Morning, ladies and gentlemen. Thank you for waiting. I'm Margarita Chun from IR, and we would like to welcome everyone to Pampa Energía's Third Quarter 2022 results video conference. We inform you that this event is being recorded. All participants will be in listen-only mode during the presentation. After the company's remarks, there will be a Q&A session. Questions can only be submitted in writing through Zoom. Should any participant need assistance, please send us a chat message. Before proceeding, please read the disclaimer that is located on the second page of our presentation. Let me mention that forward-looking statements are based on Pampa Energía's management beliefs and assumptions and information currently available to the company. They involve risks, uncertainties, and assumptions because they are related to future events that may or may not occur.
Investors should understand that general economic conditions and industry conditions and other operating factors could also affect the future results of Pampa Energía and could cause results to differ materially from those expressed in such forward-looking statements. Now I'll turn the video conference over to Lida Wang, the Investor Relations and Sustainability Officer of Pampa Energía. Please go ahead.
Hello, hello? Do you hear me? Okay. Sorry. Technical problem. Anyway. Thank you, Maggie. Hello, everyone, and thank you for joining our conference call. I will make it short and sweet so we have plenty of time for Q&A with our CEO, Gustavo Mariani, who's here, and our CFO, Nicolás Mindlin, who is here as well. Let's start with the quarter's figures. It's been another solid quarter for our businesses, though gas made it to the headlines again, as expected. Revenues increased 11% year-on-year and 10% quarter-on-quarter to $621 million, mainly driven by seasonal gas sales, petchem, commodity prices, electricity spot prices, and Energía Plus. However, the end of Loma and Piquirenda PPA last year mainly offset these increases, as well as Loma's gas turbine number 5 outage and lagged regulated tariffs. 87% of our sales were dollar-linked.
The remaining are electricity spot, and regulated utilities. Those are in pesos. The adjusted EBITDA amounted to $246 million, 5% less year-on-year, but similar quarter-on-quarter, basically explained by the same reasons detailed before, plus higher payroll in U.S. terms, dollar terms. As you can see on the right below, the business share flipped, and now oil and gas leads the consolidated adjusted EBITDA, thanks to our gas business, which took almost half of our EBITDA. CapEx in Q3 was 87% higher year-on-year and 27% up quarter-on-quarter, mainly due to the fast pace at our power expansion project, PEPE 3, and to a lesser extent, the finishing touches in Barragán. E&P remained similar to last year, but it's 27% lower than Q2, as drilling and completion activity slows down during the winter peak. Moving on to power generation.
As seen on slide 4, we posted an EBITDA of $89 million in Q3, down 29% year-on-year and 10% quarter-on-quarter, mainly due to the maturity of these PPAs that we talk about and outages at Loma that we mentioned before, plus higher pesos expenses offset by better spot energy. This is thanks to the price increases back in February and June and increased thermal B2B sales, known as Energía Plus. Q3 dispatch was 17% down year-on-year, mainly due to limited gas procured by CAMMESA for power generation, affecting mostly Genelba Barragán, which triggered higher dispatch firing liquid fuels. This quarter, we also experienced certain outages and program overhauls offset by higher water input. The power generation business model relies on take-or-pay capacity payment, so availability is what matters most.
In Q3, we reached an outstanding rate of 96%, just a little bit above the 95% recorded last year. It would have been higher if it wasn't for Loma number 5 outage. Pampa's availability was way above the system average that it recorded 78%. Regarding our expansion at Ensenada Barragán, the closing to CCGT is advancing as we are entering the last stages towards the COD. We successfully performed the steam blow and carry out our facilities reinstatement works to deliver the first steam to the turbine. We also keep working on commissioning the water treatment plant and the cooling tower. Around 200 people are working daily on this project to achieve the COD forecast by the end of this year. Moving to PEPE 3, PEPE number 3, wind farm expansion. The project is now 72% advanced. We completed the civil works and the wind turbine bases.
