Good afternoon, everyone. Welcome to the Engie Energía 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.engie-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 Engie Energía 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, the Head of Corporate Finance of Engie Energía Chile . 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'll discuss the guidance that we have provided for 2022. Now let's start and please turn directly to page seven to go through the key messages that we want to share today. To page three, 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.
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. Finally, pushed also even higher by a strong recovery in electricity demand. As we also explained in the previous quarters, let's say the non-linearity and combination of these elements created a perfect storm and pushed the spot prices far off where the industry was expecting for 2021. In summary, we faced, during 2021, 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 MW Calama wind farm is ready and injecting to the grid. PV Tamaya with 114 MW is also ready. This morning, I mean today, this morning, we received the formal approval for its commercial operation from the market coordinator. Now both projects are in full operation, while then in 2022, we expect to reach the commercial operation date of two additional PV renewable projects with a combined capacity of approximately 270 MW.
In relation to the supply agreements signed with other generation companies, or as we can call them, backup PPAs, during 2021, we signed additional contracts for approx 0.6 TWh per year to hedge our position. 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 a second wave of 1,000 MW of additional renewables, together with the conversion of three 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 GW of renewables, while 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. Fourth, despite the 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 strong 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. Let's move to page four, we can see the evolution of ECL results during the last three intense years of our transformation process. First, this is to give context, we secured a 12 TWh per year contracted demand with an 11-year duration.
We started the 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 TWh per year during the last three years, and regulated PPAs represented almost 5 TWh 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.
On page five, we show the transformation path to replace the coal power plants that ECL is disconnecting with up to 2 GW of renewables that, as I mentioned in our previous calls, could be combined also with the storage solutions, and this is something that we are still analyzing. On page six, I just want to recall ECL's main strength. It's a long-term contracted portfolio of PPAs with the 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's main objective is to control and optimize the supply costs.
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 renewables that we are building have a longer life than these 11 years. Now, please turn to page seven 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 costs 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.
These are good news in terms of demand. On the supply cost, spot purchases during 2021 decreased 30% compared to 2020, and this is mainly explained by the need to run ECL's thermal plants to cover the lack of hydro production in the system. In this line, units 14 and 15 in Tocopilla, that were planned to be disconnected by the end of 2021, were requested by the market coordinator to remain available at least until June of this year. The also relevant piece of information is that our supply costs 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. This negative impact on the average supply costs is explained in the lower EBITDA and net result in 2021 compared to the previous year. 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 approximately $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 eight to explain the main elements that impacted 2021. These two 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 2 x higher than in 2020. Considering that ECL bought 3.2 TWh in 2021, we can get close to $150 million of additional costs, multiplying the 3.2 x the different spot price.
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 nine, we present the hydroelectric production during the last three 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 P98.
As you know, the new hydroelectric 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 the electricity produced with coal, LNG, and gas from Argentina would play a key role to replace hydro production. In this line, the fuel prices will also be a key driver for 2022. We can see in next pages, 10 and 11, what happened with coal and LNG. As we mentioned in this page, coal prices hit all-time highs in October 2021, then the Chinese government applied some controls and the coal prices decreased. 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.
This whole restriction was applied only until January 2020. The market is again returning to a normal phase. In between, we are facing again some volatility related to the crisis between Russia and Ukraine. This means we are still in a volatile environment, so we need to be cautious with this variable, considering that still 30%-35% of the electricity is produced in the system with coal. 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 increase in the European and Asian markets. This opportunity cost for LNG producers is driving the LNG price for spot purchases, and unfortunately, not helping to reduce average electricity supply costs 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 approximately 6 million CBM per day, and this is equivalent to 1,200 MW 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 PPAs. 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 the system's energy balance, the generation company, providing this hedge for the contracted volume. These are energy contracts only, and between 2022 and 2025, we have secured backup PPAs for average 2.5 TWh per year. 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 2021, and then in 2022, we are seeing an important amount of energy coming from backup PPAs. In addition, in 2021, we signed additional 0.6 TWh per year for the next three, four years. This will, of course, help to reduce the volatility on our energy margin, and this is a complementary strategy to the construction of renewables 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 contracts. 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. Then IEM, CTA and CTH power plants operate as base load units. The variable costs of our coal plants in general was higher because of higher coal prices. The rest of our coal units, which in 2020 were marginally dispatched, had to be dispatched in 2021, representing 12% of our power supply.
