Canacol Energy Q3 2023 Earnings Call Transcript

Quartr
Provided by Quartr
November 10, 2023

There are 11 speakers on the call.

Operator

Hello, and welcome to the Canacol Energy Third Quarter 2023 Earnings Financial Results Conference Call. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. 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.

Operator

Please go ahead.

Speaker 1

Good morning, and welcome to Canacol's Q3 2023 financial results conference call. This is Carolina Orozco, Vice President of Investor Relations. I am with Mr. Charles Gamba, President and Chief Executive Officer And Mr. Jason Bednar, Chief Financial Officer.

Speaker 1

Before we begin, it's important to mention that the comments on this call by Canacol Senior Management These projections neither constitute any commitment to future results nor take into account risks or uncertainties that could materialize. A result, Canacol assumes no responsibility in the event that future results are different from the projection share on this conference call. Please note that all finance figures on this call are denominated in U. S. Dollars.

Speaker 1

We will begin the presentation with our President and CEO, Mr. Charles Gamba, Who will summarize highlights from our Q3 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 and A session.

Speaker 1

I will now turn over the call to Mr. Charles Gamba, President and CEO of Canacol Energy.

Speaker 2

Thanks Carolina and welcome everyone to Canacol's 3rd quarter

Speaker 3

In the Q3, we realized natural gas sales of 178,000,000 standard cubic feet per day, which is slightly below the midpoint of our annual guidance of 160,000,000 to 206,000,000 standard cubic feet per day. After short term production capacity restrictions that began in the 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 $62,000,000 and record funds flow from operations of $49,000,000 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 We call that our reserves in our core producing area are typically held in fields with multiple stacked reservoirs, We are typically only producing from 1 reservoir at a time in any given well. One consequence of that is we have a lot of developed On producing reserves, which we will typically bring into production to meet demand in a staged manner.

Speaker 3

In recent months, we've increasingly focused on development drilling to ensure that we have capacity to meet demand and potentially take advantage of strong pricing in the spot market that we've already seen and anticipate We continue through the Q1 of 2024 related to the El Nino phenomena. During the quarter, we also announced the cancellation of the whole to Medellin project CFO will discuss the 3rd quarter financials in more detail.

Speaker 4

Thanks, Charles. The 3rd quarter was another very good quarter with strong netbacks from our operations. Our gas operating netback was $4.14 per Mcf In the 1st 3 months ended September 30, 2023, which is 11% higher than the same period in 2022 And substantially above our guidance for $3.81 to $3.84 on average for 2023. These high netbacks are mainly attributable Operating expenses were $0.36 per Mcf in Q3, only slightly higher than the prior quarter, and The 1st 9 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 For the Q3, we reported $77,000,000 net of royalties in transportation, which represents a 9% increase from Q3 of 2022.

Speaker 4

The increase was driven by a 13% increase 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 plus years. Adjusted funds from operations was $49,000,000 which represents a 26% increase from the Steadily drawing funds flow over the last 8 plus years. The exhibit also shows the increase in funds flow in the 3rd quarter Relative to the first half of the year, with substantial increase in the 3rd quarter being due to higher netbacks as well as significantly lower cash taxes. The current tax expense averaged $25,000,000 for each of the first and second quarters and was only $10,000,000 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 You're seeing significantly lower cash taxes now that the major steps of the corporate restructuring that began last year are in place.

Speaker 4

Recall that we had a one off current tax expense of $65,000,000 paid in the Q2 of the year, combined with a recognition of a new two zero Termination of the Medellin Pipeline Project. Since it's difficult to compare on adjusted earnings for individual quarters, I have included the presentation materials a Before I hand the call back to Charles, 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 2nd quarter results call in August. Our cash capital expenditures of $143,000,000 for the 1st 9 months represents approximately 88% of our original high case CapEx budget Guidance of $163,000,000 for 2023. The $143,000,000 9 month CapEx does include $19,000,000 of warehouse Inventory as at September 30, this was required under IFRS, including a wellhead and casing materials for Poula 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 $44,000,000 in the 3rd quarter compared to $50,000,000 per quarter in the 1st 2 quarters of the year, Despite higher field level activities in the Q3, we do now anticipate that our total CapEx for 20.20 will be in the range of $190,000,000 to $200,000,000 which, as I just mentioned, includes significant inventory and pre spending for planned activities in The main reason for the increased CapEx spending versus the original budget are, 1st of all, acceleration spending on development drilling in order to increase short term production capacity to take advantage of Tractive market dynamics and offset by the short term production issues we've experienced.

