ENGIE Energia Chile SA
SGO:ECL
If you don’t study any companies, you have the same success buying stocks as you do in a poker game if you bet without looking at your cards.
Utilize notes to systematically review your investment decisions. By reflecting on past outcomes, you can discern effective strategies and identify those that underperformed. This continuous feedback loop enables you to adapt and refine your approach, optimizing for future success.
Each note serves as a learning point, offering insights into your decision-making processes. Over time, you'll accumulate a personalized database of knowledge, enhancing your ability to make informed decisions quickly and effectively.
With a comprehensive record of your investment history at your fingertips, you can compare current opportunities against past experiences. This not only bolsters your confidence but also ensures that each decision is grounded in a well-documented rationale.
Do you really want to delete this note?
This action cannot be undone.
| 52 Week Range |
770
920
|
| Price Target |
|
We'll email you a reminder when the closing price reaches CLP.
Choose the stock you wish to monitor with a price alert.
This alert will be permanently deleted.
You don't have any saved screeners yet
Good morning, and welcome to the Engie Energia Fourth Quarter 2022 Results Conference Call. [Operator Instructions] 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, operator. Good afternoon. I'm here with Bernardita Infante; [indiscernible] who recently joined our Corporate Finance and Investor Relations team; and Marcela Munoz. 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 as well as the -- recognizing the social, economic, cultural and the political achievements of women and to recognize the importance of promoting and taking action altogether on gender equality.
So 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 2 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 stock prices, which impacted our average supply cost, given the approx 4 terawatt hour share position this year we had in 2022. Then 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. So this $300 million were not collected and have temporarily increased the company's working capital and short-term debt needs.
Now, on the right, we are highlighting what's next and giving some color on these elements for 2023. First, as we mentioned during previous quarter, there is an indexation lag in our regulated PPAs of about 6 months to 8 months. So the higher fuel prices in 2022 materialized into higher PPA prices in 2023. This will bring a positive impact on the revenue side where the average supply cost will be lower because of the other elements we also mentioned in this page. So this year we'll have additional renewal generation for around 0.9 terawatt hour during the year. And on top of that, we have additional hedges or backup PPAs for additional 1 terawatt hour.
Then there is a positive impact coming from lower fuel prices, gas coming from Argentina and the LNG we sourced to replace the 4 LNG cargoes that our supplier didn't deliver in 2023. Between all these elements, ECL share position is expected to reduce from the 4 terawatt hour we had in 2022 to less than 2 terawatt hour in 2023, which should reduce volatility and risk, in case spot prices increase again.
Finally, as I mentioned before, the amount of receivables this year and the other gen cost accumulated -- and are not collecting in relation to the PEC and NPC 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.
Then, 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 total sales grew in 3%, the main message in this page is that our long-term portfolio of regulated and unregulated sales 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 the transmission bottlenecks in the southern region where we have about 6% of our total withdrawals. So the situation triggered an action plan on our side to reduce our share position in the south. And as a result, we successfully acquired the wind farm in Chiloe, which will bring and will contribute to reducing approx 50% our spot 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 high in 2022. And then the impact of these international markets directly impacted the spot pricing too. The average price per ton in 2022 reached $314, which can be translated into a production cost of approx $150 per megawatt hour.
Now, it is important to highlight that the recent evolution in coal price as of March of this year, the spot and forward price of coal decreased to around $130 per ton, which is approx 2.5x 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 and the [ question ] 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 of $130 per ton, the production costs with coal power plants should decrease to the $60 to $70 per megawatt hour range.
Now let's continue and move please to Page #9 in which we show the evolution in 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.
Then let's go to next Page 10 and discuss about the natural gas role, which has coal as a key fuel for the Chilean system. The graph on top shows the evolution of international LNG prices. You can see the all-time highs in 2022 due to the Russia-Ukraine conflict, and it's impacting the supply-demand balance. LNG, you can see in the graph, reached $40 per million BTU to $50 per million BTU, which made impossible to buy LNG in spot market. At $40 million BTU, the production costs with the combined cycle using natural gas is close to $300 per megawatt hour.
