Canacol Energy Ltd

Good morning, and welcome to Canacol's fourth quarter and fiscal year-end 2019 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 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 continue the operational highlights for the fourth quarter 2019. Mr.

Jason Bednar, our CFO, will then discuss the financial highlights. Mr.

Gamba will close with a discussion of the corporation's outlook for fiscal year 2020. A Q&A session will follow Mr.

Gamba's closing segment. Mr.

Gamba is joining us today from the line from Bogota, and Mr. Bednar is joining us today from the line from Calgary.

I will now turn the call over to Mr. Charle Gamba, President and CEO of Canacol Energy.

Thank you, Carolina, and welcome to Canacol's fourth quarter and fiscal year 2019 conference call. In 2019, the Corporation achieved several important goals with respect to growing its gas business in Colombia, including a 26% increase in gas sales year-over-year related to the expansion of transportation infrastructure, a 12% increase in 2P reserves year-over-year related to continued exploration and development success, the award of three new conventional gas exploration blocks in the 2019 exploration bid round and the sale of our last remaining oil producing assets.

Following the completion of the new Holo to Cartagena gas pipeline expansion in third quarter 2019, fourth quarter 2019 marked our eighth consecutive quarter of year-over-year production growth. In fourth quarter, we increased our realized contractual gas sales by 54%, to 181 million standard cubic feet per day, up from 119 million standard cubic feet per day during the same period in 2018.

Growing our position as the largest independent gas producer in Colombia behind Ecopetrol, the state oil and gas company. Our production now supplies approximately 25% of the Colombian gas markets.

This trend of increase in gas sales continue through January through mid-March 2020, with gas production averaging 207 million standard cubic feet per day, 14% higher than average gas sales for fourth quarter of 2019. Our gas exploration and development drilling programs also continue to deliver positive results in 2019.

We achieved a 224% 2P reserves replacement ratio and a 12% increase in our 2P gas reserves base to 624 billion cubic feet. The largest driver of those reserves additions has been successful exploration drilling, where we continue to build on the strategic advantage and our growing experience of seismic interpretation and geological modeling.

Our gas exploration and drilling results over the past six years have yielded an industry-leading 83% hit rate in respect to commercial gas discoveries. I also want to highlight the substantial technical revisions that have contributed to the growth in our reserves, driven primarily by our reservoir management team that has allowed us to target previously unrecognized, undeveloped or less developed sand reservoirs and sections in a very cost efficient manner within our existing producing fields.

The estimated net present value of future net revenues from reserves discounted at 10% has increased year-over-year by 46% to $1.6 billion on an after-tax basis and $2.1 billion on a pretax basis, which equates to CAD15.47 per share of reserve value and CAD13.41 per share of 2P net asset value. 2P finding and development cost came in at an industry leading $0.87 per Mcf and $0.67 per Mcf for the one and three year periods ending December 31, 2019 respectively.

We also achieved a 4.4 times and 5.7 times 2P recycle ratio for the one and third year periods ending December 31, 2019 respectively. I would [Technical Difficulty].

It's okay. It's Jason here, that was just Charle -- he obviously has a connection issue.

He was just about to hand it over to me. So I will take over here.

It happens to be good timing from the drop off as it turns out. So 2019 was a great year for Canacol, both operationally and financially, as we continue to execute our plan and drive our growing natural gas business forward, largely driven by the increase in 2019 gas sales following the completion of the Promigas expansion in late August of 2019, that Charle has already spoken to.

We reported approximately $125 million in funds from operations for the full year of 2019, being a 19% increase from 2018. In combination with reduced capital expenditures, as we focused on the most value enhancing activities within our core gas operations, this allowed us to generate substantial amounts of free cash flow supporting our new quarterly dividend that was initiated in the fourth quarter, while also improving our leverage ratios.

Our net debt to EBITDAX ratio was reduced from 2.4 times as at December 31, 2018 to 2.1 times as at December 31, 2019. Looking forward, we anticipate this leverage ratio to fall dramatically to approximately to 1.1 times by the end of 2020.

Focusing on the fourth quarter 2019, financial highlights include revenues increasing 30% to $66 million compared to $51 million for the same period in 2018, adjusted funds flow from operations increasing 15% to $33 million from $29 million, and EBITDAX increasing 36% to $43 million from $32 million. As expected, increased gas sales allowed us to substantially decrease our operating costs and G&A expenses on a per unit basis.

