Canacol Energy Ltd

Good morning. And welcome to Canacol First Quarter 2022 Financial Results Conference Call.

This is Carolina Orozco, Vice President of Investor Relations. I am with Mr.

Charle Gamba, President and Chief. Officer, Mr.

Mark Teare, Senior Vice President of Exploration, and Mr. Jason Bednar, Chief Financial Officer.

Before we begin, it's important to mention that the comments on this call that Canacol senior management's coming through projections of the corporation's future performance. These projections neither constitute any commitment as to future results nor take into account risks or ensure agencies 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.

Mark Teare, Senior Vice President of Exploration, will then discuss some of our exploration plans and new perspective resources estimates that we announced in April. Mr.

Gamba will close with a discussion of the corporation's outlook for the remainder of 2022. At the end, we will have a Q&A session.

Charle is joining us on the line from Bogota, and Jason and Mark are joining us on the line from Calgary. I will now turn the call over to Mr.

Charle Gamba, President and CEO of Canacol Energy.

Thanks, Julia. Good morning or good afternoon and welcome to Canacol's First Quarter 2022 Conference Call.

In the fourth -- in the first quarter of 2022, we realized natural gas sales of 182 million standard cubic feet per day, which is above the midpoint of our annual guidance of 162 million cubic center feet per day. What we've seen so far this year in the Colombian gas market, is it the Colombian economy and as a result of the climbing gas markets appear set to start growing again as we enter a post-pandemic fees, even though we've also seen relatively high rainfall levels which will provide ample hydroelectric generation capacity.

Our stable production operating conditions allows us to report another quarter with high operating margins of 77% and relatively high return on capital employed of 19% annualized for the quarter. We continue to progress key growth projects including the hobo demeaning pipeline project, which at the end of the quarter was declared a project of strategic national interest by the Government, Colombia.

And we continue to return capital shareholders through dividends and share buybacks, including a significant block purchase of over 5 million shares in late January. As a result of which the total number of shares outstanding declined by just over 3% during the quarter.

That's going to the first quarter, we announced new prospective resources assessments with total risk main prospective resources over 7. 6 trillion cubic feet intervention place in both the lower Magdalena valley, as well as new deep play we're pursuing in the Middle Magdalena valley.

As Carolina already indicated, our Senior Vice President, exploration markets here to discuss these resource estimates and our exploration plans after we finish discussing our first-quarter results. I'll now turn the presentation to Jason Bednar, our CFO, who'll discuss our first quarter financials in more detail.

Thanks, Charle. We continue to execute our plan to develop our natural gas business in the first quarter of 2022.

Our operating netback was $3.58 per Mcf in the first three months ended March 31st, 2022, which is 7% higher than in the same period of 2021, virtually unchanged from the prior quarter and very close to our guidance for 360 on average for 2022. Our realized gas price of $4.66 was also very much in line with our guidance for the year of $4.61 to $4.74 per Mcf.

Recall that the majority of our guidance is based on sales under fixed price take-or-pay contracts with an average fixed price of $4.74 per Mcf. OpEx of $0.36 per Mcf was slightly higher than the prior quarter and up 29% on the same quarter last year.

Higher OpEx in both the first quarter of 2022 and the fourth quarter of 2021 was caused by relatively high levels of maintenance work being carried out, which we don't expect to persist through the remainder of 2022. That said, as you like, we already know, consumer price inflation has been running in the high single-digits recently, so higher than it was in recent years, and that means OpEx won't be quite as low going forward as it was in previous years, even when we're not doing any maintenance work.

In percentage terms, our gas royalties were 15.5% of gross revenue, which is in line with the average for the preceding two years, so hopefully roughly in line with everyone's expectations. To further highlight the strength and stability of our natural gas business, as well as growth that we see in our business and financial results, we want to again highlight the return on capital employed implied by our financial statements over the last 13 quarters, which was 19% for the first quarter of 2022.

We reported the falling for the first quarter of 2022. $66 million of production revenues, net of royalties and transportation which represents an 11% increase from Q1 of 2021.

The increase was driven by the combination of higher volumes and a higher realized price per MCF. We also reported $34 million in adjusted funds from operations, which represents an 11% decrease from the same period in 2021.

