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Edited Transcript of CNE.TO earnings conference call or presentation 9-Aug-19 3:00pm GMT

Q2 2019 Canacol Energy Ltd Earnings Call

Calgary Aug 19, 2019 (Thomson StreetEvents) -- Edited Transcript of Canacol Energy Ltd earnings conference call or presentation Friday, August 9, 2019 at 3:00:00pm 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

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Conference Call Participants

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* Jenny Xenos

Canaccord Genuity Corp., Research Division - Analyst of Energy

* Luiz Carvalho

UBS Investment Bank, Research Division - Director and Analyst

* Nicolas Erazo;Credicorp Capital;Analyst

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Presentation

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Operator [1]

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Hello, and welcome to the Canacol Energy Second Quarter 2019 Earnings Conference Call. (Operator Instructions) Please note this event is being recorded.

I would now like to 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 Second Quarter 2019 Earnings Conference Call. This is Carolina Orozco, Director of Investor Relations. I am with Mr. Charle Gamba, President and Chief Executive Officer; and Mr. Jason Bednar, Chief Financial Officer.

We would like to apologize that there was a mistake in the link to join the webcast. We just sent an e-mail with the correct link to our distribution list. If you can't access, please send us an e-mail, and we will sent it to you immediately.

Before we begin, it is important to mention that the comments on this call by Canacol senior management can include projections of the Corporation's future performance. These projections neither constitute any commitment as to future results nor take into account risks or uncertainties that could materialize. As a result, Canacol assumes no responsibility in the event that future results are different from the projections shared on this conference call. Please note that all finance figures on this call are denominated in U.S. dollars.

We will begin the presentation with our President and CEO, Mr. Charle Gamba, who will cover the operational highlights for the second quarter 2019. Mr. Jason Bednar, our CFO, will then discuss financial highlights. Mr. Gamba is joining us from Bogota and Mr. Bednar is joining us from Calgary.

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 our second quarter 2019 conference call. Q2 marked another solid quarter of natural gas sales growth and industry-leading finding and development costs, where we increased our realized contractual gas sales by 8% to 121 million standard cubic feet per day, up from the 112 million standard cubic feet per day during the same period reported in 2018.

In late-July, we announced that the works associated with the expansion of the gas pipeline between our operated Jobo gas plant and Cartagena was completed. These works include delaying of 85 kilometers of new 20-inch pipeline and the addition of installation of compression at the Filadelfia station. Both resulted in an increase of 100 million standard cubic feet per day of transportation capacity for the Corporation to its clients in Cartagena and Barranquilla. The Corporation anticipates total corporate sales of 215 million standard cubic feet per day will be achieved by mid-August 2019, and this level of sales is anticipated to be maintained for the remainder of the year.

Sales this week have been up to 180 million standard cubic feet per day as the line filling continues.

The completion of this part of the pipeline expansion marks a significant milestone in our initiative to commercialize our large natural gas resource base in Colombia. In addition to this important objective having been realized, the Corporation has also delivered very good results from its exploration and development drilling program in the second quarter, with 2 new discoveries having been made in the first half of this year.

We have also made very good progress on structuring the new pipeline project in Medellin, which we anticipate to close in the third quarter of this year.

We also increased our average natural gas operating netback by 2% to USD 3.88 per thousand cubic feet, up from $3.81 per thousand cubic feet in the same period of 2018. The increase is mainly attributable to a 26 -- 26% reduction of operating expenses to $0.31 per Mcf for the 3 months ended June 30, 2019, compared to $0.42 per Mcf for the same period in 2018.

Second quarter also saw a strong start to our 2019 exploration drilling program as we hit on the first 2 of 4 planned exploration wells for 2019, with the Acordeon-1 discovery, testing 33 million standard cubic feet per day; and the Ocarina-1 discovery, testing 30 million standard cubic feet per day. These wells have been tied into the Jobo production facility near the Pandereta flowline and are now on permanent production.

