Canacol Energy Ltd (CNECCL.SN) Earnings Call Transcript & Summary

Welcome to the Canacol Energy Business Update Conference Call. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Carolina Orozco, Vice President of Investor Relations. Please go ahead.

Good morning, and welcome to Canacol's Medellin Exit and Bolivia entry Conference Call. This is Carolina Orozco, Vice President of Investor Relations. I am with Mr. Charle Gamba, President and Chief Executive Officer; Mr. Jason Bednar, Chief Financial Officer; and Mr. Anthony Zaidi, Vice President of Business Development and General Counsel. Before we begin, it is important to mention that the comments on this call by Canacol's senior management can include projections of the corporation's future performance. These projections neither constitute any commitment as to future results nor take into account risks or uncertainties that could materialize. As a result, Canacol assumes no responsibility in the event that future results are different from the projections shared on this conference call. Please note that all finance figures on this call are denominated in U.S. dollars. We will begin the presentation with our President and CEO, Mr. Charle Gamba, who will summarize the changes in our plans announced yesterday. Following those statements, we will have a Q&A session. I will now turn the call over to Mr. Charle Gamba, President and CEO of Canacol Energy.

Thanks, Carolina, and welcome, everyone. As per our press release yesterday, we have made the decision to terminate the long-term take-or-pay gas sales contract with EPM, under which we were scheduled to commence gas deliveries on December 1, 2024. We've also canceled the contract with SETCO who were to build, own, operate and maintain the pipeline. Our decision to terminate the contract with EPM was driven by: one, delays in the process of obtaining the environmental license required for the building of the pipeline originally scheduled for July this year; two, increasingly difficult, legal, social and security circumstances. Three, the dynamics within the Colombian gas market. And four, the corporation make a decision to invest in its natural gas exploration programs in the Middle Magdalena Basin in Colombia and now in Bolivia. Following a careful review of all of the relevant factors, the corporation decided it prudent not to execute the Jobo to Medellin pipeline project. Following the termination of the Medellin pipeline project, we plan to: one, reduce capital spending in the Lower Mag Basin starting in 2024 since the volumes planned to be sent to Medellin will no longer be necessary. Two, planned longer-term capital spending in the Lower Magdalena Basin to target full use of existing transportation infrastructure; three, drill the high-impact Pola-1 exploration well in the Middle Magdalena Basin in the second quarter of 2024, which is targeting a very large resource potential, which, if successful, could be commercialized into the interior market of Colombia, including Bogota and Medellin via the existing TGI gas pipeline located 10 kilometers to the east of the Pola location. And finally, four, use excess capital originating from a reduced Lower Mag Valley program to reduce debt. As we announced yesterday, we have made a strategic entry into Bolivia, which holds significant promise as a material new gas exploration and production base for Canacol, equal, we hope to that of Colombia in the midterm. For the past 5 years, our new ventures team have assessed most of the major onshore gas prone basins in South America, looking for an entry opportunity that exposes Canacol to material economic gas opportunities characterized by the presence of a significant gas resource, easy access to infrastructure, stable contractual terms, a benign operating environment and access to markets where gas commands a good price. After zeroing in on Bolivia, we have spent 4 years working with YPFB, state oil and gas company to locate, identify and negotiate 4 E&P contracts that fit those criteria. We've now executed 3 contracts and are seeking government approval for 1 additional contract, which has a significant gas field redevelopment project, where we expect to initiate production in gas sales in 2025. Similar to our decision to enter the Colombian gas market in 2012, Bolivia has also seen underinvestment in exploration for the past 2 decades, resulting in decreasing gas production from large discoveries made decades ago and significant spare capacity in gas processing and transportation infrastructure. Unlike Colombia, Bolivia has the advantage of being able to export large quantities of gas to international markets, including Brazil, where gas prices are linked directly to global LNG prices. The potential for attractive returns on investment are increased by the fact that we have been able to secure multiple blocks in close proximity to one another within a prolific gas prone basin containing multi-zone drilling potential which should allow us to operate cost effectively from the outset. Potential gas production from these blocks should be relatively easy to commercialize as they are strategically located along the main gas pipeline routes with export to Brazil and we anticipate commencing investment in operations in 2024. I'd like to thank our new partners YPFB for getting to this point and look forward to providing more details of our planned operations there in the near future. Before I open the call to questions, note that we are planning to host our Q3 conference call in less than a month. when we will discuss our third quarter results. We also typically don't announce our budget for the following year until December after we finalized sales contract negotiations for the year in Colombia. With that said, Jason, Anthony and I are open to questions.

