Hello, and welcome to the Canacol Energy Third Quarter 2023 Earnings Financial Results Conference Call. All participants will be in the 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. To ask a question, you may press star, then one on your touchtone phone. To withdraw your question, please press star, then two. Please note, today's 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 Third Quarter 2023 Financial Results Conference Call. This is Carolina Orozco, Vice President of Investor Relations. I am with Mr. Charle Gamba, President and Chief Executive Officer, and Mr. Jason Bednar, Chief Financial Officer. Before we begin, it's 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 financial figures on this call are denominated in US dollars. We will begin the presentation with our President and CEO, Mr. Charle Gamba, who will summarize highlights from our third quarter results. Mr.
Jason Bednar, our CFO, will then discuss financial highlights. Mr. Gamba will close with a discussion of the corporation's outlook for the remainder of 2023 and into 2024. At the end, we will have a Q&A session. I will now turn over the call to Mr. Charle Gamba, President and CEO of Canacol Energy.
Thanks, Carolina, and welcome everyone to Canacol's Third Quarter 2023 Conference Call. In the third quarter, we realized natural gas sales of 178 million standard cubic ft per day, which was slightly below the midpoint of our annual guidance of 160-206 million standard cubic ft per day. After short-term production capacity restrictions that began in the second week of August 2023, our sales have begun recovering from 161 million standard cubic ft per day in September to 170 million standard cubic ft per day in October.
Despite slightly lower production and sales volumes compared to prior quarters, we reported strong netbacks of $4.14 per Mcf, maintained robust operating margins of 77%, reported record EBITDA of $62 million, and record funds flow from operations of $49 million. We've executed a number of successful remedial measures and are finalizing others to bring production back to normal levels by the end of November. We don't expect this situation to have a material impact on overall operations and results for the year. We also don't currently anticipate material reserve revisions in relation to the production capacity constraints we're working to resolve. We call that our reserves in our core production area are typically held in fields with multiple stacked reservoirs, where we are typically only producing from one reservoir at a time in any given well.
One consequence of that is we have a lot of developed but non-producing reserves, which we will typically bring into production to meet demand in a staged manner. In recent months, we've increasingly focused on development drilling to ensure that we have sufficient productive capacity to meet demand and potentially take advantage of strong pricing in the spot market that we've already seen and anticipate to continue through the first quarter of 2024 related to the El Niño phenomenon. During the quarter, we also announced the cancellation of the Jobo to Medellín project and the EPM contract and our growth strategy in Colombia and Bolivia. I'll now turn the presentation over to Jason Bednar, our CFO, who will discuss the third quarter financials in more detail.
Thanks, Charles. The third quarter was another very good quarter with strong netbacks from our operations. Our gas operating netback was $4.14 per Mcf in the three months ended September 30, 2023, which is 11% higher than the same period in 2022, and substantially above our guidance for $3.81-$3.84 on average for 2023. These high netbacks are mainly attributable to relatively high realized prices. We remain encouraged by the persistence of robust pricing for gas in Colombia. Operating expenses were $0.36 per Mcf in Q3, only slightly higher than the prior quarter, and for the first nine months, averaged $0.32 in line with OpEx in the prior year. In percentage terms, our gas royalties were also roughly in line with prior quarters at 16.7% of revenue.
For the third quarter, we reported $77 million net of royalties in transportation, which represents a 9% increase from Q3 of 2022. The increase was driven by a 13% increase in realized prices, slightly offset by a 3% decrease in sales volumes. EBITDAX of $62 million represents an 11% increase from the same period in 2022 and also represents a new record EBITDAX generation. I will again highlight the long-term trend of steadily growing EBITDAX over the last 8+ years. Adjusted funds from operations was $49 million, which represents a 26% increase from the same period in 2022, and also represents a new record for the company. I also want to highlight the long-term trend of steadily growing funds flow over the last 8+ years.
