Canacol Energy Ltd

Good morning, and welcome to the Canacol’s year end 2021 financial results conference call. This is Carolina Orozco, Vice President of Investor Relations.

I am with Mr. Charle Gamba, President and Chief Executive Officer and Mr.

Jason Bednar, Chief Financial Officer. Before we begin, it’s important to mention that the comments on this call that Canacol 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 cover the operational highlights for the fourth quarter and year end 2021.

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 2022 and beyond.

A Q&A session will follow. Mr.

Charle Gamba is joining us on the line from Bogota and Mr. Bednar is 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, Carolina, and good morning or good afternoon to everyone. Welcome to Canacol’s fourth quarter and year-end 2021 conference call.

In 2021, the corporation achieved several important goals with respect to creating value for our shareholders and other stakeholders, including a 6% increase in realized natural gas sales year-over-year, a 12% return on capital employed and high and stable operating margins averaging 78%. On the exploration front, we drilled three new discoveries at Aguas Vivas, San Marcos and Siku, which at year-end, accounted for 70 Bcf of new 2P reserves.

We also added to our long-term exploration potential through the successful bid on two new large exploration blocks located in the Middle Magdalena Basin, licensing round conducted by the ANH in late 2021. In 2021, we also made an important step forward in our plans to increase gas sales from our core producing area with the execution of a new long-term take-or-pay gas sales contract with EPM.

This contract underpins our Jobo-Medellin pipeline project, which is currently in progress. Importantly, we ensured that we have the financial flexibility to continue executing our plans with the successful refinancing of our debt.

In the fourth quarter, we issued $500 million worth of new bonds due in 2028, so that the majority of our debt is now not due until over 6 years from now. And in the process, we are able to increase our cash on hand and secure lower interest rates than we are previously paying.

In 2021, we continue to deliver on our return of capital to shareholders. In 2020 via our quarterly dividend program with no cut due to the impact of COVID-19 and by buying back shares, the process that we accelerated when attractive opportunities presented themselves as evidenced by our recent purchase of a large block of shares in the market.

I will now turn the presentation over to Jason Bednar, our CFO, who will discuss our fourth quarter financial in more detail. When he is done, I will provide some more detail on the outlook for 2022.

Thank you, Charle. Although the global pandemic made it another challenging year, 2021 was nonetheless a good year financially for Canacol and its stakeholders as we continue to execute our plan to develop our growing natural gas business.

We reported approximately $154 million in adjusted funds from operations for the full year of 2021, a 6% increase from 2020, roughly in line with the 6% increase in sales volumes. Net income of $15 million in 2021 was a complete turnaround from 2020.

In 2020, we reported a large loss due to a non-cash deferred tax charge. These positive financial results allowed us to maintain our quarterly dividend, declaring just under US$30 million to shareholders, applied almost $9 million to the repurchase of shares during 2021 also, which we have accelerated subsequent to year – two year-end with just over $13 million applied to the repurchase and cancellation of shares in recent months during 2022.

Our dividend currently represents an annual yield of approximately 6% with the last quarterly dividend paid in January and the next one due to be paid on April 19, 2022. The resilience and growth in our key financial metrics also allowed us to issue a US$500 million bond, which is how we are able to more than double our holdings of cash and cash equivalents to $139 million at year-end, providing significant financial liquidity as we plan for continued investment and growth in our business.

Looking at our operational results on a quarterly basis, our operating netback was unchanged at $3.59 per Mcf in the 3 months ended December 31, 2021 as compared to the fourth quarter of the same period in 2020, but continue to show recovery from more normal levels from the slight dip we saw during a period of particularly weak gas demand in Colombia in the second quarter of 2021. These results again highlight the stability in high-margin nature of our business.

To further highlight the strength and stability of our business and financial results, we wanted to highlight the return on capital employed implied by financial statements over the last 12 quarters. Our return on capital employed remained high by E&P industry standards at 12% for both the fourth quarter and on average for the full year of 2021.

A significant event in the fourth quarter was our closing of an offering of the US$500 million aggregate principal amounts, bonds of 5.75% senior unsecured notes due in 2028. These new bonds allowed us to refinance our previously outstanding 7.25% senior notes that were due in 2025.

