Transcripts
Canacol Energy Ltd (CNNEF) Q1 2023 Earnings Call Transcript
Operator
Good morning and welcome to the Canacol Energy First Quarter 2023 Financial Results Conference Call. [Operator Instructions] 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.
Carolina Orozco
Good morning and welcome to Canacol’s first 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 is important to mention that the comments on this call by Canacol’s senior management can include projections of the corporation’s future performance. These projections neither constitute any commitment as to future results nor take into account risks or uncertainties that could materialize. As a result, Canacol assumes no responsibility in the event that future results are different from the projections shared on this conference call.
Please note that all finance figures on this call are denominated in U.S. dollars. We will begin the presentation with our President and CEO, Mr. Charle Gamba, who will summarize highlights from our first 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. At the end, we will have a Q&A session.
I will now turn the call over to Mr. Charle Gamba, President and CEO of Canacol Energy.
Charle Gamba
Thank you, Carolina and welcome, everyone, to Canacol Energy’s first quarter 2023 conference call.
In the first quarter of 2023, we realized natural gas sales of 184 million standard cubic feet per day which is just above the midpoint of our annual guidance of 160 million to 206 million standard cubic feet per day. Our relatively stable production and operating conditions allowed us to report a quarter with the highest sales prices and netbacks prior to COVID, an operating margin of 78%, record EBITDAX of $61 million and a relatively high return on capital employed for the quarter on an annualized basis.
With respect to our drilling activity, we were largely focused on production testing of the Saxofon-1 and Dividivi-1 gas discoveries. With Saxofon-1 testing a combined rate of 15 million standard cubic feet per day and Dividivi testing a rate of 5 million standard cubic feet per day. Saxofon is currently being tied into the Jobo facility and a commercialization plan is currently being worked up for the Dividivi discovery.
Subsequent to the first quarter, we announced the discovery at Lulo-1 which is located on a 100% operated VIM-21 exploration and production contract. Lulo-1 encountered 207 feet of gas — net gas pay within the primary Cienaga de Oro sandstone reservoir. And once we finalize production testing which commenced last night in various zones, the well will be tied into permanent production directly to the full gas treatment facility located only 50 meters from the well. Lulo-1 is part of our 2003 exploration program and has opened an area of deeper potential in and around our main producing area that we’re planning to pursue aggressively in the short term.
I’ll now turn the presentation over to Jason Bednar, our CFO, who will discuss our first quarter financials in more detail.
Jason Bednar
Thanks, Charle. The first quarter was another very good quarter with strong netbacks from our producing operations. Our gas operating netback was $4.01 per Mcf in the 3 months ended March 31, 2013 [ph] which is 12% higher than in the same period in 2022, 8% higher than the prior quarter and approximately 5% above our guidance of $3.81 to $3.84 on average for 2023. These high netbacks can be attributed to spot market pricing that was significantly stronger during the quarter than we had assumed it would be for the whole year of 2023 on average.
As such, our total realized gas price of $5.13 per Mcf was relatively strong. We’re encouraged by the persistence of robust pricing for interruptible gas sales despite somewhat subdued demand in terms of volumes. Recall that the majority of our guidance is based on sales under fixed take-or-pay contracts with an average fixed price of $5.09 per Mcf. OpEx was $0.25 per Mcf in Q1, down from $0.30 in the fourth quarter as we were undertaking less maintenance. In percent terms, our gas royalties increased slightly to 17% of revenue due to higher production at the VIM-5 block which is subject to higher royalties. I’ll also note that our recent Lulo discovery as well as its planned development wells will only have a 9.4% royalty.
Return on capital employed was 17% for the quarter on an annualized basis and 12% on a trailing 12-month basis. We reported $74 million of revenue net of royalties and transportation which represents a 12% increase from Q1 of 2022. This increase was driven by a 3% increase in sales volumes, combined with a 10% increase in realized prices, slightly offset by higher royalties; $33 million in adjusted funds from operations which represents a 3% decrease from the same period in 2022; EBITDAX of $61 million which represents a 23% increase from the same period in 2022; and finally, net income of $17 million being 31% lower than the same period in 2022. The significantly different trend in adjusted funds flow from operations and EBITDAX is mainly attributable to an increase in cash taxes relative to the same quarter in 2022. The $26 million of current taxes this quarter have several factors impacting that relatively large number.
First of all, is the increased sales tax — increased taxes on the company’s record EBITDAX which was $11 million higher than in the same quarter of 2022. Secondly, the recent tax reform made royalties nondeductible beginning in 2023 and also added an additional surtax on a relatively modest oil operations. And lastly, as you may recall, in Q4 of 2022, we initiated a corporate reorganization in order to better optimize our business alongside of which we also increased our deferred tax asset by $202 million which is still expected to provide benefits over the next 10 years. The final steps of that reorg are currently being completed and as such, this quarter’s tax provision recognized some associated trailing costs.
