Canacol Energy Ltd

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

Mr. Gamba, Mr.

Ravi and Mr. Bednar are joining us from the Delanco Bogota.

Mr. Gamba will close with the discussion of the Corporation's outlook for fiscal year 2019.

A Q&A session will follow Mr. Gamba's closing segment.

I will turn now 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 2018 conference call. Q4 2018 marked our fifth consecutive quarter of production growth, an 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 producers in Columbia 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 cubic standard feet per day, 6% higher than average gas sales for Q4 2018.

With respect to the pipeline expansion to Cartagena, Promigas is progressing on four separate constructions fronts on to Jobo to Cartagena segment, which includes the lane of approximately 85 kilometers of new 20-inch pipeline and the addition of compression to their Philadelphia 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 continue to deliver positive results in 2018, achieving a 232%, 2P reserves replacement ratio and 11% increase in our 2P gas reserves based to 559 billion cubic feet with a pretax value of $1.5 billion or CAD9.37 per share.

2P finding and development costs came in at an industry leading $0.32 per Mcf and $0.57 on Mcf for the one and three year periods ending December 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 number one amongst our publicly traded Columbian peers. Our gas exploration drilling results over the past five years have yielded an industry leading 80% hit rate of commercial discoveries, adding 481 Bcf for the 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 resources of 2.6 trillion cubic feet according to our resource report from Gaffney Cline and Associates date of April 2018. As such, we anticipate many more years of successful exploration drilling continue to build out our reserve base.

During the three months ended December 31, 2018, we completed the Nelson-13 development well on our Esperanza block. Nelson-13 is our 7th well drilled into the field which we discovered in 2011.

The well encountered 266 feet of net gas paying, the biggest gas paying encountered in any of the wells we 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 drill 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 Ciénaga de Oro sandstone reservoir and is currently being tied into the Palmer 1 manifold to be brought onto permanent production shortly. The Pioneer 302 drilling rig has been mobilized to drill the Nelson 7 development well, which is anticipating to spud of the end of this month.

Nelson 7 will take approximately five weeks drilling 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 operating 100% interest block VIM 5 and year end below one well expiration wells 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 well and on our operated 100% working interest Esperanza blcok. Flexibility has been built into the 2019 drilling programs 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.

Okay. So, on the facility side, in Q1 2019, we completed the construction of the Jobo-3 gas treatment plant, which is 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 a plan 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 flowline, which connects the three existing wells at Pandereta to our gas processing facility.

These three wells have a productive potential of approximately 75 million standard cubic feet per day based on the well test. We've also completed the debottlenecking of the Bretana to Jobo flowlines, which are two 6 inch flowlines that have the capacity to transport up 140 million standard cubic feet per day from the Nelson and Promigas 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'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 fourth quarter and fiscal year-end 2018 results. When he's done, Charle will provide the outlook for the remainder of 2019.

Thanks, Ravi. 2018 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.

For the year ended December 31, 2018, total realize 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 gas per day of 2018 sales, represents a 41% increase over the 80.5 million cubic feet that we the 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 reported approximately $105 million in funds from operations, a 62% increase in 2017. Focusing on the fourth quarter of 2018, financial highlights include natural gas and oil sales volumes increased in 20% to 21,519 boe per day compared to 17,953 boe per day for the same period in 2017.

Realized contractual natural gas sales for the 3 months ended December 31, 2018, average 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 fully 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 realized in the fourth quarter of 2017.

Additionally, our average gas sales 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 net back of $3.92 per Mcf in the fourth quarter of 2018 or a margin in excess of 79%. Focusing on the other components of the very strong $3.92 net back, natural gas operating expenses per Mcf decreased 19% to $0.44 per Mcf for three 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, overall higher production days. 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 average $0.59 during Q4 or approximately a 12% royalty rate, which is consistent with prior quarters. Once again, due to increase gas volumes, Q4 2018 fund from operations is $28.7 million, with 73% higher than the $16.6 million reported in Q4 of 2017.

