Canacol Energy Ltd

Good morning, and welcome to Canacol's Third Quarter 2020 Financial Results Conference Call. 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 by Canacol's senior management team 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 third quarter 2020. 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 fiscal year 2020 and beyond. A Q&A session will follow.

Mr. Gamba is joining us today from the line in Bogotá 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.

Thank you, Carolina. Good morning, and welcome to Canacol's third quarter 2020 conference call.

Cash sales during Q3 were 163 million standard cubic feet per day, a 7% increase from the second quarter of 2020, and an 11% increase from the same period in 2019. Revenues during Q3 were US$57.4 million, a 1% increase from the same period last year.

Realized gas sales have been recovering from a low point of 136 million standard cubic feet per day in April to 168 million standard cubic feet per day in September of this year, and 173 million standard cubic feet per day in October of this year as demand is recovering after the country-wide lockdown related to the COVID virus. Production operations during the third quarter ran smoothly with no major interruptions drilling operations, which have been completely suspended from March 26 to May 27 due of course to the nationwide lockdown were ramped up in the third quarter with a secondary commencing drilling operations in July.

The second rig's, first job was to drill our first significant exploration well in our 2020 drilling program. And in early September, we announced a new gas discovery with the Porro Norte-1 well.

As announced in August in a major store of confidence in the stability of Canacol's business model, our syndicated lenders extended our existing $30 million term debt facility at an approximately 2% lower interest rate than before, and expanded as a further $121 million in new low interest term and revolving credit during a period when many oil and gas producers had their borrowing base is re-determined and lowered. Finally during the quarter, we continued to deliver on our return of capital to shareholders via the continuation of our quarterly dividend with no cut-to-yield.

In September, we also started actively buying back shares under the previously announced normal course issuer bid. I'll now turn the presentation over to Jason Bednar our CFO, who will discuss our second quarter financials -- our third quarter financials, I should say in more detail.

When he is done, I'll provide a detailed outlook for the remainder of 2020.

Thanks, Charle. Although impacted by the global pandemic, Q3 2020 was another strong quarter for Canacol, both operationally and financially, as we continue to execute our plan and drive our growing natural gas business forward.

Focusing on the third quarter of 2020, financial highlights include: revenues increasing very slightly by 1% to $57.4 million compared to $56.6 million for the same period in 2019; cash flow from operations increasing 36% to $50 million from $37 million; adjusted funds flow from operations decreasing 8% to $33 million from $36 million; cash CapEx decreasing 11% to $27 million from $31 million; EBITDAX decreased 8% to $42 million from $46 million; our cash position increasing 127% to $94 million from $41 million at September 2019; net income increased 294% to $2.6 million from $0.7 million. Gas sales increased 11% compared to the same period last year, as the commissioning of new pipeline infrastructure and associated ramp-up in sales volume was still ongoing in the third quarter of last year.

That said, increased gas sales were offset by lower interruptible realized gas prices as compared to 2019, mainly due to lower demand for spot sales as a result of the COVID-19 pandemic. July and August 2020 had the lowest intercable prices of the year for Canacol.

However, those prices rebounded sharply in September to average $4 per Mcf. While Q3 funds flow from operations was slightly reduced relative to Q3 2019, capital expenditures were also lower as we were working on completing and commissioning the Jobo 3 gas plant expansion in the third quarter of 2019.

Our capital spending this year has been somewhat constrained by COVID-related restrictions, particularly in the second quarter of 2020, as Charle just mentioned. And the capital program has benefited from cost savings stemming from lower drilling rates than we had originally budgeted for amongst other things.

As a result, we were still able to generate $6 million in free cash flow before interest payments relatively unchanged from the same period last year. That free cash flow supports our unchanged quarterly dividend that was initiated in the fourth quarter of last year, which currently represents an annual dividend yield of approximately 5.5% with the last dividend being paid in October.

With respect to our share buyback program, we began actively repurchasing shares for cancellation on September 10 and bought 462,000 shares at an average price of CAD 3.50 in the month of September as reported in these Q3 financial statements. During the month of October, we repurchased an additional 763,000 shares, at an average price of CAD 3.47, bringing total purchases to approximately US$3.2 million over that two-month time frame.