And we reported EBITDA acts of $50 million, which represents a 6% increase from the same period in 2021. Finally, net income of $24 million when we reported a small network in the same period of 2021.

To explain the different movements in some of these measures relative to the same quarter a year ago, a big driver of our net income each quarter relates to the Colombian peso strength or weakness during the period as compared to the U.S. dollar, which of course is our reporting currency.

This impacts the valuation of our tax boules, which are in Colombian pesos. In the first quarter of this year, we recorded inferred tax recovery of $12 million, while we reported an $11 million non-cash deferred tax expense in the same period a year ago.

This time last year, I said that the latter was primarily due to the effect of the reduction in the Colombian peso exchange rates on the value of unused tax losses and cost pools. And that in the event the peso strengthens against the US dollar in the future, the corporation would realize in deferred income tax recovery for the period.

This is exactly what has now happened. And those two numbers alone account for the vast majority of the change in net income relative to a same period a year ago.

While EBITDA was up 6% year-over-year, funds from operations saw a decrease of $4.3 million in Q1 as compared to Q1 of 2021, which can be solely attributed to a $7.5 million increasing in cash taxes. In the first quarter of last year, we had lower revenues.

We had some unrealized foreign exchange losses, and one-off exploration well expense related to an unsuccessful well. Which is why our cash taxes being relatively low in the first quarter last year, and the opposite occurred in the first quarter of this year, which is why our cash taxes were relatively high this quarter.

The 4% increase in the Colombian corporate income tax rate to 35% from the start of 2022 also contributed slightly to the increased cash taxes. Obviously, cash taxes are an important part of our financial performance but we hope everyone recognizes that most of the quarterly fluctuations are driven by things that are either one-offs or likely to reverse from quarter-to-quarter.

In terms of guidance on this topic going forward, we expect our effective tax rate under the current tax regime to be in the range of 25% to 28% of EBITA. That concludes my comments on our first quarter financial results.

I will now turn the presentation over to Mark Teare Senior Vice President of Gas exploration.

Thank you Jason, On April 6, we provided a new resource estimate for our Gas exploration blocks in the lower and Middle Magdalena Valley Basin. Assuming an un -risked mean perspective results potential of 20.5 trillion cubic feet at Canacol and a risks mean prospective resource of over 7.6 trillion cubic feet, estimated by brewery global energy consultants in the orders head report effective December 31st, 2021 that represents an increase of over 300% in risks, mean perspective resource over the last resource report.

We continue to see large and relatively unchanged exploration potential in the lower Magdalena valley Basin, where our core producing operations are located. To quantify that statement, our updated resources evaluation estimated 3.2 TCF gross on risks, a 986 Bcf risks gross mean perspective resource for relatively shallow prospects and lead the vast majority of which are in the lower Magdalena valley.

We plan to continue testing that resource potential and converting it to reserves with the drilling in the CNR good ARO import carrier play fairways, where our experience and expertise allows us to report an exploration drilling success rate around 80%. Perhaps such as important drilling in the lower Magdalena Valley base.

And we will be acquiring new seismic on the large VIM-5 block this year to a north of our core producing fields. We anticipate new 3D seismic will allow us to material exploration leads to prospects and to continued drilling prospects for the high rates of drilling success.

Once our interpretation of the seismic has allowed us to further refine our resource evaluations for our low Magdalena value blocks. The large growth in total perspective results from previous years is due to increased estimates for our exploration blocks in the Middle Magdalena valley basin.

Thanks to the technical work we have been doing to refine our understanding of these blocks, as well as being awarded two large new blocks from the ANH late last year. These two blocks, VMM 53 and VMM 10 - 1 are on trend with the new deep conventional gas play we have identified and plan to investigate starting with the drilling of the Pola-1 exploration well this year.

In order to provide an indication of this pleased potential, we announced unrest and risk mean perspective resource estimates 17.3 TCF and 6.6 TCF respectively. For prospects and leads in the deep conventional gas play, in the Middle Magdalena Valley Basin.

In the press release on April 11th, we also announced perspective resource estimate for just the Pola prospect of 1.2 TCF unrest, and 470 Bcf risk. We don't usually provide resource estimates for individual prospects and we don't expect that to change going forward.

