ENGIE Energia Chile SA
SGO:ECL
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Good afternoon, everyone and welcome to the Engie Energia Chile's Fourth Quarter 2021 Results Conference Call. If you need a copy of the press release issued last week, it is available on the company's website at www.ng-energia.cl. Before we begin, I would like to remind you that this call is being recorded and that information discussed today may include forward-looking statements regarding the company's financial and operating performance. All projections are subject to risks and uncertainties and actual results may differ materially. Please refer to the detailed note in the company's press release regarding forward-looking statements. We would now like to advise participants that this call is being dedicated to investors and market analysts and not for the press. We ask all journalists to contact NG Energia Chile's PR Department for details.
I will now turn the call over to Mr. Eduardo Milligan. Please go ahead, sir.
Thank you. Good afternoon to everyone and thank you for being with us today. I'm here with Bernardita Infante, Head of Corporate Finance of Engie Energia Chile. And today, we will present ECL results during a very complex 2021. We will also discuss the recent progress on the renewables and transmission projects and of course, we will discuss the guidance that we have provided for 2022.
So now let's start and please turn directly to Page #7, to go through the key messages that we want to share today -- to Page 3, sorry. First, as we mentioned during our previous call in 2021, the power generation industry faced a very complex and challenging year, with very high spot prices and these high spot prices are explained by the combination of an extreme drought, the unavailability of efficient thermal coal power plants during the year and also an important increase in fuel prices, mainly coal during the second half and LNG during the first half and also during the second.
And finally pushed also even higher by a strong recovery in electricity demand. As we also explained in previous quarters, let's say, the non-linearity and combination of these elements created a perfect storm and pushed spot prices forth where the industry was expecting for 2021. So in summary, we said during '21 spot prices that were 2x what we were expecting without the combination of all such elements I recently mentioned and that we will discuss in a few minutes.
Second, we'll go through the renewal projects under construction and supply agreements that we have signed with other generation companies to support our portfolio of customers and PPAs. The 151-megawatt Calama wind farm is ready and injected to the grid. PV Tamaya with 114 megawatts is also ready. And this morning, I mean today, this morning, we received a formal approval for its commercial operation from the market coordinators. So now both projects are in full operation.
Well, then in 2022, we expect to reach the commercial operation date of 2 additional PV renewable projects, with a combined capacity of approx 270 megawatts. And in relation to the supply agreement signed with other generation companies or as we can call them backup PPAs during 2021, we signed additional contracts for approx 0.6 terawatt hour per year to hedge our position. And as we will see on Page 12, by 2022, 20% of our contracted demand will be hedged with these instruments.
Third, it is important to recall that last April, we announced second wave of 1,000 megawatts of additional renewables together with the conversion of 3 coal power plants to biomass and natural gas. During this year, we secured also through land concessions the optionality to build up to 1.5 gigawatts of renewals, where we already filed permits for the future conversions.
During 2022, we expect to finalize the development phase of additional wind projects and be ready to give the notice to proceed to start their construction. And fourth, despite market context that negatively impacted results in 2021, that is far below our guidance, ECL continues to keep a solid and flexible capital structure, while the company continues to have a stronger cash generation that should allow ECL to finance its transformation plan with a mix of internal cash flow and financial debt, keeping our leverage under control.
So let's move on Page 4. We can see the evolution of ECL results during the last 10 years of our transformation process. First and this is to give context, we secured a 12-terawatt hour per year contracted demand with an 11-year duration. Then we started reorganization process of our portfolio by shutting down coal power plants and building renewables in parallel to replace those coal power plants.
As we can see on the right hand, total energy sales were above 11-terawatts hour per year during the last 3 years and regulated PPAs represented almost 5-terawatts hour out of the total, so this means around 40%. EBITDA net result in 2019 and 2020 were relatively stable and in line with the guidance, excluding one timers and 2021 as I explained before was severely impacted by high spot prices in the system.
