Welcome to the Canacol Energy Business Update Conference Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. 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 Medellín Exit and Bolivia Entry Conference Call. This is Carolina Orozco, Vice President of Investor Relations. I am with Mr. Charles 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 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 financial figures on this call are denominated in U.S. dollars. We will begin the presentation with our President and CEO, Mr.
Charles 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. Charles 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 the 1st of 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 making the decision to invest in its natural gas exploration programs in the Middle Magdalena Basin of Colombia and now in Bolivia.
Following a careful review of all of the relevant factors, the corporation decided it prudent not to execute the whole Medellín pipeline project. Following the termination of the Medellín 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 Medellín will no longer be necessary. Two, plan longer-term capital spending in the Lower Magdalena Basin to target full use of existing transportation infrastructure. Three, drill the high-impact Polo-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 Bogotá and Medellín, via the existing TGI gas pipeline located 10 km to the east of the Polo location.
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 five 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 four years working with YPFB, the state oil and gas company, to locate, identify, and negotiate four E&P contracts that fit those criteria.
We've now executed three contracts and are seeking government approval for one additional contract, which has a significant gas field redevelopment project, where we expect to initiate production and 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 two 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 finalize 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. To ask a question, you may press star, then one on your touch-tone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. At this time, we'll pause momentarily to assemble our roster. Our first question comes from Oriana Covault from Balanz. Please go ahead.
Hi, good morning. Thanks, Charles and all the team for setting up the call. Just I had three 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 force majeure, 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. As the contract was not in execution phase, it was still awaiting the environmental license as a condition precedent. At this time our exit does not involve any penalties.
Okay. Just moving on to perhaps more of the estimated CapEx savings that are associated with the decision to terminate EPM contract and just linking it with the development plans in Bolivia. Perhaps if you could add more color in terms of yearly investments, how would be the strategy in Bolivia, estimated costs per well, and more precisely, how do you plan to commercialize these volumes out of Bolivia? Either through take-or-pay agreements or at spot. What should we think of, perhaps of a longer-term strategy there?
With respect to Bolivia, you know, we've just entered three exploration contracts, and we are currently negotiating the entrance of a fourth contract. We expect to commence operations in Bolivia next year, 2024. As I mentioned in the press release, we're 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.
Perfect. Thank you. Just one last one. Regarding contracts renegotiation, we understand that you have some compromises coming due in the Caribbean area next year. Any thoughts on perhaps contracts or negotiations, 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? Thank you.
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 markets, given that current pricing into the Caribbean coast has been impacted by the El Niño effect, where thermal generation has been reduced. As a result, gas prices on the spot market are relatively high.
The strategy at this point in time will be to maintain our current commitments with respect to our 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.
Perfect. That will be all from my side. Thank you.
The next question comes from Daniel Guardiola from BTG. Please go ahead.
Good morning Charle , Jason, and Carolina. I have a couple of questions. I just wanted to begin with a question related to the termination of this contract, because you announced that you were basically canceling the contract with EPM and SETCO. If I'm not mistaken, you have signed a second contract to ship gas to Medellín with a confidential party, and that contract, the volumes were ranging between 20 million-25 million cubic per day. Can you comment on this? Are you also canceling that contract? Are you expecting to incur in any penalty related to the cancellation of that contract? That would be my first question. If you want, we can answer one by one, and then I can ask you the second question.
I can answer that first question, Charle, if you want.
Sure.
Yeah. That contract had a condition precedent related to the construction of the pipeline as well, so it automatically falls away.
Okay. No penalties. Okay, perfect. I'm just wondering, yeah, because it sounds, I mean, it seems weird, to be honest, I mean, that because of a delay of 3 months and a more difficult environment, I would say, to operate, you have decided to cancel this contract. I'm just wondering if you can share with me if, I don't know, if maybe the potential disruptions in production that you experienced since August 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?
I'm sorry, Daniel, I didn't quite catch that. Could you summarize that question?
No, no, no, no, I just want to better grasp the reasons why you decided to terminate the contract.
Well, I think we were quite clear in the press release and on this conference call. I believe I iterated the four points behind that. Yes, I have nothing further to add to that.
Okay. Okay, okay. Okay. Can you share with us what is the average duration of the current contract that you have in Colombia?
