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Edited Transcript of CNE.TO earnings conference call or presentation 22-Mar-19 2:00pm GMT

Q4 2018 Canacol Energy Ltd Earnings Call

Calgary Apr 1, 2019 (Thomson StreetEvents) -- Edited Transcript of Canacol Energy Ltd earnings conference call or presentation Friday, March 22, 2019 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Carolina Orozco

Canacol Energy Ltd - Director of IR

* Charle A. Gamba

Canacol Energy Ltd - President, CEO & Director

* Jason Michael Bednar

Canacol Energy Ltd - CFO

* Ravi Sharma

Canacol Energy Ltd - COO

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Conference Call Participants

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* Daniel Guardiola

Banco BTG Pactual S.A., Research Division - Director of Equity Research

* Jenny Xenos

Canaccord Genuity Limited, Research Division - Analyst of Energy

* Josef I. Schachter

Schachter Energy Research Services Inc. - Author & President

* Luiz Carvalho

UBS Investment Bank, Research Division - Director and Analyst

* María Antonia Yarce Villa

Bancolombia S.A., Research Division - Share Analyst of Oil and Gas Sector

* Shahin Amini

Pareto Securities, Research Division - Analyst

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Presentation

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Operator [1]

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Hello, and welcome to the Canacol Energy Fourth Quarter and Fiscal Year 2018 Earnings Conference Call. (Operator Instructions) Please note, this event is being recorded. I would like to now turn the conference over to Carolina Orozco, Director of Investor Relations. Please go ahead.

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Carolina Orozco, Canacol Energy Ltd - Director of IR [2]

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Good morning, and welcome to Canacol's Fourth Quarter and Fiscal Year 2018 Conference Call. This is Carolina Orozco, Director of Investor Relations. I am with Mr. Charle Gamba, President and Chief Executive Officer; Mr. Ravi Sharma, Chief Operating Officer; and Mr. Jason Bednar, Chief Financial Officer.

Before we begin, it is important to mention that the comments on this call by Canacol's senior management can include projections of the Corporation's future performance. These projections neither constitute any commitment as to future results nor take into account risks or uncertainties that could materialize. As a result, Canacol assumes no responsibility in the event that future results are different from the projections shared on this conference call. Please note that all finance figures on this call are denominated in 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 2018; Mr. Ravi Sharma, our COO, will give an update on our facilities and flow line expansion; Mr. Jason Bednar, our CFO, will then discuss financial highlights. Mr. Gamba, Mr. Ravi and Mr. Bednar are joining us from the line from Bogota. Mr. Gamba will close with a discussion of the Corporation's outlook for fiscal year 2019. A Q&A session will follow Mr. Gamba's closing segment.

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

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [3]

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Thank you, Carolina, and welcome to Canacol's Fourth Quarter and Fiscal Year 2018 Conference Call. Q4 2018 marked our fifth consecutive quarter of production growth and industry-leading finding and development costs. In Q4, we increased our realized contractual gas sales by 40% to 119 million standard cubic feet per day, up from 85 million standard cubic feet per day during the same period in 2017, making us the largest independent gas producer in Colombia behind Ecopetrol state oil and gas company. The trend of increasing gas sales continued through January and February of 2019 with gas production averaging 126 million standard cubic feet per day, 6% higher than average gas sales for Q4 2018.

With respect to the pipeline expansion at Cartagena, Promigas is progressing on 4 separate constructions fronts on the Jobo to Cartagena segment, which includes the lane of approximately 85 kilometers of new 20-inch pipeline and the addition of compression to their Filadelfia compression station. Promigas anticipates that all of this work will be completed in June of 2019, which will lift our gas sales to approximately 215 million standard cubic feet per day at that time. Promigas anticipates completing the final leg of the expansion between Cartagena and Barranquilla by September of 2019, which will not impact our gas sales.

Our gas exploration drilling programs also continued to deliver positive results in 2018, achieving a 232% 2P reserves replacement ratio and an 11% increase in our 2P gas reserves base to 559 billion cubic feet with a pretax value of USD 1.5 billion or CAD $9.37 per share. 2P finding and development costs came in at an industry-leading $0.32 per Mcf and $0.57 an Mcf for the 1 and 3 year periods ending December 31, 2018, respectively.

We achieved a 12x and 7.1x 2P recycle ratio for the 1 and 3 year periods ending December 31, 2018, respectively. Our Gas Reserves Life Index now stands at approximately 13 years, placing us #1 amongst our publicly traded Colombian peers.