On a historical basis, Canacol had achieved an 85% commercial success rate in its gas exploration drilling programs, which is really remarkable for an onshore conventional gas play. Our commercial success rate on gas appraisal and development drilling is 100%. These statistics bode well for the future drilling of the over 140 exploration prospects in a lease we have identified on our 1.1 million-acre exploration position in the Lower Magdalena Basin of Colombia.

In June 2019, the expansion of the Jobo 3 natural gas processing facility was completed, lifting Canacol's natural gas treatment capacity from 200 million standard cubic feet to a current capacity of 330 million standard cubic feet per day. With the existing wells we now have tied into the Jobo facility, we now have the productive capacity to deliver 330 million standard cubic feet per day, well above the forecast level of 215 million standard cubic feet per day of gas production anticipated for the remainder of the year.

I'd 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 second quarter 2019 results. When he is done, I will provide the outlook for the remainder of 2019.

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Jason Michael Bednar, Canacol Energy Ltd - CFO [4]

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Thanks, Charle. Success continued in Q2 2019 for Canacol both operationally and financially as we continue to execute our plan to drive our growing natural gas business forward.

For the quarter ended June 30, 2019, total realized contractual gas sales were 21,499 BOE per day, including 120.5 million cubic feet of gas a day, and 356 barrels of oil a day on average throughout the quarter.

The 120.5 million cubic feet of gas sales per day was an 8% increase over the 111.9 million cubic feet that we averaged in the second quarter of 2018. The increase in natural gas sales is due to Sabanas pipeline and compressors now operating at full capacity, which it was not in the first half of 2018. During the quarter, gas sales were marginally impacted by several off-takers exercising their contractually allowed downtime.

Now that the expansion of the gas pipeline between Canacol's Jobo gas processing facility and Cartagena has been completed, we anticipate total realized contractual sales to increase by 78% from 120.5 million cubic feet per day average for Q2 2019 to 215 million cubic feet per day by mid-August 2019.

Total natural gas revenue net of royalties and transportation expenses for the 3 and 6 months ended June 30, 2019, increased 8% and 15% to $45.7 million and $93.1 million respectively, compared to the $42.4 million and $81.1 million for the same periods in 2018, mainly attributable to this increase in natural gas sales.

The Corporation realized an EBITDAX of $37 million and $76.8 million for the 3 and 6 months ended at June 30 here compared to the $33.6 million and $67.2 million for the same periods in 2018, despite the inclusion of 1,900 barrels of oil sales in the 2018 figures. The vast majority of the oil production was sold in the Arrow transaction, which closed in September of 2018, and hence not in the 2019 numbers.

The Corporation reported net income of $8.2 million for the 6 months ended June 30, 2019, compared to a net loss of $17.7 million for the same period in 2018. Quarterly net income is anticipated to rise substantially now that the natural gas production is ramping up as a result of the completion of this Promigas pipeline.

Funds from operations increased 11% to $65.5 million for the 6 months ended June 30, 2019, compared to $49.8 million for the same period in 2018, once again, despite the disposition of substantially all the Corporation's oil assets.

Net capital expenditures for the 3 and 6 months ended June 30, 2019, were $13.4 million and $48.2 million. Net capital expenditures were net of the $14.5 million disposition of working interest in the Sabanas flowline during the 3 and 6 months ended June 30, 2019, which netted the Corporation a positive cash return on its investments.

Net capital expenditures during the 3 months ended June 30 are primarily related to, first of all, the drilling of the Nelson-7, Acordeon-1 and Ocarina-1 wells; the start of the 155 square kilometer new 3D seismic program on the VIM-5 block, which will firm up a new set of prospects heading into the Corporation's 2020 drilling campaign; thirdly, facilities costs at Esperanza and the VIM-5 block, including the final completion of Jobo 3; and lastly, the disposition of the Corporation's working interest in the Sabanas pipeline, as just discussed.

The $48.2 million of net capital expenditures for the 6-month period included noncash additions of $7.4 million, mainly due to the adoption of IFRS 16, thus leaving real net cash additions of $40.8 million, which represents a net spend of only 74% of our funds from operations, which were $55.5 million for the same 6-month period.