But in this case, we wanted to show that the first prospect we will be drilling this year in this play has significant potential. Of course, you have to highlight that this is exploration.

It's always carries significant risks and uncertainties. [Indiscernible] have commercial success at Pola-1 across the whole play that is implied by the resource estimates we disclosed is around 40%.

It's very attractive with tasks given the size of the resources we are targeting. We plan to spot the Pola -1 well in August this year, and it will take approximately 3 1/2 months to drill, and a total of five months to drill, test, and complete.

Therefore, we will be expecting results by the end of 2022 or early in 2023. It's also worth highlighting that our plan for polar anticipate drilling to depth of more than 17,000 feet, making this the deepest conventional natural gas well we have ever drilled.

We anticipate having to manage high temperatures and pressures during drilling as well as during any subsequent operations. That said, there is nothing in our plans for this play that is not a standard operation, but the global oil and gas industry has regularly managed for decades.

We believe Canacol was uniquely positioned to identify this place potential. Thanks to our history of operations in the Middle Magdalena Valley Basin, our experience in the Colombian gas market, and our team's broad international experience.

We're also confident we have the expertise to test it and potentially develop any commercial discoveries we might be able to make. As you can see, all of our blocks in the Middle Magdalena Valley Basin are located relatively close to the existing TGI gas pipeline, which has significant spare capacity.

We are optimistic about this deep conventional gas play and excited to be drilling our first high-impact exploration well here. But it's important to emphasize Pola 's only one of 18 targets we have identified on blocks in this play.

In total, we have 178 prospects and leads identified across all our plays in the two bases. This number could increase since we acquired and evaluate new seismic.

Pola is also only one of us for AidEx for eastern wells, we plan to drill this year. With all other planned wells being in the low Magdalena valley.

While we started this year with a discovery in the Poquero fairway at Carambolo, it is unlikely that we will be successful with every well we drill. However, we do expect to continue to see our exploration programs deliver on transferring prospective resources into reserves, and ultimately production and cash flow in a cost-efficient manner, utilizing our unique expertise experienced, and access to data and technology.

Thank you for your attention. I'll now hand it back to Charle.

Thanks for that, Mark. Our quarterly results once again demonstrated high and stable operating margins, as well as a very respectable return on capital employed.

For the remainder of the year, we anticipate production and cash flow to be near our high guidance rather than the low end of the range, which is simply based on our 2022 take-or-pay contracts which averaged 160 million standard cubic feet per day. We also anticipate that our CapEx spending will come in at around $172 million, as we've been contracting services and equipment at long-term at very reasonable rates.

Practical significance of the national strategic importance that the Medillin pipeline project has been granted by the Colombian government, is that the designation should drastically improve the timing of delivery of items critical to the project, including the issuance of the environmental license. We have received binding offers from four international pipeline construction consortiums, which are currently under evaluation, and we are negotiating an additional long-term take-or-pay gas sales contracts with clients located in interior of Colombia to fill the remaining 46 million standard cubic feet per day of initial capacity of the pipeline, which is -- will be 100 million cubic feet.

Our exploration drilling program will accelerate in the short term and through the second half of the year, as we have now contracted a second drilling rig and we'll be drilling both the Alboka and Cornamusa exploration wells in the Lower Magdalena Valley in parallel, where we have three higher impact exploration wells planned for later in the year, including the Pola-1 well in the Middle Magdalena valley which Mark just referenced. In summary, we expect to continue delivering financial results within our previously stated guidance, allowing us to proceed with both returning capital to shareholders and also investing for growth, operating from a position of financial strength.

We're now ready to take any questions.

Hi. Good morning, everyone.

Matteus Insulet from UBS. Thanks for taking my questions in for the thorough update on exploratory operations, much appreciated.

My first question is on that very same topic. I mean, looking to the mid to long-term perspective as a company, anticipates to increase production in the context of the new pipeline NDP and contracts.

We do view that there's additional production to come from new exploration. Our question on that sense is we would like to see what the company's sees as risks on top of the regular, let's call it like that.

The regular exploratory risks for these assets in developments, whether the risks that calls were unable to achieve production as scheduled for the contracts. And on the other hand, if you are able to achieve production ahead of the start of the weekend contract is there, is potential for sufficient spot demand to demand for this new production?