Seven years.
Expiring this year?
Seven years, average duration, and approximately this year, for example, approximately 30 million cubic feet of take-or-pays expire on November 30th, which is fairly typical for the remainder of the contracts.
Okay, 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 this contract?
Jason, if you could go ahead and provide that.
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Okay. Thank you, guys.
The next question comes from Chen Lin from Lin Asset Management. Please go ahead.
Hi, thank you for taking my questions. First is, how strong is the spot market right now in Colombia? What kind of anticipation do you have for the next few months due to El Niño? 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 Niño season extends out to the end of March for the moment. You know, there is some stress on electricity pricing, which is starting to attract some national attention. There is some concern about high electricity prices as a result of some of these high natural gas prices. We think there might be the potential for the regulator to step in and try and ease the burden on these high electricity prices.
The intention is to essentially, you know, take advantage of this period to divert all production outside of current take-or-pays towards that spot market.
Okay, you believe you can sell all the extra capacity to the-
Yeah.
Spot market?
That's correct.
Okay, great. Thanks. Also, next question is, you know, this week, for example, United States lifted sanction to Venezuela. Do you have any plan? I have some company, you know, I involve with. They are, you know, rushing to Venezuela. You are so close to Colombia. Is there some plan or some ideas you want to get involved in the Venezuela area?
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But if that changes, that certainly could be an avenue to pursue.
Great, thank you. My final question is, you're gonna renegotiate the take-or-pay contract. Can you shed some light on? Do you think that there's a pressure to get a higher price or roughly stay where you are right now?
Well, as I mentioned, I think on the previous question, you know, we have approximately 30 million cubic feet a day of existing take-or-pays falling off on November 30th of this year. It's likely that we will simply not contract at 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.
Okay. Do you plan to sign new take-or-pay, maybe after the El Niño spot price, high price is over?
Yeah, potentially, yes. I mean, our history, you know, 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. 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.
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I think the emphasis, as I mentioned, Chen, was really, you know, the high pricing of interruptibles, certainly through to March of next year, the anticipation for high interruptible pricing. That's what's driving our strategic considerations.
Okay, great. Thank you.
Our next question comes from Joseph Schachter from Schachter Energy Research. Please go ahead.
volved in providing gas to that area, is this still gonna be a government national priority, and that they're gonna have to try to find a solution to get gas down to those southern markets?":* Check spelling: E-v-e-n t-h-o-u-g-h w-h-i-l-e y-o-u-'-r-e n-o-t g-o-n-n-a b-e i-n-v-o-l-v-e-d i-n p-r-o-v-i-d-i-n-g g-a-s t-o t-h-a-t a-r-e-a, i-s t-h-i-s s-t-i-l-l g-o-n-n-a b-e a g-o-v-e-r-n-m-e-n-t n-a-t-i-o-n-a-l p-r-i-o-r-i-t-y, a-n-d t-h-a-t t-h-e-y-'-r-e g-o-n-n-a h-a-v-e t-o t-r-y t-o f-i-n-d a s-o-l-u-t-i-o-n t-o g-
Well, you know, 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. You know, the anticipated shortfall in supply, you know, still stands starting in 2024-2025. You know, 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.
The government is still gonna have to try to find a solution then?
Yeah, somebody's gonna have to try and find a solution to that.
Okay.
Convert to a different form of energy.
Yeah. Going to Bolivia. You've talked about recompleting a field there and reactivating wells. Are you gonna be doing a major seismic program on the three and potentially four concessions that you're gonna get? How long will that seismic take before you be involved in a more active drilling program in 2025 or whenever?
Three of the four contracts are exploration contracts, so pure exploration. Those contracts have a variety of historical 2D and 3D seismic, although, you know, we'll likely shoot 3D seismic on a couple of those to high-grade some leads so we can drill. You know, we have up to five years of exploration period on those three blocks, so it's likely, you know, in year two, year three, we would shoot a bit of seismic, and then in year three and year four, we would start 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.
There we have a situation 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. Since that field was shut in, a major gas pipeline has been built across the block. The concept there is simply to go in, work over some of the existing wells and drill some new development wells and return the field's gas production. That we can do quickly, given that we already have a modern 3D seismic. Joseph, just to follow up on your last question about the interior and supply to the interior.