Then the graph below shows the LNG source through long-term contracts and the natural gas coming from Argentina. Let's start with the natural gas from Argentina. This volumes imported through the center region, have been key for the system and fuel volumes have been committed until May 2023, while interrupting of volumes could be expected during the winter, to then come back on a firm basis starting October.
Then on the LNG side, as you know, we have 2 long-term contracts for a total volume of 23 TBtu per year. One of these contracts was confirmed by our suppliers for about 10 TBtu, while the second contract with a volume of about 13 TBtu was not confirmed, and therefore, we were not able to add this LNG volume to the annual delivery program in [ G&L Materials ].
As a consequence, ECL is exercising its rights into 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. So in this regard, we have secured around 14 TBtu of replacement LNG in the ordinary course of business, and we continue to assess all regional options.
The purchase of these 14 TBtu, together with other actions, has been key to reduce our spot exposure 2023 and now expected to be less than 2 terawatt hour 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 terawatt hour in 2023 compared to 2022. And this is why I was mentioning that the share 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 remained stable into 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 costs for the portfolio. As mentioned on the bottom, the average supply cost should reduce in the future as a result of investment in renewables to replace spot purchases. We're not yet there, but we have a clear goal in this [ slide ].
On next, Page 13, we present a classic supply-demand curve for the overall portfolio for year 2022. Below the graph, we can see the total sales of 4 terawatt hour, and then how demand is met with the different sources starting in yellow with renewals to end on the right side of the graph with a less efficient coal power plant.
As I mentioned before, the share position in 2022 was 4 terawatt hour, then 2 terawatt hour were supplied through hedges, and the other 50% with ECL's own generation, of which 1.2 terawatts hour were supplied through renewals, and this portion should continue to increase in 2023, helping to reduce the share position below 2 terawatts hour.
The continuous and dotted lines above basically show how the average PPA monomic price increased in 2022 because of the indexation formula, but 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 lagging regulated PPAs which will be up to date in 2023.
So now I will hand over to Bernardita to continue with a detailed financial report.
Thank you, Eduardo, and good afternoon to everyone. Let's go to Slide 14 to give a closer look at the 2022 results. So 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, our costs grew further as price indexation in our PPAs reflects the increase in fuel prices with a 6 to 18 -- to 8-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 term of 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 and an increase in spot sales from some of our companies, Eolica Monte Redondo, CTA and Solar Los Loros. And 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. With 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 of 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-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 Chiloe and the almost $300 million build-up 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 gold 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, #18, we see the effects of the steep increase in net debt, about half of which consists of short-term debt with our local relationship banks and the other half of 5-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 3 main objectives related to our debt profile. First, to reduce net debt/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 intermittent risks associated to PV plants in the future. And 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.
So far, our ratings have been confirmed at BBB 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.
Now I'll leave you with Eduardo, who will brief us on the recent events, action plans for 2023 and key takeaways.
Thank you, Bernardita. The actions mentioned in Page 19 are key to explain why we expect an improvement in ECL's operational performance. On top of -- on top we just highlight the context, which is also healthy. Lower coal and LNG prices should reduce pressures for prices. But then on the controllable actions that are in our hands, we secured 24 TBtu of LNG for 2023 and implemented in parallel a tolling agreement with third parties and CCGTs. Then we will schedule the maintenance of IEM coal power plant and we'll keep a higher reliability in the other thermal power plants of our portfolio.
Third, we secured additional back up PPAs for 2023, increasing the total hedges to 3.2 terawatts hour. They are equivalent to 27% to 30% of our total contracted PPAs.
Fourth, in 2023, we have additional 0.9 terawatts hour renewable generation coming from the recently commissioned plants and the recently acquired wind farm in the south.
And finally, the development of additional renewables continues, and we approved the construction of 2 additional projects of 342 megawatts wind farm in the North and 638 megawatt hour 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 terawatts hour in 2023 compared to the 4 terawatts hour we had in '22. This new context and action plans should be reflected in higher margins.
