Good morning, and welcome to the Canacol Energy first quarter 2023 financial results conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your telephone keypad. To withdraw your question, please press star then two. Please note, this event is being recorded. I would now like to turn the conference over to Carolina Orozco, Vice President of Investor Relations. Please go ahead.
Good morning, 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 US 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.
Thank you, Carolina. 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 160-206 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 8%, 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 at a combined rate of 15 million standard cubic feet per day and Dividivi testing at a rate of 5 million standard cubic feet per day. Saxofon is currently being tied into the Jobo facility, a commercialization plan is currently being worked up for the Dividivi discovery. Subsequent to the first quarter, we announced a discovery at Lulo-1, which is located on a 100% operated VIM21 exploration and production contract. Lulo-1 encountered 207 feet of gas, net gas pay within the primary Cienaga de Oro sandstone reservoir.
Once we finalize production testing, which commenced last night in various zones, the well will be tied into permanent production directly to the whole 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.
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 three months ended March 31, 2013, 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-$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. 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 twelve-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. 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 has several factors impacting that relatively large number. First of all, is the increased sales 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 our relatively modest oil operations. 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 recognizes 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+ years is worth highlighting briefly. 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 Charles.
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 million and 206 million 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. We have started the year around midpoint of our guidance.
The corporation's firm 2023 take-or-pay contracts alone average 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 Niño the second half of this year, allowing us to report continued growth in sales volumes, revenues, and funds from operations. We 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.
We will now begin the question-and-answer session. To ask a question, you may press star, then one on your telephone keypad. 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 our roster. Our first question is from Oriana Oriana Covault with Balanz. Please go ahead.
Hi. Thanks to all Canacol team for the material, team, congratulations for the quarter. This is Oriana Covaultl with Balanz. I had tree 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. 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.
Yeah, I can answer that question. You know, due to various, you know, timing issues, et cetera, you know, the, 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.
Perfect. Thank you. maybe just moving on to the second one. In terms of the RCF, we noticed that you used $75 million during the quarter, and $40 million additional on the $35 million you had initially used for debt repayment. 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?
I'm going to tie that in with a written question I already have from Christian Calderon, where he's basically asking, you know, the similar schedule of the tax payment. 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, the balance of that will be paid this quarter. With respect to, you know, the use or how much we may use of the $200 million, I will say that at today we have drawn $130 million of that.
That amount, of course, is, you know, has been upsized from the 75 to the 130 amount in order to pay that last $65 million of the restructuring costs. 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. On a, you know, debt-to-EBITDA ratio, we expect to end the year at approximately 2.4x. I think this quarter we ended at 2.31x. To refresh everyone's memory, our bond covenant is at 3.25x and the revolver is at 3.5x. We're well inside those covenant restrictions.
Perfect. That's very clear. Thank you. Just one last one, with regards to sales that are coming up, from Tesorito. Just to, maybe if you could provide additional colors 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. Thank you.
Charle, would you like me to answer that?
Sure. Go ahead, Jason.
Sure. 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 to Tesorito at a healthy price of $5.66.
Okay. That's very helpful. Thank you very much, guys. Again, congratulations for good results during the quarter.
Thank you.
The next question is from Josef Schachter with SER. Please go ahead.
Good morning, everyone, and thanks for taking my questions. Jason, back to you. With the increase, as you mentioned on the RCF to $130, is that for our modeling going to be the high point for debt and that you expect debt to be lower by the end of 2023?
That will be the high point for the year. At this stage, you know, according to the budget, you know, which could conceivably have some upside left on them. According to the budget, we would also end the year at that $130 million. Like, you know, I said earlier, and I'll re-note here that our current cash balance is $85 million. You know, it's been adding to the current cash position, not just simply being spent or drilled into the ground at this stage.
Just to follow up, net debt at the end of December 2022 was $573 million. Do you expect to be below that at the end of this year?
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.
Okay. Super. Charles, you mentioned in your-.
Right around $600 mil.
600? Okay. Yeah, I made that note. Thanks very much. Charles, you mentioned, in your commentary about El Niño, is that gonna affect the hydro, and is that gonna open up the ability for more spot sales? Maybe if you can give us your thoughts of how El Niño might affect operations in Colombia, so that we can get an idea of the impact of that.
Yeah, two things. El Niño, the forecast from NOAA for El Niño 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. Typically, that would indicate that by third quarter this year, we'll start to see reservoir levels here in Colombia at very low levels. That, of course, will require the use, the addition of. Just bear one moment. That will essentially necessitate the use of thermoelectric power plants to make up for the shortfall in electrical power. That will translate into two 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. The second factor will be pricing. Typically, we tend to see much higher pricing on the spot market during El Niños. If we go back to 2016, during the last El Niño, we saw spot pricing in the $12-$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. Yes, we expect higher volumes and better pricing on interruptible prices and Tesorito pricing.
Okay, super. That'll be fabulous if that occurs and really help cash flow and maybe knock that debt down a little further. You mentioned that you're following up on the exploration success. Does that mean that Polo now gets moved into... Polo One 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, to, you know, and if Polo needs to be pushed further into the future.