With respect to G&A, this slide shows a year-over-year, 9% decrease in the fourth quarter. However, included in the above numbers are one-time severance costs.

In the absence of these, G&A per BOE was $3.28 or a 28% reduction from the prior year. Of course, Q4 also includes additional seasonal costs such as accounting and reserve audits, and as such, it's typically the highest quarter in the year.

Looking forward to 2020, we anticipate G&A to be approximately $2 at BOE or $0.35 in Mcf. Gas operating cost decreased from $0.42 in Mcf in 2018 to $0.28 in 2019.

We expect further reductions in 2020 with our current budget being approximately $0.25 in Mcf for gas OpEx. While the main driver of that is sales growth, we shouldn't underestimate the achievements of our operations teams and their continuous efforts to achieve increased operational efficiencies.

We have built the culture of continuous operational learning that we expect to continue yielding positive results. At a time of increased volatility in the energy commodity markets globally, I want to highlight one thing that didn't really change for us in 2019, which did support our ability to continue producing positive financial results, which of course is our high and stable gas prices.

Those high gas prices were driven by continued strong demand for natural gas that we produce in northern Colombia, which we expect to continue in 2020 and beyond. The drivers behind this are continued declines in the main historic natural gas producing fields on the Caribbean coast of Colombia, a rapidly growing local economy with growing energy demand, limited alternatives to supply increasing energy demand, and then increasing preference for clean burning natural gas over coal or oil.

As a result, we continue to be very happy with our decision to focus exclusively on natural gas, where we're seeing consistently high prices and stable prices, and we're able to produce with exceptionally low costs. That operational predictability and stability makes it easier for us to operate with certainty as we negotiate with partners, debt providers, and customers, and as we plan our future business developments.

On this slide, you can see our exceptional operating margins, which were close to 80% throughout 2019. Fourth quarter funds from operations, netbacks and margins were down slightly from the third quarter levels due to a number of seasonal factors, cash tax adjustment in costs associated with pipeline commissioning, while the increased pipeline capacity is not fully utilized in October, November.

However, over 90% of the Corporation's natural gas operating expenses are fixed, and as such, as I mentioned earlier, the Corporation expected its natural gas OpEx per unit to further decrease to approximately $0.25 or -- $0.25 in Mcf or $1.42 of Boe during 2020, now that the Promigas pipeline is operating at full capacity. We are maintaining our guidance for 2020 for operating netbacks of $3.80 in Mcf, which is approximately $22 in Boe.

After G&A, we expect to generate approximately $265 million of EBITDA, which after interest payments, taxes and CapEx of $114 million will translate into approximately US$80 million of free cash flow that we will -- that will support continued payment of our newly introduced dividend, debt reduction, and share buybacks. As we have indicated, sales increased substantially to slightly exceed our 2020 guidance of 205 million cubic feet a day from the start of the year through to mid-March.

I want to briefly comment on foreign currency during these volatile times. As a result of recent world events, the Corporation is benefiting from the current depreciation on the Colombian peso and the Canadian dollar.

The peso has declined approximately 22% against the US dollar, effectively reducing peso denominated expenditures on capital expenditures, operating costs, and G&A of approximately $15 million for the remainder of 2020 as compared to the Corporation's original budget estimates. Our foreign currency exchange collar on the peso, which expires in July 2020, on which Canacol has historically been in on money on, effectively reduces the $15 million savings by approximately 15% for the remainder of 2020.

Similarly, the recent 8% weakness in the Canadian dollar effectively reduces our Canadian based G&A. There is also a press release last night with the reaffirming our dividend at $5.02.

I believe at today's prices, that's roughly a 6.6% dividend yield, and of course, the details of that are in that press release which I'm going to look at. At this point, I would like to hand it back to Charle for closing comments.

Let's just check and see if Charle is on the line. If not, I'll proceed with those.

Thanks, Jason. Back on the line here.

In 2020, the Corporation remains focused on the following objectives. Firstly, the drilling of 12 exploration appraisal and development wells in a continuous program representing the largest program ever executed by Canacol for gas.