Speaker 4

Therefore, we are now anticipating drilling up to 14 wells during 2020 Some of the original exploration wells were budgeted to drill and test only, so developing these wells required additional tie in costs. And lastly, pre spending on materials in preparation for 2024 activities. Some of this was opportunistic acquisition of general oilfield materials at With respect to leverage, on our net debt to EBITDA, leverage ratio was 2.6 times on a trailing 12 month basis at September 30, Down slightly from 2.7x at June 30 due to higher EBITDA levels. How this ratio evolves moving forward will depend on a host Factors including, 1st 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.

Speaker 4

With our one off cash tax payment now behind us and despite an 2.5 times and the revolver is at 3.5 times. As such, we're well inside those covenant restrictions. Finally, at September 30, we had $44,000,000 in cash $55,000,000 undrawn on our revolving credit facility. That concludes my comments. I'll now hand it back to Charles.

Speaker 3

Thanks, Jason. Our results for the Q3 once again demonstrated high and stable Demand associated with the El Nino phenomenon for the Q1 of 2024. Looking forward to 2024, we will focus on 3 main gross avenues, which are to grow gas sales into the Caribbean market via existing transportation infrastructure, explore the 6.6 Tcf of risk gas resource 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 As supply from Ecopetrol's legacy fields continues to decline. With respect to our middle mag assets, we are planning to drill the Polo 1 exploration well The polar prospect has estimated mean prospective resource of 1.1 Tcf on an unrisked basis and 470 Bcf on a risk basis.

Speaker 3

Polo 1 is one of 17 look alike Polo 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 260,000,000 standard cubic feet per day of spare capacity, meaning that any discovery made at POLA-one can be quickly Bolivia's gas reserves and production have been in decline with current gas production of approximately 1,500,000,000 cubic feet per day, 70% of which is 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, 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 to $15 per Mcf at the wellhead. Of note, The Bolivian market is connected to Brazil by the Gas Bowl pipeline, which has a capacity of 1,100,000,000 cubic feet per day, Approximately 35% of which is currently under you guys.

Speaker 3

Similar to our decision to enter Colombian, 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, mainly Brazil. After 4 years of working with the state oil company, YPFB, we have now executed 3 contracts and are seeking government approval for one additional contract, Potential gas production from these blocks should be relatively easy to commercialize As they are 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 $27,000,000 over the next 5 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 next year.

Speaker 3

We are now ready to take questions.

Operator

And the first question comes from Ariana Koval from Balenoz.

Speaker 5

Hi, thanks for taking my questions. This is Pollyanna Goltz with Valens. I have three questions. The first one is regarding the average sales You're currently seeing if I understood correctly, current sales are around 170 input fixed per day And a time below the $180,000,000 that you shared back when you did the business update. So just to understand How are you seeing sales?

Speaker 5

If you could comment anything of this and if you're meeting your contract yes, your contracts at the moment?

Speaker 3

Yes. So average sales are averaging currently just above 180. The last 2 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.

Speaker 5

Got it. And then just following up on the 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?

Speaker 3

Yes. 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.

Speaker 5

Understood. And just basically seeing these changes in your average sales, it seems according to the historical 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 Comfortable level for you and what are you targeting seeing that you were before this last quarter about 50% of market share in the Caribbean?

Speaker 3

Yes. We're targeting average gas sales between 160,000,000 to 206,000,000 cubic feet per day.

Speaker 5

Understood. And 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. So just To understand if there's any update on that, you may be in process, any color that you can share in this regard?