Then on Page 5, we show the transformation path to replace the coal power plants that ECL is disconnecting with up to 2 gigawatts of renewables that as I mentioned in our previous calls could be combined also with storage solutions and this is something that we are still analyzing.
On Page 6, I just want to recall ECL main strength. It's a long-term contracted portfolio of PPAs with top-tier companies and the average life close to 11 years and maturities that go even beyond 2030, with predictable revenues over time. Now ECL main objective is to control and optimize the supply cost and this is the main challenge to optimize our margins during the 11-year contracted phase and to build a new platform to capture additional PPAs in the long-term, considering that the renewals that we are building have a longer life than these 11 years.
Now please turn to Page 7 to discuss ECL 2021 main KPIs and financial results. EBITDA in 2021 is negatively affected by higher marginal costs due to drought and availability of thermal power plants, higher fuel cost and also the demand recovery. In this line, EBITDA fell 31% compared to 2020. In relation to our sales, we can see a positive evolution in physical energy sales of 3% compared to 2020, even considering one important PPA with Zaldivar ended back in June 2020. So these are good news in terms of demand.
Then on the supply cost, spot purchases during 2021 decreased 30% compared to 2020 and this is mainly explained by the end -- by the need to run ECL's thermal plants to cover the lack of hydro production in the system. So in this line, Units 14 and 15 in Tocopilla that were planned to be disconnected by the end of 2021 were requested by a market coordinator to remain available at least until June of this year. The relevant also piece of information is that our supply cost increased in 2021 compared to 2020, explained by the higher fuel costs and higher spot prices. The average spot price at which ECL bought a portion of its energy needs was much higher than in 2020 and much higher than in the business plan of the year.
So this negative impact on the average supply cost is explained in the lower EBITDA and net result in 2021, compared to the previous year and also as I was mentioning compared to the business plan. The recurring net income is 54% lower than in 2020 and was impacted by both the operating performance we just explained and also by the upfront recognition of $50 million financial expense on the sale of regulated receivables that on the positive side is releasing an important amount of cash of approx $200 million for our financial plan between 2021 and 2022.
Finally, net debt increased in line with the disbursement of the $125 million green loan arranged with IDB Invest and also because of the recognition of financial leases related to new land concessions that were awarded to ECL back in 2021.
Now please turn to Page 8 to explain the main elements that impacted 2021. These 2 graphs show the average spot price in the north and in the center south regions. We can see how in both regions spot prices in 2021 are almost 2x higher than in 2020. Then considering that ECL bought 3.2 terawatts hour in 2021, we can get close to $150 million of additional costs, multiplying the 3.2x the different spot price. And this is impacting the energy margin that will only be partially offset with the average PPA prices that also increased in this context, but at a slower pace.
On Page 9, we present hydroelectric production during the last 3 years in Chile, 2019 and 2020 were already dry years and then we experienced in 2021 a new record well below 2020 and in almost 20% and becoming one of the driest in the last 60 years. This means the hydroelectric year 2021, 2022 was at [ P-98 ]. As you know, the new hydrolytic year starts in April. So this means the first half of 2022 is well known and that the second quarter of 2022 would again be difficult and electricity produced with coal, LNG and gas from Argentina would play a key role to replace hydro production. And in this line, the fuel prices will also be a key driver for 2022.
So then we can see in next pages 10 and 11, what happened with coal and LNG. As we mention in this page, coal prices hit all-time highs in October '21. Then the Chinese government applied some controls and coal prices decreased. But afterwards, Indonesia, the largest exporter of coal in the world restricted exports to first secure its local consumption, impacting again the coal price in different markets.
So this full restriction was applied only until January '20. Now the market is again returning to a normal phase, but in between we are facing again some volatility related to the crisis between Russia and Ukraine. So this means we are still in a volatile environment. So we need to be cautious with this variable considering that still 30% to 35% of the electricity is produced in the system with coal. And this means it has an important impact on spot prices. This is an important variable we need to consider in the guidance for this year, which is reflecting the current forward curves of coal.