Our gas exploration drilling results over the past 5 years have yielded an industry-leading 80% hit rate of commercial discoveries, adding 481 Bcf of new 2P reserves, representing a compound annual growth rate of 55%.

Looking ahead, we have a portfolio of over 140 prospects and leads to drill across our 1.1 million net acres containing mean un-risked prospective gas resource of 2.6 trillion cubic feet according to a resource report from Gaffney, Cline & Associates dated April 2018. As such, we anticipate many more years of successful exploration drilling continuing to build out our reserve base.

During the 3 months ended December 31, 2018, we completed the Nelson 13 development well on our Esperanza block. Nelson 13 is our seventh well drilled into the field, which we discovered in 2011. The well encountered 266-feet of net gas pay. The thickest gas pay encountered in any of the wells we've drilled on any of our blocks in the Lower Magdalena Valley basin. Nelson 13 recently was tested at 33 million standard cubic feet per day and is now tied into the whole facility and is on permanent production.

In Q1 of 2019, we drilled the Palmer 2 appraisal well, our second well drilled into the Palmer Gas field, also located on our Esperanza block. The well encountered 81-feet of gas pay within the Cienaga de Oro sandstone reservoir and is currently being tied into the Palmer 1 manifold to be brought on to permanent production shortly. The Pioneer 302 drilling rig has been mobilized to drill the Nelson 7 development well, which is anticipated to start at the end of this month. Nelson 7 will take approximately 5 weeks to drill and complete, after which the rig will be mobilized to drill the Acordeon-1 exploration well, which is anticipated to spud in May of 2019. The remaining Gas exploration wells planned for 2019 include the Acordeon-1 and Saxofon-1 exploration wells on our operated 100% interest block VIM-5 and the Arandala-1 exploration well on our operated 100% working interest VIM-21 block. Appraisal wells Pandereta-5 and Clarinete-4 are planned for our VIM-5 block with the Canahuate-2 development block and on our operated 100% working interest Esperanza block.

Flexibility has been built into the 2019 drilling program such that in the event of exploration success, funds may be reallocated for immediate follow-up appraisal drilling locations.

I'll now take the opportunity to turn the presentation over to Ravi Sharma, our Chief Operating Officer, who will provide an update on the facilities' expansion projects

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Ravi Sharma, Canacol Energy Ltd - COO [4]

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Okay. So on the facilities side, in Q1 2019, we completed the construction of Jobo 3 Gas treatment plant, which has a treatment capacity of 130 million standard cubic feet per day, bringing our total Gas processing capacity of the corporation's operated Gas facilities at Jobo to 330 million standard cubic feet per day. Commissioning of Jobo 3 is currently underway and is expected to be completed in April 2019, well ahead of the planned completion of the Promigas pipeline expansion to Cartagena, which is scheduled for June 2019.

In Q1 2019, we also completed the Pandereta to Jobo 8-inch Gas flow line, which connects the 3 existing wells of Pandereta to our Gas processing facility. These 3 wells have a productive potential of approximately 75 million standard cubic feet per day based on well tests. We've also completed the debottlenecking of the Betania-to-Jobo flowlines which are 2 6-inch flowlines that have the capacity to transport up to 140 million standard cubic feet per day from the Nelson and Palmer Gas fields. Based on the wells that are currently tied into the Jobo facilities, we have a gross productive capacity of approximately 300 million standard cubic feet per day.

I would now like to turn the call over to Mr. Jason Bednar, Chief Financial Officer for Canacol, to discuss some of the financial highlights associated with our fourth quarter and fiscal year end 2018 results. When he is done, Charle will provide the outlook for the remainder of 2019.

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Jason Michael Bednar, Canacol Energy Ltd - CFO [5]

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Thanks, Ravi. 2018 was a great year for Canacol, both operationally and financially, as we continue to execute our plan to drive our growing natural Gas business forward. For the year ended December 31, 2018, total realized contractual sales were 21,590 BOE per day, including 113.3 million cubic feet of Gas a day and 1,720 barrels of oil a day on average throughout the year. I'll note that given the majority of the company's oil assets were sold to Arrow Exploration in late September, the 21,590 BOE per day is within the original guidance that we had given for 2018.

As you can see, the 113.3 million cubic feet of gas per day of 2018 sales represents a 41% increase over the 80.5 million cubic feet that we averaged in 2017. As a result of the Promigas pipeline completion expected in June 2019, we expect to see another dramatic increase in 2019 gas sales.

Largely driven by this increase in 2018 gas sales, we recorded approximately $105 million in funds from operations, a 62% increase from 2017.