It also allowed us to refinance some other debts and to increase our cash on hand. By replacing the 2025 notes, Canacol will benefit from lower interest rates, deferred maturity and additional liquidity to be used towards capital expenditures.

Notably, leading into the bond refinancing, we received a ratings upgrade from Moody’s to Ba3. And we are able to add S&P at a BB minus rating alongside Fitch, who maintained their BB- with a positive outlook.

These ratings upgrades further highlight the strength of our core gas business. In closing, our Q4 financial results were strong and relatively stable despite the challenges that the coronavirus pandemic continued to present.

And we are now on an increasingly enviable position of financial strength with an ability to maintain a steady return of capital to shareholders and increased flexibility to ramp up investment levels when we think that it makes sense to do so and if operational restrictions don’t prevent us from doing so. At this point, I will hand it back to Charle.

Thank you, everyone.

Thank you, Jason. With respect to the outlook for 2022, we are pretty optimistic for the remainder of the year that we will continue to see demand and related sales volumes and pricing gradually strengthen, 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 reducing our leverage ratios and investing for growth. A brief summary of the six things we are focused on for the remainder of this year.

First, the drilling of up to 12 exploration development wells in a continuous program targeting the 2P reserves replacement ratio of more than 200%. Secondly, the acquisition of 470 square kilometers of 3D seismic on the VIM-5 exploration block to expand the corporation’s prospect inventory.

Third, the purchase of rental facilities equipment and the installation of gas compression to lower OpEx and increased recovery factors, respectively. Fourth, the selection of a contractor for the new gas pipeline from Jobo to Medellin, which will add approximately 100 million cubic feet per day of new gas sales to the interior in late 2024, resulting in Canacol being responsible for 30% of Colombia’s domestic gas play in 2025.

It’s important to note that the pipeline is being designed to expand up to a total capacity of 200 million cubic feet per day with the installation of additional compression subsequent to 2024. With respect to the selection process, we anticipate selecting the final contract to be completed by mid-April.

Fifth, we are continuing to return obviously our capital to shareholders in the form of dividends and share buybacks. And finally, continue with our commitment of strengthening our environmental, social and government strategy.

With respect to current drilling, we are planning to commence something that we have not done in current years this year, which is the drilling of high-impact exploration wells targeting prospective resources in new areas outside of our historical core production area. Of note, the Pola-1 well will test a deep new gas play located in the Middle Magdalena Basin, where any exploration success can be tied in and put on production very quickly, thanks to the current spare capacity in the TGI gas pipeline, which is connected to the interior.

Pola-1 is situated 10 kilometers from that TGI pipeline, which currently has spare capacity of 260 million cubic feet per day allowing us to transmit or to transport any gas we find in Pola directly into the interior markets of Bogota and Cali. Pola-1 is located at the northern end of the play trend where we have secured just over 600,000 acres of land across 5 exploration blocks that we picked up over a 3-year period, including this last licensing round in which we more than doubled our landholding in the area.

Having spent years building this land position, we are excited that we will be testing the play this year, this deep gas play. We expect to have results from the Pola-1 well in the fourth quarter.

I’d like to take the opportunity to thank the entire Canacol team as well as our contractors, partners and clients for their support and hard work during 2021. It’s our team, partners and clients that allow us to continue operating safely, sustainably, reliably and profitably while securing investment for the future.

We are now ready to answer any questions that you might have.

Good morning, Charles and Jason, two questions for me. First one is your guidance has got a pretty big range in it in terms of 2022, your natural gas sales volumes and your EBITDA.

Can you give us a little more color on why is there some economic issues? The El Tesorito is that – is there some delays in that coming on stream?

Or is it related to maybe business climate because of the politics? Can you just maybe shed some color on the wide variance in those numbers?

Yes. I’ll maybe go first just from a high level here.

So historically, the company had only given one set of numbers that we think was the best set, most likely scenario. When COVID hit, obviously, there was abundant uncertainty in 2021 after the COVID pandemic hit approximately March, we then put at that point in time, put out a range related to 2020.

We carried that forward in 2022 – or sorry, 2021 and 2022, where the low end of the range was simply the take-or-pay volumes. So for both – for this year, that number is 160 million cubic feet a day with a price of $4.74 net of transportation.