Speaker 3

Yes, the solicitation for additional Power generation organized by the U. K. May has been delayed until February of next year. So we continue to analyze various projects. Our Tesarito I project with Southsea has performed very, very well.

Speaker 3

We're very pleased with the results of the project that we executed with Southsea. 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.

Speaker 5

Got it. Thank you. That was all from my side.

Operator

Thank you. And the next question comes Mark Higbee with Blue Base.

Speaker 6

Hi. Thanks for the call. I 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 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 field, etcetera?

Speaker 6

And if not, kind of what's the rationale Not sharing the additional details would be useful for us to understand as well. Thanks very much.

Speaker 3

We saw And the second, some water breakthrough from 2 of our minor fields, minor producing smaller producing fields, some early water breakthrough. To address those issues, we executed a series of technical repairs to the facilities, which are Not functioning properly. And we've worked over some of those minor fuels wells in addition to drilling some additional Development wells into our main producing fields that we've commented on publicly in our press releases.

Speaker 6

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 you expect them to be at that level by the end of November? Or kind of have you only managed to recover a Partial amount of the volume that they were producing before the operational issues started aside from the Grub gas treatment facility?

Speaker 3

Yes, 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

Speaker 6

Okay. Thank you.

Operator

Thank you. And the next question comes from Kevin Salisbury with 91 Asset Management.

Speaker 7

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, Talking to them, they've premised it on effectively the take or pay agreements dropping to around 50% by 2026 And their claim was that they made the 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.

Speaker 4

Yes, Sure. I mean, Fitch was one level higher than both Moody's and S and P. So even the one level downgrade put them in line with The other 2, of course, the other 2 have not changed their opinion or their outlook. With respect to Fitch's assumption that our take or pays will only be Percent by 2026. We've typically contracted 80% of our expected volumes in take or pays.

Speaker 4

Heading into El Nino or now that we're in El Nino and heading into the new December 1 contract year, We may not do all 80%. There's still another 20 days left in this month to Sign other contracts, but I don't expect that we'll be deviating significantly from that historical plan Post El Nino, the prices are relatively high and climbing in terms of long term contracts. So we'll be

Operator

Thank you. And the next question comes from Daria Lima with Bloomberg Intelligence.

Speaker 8

Hi, good morning. Thank you for taking my questions and congratulations on a good quarter. My understanding is that you renegotiate your prices in Are you looking to secure higher prices for the fixed contract volumes in December? And if so, can you give us any

Speaker 3

To our contracted volumes, take or pay volumes, a percentage of them roll off on November 30, and we either We negotiate and extend those volumes with the clients or we look for other clients or we leave those volumes unoccupied to sell in the spot market. So this November 30, approximately 40 1,000,000 cubic feet per day of take or pays will roll off. And we're currently looking at Analyzing our strategy with respect to what percentage of those additional those 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 Q1 and into the Q2 of next year due to the El Nino effect.

Speaker 8

Thank you. That's helpful. Just a couple of 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 206 Mcf a day?

Speaker 3

Yes. We expect to achieve normal conditions, which are Current to our guidance of 160,000,000 to 260,000,000 cubic feet per day.

Speaker 8

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?

Speaker 3

Yes. With respect to upstream competition, there's very little, only really the majors and YPFB We are involved in upstream activities in Bolivia. There's no real smaller or medium sized companies active there aside from Oxy With respect to where the gas goes in Bolivia, 70% of gas is exported both to Northern Argentina and to Brazil. With respect to Argentinian gas Production 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 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 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, we feel quite comfortable that Bolivia is a very good jurisdiction for us to invest in natural gas operations.

Speaker 8

Thank you. That's very helpful.

Operator

Thank you. And the next question comes from Alvin Lim with Morgan Stanley.

Speaker 3

Hi, how are you?

Speaker 9

Just have a question on CapEx. So pull out one type of exploration activity, I understand it is a deep gas What would be the CapEx difference of the exploration for Polar 1 versus Midmac 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 Budd, 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 20 Or would you expect, I guess, given the new exploration opportunities in lower math, the overall CapEx should not deviate too much from the recent figures that we saw in 2022 and 2023. Thank you.