Focusing on the fourth quarter of 2018, financial highlights include natural Gas and oil sales volumes increasing 20% to 21,519 BOE per day compared to 17,953 of BOE per day for the same period in 2017.

Realized contractual natural Gas sales for the 3 months ended December 31, 2018, averaged approximately 119 million cubic feet per day, a 40% increase from the 85 million cubic feet per day that was sold in Q4 of 2017. This is primarily as a result of the additional sales related to Gas flowing down the corporation's partially owned Sabanas pipeline that was operational throughout 2018. This large increase in natural Gas sales drove Q4 revenues net of royalty and transportational expenses to approximately $51 million, up 28% from the approximately $40 million recorded in the fourth quarter of 2017. The decrease in oil sales during this quarter related solely to the company's sale of the majority of its Colombian oil assets to Arrow Exploration in September as previously mentioned.

The corporation's average realized natural Gas sales price net of transportation was $4.95 per Mcf in the fourth quarter of 2018. This price is 6% higher than the $4.65 per Mcf, which we realized in the fourth quarter of 2017. Additionally, our average Gas sale price net of transportation expenses for the fourth quarter of 2018 was higher than the $4.80 we realized in the third quarter of 2018.

The increase in the natural Gas prices is due to higher prices from spot sales that generally represent 10% of our sales portfolio. This $4.95 price in Q4 drove a very strong natural Gas netback of $3.92 per Mcf in the fourth quarter of 2018 or margin in excess of 79%.

Focusing on the other components of the very strong $3.92 netback, natural Gas operating expenses per Mcf decreased 19% to $0.44 per Mcf for the 3 months ended December 31, 2018, compared to $0.54 per Mcf for the same period in 2017. The decrease is mainly attributable to largely fixed operating costs over a higher production base.

Over 90% of the corporation's natural Gas operating expenses are fixed and as such, the corporation expects its natural Gas operating expenses per Mcf to further decrease to approximately $0.30 per Mcf upon the commencement of operations of the new Promigas pipeline by mid-2019. Natural Gas royalties averaged $0.59 during Q4 or approximately a 12% royalty rate, which is consistent with prior quarters.

Once again, due to increased Gas volumes, Q4 2018 fund from operations of $28.7 million was 73% higher than the $16.6 million reported in Q4 of 2017.

On an annual basis, our realized natural Gas price net of transportation averaged $4.83 per Mcf for 2018, which is consistent with the sales price we achieved in 2017. I'll also note the 43 sales price is higher than the $4.70 per -- $4.75 per Mcf guidance we had released for 2018. For the year ended December 31, 2018, natural Gas operating expenses were $0.42 per Mcf, similar to those in 2017. Royalties of $0.61 per Mcf equate to approximately a 12.5% royalty rates, once again in line with previous guidance.

G&A expenses per BOE decreased 19% and 15% during the 3 months and year ended December 31, compared to the same periods in 2017, respectively. The decrease is due to the 40% and 43% increase in natural Gas production during those periods. G&A per BOE is expected to continue to decrease as the corporation's production base grows into 2019 and 2020.

At December 31, 2018, the corporation had $51.6 million in cash and $4.2 million in restricted cash, remains well capitalized, while also generating cash flow in excess of its planned 2019 capital budget. In early December 2018, the corporation entered into a $30 million term loan with Crédit Suisse. The proceeds of which were used to purchase the Jobo-2 Gas plant, which was leased from Promisol and previously carried on our balance sheet as debt.

As such, I would like to stress that this new Crédit Suisse term loan is not new debt per se, rather simply replacement debt, the benefits of which were twofold. Firstly, the buyout of the $24.2 million Promisol gas finance lease was achieved via the Crédit Suisse facility which carries interest at a fixed rate of 6.875%, which is a lower rate than the previous facility.

Secondly, the company is now able to operate Jobo-2 as opposed to Promisol previously operating it, and as such is able to reduce its operating cost by approximately $2 million per year going forward.

Capital expenditures for Q4 2018 totaled $37.7 million. The largest item of CapEx in the quarter included the construction of the Jobo-3 Gas plant, which will be completed later this month; at which time, the company will have 330 million cubic feet per day of natural Gas treatment capacity.

Other items in the fourth quarter included the drilling completion of the Nelson 13 well and the testing and completion of the Canahuate-3 well.

As you can see, the fourth quarter of 2018 marked the fifth consecutive quarter of growth in realized contractual natural Gas sales, with Q4 averaging over 119 million cubic feet per day. Earlier this morning, we released an operational update which amongst other things announced that natural Gas sales averaged 126 million cubic feet per day in the months of January and February 2019, which continues our trend of growing gas production and sales.