I forgot to mention that, you know, we are drilling the Polo-1 exploration well located in the Middle Magdalena Valley. It's a very high-impact prospect. We have significant prospective resource booked 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 km to the east of the Polo-1 well. That well and that field could supply gas directly into the interior, including Medellín, Bogotá, and Cali. Just to follow up on your last question.
Okay, super. Thanks for the clarity on that, and thanks for taking my questions.
Thanks, Joseph.
The next question comes from Mario Epelbaum from FNY Capital. Please go ahead.
Yeah. Hi, good morning. Thanks for taking the question. Just I 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 Polo 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, what would be your estimated CapEx that you would need for that part?
Yeah, 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 Medellín pipeline, historically, that number has been around $100 million. You know, our models would indicate that, you know, that would still be the number to maintain production in the range that you suggested.
That includes what kind of reserve replacement?
I think, like last year, I'd say, if I'm not mistaken, it was a 163%. You know, in prior years, it was often over 200%. You know, as you understand, you know, reserve replacement ratio can be a bit lumpy, depending on exploration success. You know, over the last 10+ years that we've been in the gas exploration business, we've had, you know, an 85%-ish chance of success on our exploration wells. Typically, that $100-ish million would, you know, get close to a 200% reserve replacement ratio historically.
Just as a follow-up to that, why would you need to replace reserves at 200% if there is the production, there's no exit, higher exit production from there? Couldn't there be a scope for even further CapEx declines if you targeted a 100% replacement ratio?
Yep.
Which one-
That's certainly a possibility, Mario. Yep.
Let me ask then 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 for a greater exit for that gas?
Yeah, I mean, you know, all these things are board discussions. Once again, we'll release our budget come, you know, 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.
Okay, thank you. The second question I have is: Can you update us on your production recovery? What are you actually selling now, and how that process is going?
Yeah. 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. We expect the production to recover nicely with respect to the current drilling program and the current results.
Thank you.
Again, if you have a question, please press star then one. Our next question comes from Andrew DeLuca from T. Rowe Price. Please go ahead.
Hi, thanks for the time. My first question was actually just taken. What's the latest on the production issues? Has anything really changed over the last 10 days? 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'll 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 cubic feet a day and 260 million cubic feet a day.
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Yeah, I can take that call. There's approximately $6 million spent in 2023. In the aggregate, we've spent $27 million, including capitalized finance costs, because we once had a bridge loan for that, even though it was undrawn. There's obviously loan setup fees, standby fees, et cetera. The $27 million would also include, you know, some wages capitalized towards that project.
Thanks, Jason. Just the last one, on the presentation, you guys showed the amount of the revolver that was drawn until June 30th. Can you just tell us where that revolver stands today?
Yeah, I mean, the September report will show the exact same number, which was 145 million, and as of today, it remains at that amount.
Great. Thanks very much.
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 Dalia Lima, 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 Medellín project?
Yes. We've, you know, we've disclosed various, disclosed publicly various press releases highlighting the operational issues we were suffering from and our plan to recover those. I think that's very well understood. No, these operational issues have no impact whatsoever on the Jobo-Medellín pipeline cancellation. 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.
Thanks, Charles. The next question is from Stefan Chaling. 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 than spending on the construction of the new gas line to Medellín?
You know, success at Polo-1 mid-year next year will certainly allow us to commercialize gas into the interior via the TGI pipeline. It all, you know, 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, you know, the option for us now to the 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. Last year, import price for gas into Brazil was about $12-$14 per MMBtu, which was the price being realized in Bolivian exports.
Thank you. 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.
Yeah, no, for legal reasons, I wouldn't wanna get into those details. The details that were provided in the press releases, as far as we can go in terms of those details.
Okay. 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?
You know, I think I've answered that a couple times on this call. We'll have more color in the, you know, 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.
Hundred perce
Next question from Christopher Tu, from Eight Capital. How does the narrative change for CNE? For example, what will be the messaging to shareholders moving forward?
I think, you know, a couple main points. You know, we still remain very committed to Colombia. We see a very good potential with respect to our exploration programs going forward. We see a fairly good pricing environment with respect to supply and demand. You know, 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, where we're pursuing a very, very large multi TCF prospective resource base that we can commercialize into the interior. 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.