We remain actively repurchasing shares in November. Our net debt-to-EBITDAX ratio is 1.7 times at September 30, 2020, reduced from 2.3 times at September 30 2019, obviously well within our financial covenants of 3.25 times.

To compare Q3 of 2020 to Q2 of 2020, during the second quarter of 2020, Canacol felt the peak of the impact on gas demand from COVID-19. Q3 results showed an uptick in gas demand.

As such, revenues increased 6% in Q3 as compared to Q2, cash flow from operations increased 32% quarter-over-quarter, adjusted funds flow from operations increased 7% to $33 million from $31 million, cash CapEx increased 129% to $27 million from $12 million in Q2 and as we were able to reengage in drilling in other operations, EBITDAX increased 5% to $42 million from $40 million and ending cash increased 60% to $94 million at September 30, up from $59 million at June 30, 2020. Our operating netback decreased slightly to $3.47 per Mcf in the three months ended September 30, 2020 compared to $3.86 per Mcf for the same period in 2019.

Once again, this decrease is due to lack of premium price spot market gas sales as a result of the lower demand driven by the COVID-19 economic downturn. Despite the reduction in netbacks caused by the lower gas demand, it's worth noting that we maintained relatively high and stable netbacks as well as strong operating margins of 79% during the quarter, which speaks to the strength and stability of our business and the value of our sales contracts in particular.

The financial strength and stability of our operations is giving us increased financial flexibility. We've -- and what we've done to make sure it isn't just theoretical is to reprofile our debt as announced in August.

We're able to lower our cost of capital and secure substantially increased financial flexibility during the third quarter. Although I did go through these initiatives on our last quarter's call, I'll briefly touch on two of the components that closed in Q3 on July 31, specifically as outlined on the right-hand side of this slide.

We put in place a new $46 million revolving credit facility, which is approximately 5%, if and when drawn. Given Canacol ended Q3 with approximately $94 million of cash, this facility remains undrawn.

Although Canacol can fund its capital and dividend programs with existing cash and cash flows, we thought it prudent given the favorable rates to add to our financial flexibility. We also completed a $75 million bridge term loan at approximately 4.5%, which resides inside the company that will build the Medellin pipeline.

The first $25 million was drawn in August and will be used to fund expenditures such as engineering and environmental permitting through to mid-2021. Remaining $50 million could be used to order long lead time items such as pipe when the timing is appropriate.

We anticipate that during the term of the bridge, Canacol would divest between 75% to 100% of the shares of the subsidiary to an equity partner while maintaining up to 25% working interest in the ownership of the pipeline project. Once the equity partners and bank syndicate agreements have been signed in any applicable conditions precedent have been met, we anticipate the long-term funding will be advanced and the bridge will be repaid in its entirety.

For clarity, although the $25 million draw appears as debt on our balance sheet at September 30, along with the corresponding cash amount, we do expect this debt to no longer be on our balance sheet once partner deals have been finalized on this project. We're seeing our cost of capital decline as market participants come to understand the value of our business.

On the debt side that is clearly reflected in these new terms and expanded debt capacity, while on the equity side is reflected in a very stable share price compared to many other oil and gas producers. During the remainder of 2020, the corporation plans to use excess cash, firstly to maintain our quarterly dividend payment $7 million a quarter, which is CAD0.052 a share, represent approximately 5.5% dividend yield at current share prices.

And secondly to continue to repurchase common shares of the Corporation under its normal course issuer bid. In closing, our Q3 financial results were strong and relatively stable despite the challenges that the coronavirus pandemic presented.

And now we're under an increasingly enviable position of financial strength with increased flexibility to ramp up investment levels when we think it makes sense to do so and if operational restrictions don't prevent us from doing so. At this point, I'll hand it back to Charle.

Thank you everyone.

Thanks Jason. Stability provided by our fixed take-or-pay gas sales contracts have allowed us to continue weathering the financial effects of this pandemic and we have maintained robust cash flow and operating margins as discussed by Jason.

We've also maintained our return of capital to shareholders via the continued issuance of dividends with no change in yields and we have been actively buying back shares since September. Our lenders as Jason has just discussed have renewed our existing bank facility or reduced interest rates and extended new lending and revolving credit facilities to put us in a position of strong liquidity.