Yeah, two 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. It's about a 5-kilometer square area in and around our producing facilities. After we drill Lulo-2, we're gonna be drilling the Piña Norte-1 and the Cereza-1 exploration prospects, which are very similar, identical to Lulo, and then possibly a fourth exploration prospect. With respect to Polo, we're currently negotiating a 3,000 horsepower rig. We expect that if we successfully negotiate that rig, we will be spudding Polo 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 first quarter of 2024.
Super. Okay, that does it for me. Thank you so much for taking my questions, and congratulations on the improved quarter.
Thanks, Joseph.
Again, if you have a question, please press star then one. While we wait, I'd like to turn the call back over to Carolina Orozco for some web questions. Please go ahead.
Thank you. 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 first Q 2023 for the whole year?
Yeah, I think I partially answered that. I mean, our operating expenses, you know, as a quantum are relatively low. This quarter it was, you know, $5 million, which equaled the $0.25. Even an additional $1 million of maintenance activities, which would have been in the original budget, you know, would bring that $0.25 up to the $0.30. As I think I already stated earlier, we do expect to catch up on those maintenance activities, whether it's they occur in Q2 or Q3, with those quarters, you know, having higher than the annual budget of $0.32. 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.
Thanks, Jason. We have another question from Cesar Orozco. 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 risks? How are they going, especially in Bolivia or other locations?
Okay, I think I covered our expectations with respect to El Niño and the increase we expect in volumes and interruptible pricing, on a question with Josef. With respect to our activities outside of Colombia, you know, 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. That, of course, would be gas as well.
Carolina, I'll just note here also that, you know, 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 zero upside put into those numbers with respect to El Niño. Those are simply just based on our actual quarter to date and the remainder of the year averaging that 206 number.
Thanks, Jason.
Excuse me. Our next question is from Nikos Manolios with Ingalls & Snyder. Please go ahead.
Good morning and congratulations. I have some more exploration related questions. The Dividivi 1 well, what was the drilling cost? What are the potential development costs for the options you're considering, the pipeline connection or a CNG plant? Could you give us an update on the status of the Chimela 1 well that you drilled back in January and the Natilla well, Natilla one well?
With respect to Dividivi, that was a very shallow well, 5,600 feet vertical depth. I believe the final drilling completion cost came in at about $3 million, 'cause 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, 3-D seismic. It's a fairly wet area. The first thing we're gonna 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. A 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 two options: either tie it into the TGI pipeline 35 kilometers to the east, if it's sufficiently large, or to install a liquefaction 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 on the Venezuelan border, which has a consumption of about 8 to 9 million cubic feet per day of natural gas, which is not connected to any pipeline system. That consumers in Cucuta are using compressed natural gas at fairly high cost. 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 encounter 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. With respect to Natilla, we do not have an update to provide at this point in time.
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?
Given the distance and the cost of the pipeline connection, probably 25 BCF would be sufficient to construct a 6-inch flow line. A 6-inch flow line, which would be capable of transporting about 20-25 million cubic feet per day. That's the transportation option via pipeline. The LNG option, you know, based on the production test that we currently have completed, the LNG option is commercial at this point in time.
Okay. Thank you very much.
The next question is from Chen Lin with Lin Asset Management. Please go ahead.
Hi, Charle, congratulations for the good quarter. I did probably missed a little bit. I think a lot of people were asking about El Niño. I know we discussed that last time we were in Bogota. The question is: Right now, you're producing about 185 million cubic feet a day. What's the, like, actual maximum capacity you can provide in term of El Niño? I understand that right now, the 160 is the contract price, that the rest will be at a spot price. Is that correct?
That's correct, Chen. Anything above 160 is essentially offered a spot price. Our current productive capacity at the moment is about 240 million cubic feet per day. Lulo and Lulo-2 should boost that significantly.
Would Lulo, and already in time of this El Niño season, this surge of the natural gas demand?
Lulo is already connected into the Jobo production facility. We're flowing the well as we speak into the Jobo production facility.
Okay, great. Thank you, Charles.
Mm-hmm.
Great. Thank you, Chen. At this point, I'd like to turn the call back over to Carolina Orozco.
Thank you. We have a question from Agustin O'Donoghue from Pinebridge. Can you provide some update on the next option for new thermal capacity? If you can share the strategy and update on timelines. Many thanks.
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 would both be thermal projects very similar to the Tesorito project we're cur rently partnered with Celsia and Proeléctrica on. With respect to the timing, that bid round, bids will be due in mid-August currently. 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. These projects would come online in 2026 or 2027.
Thank you, Charle. We have one more question from Teal Knowles from Schroders. In the light of your strong exploratory activity, if you were to keep the current pace, how many years of exploratory activity will your current portfolio of exploratory licenses last?
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. That's probably, you know, at least 10 years of portfolio on the exploration side.
Thank you, Charles. With this, we don't have any more questions. Thank you all for participating in Canacol's first quarter conference call. We hope you'll have a great day.
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.