For Q2 2019, total natural gas operating expenses per Mcf decreased 26% to $0.31 in Mcf, for the 3 months ended June 30 compared to $.42 for the same period in 2018. The decrease is primarily attributable to the purchase and operation of the Jobo 2 gas plant and other operating efficiencies. The majority 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 with greater realized contractual sales starting this month.

G&A expenses per BOE decreased 20% during the 3 months ended June 30, 2019, compared to the same period in 2018. The decrease is primarily due to cost efficiencies and increased natural gas sales. The G&A per Mcf is expected to continue to decrease as the Corporation sales base grows for the remainder of 2019 and into 2020 now that the new Promigas pipeline has been completed.

Gas sales price net of transportation of $4.83 per Mcf and $4.90 per Mcf for the 3 and 6 months ended June 30, 2019, were both ahead of our previously announced guidance of $4.75 per Mcf. These sales prices, in conduction with our dramatically decreased operating costs, led to very healthy netbacks of $3.88 per Mcf and $3.96 per Mcf, once again, both higher than anticipated.

As at June 30, 2019, the company had $28.7 million in cash plus $4.6 million in restricted cash and the working capital surplus of $47.1 million. For the remaining 6 months of the year, the Corporation anticipates its spending to be within the projected funds from operations, thus ensuring a healthy cash and working capital surplus heading into 2020.

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

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [5]

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Thanks, Jason. For the remainder of 2019, the Corporation is focused on executing our exploration and development drilling program and executing the necessary agreements related to the construction of a new gas pipeline to Medellin, which will transfer 100 million standard cubic feet per day of new gas sales in late 2022.

The remainder of the drilling program includes the Pandereta-5 appraisal well, which is currently being drilled, to be followed by the Clarinete-4 appraisal well and the Porro Norte-1 and our Arándala-1 exploration wells through to year-end.

Pandereta-5 is placed in the western expansion of the Pandereta field, which has been in production since 2017, and could represent an important reserves add, if successful. We expect results from this well within the next 3 weeks.

With respect to the Medellin pipeline project, the Corporation anticipates executing a take-or-pay contract with a major Colombia utility during the month of August 2019, whereby half of the capacity of the 100 million standard cubic feet per day pipeline will be contracted for a period of 10 years.

The next step, to be completed by the end of third quarter 2019, will be to form the consortium which will build and operate the pipeline, with entrance of the pipeline into operation anticipated in late 2022.

That concludes my remarks concerning the outlook. Carolina?

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Carolina Orozco, Canacol Energy Ltd - Director of IR [6]

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Gabby, please go ahead with Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions) The first question comes from Luiz Carvalho with UBS.

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

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I have basically three questions. The first one, how can I say it, what are the prices in respect to the netbacks that are being negotiated in the Medellin contract -- or the contracts from the -- from Medellin pipeline? The second question is -- I mean, do you have any idea on who will be buying the, let's say, these additional 50,000 cubic feet per day from Medellin pipeline that are still not contracted?

And the third question, Charle, maybe you can help us on this. I mean, Canacol now is basically -- I mean with a large production that is already contracted, and I just wonder why -- how do you see Canacol potentially shifting from a pure E&P company towards more utilities and even potentially trading at much higher multiples than what the stock is trading currently right now?

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

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Thank you. Can you -- I apologize, but can you repeat the first question you had? I didn't quite catch it.

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Luiz Carvalho, UBS Investment Bank, Research Division - Director and Analyst [4]

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Yes. I mean, the first question is basically the price, if you can share the price with respect to the netbacks that are being negotiated in the, let's say, with the Medellin pipeline?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [5]

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Okay. Thank you. I understand. Okay, with respect to the pricing of the contracts we're negotiating in Medellin, we expect very similar wellhead pricing to what we currently enjoy, which I would say ranges from $4.80 per MMBtu to $5.20 per MMBtu. So that's the range of pricing we're negotiating at the wellhead. There, of course, is transportation on top of that, which the client is responsible for paying for.