Secondly, the execution of a definitive agreement to construct a new gas pipeline, which will increase the Corporation's gas sales by an additional 100 million standard cubic feet per day in 2023. Thirdly, continuing our program of quarterly dividend payments and scheduled debt repayments.

And lastly, continue with our commitment of strengthening our Environmental, Social and Governance strategy and reporting to ensure successful results for our stakeholders. Our production mix consists of 100% natural gas with no oil production.

Approximately 80% of our gas production is sold under take-or-pay contracts denominated in US dollars priced at the wellhead. The other 20% of our gas sales is sold under interruptible contracts denominated in US dollars and priced at the wellhead.

As such, the Corporation is insulated from the current effects of low worldwide oil prices, which has seen its oil weighted peers recently cut capital programs, production forecasts, and return of capital to shareholders. The Corporation therefore maintains its previously announced 2020 capital expenditure, production, and return of capital guidance.

The 2020 capital budget remains at $114 million, which will be fully funded from existing cash held and 2020 cash flow. Forecasted realized contractual gas sales for 2020, including off-taker downtime, are anticipated to average approximately 205 million standard cubic feet per day, representing a 43% increase over the 2019 average natural gas realized contractual sales of 143 million standard cubic feet per day.

The average natural gas sales price, net of transportation costs, where applicable, is expected to be approximately $4.80 per Mcf. We are currently in the process of contract in a second drilling rig in order to achieve our drilling target of 12 wells, with the goal of replacing production by more than 200% and continuing to increase our reserve base.

The Corporation's forecasted production, EBITDAX, and cash flow from operations for 2020 is anticipated to be substantially higher than previous years, with EBITDAX forecasted to be approximately $265 million, up 58% from $167.5 million in 2019. During 2020, the Corporation plans to use excess cash to: maintain our quarterly dividend payment, which has been set at CAD0.052 per share, totaling approximately $7 million for the first quarter of 2020, payable on April 15th, 2020 to shareholders of record at the close of business on March 31, 2020; secondly, reduced debt by approximately $15 million; and thirdly, continue to repurchase common shares of the Corporation under its Normal Course Issuer Bid.

Also notable is a significant forecast decrease in the Corporation's Net Debt to EBITDAX ratio, which stood at 2.1 times at December 31, 2019, and is anticipated to be approximately 1.1 times on December 31, 2020. Over the past six years the Corporation has been transitioning to a clean energy company, and I invite you to visit our website to view our updated corporate presentation which focuses on our effort to deliver positive financial and operational results, while transitioning to a lower carbon footprint.

Finally, with respect to the coronavirus crisis, the Corporation has taken all of the appropriate measures to ensure the continuity of its operations and business in Colombia and Canada, including compliance with all local, provincial, and national mandatory decrees. Operations in the field are running smoothly with no operational interruptions.

Staffing in the Bogota and Calgary offices have been reduced to essential personnel, with the remainder of personnel working remotely from their homes. In the event of an emergency, contingency plans have been put in place to ensure that operations and gas sales continue smoothly.

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

Good morning, everyone. Congratulation for 2019 results, and thank you for bringing up this Q&A session.

For the moment, I have three topics I would like to discuss with you if you allow me. The first one is with buyback program.

Given the current pricing scenario for the equity, should it be relevant in your consideration to give some pressure to this buyback program taking into account the current discount price. The second one is the dividend payouts.

Regarding the dividend program with 2019 net income result of $34 million approximately and $28 million in dividends expected for this year. The cash out represent about payout nearly about the 80%.

We do remain with the quarterly program of the $77 million indefinitely from the net income or how can we read the further payout intending from the Corporation? And the last topic I want to discuss with you, if you let me, is the competition and contracts.

What are the spreads for the gas offer in Colombia coming from the clear LPG and SPEC LNG and how is the rating for the risk in the gas and spot market for Colombia, and if you need to be more flexible in your contracts with your clients considering these spot prices in the Henry Hub?

Okay, thank you. I can start with the first two questions.

With respect to the normal course issuer bid, also known as the share buyback, as outlined in the press release a couple of months ago, we are allowed to participate to a maximum of approximately 46,000 shares a day, which we are currently doing at these levels. So we currently intend at these levels to participate to the maximum on that share buyback.