The exhibit also shows the increase in funds flow in the third quarter relative to the first half of the year, with substantial increase in the third quarter being due to higher netbacks as well as significantly lower cash taxes. The current tax expense averaged $25 million for each of the first and second quarters and was only $10 million in Q3, despite record EBITDA, as a result of our restructuring plan now being largely completed. As detailed on previous calls, I anticipate that we will continue seeing significantly lower cash taxes now that the major steps of the corporate restructuring that began last year are in place.
Recall that we had a one-off current tax expense of $65 million paid in the second quarter of the year, combined with a recognition of a new $202 million deferred tax asset, as noted in our financials for the year ending 2022. Finally, we also reported a net loss of $500,000 for the third quarter of 2023. The loss is entirely attributable to a one-time impairment of $32 million, resulting from the termination of the Medellín pipeline project. Since it's difficult to compare unadjusted earnings for individual quarters, I've included the presentation materials, a comparison of year-to-date net income of $56.3 million for 2023, which represents an increase of over 300% from the comparable period in 2022.
Before I hand the call back to Charle, I'll also make some comments on capital spending to date and the outlook for the remainder of the year, as well as debt levels that are very similar to what I said on the second quarter results call in August. Our cash capital expenditures of $143 million for the first nine months represents approximately 88% of our original high case CapEx budget guidance of $163 million for 2023. The $143 million nine-month CapEx does include $19 million of warehouse inventory as at September thirtieth. This is required under IFRS, including a well head and casing materials for Pola and other upcoming wells.
As expected, and as a result of that spend on inventory, that was mainly completed during the first half of the year, we were able to report slightly less CapEx of $44 million in the third quarter, compared to $50 million per quarter in the first two quarters of the year, despite higher field level activities in the third quarter. We do now anticipate that our total CapEx for 2023 will be in the range of $190 million-$200 million, which, as I just mentioned, includes significant inventory and pre-spending for planned activities in 2024. The main reason for the increased CapEx spending versus the original budget are, first of all, acceleration of spending on development drilling in order to increase short-term production capacity to take advantage of attractive market dynamics and offset by the short-term production issues we've experienced.
Therefore, we are now anticipating drilling up to 14 wells during 2023. Some of the original exploration wells were budgeted to drill and test only, so developing these wells required additional tie-in costs. Lastly, pre-spending on materials in preparation for 2024 activities. Some of this was opportunistic acquisition of general oil field materials at attractive pricing, including the acquisition of specialized materials for Pola well, which was particularly material. With respect to leverage on our net debt-to-EBITDA leverage ratio was 2.6 times on a trailing twelve-month basis at September 30, down slightly from 2.7 times at June 30, due to higher EBITDA levels.
How this ratio evolves moving forward will depend on a host of factors, including, first of all, gas demand as a key driver of revenue and hence also EBITDA, and it will depend on CapEx and net debt levels, noting that although we won't be providing precise guidance until next month, we do anticipate lower spending in the Lower Magdalena Basin in 2024. With our one-off cash tax payment now behind us, and despite an anticipated higher CapEx spend than what we originally budgeted, my expectation continues to be that our leverage ratio will decrease to approximately 2.5 times at year-end. To refresh everyone's memory, our bond leverage ratio covenant is at 3.25 times, and the revolver is at 3.5 times. As such, we're well inside those covenant restrictions.
Finally, at September 30th, we had $44 million in cash and $55 million undrawn on our revolving credit facility. That concludes my comments. I'll now hand it back to Charle.
Thanks, Jason. Our results for the third quarter once again demonstrated high and stable operating margins with record results in terms of EBITDA and funds flows from operations. For the remainder of 2023, we remain focused on raising production capacity for the increased demand associated with the El Niño phenomenon for the first quarter of 2024. Looking forward to 2024, we will focus on three main growth avenues, which are to grow gas sales into the Caribbean market via existing transportation infrastructure, explore the 6.6 TCF of risk gas resource potential we've identified on our blocks in the Middle Magdalena Basin, and lastly, commence gas production operations in Bolivia. With respect to our Lower Mag assets, we expect to reduce our exploration spending, given that we no longer need to supply gas to the interior.