On Page 20, we are presenting the evolution of renewables, the committed CapEx for 2023 and 2024, and the addition of projects that are under development for the next phase. As of December '22, we already added 0.8 gigawatts of renewables to the portfolio, and we have additional 0.5 gigawatts 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 '23 and '24. 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. But that will not allow a fast increase in the leverage ratio.
Then on Page 23, we're just adding some details on these actions on the operational side. And on the right side, the 2 transactions we are working on to monetize the PEC receivables, releasing $30 million plus of cash sources in 2023 and the $400 million Super green 10-year loan we're structuring with the IFC to profile a portion of the short-term debt and define the CapEx needs for the next 2 years.
So 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, energy generation and keep a high availability of our power plants. Second and third in the investment plan, we have launched new investments for 2023 and 2024. And then we need to continue investing in more renewables and adding other complimentary solutions like storage to our existing solar plants, to increase our generation in non-solar hours. This will be key in the system. And finally, to improve liquidity will be key to complete the monetization of the PEC receivables, which is underway, together with the EUR 400 million Super green loan with IFC.
So with this summary, we end our presentation today, and we are ready for your questions. Thank you for your attendance.
[Operator Instructions] And our first question comes from Ezequiel Fernandez of Balanz.
This is [indiscernible] from. Balanz. I have 3 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 cancelled. I wanted to know if you could provide us with an idea in terms of dollars per MMBtu, what was the cost of these spot [ terms ], I guess? And a sub-question is, 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 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?
So let me start with the first one. In terms of the LNG, in LNG we source during the first, say, quarter of this year. As we mentioned today, we already sourced 24 TBtu of LNG for 2023, which represents at least 2.5 terawatts hour of production coming from LNG, and this volume includes our [ procured ] LNG footprint and the LNG will serve in the local, international market during the first quarter.
So 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 per million BTU to $20 per million BTU range. If you multiply this amount by 7, you can have a good proxy of the production costs in megawatts hour in our CCGTs. That's on the first one.
Then, on the second one, basically, at this stage, I can't comment more on the status of this process. Thanks to the confidentiality and obligations in the contract, we are not able to disclose any specific details regarding the legal procedure that is involved. Once we have approval [Technical Difficulty], we would able to share it.
So 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 the extending duration, the greening of the PPAs and a progressive reduction in PPA process as well. Should we see this reduction of the unrelated PPAs at play during 2023 and '24? And if you could give us sort of rough measure on what should we expect there in terms of percentage-wise or some quantification?
No. I think, in this regard, remember that we negotiated good volume with this PPAs back in 2017 to 2018. There were 3 pages. Our first initial discount between 2018-2020, and then a further discount afterwards, which is already, the price that [ reach ] today in those 2 PPAs are, and the main change of the PPA was the change in the [ dictation formula e] since 2021, bringing the list to 4, and the current list to U.S. CPI since 2021. So we should not see a further decrease in those PPAs until at least 2025 when, in this specific case, for example, in the [ Coerco PPA with Choke ], a new PPA [indiscernible] with a 10-year tenure. And such PPA is linked to the market prices and re-negotiated PPA back into our...
And the final one is, we're all in the projections that you're sharing. There's going to be more CapEx than EBITDA in 2023, almost similar in 2024. About funding sources -- of course, you have the PEC monetization, plus the new IFC green loan. Do you think you're covered with that or you're going to need something else further down the road? And has the IFC loan has 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 2 solutions that we mentioned. They are the monetization of the PEC receivables and the IFC green loan of $400 million, which together with improved results should be sufficient to finance the capital plan that we have approved at this stage. So this is linked to the business plan and investments that today we have approved and are committed.
If in the future we accelerate and we have further needs, we will need, of course, to reassess the financing plan for any additional needs. But at this stage, with the CapEx that we have announced and approved, we should be able to finance this investment.
And just confirming that the IFC loan has already been -- the deal has already been closed? Or do you have any pending stuff there?
We are working with IFC completing the due diligence and the objective is to have this financing structured by [ June ].
The next question comes from Andrew McCarthy of CreditCorp Capital.