That's my first question. My first [Indiscernible] of questions.

And then the second question that we have still on the additional volumes, if you could provide any updates on how are negotiations for, the additional volume for the pipeline other than the -- other than the EPM contract. Thank you.

I'll take a crack at the both questions here. Now, with respect to our production, future production expectations, and as it relates to our exploration programs.

The Medillin pipeline, when it comes on stream at the end of 2024, we'll add an additional 100 million cubic feet per day of production sales to the company. So we expect that in 2025, average production will be sort of in the 320 million to 340 million cubic feet per day range, which can be supported by our existing reserve base and the assumption that we will continue to successfully add reserves through our exploration drilling programs.

As Mark highlighted, we do have over 170 exploration prospects identified, the majority of those being in the Lower Magdalena Valley, which the new pipeline will be connected to, as well as in the Middle Magdalena Valley. So we're quite confidence with our current base 2P reserves and our risk perspective resource we've identified on the acreage that we operate.

And we are able to continue to replace reserves and grow our reserve base to sustain those levels of production, sales in 2025. With respect to risks, other risks, Side from exploration and development, there are up political risks.

We are in the midst of an election year here, which results to be decided by the end of June. And there are some risks with respect to the Oil and Gas Business should there be any change with respect to regulatory or community type issues associated with the oil and gas operation.

But we view those risks as relatively minor and risks that we can easily absorb. With respect to your second question, additional volumes for the pipeline as, as I mentioned here we filled plus 55% of the initial volume of the pipeline, initial 100 million cubic feet EPM contract.

And we are currently negotiating three additional contracts which will effectively fill the remaining 45 million cubic feet per day. We expect to achieve that by mid-summer, July-August of this year.

And those are all with very large distributors located in the interior of the country.

Thank you very much and congrats on the quarter.

Hi, thanks for taking my question. This is Oriana with Balanz.

I had three questions. I don't know if we can go one-by-one, but perhaps linking on with the previous question in terms of production.

Can you confirm like which of this four wells were drilled during the quarter? And I've been tracking your monthly operational updates and it seems that production keeps on decreasing.

So when can we see higher production coming from these new development wells that you drilled during the first quarter? That would be my first one.

[Indiscernible] our production is really not -- not necessarily limited by the capacity or productive capacity of the wells. Our production is limited by demand.

So it's not like every new well we drill increases our production -- our production sales I should say. Every new well we drill increases our productive capacity to produce gas.

But the real driver on production is actually sales, of course, so we're selling into a market that's relatively stable. It can only absorb so much gas.

And we're meeting those commitments with respect to that. So it's not like an oil well where you drill an oil well and you immediately put the oil into a truck and sell it into a pipeline.

We're selling the gas directly through consumers and there's only so much gas that the market can absorb, so to speak.

Great. That's clear and perhaps moving on into a different area.

Like if we're not mistaken this transmit tunnel pipe connecting, managing to the TDI backbone would need to be made reversible. Just thinking of future projects that you would flow in both there for Canacol to sales volumes in well with die and Medillin.

For now, gas flows are already flowing in direction from the TDI pipes towards Medillin. So just to understand, just to make sure that we're getting this correctly and if we are, who will pay for making this translates to transmit bi-directional Canacol or the owner.

That was one of the questions that we had.

That with respect to the directionality of transmit condo. So we actually, when our pipeline is connected, our new pipeline connects to city gauge of Medillin.

Essentially, all of Medillin's demand will be met by our pipeline, so there will be basically no need for transplant tunnel to continue shipping gas from east west to the city of Medillin. And the way that the reversal of that pipeline occurs is that the clients that we are negotiating with the remaining 45 million of capacity, are all located within Bogota and Cali.

So they -- those clients will sign a transportation agreement with Transmit Tunnel, whereby Transmit Tunnel will reverse their pipeline, bringing the gas that we're selling to those clients, that those clients are buying from Meding to Bogota and Cali. Yeah, so they will essentially sign with Transmit Tunnel a shipping agreement -- a transportation agreement whereby transmit Tanner will invest in the bi - directionality of the pipeline.