With respect to the dividend payout, as you properly note, it's approximately US$7 million a quarter, which is CAD0.052 that will be paid on April 15th to shareholders of record on March 30 or 31. I think your question was revolving around the size of the payout being 80% of net income.

So the bond covenant indentures allow us to pay 50% of net income, not 80% which it happens to be. Having said that, that's a cumulative net income and there are certain baskets that there is a starter amount that I can use, there is annual additions to that.

So that dividend at this point in time, and certainly we have stress tested that is safe. The exact ratio on net income on any given quarter may vary, but we expect to continue to keep paying that $7 million dividend.

With respect to your contract question, I'll hand that over to Charle.

Thanks. Yes, Nicolas.

With respect to the contract question, recall that 80% of our gas sales are from take-or-pay contracts, priced in US dollars. So there is no impact whatsoever with respect to external threats, such as the SPEC LNG.

20% are interruptibles, which could be affected by spot LNG prices, but of course, the forward curves on both Henry Hub and LNG are both increasing. So we continue to maintain that LNG SPEC is not a significant threat over the mid to long-term, as well as the fact that with the impact of oil prices on US shale production should see a significant decrease in the amount of associated gas production in the Continental US as well putting some stress on -- upward stress on Henry Hub prices.

So we don't see -- we continue not -- to not see SPEC LNG imports as a significant threat to our netbacks.

Okay. Perfect, thank you very much.

Thank you. Hey Jason, hey Charle.

Two quick questions from my end. The first one is regarding the transportation costs.

We saw that, I mean [indiscernible] increased during the quarter, but really in my past notes from your previous conference calls, you mentioned about the reduction after Promigas was somehow online. So just trying to get a bit more color on where the transportation cost would stabilize looking forward?

The second one is about the new projects in terms of capacity increase. I mean, do you see any -- I mean, with the, I would say, current oil environment, do you see any impact in terms of prices on how these contracts would be affected and then by the time to design then or would you expect the same, I would say, average price from the contracts that you really have in your portfolio?

Thank you.

Thanks, Luiz. I'll answer the first question with respect to transportation.

So as you're familiar, we only look at our gas price, being net of transportation, and let me explain that further. So certain off-takers historically would have signed to pick up our gas at the plant gate and pay us in this simple example $4.80, and then they would pay Promigas the transportation.

Certain other off-takers would request or have requested that we deliver the gas to the plant gate in which case we get a much higher price and then pay Promigas the transportation, and it's in that second example where you would see the transportation expense on our income statement. Regardless, we typically get the exact same price net of transportation.

So fluctuating transportation costs on the income statement from quarter to quarter are largely irrelevant, but once again we only deal with the price net of transportation. Now to deal with the fourth quarter specifically as to why it would have gone up.

As you know, that given the delays of the Promigas pipeline and many new contracts coming into effect on, you know as it turned out December 1st, so during the first two months being October and November, we had more sales into the spot markets, and many of those interruptible/spot contracts wanted it delivered to their plant gate. Hence, we paid the transportation.

But once again, net of transportation would have realized the exact same price. Hope that answers it fulsomely.

With respect to your pricing question, I'll hand it over to Charle.

With respect to pricing, electrical demand and refining demand remain very robust in Colombia as does the declining production from the mature fields that have been supplying the majority of gas in Colombia, namely the Caribbean coastal fields of the Guajira and the Piramonte of the interior Yanos. So we still see very strong fundamentals with respect to demand, certainly across the medium to long-term.

They might, you know depending on how affected the Colombian economy is in the very short term with related to the current coronavirus outbreak, we do see some possibility for interruptions with respect to the daily demand, particularly in the spot market as more people stay at home in quarantine, obviously electrical demand is going to be impacted. So we do see some very short-term possible fluctuations with respect to spot sales and pricing in the very near term.

But in the long-term, the medium to long-term, the business model remains the same, the fundamentals of declining supply are still a fact and that places us as always very favorably to sell into a demand side [ph] of market.

Okay. Thank you.

Good morning, guys. So two questions.

Firstly, obviously we're in very challenging times, but I'm wondering if you can give us an outlook on spot prices and how they relate to the current power -- hydropower demand? And the second question is, your free cash flow Jason is US$80 million, which is a little higher than mine.

Just wondering what of the impacts of the Colombian peso might have been factored into your costs, your operating and G&A costs, and what might factor into your CapEx costs?

