiality obligations in the contract, we are not able to disclose any specific details regarding the legal proceeding that is ongoing. Once we have something to share, we will be able to share this.
Understood. That's understandable. Yeah. My second question goes related to the renegotiation of PPAs that were conducted in 2019, where you struck a deal with several of your mining customers, which include extending duration, the greening of the PPAs and a progressive reduction in PPA prices as well. Should we see this reduction of the unregulated PPAs at play during 2023 and 2024? If you could give a sort of rough measure on what should we expect there in terms of percentage-wise or some quantification?
I think, in this regard, remember that, when we renegotiated, a good volume of these PPAs back in 2017, 2018, there were three stages. A first, an initial discount between 2018-2020, and then, a further discount afterwards, which is already the price at which today those two PPAs are. The main change in those PPAs was the change in the indexation formula, breaking the link to coal and becoming linked to US CPI since 2021. We should not see a further decrease in those PPAs until at least 2025, when in the specific case, for example, of the Codelco PPA with Chuqui, a new PPA will start with a 10-year term.
Okay.
Such new PPA is linked to the market prices and we negotiated the PPA back in 2018.
Okay. That's great. The final one is, well, in the projections that you're sharing, there's gonna be more CapEx than EBITDA in 2023, almost similar in 2024. As funding sources, of course, you have the PEC monetization plus the new IFC green loan. Do you think you're covered with that, or are you gonna need something else further down the road? Has the IFC loan already been approved, and what can we expect in terms of the calendar for disbursement of the funds?
Sure. Following the business plan that we presented today, we are focused on two solutions that, as you mentioned, are the monetization of the PEC receivables and the IFC green loan for $400 million. Which together with improved results, should be sufficient to finance the CapEx plan we have approved at this stage. This is linked to the business plan and investments that today we have approved and are committed. If in the future we accelerate, we have further needs, we will need of course to reassess the financing plan for any additional needs. At this stage, with the CapEx that we have announced and approved, we should be able to finance this investment.
Okay. That's great. Just confirming that the IFC loan has already been closed, or do you have any pending stuff there?
We are working with IFC, completing the due diligence. The objective is to have this financing structured by June.
Okay. That's great. That's all from my side. Thank you very much for your time.
Thank you.
The next question comes from Andrew McCarthy of Credicorp Capital. Please go ahead.
Good afternoon. Many thanks, Eduardo, Bernardita, for the presentation. My first question was wondering if you could give some more color on the breakdown of the sources of energy to enable you to get below that, you know, that 2 TW hour net spot exposure in 2023. I know you already mentioned there I think 2.5 TW hours coming from production via CCGTs. You also talked about up to 3.2 TW hours from backup PPAs. Wondering if you could just maybe fill in the sort of the gaps there just to better understand, you know, how, you know, given the 12 TW hour of contractual commitments, how you sort of get to the get to the less than 2 TW hour spot exposure for this year. That'll be my first question.
Thanks.
Hello, Andrew. You will make me make some calculations now. Let me start with what I already mentioned. Let me recall what I already said during the presentation. We mentioned a short position of 2. Okay? Two come from the spot. We mentioned 3.2 coming from backup PPAs, so we have three. We mentioned 2.5 coming from LNG production with the 24 TBtu that we already sourced for the year. What else? We have 2.5 coming from coal production with CTA, CTH, IEM, CTM1, CTM2. We are missing two coming from renewables. We should have 12.
Got it.
2.5, 3.2, 2.5. Yes. We should reach the 12 TWh of the portfolio.
Perfect. Got it.
Perfect.
That's very clear. Just in terms of the, that net position in the spot then. There, are you assuming that you would purchase therefore no more than 2 TW hours or is there some kind of spot sales number baked into that, therefore you would have maybe greater than 2? Your actual purchase requirements would end up being more than the, you know, the 2 TW hour. Just trying to gauge the, that sort of how that works.