As we move to the right, we see ECL supplies 37% of its contract through purchases from both the spot market and backup PPA supply agreements. Finally, our two 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. We did this to hedge our spot exposure, but unfortunately at a higher LNG cost. The result was that our average supply cost increased, as we can see, from $52-$75, and this was partially compensated by an increase in the average monomic price, which also increased from $102-$112.
This means despite the total cost increase in $23, the average monomic price increased in $10, partially offsetting the negative impact. The new hydrologic year as from April 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, ECL results in 2021 were far below the guidance, given the combination of all the elements that I mentioned in previous pages. 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.
First, in this guidance, we are considering the most updated fuel curves and a similar hydrologic year during the period April 2022 to March 2023 to the hydrologic year that we faced in 2021. 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's spot prices.
In this guidance, we're 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. Third, ECL would be less exposed to spot prices with the new renewables 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 that, as I mentioned before, is representing approximately 1,200 MW of average production on a daily basis.
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. Also on coal prices, given its relevant impact on the system's spot prices. Our 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're considering that the system is returning to its normal failure or unavailability rate.
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 $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 renewable 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 two 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 3 x, given the lower EBITDA of $221 million and the recognition of land leases as a financial debt. During the next years, we should return to the baseline we defined to keep our leverage ratios not exceeding 3 x 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 renewables, we'll rapidly generate an additional EBITDA. In practice, and I mentioned this before, the renewables ECL is developing will replace the energy purchases in the spot market to supply the PPA demand. This means every 1 TWh per year of renewables production should at least create $30 million-$40 million additional EBITDA for the company. The following section describes ECL's transformation plan. The four pillars are described on page 19. On pages 20 and 21, we present our portfolio of clients and how the indexation of these PPAs will evolve in the medium term.
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. 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.
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. On page 22, we show a complete view of the transformation plan by type of technology to 2025. As you know, the key component is the development of 2,000 MW of renewables. 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 renewables 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. Let's go to the next pages. The next pages 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 renewable project, Wind Calama, reached its COD back in October 2021, adding 151 MW to our portfolio with a total investment of $160 million. On next page 26, we present the Tamaya solar plant, which is fully energized. As I also mentioned today, this morning, we received the formal COD from the market coordinator.
This is a 114 MW PV plant. This new plant required a total investment of $84 million. The next project on page 27, Capricornio Solar, had a delay in its original schedule, and it's 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 obtaining of certain archaeological permits for some ground tracts, as well as financial issues of its contractor, both influenced by COVID crisis, and the expected investment to include this project is $85 million. Well, the total investment is $85 million. On page 28, we present the global advance of Coya Solar project.
The project has a 65% global advance, and last quarter, we rescheduled 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 logistical issues that have been solved so far. That's why we expect this project will be ready during this year. On page 29, we have secured two 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 GW 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 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. Vientos del Loa and Lomas de Taltal, with a combined capacity of almost 500 MW, have received both their environmental permits, and we expect to launch their construction during 2022, at best time to market conditions, and should become the next wind projects to be added to our portfolio. Let's talk about the transmission projects. On page 31, we can see the three successful projects that were concluded in 2021.
These three projects are adding regulated revenues of 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 seven projects will add approx $5.3 million of regulated revenues and will require a total CapEx of $66 million. While on page 33, we present four additional projects that will require a total CapEx of $44 million. In summary, we are investing close to $150 million in new transmission assets that will bring additional regulated revenues to ECL. Between the three group of projects that we just presented, the regulated revenues could be close to $10-12 million per year.
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. Now, I think, Bernardita Infante will cover the following section about our financial performance.
Yeah, thank you, Eduardo. Good morning or good afternoon to everyone. Let's go to slide 35, please. The 31% EBITDA drop in 2021 is basically explained by two main factors, as Eduardo has already explained. One is the severe and prolonged drought affecting Chile, with 2021 being one of the driest years ever, and two, the dramatic increase in fuel prices, especially in the second half of the year. 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 U.S. inflation, as well as coal and gas prices.