On an annual basis, our realized natural gas price net of transportation average $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 $4.75 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 three months and year ended December 31 compared to the same period 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 Credit Suisse.

The proceeds of which were use to purchase the Jobo2 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 Credit 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 finance leased was achieved by the Credit 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 costs 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 Jobo3 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 with natural gas sales average 126 million cubic feet per day in the month of January and February 2019, which continues our trend of growing gas production and sales.

By midyear 2019, the Promigas pipeline expansion should lift gas sales to approximately 250 million cubic feet per day, a number that includes off takers 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 flow.

Included in the 2019 CapEx program our three exploration wells, two appraise wells, and three development wells. The Company will also acquire seismic on the game side blocks during Q2 to Q3 of 2019.

In addition, as mentioned earlier, the Company will complete the Jobo-3 expansion certainly thereby lifting our gas treatments capacity to 330 million cubic feet per day. Forecast realized contractual sales for 2019 which includes 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 sale price net of transportation were applicable is 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 the strategy and outlook for the remainder of 2019. Thank you everyone.

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 with the completion of the 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 had achieved in the past four years.

And finally, we are focused on execution of the 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 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.

I have basically two questions here. The first one you mentioned that the pipeline will be ready by September, but it would an upside to say you so.

If you could shed some light on this topic on how due to the postponement would affect the sales? The second just make sure that understood that you said in one of the last comments, you mentioned about the perception 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 two additional pipelines instead of one? And how long would it take to develop them instead of basically just one for Medellin?

Thank you, Luiz. With respect to the current work undertaken by Promigas which involves three 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 Philadelphia, which is located Majaguas and Cartagena.

And the third component is a new 20-inch pipeline approximately 140 kilometers in length between Cartagena and Barranquilla to the Northeast of Cartagena. With respect to the component the impacts our gas sales that would be the Jobo to Majaguas pipeline as well as the Philadelphia 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 segment, which I mentioned is between Cartagena and Barranquilla, which is the new 140 kilometers stretch and 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 this for June of 2019 when those two segments are completed by Promigas. With respect to your second question regarding the new pipeline project that we're working on, which will either see one of two options for the new pipeline route, one between Jobo and Medellin and the other option between Jobo and Cartagena.

Both those options involved 100 million standard cubic feet per day of new transportation capacity scheduled for late 2021 or 22. We will only be building one of those two 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 and those two markets Medellin and Cartagena. We will make the decision with regards to which of those two options we are going to be going for here within the next few months.

So anyways, we anticipate completing one of those two 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.

I basically have two questions. The first ones will be regarding the gas the new Promigas pipeline.

We have previously heard that there was a senior kind of a permit spending to very part of the pipeline below on existing highway. And I would like to know, if you already have the permit for how is that going, and if that would have any impact on the completion of the first portion that you mentioned, from Jobo-2 Cartagena?

And the second one would be regarding operating expenses. We saw that as an effect of dilution during the final quarter expenses were lower.

And 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?

Thank you, Maria. With respect to the Promigas question, regarding the Promigas pipeline, there are two modifications that have been submitted by Promigas to the ANLA for the section Jobo Majaguas.

These two 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 with the ANLA within the next month, in month of April.

Again, those modifications affect a 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 it over to Jason.

Sure, yes, you're right Maria. Our OpEx has been going down sequentially as our production arises.

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 gas OpEx will be approximately $0.30 cents and Mcf. We're not anticipating any increased OpEx related in new Promigas line.

Of course, those are transportation charges that we always close to our revenue in net of transportation, which we pass through to the off takers, and that revenue net of transportation, as you can see, it's been growing sequentially every quarter on an Mcf basis.

Why is your average sale price for January and February 2019 at 499 per Mcf? is it sustainable?