With respect to your second point, concerning other clients in Medellin. There are other gas -- commercial gas consumers as well as vehicular gas consumers and investor consumers in Medellin what we're currently negotiating with, which represents a potentially interesting market. And we're also looking at the possibility of exporting the remaining pipeline capacity, which will be the 50 million into the TGI pipeline network via Transmetano to Sebastopol. So we're looking at various options to either leave all of the gas in Medellin, the full 100 million or leave part of the gas in Medellin and transport the remainder of the gas for injection into TGI in Sebastopol.

And finally, with respect to your question concerning how we migrate towards becoming more of a utility-type play, given the nature of our long-term fixed contracts, I think that's a very interesting question and a very interesting observation. And I think that as we continue to deliver fairly consistent income with respect -- which reflects the stable pricing of our contracts, I think we'll see more of a transition towards that, perhaps, also with the commencement of a dividend program, which we contemplated for later this year as well.

And finally, as we announced or as we've discussed in the past, we are looking at entering the power generation sector here in Colombia as well which, of course, would be a pure utility-type component in a way of commercializing some of the stranded gas we have that we cannot put into the pipeline due to restricted capacity.

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Operator [6]

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The next question comes from Nicolas Erazo with CrediCorp Capital.

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Nicolas Erazo;Credicorp Capital;Analyst, [7]

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For the moment, I'm interested to discuss about the new project in a thermal plant. In an interview made by Mr. Gamba, announcement yesterday, just your comment about that in the question of UBS. This project will be developed for a total investment of $150 million, with a 25% stake with this for Canacol. So I want to know which players would you develop this project with? And what are your expectations about these projects in terms of cash flow generation?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [8]

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Sure, Nicolas. Okay. Thank you. Yes. We did participate in a public bidding round, public process here in Colombia in March, which was related to the generation of 2,250 megawatts, in total, of new electricity for January of 2023. This was offered by the Colombian government, under the Cargo por Confiabilidad, which is essentially the backup generative capacity during future El Niños.

So we participated in that round with a consortium, which consisted of Celsia, which is a very large power generating entity in Colombia; and [Ethos], which also has power generation that we sell gas to in Cartagena. Canacol put the 10% stake in that consortium. But more importantly, we signed the gas contract to that consortium, whereby we would provide gas to the power plant, which is a 200-megawatt power plant, when it comes into commission in 2023 and when it is required to dispatch under the Cargo por Confiabilidad.

So a very special project, not a project that generates on a continuous basis. Again, this is simply a backup generation project, which is essentially subsidized by the Colombian government in terms of a flat tariff to be always on standby, and then the capacity to generate when required to dispatch.

Aside from that project, we're also looking now at another project, more of a project towards continuous electrical dispatch. There've been number of factors influencing electrical generation in Colombia, most importantly the failure to enter into generation of the Hidroituango hydroelectric project in December of last year, which has now been delayed until 2022 or 2024. So there is a perceived shortfall in electrical generation capacity going forward, given that electrical demand has been increasing at 3% to 4% per year here recently as the economy expands.

So one way that we see of commercializing some of our reserves that cannot be commercialized due to the lack of pipeline transportation is to construct the thermal power plant's inner gas fields essentially and generate electricity and dispatch it.

This, of course, has many advantages. It helps us commercialize our gas in that we do not require a pipeline. The cost of electricity is an interesting component to analyze. It is a very heavily regulated market in Colombia, and we're currently analyzing this type of a project, both from the perspective of the current regulation as well as potential partners to invest with us in this project, and then of course consumers or clients that we can sell electricity to in -- via the national grid.

So it's really in its early phase here. We basically started a study of the regulatory environment and have started preliminary discussions with potential clients as well as consortium members. So I think that's a pretty a fulsome answer with respect to our entrance into the electrical generation side of commercializing gas and what our future plans might look like going forward.

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Operator [9]

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The next question comes from Ricardo (inaudible) Bancocolombia.