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 2 terawatt hour net spot exposure in 2023? I know you already mentioned there, I think, 2.5 terawatt hours coming from production via CCGTs. You also talked about up to 3.2 terawatt hours from backup PPAs. Wondering if you could just maybe fill in the -- sort of the gaps there just to better understand how -- given the 12 terawatt hour of contractual commitments, how you sort of get to the less than 2 terawatt hour spot exposure for this year? That will be my first question.
We will make me -- make some calculations. Let me start with what I already mentioned. So let me recall what I already said during the presentation. So we mentioned a short position of 2, okay? So 2 come from the spot. We mentioned 3.2 coming from backup PPAs. So we have 3. We mentioned 2.5 coming from LNG production with a 24 TBtus that we already sourced for the year. And what else? Then we have 2.5 coming from coal production with CTA, CTH, IEM, CTM1, CTM2. And then we are missing 2 coming from renewables. We should have 12 -- 2.5, 3.2, 2, 2.5, yes. We should reach the 12 terawatts hour of the portfolio.
And just in terms of that net position in the spot, so there, are you assuming that you would purchase, therefore no more than 2 terawatt hours? Or is there some kind of spot sales number baked into that, therefore, you would have maybe greater than -- your actual purchase requirements would be great -- would end up being more than the 2 terawatts? Just trying to gauge that sort of how that works.
This is exactly the net position. So this is the total volume of energy on a net basis that we will buy in the spot market. Now to add some additional color to that, as you know, this is like a collector of 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 0. And also another portion will be bought in the spot market during non-solar hours. And then we can see that spot prices are in the $140-$180 range during the first half of this year and during the second half should reduce with lower fuel prices.
But you can imagine that probably half of this volume of energy could come from both type of, let's say, collectors in this case.
And then just on the additional backup PPAs. How should we think there about the prices at which you've signed those? Should we be assuming levels aligned with what you're reporting in terms of your sort of average purchase cost per megawatt hour in 2022? Or how should we think about that?
So 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 you see when we combine both. But we are not splitting both because of confidentiality. Now, the average price of the portfolio of hedges on average is below $60 megawatt hour.
The next question comes from [ Marco Geneseo ] of Blackrock.
I have 2 questions that I'd appreciate should if you could answer. The first one is, 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? And then, -- I don't know, [ can we ask ] the second one also.
I can [ start ] with the first maybe. That'll be helpful for me since, at times, I forget things. So, on the backup PPAs, the backup PPAs have been part of our, let's say, transformation strategy because we consider, since the beginning, that to replace the 12 terawatts hour that in the past was coming from thermal sources immediately with renewables through -- let's say, organic transformation was very difficult. So to be conservative, we added, to the initial strategy 2 sources, which are, the renewables we are 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.
So in this line, you can see, in one of the pages -- I don't remember the number, but the whole evolution of this backup PPAs until [ 2030 ] -- And you can see that these backup PPAs are long-term PPAs that are signed with other generation companies. And during the next years, it might be an opportunity to sign the additional volumes. Today, we have around 3.2, and this volume will remain very stable until 2027. And then we have around 2.5, if I remember correctly, until 2030.
So any additional volume in this regard will be also opportunistic. But you need to know that we are industrial company and our main objective is to build additional renewables to rebalance the portfolio, which is something 100% controllable by us.
And secondly, as we've seen in Slide 22 on guidance, if we expect an EBITDA of say $300 million to $350 million, keeping that in -- under IFC, but also the PEC [ amortization ] you're having, is it fair to assume that your leverage could reduce to 5.5 to 4.5 from 10.5 in that [ spectrum ] in 2023?
This is automatic result, or mechanical result, of predictions and the view we have for the year, considering these 3 variables: the operational performance, amortization of the PEC, the additional CapEx that we have in '23 and '24, and the additional sources we have to finance this additional CapEx.