Thanks, Ian. Currently in the current environment here in Colombia, we've seen an impact on some spot contracts of 2% to 3% in terms of pricing.

So quite minor. So far so good.

That's not to say, however, that if the crisis worsens that might not change, particularly with respect to demand on the spot market. But currently, the spot pricing is relatively stable, as I mentioned 2% to 3% currently, yesterday below outlook, but relatively stable, but that in the very short-term all depends, of course, on how bad or not bad the crisis gets here in Colombia.

Perfect.

Okay. So with respect to the $80 million of free cash, I think there was a slide there, which of course started at $265 million of EBITDA, less $30 million of interest, $40 million in taxes, $114 million of CapEx, which brings you down to approximately $80 million of what's labeled here as free cash flow.

The use of that $80 million, of course, which is also a labeled on here would be $28 million of dividend. We're paying off approximately $15 million of debt reduction, just to go down that path a little bit.

We have the $30 million in Credit Suisse loan, which was not new debt, it was simply different debt when we bought out the Promisol Hobo to lease, that begins terming out in June of 2020 and we will pay off about 8.2 million of that. We also have another finance commitment, which will be roughly $2.5 million, that we will pay off this year, and the remaining $5 million is on our finance leases, largely some compressors and there's some of those totaling about $15 million, right.

So from the $80 million, once again, $28 million to the dividend, $15 million to debt reduction, which will in fact leave then approximately $37 million of other free unallocated cash flow, for things like the normal course issuer bid, potentially some additional debt reduction or things like that. With respect to your question of how much of the peso, you know I spoke to $15 million of peso savings once denominated in USD for the remainder of the year.

These numbers that I just went through are all on the original budgets, i.e. do not contemplate whatsoever any peso depreciation that's occurred recent.

Okay. That's really the question then.

Perfect. Thanks for the clarification.

Thank you so much. Just a quickie.

The service -- the price of services in Colombia, I know they normally drop in a downturn. I don't think we have ever seen a downturn quite this steep.

So I'm wondering just how much you expect your cost to decline?

Yes, thanks, Steven. Yes, obviously, a lot of our Colombian periods, a lot of oil producing periods have been announcing recently cut backs to the capital programs, obviously that predominantly impacts drilling and associated services.

So if we can, sort of, compare this in some way through price collapse in 2014, six years ago, I think if it's similar to what happened in 2014, I think within the next six to nine months, we can see service costs coming down between 20% to 30%, which would be comparable to what happened in 2014 when the oil price collapsed in the summer time in 2014. So that's what we're sort of anticipating with respect to services going forward.

Thanks.

Thank you. Good morning.

Charle, into the management team, first off, I just want to congratulate you on the strategic changes and redirection you've made for Canacol over the past four plus years. In hindsight, obviously, it's proven to be a very astute chain, so congratulations.

So first question, regarding just Colombia as a country and this whole coronavirus situation, can you just kind of explain what the politicians and the health officials are trying to do here? What sort of change in practices have happened inside the country?

How is the country kind of operating going forward and do we have a plan in place or they're going to figure it out as -- if and when things get worse relative to the current number of infections?

Yes, Ari. Thanks.

Thank you first for those kind words. With respect to the situation here in Colombia and coronavirus in particular, I think, what we're seeing here is a very similar response to elsewhere.

I think there are currently 120 or 130 cases reported countrywide. The majority of those are in the main metropolitan centers like Bogota, Medellin and Cartagena.

What has been put in place over the past week has been a complete closure of the borders of Colombia with the bordering countries. So no land traffic is allowed in or out of the country.

All international flights coming into Colombia and leaving Colombia were suspended on Monday evening this week. And also the government, the local governments, particularly the Mayors of the various city section of Bogota have now mandated a mandatory quarantine of all of its citizens.

So all of its citizens are quarantined to their houses, effective last night through till Tuesday morning. So I would say that the response has been, one, mainly of trying to limit the spread of the virus through those three particular efforts.

The Colombian government has also relaxed various financial mechanisms as well. So they -- there they've essentially mandated that no critical services can be cut off during the course of the next two months for any of its citizens and that all the essential services are available for provision.

So I would say, Ari, that Colombia has taken a very similar tact to what we're seeing elsewhere in the world.