We will now begin the question-and-answer session. in. [Operator Instructions] Our first question comes from Oriana Covault from Balanz.

I had 3 questions, if we may go one by one, that would be great. First, it has to do with any exit fee or and/or penalties associated with ending the contract with EPM, understanding that is it a declaration of course, or that it could be an argument to call out of the contract? That would be the first one.

Anthony, if you could respond to that question.

Yes. Our reasons for terminating the contract do not trigger the penalty clause or provision and as the contract was not in execution phase, it was still awaiting the environmental license as a condition precedent, at this time or exit does not involve any penalties.

Okay. And just moving on to perhaps more of the estimated CapEx savings that are associated with the decision to terminate EPM contract? And just linking with the development plans in Bolivia, perhaps if you could add more color in terms of the investments, how would be the strategy in Bolivia estimated cost per well? And how are more precisely -- how do you plan to commercialize these volumes out of Bolivia, either through take-or-pay agreements or at what should we think of perhaps of a longer-term strategy there?

With respect to Bolivia, we've just entered 3 exploration contracts and we are currently negotiating the entrance of the fourth contract. We expect to commence operations in Bolivia next year, 2024. As I mentioned in the press release, we are committed to spend up to $27 million there. Initially, investment will be focused on a redevelopment project of an existing gas field. We expect to initiate sales and commercialization from that gas field in 2025. And the majority of that gas will be sent as exports to Brazil with a small percentage being used for local consumption.

And just one last one. Regarding contract renegotiation, we understand that you have some compromises coming due in the Caribbean area next year. So any thoughts on perhaps contract renegotiations. Seeing you won't be needing to redirect volumes to EPM, is it fair to assume that you will be seeking to keep the contracted profile that you have now or perhaps looking more to being exposed to the spot market.

We have a number of take-or-pay contracts, existing take-or-pay contracts that roll over into next year and some beyond next year, of course, which we will continue to maintain. Currently, our plan with respect to contracting in 2024 is to remain a little more flexible to take advantage of the spot market, given that current pricing into the Caribbean coast has been impacted by the El Nino effect where thermal generation has been reduced. And as a result, gas prices on the spot market are relatively high. So the strategy at this point in time will be to maintain our current commitments with respect to take-or-pay contracts to the coast and look to expose ourselves more to the spot market, certainly during the first half of next year.

The next question comes from Daniel Guardiola from BTG.

I have a couple of questions. I just wanted to begin with a question related to the termination of these contracts because you announced that you were basically canceling the contract with EPM and SETCO, but if I'm not mistaken, you have signed a second contract to ship gas to Medellin with a confidential party, that contract, the volumes were ranging between 20 million to 25 million cubic feet per day, can you comment on this? Are you also canceling that contract? And are you expecting to record in any penalty related to the cancellation of that contract? That would be my first question. So you can answer one by one, and then I can ask the second question.

I can answer that first question for all, if you want.

Sure.

Yes, so that contract had a condition precedent related to the construction of the pipeline as well, so it automatically falls away.

Okay, perfect. I'm just wondering because it sounds -- I mean, it seems -- we do have to be honest, I mean, that delay of 3 months and a more difficult environment, I would say, to operate, we have decided to transfer this contract. I'm just wondering if you can share with -- acknowledge maybe the potential disruptions in production that you experienced with [indiscernible] had to do with this? Or it's just that you are basically strategically deciding to allocate more money out of Colombia considering the current conditions.

Sorry, Dan, I didn't quite catch that. Could you summarize that question?

I just want to better grasp a reason why we decided to terminate the contract?

I think we were quite clear in the press release and on this conference call. I believe I iterated the 4 points behind that, yes, nothing for that...

Okay, can you share with us what is the average duration of the current contract that you have in Colombia? And what project expiring this year?

7 Years, average duration and approximately this year, for example, approximately 30 million cubic feet of take-or-pays expire on November 30 which is fairly typical for the remainder of the contracts.

And just a last one from my end. Can you share with us what is the potential size of savings in terms of capital spending related to the termination of these contracts.

Jason, if you can go ahead and provide that?

Yes. I mean historically, prior to the last 2 years at least, we've typically spent $80 million to $110 million on CapEx and historically have found a 200% reserve replacement ratio. Last year, I think capital was $155 million. This year, the high side was $163 million. Simply meaning that -- this year, we -- this year and last year, we've spent more than historical with the purpose of building out a reserve base and adding that extra $100 million of production that is no longer necessary. Having said that, we'll give more CapEx guidance in mid-December when we release our 2024 budget.