By mid-year 2019, the Promigas pipeline expansion should lift gas sales to approximately 215 million cubic feet per day, a number that includes offtake or downtime.

To briefly touch on our 2019 guidance that was released in December, the company announced that its 2019 capital budget is $119 million, which will be fully funded from existing cash and 2019 cash goal. Included in the 2019 CapEx program are 3 exploration wells, 2 appraisal wells and 3 development wells. The company will also acquire seismic on the Vim 5 Blocks during Q2 to Q3 of 2019. In addition, as mentioned earlier, the company will complete the Jobo-3 expansion shortly, thereby lifting our Gas treatment capacity to 330 million cubic feet per day.

Forecast realized contractual sales for 2019, which include downtime, are anticipated to average approximately 179 million cubic feet per day assuming a June 1, 2019, for the completion of the Promigas pipeline expansion.

Based upon the corporation's current portfolio of 2019 Gas contracts, the average sales price net of transportation were applicable as approximately $4.75 per Mcf. Oil sales are expected to average approximately 400 barrels of oil per day, until such time as the corporation disposes off its interest in the Rancho Hermoso oil field, it's only remaining conventional oil asset.

At this point, I'll hand it back to Charle to close with strategy and outlook for the remainder of 2019. Thank you, everyone.

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [6]

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Thanks, Jason. Thanks, Ravi. For 2019, we remain focused on lifting gas sales to approximately 215 million standard cubic feet per day from current levels of approximately 130 million standard cubic feet per day via the completion of Promigas pipeline expansion between Jobo and Cartagena.

As Jason just mentioned, we're also focused on drilling the remaining 7 exploration, appraisal and development wells in the continuous program targeting our reserves replacement ratio of over 200% as we have achieved in the past 4 years.

And finally, we are focused on the execution of a definitive agreement to construct a new Gas pipeline from Jobo to either the cities of Medellin or Cartagena, thereby increasing the corporation's Gas sales by an additional 100 million standard cubic feet per day to a total sales level greater than 300 million standard cubic feet per day in late 2021, early 2022.

We're now ready to answer any questions you might have regarding this call.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question today comes from Luiz Carvalho of UBS.

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Luiz Carvalho, UBS Investment Bank, Research Division - Director and Analyst [2]

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Charle, Jason, I have basically 2 questions here. The first one you mentioned the pipeline will be ready by September, but it wouldn't effect to the sales. So if you could shed some light on this topic on how the postponement wouldn't affect, you said, the sales on this front? The second, just make sure that I understood in the segment of the last comment, you mentioned about the construction of the pipeline to Jobo that would increase the capacity to 300 by 2021, if I'm not wrong. What is the likelihood of having 2 additional pipelines instead of 1? And how long will it take to develop them instead of basically just one for Medellin?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [3]

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Thank you, Luiz. With respect to the current work undertaken by Promigas, which involves 3 components. The first is a new section approximately, 85 kilometers long of 20-inch pipeline between Jobo and Majaguas. This is the distance approximately halfway between Jobo and Cartagena. The second is the expansion of the existing compression station located at Filadelfia, which is located between Majaguas and Cartagena. And the third component is in a new 20-inch pipeline approximately 140 kilometers in length between Cartagena and Barranquilla to the northeast of Cartagena.

With respect to the component that impacts our Gas sales, that would be the Jobo to Majaguas pipeline as well as the Filadelfia expansion. Both of those works, as I mentioned during the main text of my presentation, are anticipated to be completed by Promigas in June of this year. The remaining segments, which I mentioned is between Cartagena and Barranquilla, which is the new 140-kilometer stretch of 20-inch pipeline will be completed in September of 2019. That segment does not impact the 80 million cubic feet per day of additional transportation capacity between Jobo and Cartagena. Hence, our 215 million cubic standard feet per day forecast is for June of 2019 when those 2 segments are completed by Promigas.

With respect to your second question regarding the new pipeline project that we are working on, which will either see 1 of 2 options for the new pipeline route. One between Jobo and Medellin and the other option between Jobo and Cartagena. Both those options involve a 100 million standard cubic feet per day of new transportation capacity scheduled for late 2021 or '22. We will only be building 1 of those 2 projects. So we are currently analyzing both of those routes with respect to cost. The trains are different, obviously, between both those destinations. Transportation costs as the distances are different and the average pricing in those 2 markets, Medellin and Cartagena. We will make the decision with regards to which of those 2 options we are going to be going for here within the next month. So anyways, we anticipate completing 1 of those 2 options by late 2021, 2022; at which time, we will have available to us another 100 million standard cubic feet per day of transportation capacity to lift our Gas sales well beyond 300 million cubic standard feet at that time.