We also received all the wind turbine components at the port of Bahía Blanca. As of today, we have nine wind turbines ready to be assembled. Vestas, who is our supplier, is already assembling the first section of the towers and the nacelles. The estimated COD is split in two stages, the first 54 MW by February 2023, and the remaining 27 MW by March 2023. Moving on to E&P. Between May and August, we delivered close to 11 million cubic meters per day, as stipulated in Plan Gas. Still, because of better weather and hence lower demand, we reduced to almost 10 million cubic meters per day in September. However, our gas production in Q3 outperformed by growing 20% year-on-year and 6% quarter-on-quarter, averaging 10.7 million cubic meters per day and outpacing nationwide growth that only increased by 4%.
76% of the quarter's production came from only one block, that's El Mangrullo, and almost all its tight gas. This month, we are adding 3.3 million cubic meters per day of evacuation and treatment capacity at El Mangrullo, reaching 14 million cubic meters per day of capacity, more than doubling last year's. Río Neuquén and Sierra Chata also contributed to the growing output, but at a smaller pace. Though tight gas is our primary production source, we are drilling shale gas wells to increase our share. We drilled four shale gas wells at Sierra Chata and also drilled and completed two tight gas wells. Last Friday, we also received news regarding the tender tapping the new pipeline, the extension of Plan Gas until 2028, and exports can be done on a take-or-pay basis during winter season, but following certain restrictions.
All are good signs towards bringing more stability to the gas market, but we are still waiting for more details. Briefly commenting on E&P business, figures as seen on slide eight. We posted an adjusted EBITDA of $117 million in Q3, the highest quarter since 2018. This figure is 13% up year-on-year and 15% up quarter-on-quarter, explained by the gas performance mentioned before and the higher realizable prices, offset by increased costs related to the growing activity, exports, and payroll expenses. Our total production averaged more than 68,000 BOE/d , of which 92% is gas. Our lifting costs grew by 45% year-on-year and 16% quarter-on-quarter, explained by the Plan Gas increased commitment. However, the lifting cost only increased 22% year-on-year and 8% quarter-on-quarter, recording $6.6 per BOE, evidencing the efficiency of our operations.
Zooming in, crude oil represented 20% of the segment's revenue in the quarter. The volume sold was similar year-on-year, but 20% up quarter-on-quarter, almost 6,000 bbl/d of nearly own production. During the quarter, local sales increased, offset by reduced exports. Realized price was more than $70 per barrel, primarily due to the Brent's and the gradual rise in the domestic price. Back to gas, our average gas price of the quarter was $4.8 per million BTU, 9% up year-on-year and quarter-on-quarter, driven by seasonality and export prices. This price is also the highest since 2018. Regarding the sales breakdown, Q3 is in peak season, which is a skew to retail because they hold priority under Plan Gas. As a result, we slightly reduced B2B share and gained exposure to exports despite selling in spot markets.
Export share will take off during Q4 as we began exporting 1.5 million cubic meters per day on their take-or-pay basis since October until May of next year to Chile. Okay, briefly about petrochemicals. It delivered another outstanding EBITDA of $19 million in Q3, much higher than the last year's $7 million. This is primarily contributed by better prices of reforming, plus the higher dispatch of octane bases in the local market, partially offset by higher raw material costs. However, quarter-on-quarter, the EBITDA remains similar because of the higher sales volume was offset by a reduced styrene margin. Sales volume was 7% down year-on-year, mainly due to lower exports and higher industry conflicts, offset by local demand growth for styrenics and octane bases. In Q3, one-third of the total sales volume was exported. Moving on to the cash flow.
We recorded a free cash flow of $11 million, driven by the outstanding operating performance from all three businesses, helped by leaner working capital offset by debt service. The increased debt considers the pesos raised in the local market and nets from the 2023 notes exchange we finalized last August. In addition, in Q3, we collected $20 million out of the $40 million from the Edenor sale final milestone, so we concluded that sale and acquired the full ownership of Mario Cebreiro Wind Farm for over $20 million. In summary, we generated $119 million of net cash flow in the quarter, achieving $685 million of cash in September. Moving on to the slide 12. This slide shows the consolidated figures of our financial position, including our affiliates at ownership. But let's just focus on the restricted group that reflects the bond parameter.