Obviously, we anticipate doing more than the take-or-pay, but we wanted to let people know just where the absolute baseline would be. The second set, the other goalpost would be what we more actually anticipate doing, which in this year is 200 million cubic feet a day.

And of course, that has adjustments to allow for the interruptible pricing, et cetera, which, of course, would add on approximately 40 million cubic feet a day to the $200 million take-or-pay. So it’s meant to be essentially two goal posts for readers to use.

Okay. And is El Tesorito coming on during Q2 and the volume is starting?

Yes, I’ll hand it over to Charle here.

We’re expecting El Tesorito to enter commissioning in the second quarter. So, that should be generating at the capacity here probably into July after second quarter.

Okay. And my second question is related to CapEx.

You spent $100 million last year. You’ve got a very big program focused on exploration.

And of course, you mentioned the Pola-1 well. When you look at the reserves, you have such a big gap between PDP, 1P and 2P.

Is there going to be an increase in the amount of drilling to move 1P to PDP and 2P to 1P because there is such a large gap there? But of course, that has a big impact on your NAV and also your deliverability and ROIs.

Yes. We do have four out of the 12 wells we’re drilling this year are development wells, specifically targeted at moving 2P to 1P.

For example, the Chirimia-1 side track that we’re currently drilling right now will be directly along that type of vein as well. So yes, part of our drilling program and our workover programs this year are aimed at exactly that migration of reserve category.

And the CapEx budget for this year, 2022?

I think we’re outlooking our guidance was up to $190 million, basically. So fairly hefty budget game that primarily exploration.

The Pola-1 well, in particular, Josef, is a very deep test, 18,000, 19,000 feet measured depth. So we’re looking at a drill and complete cost of up to $30 million.

So much more expensive than our traditional wells, but 10x the reserve potential or the resource potential of our typical targets.

Wonderful. That’s it for me.

Thanks very much for taking my questions.

Thanks, Josef.

Hi, Charle. Hi, Jason.

How are you? Thanks for taking my question.

One, I noticed that your spot cell seems to be – have a pretty high price and – but it’s – it just come and go. Can you – do you have any expectation of the spot natural gas sales this year?

Yes, Chen. Good to hear from you.

Spot pricing – spot volumes have been relatively good this year compared to last year in the first quarter so far. So we’re very pleased about that.

The market is relatively tight in terms of supply. There is really only echo patrol competing with our production.

So we’re seeing a natural tendency towards higher spot pricing this year than last year. For example, I would say our average spot prices in 2021 averaged around $360, $370 million.

And we’re seeing spot pricing now well over 450, 460. So that simply reflects two components: an increase in the demand as the economy recovers post COVID; and secondly, a reflection of the tight fundamentals of supply and demand.

Okay, great. Thank you.

Just – can you comment a little bit about your stock price? In the past few years, it’s a very good story, and you have a lot of success in exploration and development and doing a lot of share buyback, which I’m paying dividend, which shareholders appreciate, but it just doesn’t catching the win of the energy boom recently?

I think Jason can provide some color on that.

Yes. I mean that’s always a difficult one.

We’ve been relatively flat for several years here. It’s also been several years since the last expansion of the Medellin pipeline came on.

Obviously, the pandemic has created some uncertainty with respect to interruptible demand and hence, the range that we gave in our guidance press release. Obviously, we’re actively working on the Medellin pipeline project and things that provide a very large step change to our production as well as some of the things that backfill incremental steps until Medellin is online.

Those things are things such as Tesorito. So we’re hopeful that the share price will respond in due course.

Okay, great. Thank you.

My final question is you have some shale value opportunity, if I remember correctly. Do you have any plan for this year or the next in the near-term?

Yes, you are quite correct. We do hold interest in two non-conventional shale blocks basically with ConocoPhillips.

And we’re really just waiting to see the results of the drilling pilots that Exxon and Ecopetrol are going to conduct next year to test the commercial viability of that resource. So we’re sort of just sitting and waiting on those results to come out.

And if they are successful, hopefully, that’s something we could develop in the mid to long-term, but no plans this year or next.

Okay. Do you know when their results will come up?

They are planning to execute the horizontal fracking pilots next year. That’s Ecopetrol with their partners, Exxon, on their two pilots that they are going to be executing very close to our blocks with ConocoPhillips.

So I expect that we should see results from those probably second half of next year.