Thank you. And then just two more questions.

To clarify the financial questions from earlier. You've provided this US$265 million EBITDA target for 2020.

I just want to double check that. The $15 million of reduced G&A and other costs that may happen here in the next, rest of the year, those are not included in that $220 million guidance?

Is that correct?

To the $265 million, that's correct. It's confirm.

And then just lastly, obviously, you have a very strong balance sheet and free cash flow here. They are unfortunately going to be probably distressed assets out there and the opportunity for acquisitions.

I'm just try to understand strategically what sort of areas you would be looking opportunistically potentially to spend some money or are you going to just say, no, thank you, we're going to focus on reducing our debt and sticking to our -- now our focus of being a natural gas only producer in Colombia?

Yes, I can state that the focus is purely natural gas in Colombia, in the lower-middle Magdalena Valleys. So we're not looking currently at any acquisitions inside or outside of Colombia.

We are looking, however, at the potential of accelerating some of our drilling and seismic programs, the exploration programs, taking advantage of the previous caller's questions, these question about the likely impact on service company prices going into this downturn. So we're looking at the potential of accelerating some of our exploration drilling programs, and the acquisition of exploration seismic.

So that would be the strategy that we're considering in terms of potential additional uses of cash. But the strategic focus is purely on natural gas exploration and commercialization in our existing assets.

Great. Thank you again, and best of luck.

Thanks, Ari. I'm just going to -- I'm going to revisit your question and Ian's question with respect to the $15 million savings.

So the bulk of that being $10 million of the $15 million is CapEx related, the other $5 million would be a split between operating costs and G&A. So if I were to include the Colombian peso depreciation into the EBITDAX calculation, it would have roughly a $5 million benefit, whereas the other $10 million being capital of course doesn't hit EBITDA, it's just a cash savings.

Got it. Thank you.

Good morning, Charle and Jason, and again, congratulations on the quarter and the year. And it's nice to be on an optimistic phone call relative to all the others that we've been having in the last few weeks.

I have two questions and quite a few of them were answered. On the Hobo, potential co-gen facility, is that still in the cards, are you working on that, when will you have more insight on potentially that moving forward and that taking some more of your gas volumes in the area?

Yes, thank you Joe. Yes, with respect to the Hobo power projects, yes, as we indicated, we were -- we formed a consortium last year with Celsia, which is a very large thermoelectric power generation company here in Colombia and were awarded by the Colombian government a 200 megawatt project called El Tesorito, which will be constructed very close to our producing facilities, about seven kilometers to the south of our producing facilities, very close to a substation, a 500 megawatt substation.

So that project is ongoing. That consortium recently has made the selection in terms of the motors and the equipment they are going to use.

And the current timeline for that project sees the project come online in December of 2021. 200 megawatts will consume approximately 40 million cubic feet per day of gas.

We, of course, have the gas sales contract to the consortium. So we can anticipate -- and in 2021 with that plant coming online, a 200-megawatt plant coming online, with an additional uptick in sales -- gas sales related to supplying that power station.

We're also evaluating another project of similar size, which would also be constructed close to our facilities and provide power to a specific industry partner. So we are very interested in evaluating and participating in that project as well.

So I would say that, the project that we do have in our hand out, El Tesorito, the 200 megawatt project, it looks to be online, it looks to be on schedule to come online in December of next year.

And pricing would still be in that US$4.80 [ph] range for the per Mcf.

Yes, the pricing is similar to our other contracts. That's correct.

Okay.

There is, however, obviously because the plant has been -- has been constructed very close to our producing facilities. There is very little with respect to transportation cost, of course.

Okay. Second question from me.

Some of your competitors in the south have had farmer problems, where they weren't getting paid by the government, related to change in kind of the crops they were growing. Do you have any of those problems in your area and do you have any insight if those issues have been resolved with the farmers across the country?

Well, that continues to be a problem countrywide, the program to supplement or to exchange that particular type of farming for legal types of crops has not -- has not worked that particularly well anywhere in Colombia. Fortunately, that particular crop is not the predominant crop in our area of operations.

So while we do have that sort of activity in and around our operations, it's nowhere near as extensive as it is on the Ecuadorian or the Venezuelan border. So we don't see much in the way of issues with the communities in our areas and relationships are very good there.