The net debt reflects the successful exchange of 2023 notes by issuing $293 million of amortizing 2026 notes and paying down $122 million in cash. Hence, we lower our international debt. In addition, taking advantage of the domestic liquidity and from the higher seasonal working capital from CAMMESA, we also issued a local bond for ARS 22 billion due in 18 months and took ARS 7 billion net peso-bearing loans and $7 million of pre-import credit facility. We posted a gross debt of $1.6 billion, similar to last quarter. 85% of that is dollar-denominated, bearing an average interest rate of 8.3%. Net debt and leverage ratio remain similar at $927 million and 1.3x . The average life decreased slightly to 3.7 years. As you can see, Pampa does not face relevant debt maturities until 2027. This concludes our presentation.
Now, I will turn the word to Maggy, who will poll for questions. Thank you.
Thank you, Lida. The floor is now open for questions. If you have a question, please send us a Zoom chat. We will read and answer them in the order received. Also, please make sure your name and company are correctly displayed so that we can introduce you to the audience. Should any participant need assistance, send us a chat message or raise your hand. Please hold while we poll for questions. Our first question comes from Maria Moyano from the company Adcap. Her first question is regarding the PPAs, if the company has a plan to replace the mature PPAs. Another question is regarding the lack of gas for power generation, if it is still in place, the lack of gas for generation, and the delays on CAMMESA payment.
Okay. Hi. Good morning, everybody. Thank you for joining. Thank you, Maria, for your question. Regarding the replacement of the PPAs, we have been working the last two years on the closing of the combined cycle of Central Térmica Ensenada Barragán together with YPF. That is an expansion of 280 MW that we will begin, hopefully, the PPA by year. That will be an addition of an important PPA for Pampa. Also, we have been working this year on the expansion of PEPE 3, as Lida has mentioned. Those are another 80 MW of wind farm that will be online, I think even sooner than what Lida has just announced. I think we may have a small portion of it even before year-end, and the rest within the first quarter of next year. The other issue was regarding lack of gas, right?
This year has been peculiar in terms of pricing. Liquids for the first time in, I think, history, liquids meaning diesel oil, was cheaper than imported LNG. CAMMESA tried to maximize the use of liquid fuels, diesel oil and fuel oil, vis-a-vis the use of imported natural gas. Obviously, that was during the winter season. It won't happen now in spring and during the summer and next autumn. But on the winter of 2023, we are envisioning a similar situation. At least that is what the futures of LNG are telling us, are more or less in the same range that they were this winter, or even a little bit more expensive. We think that next year, CAMMESA will also try to maximize the use of liquid fuels vis-a-vis imported LNG. The last question was regarding the delays of CAMMESA. CAMMESA, I don't have the exact number.
Probably you can put it on the screen.
Yeah.
Okay. The last three months, CAMMESA has improved its payment regularity, and currently, the last payment was with a 25 days of delay vis-a-vis the contractual obligation. It has been improving. We hope that the worst is over. The worst is during the winter, that CAMMESA has to spend a lot of funds in importing fuels. I think that the spring and summer months are easier in terms of funding for CAMMESA, so we should collect with less delays. At least that is what we're expecting.
Thank you, Gus. Our second question comes from Frank McGann of Bank of America. He has two questions. The first one is: What are your current expectations for gas production over the next two years?
Hi, Frank. As Lida mentioned, we have been investing in order to increase our production capacity, especially at El Mangrullo area, and we are just finishing a new gas plant treatment, which will allow us to increase production going forward. How much it will depend on the auction that we are expecting any time, and for the fulfillment of the new pipeline that is expecting to be available online next winter. Once that bidding process is over, we will have more clarity as to our gas production moving forward in the next two years.
Thank you, Gus. The second question of Frank is about, could you please remind us of the timing for the ending and startup of PPAs through 2023 and 2024? It was kind of answered before.