The next question comes from [ Juan Carlos Petersen ] of [ Inversiones Chufquen. ]
I have 3 questions. The first one is related to -- actually the 3 of them are related to Page #20, Please? Yes -- No, Page #22, sorry. Page #22. This presentation was prepared and presented on your website a few weeks ago. Has, given the current circumstances or recent events, are those -- 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 is executing?
And 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/EBITDA or to improve the return on equity as a whole?
[Technical Difficulty] Sorry about that. We had some technical problems.
So Juan, on the first question, the presentation was recently updated. So it was not published some weeks ago as we used to in the past. So 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 and we wanted to come back not only with the explanation of 2022 results, but also with some color for 2023.
Then, 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 '23 and '24, which is considering the current market current context, the current [indiscernible] and the targets that we're implementing, in 2025, we should add around 1 terawatt hour of additional production coming from Taltal, which is the wind farm, 342 megawatts, that will happen to construction, plus the [ batteries ] that we will start in January 2024.
So this means that in 2025, we should continue to see a positive trend in the results because the tactics behind adding renewables to the portfolio is to replace spot purchases at the average spot price usually by visiting the spot market. And renewals at, let's say, 2, and that's why we should see also an improvement in 2025.
And then on the transmission side, well, the transmission business provides stable cash flows and a regulated return in a country like Chile, and continues to be strategic for our business and integrated model in the country. So we are not working at this stage on any plans to do something else. In fact, 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 we were awarded in recent transmission auctions. That will add additional cash flows in the future.
The next question comes from Mario [indiscernible] of Itau AGF.
My communication stopped for a while. So if I repeat a question, I apologize. But you mentioned that prices are still to capture a little bit more of the fuel increases in '22. I was wondering what time in the year -- I'm assuming mid-'23 -- the prices will start to come down as fuel prices would decrease, right, during this part of the year? So that's my first question.
And a little -- my second question, a little bit more relied on the guidance of EBITDA. I understand from the graphic that you're assuming -- you're estimating [Technical Difficulty] close to $300 million. And I would like to understand what's that light blue portion of the graph like? I don't know if that -- is that like a [ blue case ]? So the rent would be between $300 million, $350 million?
And my last question, if you don't mind, if you -- from the CapEx slide, I infer that the average cost per megawatt that you're assuming is approximately $1.3 million per megawatt. So that's approximately the rent. So that would be the cost per megawatt per se, or that will be a little bit lower? So that would be my 3 questions.
Sure. Sorry, if I didn't get the first one because we were having some technical problems. But in relation to the last one and the cost per megawatt hour, yes, you can see that the total cost for the wind farm is in the $400 million to $500 million range for 350, let's say, average megawatt plant. It's exactly 342 megawatt, if I remember correctly.
And then the additional CapEx comes from the storage solution that will be added to the PV plant, Coya, which will require around $200 million. So that's how you get to the $600 million to $650 million.
And that would be approximately $1.3 million per megawatt, right? Is that correct? That's what I want to know.
Yes, 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 2 or 3 years ago. So there has been some correction.
Yes, 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. So I was wondering when we will see the decrease, right, in the prices following the decrease in fuel in this part of the year? I was assuming mid-2023, but I would like somewhat more color on that.
That's a very good question. So let me explain a little bit how it works. So Discos tariffs are indexed on a regular basis every 6 months. This occurred on April and October. And then there is an extraordinary adjustment in case the variation exceeds in a specific month, plus less 10%. So as we explained before, given the rise in cost to our coal prices, this extraordinary indexation has been occurring frequently, which is reflected in a sustained rise in the energy rates or the energy prices of the Discos, right?
There is an indexation lag of around 6 to 8 months. So that means that the current prices that we are seeing in this, let's say, first half of 2023 will be in a range of $180 million to $190 million during the first half. And afterwards, and 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 million to $170 million to probably end this year in the $140 million to $150 million range. This is considering the current forward prices of coal, LNG. So this could change as we have seen in the past. But 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.
The last one, if you don't mind. You mentioned you were estimating a 2 terawatt hour purchases in the spot market. What's the average price in the year that you're foreseeing for 2023?