All of these aspects reinforce the long-term stability of our business model. Mainly due to the two-month delay in the drilling program related to the lockdown in the second quarter and to the implementation of COVID protocols in the field, we anticipate drilling eight of the originally planned 12 exploration and development wells this year with the remainder being pushed into 2021.

We anticipate commencing the drilling of the Flauta-1 and Siku-1 exploration wells shortly here in December. In October of this year, the Corporation tested the Arandala-1 exploration well, which was drilled in late 2019.

Well encountered 30-feet of pay within the Porquero sandstone and was tested with a final production rate of 13 million cubic feet per day. Well is currently tied to production mainfold and ready for production.

The Corporation also plans to add two new exploration and production contracts to its portfolio, the VAM-44 block, which is located in the Lower Magdalena Basin adjacent to our main gas producing areas, and the VMM-47 block located in the Middle Magdalena Basin, which complements our large existing gas exploration position in this basin where we are chasing a major new conventional gas play. The Corporation has had an ongoing discussions with our partner Promigas SA with respect to ship or pay contracts and expects to reach an agreement in the very near term.

I would like to thank the entire Canacol team as well as our contractors, lending partners and clients for their support and hard work during these very uncertain times, which have allowed us to continue operating safely, sustainably, reliably and profitably while investing for future growth. We're now ready to answer any questions that you might have.

Good morning. Thanks for taking my questions, and congratulations on a very nice quarter and the financing changes.

Can I get a little more light shed on the Celsia expansion, the 200 megawatt power plant. You have in the presentation estimated start date December 2021, but it has a subject to COVID-19.

And then there's a comment about firm energy obligation December 2022 to QEF. Can you walk us through a little more in detail on that?

And also how much delay do you see potentially happening because of COVID? And yes, that would be much appreciated.

Yes. The El Tesorito power plants which we are part of joint venture with Celsia andProelectricahere in Colombia is a 200-megawatt power plant located approximately 7 kilometers to the southwest of our Jobo facility.

That facility or that project was awarded in March of last year as part of a 2,500-megawatt bid round that the government orchestrated. It's operated under the cargo de confiabilidad system here in Colombia primarily to active backup generation at times of need.

The project itself is well underway. The EPC contract for the motors was awarded in June of this year.

The civil works started in July of this year. It's anticipated that the civil works will be completed in the first quarter, late first quarter 2021 and the motors should be arriving to be installed mid-year of 2021.

All environmental permits related to the connection of the power plant to the adjacent substation have been received the past summer. So there are no permits pending with respect to the connection of this patient to the main power grid.

So at this particular moment the project is on schedule and the consortium anticipates that the project will start to generate December 1st of 2021.

And the firm energy obligation QEF December 22 could you walk us through that?

Yes. So as I mentioned the project was awarded under 2,500 megawatt bid round for something that's known as cargo de confiabilidad in Colombia, which is essentially back up generation to be called upon should there be a need for additional electrical generation country related to decreased hydroelectric generation particularly during the dry seasons.

So this plant has that -- that would actually put it. It has that condition.

It will receive a daily tariff from the government to be in standby mode to be ready to instantly start-up should so power be generated. So that's one component of the project.

The plant is free to generate on its own under market conditions to sell electricity into the grid, into the regulated and unregulated grid. And that's where the majority of the generation will occur.

So essentially the plant will gain a revenue from the government a 15-year PPI, PPA, I should say on a standby basis. And then separately, we'll generate revenue on its own dispatching under normal operating conditions.

And that's the -- is that a -- is that standby that takes effect in 2022. That's when it starts to receive that particular revenue.

Right. And then lastly for me how much is the shortage of electricity in the area right now so that how much of that $30 million capacity or impact for you for Canacol?

Are we looking at based on the shortage of electricity at this time?

So it's important to say that the plant has a generating capacity of 200 megawatts, which is 40 million cubic feet per day. It's anticipated the consortium estimates that will be generated at approximately 75% capacity under normal conditions, which is the consumption of around 30 million cubic feet per day.

The bid round that was auctioned last year by the government the 2,500 megawatt bid round was done to cover a shortfall related to the significant delay of EPM's Ituango hydroelectric power generation project which represents 2,500 megawatts of new hydroelectric power. That project was supposed to come on stream in December of 2018, but has been delayed due to significant issues associated with construction of the project.