No, but that. Okay. No. I think we do not have any maturities of PPA in the next couple of years. I think the next PPA maturing is in 2026. Is that correct?
July.
July 2026. For the next three and a half years, we do not have any maturity of PPAs.
Thank you, Gus. Our next question comes from Alejandro Demichelis from Nau Securities. He has two questions, but the first one is very similar to Frank's question. It was about the visibility of Pampa's gas production until 2028. We need more information regarding the tender first. The second question was about an M&A opportunity. If we have interest in increasing our stake in Río Neuquén block. Currently, we have one-third of the block. How is the situation with Petrobras?
Yes, Petrobras Brazil has announced that it has launched an M&A process to divest its one-third stake in the block. There we are partners with YPF. It's one-third each. We will analyze the opportunity. We are interested in participating in the process. It will be a competitive process, so we will see how it goes. We do have, the same way YPF, we have a right of refusal on this area. So depending on the price at the end of the process, we might decide to exercise our right or not, but that's something to be seen.
Thank you, Gus. Our next question comes from Bruno Montanari from Morgan Stanley. He has three questions regarding E&P business. The first one is, can you provide an update of the Néstor Kirchner pipeline project? Does the industry expect it will be ready on time for next winter?
Hi, Bruno. Well, I don't want to speak for the industry. I don't know what the industry is expecting. We are optimistic that it will be ready. At least, as you know, aside from Pampa, we are involved in one of the construction companies that it's involved in the construction, and they're working at full speed. Pipes have already begun to arrive to the construction sites. So the work is in progress, and so far, there are a lot of hurdles, but so far, we haven't identified yet anything that make us pessimistic about not being able to reach the conclusion of the pipeline for the end of June of next year. I would assume that the industry thinks the same way, but honestly, I don't know.
We are optimistic that the pipe will be ready, and it is actually quite important, not only for the industry but for the country as well. Because given the price differential and the fact that the local gas, even though it is priced in dollars, is paid with pesos, while imported LNG is paid with dollars. In terms of the amount of dollars that will not be spent, if the pipe is ready, it is around between $2.5 billion- $3 billion that will not be needed if the pipe is ready by the end of June. So it is a very important contribution to the Central Bank reserves.
Thank you, Gus. The second question from Bruno is regarding the expected CapEx, the investment for E&P business for the next two years. How much of the CapEx is conditioned to the pipeline being ready, and what is the corresponding production amount that can be linked to the incremental CapEx? Before answering, keep in mind that we do not give guidance. This is our latest figure.
This is for me. The CapEx for 2023 will be conditioned by the pipeline being ready next year. But I think more important to that will be conditioned to our success in the bidding process to fulfill that pipeline. Still cannot give you We think it is going to be in the area of $500 million, the CapEx for this segment. Part of that is in order to keep the production, and a portion of that, majority of that, is to increase production if we are successful in the upcoming Plan Gas bidding process for the fulfillment of the Néstor Kirchner gas pipeline. 2024, again, it is related to the same thing, so cannot give you any figures.
Thank you, Gus. The last question from Bruno is regarding lifting costs. Lifting costs have increased on the back of inflation. What can you expect for costs going forward? Should we assume they stay at current level, or is there anything the company can do to try to manage costs?
I think one of the reasons that the lifting costs have been going up is the fact that we have been recently investing in new capacity that is not fully utilized yet. We hope if we are successful, as said before, in the bidding process, and we are able to increase our production of natural gas, and we have a better utilization rate of the new plant that has been recently been online. I hope that lifting costs will come down slightly.
Thank you, Gus. Our next question comes from Konstantinos Papalias, from PUENTE. He has three questions. One of them is already answered because it was the outlook of the new pipeline. The second question is about what is the position or strategy that Pampa is looking for the upcoming Plan Gas rounds?
Look, I think I already answered that. We are eager to increase our participation in our market share in the gas industry. We are looking forward to that, but it's a competitive process, so we cannot discuss the strategy, as I think it won't be in our best interest. But I think as we have been saying several times, we are looking to increase our market share.