Next Page 11 shows the LNG prices in different markets. We can see the LNG price materially increased the European and Asian markets and this opportunity cost for LNG producers is driving the LNG price for spot purchases and unfortunately not helping to reduce the electricity average supply cost in Chile, since we can't import spot LNG at these prices and we are just keeping the firm contracts that we already have.
Now the good news is that Argentina is exporting gas to Chile in the central region, that is helping to mitigate the lack of hydro and expensive LNG prices. Currently, we are seeing daily imports for approx 6 million cubic meters per day and this is equivalent to 1,200 megawatts average per day.
Next Page 12 shows what we are doing to manage the spot price volatility and its impact on the average supply cost for our portfolio of PPA. The yellow area of this graph represents the contracted energy with other generation companies and we can see an important ramp-up in 2022. These are what we call backup PPAs. Basically, ECL is replacing in the systems energy balance, the generation company, providing this hedge for the contracted volume. So these are energy contracts only between 2022 and 2025. We have secured backup PPAs for average 2.5 terawatts hour per year. So this means at least 20%, 25% of ECL total contracted demand is hedged with these backup PPAs until 2030 to reduce the exposure to spot market volatility. This was not the case back in 2021 because the ramp-up of several of these PPAs started in '21.
And then in '22, we are seeing an important amount of energy coming from backup PPAs. And in addition, in 2021, we signed additional 0.6 terawatts hour per year for the next 3, 4 years. So this will, of course, help to reduce the volatility on our energy margin and this is a complementary strategy to the construction of renewals during the transformation phase of ECL.
Now let's move directly to Page 14, where we can see the demand-supply balance for the full year. This graph shows average realized PPA prices compared to the average supply cost, which is the result of the different power resources to meet the total demand from our PPA contract. This is a graphic explanation of what happened during 2021. We can see that a new area in yellow starts to appear at the left part of this graph. And then IEM, CTA and CTH power plants operate as base load [indiscernible]
The available costs of our coal plants in general was higher because of higher coal prices. The rest of our core units which in 2020 were marginally dispatched had to be dispatched in 2021, representing 12% of our supply. As we move to the right, we see ECL supply 27% of its contract through purchases from both the spot market and backup PPA supply agreement. And finally, our 2 combined cycle units running with natural gas represented almost 20% of our energy supply.
The production cost of our combined cycles increased compared to the previous year, in line with the additional LNG that we imported through spot purchases. And we did this to hedge our spot exposure, but unfortunately at higher LNG cost. The result was that our average supply cost increased as we can see from 52% to 75% and this was partially compensated by an increase in the average monomic price, which also increased from 102 to 112. So this means despite the total cost increased in $23, the average monomic price increased in $10, partially offsetting the negative impact. Now the new hydrologic year is from April to April, May 2022 and fuel prices during 2022 will be key for ECL's average supply cost during the year.
Let's turn now to page 16. As explained during this presentation, here results in 2021 were far below the guidance, given the combination of all the elements that I mentioned in previous pages. Now despite the current context has not fully reverted and that the volatility we faced in 2021 will continue. We decided to continue giving our best estimate or guidance for 2022 to give some visibility on the potential scenario we foresee under the current market scenario.
So first in this guidance, we are considering the most updated field curves and a similar hydrologic year during the period April '22, March '23 to the hydrologic year that we faced in 2021. So this means we are not using an optimistic change for the second half of 2022. This means dry conditions to continue during the first half of 2022 and coal and gas prices to remain high also during this year. This also means that we need to consider in this best estimate. First, that we still expect a complex first half of the year since the new hydrologic year will impact the second half.
Second, fuel prices, mainly coal and LNG will be key considering its impact in the system spot prices. So in this guidance, we are considering the most updated forward curves you can find for LNG and coal in the market. This also means that if coal and LNG prices increase, this will impact the spot price and hence our energy margin and vice versa on the positive side.