This is exactly the net position. This is the total volume of energy on a net basis that we will buy in the spot market. To add some additional color on that, as you know, this is like a cholesterol, the good and the bad one. In this case, a portion of this volume will be acquired in the spot market at very low prices. You can see that during solar hours, the spot market is close to zero today. Another portion will be bought in the spot market during non-solar hours. We can see that spot prices are in the $140-$180 range during the 1st half of this year, and during the 2nd half should reduce with lower fuel prices.
You can imagine that, probably half and half of this amount, of this volume of energy, could come from both type of, let's say, cholesterols in this case.
Yeah. No, that's very clear. Just on the additional backup PPAs.
Backup PPAs.
How should we think there about?
Yeah.
the prices at which you've been, you know, you've signed those? You know, should we be assuming levels, you know, aligned with, you know, what you were reporting in terms of your, you know, your sort of average purchase cost per megawatt hour in 2022? Or how should we think about that?
Okay. First, let me clarify that the graph that we are showing in the presentation is considering an average cost between the backup PPAs and spot purchases. As you can imagine, the price of the backup PPAs is much lower than the spot purchases. In the graph, you will see or you can see that there is an average cost, but it's not the cost of the backup PPAs. That means that the cost of the backup PPAs is much lower than the price we see when we combine both. We are not splitting both because of confidentiality. The average price of the portfolio of hedges, on average is below $60 MW hour.
Okay, that's very helpful. thanks very much, Eduardo. That's it for me for now.
You're welcome.
The next question comes from Marco Siniscalco of BlackRock. Please go ahead.
Hi. Thank you, Eduardo, Maria, for the very informative presentation. I have two questions I'd appreciate if you could answer. The first one is, you know, given what you discussed in the presentation of the increased energy purchases through backup PPAs, reducing the spot market purchases, is this a structural shift on how you're looking to source energy to fulfill your contracted PPAs going forward? I don't know, maybe that's the second one as well.
I can.
And then-
with the first one, maybe, that would be helpful for me. Sometimes I forget things. On the backup PPAs, the backup PPAs have been part of our, let's say, transformation strategy, because we considered since the beginning that to replace the 12 TW hour that in the past was coming from thermal sources immediately with renewables through, let's say, organic transformation was very difficult. To be conservative, we added to the initial strategy two sources, which are the renewables we're building and also signing backup PPAs or hedges, like in other markets it's possible, but this is not a very liquid market, which are signed with other generation companies.
In this line, you can see in one of the pages, I don't remember the number, the whole evolution of these backup PPAs until 2030. You can see that these backup PPAs are long-term PPAs signed with other generation companies. During the next years, it might be an opportunity to sign the additional volumes. Today we have around 3.2, this volume will remain very stable until 2027. We have around 2.5, if I remember correctly, until 2030. Any additional volume on this regard will be also opportunistic. You need to know that we're industrial company, and our main objective is to build additional renewables to rebalance the portfolio, which is something 100% controllable by us.
Thank you. That's super clear.
Thank you.
Secondly, as you see in slide 22 on your guidance, if you expect an EBITDA of, say, $300 million-$350 million, keeping that flat given the IFC debt you're having, but also the tax monetization you need to have, is it fair to assume that your leverage could decrease to 5.5 to 4.5 turn from 10.5 in net debt terms for 2023?
Indeed, this is the, this is a, it's a mathematical result or mechanical result of the projections and the view we have for the year, considering these three variables: the operational performance, the monetization of the PEC, the additional CapEx that we have in 2023 and 2024, and the additional sources we have to finance these additional CapEx.
Got it. Thank you. Got it. Thank you.
You're welcome.
The next question comes from Juan Carlos Peterson of Inversiones Chusquin Ltda. Please go ahead.
Thank you. Good morning, Eduardo. Can you hear me well?
Yes. Hello, Juan Carlos.
