Canacol Energy Ltd

Thank you. Welcome to Canacol’s Third Quarter 2017 Financial Results Conference Call.

This is Carolina Orozco, Director of Investor Relations. I’m joined with Mr.

Charle Gamba, President and Chief Executive Officer; Mr. Jason Bednar, Chief Financial Officer.

I will now turn the call over to Mr. Charle Gamba

Good morning, everyone. 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 financial figures in this call are denominated in US dollars. Operating highlights for the third quarter included realized contractual sales volumes increased 10% to 17,276 Boe per day for the nine months ended September 30, 2017, compared to 15,727 Boe per day for the same period in 2016.

For the three months ended September 30, 2017, realized contractual sales of 16,606 Boe per day of sales of which 80% was natural gas. In the third quarter ConocoPhillips Colombia Ventures Ltd.

and the Corporation tested the Pico Plata 1 oil well in Columbia. The Pico Plata 1 well is located on VIM 3 exploration and production contract in the Middle Magdalena Valley of Columbia and was drilled by the consortium in 2015.

Pico Plata 1 was designed to test the petroleum potential of shales and limestones within the pretaceous laguna formation. And the well encountered over 1,200 feet of oil bearing reservoirs.

During the course of 2017, five discrete formation injection tests and three hydraulic fracture stimulations spanning the entire interval were performed in three shale reservoir intervals within the laguna shale at the Pico Plata 1. The objective of the program was to collect information on the productive capability of the reservoir, the quality of the fluids contained within the reservoir.

The formation pressures of the reservoir and the ability of the reservoir to be hydraulically stimulated. The operation completed in July, 2017 was successful, with all intervals that were hydraulically stimulated and tested producing light gravity crude oil with no indication of formation water.

Individual slick water hydraulics stimulation frac size in vertical wells sets is between 27 feet to 30 feet thick, vary between 80,000 and 346,000 pounds with resulting natural flow rates up to 500 barrels of oil per day with no formation water over flow periods of three to 28 days. The testing program achieved the objectives of collecting the post stimulation production pressure and fluid data as well as confirming the viability of hydraulically fracture stimulating the reservoirs in the Pico Plata-1 well.

Canacol and its partner ConocoPhillips Colombia are planning the next steps in the commercialization of the La Luna shale, which will include the drilling of a horizontal well and the application of a massive multi-stage hydraulic frac in 2019. The first ever in Columbia.

Canacol holds approximately 371,000 net acres in this highly prospective shale oil play and we see a potential value rivaling that of our Lower Magdalena gas play developing over time in this exciting play. In early August 2017, the Corporation signed an agreement for the construction operation ownership of Sabanas gas flowline from its Jobo gas plant to the connection point with the Promigas as a gas pipeline at Bremen.

The dashed red line on the exhibit located on Slide 4 shows you the path of this new 82 kilometer flowline. Sabanas flowline will have an initial transportation capacity of 20 million cubic feet per day commencing on December 1 of 2017 and a final transportation capacity of 40 million cubic feet per day in mid-January of 2018.

Once the final compression has been installed and tested. The productive capacity of the Corporation's current gas wells is approximately 195 million cubic feet per day and that of the Corporation's gas processing facilities located at Jobo approximately 200 million cubic feet per day.

Realized contractual gas sales volumes increased 20%, 79 million cubic feet per day for the nine months ended September 30, 2017, compared to 66 million cubic feet per day for the same period in 2016. For 2018, the Corporation is targeting average realized contractual gas sales volumes of 130 million cubic feet per day.

The volumes represented 65% growth in sales versus 79 million cubic feet per day for the nine months ended September 2017. For 2019 the Corporation is targeting realized contractual gas sales volumes of 230 million cubic feet per day.

These volumes represent 77% growth in gas sales versus 130 million cubic feet per day estimated for average 2018 gas sales. Canacol’s gas assets require very little capital and feature industry leading reserve life indices.

We spend little to no capital to main existing production to maintain existing production of 2017. And we anticipate spending a total of $85 million for the remainder of 2017 and 2018 to lift and maintain 230 million cubic feet per day of production exiting 2018.

Subsequent to third quarter, drilling operations concluded at the Pandereta-1 exploration well with gas encountered in the primary Ciénaga de Oro reservoir target as anticipated. The well is currently being cased ahead of production testing.