The next question comes from Chen Lin from Lin Asset Management.

First is how strong is the spot market right now in Colombia? And then what can the anticipation do you have for the next few months due to El Nino, and how much extra capacity do you have to sell to the spot market?

Spot prices now are varying between $6 and $8 per MMBtu. We expect that to essentially be maintained through to the end of March. The outlook for the El Nino season extends out to the end of March for the moment. There is some stress on electricity pricing, which is starting to attract some national attention. So there is -- there is some concern about high electricity prices as a result of some of these high natural gas prices. So I think there might be the potential for the regulator to step in and try and ease the burden on these high electricity prices. And the intention is to essentially take advantage of this period to divert all production outside of current take-or-pay towards that spot market.

Okay you believe you can sell all of the extra capacity to the spot market?

That's correct.

And also next question is basically, how we -- this week, for example, United States lifted sanction to Venezuela, so do you have any plan to have some company involved with -- they're rushing to Venezuela. There's some -- you are so close to Colombia. There's some plan or some ideas you want to get involved in the Venezuela area?

I think as I mentioned, we looked at most of the gas prone basins in onshore in South America, including Venezuela. One of the criteria that we used was contractual stability and a benign operating environment, which, unfortunately, Venezuela does not fit that bill at the moment. You might know that the waiver provided by OFAC the other day, it was for 6 months, basically, until early next year, at which point it will be reviewed. So there's still a fair bit of uncertainty with respect to contractual stability in Venezuela for us, which prevents us from looking at it very serious at the moment. But if that changes, that certainly could be an avenue to pursue.

My final question is you're going to renegotiate the contract. Can you share some light? Do you think there is a pressure to get a higher price or roughly stay where you are right now?

As I mentioned, I think on the previous question, we have approximately 30 million cubic feet a day of existing take-or-pays falling off on November 30 of this year, and it's likely that we will simply not contract that $30 million to new take-or-pay contracts, but push it out into the interruptible market certainly for the first half of next year. That's the strategy we're considering at the moment that has yet to be finalized.

Do you plan to sign new take-and-pay maybe after the El Nino spot price is over?

Yes, potentially, yes. I mean, our history, historically, we've been hedged fairly heavily through take-or-pay contracts up to 80% of our annual production, for example, this year is take-or-pay. So historically, we have tended towards higher take-or-pays. I think we'll ease off on that a little bit into the first half of next year and then make a decision whether or not to return to our historical practice.

Just a follow-up. Sorry, I saw the report. I think I forward to you there will be a starting severe gas shortage in Colombia starting next year. Is that the reason you are more on the spot than the take-and-pay long-term hedge contract?

I think the emphasis, as I mentioned, Chen, was really the high pricing of interruptibles, certainly through to March of next year, the anticipation for high interruptible pricing. So that's what's driving our strategic considerations.

Our next question comes from Josef Schachter from Schachter Energy Research.

The first one, just to get an idea of what's going on in the southern part of the country with the pipeline not going through to Medellin. Is there still a shortage in that part of the country. So even though while you're not going to be involved in providing gas to that area, -- is this still going to be a government national priority and that they're going to have to try to find a solution to get gas down to those southern markets?

Well, all of the majority of gas going into the interior markets comes out of the Piedemonte of the Llanos Basin. It's all Ecopetrol's gas from Cusiana, Cupiagua. Those are mature fields. There's not a lot of drilling activity there. And the anticipated shortfall in supply still stands starting in 2024, 2025. So I think that's -- that's just the dynamics of supply and demand to the interior in that, most of the gas to the interior comes from those Piedemonte fields, which are declining.

So the government is still going to have to try to find a solution there.

Yes. Somebody is going to have to try and find solution, or convert to a different form of energy.

Yes. Going to Bolivia. You've talked about recompleting a field there and reactivating wells. Are you going to be doing a major seismic program on the 3 and potentially 4 concessions that you're going to get -- and how long will that seismic take before [indiscernible] and evolved in a more active drilling program in '25 or whenever?