Thank you, Gus. Kostas' second question is about the upcoming winter outlook. Could you give us a color of how do you see the upcoming winter, considering that we won't have the regasification ship at Bahía Blanca, and still we don't know if we will have on time the new pipeline?
Yeah. I think it's very important that the pipeline, it's there for next winter. Otherwise, as you correctly pointed, if we don't have the ship, that means on average around 13 million cubic meters of natural gas less, coming from Bahía Blanca. That needs to be replaced by the 11 million that will be contributed with the Néstor Kirchner pipe on the first stage. Remember that once the pipe is complete, the second stage is to add compression capacity to that pipeline, and the capacity of the pipe goes from 11 to 22. It doubles. But for next year, the balance will be 13 million less injected by the LNG ship that won't be there anymore. It's replaced by 11 from the new pipeline being ready, hopefully by the end of June of next year.
Thank you, Gus. Our next question comes from Paula La Greca from TPCG. She has two questions, but the first one is about the lifting cost that is already answered. The second question is, when are you planning to shift gas production from the tight gas fields to the shale fields?
We are currently shifting from tight to shale. Actually, the campaign that we have already started, but it will intensify as we approach next winter. It's a combination of both tight gas wells and shale gas wells. It's not a different field. It's a different horizon. Within El Mangrullo area and the same in Sierra Chata, we have both horizons, the Mulichinco and the Vaca Muerta. That it's tight gas and shale gas in the case of Vaca Muerta. So although we will still be drilling a few tight gas wells next year, most of them, we will be drilling between 30 to 35 wells next year. Most of them will be, and I'm speaking about the areas that we operate. Most of them will be to shale gas, to Vaca Muerta, to shale gas horizons.
Thank you, Gus. Our next question comes from Rodrigo Nistor, from Latin Securities, former AR Partners. He has three questions. But the first one regarding the gas pipeline and the upcoming winter outlook is already answered. His second question is about the oil business. Are you actively looking to increase focus on crude oil production? If so, what is the current status of your expansion plans?
On the oil side, in the area that we operate, we don't fully own the area. We have a partner. We are discussing with our partner and trying to get to an agreement in order to begin the development of the area. First, we need to do some pilot project, some exploration, and then the development. We are eager to start as soon as possible, but we are discussing with our partner, as we need to get to an agreement before beginning. We hope, we are optimistic that we will be able to do so at some point next year.
Thank you, Gus. The last question from Rodrigo is about the power generation business. He has two questions regarding power generation. The first one is: do you expect any tariff increase for the legacy units?
We are discussing that with the authorities. Nothing has been published. They understand that we are running behind inflation by a big amount, and that the sector needs an improvement, an adjustment in order to cope with the inflation that has been very high this year. We hope something will be announced before year-end, but we don't have any security yet or confirmation yet.
Thank you, Gus. Also, he wanted to know, regarding the hydro concession maturing in 2024, any color on that, of what the provincial and national government's plans to do?
No. We don't have any visibility as to what the government will be doing next year. They are studying the situation. In our case, our hydro concessions do not mature next year. Ours mature in 2024, and in the case of Pichi Picún Leufú, in 2029. So we still have time. It's not something that will impact our business next year.
Thank you, Gus. Rodrigo had another question regarding the CAMMESA delays on the payment, but it was already answered. We are moving on to the question of Ezequiel Fernández. He has four questions. The first one is already answered. It was about the E&P business, CapEx, and the plans of wells to be drilled next year. The second question is about the LNG project announced by TGS. It is being evaluated by TGS. If we understood this is right, it could involve a 2-million-ton per year modular project. We estimate $1 billion of CapEx. Would you consider taking the decision about moving forward with this before the elections? If so, would you expect a significant equity investment from Pampa into TGS?