And third, ECL would be less exposed spot prices with new renewals that recently reached COD. The additional renewables that will enter into operation in 2022 and the additional backup PPAs signed with other generation companies that will be larger in 2022. Together with the Argentinian gas that is currently available in the center and as I mentioned before is representing approx 1,200 megawatts of average production on a daily basis and this is probably around 10% of the country's demand.
All in all, our guidance show an improvement in 2022 from a margin perspective, but as I mentioned before, we need to be cautious on the new hydrologic year that will start around April, May and will materialize in June, July, August, September. And also on coal prices, given its relevant impact on the system spot prices.
Last element is the efficient thermal availability in the system. As you know and as we explained before in 2021, several failures impacted the overall thermal production in the country. In this guidance, we are considering that the system is returning to its normal failure or an availability rate. And again, any relevant failure of our efficient thermal plants or from third parties will, of course, have an impact on the spot prices during the year.
Now let's continue and please turn to Page 17. We have updated our CapEx forecast for 2022 and we expect investments for approximately EUR 370 million, mainly focused on our renewable and transmission projects as well as maintenance. In this forecast, we are including the expected CapEx for 2022, which includes the completion of the renewal and transmission projects that are currently under construction and also includes additional CapEx related to the additional wind projects that we expect to launch during the year.
The remaining CapEx of the 2 projects that are under construction would be close to 50% of the $249 million and the other roughly 50% would be related to the new projects. As we mentioned, since we started this transformation plan, we plan to finance this CapEx with a mix of internal cash generation and financial debt. Our net debt-to-EBITDA ratio increased slightly above 3x given the lower EBITDA of 2021 and the recognition of land leases as financial debt.
During the next years, we should return to the baseline -- we define to keep our leverage ratios not exceeding 3x on a structural and regular basis. We may face, of course, temporary increases in this ratio during the construction phase, but this will only be temporary. Considering renewals, we'll rapidly generate an additional EBITDA. So in practice and I mentioned this before, the renewables ECL is developing, we replace the energy purchases in the spot market to supply the PPA demand. So this means every 1 terawatt hour per year of renewals production should at least create $30 million to $40 million additional EBITDA for the company.
The following section describes ECL transformation plan. The 4 pillars are described on Page 19. Then on Pages 20 and 21, we present our portfolio of clients and how the indexation of these PPAs will evolve in the medium-term. Then as we can see on Page 21 between 2020 and 2022, we will see how the indexation of our portfolio of contracts will change to US CPI, which will represent almost 80% by 2022 compared to 60% back in 2020, while coal will move from 29% to only 11%. LNG will continue driving the regulated PPA in the north and a small portion of the PPA in the center.
And we expect this structure will remain stable until 2025. The recent increase in the LNG and coal prices will, of course, have some lag in the indexation formula of some PPAs. So this is why in 2022 we should also expect an increase in the average monomic price of the overall portfolio, considering the recent increase in coal and LNG prices and the lag that we may have in some contracts.
Then on Page 22, we show a complete view of the transformation plan by type of technology 2025. And as you know, the key component is a development of 2,000 megawatts of renewables. Then we can move to next Page 23, in which we can see how by 2022 we are expecting to complete 70% of the first phase, while we are planning to launch the construction of additional renewals to reach the objective by 2025.
The additional component of the transformation plan is a conversion of the remaining coal units to biomass and natural gas that are described in Page 24. Then let's go to the next pages. The next page give us some additional details of the renewable and transmission projects under construction and also under development. First, on Page 25, as I mentioned at the beginning of this call, we are glad that our first renewal project wind Calama reached its COD back in October 2021, adding 151 megawatts to our portfolio, with a total investment of EUR 160 million.