So, as we've discussed on previous calls, even though we have a large portfolio of contracts, multiyear contracts, we do leave about 10% of our gas production available for sale in the spot market. So, during these two 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.

Two questions please. First, on your capital expenditure.

Looking forward to potentially selling 300 million stocks per day in late 2021, 2023 ahead of that's. And what is the level of drilling expenditure that we 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 buybacks that you announced late last year. Do you have any other plans for potential return of capital to shareholders in the near term?

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 to that facility, we have with the current wells, we have tied in to facilities we have between 280 million or 290 million standard cubic feet per day rate now, a productive potential from the existing well, so I anticipate that, going forward through 2019, 2020 and 2021, you will maintain a fairly constant rate of drilling between 8 to 10 wells per year as well respected our CapEx associated with that.

I will not be two 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 for 300 million plus level of productive capacity.

With respect to the share buybacks and other shareholder in issues were contemplating, we did continue to share buybacks from Q4 of last year and in Q1 of this year, we continue to buy back shares. We are contemplating now with respect to the timing of the Promigas expansion, where we will formally take a decision wait to see that happen in June.

And we will be considering the potential of a dividend issue to shareholders, either continuous regular dividend or especial dividend. So we will take that decision once we have seen the production bump coming here as in June of 2019.

Just a bit more color on the number of issued. So to-date, we've bought 674,000 shares, at an average price of $4.15, which would then total CAD2.8 million.

Thank you. That's very helpful.

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

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 that entire budget for the 3D seismic to be executed through the summer time.

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

No, I mean, we believe about 10% of our production available for the spot so the rest is contracted. So there will be -- there's little room to increase the tax back.

And the basic reason for the increase in the prices achieved on those spots sales was a bit of an El Nino year-over-year and that is much more demand for that gas.

And my second question is given the rights of way to go to Barranquilla place with the expansion that promises doing. Isn't going to be much easier?

Or is there rights away 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, remember, you're 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 to speed here and that the processes one you think would be smooth to give you an equal opportunity to go to Medellin?

Josef, this is 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, mostly geography that's difficult to contemplate and the route is about 185 to 200 kilometers Cartagena so a little shorter. The process is the same in other case, which required of course, is a license and some community consultations.

Those take approximately one year to do and will be the same in either case. So both the routes present different challenges in respect to construction, the environmental permitting is the identical.

And really from our perspective the main criteria, is the future market potentials between those two locations. Of course we understand is a 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 interiors 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 risk. So that's really the main criteria, we're looking at not just the route, but also which was a better market feed into and should be go to Medellin to diversify our client base, which is currently located on the coast.

Okay. The timeline for approval of either route would be about the same amount of time?

That's correct.

Most of my questions have been answered, maybe just one, one quick one, please. With the Jobo-3 guys treatment plan 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?

Well, there's two little scheduled for this year. One is an additional flowline from Pandereta-to-Jobo to the bottleneck that those wells.

And the second one is in the Acordeon success case, tying in the Acordeon wells to the founder of Pandereta of the flowline.

Okay, so first of all, I don't think our debt levels have been increasing as 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 years now.

Meanwhile, our production dates is certainly growing. So, perhaps one -- the way that I would look at that is and what is your debt to your EBITDA, right.

So, currently, it's about 2.5 to 1. And when the Promigas pipeline comes on by year end, it'll be 1.5 to 1, right.

So, in relation to our production, our debt levels are shrinking materially throughout 2019. I also explained the swap of the Promigas -- Promisol finance lease for the new Credit Suisse term debt, once again, that was not an increasing debt but rather a swap different debt, net of 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 seven 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 a 100 million cubic feet a day to 230 million cubic feet a day. And then, 230 on a new pipeline 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.

I have a very brief question on Venezuela. I would like to know if you could share your thoughts on Venezuela, any potential for changing this country, which is one [audio gap] could be an opportunity or either a threat for Canacol?

I'm sorry. I believe that question is Venezuela threat to.