We do, however, see the potential for growing gas sales to the Caribbean via the existing transportation infrastructure, which currently has a capacity of about 270 million standard cubic ft per day, as supply from Ecopetrol's legacy fields continues to decline. With respect to our Middle Mag assets, we are planning to drill the Pola 1 Exploration well to test the potential of a Cretaceous deep gas play. The Pola prospect has estimated mean prospective resource of 1.1 TCF on an unrisked basis and 470 BCF on a risked basis. Pola 1 is one of 17 lookalike prospects that we've identified on our acreage in the Middle Mag Valley that contain approximately 6.6 TCF on a risked mean basis.
Pola 1 is located within 10 kilometers of the TGI-operated gas pipeline that transports gas from mature gas fields in northern Colombia to the interior of Colombia, and currently has approximately 260 million standard cubic ft per day of spare capacity, meaning that any discovery made at Pola 1 can be quickly commercialized and sold into the interior market of Colombia. Finally, with respect to our strategic entrance to Bolivia, we see the potential there to create a material new gas production base for the company, equal, we hope, to that of Colombia in the midterm. Due to years of underinvestment, Bolivia's gas reserves and production have been in decline, with current gas production of approximately 1.5 billion cubic ft per day, 70% of which is exported to Brazil and Argentina.
These gas exports are a key part of Bolivia's economy, accounting for approximately a third of the total values of exports from the country. In recent years, this has caused gas prices in Bolivia to become driven by gas pricing in Brazil, where gas demand is growing while domestic production appears stagnant, making Brazil dependent on imported LNG and Bolivian gas imports to meet demand. As a result, gas prices in Bolivia are in the range of $10-$15 per Mcf at the wellhead. Of note, the Bolivian market is connected to Brazil by the GASBOL pipeline, which has a capacity of 1.1 billion cubic ft per day, approximately 35% of which is currently underutilized.
Similar to our decision to enter Colombian, 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, mainly Brazil. After four years of working with the state oil company, YPFB, we're now executed three contracts and are seeking government approval for one additional contract, which has a significant gas field redevelopment project. Potential gas production from these blocks should be relatively easy to commercialize, as they're all located along the main gas pipeline routes, including export to Brazil.
We anticipate commencing investment and operations in 2024, with first gas production expected in 2025, with relatively small near-term capital requirements of just $27 million over the next five years. Note that as we typically do every year, I anticipate we will publish our 2024 guidance in December of this year, and until we have finalized our plans and received board approval, we won't be in a position to provide precise guidance for next year. We are now ready to take questions.
Yes, thank you. To ask a question, you may press star then one on your touchtone phone. If you are 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 will pause momentarily to assemble the roster. The first question comes from Oriana Covault from Balanz.
Hi, thanks for taking my question. This is Oriana Covault with Balanz. I have three questions. The first one is regarding the average sales that you're currently seeing. If I understood correctly, current sales are around 170 million cubic ft per day and a tad below the 180 that you shared back with, when you did the business update. So just to understand, how are you seeing sales? If you could comment anything of this, and if you're meeting your contract, your, Yeah, your contracts at the moment.
Yes. So average sales are averaging currently just above 100, just above 180. The last two weeks of October were quite wet here in Colombia. Quite a bit of rain, which means a higher level of hydroelectric electrical generation. So gas sales were lower during the second half of October. But things have dried out over the past week or so here in Colombia, and gas sales have returned to those levels.
Got it. And just following up on your contracted capacity, and if you are currently meeting all of these contracts, and when do you expect to be selling back at spot market?
Yeah, we expect to be back to normal operating conditions through to the end of November, where we'll see gas sales return to the spot market.