Then on next Page 26, we present the Tamaya solar plant, which is fully energized. And as I also mentioned today, this morning, we received a formal COD from the market coordinator. This is a 114-megawatt PV plant and this new plant required a total investment of $84 million. The next project on Page 27, Capricornio Solar had delayed its original scale and is expected to be ready by the end of the third quarter of this year. The delay in construction is explained by the delay in the obtention of certain archaeological permits for some ground trucks as well as financial issues of its contractor, both influenced by COVID crisis and the expected investments to include this project is EUR 85 million.
Well, the total investment is EUR 85 million. On Page 28, we present global advance of Coya solar project. The project has 65% global advance. And last quarter, we scaled its energization for the third quarter of 2022 and formal COD by the end of the year. Here, we have experienced a delay in the transportation of equipment from Vietnam and other logistic issues that have been solved so far. So that's why we expect this project will be ready during this year.
Then on Page 29, we have secured 2 land concessions, Pampa Fidelia and Pampa Yolanda in the Northern region close to our operations and mining clients, with a combined capacity of 1.4 gigawatts between wind, solar and potential storage.
As I explained before, the exact design and configuration of these projects is under analysis. And before launching the construction of these projects or projects inside these concessions or land concessions, we will launch others that we can see on next Page 30, where we can see some examples of the different projects that are under development, Â Vientos del Loa and Lomas de Taltal, with a combined capacity of almost 500 megawatts have received both their environmental permits and we expect to launch their construction during 2022, best time to market conditions and should become the next wind projects to be added to our portfolio.
Then let's talk about transmission projects. On Page 31, we can see the 3 successful projects that were concluded in 2021. These 3 projects are adding regulated revenues for approx $2.4 million and required a total CapEx of $41 million. On Page 32, we can see the additional projects that were awarded to ECL and that are currently under construction. These 7 projects will add $5.3 million approx of regulated revenues and will require a total CapEx of 66 million.
While on Page 33, we present 4 additional projects that will require total CapEx of 44 million. So in summary, we are investing close to 150 million in new transmission assets that will bring additional regulated revenues to ECL between the 3 group of projects that we just presented, the regulated revenues could be close to $10 million, $12 million per year. And we will continue participating in transmission auctions in which we can unlock synergies with our existing or future portfolio of generation and transmission assets. For sure, we'll continue participating in this type of auctions that will be part of the expansion plan of the Chilean system.
So now I think Bernardita will cover the following section about our financial performance.
Yes, thank you, Eduardo. Good morning or good afternoon to everyone. So let's go to Slide 35 please. So the 31% EBITDA growth in 2021 is basically explained by 2 main factors, as Eduardo has already explained. So one is the severe and prolonged drought affecting Chile, with 2021 being one of the driest years ever. And 2, the dramatic increase in fuel prices, especially in the second half of the year.
So now if we look at each of the main variables behind the EBITDA behavior in 2021, we can observe an increase in average realized prices, which has to do with the indices to which our tariffs are tied that is US inflation as well as coal and gas prices. Also, the tariff discount agreed in the March 2020 renegotiation on the Centinela PPA was smaller in 2021 than it was in 2020. So higher prices explain EUR 104 million positive effect on EBITDA, which partially offsets the increase in our average supply costs as we will see.
In second place, we had to buy less power from third parties as our own generation increased. The drought and absence of Argentine gas through most part of 2021 led to the dispatch of our coal fleet, including the less efficient units number 14 and number 15 that we were planning to close at the end of 2021. The lower volume of spot purchases had a positive EUR 98 million effect on EBITDA, which offsets in part the negative effects of the increase in spot prices.
In third place, physical energy sales increased notably in the free client segment with a EUR 21 million positive impact. Demand from our mining clients increased offsetting the end of Zaldivar PPA in June 2020. Sales to distribution companies, although demand increased during the year, but these sales flattened given our lower pro rata in the pool of regulated PPAs due to the start-up of new PPAs from other generation companies in the system.
Now the next bar shows $6 million in insurance recoveries related to business interruption losses from past outages reported by our IEM and CTA units. Our operating and administrative expenses overall decreased by $5 million due to cost savings and foreign exchange effects.