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Unidentified Analyst, [10]

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Just a quick follow-up on the question about the thermal power generation plants. I'm wondering if you have -- if you may have any target return for this new electric business?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [11]

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I'm sorry, could you repeat the question, Ricardo?

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Unidentified Analyst, [12]

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Sure. Do you have any target return for this new business? I mean, if you have any annual return target as a potential -- as a percentage of the equity or of the capital invested?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [13]

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Okay. Understood, Ricardo. Well, it's sort of interesting to us in 2 perspectives. The first is we sell gas to the consortium that operates the thermal plant, correct? So we, Canacol, receive a dollar price for MMBtu for the gas that we put into the plant. So that's one revenue stream.

And the second revenue stream is, as partners, and we are limited under regulation here in Colombia to only being allowed to participate up to 25% of a consortium, generating electricity. So as partners in the actual generation and sales of electricity, we received 25% of the profit related to the sale of electricity as well.

So those are 2 components of revenues we're looking at. On the one side is the revenues from the gas sales, which we're very familiar with obviously. And on the second, there's the revenues from the electrical sales. I might add that given that significant proponent -- component of the cost of gas for normal generating companies in Cartagena, for example, is actually related to the transportation tariff of that gas that is paid to ship the gas along the pipelines, yes? so in the case of putting the plant in the field, a very significant component of the cost of that gas that is normally paid by thermal electric companies is eliminated because there's no transportation required.

So this project looks very economic. From the gas sales side of the equation, a 200-megawatt plant will consume up to 40 million cubic feet per day. So if we're looking at wellhead prices around our current pricing, that's a significant income for the company. And then given the fact that there's no transportation costs associated with that gas, the margin on the electrical generation should be pretty good as well. So really, those are the 2 revenue streams we're analyzing. The first, we know very well, of course, which is gas sales. The second less familiar with the electrical side of the equation in terms of sales, but we've contracted industry experts here in Colombia to assist us with that analysis.

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Operator [14]

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The next question comes from Jenny Xenos with Canaccord Genuity.

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Jenny Xenos, Canaccord Genuity Corp., Research Division - Analyst of Energy [15]

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Most of my questions have been answered, but maybe just a couple with regards to the exploration and appraisal program for the rest of the year. I'm wondering about the Porro Norte target. I can see that it's targeting 3 stacked reservoirs. CDO, which we're very familiar with; and then Cicuco and Tubara, I believe as well, we've seen before. Could you share with us please what is the size of the overall target here?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [16]

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Yes. We're looking at 3 stacked targets, the CDO and the Cicuco are the 2 main production targets in the area. There's good upside analyzed to those, but Tubara not so. But we're looking in the vicinity of around 40 Bcf of risk recoverable resource in our analysis. We're drilling off of 2D there, Jenny, as you know. So there's some risk associated with the seismic interpretation, given the fact we're drilling off of 2D seismic. Normally, we drill off 3D seismic, of course. But this is a fairly -- looks like a fairly straightforward 4-way closure across basement feature. And we did process the existing 2D lines for AVO, and we see fairly good indications of gas within the CDO and the Cicuco. So it is a little bit of a different type of target for us. This will be the very northerly most well we drilled on our VIM-5 block, so we're going well beyond our typical exploration area, and we're drilling off of 2D on this one as well.

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Jenny Xenos, Canaccord Genuity Corp., Research Division - Analyst of Energy [17]

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Okay, great. And whatever happened with Canahuate-2 and -3 appraisal wells? I believe the 2 was drilled last year. And 3 was initially planned for this year, and then the 2 were supposed to be tested at the same time. And then they seemed to have been either delayed or canceled. Could you share with us please whatever happened with those wells?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [18]

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The Canahuate-3, we just put it on to production. Or we're just about to put it on production. We just finished connecting it basically, so it should come on to production within the next 1 or 2 weeks basically. So that will be on permanent production shortly. And the remaining Canahuate well, we plan to drill in next year's drilling program, at some point during next year.