Understood. And just basically seeing these changes in your average sales, it seems according to the historical gas data, that your market share in the Caribbean has dropped to about 35% in the last quarter. So just to check with you, what would be a comfortable level for you, and what are you targeting, seeing that you were, before this last quarter, at about 50% of market share in the Caribbean?
Yeah, we're targeting average gas sales between 160-206 million cubic ft per day.
Understood. Just one last one. In this type, you had mentioned in the last earnings call that you would be participating in another Tesorito Light contract. Just to understand if there's any update on that UPME bidding process, any color that you can share in this regard?
Yes, the solicitation for additional power generation organized by the UPME has been delayed until February of next year. So we continue to analyze various projects. Our Tesorito 1 project with Celsia has performed very, very well. We're very pleased with the results of the project that we executed with Celsia, and we're looking with interest in potentially participating in that bid round in February. But at the moment, that round has been delayed on several occasions, with the latest delay now setting the bid date sometime in February of next year.
Got it. Thank you. That will be all from my side.
The next question comes from Mark Higby with BlueBay.
Hi, thanks for the call. Just wanted to ask, and apologies if you did mention because I lost connection for a bit, but could you provide a bit more information on the operational issues that we've seen in the last couple of months? And kind of you mentioned that you expect production to get back to normal levels by end of November, but is that expected to come from new production wells, or is it partially expected to be from some of the same production wells that were having issues? Is there any way that you could give detail on how many wells were having issues and in what fields, et cetera?
If not, kind of what's the rationale for not sharing the additional details would be useful for us to understand as well. Thanks very much.
Yeah, we saw two, two production issues. One was associated with the gas treatment facilities, some technical issues with some of the gas processing equipment. And the second, some water breakthrough from two of our minor fields, our minor producing or smaller producing fields, some early water breakthrough. To address those issues, we executed a series of technical repairs to the facilities, which are now functioning properly. And, we've worked over some of those minor fields wells, in addition to drilling some additional development wells into our main producing fields that we've commented on publicly in our press releases.
Oh, sorry, that's very helpful. Thank you. But I meant more kind of so the, Maybe to ask my question another way, the wells that were having the issues are now fully back to kind of producing the same volumes that they were before, post the repairs, or are you to expect them to be at that level by the end of November? Or kind of have you only managed to recover, you know, a partial amount of the volumes that they were producing before the operational issues started, aside from the Jobo gas treatment facility?
Yeah, those minor fields, those wells have been reworked. We reentered those wells and worked them over to switch zones to shallower producing zones. They're producing at a lower rate than they were originally from different zones. And as I mentioned, we have drilled some additional development wells into some of our main producing fields to recover those production losses.
Okay. Thank you.
Thank you. The next question comes from Kevan Salisbury with Ninety One Asset Management.
Hi, thank you for taking my call and for the results. Just a quick question, kind of on the. I don't know if you can comment, but on the Fitch outlook downgrade. You know, talking to them, they've premised it on, you know, effectively the take or pay agreements dropping to around 50% by 2026. And their claim was that, you know, they made this statement and that you kind of didn't push back on them when shown the report. I mean, can you comment on your expectations of your take or pay ratio going forward and whether you intend to push back on this assertion going forward? Thank you.
Yeah, sure. I mean, Fitch was one level higher than both Moody's and S&P, so, you know, the one-level downgrade put them in line with the other two. Of course, the other two have not changed their opinion nor their outlook. You know, with respect to Fitch's assumption that our take or pays will only be 50% by 2026, you know, we've typically contracted 80% of our expected volumes in take or pays. You know, heading into El Niño, or now that we're in El Niño and heading into the new December first contract year, we may not do all 80%. You know, there's still another 20 days left in this month to sign other contracts. But, you know, I don't expect it will be deviating significantly from that historical plan post El Niño.
The prices are relatively high and climbing in terms of long-term contracts, so, you know, we'll be opportunistic in dealing with those.
Thank you. Very clear.
Thank you. The next question comes from Davina Lima with Bloomberg Intelligence.