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Operator [4]

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Our next question comes from María Yarce of Bank Colombia.

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María Antonia Yarce Villa, Bancolombia S.A., Research Division - Share Analyst of Oil and Gas Sector [5]

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I basically have 2 questions. The first one will be regarding the gas stock, the new Promigas pipeline. We have previously heard that there was still kind of a permit pending to bury part of the pipeline below on existing highway. And I would like to know if you already have the permit? Or how is that going? And if that would have any impact on the completion of the first portion that you mentioned from Jobo to Cartagena? And the second one would be regarding operating expenses. We saw that as an effective dilution during the final quarter expenses were lower. My question is, can we expect these expenses to continue diluting as we move forward with higher production levels? Or can we expect any additional operating expenses from the usage of the new Promigas pipeline?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [6]

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Thank you, María. With respect to the Promigas question regarding the Promigas pipeline, there are 2 modifications that have been submitted by Promigas to the ANLA for the section Jobo, Majaguas. These 2 modifications involve approximately 1.5 kilometers of the 85-kilometer stretch where it is necessary to drill under some existing infrastructure. Those modifications were submitted late last year, and those modifications are expected to come out of the ANLA within the next month, in the month of April. Again, those modifications effect very, very small component of the pipeline route and construction of the remainder of the pipeline is currently underway, as you can see from the presentation. With respect to the second question on OpEx, I'll turn that over to Jason.

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Jason Michael Bednar, Canacol Energy Ltd - CFO [7]

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Sure. Yes, you're right, María. Our OpEx has been going down sequentially as our production rises, and that will continue throughout 2019, specifically, once the Promigas line is turned on and we're able to produce at rates of approximately 215 million cubic feet a day. Our models will be that, that Gas OpEx will be approximately $0.30 in Mcf. We're not anticipating any increased OpEx related to new Promigas line. Of course, those are transportation charges that we always quote, our revenue net of transportation, which we pass through to the offtakers and that revenue net of transportation, as you can see, has been growing sequentially every quarter on an Mcf basis.

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Operator [8]

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Our next question comes from Miguel Ospina from Compass.

Why is your average sale price for January and February 2019 at $4.99 per Mcf. Is it sustainable?

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Jason Michael Bednar, Canacol Energy Ltd - CFO [9]

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So as we've discussed on previous calls, even though we have a large portfolio of contracts, multi-year contracts, we do leave about 10% of our Gas production available for sale in the spot market. So during these 2 particular months, and indeed even in Q4, the sales that we were achieving on that 10% that is sold into a stock market -- sorry, the spot market were at a significantly higher rate.

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Operator [10]

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Our next question comes from Shahin Amini of Pareto Securities.

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Shahin Amini, Pareto Securities, Research Division - Analyst [11]

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Two questions, please. First on your capital expenditure. Looking forward to potentially selling 300 million stocks per day in late 2021, 2022, ahead of that and what is the level of drilling expenditure that I should be thinking about in order to get you to that point where you can satisfy that demand? And the second question as well as your national -- your share buyback that you announced late last year, do you have any other plans for potential return of capital to shareholders in the near term?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [12]

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Thanks, Shahin. With respect to the new pipeline project that I mentioned either to Medellin or Cartagena that will add approximately 100 million standard cubic feet per day taking gross sales over 300. From the perspective of Gas treatment facilities, the expansion that Ravi discussed of the Jobo-3 takes us to a total processing capacity of 330 million standard cubic feet per day now. So we have more than sufficient processing capacity for that new pipeline project. And with respect to our current well potential going through that facility, we have -- with the current wells we have tied in to facilities, we have between 280 million to 290 million standard cubic feet per day right now of productive potential from the existing well. So I anticipate that going forward through 2019, 2020 and 2021, we will probably maintain a fairly constant rate of drilling between 8 to 10 wells per year. So I would expect that our CapEx associated with that will not be too different than the CapEx we saw last year or this year for that well count. So I don't expect a massive drilling campaign required to bring us up to that 300-million-plus level of productive capacity. With respect to the share buyback and other shareholder in issues we're contemplating, we did continue the share buyback through Q4 of last year and in Q1 of this year, we continued to buy back shares. We are contemplating now with respect to the timing of the Promigas expansion where we will formally take a decision. We'll wait to see that happen in June, and we will be considering the potential of a dividend issued to shareholders, either continuous regular dividend or special dividend. So we will take that decision once we have seen the production bump coming here at us in June of 2019.