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Jenny Xenos, Canaccord Genuity Corp., Research Division - Analyst of Energy [19]

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Okay. Great. And finally, what is the current status of your Rancho Hermoso asset sale?

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

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We're currently finalizing -- the party that's under exclusivity is currently finalizing their legal due diligence, and we expect to transact by the end of third quarter. So we expect to dispose of that asset and close the deal by the end of third quarter, end of September.

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Operator [21]

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The next questions are coming from the webcast.

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Carolina Orozco, Canacol Energy Ltd - Director of IR [22]

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We received a question from [Eric Pool] which says, hello, Charle, congratulations for the accomplishments to date. How worried are you that offshore natural gas will flood the Colombian market and drive domestic natural gas prices down?

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Charle A. Gamba, Canacol Energy Ltd - President, CEO & Director [23]

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Eric, thank you for that question. There have been a number of discoveries announced in the Deepwater of the Caribbean off the cost of Northern Colombia. Most recently, Anadarko, 2 or 3 years ago, announced a gas discovery and Ecopetrol and Repsol have announced a couple of gas discoveries prior to that.

So there is, obviously, gas in the Colombian offshore. The issues concerning that gas and in terms of the commercial issues, there are 2 issues. The first is, these are single well discoveries, so no -- there's no real confidence in the size of each of these discoveries because they've not been appraised or even flow tested, if you can imagine that.

These wells were very expensive, up to $250 million, to drill. The second issue with these discoveries is that they're located in very deep water, 2,000 meters of water, which would make them the deepest dry gas discoveries in the world, basically. So these are ultradeep water of uncertain size. So both of those issues need to be resolved. First, with appraisal drilling of these discoveries, which may or may not happen within the next couple of years. And then if a discovery is appraised and is deemed to be of sufficient size, which in these water depths, would have to be multi-Bcf discoveries, then these would have to be commercialized. So these would require billions of dollars of investment in terms of drilling and offshore subsea completions. And then tiebacks into the domestic network. We're talking 200 to 300 kilometer-tiebacks from offshore to onshore. So we're looking at very long time lines to develop, probably 8 to 10 years to develop these from the appraisal, proving them up; and then very expensive gas in terms of the gas landing onshore.

So from our perspective, our window really is in the 1- to the 10-year time frame to develop our onshore gas reserves, and we don't see any threat whatsoever from these ultradeep water discoveries on our business within the next 10 years.

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Carolina Orozco, Canacol Energy Ltd - Director of IR [24]

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We have one final question from Gage Jull from Bordeaux Capital.

Congratulations on a great quarter. Is the 26% decline in operating cost a result of compression running at capacity? What other factors are driving this efficiency?

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Jason Michael Bednar, Canacol Energy Ltd - CFO [25]

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Thank you, Carolina. I can handle this one, Charle. So first of all, most of our operating costs are fixed, so hence the 8% year-over-year production increase would certainly account for part of the 26% reduction in OpEx.

Secondly, and most importantly on the list here is, Jobo 2 used to be contract operated, and that was one of the reasons why we bought it out, 2 reasons. First one was a lower interest rate on the terms and the second one was that we now operate Jobo 2. And we've managed to save about $2.5 million per year on the operation of Jobo 2 compared to the prior contact operator as basically, we constantly look for efficiencies in there.

And thirdly, and I guess the most minor one, is the adoption of IFRS 16, which basically capitalized leases, ends up saving a couple pennies on this number also. So it's the combination of those 3.

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Carolina Orozco, Canacol Energy Ltd - Director of IR [26]

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Thank you, Jason. And thanks, everyone, for participating in Canacol's second quarter conference call. Please join us again in November for our third quarter 2019 conference call. Have a great day.

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Operator [27]

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This concludes our question-and-answer session. I would like to turn the conference over to Carolina Orozco to see if there are any further final comments.

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Carolina Orozco, Canacol Energy Ltd - Director of IR [28]

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Thank you, Gabby. I think with this, we have concluded the conference call today.

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Operator [29]

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