We employ a lot of the locals in all of our projects. So we don't suffer from that particular problem.

Perfect. Thanks very much and congratulations again and much success in the future.

Thank you.

Good morning, everyone. Thank you for the chance.

I just have one question. Do you think that Korean market condition regarding low natural gas prices could impact Canacol natural gas reserves due to a price effect has happened in oil?

Thank you.

Hi, Diego. Thanks for that question.

Well, you have to recall that the majority of our gas contracts are take-or-pay contracts. So the price is fixed.

There is no accounting for any change in the price. There is no possibility of any change in the price.

So we -- unlike oil reserves, we're typically -- the reserve rider uses a price forecast, ten-year price forecast strip. Our forecast strip is primarily, obviously, the executed take-or-pay contracts that we have signed.

So we see -- we expect little to no impact whatsoever on the value of our reserves, because the price of our gas is essentially fixed.

Hi, thank you for taking my question. Most of my question has been answered, and mostly related to the coronavirus and the Colombian situation.

Also I'd like to take advantage of this opportunity and congratulate you for turning around the operation into the oil, unrelated, and natural gas long-term contract, congratulations. And with fixed contract and then dividend and share buyback, your company probably one of the few energy company in very good shape.

You mentioned that your contract fixed fee with not any room for, you know, [Technical Difficulty]. If in term of the crisis, if the crisis worsened in Colombia, do this country if announce an emergency -- in the US, they are saying some utility have to provide, you know all these facility regardless of the customer paying or not.

Do you see any possibility that happen in Colombia? Thank you.

Thank you. Thank you, Chen.

If we -- first of all, look back to historic crisis in Colombia related to -- primarily to the provision of gas for thermoelectric power generation, we've never seen any examples historically of a price freeze on either gas or oil contracts historically. So that's one perspective, of course, anything can happen.

I mean, it could be a first time for everything. I would say that all of our contracts, all of our gas sales contracts have counter-party guarantees that are liquid with respect to making payments.

So if a party does not make a payment, we can seize those liquid guarantees and those guarantees are generally in place to cover between one to three months of current gas supply to that contracts. We do have short-term mechanisms to ensure price stability, but going forward beyond that, if there are defaults from counter-parties, which at this point of period, unlikely, all of our accounts are basically current, we could run into default problems if this is a deep and extended crisis.

Okay. Thank you.

Congratulations.

Could you please provide an update on the Medellin pipeline project. Normally take-or-pay contracts have embedded some flexibility swing factors causes to cope with demand moves of customers.

Could you please confirm whether your take-or-pay contracts have these clauses and roughly how much swings your contracts have?

I'll start with that Charle. So I'll start with the contracts and then you can answer the Medellin portion.

So Charle explained much of the contracts already. I'd like to add a couple of points to his already explained.

So there are no such clauses with respect to swing. However, I do note that these contracts typically have 6% operator downtime which does provide them some flexibility on when they take their gas.

And of course, properly, we factored that 6% downtime into our guidance. Second point, I would like to make with respect to the contracts is, these take-or-pay contracts typically have up to 12 months' time for them to take their gas.

So while they pay us upfront on a monthly basis by virtue of the take-or-pay contract, should they choose to take their gas at a later date. They have the ability to do so, but we're paid upfront.

And if you were to refer to the financial statements, you do see some take-or-pay revenue explicitly listed on there. Those are the instances where people have paid us upfront.

There are 12 month time frame to take their gas has expired, and at that point in time, it's recorded as take-or-pay revenue. So I hand it over to Charle to give [indiscernible] Medellin pipeline update.

With respect to the gas project, the gas pipeline from Hobo to Medellin which will provide an initial 100 million cubic feet per day of gas sales through 2024. We have currently completed the negotiation of the offtake contract with EPM, that has been completed.

We are currently out to tender for EPC contractors who will construct the pipeline. We anticipate awarding the EPC by the end of April, and we are currently working on the financial structuring of the projects, which involves both bank debt and equity, and we expect to close the financing of the project shortly after the award of the EPC contracts.

So that would be the update for the Medellin project.

Thank you for participating in Canacol's fourth quarter and fiscal year-end conference call. Please join us again in May for our first quarter conference call 2019.

Have a great day.