As mentioned, EBITDAX of $61 million was the highest we have ever reported. And I think the long-term trend of steadily growing EBITDAX over the last 7-plus years is worth highlighting briefly. We do not — we do anticipate this trend continuing. And as such, our high-case 2023 EBITDAX guidance of $263 million remains unchanged.
This concludes my comments. I’ll now hand it back to Charle.
Charle Gamba
Thanks, Jason. Our results for the first quarter once again demonstrated high and stable operating margins as well as a very respectable rate of return on capital employed. Our guidance and plan for 2023 which I discussed on our year-end results conference call in March, remain largely unchanged. Forecast realized contractual gas sales for 2023 which include downtime, are anticipated to range between 160 and 206 million of standard cubic feet per day. Our gas sales averaged 185 million standard cubic feet per day for the first quarter and 180 million standard cubic feet per day during April of this year. So we have started the year around midpoint of our guidance. The corporation’s firm 2023 take-or-pay contracts alone averaged 160 million standard cubic feet per day, net of 2023 contractual downtime.
We’re optimistic we will continue to see demand and related sales volumes and pricing remain strong, particularly heading into what is expected to be a very strong El Nino in the second half of this year, allowing us to report continued growth in sales volumes, revenues and funds from operations. We, therefore, expect to remain well positioned to continue returning capital to shareholders while investing for growth. Our capital program has flexibility to adjust spending as new information is obtained and opportunities present themselves. An example of this is our decision to immediately drill the Lulo-2 well following discovery of Lulo-1 to appraise the extent of this important discovery.
We’re now ready to take questions.
Question-and-Answer Session
Operator
[Operator Instructions] Our first question is from Oriana Covault with Balanz.
Oriana Covault
This is Oriana Covault with Balanz and I had 3 questions. If I may go one by one, that would be great. The first one has to do with this lower maintenance activity that you recorded during the quarter and that actually drove lifting costs down. So if maybe you could mention how should we think of upcoming scheduled maintenance activities and in terms of lifting cost impact, should we think these are some new sustainable levels? That would be the first one.
Jason Bednar
Yes, I can answer that question. Due to various timing issues, etcetera, the maintenance or the OpEx by quarter sometimes gets a little lumpy. I would not consider this $0.25 as the new go-forward norm. Our budget is for $0.32 on average for the year and we still do expect to see $0.32 on average for the year.
Oriana Covault
Perfect. And maybe just moving on to the follow — the second one. In terms of the RCF, we noticed that you used $75 million during the quarter, $40 million additional on the $35 million you had initially used for debt repayment. So just to understand if this $40 million is in connection with the tax payment that you had already anticipated — that you had already mentioned during your last earnings call? And if you’re seeing perhaps revisions in the additional amount that you plan to tap from this RCF in the following quarters?
Jason Bednar
Yes. I’m going to tie that in with a written question I already have from Christian Calderan, where he’s basically asking the similar schedule of the tax payment. So these financial statements show that we paid $18 million of tax cash payments physically out the door during Q1. Of course, that initial tax restructuring bill, if you will, of $65 million, that will be paid — the balance of that will be paid this quarter. With respect to the use or how much we may use of the $200 million, I will say that today, we are drawing $130 million of that. That amount, of course, is — has been upsized from the $75 million to the $130 million amount in order to pay that last $65 million of the restructuring costs. But I will also state at this point in time, as of today, we do have $85 million in the bank. We do not intend, anticipate to draw any more of that revolver during the remainder of the year and on a debt-to-EBITDA ratio, we expect to end the year at approximately 2.4x. I think this quarter, we ended at 2.31x and to refresh everyone’s memory, our bond covenant is at 3.25x and the revolver is at 3.5x. So we’re well inside those covenant restrictions.
Oriana Covault
Perfect. That’s very clear. And just one last one with regards to sales that are coming up from Tesorito. So just to — maybe if you could provide additional color in terms of availability. If you saw any improvement during the quarter? And how much of the total sales that you’re reporting are coming in from Tesorito? That would be helpful.
Jason Bednar
Charle, would you like me to answer that?
Charle Gamba
Sure. Go ahead, Jason.
Jason Bednar
Sure. So during Q1, included in our numbers was 21.9 million cubic feet a day on average for the 90 days of Q1 that were sold for Tesorito at a healthy price of $5.66.
Oriana Covault
Congratulations for good results during the quarter.
Jason Bednar
Thank you.
Operator
The next question is from Josef Schachter with SER.
Josef Schachter
Jason, back to you. With the increase, as you mentioned on the RCF to $130 million, is that for our modeling going to be the high point for debt and that you expect the debt to be lower by the end of 2023?