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Jason Michael Bednar, Canacol Energy Ltd - CFO [13]

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Just a bit more color on the normal course (inaudible). So to date, we bought 674,000 shares at an average price of $4.15, which would then total CAD 2.8 million.

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Shahin Amini, Pareto Securities, Research Division - Analyst [14]

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That's very helpful. Just a very quick follow-on on the capital expenditure for this year. You got $60 million of 3D seismic. When do you expect that to be spent?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [15]

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The 3D seismic is currently underway. We're in the field. We should start recording that program probably in early June. So we expect that entire budget for the 3D seismic to be executed through the summertime.

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Operator [16]

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Our next question comes from Josef Schachter of Schachter Energy Research.

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Josef I. Schachter, Schachter Energy Research Services Inc. - Author & President [17]

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First one is, you mentioned earlier about the spot market with that January, February increase of $7 million a day. Are you going to be looking at increasing your spot percentages from 10% to a higher level as you increase your production starting this summer?

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Jason Michael Bednar, Canacol Energy Ltd - CFO [18]

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Josef, no. I mean, we leave about 10% of our production available for the spot, so the rest is contracted. So there will be -- there is little room to increase and pass that. And the basic reason for the increase in the prices achieved on those spot sales was a bit of an El Niño year here and as such, more demand for that Gas.

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Josef I. Schachter, Schachter Energy Research Services Inc. - Author & President [19]

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Okay. And my second question is given the rights of way to go to Barranquilla place where the expansion that Promisol is doing, with -- isn't that going to be much easier? Or is there rights of way going to Medellin? Or do you have to go through a very lengthy environmental process to get the line to go to Medellin? And as you said, you mentioned you're going to be looking at doing that over the coming months. Do you have to go through any of the same regulatory anguish that we do in Canada? Or is there's something that's a lot speedier and that the process is one you think would be smooth to give you an equal opportunity to go to Medellin?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [20]

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Yes, Josef. It's Charle here. The 2 routes are quite different. The route to Medellin is approximately 300 kilometers in length. It involves mountainous terrain, large river crossings, the Cauca river, which is a very large river, of course, in Colombia. The route to Cartagena is in floodplain, very flat manageable floodplain. Multiple geography that's difficult to contemplate and the route is about 185 to 200 kilometers. Cartagena is a little shorter. The process is the same in either case. What's required, of course, is a license and some community consultations. Those take approximately 1 year to do and would be the same in either case. So both the routes present different challenges in respect to construction. The environmental permitting is identical. And really, from our perspective, the main criteria is the future market potentials between those 2 locations. The coast, we understand very well and have a very clear perspective with respect to what the future market trends look like in terms of demand and pricing. The interior is a much -- is a larger market for us with different types of dynamics that we're currently analyzing in terms of the 10-year market potential there. So that's really the main criteria we're looking at. Not just the route, but also which is the better market to feed into and should we go to Medellin to diversify our client base, which is currently located on the coast.

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Josef I. Schachter, Schachter Energy Research Services Inc. - Author & President [21]

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But the time line for approval of either route would be about the same amount of time?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [22]

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That's correct.

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Operator [23]

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Our next question comes from Jenny Xenos of Canaccord Genuity.

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Jenny Xenos, Canaccord Genuity Limited, Research Division - Analyst of Energy [24]

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Most of my questions have been answered. Maybe just one quick one, please. With the Jobo-3 Gas treatment plant construction now completed and the Pandereta-to-Jobo flowline now also completed, what infrastructure projects are there remaining before the Promigas expansion comes on? And have all the major fields now been tied in?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [25]

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Well, there is 2 that are scheduled for this year. One is a additional flowline from Clarinete to Jobo to debottleneck those wells, and the second one is in the Acordeon success case tying in the Acordeon wells to the Pandereta flowline.

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Operator [26]

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(Operator Instructions)

Our next question is from an online submission. Could you please provide some color regarding whether you have considered any planned reduction of debt levels going forward? Or are you comfortable with the continued increasing debt levels?