Speaker 3

Jason, these seem to be CapEx questions.

Speaker 4

Yes, sure. I mean the 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 $30,000,000 to drill. Some of our lower mag wells are anywhere in the range from 4,500,000 to 6,000,000 Depending on if we're drilling a off an existing pad. Obviously, follow-up polo wells, If there's no demow above the rig and if they're from an existing pad would be less than the 30 mill that the first well is expected

Speaker 3

I think there was a question concerning CapEx levels next year, Jason.

Speaker 4

Sorry. Yes, I mean CapEx levels next year In the lower MEG, they'll be significantly less than this year's levels. Then we're going to add on approximately $30,000,000 for Apollo well. And depending on timing, we're currently budgeting that Bolivia may see about $5,000,000 of CapEx in the latter half of the year currently. Would that be timing dependent?

Operator

Thank you. And the next question comes from Joseph Stockter with Stockter Energy Research.

Speaker 10

Good morning, Charles and Jason. First thing going back to Bolivia, and I thank you for the comment, Jason, about the $5,000,000 for 2024 second half based on timing. Just thinking going out 2025, 'twenty six, Are we looking at something like by the end of 'twenty five, a couple of 1,000 BOEs a day and maybe 5000 to 10000 BOEs a day in 'twenty six? Is that the kind of magnitude we should be looking at, if you're successful with the drill bit?

Speaker 3

Yes, Joe. Based on the 4 contracts We're interested in and that we signed 3 of them we signed and 1 yet to be signed. We're targeting a production and reserve base equal to what we currently have in Colombia currently within a 3 to 5 year timeframe. And that's based on 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.

Speaker 3

So I would say that We expect within 3 to 5 years to have a production profile similar to what we have currently in Colombia based on those assets. That's the

Speaker 6

target. Okay.

Speaker 10

Yes, 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 going to give us kind of guidance of where you see Debt going in 24%, 25%, 26% to kind of get those numbers to 1.5% or lower debt to EBITDA?

Speaker 4

Yes, I think when we release our 2024 budgets, we will give some guidance as to how much Debt we will repay during that year. Obviously, there's some anticipated windfall like revenues coming From significantly higher prices during El Ninos, so there'll be some assumptions in there. And I guess, we'll have a discussion at a Board level if we plan on giving out longer guidance with respect to Debt repayments in following years.

Speaker 10

Okay. And last one from me, the market's voting that You're probably going to cut the dividend by a third to a half. There's no comment in here. Is this something that will come out with the December Announcements and why wasn't it in here given how significant the markets repriced the stock just over the last month and a half?

Speaker 4

Yes. So I think I mentioned on the last call, there is a dividend discussion every quarter. The next dividend we would declare on or about December 15, and the Board looks at Current circumstances, future projections, December 15 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. This quarter, despite the production interruptions, was record EBITDA for us, right? They'll consider everything.

Speaker 4

And I guess, once again, we'll Approximately December 15 is when that decision is to be made.

Speaker 10

Okay. Thank you. I'll be waiting for that. Okay. Thanks very much.

Operator

Thank you. And the next question comes from Tom Moses with Schroders.

Speaker 2

Hello. Thanks for taking my question. Congratulations on the results. Can you elaborate a little bit what the Prioritization of production costs that the issues that 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 Allow our reserve replacement ratio, but there might be offsetting factors. So I'd much appreciate your comments.

Speaker 3

Yes. Based on our focus on development drilling opportunities this past quarter and the fact we're drilling 2 development wells through to year end, We are expecting a lower reserve replacement ratio based on the slower pace of exploration drilling. I would add that next year, as I think I mentioned, we are going to decelerate the pace of exploration drilling at Lower Mag Valley. However, we are adding some material exploration targets in the Middle Magp 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.

Speaker 3

However, next year, we're anticipating a fairly aggressive reserve Replacement ratio in the Middle Magdalena Valley and Bolivia, but not the Lower Magdalena.

Speaker 2

Can you provide any ballpark figures here?

Speaker 3

No.

Speaker 7

All right.