Could you please repeat the question? I'm sorry.

We didn't hear that very well. Sorry.

Sure, sure Charles. I mean, bearing in mind, that once again, a political changing regime in Venezuela is grabbing the headlines.

I would like to know if you could share your thoughts. Is a political change in this country could be an opportunity or a threat for you guys?

Yes, it's very good, sorry. I understand the question now.

Thank you for clarifying that. Obviously, the expectation is that something may change in Venezuela within the near to midterm.

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, as that's what we required to increase oil and gas production there. So from two 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.

So, it should situations 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 Columbia as well, that would be part of our strategy of course going into Venezuela, take advantage of the pipeline that connects Maracaibo to the Guajira. But in any event, you know, given the situation currently in Venezuela, given the need for massive amounts of investment in Venezuela to increase production should change further.

I don't see much in the way of opportunity within the short form, but certainly potential opportunities within the 5 to 10 year period. Obviously a lot of that investment that might go into Venezuela as well as a result of that change will be utilizing Venezuela.

But again Venezuela had his own consumption concerning gas, which needs to be addressed both industrial and commercially. So, I don't expect any export potential out of Venezuela into Colombia within the current 5 or 6 year timeframe, but after that there is potential for that.

Yes, I basically have two questions. The first one is, can you explain us what happened is for with the differ taxes?

And the second one is. When do you plan to sell your participation in Rancho Hermoso?

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

Yes, so this quarter, the first taxes we had written off certain blocks and they're taking of the aspects as compare to the taxable balance. So actually there's a 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.

For they're being is as the Colombian pesos, the U.S. dollar exchange rate varies that will generate deferred tax positives or negatives, which of course is nearly impossible to predict.

Thank you.

With respect to your second question, the Rancho Hermoso oilfield, which was, 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 of that deal. And we expect that 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.

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

Shahin was your question regarding conventional or unconventional oil activities?

Unconventional.

Yes, thank you. Thank you for that clarification.

Yes. As you know, we have interest in two 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 contract with the ANH. As you know, both of those blocks have significant potential for shale oil, which has been demonstrated on a technical basis and on a production basis from one of the [Pikul] plateau 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's the committee analysis 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 we see it very warmly. As was announced a couple of days ago, Canacol and ourselves in 2017 applied to the ANLA which is the environmental authority for two licenses, for two separate pilots.

One on each block, those licenses would have covered during about the six 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 two applications that were submitted to Canacol ourselves. And we're currently evaluating with our partners, the pass forward.

As I anticipated that echo patrol currently is in the process of a paying those permits and perhaps the payment with better results and needed. So at the moment, I must say, both of our projects with ConocoPhillips both of those contracts are essentially in force majeure, waiting an assessment on our part of how to proceed forward with the new applications for those pilots.

So, I just covered that with my response to Shahin, I think. Again, I think the Colombian government or 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 VIM5, which is located in the Lower Magdalena Valley, these blocks all of our gas production is conventional production. So, we do not utilize any hydro stimulation whatsoever with respect to developing those conventional gas resources.

So we have no plans to deploy any non conventional techniques to our conventional exploration gas blocks.

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 back stop looking at both options?

No, no, we wouldn't. You know, we were only planning the one pipeline, Josef, either in north or south.

But however, if we continued in 2020 and 2022, to continue to build our reserve base at the rate that we have been building at out over the past five years. I think you know when we're halfway through the project we're contemplating for 2021, '22 so sometime at the end of 2020 early 2021 we could conceivably based on very positive outcomes from our 2019 and '20 exploration programs.

We could conceivably be planning another root in 2024 to those markets but at the moment we're sort of only planning one pipeline to accommodate and additional100 million standard cubic feet per day targeting delivery in 2021 -- late 2021, early 2022.

Okay, so more manageable steps and if there is excess cash flow the MCI be or dividend as you mentioned earlier?

That's correct, Josef.

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.