Okay. So 3 of the 4 contracts -- 3 of the 4 contracts are exploration contracts, so pure exploration. Those contracts have a variety of historical 2D and 3D seismic, although we'll likely shoot 3D seismic on a couple of those to high-grade some leads that we can drill. We have up to 5 years of exploration period on those 3 blocks. So it's likely in a year 2, year 3, we would shoot a bit of seismic. And then in year 3 and year 4, when we started drilling exploration wells there. The fourth contract, which we're waiting for approval is the field redevelopment. It has a 3D seismic survey on it already that was shot by the previous operator before they relinquished that contract. So there, we have a situation -- situation there where the field was producing primarily gas with some condensate. There was no pipeline to the field at the time. So essentially, the gas was being let off and the condensate was being collected. And since that field was shut in, a major gas pipeline has been built across the block. So the concept there is simply going, work over some of the existing wells and drill some new development wells and return on fuels gas production that we can do quickly given that we already have a modern 3D seismic. And Josef, just to follow up on your last question about the interior and supply to the interior. I forgot to mention that we are drilling the POLA-1 exploration well located in the Middle Magdalena Valley. That's a very high-impact prospect. We have significant prospective resource booked on that on that prospect, which you can refer to in our corporate presentation. If we're successful in that well, that well can be tied in directly to the TGI pipeline 10 kilometers to the east of the Pola-1 well, and that well -- and that field could supply gas directly into the interior, including Medellin, Bogota and Cali. So just to follow up on your last question.

The next question comes from Mario Epelbaum from FNY Capital.

Just want a little bit more clarity on the potential CapEx savings. It would be nice if you could provide it. It's not that I'm asking you to give me your budget rather let's have a hypothetical, if you did not do Pola and if you did not do Bolivia and you have the new budget now where you want to maintain the current profile of production between 160 and 200 in the current value where your -- what would be your estimated CapEx that you would need for that part?

Yes, I'll take that question. I mean, as I stated earlier, historically, that number prior to last year when we began additional spending in anticipation of the Medellin pipeline, historically, that number has been around $100 million. And our models would indicate that, that would still be the number to maintain production in the range that you suggested.

And that includes what kind of reserve replacement?

I think like last year, I'd say if I'm not mistaken, it was 163%. In prior years, it was often over 200% as you understand, reserve replacement ratio can be a bit lumpy depending on exploration success, but over the last 10 plus years that we've been in the gas exploration business, we've had an 85-ish percent chance of success on our exploration wells. And typically, that $100-ish million would get close to a 200% reserve replacement ratio historically.

So just as a follow-up to that, why would you need to replace reserves at 200%, if there is -- the production -- there's no higher exit production from there. So couldn't there be a scope for even further CapEx declines if you targeted 100% replacement ratio?

That's certainly a possibility, Mario yes.

Let me ask a different follow-up on that. Why would you want a 200% replacement ratio? Or would you want one in that condition, given that you don't have an exit -- further greater exit for the gas?

Yes. I mean all these things are board discussions, but -- and once again, we'll release our budget come historically mid-December of this year relating to next year. We may not necessarily need a 200% reserve replacement ratio. We do have some additional pipeline capacity that assuming the gas market in Colombia remains tight. If there is additional demand, we'll do additional drilling to try and fulfill that, albeit heading north.

And then the second question I have is, can you update us on your production recovery? What are you actually selling now? And how some of those -- that process is going?

Yes. Yesterday, gas sales were about 184 million cubic feet per day. As per our last press release, our operational update, which we issue at the beginning of the month each month, we are drilling and completing and tying in a number of development wells. So we expect production to recover nicely with respect to the current drilling program and the current results.

[Operator Instructions] Our next question comes from Andrew De Luca from T. Rowe Price.

My first question was actually just taken, what's the latest on the production issues? Has anything really changed over the last 10 days? And maybe just to add on, can you just tell us kind of exit rates, where you see the end of the year kind of trending? That would be my first question.

I think I've touched on where we are with respect to operations. With respect to guidance for 2023, we expect to achieve guidance between 160 million and 206 million cubic feet per day.

Okay. And just going back to the pipeline, can you just remind us how much capital is actually deployed on that project from inception?

Yes, I can take that call. So there is approximately $6 million spent in 2023. And -- and in the aggregate, we've spent $27 million including capitalized finance cost because we once had a bridge loan for that even though it was undrawn. There's obviously loan setup fees, standby fees, et cetera, and the $27 million would also include some wages capitalized towards that project.

And just the last one. On the presentation, you guys showed the amount of the revolver that was drawn until June 30. Can you just tell us where that revolver stands today?

Yes. I mean the September report will show the exact same number, which was $145 million. And as at today, it remains at that amount.

At this time, I'm told we have some webcast questions. I'll hand it back to management to answer those.