Now moving to the red bars in the chart, we note a EUR 1 million net negative effect from the transmission and gas business. This bar includes a $7 million accounting loss corresponding to the potential hit of the implementation of a new transmission tariff degree on the valuation of our investment in turn. The most significant negative impact of EUR 196 million was the increase in fuel costs, explained by the increase in our own generation and the record high coal and LNG prices in the second half of the year.
In second place, the increase in marginal costs represented a $170 million hit on EBITDA in 2021. We bought less from the spot market, but at much higher prices. Finally, we reported a $7 million increase in capacity payments. So all of these changes taken together led to EBITDA of $315 million in 2021, down from EUR 455 million in 2020.
Now if we move to Slide 36, this slide shows the evolution of net results, which went from EUR 164 million in 2020 to EUR 47 million in 2021. Last year or rather in 2020, we reported nonrecurring expenses of $10 million related to the premium paid on the early redemption of EUR 400 million 144A bond, which we refinanced with a new EUR 500 million bond. Our net recurring income in 2020 reached EUR 181 million.
As we could see in the previous slide, in 2021, our EBITDA fell impacting our net results by EUR 110 million net of taxes. We also had other items such as depreciation and asset write-offs, which had a net $9 million negative effect. We had a couple of positive effects, such as FX gains, mainly resulting from the effect of depreciation of the Chilean peso on leasing liabilities, which are denominated in pesos.
Finally, we reported lower financial expenses due to lower average coupon rates and greater capitalization of interest in our investment projects. Our net income would have reached $83 million had it not been for the EUR 36 million one short financial expense. This resulted from the sale at a discount of $167 million in long-term accounts receivable from distribution companies related to the price stabilization law.
Just remember that the impact was about $50 million, but here we are presenting it net of taxes, this is why we show $36 million. In sum, net income dropped to EUR 47 million, basically due to the EBITDA drop and the financial expenses resulting from the implementation of a price stabilization law in late 2019.
Now let's go to Slide 37. Our net debt increased by EUR 245 million from year-end 2020. The main cash outflows included $199 million in CapEx, mostly in our renewable projects, $91 million in dividends, including the final dividend on 2020 net earnings and before $41.5 million provisional dividend paid in August and also $25 million in income taxes.
In terms of increases in net debt, you may note a $70 million increase in financial leases, which qualify as financial debt per IFRS 16. These are primarily related to land concessions such as the Pampa Yolanda and Pampa Fidelia land sites in the Antofagasta region for the future development of hybrid renewable projects. These contracts consider annual payments for up to 40 years and the present value of future installments is accounted for as financial debt.
On August 27, we disbursed the $125 million from the IDB Invest to finance the Calama wind farm, but this loan does not show up in this chart because the debt increase is fully netted out with the corresponding cash increase. So now let's look at the green bars representing the main cash inflows in 2021. This included $118 million in proceeds from the true sale of long-term receivables from distribution companies to Chile electricity PEC.
The next most important cash inflow was net operating cash flows, which decreased compared to the previous years, mainly due to high fuel prices, high marginal costs and lower collection from distribution companies due to the price stabilization role. So the following green bar shows a $24 million cash contribution from Minera Centinela, corresponding to equity increase in Inversiones Hornitos pursuant to the amendment to the shareholders' agreement signed in March 2020, together with the PPA renegotiation.
Finally, we received an $8 million payment from our 50% owned ten. So at year-end 2021, our net debt including financial leases reached EUR 1.04 billion. The following Slide #38, shows little change compared to the third quarter. Our international ratings remained unchanged at BBB+ and BBB. International scale, Feller Rate kept its AA- rating, although the outlook was changed to stable.
Net debt-to-EBITDA increased from 1.8 to 3.3x because of the financial leases, the IDB Invest loan and the EBITDA decrease in 2021, which we expect to recover in the following years as our renewable projects become operational among other reasons. On Slide 39, we can appreciate an increase in cash dividends paid with an increasing dividend yield. However, our share price has clearly underperformed the ETSA and has generally followed the declining trend of the 4 main generation companies in Chile. The main factors behind this trend include the perception of a more uncertain regulatory framework, effects from the pension fund withdrawals and slower operating performance due to the drought and high-skilled prices among others.