Jason Bednar
That will be the high point for the year. At this stage, according to the budget which could conceivably have some upside left on them. But according to the budget, we would also end the year at that $130 million. Now like I said earlier, in all re-note here, that our current cash balance is $85 million. So it’s been adding to the current cash position, not just simply being a spender drilled into the ground at this stage.
Josef Schachter
Just to follow up there. Net debt at the end of December ’22 was US$573 million. Do you expect to be below that at the end of this year?
Jason Bednar
Let me just look on the screen here. The net debt at the end of the year, we anticipate to be just over $600 million.
Josef Schachter
Super. And Charle, you mentioned…
Charle Gamba
Right around a $600 million.
Josef Schachter
$600 million. Okay, yes. I made that note. Charle, you mentioned in your commentary about El Nino. Is that going to affect the hydro? And is that going to open up the ability for more spot sales? Maybe if you can give us your thoughts of how El Nino might affect operations in Colombia so that we can get an idea of the impact of that.
Charle Gamba
Yes, two things. El Nino, the forecast from NOAA for El Nino is now at 93% probability according to the last update this week from NOAA, starting in July of this year and extending potentially through midyear 2024. So typically, that would indicate that by third quarter this year, we’ll start to see reservoir levels here in Colombia at very low levels. And of course, will require the use — the addition of — just spare one moment. And that will essentially necessitate the use of thermoelectric power plants to make up for the shortfall in electrical power. So that will translate into 2 factors related to us. First, we will increase overall volumes. We have a productive capacity now a fairly healthy productive capacity to meet anticipated demand.
And the second factor will be pricing. So typically, we tend to see much higher pricing, not on the spot market during El Ninos. If we go back to 2016, during the last El Nino, we saw spot pricing in the $12 to $14 per MMBtu. We also anticipate that Tesorito, the 200-megawatt power plant that we’re connected to will be dispatching at 100% and the capacity of that plant is 40 million cubic feet per day. So yes, we expect higher volumes and better pricing on interruptible prices and Tesorito pricing.
Josef Schachter
Okay, super. So that will be fabulous if that occurs and really help cash flow and maybe not got debt down a little further. You mentioned on the — that you’re following up on the exploration success. Does that mean that Pola now gets moved into — Pola-1 gets moved into 2024. Maybe if you can give us some guidance on how you see the exploration program and any issues related to equipment or whatever and Pola needs to be pushed further into the future?
Charle Gamba
Yes, 2 things. With respect to the success at Lulo which is a deep Cienaga de Oro play in and around our production facilities, we’ve identified several other prospects to drill in the area, that’s about a 5-kilometer square area in and around our producing facilities. So after we drill Lulo-2, we’re going to be drilling the [indiscernible] exploration prospects which are very similar, identical to [indiscernible] and then possibly a fourth exploration prospect. With respect to Pola, we’re currently negotiating a 3,000 horsepower rig. We expect that if we successfully negotiate that rig, we will be spudding Pola mid-September to mid-October of this year. With that date in mind, we could possibly have results by year end but it’s likely we would have results in the first quarter of 2024.
Josef Schachter
Perfect. Okay. That does it for me. Congratulations on the improved quarter.
Charle Gamba
Thanks, Josef.
Operator
[Operator Instructions] While we wait, I’d like to turn the call back over to Carolina Orozco for some web questions.
Carolina Orozco
We have one question from Ricardo Sandoval from Bancolombia. Can you explain how did you accomplish a reduction of 27% in operating costs? Can we expect the margins like for 2023 for the whole year?
Jason Bednar
Yes, I think I partially answered that. I mean, our operating expenses as a quantum, are relatively low. This quarter, it was $5 million which equaled the $0.25. So even an additional $1 million of maintenance activities which would have being in the original budget would bring that $0.25 up to the $0.30. So as I think I already stated earlier, we do expect to catch up on those maintenance activities, whether they occur in Q2 or Q3 with those quarters having higher than the annual budget of $0.32. But overall, as a whole, our look through till the end of the year, we still believe the year will average approximately $0.32 of OpEx.
Carolina Orozco
Thanks, Jason. We have another question from Sergey Bolshakov. Which one is your expectation of net sales according to the dry climate is coming in Colombia? Do you keep expecting to make investments outside Colombia according to the new political risk? And how are they going, especially in Bolivia or other locations?
Charle Gamba
Okay. I think I covered our expectations with respect to El Nino and the increase we expect in volumes and interruptible pricing question with Josef. With respect to our activities outside of Colombia, we continue to negotiate several exploration and production contracts in Bolivia. We expect that process to conclude shortly, at which time we’ll be making a decision with respect to proceeding in that in Bolivia. And that, of course, would be gas as well.