Thank you. I have three questions. The first one is related... Well, actually the three of them are related to page number 20, please. Yeah. No, page number 22, sorry. Page number 22. 2 2. This presentation was done, was prepared, and presented on your website a few weeks ago. Has, given the current circumstances or recent events, though, are those... Do or do they have, they could have an impact on your 2023 guidance reflected here? That's my first question. The second question is, could you give us a color regarding 2025? What it should look like given current context and of course the pipeline of projects and KPIs and actions that the company's executing? The third one is related to the transmission asset.
Given the return on capital of that asset, the current return on capital of that asset, is the company reconsidering any options to reduce its net debt to EBITDA or to improve the return on equity as a whole? Thank you very much.
Can you hear me?
Yes.
Okay. Sorry about that. We had some technical problems. Juan Carlos, on the first question, the presentation was recently updated, so it was not published some weeks ago as we used to in the past. That's why we postponed the conference call and these meetings to March to give more color, given that we were seeing some improvements in the market. We wanted to come back not only with the explanation of 2022 results, but also with some color for 2023.
On the second one, basically on color for 2025, what we can mention is that in 2025, besides the trends that we see in the guidance in 2023 and 2024, which is considering the current market context, the current fuel curves and the projects that we're implementing. In 2025, we should add around 1 TW hour of additional production coming from Tal Tal, which is the wind farm, 342 MW that we have under construction. Plus the batteries that we start in January 2024.
This means that in 2025, we should continue to see a positive trend in results because the thesis behind adding renewables to the portfolio is to replace spot purchases at the average spot price you usually buy electricity in the spot market by renewables at, let's say zero. That's why we should see also an improvement in 2025. Then on the transmission side, well, the transmission business provides stable cash flows and a regulated return in a country like Chile, and continue to be strategic for our business and integrated model in the country. We are not working at this stage on any plan to do something else. As you can see in the presentation, we continue to invest in this business.
In 2023 and 2024, we're investing $170 million in additional projects that were awarded in recent transmission auctions that will add additional cash flows in the future. Thank you.
The next question comes from Mario Estrella of Itaú BBI. Please go ahead.
Hello. Thank you for taking my question. My communication stopped for a while, so if I repeat a question, I apologize. You mentioned that prices are still to capture a little bit more of the fuel increases in 2022. I was wondering what time in the year, I'm assuming mid 2022, mid 2023, the prices will start to come down as fuel prices would decrease, right, during this part of the year. That's my third question. A little bit, my second question, a little bit more light on the guidance of EBITDA. I understand from the graphic that you're estimating an EBITDA close to $300 million.
Yeah.
I would like to understand what's that light blue portion of the graph like? I don't know if that's like a bull case? You know, the range would be between $300 million-$350 million. My last question, if you don't mind, if you from the CapEx slide, I inferred that the average cost per megawatt that you're assuming is approximately $1.3 million per megawatt. That's approximately the range. That would be the cost per megawatt per se or that would be a little bit lower? That would be my three questions. Thank you.
Sure. sorry if I didn't get the first one because we were having some technical problems. in relation to the last one and the cost per megawatt hour, yes. You can see the total cost for the wind farm is in the $400 million-$500 million range for 350, let's say, average megawatt plant. It's exactly 342, if I remember correctly. The additional CapEx comes from the storage solution that will be added to the PV plant, Coya, which will require around $200 million. That's how you get to the $600 million-$650 million.
Okay. That would be approximately $1.3 million per megawatt, right? Is that correct? That's just want to
Yes, that's correct. That's correct. I think it's obvious, and we can see that the CapEx for renewables it's not anymore in a downward trend or recently at least, and increased a bit compared to some ratios we used to see two or three years ago. There have been some correction.
Yeah. Yeah. That's definitely the case. My first question, if you didn't hear, You mentioned that the prices in PPAs are still yet to capture some of the increases in fuels in 2022. I was wondering when we would see the decrease, right, in the prices, following the decrease in fuels in this part of the year, right? I was assuming mid-2023, I would like some more color on that.