Speaker 2

Thank you.

Speaker 3

Thank you.

Operator

Thank you. At this time, I would like to return the call to Carolina Orozco for any Internet questions.

Speaker 1

Thank you. The first question comes from Ekaterina Shaleg from Bloomberg 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?

Speaker 4

Yes. I won't comment on the current market price of the bonds. We all know that's been a tough market recently. Now with respect to debt repayments, I guess, 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 sulfur plus 4.5%. Our bond interest rate is only $5,750,000 but of course we could be buying those back at whatever it is now, dollars 0.72 or $0.75 on the dollar.

Speaker 4

So that decision has not yet been made by the Board.

Speaker 1

Thank you, Jason. The next question is from Alexander Emery from S&P Global Plus. Is there a more firm start up date for exploration work in Bolivia

Speaker 3

Yes, 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 We're up to $5,000,000 of spending related to those activities, which will be we anticipate that that $5,000,000 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.

Speaker 1

Thanks, Charles. 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?

Speaker 4

Yes. Once again, that will come out in our guidance in December relating to 2024. And some of that, of course, is dependent upon how long the ultimately, it will be And upon how long these elevated prices stick around with respect to El Nino, but there is Some significant debt reduction currently planned in the budget in preliminary budget numbers.

Speaker 1

Thank you. The next question is from Agustin Bonasora from Pine Bridge. Could you please give us some color on the increase in payables and the reduction of receivables during

Speaker 4

Quarter? Yes, there's nothing untoward with that. I mean, the payables and receivables, it's Just timing issues. There's been no management of those per se. It's just strictly timing.

Speaker 4

With the elevated CapEx levels this year as compared to prior years, it's just timing of when they get paid. But there Everything has been paid on regular terms. It's not something we're actively managing at all.

Speaker 1

Thank you. The next one is from Manuela Chavarria from Compass Group. Can you comment on your CapEx

Speaker 4

Yes, I mean Q4, we ended Q3 with $144,000,000 of CapEx, Given that our guidance is $190,000,000 to $200,000,000 of CapEx, I guess the math would be that's $46,000,000 to 56,000,000 Q4, to comment on that specifically, I guess, we're going to see 2 Development wells, as noted in our press release, being a Nelson 16 and Pandereta 10.

Speaker 1

Thank you, Jason. And we have one last question from Alex Marucho from Lord Abbot. 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? Yes.

Speaker 3

As I mentioned on a previous to a previous question there, 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 Some clarinete, Pandereta, Agos Rivas, old producing fields where the bulk of our reserves are unaffected. Both have been performing very well and as predicted. And as a matter of fact, based on some of the recent drilling we've done in Nelson and in Andaretta and Clarinete, we're seeing some good additional upside in those fields as well. For that reason, we do not expect any material change to our

Speaker 1

Thank you, Charles. Please give us a minute. We're waiting to see if there's any additional incoming questions.

Operator

Yes.

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Key Takeaways

  • Despite slightly lower production from temporary capacity restrictions, Q3 netbacks were $4.14/Mcf, operating margins reached 77%, and the company delivered record EBITDA of $62 M and $49 M in funds flow from operations.
  • The short‐term production issues from water breakthrough in minor fields are being addressed through technical repairs and additional wells, with full production recovery expected by end-November and no anticipated material reserve revisions.
  • Through September, $143 M in capital spending was incurred (88% of the original 2023 budget), and total CapEx is now forecast at $190 M–$200 M to accelerate development drilling and pre-spend for 2024 activities.
  • For 2024, Canacol plans to grow gas sales into the Caribbean via existing infrastructure, drill the Polo-1 prospect (1.1 Tcf unrisked resource) in the Middle Magdalena Valley, and develop Bolivia assets under four contracts with first gas expected in 2025.
  • Leverage remains conservatively managed with net debt/EBITDA at 2.6×, ample liquidity (US$44 M cash and US$55 M undrawn credit), and anticipated debt reduction funded by higher Q4 cash flows and lower tax payments.
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Earnings Conference Call
Canacol Energy Q3 2023
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