Jason Bednar
Yes, Carolina, I’ll just note here also the numbers that I gave out with respect to net debt at the end of the year and net leverage ratios at the end of the year were based on — there is 0 upside put into those numbers with respect to El Nino. Those are simply just based on our actual quarter-to-date and the remainder of the year averaging that 206 million [ph] number.
Operator
Our next question is from Nikos Monoyios with Ingalls & Snyder.
Nikos Monoyios
I have some more exploration related questions. The Dividivi-1 well, what was the drilling cost? And what are the potential development cost for the options you are considering the pipeline connection or CNG plant? And also, could you give us an update on the status of the Chimela-1 well that you drilled back in January and Natilla well — Natilla-1 well?
Charle Gamba
With respect to Dividivi, that was a very shallow well, 5,600 feet vertical depth. I believe the final drilling collision cost came in at about $3 million because it’s quite shallow for us. With that particular discovery, we’re looking at a plan. In that area, we are unable to shoot seismic, 3D seismic. It’s a fairly wet area. So the first thing we’re going to do later this month is commence a very long-term production test of the zone, the Cicuco limestone we encountered to see what the potential reserves might be associated with that long-term production test can give us some idea. Upon the completion of that long-term production test, we will formulate a commercialization plan which has 2 options: either tie it into the TGI pipeline, 35 kilometers to the east, if it’s sufficiently large or to install a liquefication plant at Dividivi and sell liquefied natural gas to some of the surrounding population centers. One of the largest ones would be the city of Cucuta in the Venezuelan border which has a consumption of about 8 million to 9 million cubic feet per day of natural gas which is not connected to any pipeline system. So that consumers in Cucuta are using compressed natural gas at fairly high cost. So we should have a commercialization plan worked out for Dividivi after that long-term production test.
With respect to Chimela, we plan to initiate production testing here at the end of this month. We’re testing several of the oil zones we encountered there. And if the test results are good, we will immediately commence temporary production of those wells and truck the oil to local transportation points. And with respect to Natilla, we do not have an update to provide at this point in time.
Nikos Monoyios
I see. One more follow-up on the Dividivi. What would be the minimum reserve size to justify a pipeline connection? Would we be looking at something at least a minimum of 50 Bcf to justify a pipeline connection?
Charle Gamba
Given the distance and the cost of the pipeline connection, probably 25 Bcf would be sufficient to construct a 6-inch flow line, 6-inch flowline which would be capable of transporting about 20 million to 25 million cubic feet per day. So that’s the transportation option via pipeline. The LNG option based on the production test that we currently have completed, the LNG option is commercial at this point in time.
Operator
The next question is from Chen Lin with Lin Asset Management.
Chen Lin
Charle, congratulations for the good quarter. I did — I probably missed a little bit. I think a lot of people were asking about El Nino I know we discussed that last time we were in Bogota. So the question is what — right now, you’re producing about 185 million cubic feet a day. So what’s the — like the actual maximum capacity you can provide in terms of El Nino? And I understand that right now, the 160 million is the contract price, the rest will be at the spot price. Is that correct?
Charle Gamba
That’s correct, Chen. So anything above 160 million is essentially offered a spot price. And the current productive capacity at the moment is about 240 million cubic feet per day. Lulo and Lulo-2 should boost that significantly.
Chen Lin
With Lulo already in term of this El Nino season, this [indiscernible] of the natural gas demand?
Charle Gamba
Lulo is already connected into the Jobo production facility. We’re flowing the well as we speak into the Jobo production facility.
Operator
At this point, I’d like to turn the call back over to Carolina Orozco.
Carolina Orozco
We have a question from [indiscernible]. Can you provide some update on the next option for new thermal capacity, if you can share the strategy and update on time line?
Charle Gamba
Yes. The UPME has initiated a new bid round for energy, both thermal and renewable. We are currently evaluating a couple of projects. With respect to that, those will both be thermal projects very similar to the Tesorito project. We’re currently partnered with Celsia and Proelectrica. With respect to the timing, that bid round bids will be due in mid-August currently. So we are working with a number of different parties to look at participating in that bid round with the objective of participating in at least 1 or 2 new power projects. And these projects would come online in 2026 or 2027.
Carolina Orozco
We have one more question from Till Moes from Schroders. In the light of your strong exploratory activity, if you were to keep the current pace, how many years of exploratory activity for your current portfolio of exploratory licenses left?
Charle Gamba
On our current 11 E&P licenses that we currently have under contract with the regulator, we’ve identified about 175 remaining exploration prospects that we could drill under the current contractual terms. So that’s probably at least 10 years of portfolio on the exploration side.
Carolina Orozco
With this, we don’t have any questions — any more questions. Thank you all for participating in Canacol’s first quarter conference call. We hope you all have a great day.
Operator
The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.