Okay. Great.

Thank you. Thanks for taking my question.

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

I had a question regarding your drilling program. Per your last update, you were – you mentioned that the Carambolo-1 well I wasn’t clear whether it was unsuccessful or not, what was the status there?

And it was initially planned to go to Arandala-3, and I understand that now you will be moving to Chirimia-1 sidetrack. So just to understand what drove that change in planning and the actual results from Carambolo-1 well, that would be great.

Thank you.

Thanks, Oriana. Yes, Carambolo-1 encountered about a 67-foot thick gas column in the mid Porkero target.

So we are currently preparing to complete and test that well. And if it’s commercial, we will bring it on to production.

With respect to the Arandala well, we’ve delayed the drilling of that well due to some issues we’ve had surface issues there and some community issues. So we’ve sent the rig instead to the Chirimia-1 location to sidetrack that well, which is something that’s relatively easy to do, and we will reschedule Arandala later in the drilling program this year.

Thank you. And if I may, just a follow-up regarding – I believe last month, we heard some comments about the possibility of Canacol entering Bolivia and that interest.

So just to understand what are your view – what is your view regarding this? And if there is any comment you could share with us regarding the Bolivia?

Thank you.

Sure, of course. Yes, we maintain a very active interest in assessing gas opportunities, gas exploration and production opportunities, both inside and outside of Colombia.

So we have been working on various opportunities, including some opportunities in Bolivia, where we see the potential to try and achieve something of the scale that we’ve achieved here in Colombia in a jurisdiction located outside of Colombia. So yes, we have been looking at Bolivia for the past 2 or 3 years.

We have not executed any contracts at the moment, but we have been looking at various gas opportunities, exploration opportunities and some production opportunities located outside of Colombia and Bolivia would be one of those.

Great. That’s helpful.

Thank you very much.

Thank you. The first question comes from Carlos [indiscernible].

He is asking what was behind the decrease of reserves in absolute terms?

Yes, two factors. Essentially, historically, we’ve maintained a 200% reserve replacement ratio on a 2P basis, primarily through our successful exploration drilling programs.

Last year, we were scheduling to drill nine exploration wells in our program. We were only able to drill 6 of those exploration wells for various issues we encountered in the field.

So, we only drilled 66% of our exploration portfolio instead of the full 100%, the full 9 wells. Of those 6 wells, 3 were discoveries, very good discoveries that added 70 Bcf in total and 3 were dry holes.

So, the 3 good wells we did drill had a very good addition with respect to 2P reserves, but three of the wells were dry holes, and we did not drill the other three that we were planning to drill. So, the reserves adds from exploration were a little less than expected.

Also, we had a negative revision of 34 Bcf associated with our producing fields. That’s a fairly large revision.

It’s not unusual. In 2016, we also experienced a negative revision of around 7 Bcf on a 2P reserve.

So typically, technical revisions generally are positive, but last year turned out to be somewhat negative. So, those two factors, lack of executing our full exploration program as well as some technical revisions resulted in relatively light reserve adds for last year.

And those – we are planning to correct that this year, obviously, with an expiration with a drilling program focused on exploration, including some very large targets, much larger than we normally drill.

Thank you, Charle. The next question is from Oscar Gisi from Cassara Management.

Any updates on Jobo-Medellin, who will build it, any new contracts other than the EPM 1 is Promigas off the table?

Yes. So, with respect to Jobo-Medellin, we have been very busy on a number of fronts of that project, of course.

We have received bids, final binding bids from four international pipeline construction companies. So, we are currently analyzing those bids, and we are preparing to finalize the contractor selection, as I mentioned, a little easier – a little earlier, I should say, by mid-April.

On the gas sales contracts, we are also negotiating additional sales contracts for the remaining 45 million cubic feet per day of capacity in that pipeline. So, we are currently negotiating a new contract, a 10-year contract for 20 million cubic feet per day off-take to a gas distribution company.

And we are negotiating with two other gas distribution companies, one in Bogotá, and one in Cali with respect to the remaining capacity. So, the intention is that by midyear, midyear or Q3, we will have the full 100 million cubic feet per day of transportation capacity fully assigned to long-term take-or-pay contracts.

The next question is from Mario Beaulieu. Can you please elaborate on any further sales or in contract negotiations with respect to the Medellin pipeline volumes?