That's a very good question. That's a very good question. Let me explain a little bit how it works. These coal tariffs are indexed on a regular basis every six months. These occur in April and October. Then there is an extraordinary adjustment in case the variation exists, exceeds in a specific month, plus or less 10%. As we explained before, given the rise in post war coal prices, this extraordinary indexation has been occurring frequently, which is reflected in a sustained rise in the energy rates of or in the energy prices of the discos, right? There is an indexation lag of around six to eight months.
That means that the current prices that we are seeing in this first half of 2023 will be in a range of $180-$190 during the first half. Afterwards, considering the prices that we have today and we had during the last quarter of 2022, we should see a decrease to probably a range of $160-$170, to probably end this year in the $140-$150 range. This is considering the current forward prices of coal, LNG. This could change as we have seen in the past.
This is our best view today given the already materialized prices in the recent months and the forward curves for the rest of the year.
Thank you. That's very clear. Last one, if you don't mind. You mentioned you were estimating 2 TW hour purchases in the spot market. What's the average price in the year that you're foreseeing for 2023?
Probably. It depends. It depends on by zone. I'm not anymore looking to average prices, let's say, on a consolidated basis, we are looking to solar, non-solar, north-center, center-center, south, and south. It depends a lot on each region. Difficult to say what is the average price of the whole system, I think would be to oversimplify the analysis, and that could make us or will bring some results that will not be accurate or at least would not be an educated guess. I think you will need to see prices by region and between both the type of, let's say, hours. Probably.
I would need to be forced to give you a number, it's in the 80-90, probably. we're seeing.
Okay. Well, that's really helpful. Thank you. Thank you all.
You're welcome.
The next question is a follow-up from Andrew McCarthy of Credicorp Capital. Please go ahead.
Many thanks for taking my follow-up question. I just wanted to double-check on the additional 14 TBtu's of gas volume secured. Who are the counterparts there? You know, is it Enel and ENAP as had been mentioned in the press? What are the... if those are interruptible or not, supplies of gas, is there a way, you know, in the end, Enel, ENAP could decide to say, "No, we can't deliver the gas"? Trying to understand how firm that gas supply is from the perspective of ENGIE. Many thanks.
Sure, Andrew. There is, the gas is already or was already burned probably in our CCGTs. The first, two volumes that were mentioned in the press. The additional volumes are coming from, directly from ENGIE. Global Energy Management, from GEMS. They are helping us to source this additional LNG in the international market. I hope that, and I'm sure this is on a firm basis.
Okay. That's very clear. Thanks, Eduardo. Just one final question. Just coming back to, you know, your projection of seeing, you know, the net debt to EBITDA coming down to approximately 5 to 5.5 times by the end of the year. Just from your conversations, maybe with the rating agencies and just trying to, you know, in terms of, you know, how they're thinking about whether, you know, you'd be able to maintain the investment grade or not. What's, you know, what are the sort of the dynamics there? I mean, are they...
What variables maybe are they looking for between now and the end of the year to be able to, you know, continue with that, maintain that investment grade rating, which I guess remains very, very important for ENGIE? If you could provide some color around that'd be really helpful.
Sure. I don't want to answer on their behalf. What I can mention is that so far our ratings have been confirmed at triple B with stable outlook. On this line, I think a rating agency is considering that the current increase is temporary. We're also investing in additional renewables to increase our cash flow and margins in the coming years. They are also, as far as I understand, giving a great value to the strategic importance of Engie Chile to Engie Group. I think this is something that it's explicit, at least in the rating and in the report of one of them.
In which it is clearly stated that Engie Chile rating could be upgraded in up to 3 notches, based on the strategic importance of Engie Chile for ENGIE Group.
Great. Thanks very much, Eduardo.
You're welcome.
The next question is from Nicolas Delamer of HSBC. Please go ahead.