Probably in the -- it depends 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, north-center, center, center-south, and south. So it depends a lot on each region. So 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 we bring some results that would not be accurate, or at least would not be an educated guess. I think you would need to see prices by region and between both the type of, let's say, hours.
But probably I would need to -- first to give you a number, it's in the $80 million to $90 million probably.
Next question is a follow-up from Andrew McCarthy of CrediCorp Capital.
I just wanted to double check on the additional 14 TBtus of gas volumes secured. Who of the counterparts there -- Is it [ Enel and NAPA ] as has been mentioned in the press? And what -- in terms of the -- if those are interruptible or not suppliers of gas -- is there a way that, in the end, [ Enel ] could decide to say, no, we can't deliver the gas? Just trying to understand how firm that gas supply is from the perspective of Engie?
Sure, Andrew. There is -- the gas is already, or was already burned probably in our CCGTs, the first 2 volumes that were mentioned in the press. The additional volumes are coming directly from Engie. Global Energy Management, from GEM, they are helping us to source the additional LNG in the international market. So I hope that -- and I'm sure this is on a firm basis.
And just one final question. Just coming back to your projection of seeing the net debt/EBITDA coming down to approximately 5 to 5.5x by the end of the year, just from the -- and from your conversations maybe with the rating agencies and just trying to -- in terms of how they're thinking about whether you'd be able to maintain the investment grade or not, 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 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, that would 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 BBB with stable outlook. And on this line, I think the rating agency is considering that the current increase is temporary, and that we are also investing in additional renewables to increase our cash flow and margins in the coming years. And 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 is 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.
The next question is from [ Nicolas Bilmer ] of HSBC.
I have 2. 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 if it was something else. If you could comment on that, and what impact that would have on your -- I think I guess that's why you're putting 2.5 terawatts in your guidance as opposed to the 3 terawatts that you were generating from coal last year. Is that right? And I have a second question, if I may.
Sure. It's also a good point. So IEM had a failure in 1 transformer end of January. So the plant has been out of service during February. And to, let's say, offset or to mitigate 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. So that means that the plant will be out of service because of the maintenance until April 15.
During this period, the FlexGen 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, it's not material, but the logistics are difficult. So that's why it might take probably a bit of more time. It could be June to come back. So it's not related to the conversion. It's 100% linked to its existing operation. And 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. So 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 CCGTs at the production cost of $100, $120. So 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 the $130, $140 per ton. So this is basically the current situation on IEM.
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.
And I guess my second question is around -- I don't know if you could comment on how you're managing your liquidity? I listened to early -- kind of first part of the year, I think you have debt maturities, mostly bank loans of the of $300 million maturing the first year. I don't know if you could comment on how you're managing or refinancing or extending those? And I guess that coupled with your CapEx plan and balanced with the other liquidity needs and sources? I think you mentioned that the IFC loan, that could be available later in the year. Can you confirm that, that's available also to refinance that? It's not just for CapEx.
And again, if you -- 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 [ you have ] left of PEC 1 as well? Just understanding the liquidity situation in the first half of the year, that would be great.
We already refinanced a portion of the short-term debt maturing in the first half of this year. And then those are the short-term debt, the short-term loans that were maturing between January and March. And 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, and this is expected to happen between April and June.
And in between, we are also finalizing the structure with IFC, which we expect to be ready also by June, and part of the use of proceeds of the IFC would be for refinancing or reprofiling part of our short-term debt.
So in the first half, your share balance [ somewhere ] at the beginning -- at the end of that year of $132 million. Is that -- do you foresee any issues with that level of liquidity in the first half of the year given all these cash needs?
Yes. So we already refinanced during the first quarter of this year, $130 million. But then we have other maturities coming in April and May. That are the ones I was mentioning that we may need to refinance for some additional short-term period until we finalize amortization on the PEC and we complete the structure with IFC.
The next question comes from [ Vlad Nicolas of Lorision. ]
So all my questions have already been asked.
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. That's all 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, and we are committed to continue delivering the results and the action plans that we presented today 2023. Thank you very much.
The conference has now concluded. Thank you for attending today's presentation, and you may now disconnect.