And the start-up of that project is anticipated now to be in 2024 at the earliest and only at less than 50% capacity. So there is a shortfall of electricity in the market-related to the delay of that very significant hydroelectric product.

And for that reason, the government tendered this additional 2,500 megawatts of which Tesorito is 200 megawatts of that shortfall.

Okay. Thank you very much.

And again, congratulations of the nice quarter.

Thank you very much.

Hi. Good morning and thank you for taking the questions.

I just have two quick -- a couple of questions. So, like, what you're seeing right now in the spot market, as spot prices continue to push average gas pricing down.

So, I guess -- and that's kind of being in favorable gas amounts for this quarter, given that lockdown measures have been lifted since September. So, I guess, I would like to know that what level of production are you expecting to see in this last quarter.

My second question is related to the Jobo to Cartagena pipeline. I would like know if there is any update on the negotiations with Promigas regarding the transportation contract on this pipeline?

And lastly, I would like to know how valuable is the expectation of vehicle on the upstream gas taking into consideration spot gas prices in the current market right now? I would like to know your opinion on that.

Thanks. Thanks for taking the questions.

I'm sorry, Daniel. I did not catch your first question, if you could please repeat it.

My first question has to do with spot prices. So I would like to know what's been the behavior so far this quarter on demand and what can be the impact on that for gas prices on the last quarter?

And in line with that what that level of production are you expecting to see in the fourth quarter?

Okay. I think Jason can -- Jason went over the spot pricing.

But Jason if you can just repeat the spot pricing recently and currently?

Yes, sure. So let's just deal with the production first.

So, of course, Q2 was 152 million cubic feet a day, as reported. July and August were about 162 million cubic feet a day.

September was 168. And I think last week or the week before we announced -- or last week, I guess, we announced October at 173 million cubic feet a day.

So, typically, we'll report November and December within a week or two of those months closing. But once again October was at 173.

There's another couple of questions in the queue which relate to the spot prices also. So I'll just sort of jump the gun on those and answer your question more fulsomely.

So, obviously, the COVID pandemic hampered -- hindered, rather, gas demand and with that hindered to gas prices. Having said that, general terms, Q1 of 2020 saw those interruptible prices average slightly more than $4 an Mcf.

Q2 of 2020 saw those same interruptable prices averaged slightly less than $3 an Mcf. And when we got to Q3, July and August averaged right around $2 an Mcf.

Having said that, September bounced back to $4 and October was in line at the same $4 price.

Thanks, Jason.

I'm sorry Daniel, there was a -- I think for that second question, if you could just repeat that as well, please?

Yes. Okay.

So my second question is related to the Jobo Cartagena pipeline. I'd like to know if there is any update on the negotiations with Promigas regarding the transportation contract on this pipeline?

Yes. As I mentioned during the course of the presentation today, we're currently in discussions with Promigas regarding the ship or pay contracts there and we'll have an agreement.

We feel we will come to an agreement very shortly.

Okay. Again and lastly, I would like to know your opinion and how viable is the exportation of the Colombian offshore gas that's been announced by Canacol taking into account fundamental gas prices in Colombian market?

I think there have been a couple of potentially significant discoveries in the offshore over the past five or six years by Petrobras, by Repsol, by Ecopetrol, Anadarko. They are located in very deep waters up to 2,000 meters of water depth.

And they have yet to be fully appraised with respect to the drilling of additional wells to try and better estimate the size of those discoveries before a commerciality decision is made to invest in the infrastructure, which will be necessary to develop those discoveries. So I would say that the first -- the initial results are encouraging with respect to the presence of gas there.

The uncertainty lies within how large these discoveries are. So that's going to require additional drilling which was supposed to happen next year has been delayed into 2022 I believe now.

And then a commercial decision has to be made with respect to developing those discoveries and given the water depth of these discoveries these would be multibillion-dollar offshore deepwater type developments, which would have a significant impact on price obviously of cost of that gas coming to the market. So on one hand you're looking at a seven to 10-year type of development scenario before that gas can be put into the Colombian market.

And then the cost would likely be quite high compared to gas developed and produced onshore.

Thank you very much for your answers, Charle.

Thank you, Daniel.

Hey, everyone. Good morning, Charle and Jason and also Canacol's IR team.

I just have one question. Actually if you could please share with us if you are receiving any interest around the open season for Jobo Transmantaro.