They'll reverse the [Indiscernible], which is a relatively simple operation. You simply have to swing the compression stations around 180 degrees basically.

So that was in the opposite direction. But the bottom line is that the reversal of the transmit Tanner will be -- be executed via the new gas sales agreements.

The gas off-take agreements we will sign with clients in Bogota and Cali.

Perfect. That's very clear.

And just one last one regarding with El Tesorito just to confirm, is it already commissioned or at least burning gas in test mode? And if so, how many land cubic feet per day are you expecting it to bring to a top-line now that were closer to the start?

As retail commission was delayed from April until July. So we expect that commissioning will start in the month of July, and that will consume up to 40 million cubic feet per day of gas during the commissioning.

And then we expect Tesorito will be generating between 25% to 50% capacity, which will be essentially between 10 and 20 million cubic feet per day of sales

Perfect. That was all from my side, thanks for taking my questions.

Good morning, everyone, and thanks for taking my calls and thanks for the -- Mark, for the full details and update on the drilling and the size of the prices on the geological side, I'll look forward to talking to you more about that. My first question is probably for Jason.

You bought that $5.31 million shares in January 248 a share U.S. 323 or so Canadian, are you in a blackout period now or is the NCIB still active?

What's going on there? Especially given how the stock as weakened in the last few weeks.

Yeah. I mean, we are in a blackout period having said that there are certain allowances that you could put in your orders ahead of the blackout, just be hands off, but we chose not to do that this quarter.

I see a couple of questions coming in with respect to buybacks and why we haven't been active. So I will just sort of given more fulsome answer to your question.

We did buy obviously that $13 million use of stock this year in January, significantly more than the 8.7 we did all in all of 2021. We have the ability and cash to buy more.

But we've chosen not to at this point in time, and we'll play that by year as we move forward.

Okay. So going on the weakness of the stock, are we looking at the reasons more on the political side, given the concern that the leading candidate, Pedro and his running mate, which is considered -- quite left us sort of some of the art articles, is that what you think might be also weighing on the stock?

Correct. After many investigative calls to people like yourself, that appears to be the reason.

I mean, our operations are stable quarter-over-quarter. The only rational explanation is the election.

And last one for me. When -- you've talked about having four companies with with final binding bids to build the Hobo Medellin pipeline.

What's the process for reviewing them? What are the critical points you are looking for to make that final decision of who wins the contract?

Just to get an idea of the scope of those kinds of issues.

The contracts we've received are all BOOM contracts; build own operate, and maintain, whereby Canacol will not make any investment whatsoever ultimately in the pipeline. So our driver is transportation tariff.

The contractor will build the pipeline and invest in the pipeline and they expect a return on their capital of something 14% or 15% IRR. And our concern is what the resulting transportation tariff they offered us was.

So all we care about is how much it costs to transport a molecule of gas from Hobo to Medellin. And obviously, the lower the transportation tariff, the higher we can net off the gas, basically.

So that is the sole criteria. All of them are technically qualified, all our international operators, all are very well financed.

The driver is transportation tariff.

And Charles, when do you think a decision will be made? When -- what's the window that we should be looking for something to potentially come out?

We expect to make the final decision within the next two months.

That's it for me. Thanks very much.

Hi, Charle, thank you for taking my questions. Some of my question has been answered.

I just wanted to just confirmed what Jason has said, that it seems like the [Indiscernible] for this year of share buyback is the mostly gone, is that correct? assessment there has the wait for next year for most share buyback?

We have ample cash on hand and expect the end the year with Apple cash-on-hand. Excuse me, but it this time we are not buying shares recently obviously, but that does not mean that we will not accelerate our share buyback program in the coming months.

Okay, great. That's reassuring, thank you.

And also just on your -- do you see the drilling costs escalate due to inflation in the recent month or in the path year?

Drilling costs are definitely escalating, however, all of our drilling and service contracts, our long-term contracts that were all renegotiate last year. So we have a fairly good buffer with respect to escalation associated with drilling and associated services.

Okay. Great.

How long are those contracts?

We negotiated in July of last year and the contracts are two to three years in life.

Okay. That's very good.

Thank you. So in terms of inflation, the natural gas hit $8 last week in the United States.

Do you see any more negotiating power for future contract and then renewing the existing contracts?