The tariff discount agreed in the March 2020 renegotiation on the Centinela PPA was smaller in 2021 than it was in 2020. Higher prices explain a $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 15, that we were planning to close at the end of 2021. The lower volume of spot purchases had a positive $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 $21 million positive impact. Demand from our mining clients increased, offsetting the end of the Zaldivar PPA in June 2020. Our 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 $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 the new transmission tariff decree on the valuation of our investment in TEN. The most significant negative impact of $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. All of these changes, taken together led to EBITDA of $315 million in 2021, down from $455 million in 2020.
Now, if we move to slide 36, this slide shows the evolution of net results, which went from $164 million in 2020 to $47 million in 2021. Last year, or rather in 2020, we reported non-recurring expenses of $10 million related to the premium paid on the early redemption of the $400 million 144A bond, which we refinanced with a new $500 million bond. Our net recurring income in 2020 reached $181 million. As we could see in the previous slide, in 2021, our EBITDA fell, impacting our net results by $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 the 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 $36 million one-shot 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 $47 million, basically due to the EBITDA drop and the financial expenses resulting from the implementation of the Price Stabilization Law in late 2019. Now, let's go to slide 37. Our net debt increased by $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 the $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. This loan does not show up in this chart because the debt increase is fully netted out with the corresponding cash increase. Now, let's look at the green bars representing the main cash inflows in 2021. These 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 Law. The following green bars show 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. At year-end 2021, our net debt, including financial leases, reached $1.04 billion. The following slide, number 38, shows little change compared to the third quarter. Our international ratings remained unchanged at BBB+ and BBB.
In the national scale, Feller Rate kept its double A minus rating, although the outlook was changed to stable. Net debt to EBITDA increased from 1.8x - 3.3 x 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 increase in dividend yield. However, our share price has clearly underperformed the IPSA and has generally followed the declining trend of the four 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 fuel prices, among others.
Well, this is all on my side, and I'll leave you with Eduardo for the final remarks. Thank you.
Thank you, Bernardita. We are summarizing the main key takeaways on page 40. 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 planification of the system and the related risks during the energy transition. Second, despite the volatility, we have shared the new guidance for 2022, in which we are expecting an improvement compared to 2021, given the lower exposure in 2022 to spot prices.
As I mentioned, we are still navigating through a complex storm, and going forward, we need to closely monitor hydro conditions for the second half of 2022, and the evolution of fuel prices, and the availability of gas from Argentina in the central region. Third, we are glad that the first two renewal projects are ready and injecting 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. 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.
Finally, despite increasing 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 will be possible thanks to the additional operating margin the new renewables will create for ECL. 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.
Thank you. The floor is now open for questions. If you have a question, please press star one on your touch-tone phone at this or any time. If at any point your question is answered, you may remove yourself from the queue by pressing star two. Questions will be taken in the order they are received. We do ask that when you pose your question, that you pick up your handset to provide optimum sound quality. Please hold while we poll for questions. Our first question will come from Murilo Riccini with Santander. Please go ahead.
Hi, Eduardo, Bernardita. Many thanks for the call. I have two questions for you guys, if I may. The first one, how should I think about the regulated demand for 2022, considering the adjustment of the new regulated PPA from the competitor that will start this year, the potential additional migration and also the portability bill that seems not to be the base case, at least for the short term. Basically, what levels of regulated demand you are 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 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. This is what we are using today in our guidance, but also because one PPA ends in 2021, related to Eólica Monte Redondo. In terms of usage for the PPA in the sense, yes, we are considering a lower demand conservatively. 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 Argentine gas. The gap between the Argentine gas and the LNG in the European or Asian markets is huge. The gas in those markets is far above $20, $25, $30 at some point. 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.
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. Many thanks, Eduardo.
You're welcome.
Again, if you have a question, please press star then one. 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 Energía Chile for any closing remarks.
Thank you, operator. Thank you everyone for your participation. We hope this presentation was helpful. We remain, as always, available for you for any further questions that you may have. 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 line at this time and have a nice day.