Yes, we hope to be able to take a decision on the project before next year election. We do see this project as strategic for us, for the sector, and for the country as well. Argentina has a big seasonality in its consumption of natural gas. If we want to supply locally all the natural gas that is consumed during the winter, we need to, in order to be efficient, to be able to export during the summertime, the gas that is not consumed in Argentina. So an LNG project is crucial for that. It goes beyond any political results on the elections. So we are working as fast as we can in order to be able to take the decisions and start the project. It's not easy. It's a very complex project, so it takes time, even more than we thought initially.
We hope to be able, in the first semester of next year or during the first quarter of next year, to be able to take a decision. Regarding Pampa's involvement in the project, still to be discussed. It's going to be a joint venture, so it will certainly be a capital contribution from Pampa into the project, but amounts are still not defined.
Thank you, Gus. The third question from Ezequiel Fernández from Balanz is about an M&A opportunity. Which sub-sectors of the Argentina energy chain do you perceive as more attractive for acquisitions right now?
With the sale of Refinor, we just finished divesting in our non-core assets, many of them acquired when we bought Petrobras Argentina asset, to focus our resources in our main businesses such as power generation and E&P. Now we are analyzing some M&A opportunities in shale oil and renewables, but nothing in concrete yet.
Thank you, Nico. There is another question from Ezequiel. This is the last one. Would you expect to start paying corporate taxes next year, or do you still have tax offsets to use?
I think on 2023, we still have carryforwards. Tax carryforwards? Sure. Okay. No. We are not expecting to pay income tax next year.
Thank you, Gus. Kostas Papalias from PUENTE added one more question. It is about the overdue receivable of Plan Gas. Could you give us an estimate on the overdue receivable from the Secretariat of Energy regarding the natural gas sales under the Plan Gas regime?
Hi. We were just discussing here if somebody remembered the exact number. The reason why we don't remember is because it's not as important because the subsidy goes only on the portion that we sell to distribution companies. We are collecting with a little bit more delay than what we are collecting from CAMMESA, but nothing significant. It's similar to what we are collecting from CAMMESA. And it has been improving recently.
Thank you, Gus. The next question comes from Anne Milne from Bank of America, but it was already answered. She wanted to know the estimation of Pampa's participation in the Plan Gas. The following question comes from Daniel Guardiola from BTG Pactual. He has four questions, but some of them were answered. The first one was regarding PPA maturities. The second question was the potential EBITDA that we estimate for next year for the power generation business, considering the PPA for recently mature.
Maggie will remind me that we don't give projections, so I cannot give you a number. But no, I think the adjusted EBITDA for next year in the generation segment will go up because we don't have any PPAs maturities as I mentioned, the following maturity will be in July 2026, and we do have the addition of the wind farm and Central Térmica Barragán. So we are expecting the EBITDA of the segment to recover next year.
Thank you, Gus. The third question of Daniel Guardiola was already answered regarding the gas pipeline status. The last question from Daniel Guardiola was about the maximum transportation capacity to export gas to Chile and at what price we are exporting this gas.
From the Neuquén Basin, we have two pipes. The GasAndes, with a nominal capacity of 10.5 million cubic meters of natural gas. Because of some restrictions on the Argentine side and also some restrictions on the Chile side, the average number is between 8.5 to 9 million cubic meters of natural gas per day through GasAndes. Through that pipe, currently, Pampa is exporting 1.5 million cubic meters of natural gas per day at an average price, slightly above $8. If I think correctly, $8.20 or $8. Slightly above.
That's gross.
That is gross price. Net of export tax is slightly below $8. The other pipeline is Gas Pacífico. That it has a similar capacity, but there is this very small demand on the Chilean side where that pipeline is arriving. Argentina is currently exporting about half a million cubic meters of natural gas through Gas Pacífico.
Thank you, Gus. We have another question from Kostas from Puente. It is about power dispatch during winter 2023. What are your expectations for power dispatch during winter 2023, taking into account natural gas availability, the lack of regasification ship in Bahía Blanca, and the expected expansion in gas pipeline? What if the new gas pipeline COD is delayed by a few weeks?