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Jason Michael Bednar, Canacol Energy Ltd - CFO [27]

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Okay. So first of all, I don't think our debt levels have been increasing if you look at it on a net of the cash on the balance sheet basis. I believe they've been relatively consistent for a couple of years now. Meanwhile, our production base is certainly growing. So perhaps one -- the way that I would look at that is, what is your debt to your EBITDA, right. So currently, it's about 2.5:1. And when the Promigas pipeline comes on by year-end, it will be 1.5:1, right. So in relation to our production, our debt levels are shrinking maturely throughout 2019. I also explained the swap of the Promigas Promisol financed lease for the new Crédit Suisse term debt. Once again, that was not an increase in debt, but rather a swap different debt, and at a 6.875% rate it was a good piece of business. And of course, earlier in the year, to refresh everyone's memory, we did the $320 million bond deal with a 7-year term maturing in May 2025. That's at 7.25%. So it puts us in a very good spot to not worry about debt payments for the near term, which, of course, has allowed us to go from 100 million cubic feet a day to 230 million cubic feet a day, and then 230 on a new pipeline sale discussed from 230 to potentially yield over 300 million cubic feet a day. So I think our debt levels are at appropriate ranges for a company of our size and our production base.

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Operator [28]

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Our next question comes from Daniel Guardiola of BTG.

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Daniel Guardiola, Banco BTG Pactual S.A., Research Division - Director of Equity Research [29]

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I have a very brief question on Venezuela. I would like to know if you could share your thoughts on Venezuela and if a potential political change in this country, which is -- could be an opportunity or either a threat for Canacol?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [30]

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I'm sorry, I believe the question was, is Venezuela a threat to -- could you please repeat the question, I'm sorry we didn't hear that very well. Sorry.

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Daniel Guardiola, Banco BTG Pactual S.A., Research Division - Director of Equity Research [31]

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Sure, sure, Charles. I mean, bearing in mind that once again a political change in regime in Venezuela is grabbing the headlines, I would like to know if you could share your thoughts, if a political change in this country could be an opportunity or a threat for you guys?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [32]

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Yes, very good -- sorry, I understand the question now. Thank you for clarifying that. Yes, obviously, the expectation is that something may change in Venezuela within the near- to mid-term. Venezuela, of course, is a very -- has the potential to produce a great amount of oil and Gas. Obviously, with respect to any potential improvement in the climate in Venezuela that would be conducive to companies investing in Venezuela, that's where we'll be required to increase oil and Gas production there. So from 2 perspectives, we, of course, as Canacol will be very interested in getting into the Venezuelan market to apply some of our expertise with respect to Gas exploration and commercialization in Venezuela, should the situation change there. On the oil side, we would not be particularly interested obviously. But finally, with respect to the possibility of importing Venezuelan Gas into Colombia as well, that would be part of our strategy, of course, going into Venezuela, take advantage of the pipeline that connects to Maracaibo to the La Guajira. But in any event, given the situation currently in Venezuela, given the need for massive amounts of investment in Venezuela to increase production, should a change occur there, I don't see much in the way of opportunity within the short-term, but certainly potential opportunity within the 5- to 10-year period. Obviously, a lot of that investment that might go into Venezuela as a result of that change will be utilized in Venezuela. Again, Venezuela has its own consumption concerning Gas which needs to be addressed both industrially and commercially. So I don't expect any export potential out of Venezuela to Colombia within the current 5- or 6-year timeframe. But after that, there is potential for that.

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Operator [33]

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Our next question comes from [Andres Echeverria of Ultraserfinco]

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Unidentified Analyst, [34]

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Yes, I basically have 2 questions. The first one is, can you explain as what happened this quarter with the deferred taxes? And the second one is when do you plan to sell your participation in Rancho Hermoso?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [35]

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Okay. I'll let Jason explain the first question.

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Jason Michael Bednar, Canacol Energy Ltd - CFO [36]

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Yes. So this quarter, deferred taxes, we had written off certain blocks and they're taken out of the asset balance compared to the taxable balance. So it alluded that there is change in deferred tax related to that. And additionally, I guess, the most difficult thing to project in any model for deferred tax is the FX change, right. So just to back up a step, deferred tax is basically you're looking at your balance sheet assets compared to what it is on your tax returns. And of course, on your tax returns in Colombia, they're denominated in pesos. So now you need to convert that to U.S. dollars. Point there being is, as the Colombian peso to U.S. dollar exchange rate varies that will generate deferred tax positives or negatives, which, of course, is nearly impossible to predict.

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [37]

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With respect to your second question, the Rancho Hermoso oilfield, which was -- it actually was our first producing asset in Colombia -- oil producing asset and now is our last oil producing asset in Colombia quite fittingly, I guess. We're currently in discussions with a number of parties, all Colombian -- local Colombian operators who are interested in purchasing that asset. They're currently in our data rooms, doing an analysis of that deal and we expect to be completed that process by the end of April or mid-May. So the intention is to get the Rancho Hermoso asset off of our balance sheet certainly by the end of June.