Hi. Thanks for taking my questions. I have two. One, if you could comment on the IEM plant. I understand that the plant was not operating in February. I don't know if this is linked to the conversion to gas or it was something else. If you could comment on that. You know, what impact that would have on your... I guess that's why you're putting 2.5 TW in your guidance, as opposed to the 3 that you were generating from coal last year. Is that right? Then I have a second question, if I may.
Sure, sure. It's also a good point. IEM had a failure in one transformer end of January. The plant has been out of service during February. To, let's say, offset or to mitigate its the time the plant will be out of service, we decided to move the maintenance of this plant that was programmed for August. It's a 45-day maintenance from August to March. That means that the plant will be out of service because of the maintenance until April 15th. During this period, the Flex Gen team is working on recovering the plant. This involves basically replacing the transformer or finding any other solution.
The CapEx in relation to this action is not material, but the logistics are difficult. That's why it might take probably a bit of more time. It could be June to come back. It's not related to the conversion.
Mm.
It's 100% linked to its existing operation. This is one of the reasons why we bought additional LNG in the first half of this year. You can imagine that producing with IEM, with the expensive coal we bought last year, would bring us with a production cost of around $150 per megawatt hour. With the LNG that we sourced for the first half of this year, we are partially replacing IEM with our CCGTs and the tolling agreement we have with the other CCGT at a production cost of $100-$120 per megawatt hour.
We expect to have IEM back around June, and then during the second half of the year, IEM will be able to produce with the coal that we are buying for the second half of this year at $130-$140 per ton. This is basically the current situation on IEM.
Thanks.
Of course, when I try to summarize, with ballpark numbers, the production 2.5 or 3 with coal, let's see. Yes, there should be a lower production coming from IEM during this year because the plant is not available on February, March, April, and probably May.
Understood. Thank you. I guess my second question is around if you, I don't know if you could comment on how you're managing your liquidity. This in the early, you know, kind of first part of the year, I think you have debt maturities, mostly bank loans of, or something in the order of $300 million, in the, you know, maturing the first year. I don't know if you could comment on how you're managing or refinancing or extending those, you know, and I guess that coupled with your CapEx plan and balanced with, you know, your the other liquidity needs and sources. I think you mentioned the IFC loan that could be available later in the year?
Can you confirm that that's available also to refinance debt? It's not just for CapEx. Again, I don't know if I missed it, but if you could comment on when you actually expect the monetization of the PEC 2 and whatever is left of PEC 1 as well. Just understanding the liquidity situation in the first half of the year, that'd be great. Thank you.
Sure. We already refinanced a portion of the short-term debt maturing in the first half of this year. Then those are the short-term debts, the short-term loans that were maturing between January and March. Then on April and May, we have additional short-term loans that we plan to refinance until we are able to monetize the PEC receivables. This is expected to happen between April and June. In between, we are also finalizing the structure with IFC, which we expect to be ready also by June. Part of the use of proceeds of the IFC would be for refinancing or reprofiling part of our short-term debt.
Okay. In the first half, your balances, I think at the beginning, at the end of last year, were $132 million. Do you still foresee any issues with that level of liquidity in the first half of the year, given all these cash needs?
Yeah. We already refinanced during the first quarter of this year, $130 million.
Okay.
We have other maturities coming on April and May that are the ones I was mentioning that we may need to refinance for some additional short-term period.
Mm-hmm.
We finalize the monetization on the PEC and we complete the structure with IFC.
Got it. Understood. Thank you.
You're welcome.
The next question comes from Vlad Nikolov of Merrill. Please go ahead.
No, apologies. My questions have already been asked. Thank you.
Thank you.
This concludes our question and answer session. I would like to turn the conference back over to Eduardo Milligan for any closing remarks.
Thank you, operator. Right. From our side, it has been also, it has been a pleasure to be with you. We like this interaction, and we will be well prepared for the next quarter. We are committed to continue delivering the results and the action plans that we presented today in 2023. Thank you very much.
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.