Thank you. The first question that we have is from [ Daria Emma ] from Bloomberg Intelligence. Could you share some light on the issues you experienced at the Jobo treatment facility and if these operational issues contributed to the cancellation of the whole Medellin project?

Yes, we've disclosed various -- disclosed publicly various press releases highlighting the operational issues we were suffering from and our plan to recover those. So I think that is very well understood and know these operational issues have no impact whatsoever on the Jobo Medellin pipeline cancellation, that was due -- that decision was based on the reasons I provided -- that we provided in the current press release as well as at the start of this call.

The next question is from [ Stephane Calin ]. Is it correct at this stage to assume that the potential of the Middle Magdalena exploration makes the use of the TGI gas line a better economic option that spending on the construction of the new gas line to Medellin?

Success at Pola-1 midyear, next year will certainly allow us to commercialize gas into the interior via the TGI pipeline. It all depends on what the price of that gas will be, of course, which we would have to negotiate in the event of success. But certainly, the option for us now to be interior is through success in our Middle Magdalena Valley drilling programs here next year and the year thereafter.

Next question is from Peter Hitchens from Edison Group. What is the main driver of Bolivian gas prices?

The main drivers there are increasing demand for gas in Brazil. The cost of that gas as some of that gas comes from offshore associated gas fields, which is quite expensive. And most importantly, parity with imported LNG pricing, Brazil imports quite a bit of LNG. And the forecast for gas consumption in Brazil is very robust going forward. So last year, import price for gas into Brazil was about USD 12 to USD 14 per MMBtu, which was the price being realized in Bolivian exports.

Next question is from Anne Milne from Bank of America. Could you please give us some additional information on the legal, social and security problems in Colombia?

Yes, Anthony, if you wish to respond to that.

No. For legal reasons, I wouldn't want to get into those details, details that were provided in the press release as far as we can go in terms of those detail.

Then we have a question from Matias Castagnino from BCP Securities. You mentioned you will use excess capital to reduce debt. Can you give more color on that?

I think I've answered that a couple of times on this call. We'll have more color in the -- with respect to 2024 debt reduction and CapEx levels, in mid-December.

It is safe to say, however, that debt reduction is one of our objectives.

100%.

Next question from Christopher True from Eight Capital. How does the narrative change for CNE? For example, what would be the messaging to shareholders moving forward?

I think a couple of main points. We still remain very committed to Colombia. We see very good potential with respect to our exploration programs going forward. We see a fairly good pricing environment with respect to supply and demand. There is some political risk in Colombia at the moment, like there are in most countries. However, it still remains our focus in the long term, both the Lower Mag Valley where we've been exploring very successfully historically. And now in the Middle Magdalena Valley, we're pursuing a very, very large multi-TCF prospective resource base that we can commercialize into the interior. So Colombia remains very much a focus, although we are diversifying geographically in Colombia now stepping out into the Middle Mag Valley where we hope to establish a new production base. And finally, with respect to Bolivia, I mentioned the criteria, we used to enter Bolivia. We see there the potential of having a material production base equal to that of Colombia. So again, another theme of geographical diversification into another jurisdiction, which has very good characteristics that we like quite a bit with respect to gas potential and commercialization. And we sort of see Bolivia, as I mentioned earlier, sort of a replay of our 2012 Colombian strategy where we entered a gas market with no competition and very obvious supply-demand type trajectories.

Next one is from Alasdair Alexander from Sanarus Investment Management. What are the plans when it comes to paying out debt? Well, I think we already answered that. But then he has a follow-up question, which is are the current dividends and share buyback plans to be kept?

I could take that. So I mean, the last time we did a share buyback was January of 2022, and I believe it was USD 13-ish million. We haven't done any since. As we've obviously been focused on growth. With respect to the dividends, -- as you know, the dividends remained constant since its inception in December of 2019, the Board meets quarterly and discusses the current circumstances of the company and its future outlook. And in the context, of that, the dividend is decided every quarter. The next discussion relating to that would be mid-December when the next dividend would be planned.

Next question is from Juan Tarquino from Grupo Cobra. What are Canacol's specific plans for the Esperanza block in the Valley -- Magdalena Valley Basin. Would it involve drilling new production wells in that area and we'll see that at what time frame?

Yes, we continue to be very active drilling on the Esperanza block, both development and exploration wells. So we anticipate continuing to do that. certainly into the near and midterm. So no change of plans with respect to drilling and commercializing gas out of Esperanza -- as a matter of fact, we're just finished the drilling of a well Nelson 15 into the Nelson field on Esperanza, and we see several other candidates to drill there early next year as well.