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Operator [38]

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Our next question is a follow-up from Shahin Amini of Pareto Securities.

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Shahin Amini, Pareto Securities, Research Division - Analyst [39]

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Just -- apologies if you've covered this already, but can you give an update on your unconventional oil activities? And what could be a potential expenditure on that front sale over the next couple of years?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [40]

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Shahin, was your question regarding conventional or unconventional oil activities?

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Shahin Amini, Pareto Securities, Research Division - Analyst [41]

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Unconventional.

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [42]

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Yes, thank you. Thank you for that clarification. Yes, as you know, we have interest in 2 blocks located in the Middle Magdalena Valley, VMM2 and VMM3, which are operated by ConocoPhillips. Both of those blocks are operated under an unconventional license, a contract with the ANH. As you know, both of those blocks had significant potential for shale oil, which has been demonstrated on a technical basis and on a production basis from one of the Pico Plata well, which we stimulated a couple of years ago. What's happened in Colombia here regarding the development of unconventional deposits, there was a special committee assembled last quarter to weigh in on the pathway towards unconventional development by the government of Colombia. That committee announced its conclusions in February, which was to proceed with a number of pilot projects carefully monitored to monitor the environmental impacts of utilizing massive hydraulic stimulation. So that was sort of passed through the government and received very warmly. As was announced a couple days ago, Conoco and ourselves in 2017 applied to the ANLA, which is the environmental authority for 2 licenses for 2 separate pilots. One on each block. Those licenses would have covered the drilling of up to 6 horizontal wells in each pilot and the stimulation of each of those wells. And those applications were rejected by the environmental authority in November of last year. So despite the Colombian government being relatively supportive of the concept of moving forward with pilot projects, the environmental authority rejected those 2 applications that were submitted to -- and by Conoco and ourselves. And we're currently evaluating with our partners the path forward. It's anticipated that Ecopetrol currently is in the process of obtaining those permits and perhaps will obtain them with better results than we did. So at the moment, I must say both of our projects with ConocoPhillips, both of those contracts are essentially in force majeure awaiting an assessment on our part of how to proceed forward with new applications for those pilots.

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Operator [43]

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Our next question is from an online submission. How do you see the probability of Colombian government approving fracking? And what plans do you have for VIM-5?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [44]

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So I just covered that with my response to Shahin, I think. Again, I think the Colombian government is very supportive of moving forward with the application of these technologies to this resource. However, under a very strict environmental criteria, which I believe are still being formulated by the Ministry of the Environment. So I believe that eventually those licenses will be granted to Ecopetrol and ourselves for application on the VMM2 and VMM3 contracts. With respect to VIM-5, which is located in the Lower Magdalena Valley, these blocks, all of our gas production is conventional production. So we do not utilize any hydraulic stimulation whatsoever with respect to developing those conventional Gas resources. So we have no plans to deploy any nonconventional techniques to our conventional exploration Gas plants.

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Operator [45]

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Our next question is a follow-up from Josef Schachter of Schachter Energy Research.

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Josef I. Schachter, Schachter Energy Research Services Inc. - Author & President [46]

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If you have success with your drill program this year, would you look at both -- and if the seismic that you do this summer continues to show you positive anomalies to drill, would you be looking forward to going on a dual program of both moving for the pipeline to the north as well as working on the Medellin leg of it, if you have sufficient reserves to backstop looking at both options?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [47]

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No, we wouldn't. We're only planning the one pipeline, Josef, either north or south. But -- however, if we continued in 2020 and 2022, continued to build our reserve base at the rate that we have been building it out over the past 5 years, I think when we're halfway through the project, we're contemplating for 2021-2022. So sometime at the end of 2020, early 2021, we could conceivably -- based on very positive outcomes from our 2019 and 2020 exploration programs, we could conceivably be planning another route in 2024 to those markets. But at the moment, we're sort of only planning 1 pipeline to accommodate an additional 100 million standard cubic feet per day targeting delivery in 2021 -- late 2021, early 2022.

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Josef I. Schachter, Schachter Energy Research Services Inc. - Author & President [48]

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Okay. So more manageable steps. And if there is excess cash flow, the NCIB or dividend as you mentioned earlier?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [49]

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That's correct, Josef.

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Operator [50]

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This concludes our question-and-answer session. I would like to turn the conference back over to management for any closing remarks.

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Carolina Orozco, Canacol Energy Ltd - Director of IR [51]

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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 2019 conference call. Have a great day.

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Operator [52]

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The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.