Hi. Hi, good morning. Thank you for taking my questions, and congratulations on a good quarter. My understanding is that you renegotiate your prices in December. Are you looking to secure higher prices for the fixed contract volumes in December? And if so, can you give us any color on potential premium?
We do have a certain volume of, Well, typically, with respect to our contracted volumes, take-or-pay volumes, a percentage of them roll off on November thirtieth, and we either renegotiate and extend those volumes with the clients, or we look for other clients, or we leave those volumes unoccupied to sell on the spot market. So, this November thirtieth, approximately 40 million cubic ft per day of take-or-pays will roll off. And we're currently looking at it, analyzing our strategy with respect to what percentage of those additional volumes we'd like to roll over at higher prices versus not roll over and leave ourselves exposed to spot market conditions. So at this point in time, I think it's fairly safe to say that we're probably going to
Look for more exposure to spot market pricing, as we anticipate demand and pricing to be quite high through the first quarter and into the second quarter of next year, due to the El Niño effect.
Thank you. That's helpful. Just a couple more questions on my end. So you've said that you are on the production side, you said that you are looking to normalize the production by the end of November. Do you mean that will be all the way up to 206 Mcf a day?
Yeah, we expect to achieve normal conditions, which are, you know, current for our guidance of 160-260 million cubic ft per day.
Thank you. That's helpful. And just one last thing on my end. On the Bolivia side, could you speak perhaps a little bit about the competition in the area? For example, such as the construction of the new pipeline in Argentina or any other, would that offer supply competition to neighboring countries? If you can comment on that.
Yeah. You know, with respect to upstream competition, there's very little, only really the majors and YPFB are involved in upstream activities in Bolivia. There's no real small or medium-sized companies active there, aside from Oxy, Occidental Petroleum, which has historic operation there. You know, with respect to where the gas goes in Bolivia, you know, 70% of gas is exported both to northern Argentina and to Brazil. With respect to Argentinian gas production, you know, obviously set to increase due to shale. And there have been plans for a very long time to reverse the export pipeline from Bolivia to northern Argentina, to reverse that pipeline so that gas could flow into Bolivia and then out into Brazil.
But regardless, we see a very strong outlook for demand in Brazil in particular. Obviously, Bolivia will be very interested in commercializing its own gas reserves ahead of imported gas flowing out of Argentina, for example. So based on, you know, based on the relatively strong outlook for demand, particularly in Brazil, the capacity in that export line to Brazil, and Bolivian government's preference to commercialize its own gas reserves ahead of imported gas reserves, you know, we feel quite comfortable that Bolivia, you know, is a very good jurisdiction for us to invest in natural gas operations.
Thank you. Thank you. That's very helpful.
Thank you. The next question comes from Alvin Lim with Morgan Stanley.
Hi, how are you? Just have a question on CapEx. So Pola, one type of exploration activity, I understand it is a deep gas play in Lower Mag. What would be the CapEx difference of the exploration for Pola versus Mid-Mag, exploration activities? And I guess with that, I appreciate that the formal guidance will be released, next month, and I'm not looking for a precise guidance here, but just to understand directionally, considering the change in the mix of CapEx spending for next year, should we be expecting something closer to the historical level of CapEx before 2022? Or would you expect, I guess, given the new exploration opportunities in Lower Mag, the overall CapEx should not deviate too much from the recent figures, that we saw in 2022 and 2023. Thank you.
Jason, these seem to be CapEx questions.
Yeah, sure. I mean, if I understand the question correctly, the Pola well, being the first well into that particular field, obviously an exploration well, is going to be approximately $30 million to drill. Some of our, you know, our Lower Mag wells are anywhere in the range from $4.5 million-$6 million, depending on if we're drilling off an existing pad. Obviously, follow-up Pola wells, you know, if there's no mob, demo above the rig, and if they're from an existing pad, would be less than the $30 million that the first well is expected to be.
I think there was a question concerning CapEx levels next year. Jason, do you want to comment?