Finally, with respect to Bolivia, you know, 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. 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. We sort of see Bolivia, as I mentioned earlier, you know, it's 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.
Thank you. Next one is from Alistair Alexander from Genarus Investment Management. What are the plans when it comes to paying out debt? Well, I think you 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. I mean, the last time we did a share buyback was January of 2022, and I believe it was $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, you know, every quarter. You know, the next discussion relating to that would be mid-December, when the next dividend would be planned.
Next question is from Juan Tarquino from Corficolombiana . What are Canacol's specific plans for the Esperanza Block in the valley in Lower Magdalena Valley Basin? Would it involve drilling new production wells in that area, and within that, what timeframe?
Yeah, we continue to be very active drilling on the Esperanza Block, both development and exploration wells. We anticipate continuing to do that, certainly into the near and midterm. 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.
Thank you. Next question is from Till Moewes from Schroders. You mentioned a gas market tightness with the spot prices in Colombia between $6-$8, and you also mentioned gas export prices to Brazil of between $10-$15. Why, despite the tightness in Colombia, are prices still lower than in Brazil?
You know, there's first of all, you know, I would say that the market in Colombia is very carefully balanced. You know, there's very little in the way of imported gas pricing, imported LNG into Colombia. The market, I would say, is in a balance, which is trending up now in terms of pricing going into El Niño. As you know, you know, historically, wellhead gas pricing in the past 8 years has essentially varied between $4 and $5.50 per MMBTU. That, you know, that's been very, very stable, and that's simply a reflection of the market dynamics in Colombia. Brazil, of course, is an economy, you know, much larger than Colombia, of course.
Enormous consumption of gas for power generation in Brazil and a lot of imported LNG going into Brazil. The market, you know, the gas price in Brazil is effectively set by LNG import parity. You know, two very different types of economies, two very different types of consumption profiles, and a 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 Colombian 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 deep waters 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.
Yeah, 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 m of water, which will provide significant challenges with respect to development. That, of course, will translate into price. Yes, those discoveries may be developed at some point in the next 5-10 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.
Thank you, Charles. We have a question from Cyrus Crockett from Grandeur Peak. Did the results of drilling play into the decision to cancel the pipeline?
Uh, Anthony?
Sorry, would you mind repeating that question again?
Yes. Did the results of drilling play into the decision to cancel the pipeline?
Sorry, sorry. I've already answered. I answered that question, I think, before, and the answer is no.
Exactly.
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, $1.50, and the tariffs are another $1 or so. About $2.50, $2.50-$3 would be the sort of the average transportation and tariff and price.
Okay, coming back to audio questions. The next question comes from Rodney Thomas from Apollo. Please go ahead.
Thanks, 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 it again. Thank you, and thank you for doing the call.
As a quick reminder, if you have a question, please press star, then one. Our next question comes from Mark Agabi from BlueB ay Asset Management. Please go ahead.
Hi, team. Thanks for doing the call. I just wanted to ask if you start producing at the Polo-1 fields, what's the capacity of the or the remaining or available capacity of the TGI pipeline? See if you could kind of get close to what was the planned expansion into the interior from the Jobo-Medellín pipeline. It'd be useful to understand what additional capacity there is there for you to utilize. Thanks.
Okay, Mark, thank you. The spare capacity currently on the TGI pipeline is 260 million cubic feet per day.
Thank you.
Great. This concludes our question and answer session. The conference has now concluded. Thank you for attending today's session.
I think there were 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.
Please do. Please do.
As a reminder, if you have a question on the phone, it is star one to ask. We have a question from Dalia Lima from Bloomberg Intelligence. Please go ahead.
Hi. Thank you for taking my questions earlier. Just a couple additional ones. Can you please comment on the current sales volumes?
As I mentioned earlier, yesterday, sales were 183, 184 million cubic feet per day.
Oh, thank you. I must have missed that. Apologies. 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 Medellín project?
check the "US English" for "sorry". * Wait, I already did that
How much of debt reduction can we expect from the cancellation of the Medellín project?
Yeah, we had contracted approximately 75 million cubic feet per day on the whole Medellín pipeline route. That's the amount of future sales impacted down to Medellín, which, of course, we hope to make up partially in other projects.
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