Hi. Well, as I think it has been answered before, if the pipeline is delayed, it is going to be a very tough winter, as CAMMESA will have to stretch its consumption of liquid fuels. In terms of gas availability, we envision a winter similar to 2022 winter. We expect, that is our most likely scenario, that by the end of June, the new pipeline will be available, replacing what in 2022 has been imported through the LNG ship in Bahía Blanca.
Thank you, Gus. Our next question comes from Florencia Mayorga from MetLife. She has two questions. The first one is: Any update regarding easing FX restrictions for oil and gas companies? There was a regulation issue.
There is a 277 decree that allows oil and gas companies that are increasing exports to have access to the official FX for some uses, such as their repayments, imports, dividends, but this has not been completely implemented yet. In case it is regulated, it will give Pampa the chance to access the official FX for almost $40 million per quarter.
From this year.
From this year, right?
Mm-hmm. From this year.
Oh, $40 million per quarter.
Thank you, Nico. The second question from Florencia is about M&A. It was kind of answered, but after the sale of Refinor, any other asset that you are planning to divest or any M&A?
As I said before, there are not any relevant divestments on the pipeline now after almost five years and a lot of sales, including the downstream business, the Entrelomas assets that we sold to Vista, our stake in Oldelval, the other 25% of TGS and some others. With the sale of Refinor, we managed to divest all of the assets that we acquired from Petrobras that were not core for Pampa. Regarding buys, as I said before, we are analyzing some opportunities, mainly in renewables and in shale oil, but there is nothing concrete yet.
Thank you, Nico. The following questions, some of them were already answered. It was Daniel Guardiola regarding the power generation business, CapEx deployment, and funding requirements. Keep in mind that the power generation business is self-funding with the operating performance of its EBITDA generation. In the case of Juan José Muñoz from BTG Pactual, he wanted to know more about the Plan Gas extension and more color about the agreed gas price for the next years. Already answered. We are still waiting for the tender. The next question comes from Martin Honorato: Do you have problems with importing products that delays some projects?
Okay. I don't want to say so far, we didn't have any serious problem. We have been able to import all that we needed. But this is a problem, every day, the situation gets, in a way, more complex. For example, it's key for our intention to grow production in natural gas next year to have a new fracking equipment available, that we want to import because all the sets for fracking that are in Argentina are already committed for next year. So we need to import a new set, and we are still dealing with the complexity of the matter. We are optimistic we will solve it, but it's key for our production in 2023.
Thank you, Gus. Considering that we are running out of time, we are answering the last question from Andrés Cardona from Citibank. He has two questions. Any chance you reconsider to do capital allocation to the oil window of Vaca Muerta? Business economics have materially improved recently.
I fully agree that the outlook is very good, and we have been working this year in order to begin the development of an oil area. As I explained before, the area that we own, we own about 50% of it, so we need to reach an agreement with our partner, and sometimes it's not as easy as you would think. It takes time to reach a consensus to begin the development. We are working on that. We are eager to do so, and we hope we will be able to announce something next year.
Thank you, Gus. The last question from Andrés Cardona is regarding E&P. Can you please provide an update about full-cycle break-evens for gas at both tight shale assets? Can you please split between OpEx and CapEx?
Hi, sorry. Our lifting cost is already provided in the presentation. It's around $0.70. It's between $0.70 and $0.80 per million BTU. Full cycle depends a lot. I would say shale gas is way higher, as we are still not in a factory mode, but it's pretty close to $4 for shale. For tight, it's way lesser, of course. You can see at our financial statements that our operating cash flow in E&P, it's positive. Prices are quite accommodating in the full circle in tight gas.
Thank you, Lida. This concludes the Q&A session. We will turn to Lida for final remarks.
Thank you, everybody, for joining our call. We are on top of the hour. Gus, would you like to comment on something that we missed? Petrochemicals, maybe? If you should have any questions, I think we answered all of them, seriously this time. If you have any, just reach out, Margarita and I, we will be very happy to answer them. Thank you, and have a good year, and see you next year.