Next question is from [ Till Moes ] from Schroders. You mentioned the gas market tightness with the spot prices in Colombia between $6 to $8. And you also mentioned gas export prices to Brazil of between $10 to $15. Why despite the tightness in Colombia, our prices is still lower than in Brazil?

There's -- first of all, I would say that the market in Colombia is very carefully balanced, there is very little in the way of imported gas pricing into imported LNG into Colombia. So the market, I would say, is in a balance, which is trending up now in terms of pricing going into El Nino. But as you know, historically, Well Head gas pricing in the past 8 years has essentially varied between $4 and $5.50 per MMBtu. And that's been very, very stable. And that's simply a reflection of the market dynamics in Colombia. Brazil, of course, is an economy much larger than Colombia, of course, enormous consumption of gas for power generation in Brazil and a lot of imported LNG going into Brazil. So the market -- the gas price in Brazil is effectively set by LNG import parity. 2 very different types of economies, 2 very different types of consumption profiles and massive importation of gas into Brazil from Bolivia by pipeline and from LNG.

Till sends another question. How do you see the long-term picture for Colombia natural gas supply impacted by the recent exploration successes of Ecopetrol? For example, Ecopetrol published last night that the Glaucus-1 well has confirmed the presence of natural gas in the deepwaters of the southern Colombian Caribbean. The development of the gas reserve has the potential to make a substantial contribution to Colombia's energy security, the company said.

Yes. I mean there's no question that there is great potential, significant potential for natural gas in the ultra deepwater of the Caribbean off the coast of Colombia. That has been proved up by a number of wells, including the one announced by Ecopetrol and Shell yesterday. However, one has to keep in mind that those gas discoveries are basically the deepest water, free gas discoveries on the planet. They're in 2,200 meters of water, which will provide significant challenges with respect to development. And that, of course, will translate into price. So yes, those discoveries may be developed at some point in the next 5 to 10 years. However, there is a question with respect to landed gas pricing given the fact that developing those ultra-deepwater non-associated gas fields will undoubtedly be a commercial challenge.

And we have a question from Cyrus Crockett from Grandeur Peak. Did the results of drilling play into the decision to cancel the pipeline?

Anthony?

Do you mind repeating that question again?

Did the results of drilling play into the decision to cancel the pipeline?

Sorry. Sorry, I've already -- I answered that question, I think, before and then the answer is no.

Exactly.

And we have a question from Peter Hitchens from Edison Group. What are the likely export tariff costs in shipping gas to Brazil?

Transportation costs from Bolivia to Brazil are about $1 to $1.50 and the tariffs are another $1 or so. So about 250 -- $2.50 to $3 would be the sort of the average transportation and tariff and price.

Okay. Going back to audio questions. The next question comes from Rodney Thomas from Apollo.

Mike, someone else asked my question, and it related to the environmental and social and legal issues that led you to cancel the pipeline. And I think you've made your answer clear there, so I will not ask us again. Thank you, and thank you for joining the call.

[Operator Instructions] And our next question comes from Mark Agaiby from BlueBay Asset Management.

I just wanted to ask, if you start producing at the Pola-1 fields, what's the capacity of the -- or the remaining or available capacity of the TGI pipeline, so if you could kind of get close to what was the planned expansion into the interior from the Jobo Medellin pipeline? It would be useful to understand what additional capacity there is that is to utilize.

The spare capacity currently on the TGI pipeline is 260 million cubic feet per day.

This concludes our question-and-answer session. The conference has now concluded. Thank you for attending today's call.

Are there some additional written questions, no, Carolina?

I don't have any more, but please give us a second to check if there's any additional incoming questions. One second, please.

We have a question from [ Daria Emma ] from Bloomberg Intelligence.

Just a couple of additional ones. Can you please comment on the current sales volumes?

As I mentioned earlier, yesterday, sales were 183 million, 184 million cubic feet per day.

I must have missed that. Apologies. And one last one from me. You mentioned some debt reduction is a possibility. How much of debt reduction do you envision following the cancellation of the Medellin project?

I'm sorry, could you please repeat the question? I didn't quite catch it.

How much of debt reduction can we expect from the cancellation of the Medellin project?

Yes. We had contracted approximately 75 million cubic feet per day on the Jobo Medellin pipeline route. So that's the amount of future sales impacted down to Medellin, which, of course, we hope to make up partially in other projects.

There are no more questions in the queue. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.