So well, this is all on my side and I'll leave you with Eduardo for the final remarks. Thank you.
Thank you, Bernardita. So we are summarizing the same key takeaways on Page 40. So first 2021, as I explained before, was a very difficult and complex year for ECL and also for the industry due to a combination of the different elements that we addressed during this presentation. It is also a wake-up call for the industry to take into consideration the current volatility in the future vinification of the system and the related risks during the energy transition.
Second, despite volatility, we have shared a new guidance for 2022, in which we are expecting an improvement compared to 2021, given the lower exposure in 2022 to spot prices. But as I mentioned, we are still navigating through a complex storm and going forward, we need to closely monitor hydro content for the second half of 2022 and the evolution in fuel prices and the availability of gas from Argentina in the Central region.
Third, we are glad that the first 2 renewal projects are ready and injected its total output to the grid. This is a very good step and we need to celebrate, but this is just the beginning and we have several challenges ahead to complete the plan. So in this line, we have secured additional backup PPAs with other generation companies to reduce our exposure on the spot price volatility during the transition phase and we'll be implementing several actions to accelerate the renewables plan.
And finally, despite increase in net debt-to-EBITDA explained by the lower margins in 2021, ECL still keeps a robust and flexible balance sheet to support the future investments. We plan to keep this flexible capital structure in the upcoming years, which would be possible, thanks to the additional operating margin, the new renewables will create for ECL. So well, with these final messages, we are concluding this presentation and thank you for everyone for your participation and we are ready for any questions and comments you may have for us.
[Operator Instructions] Our first question will come from Murilo Riccini with Santander.
Hi, Eduardo and Bernardita, many thanks for the call. I have 2 questions for you guys if I may. The first one, how should we think about the regulated demand for 2022, considering the adjustment of the new regulated PPAs from the competitors that you will start this year, the potential addition -- additional migration and also the profitability yield that seems not to be the base case at least for the short-term. Basically, what levels of regulated demand you were incorporating in your guidance? The second one, what is the average spot price and the difference or the spread between the Argentinian gas and the LNG used in the 2022 EBITDA guidance. That's it from my side. Thank you.
Hello, Murilo, thank you. Well, for 2022, we are considering in the guidance, we can say a conservative approach or usage of the regulated PPAs. If 2021 was close to 60%, 59%, 60%, for 2022, we are a couple of points below that percentage. And this is what we are using today in our guidance, but also because in -- 1 PPA ends in '21 related to [indiscernible], but in terms of usage, for the PPA in the same, we are considering a lower demand conservatively.
And then in terms of the Argentinian gas and the LNG, well, the LNG in the firm contracts that we have is probably very close to the Argentinian gas. Then the gap between the Argentinian gas and the LNG in the European or Asian market is huge, the gas in those markets is far above 20%, 25%, 30% at some point. But in Argentina, there is no infrastructure to export this gas.
So there is no opportunity cost like the one that we can see for the natural gas production in Henry Hub base. So basically, what I can say is that the firm contracts that we and probably other generation companies have are in some way close to the price at which currently the Argentinian gas is being imported in the Central region.
Great, thanks a lot.
You're welcome.
[Operator Instructions] As there are no more questions, this concludes the question-and-answer section. At this time, I would like to turn the floor back to Engie Energia Chile for any closing remarks.
Thank you, operator and thank you, everyone for your participation and we hope this presentation was helpful and we remain as always available for you for any further questions that you may have. And hopefully, we will see you soon during our next quarter. Thank you. Bye-bye.
Well, thank you very much and goodbye to everyone. Have a nice day.
Thank you. This concludes today's presentation. You may disconnect your lines at this time and have a nice day.