Oh, sorry. Yeah, I mean, CapEx levels next year in the Lower Mag, they'll be significantly less than this year's levels. Obviously, then we're going to add on approximately $30 million for a Pola well. And depending on timing, you know, we're currently budgeting that Bolivia may see about $5 million of CapEx in the latter half of the year currently. But that'll be timing dependent.
Thank you. The next question comes from Josef Schachter with Schachter Energy Research.
Good morning, Charle and Jason. First thing, going back to Bolivia, and I thank you for the comment, Jason, about the $5 million for 2024 second half, based on timing. Just thinking, going out 2025, 2026, are we looking at something like by the end of 2025, a couple thousand BOEs a day and maybe 5,000-10,000 BOEs a day in 2026? Is that the kind of magnitude we should be looking at, if you're successful with the drill bit?
Yeah, Joe, based on, you know, based on the 4 contracts that we're interested in and that we signed, or 3 of them we signed and 1 yet to be signed, yeah, we're targeting a production and reserve base equal to what we currently have in Colombia currently, within a 3-5-year timeframe. And that's based on, you know, a fairly low risk field redevelopment opportunity, which will be the focus of our main investment in late 2024 and 2025, to redevelop that field and get it back onto production. And then exploration activities around that field, as well as on the other blocks to increase production.
So I, you know, I would say that you know, we expect within 3-5 years to have a production profile similar to what we have currently in Colombia based on those assets. That's the target.
Okay. Yeah, that's very encouraging. Jason, one for you. In terms of debt guidance, in December, of course, you said you'd be sending out all of the guidance for 2024. Are you gonna give us kind of guidance of where you see debt going in 2024, 2025, 2026, to kind of get those numbers to 1.5 or lower, debt to EBITDA?
Yeah, I think when we release our 2024 budget, we will give some guidance as to how much debt we will repay during that year. You know, obviously there's some, you know, anticipated windfall, like, revenues coming from, you know, significantly higher prices during El Niño, so there'll be some assumptions in there. And I guess, you know, we'll have a discussion at a board level if we plan on giving out, you know, longer guidance with respect to, debt repayments in following years.
Okay. And last one for me. The market's voting that you're probably gonna cut the dividend by a third to a half. There's no comment in here. Is this something that'll come out with the December, you know, announcements? And why wasn't it in here, given, you know, given how significant the markets reprice the stock just over the last month and a half?
Yeah. So I think I mentioned on the last call, you know, there is a dividend discussion every quarter. You know, the next dividend we would declare on or about December 15th, and the board looks at current circumstances, future projections. You know, December fifteenth just coincidentally happens to be about the time where we would typically release our 2024 budget, so they'll have that in front of them, along with any new contracts signed. You know, this quarter, despite the production interruptions, was, you know, record EBITDA for us, right? So, you know, they'll consider everything and, you know, I guess, you know, once again, you know, approximately December fifteenth is when that decision's to be made.
Okay, thank you. I'll be waiting for that. Okay, thanks very much.
Thank you. The next question comes from Tim Moroz with Schroders.
Hello, thanks for taking my question. Congratulations on the results. Can you elaborate a little bit what the prioritization of production tasks that the issues you've had means in regards to your reserve replacement ratio for the year? I could imagine that with production being the focus, there could be a lower reserve replacement ratio, but there might be offsetting factors, so I'd much appreciate your comments.
Yes. Based on our focus on development drilling opportunities this past quarter, and the fact we're drilling two development wells through to year-end, you know, we are expecting a lower reserve replacement ratio based on the slower pace of exploration drilling. I would add, you know, that next year, as I think I mentioned, we are going to decelerate the pace of exploration drilling in the Lower Mag Valley. However, we are adding, you know, some material exploration targets in the Middle Mag Valley, and in Bolivia. So I would say in response to your question, yes, we are expecting a lower reserve replacement ratio this year due to the shift towards development drilling.