What's important to keep in mind that Colombia's a closed market. No gas is exported out of Colombia.

And very, very little in the way of LNG is important to Colombia. So Colombia is completely disconnected from the external market, which is great.

For the past 10 years’ Colombian gas prices have been double WTI, a 100% higher than WTI on average. And now they're lower, so it's just the fact of life that the gas market in Colombia here is super stable, and with no inflation with respect to external natural gas pricing.

Okay. Great.

So you should be trading like a utility company.

Yes, indeed.

Very stable income and just [Indiscernible] somehow is still vary with GAP pricing. Thank you for taking my question.

As I mentioned earlier, the contracts that will be a boom contract, build, own, operate, and maintain. We've already submitted binding offers, so any inflationary pressure is borne by the construction consortium and not less.

I already answered that one.

We anticipate the started construction to occur in July of 2023.

I can probably take that Sheryl. So I think Sheryl earlier in his discussion said that we expect to be near the low end of that 172 with respect to how that plays out for the remainder of the year.

Q1 was slightly lower. We drilled the last well than anticipated, having said that moving forward, we expect to drill three to four wells in each of Q2, Q3, Q4.

So we expect the CapEx to be relatively even amongst the remaining three quarters.

I think Mark Teare can address that.

So I'll take that. Technically the main risk as we see it as encountering enhanced permeability development.

On 3D seismic, we've used coherence and coverage processing to derive size the cash refutes that predictive of Fulton fracture intensity. And so aligned with our understanding of the structural framework of the prospect that we're drilling.

The well will target these areas of enhanced effective reservoir. Which we anticipate to includes proximity to the large-scale faulting that we see on seismic we're targeting with the well.

So we expect the environmental permit to come out prior to July of 2023, which time construction will start. I don't quite understand the test; could you repeat El Tesorito question?

I already answered that, yeah.

I can probably answer that. So with a little bit of foresight, as you recall, in November, about five months ago, we redid our bond, right?

So the overrate was at 7.25%, our d-rate is 5.75%. So we were actually saving money, if you will, in terms of interest, which is a very large financial expense.

Charle already answered the CapEx questions on this topic with regard to locking in service contracts in tubulars, etc. for the foreseeable future.

And I'll just touch briefly on operating costs, although I did deal with it at a high level earlier, right? So our guidance has always been for the last several years that our OpEx would be roughly $0.30 an MCF.

We've had quarters last year that were a few cents lower than that. And of course, this quarter was higher, right?

But just in perspective, right? An 8% increase on $0.30 as roughly 2.5 cents.

And if you apply that to 180 million cubic feet a day like this quarter, that increases $400 thousand at quarter, right? So even when we look at some of the maintenance work which was probably responsible for $0.05 increase in OpEx,

and we do not expect to see that moving forward, that translates to only $800,000 a quarter. So it's somewhat deminomous on $50 million of EBITDA a quarter.

Thanks, Jason. I believe we have one more question from Oriana from Balanz.

Operator, can you please go ahead.

Hi. Thanks.

Just had a quick follow-up with regards to your drilling plans. You were mentioned that -- you were mentioning that you expect to drill about three to four wells per quarter with CapEx fairly stable.

So how should we think of the Pola-1 and the other two wells that are from these deep conventional play following in since they are expect it to be higher-cost? Just wanted to confirm that.

Thanks.

Good point. I believe we're, unless Mark corrects me here, we're scheduled to spot Pola in August.

You're correct, that is a higher-cost well. So Q3 and while it's drilling through half of Q3 and all of Q4, those two quarters would be higher weighted CapEx than Q2.

You are quite correct.

Great. Thank you.

Hi, got one questions related with the buybacks program. Could you repeat if you're expecting to make more share buybacks in 2022?

Thank you.

Yeah, we have the cash ability to do so, whether its current cash on hand or expected cash come year-end. I would anticipate us making more buybacks during 2022, but the timing as to how much in when is not yet decided.

Once again, for perspective, we did 13 million in Q1, we did 8.7 million in total for all of 2021. And I will remind everyone that our current dividend of 5.2 Canadian a quarter represents roughly 8% dividend yield at this price.

So there is ample shareholder returns already in the mix.