Well, I believe you just responded to that one as well, right, Charle?

That would be correct.

Okay. Now operator, I think we have another question – live question in the line.

Hi everyone and thanks for taking my questions. The first one on expenses, you mentioned that operating expenses increased in the quarter due to higher labor costs, rental and some maintenance costs.

Could you provide a little more details on that? And the reason why we are asking that is do the global inflation we have experienced.

Are there any relations with that? And should current levels of expenses be sustained in the upcoming years, or are there possibilities to reduce it?

My second question regarding capital allocation. I know we have discussed that broadly, but trying to discuss a little bit further company has a solid dividend policy, the buyback program and still continue investing some exploratory campaigns – but looking maybe 2 years or 3 years or even 4 years ahead, what would you say to be the priority for the company in terms of capital allocation?

Are there any possibilities to increase dividend, increase buybacks, accelerating investments. In addition on that question, what is the company’s view in terms of balancing company’s liquidity in the capital markets with these buyback programs?

Those would be my two questions. Thank you.

Yes. I think I can answer the bulk of that.

So, Q4 saw operating costs escalate to $0.35 in Mcf, what is historically had been around $0.30 in the first three quarters around $0.26. That increase is pretty much solely related to some routine well maintenance work we did in Q4.

Part of that was some field delays. Part of it was the opportunity to get efficiencies by doing it all at once.

That maintenance work in Q4 amounted to about $2.4 million, which adjusted on an Mcf basis was about $0.14. So, if you remove that, we would be in the low-20s.

Looking forward into 2022, our budget is a very typical – although detailed, the end result is a very typical $0.30 per Mcf for operating costs in 2022. Moving on to the capital allocation question, let’s start with dividends.

Our dividend rate at this point in time is a very healthy 6% or low-6%. It takes up about $30 million of capital every year.

We are clearly focused on the Medellin pipeline and growing our reserve base and productive capacity for it to be ready for the Medellin pipeline to be commissioned. So, my expectation over the next couple of years is that the dividend would not be increased.

Of course, that’s subject to change, but that’s the current expectation. Once Medellin pipeline comes on at 100 million cubic feet a day given the assumed netbacks and transportation, that adds approximately $150 million of EBITDA at that point in time.

And of course, at that point in time, we could look at raising the dividend. I believe you also touched on share buybacks.

We are quite active in 2021. For the first year, really a meaningful size of $9 million in 2021.

And in 2022, we did that block purchase in January for another $13 million. So, we will continue to be active when the opportunity presents itself in terms of us feeling that the current market value is undervalued with – in relation to our reserve base or the company value.

We received the question from Sebastian Cojante from BP Capital. When do you expect to draw the remaining $50 million of the bridge term loan?

Yes. So, I am sure as everyone is aware, we are working with various potential ECP contractors or BOOM contractors, the funding, etcetera.

And to refresh everyone’s memory, that bridge loan was put in place in order to support the Medellin pipeline activities before the ultimate owner of it was chosen, right. So, when we took it out about 1.5 years ago, we drew the first $25 million.

We are contractually due to draw that, and that will last us through things like the environmental permitting process, etcetera. The next $50 million was scheduled to by long lead time items such as preorder some of the pipe, etcetera.

Now, logically, depending on who the ultimate contractor is or BOOM contractor, etcetera, and the shape of that contract in terms of the conditions precedent, etcetera, that will play the largest portion in dictating when we draw that $50 million.

Thanks Jason. We have one last question from Nicolas Manos from Ingelsson Schneider.

Do you anticipate taking an equity interest in the new pipeline?

Yes. Thanks, Nicolas.

No, we have no intention at the moment of taking any interest in the new pipeline. The contracts that we have or the offers that we have received are all of a BOOM nature, build, own, operate and maintain on the part of the contractor.

The rationale there, of course, is that with respect to allocation of capital. The return on our capital is much greater investing in exploration projects with margins up to 78% than in pipeline projects with returns of 12% to 14%.

And so the offers we have received to-date have all been BOOM type offers.

Thank you, Charle. We don’t have any more questions.

So with this, we conclude our conference call. Thank you all for participating and hope to meet you again during the next conference call for the next quarter.

Thanks, everyone.