However, next year, you know, we're anticipating a fairly aggressive reserve replacement ratio in the Middle Magdalena Basin and Bolivia, but not the Lower Mag Basin.
Can you provide any ballpark figures here?
No.
All right. Good. Thank you.
Thank you.
Thank you. At this time, I would like to return the call to Carolina Orozco for any internet questions.
Thank you. The first question comes from Ekaterina Shelek, from Greenberg Family Office. Does the company have plans to buy bonds from the market? What do you think about the current market prices on your bonds?
Yeah, I won't comment on the current market price of the bonds. We all know that it's been a tough market recently. You know, with respect to debt repayments, I guess, you know, obviously we'll make a decision whether or not we will deal with the current revolver outstanding amount first. Which obviously is at a higher rate at SOFR plus 4.5%. You know, our bond interest rate's only 5.75%, but of course, we could, you know, be buying those back, you know, it's whatever it is now, $0.72 or $0.75 on the dollar. So that decision has not yet been made by the board.
Thank you, Jason. The next question is from Alexander Emery from S&P Global Platts. Is there a more firm start-up date for exploration work in Bolivia next year and an ETA for a fourth quarter?
Yeah, I think I mentioned previously that we were looking at starting activities in Bolivia in Q4 of next year. And I think Jason mentioned that the outlook is for up to $5 million of spending related to those activities. Which will be, you know, we anticipate that that $5 million will be spent on working over existing wells to bring them back into production, and the construction of some early production facilities to start commercializing gas.
Thanks, Charle. We have a question from Alex Monroy from Jefferies. Jason, in case you want to add something else, he's asking: Please specify how much debt reduction you expect to be engaged in and timing, as you had mentioned prior.
Yeah, you know, once again, that, that'll come out in our guidance in December relating to 2024. You know, and some of that, of course, is dependent upon, you know, how long, You know, ultimately it will be dependent upon, you know, how long it is, these elevated prices stick around with respect to El Niño. But there is some significant debt reduction currently planned in the budget, in preliminary budget numbers.
Thank you. The next question is from Agustin Bonazola from PineBridge . Could you please give us some color on the increasing payables and the reduction of receivables during the quarter?
Yeah, there's nothing untoward with that. I mean, the payables and receivables, it's just timing issues, you know, there's been no management of those per se. It's just strictly timing. You know, with the elevated CapEx levels this year as compared to prior years, it's just timing of when they get paid. But they're, you know, everything's been paid on regular terms. It's not something we're actively managing at all.
Thank you. The next one is from Manuel Echevarria, from Compass Group. Can you comment on your CapEx priorities for the fourth quarter, given third quarter execution figure was somehow below the yearly trend?
Yeah, I mean, Q4, you know, our, we ended Q3 with $144 million of CapEx. Given that our guidance is $190 million-$200 million of CapEx, you know, I guess the math would be that's $46 million-$56 million. Q4, you know, to comment on that specifically, I guess, we're going to see 2 development wells, as noted in our press release, being Nelson 16 and Pandereta 10.
Thank you, Jason. We have one last question from Alex Marucho, from Lord Abbett. Can you please expand on the reasoning why you don't expect a material reduction in reserve life due to water inflow in the fields that caused the recent production issues?
Yeah, as I, as I mentioned on, on a previous, to a previous question there, the, the influx of water, affected, a couple of wells in one of our minor fields. Our largest fields, which contain over 80% of the bulk of our reserves, 85% of the bulk of our reserves, those being Nelson, Clarinete, Pandereta, Aguas Vivas, those all producing fields where the bulk of our reserves are, are unaffected. Those have been performing very well, and as predicted, and as a matter of fact, you know, based on some of the recent drilling we've done in, in Nelson and in Pandereta and Clarinete, you know, we're seeing some, some good additional upside in those fields as well. For that reason, we do not expect any material change to our, to our reserve base. Okay.
Thank you, Charle. Please give us a minute. We're waiting to see if there's any additional incoming questions.
Yes.