And how could you -- this be related this project around the contract that is being actually renegotiated around the expansion of the 100 Mcf per day between Jobo and Cartagena which is also with from Promigas just around that? Thank you.

Thank you, Nicolas for the question. The two subjects are completely different.

They're not associated with one another. As I mentioned earlier we're currently negotiating shipper pays with respect to Promigas to park the Hainan Brink and expect to reach in previous shortly.

And with respect to the open season that is a new pipeline project that Promigas has proposed or put to the Craig with respect to a bidding process or open bidding process for a new pipeline from Jobo into Ontario. But the two projects are very distinct.

Hi, Carolina, Hi Jason. Good morning.

Thanks for the questions. I have two here.

First on these -- on Jobo following up the last question. There is any update on the EPC contract that there is any news here.

I remember that as you mentioned here that Promigas could be one of those set, if you could give us more color on this would be very helpful. And following up the other question about Promigas contract.

There is any timeline here or do share -- I don't know if you could share this time line could be very helpful for us. And the third one very quick.

Looking to the demand for the next year should we expect anything close to 200 million befit or the company are working with a lower number than that?

Thank you, Gabriel. With respect to the Jobo median pipeline project, we have received offers from three different EPC contractors which we're currently evaluating.

And we will make a decision once we have executed the main of take contracts into main with respect to the sales. So, that's the status of that project.

With respect to the timeline of the project it's all dependent upon the execution of the primary offtake contracts to Mediline. So we're still waiting for that to occur before we move on to EPC award and funding.

With respect to demand for next year, we're currently working on our 2021 budget. And as usual we will publish our guidance which will include gas sales as well as capital and whatnot in early December of this year.

So, that will be coming out within the next three weeks or so.

Okay, great. Thank you.

Thank you. The first question is from Daniel Guardiola from BTG Pactual.

At which prices are you planning to roll over the take-or-pay contracts that expire this year?

At the highest possible price.

The second question from Daniel is are you planning to record in your balance sheet a contingent legal liability related to the early termination of the transportation contract with Promigas for the 100 million cubic per day pipeline connecting Jobo to Barranquilla?

Yes, the answer to that is clearly no. As Charle pointed out, we're in discussions and expect to have an amicable resolution soon.

The third question is, how do you see gas demand in the spot market evolving, especially considering that the rainy season in Colombia has just started and water reservoirs are at record high?

Well typically, there's a dry season and a rainy season. We're currently just coming off the crest of the rainy season.

The water levels are not at record highs. The water levels are at normal highs, not record highs, and should start to fall as they usually do through December, through the first quarter and into the early second quarter of next year, as they always do.

That tends to be the highest level of thermoelectric power generation as a matter of fact is in the first quarter. So, I expect that, nature will repeat itself, as it always does, with respect to the course of the dry and rainy seasons.

And his final question is, what is preventing you from signing the take-or-pay agreement with EPM, that will make feasible the pipeline project from Jobo to Medellin?

That is currently in the Board of Directors' hands at EPM.

Now, we have another question from Percy Vega from Credicorp. Are you able to continue with this legal process with Promigas?

Or will you have an currently agreement with them?

I think, we've answered that a few times in this conversation.

The next question is from Astrid Castro from Credicorp Capital. How have evolved the negotiations with Promigas?

Why did you need to use the funds from the bridge loan? Could you give us some details about that?

Yes. I think, we've covered Promigas, but I'll deal with the bridge loan.

So the bridge loan once again is for early items on the Mediline pipeline project. That project is held inside a subsidiary company, a different company than Canacol legally.

So, essentially we're just temporary custodians of those shares, right? So, once we sign a private equity deal, when the pieces fall in place, we'll transfer them, the bulk of the shares.

The debt will be completely off our balance sheet, as we can only hold the maximum 25% interest in that company, which is the maximum allowed for a producer under Colombian law. Just to round that out, I guess obviously, the funds that are spent or the interest that will be paid et cetera, falls inside of that Mediline company right?

So, the intention is that, it won't be on Canacol books for long.

Thanks, Jason. Just give us two second to see, if we have any more questions from the queue?

Okay. I think with that, we finish our conference call today.

Thank you all for participating in Canacol's third Q conference call. The call now has been concluded and have a great day.

Thanks, everyone.