The Canadonga-1 well is drilling ahead as planned, and the Corporation anticipates drilling through the primary Ciénaga de Oro sandstone reservoir target within a week. The Corporation will provide testing results for both wells when flow testing operations are completed.

I'd like to turn the call over now to Mr. Jason Bednar, Chief Financial Officer of Canacol to discuss some of the financial highlights associated with our third quarter.

When he is done I will provide a brief counter discussion considering our strategic outlook. Thank you.

Thanks Charle. I plan to cover Canacol’s financial highlights for the third quarter of 2017.

First off, we're pleased to report that realized contractual sales volumes of 17,276 barrels per day for the nine months ended September 30, 2017 which is a 10% increase from the 15,727 Boe per day reported in the same period of 2016. Realized contractual sales volumes for Q3 decreased marginal 3% from Q2 mainly due to three of our three off-takers having scheduled maintenance for a combined downtime of 66 days in Q3, which resulted in lower gas production of approximately 8.6 million cubic feet per day or translated roughly 1,500 Boe per day averaged across the quarter.

This scheduled maintenance was an annual event that is not expected to recur in the near future approximately 80% of our realized contractual sales is indeed related to the gas volumes. EBITDA was $32.9 million for Q3 up from $29 million in Q2 of 2017.

We’ve seen a shift in gas production volumes in 2017 towards the lower royalty Esperanza block as opposed to VIM-5 as we continue to seek to reduce our royalty exposure. Adjusted petroleum and natural gas revenues, inclusive of revenues related to the Ecuador, for the three months ended September 30, 2017 were $43 million.

Our adjusted funds from operation was $19 million for the quarter, our corporate operating netbacks were $23.02 per barrel similar to Q2, which was supported by an average gas sales price of $4.96 per Mcf which was also consistent with our average gas price during Q2. Total natural gas production expenses per Boe were $2.02, or $0.35 an Mcf for the three months ended September 30, 2017, by comparison Q2 was very similar $0.36 per Mcf.

We did incur some transportation costs this quarter related to two of the short-term gas contracts that had an integrated sales price. These contracts had a combined production of approximately 9 million cubic feet per day during the quarter.

These two short-term gas contracts are replaced by a long-term fixed price contract for 10 million cubic feet a day that begins on December 1, 2017, and the pricing of that is in line with our typical pricing terms. I will mention that a minority portion of our gas contracts for 2018 and beyond do you have an integrated sales price, meaning that the headline price includes transportation to the Caribbean Coast.

Having said that, this basket of long-term contracts for 2018 and beyond will still average approximately US$5 net of any applicable transportation. Capital expenditures in the three months ended September 30 totaled $25 million, primarily related to the midstream pipeline costs being recorded as CapEx during this quarter.

As previously announced, the pipeline is budgeted to cost $41 million. We expect to recover the portion of cost incurred over and above Canacol’s committed $10.5 million contribution limits from private investors later this month.

I should note that if we make this pro forma adjustment, the September 30, 2017 cash balance of $35 million would have been approximately $15 million higher, and that total approximately $51 million of cash balance. In addition, we also have $54 million in restricted cash and we continue to be within our banking covenants.

I note that the restricted cash continues to tick down on a periodic basis, not only due to the satisfaction of ongoing ANH commitments, but also due to a cash release every six months relating to Ecuador. In addition, during this last quarter we drew last $20 million of the Credit Suisse green-shoe.

We have also sold a little more than half of our internal shares for a total proceeds to-date to $4.5 million and we still retain another 7.5 million shares or approximately $2.5 million or $3 million of this stock left. As we stated in the press release, we suspect to release our guidance related to 2018 in mid-December 2017.

I'll hand it back to Charle now at this point. Thank you.

Thank you, Jason. In conclusion, the management team and Board of Directors of Canacol are pleased to have delivered a solid third quarter.

Management remains focused on its primary goals for 2017, which include delivering a significant increase in gas production, exiting 2017 related to the completion of the Sabanas gas flowline, and adding to our gas reserves base via the successful execution of our exploration drilling program which has yielded yet another discovery at the Panderata-1 exploration well. We are now 9 for 10 in our exploration success rates, which is a remarkable achievement.

What's more remarkable is that we have approximately 40 more gas prospects identified to drill over the coming years. In this area we’re close to 2 trillion cubic feet of additional perspective resource potential to add to our portfolio of reserves.

So I think it's safe to say that with our 90% exploration success rate we will continue to deliver significant value to our shareholders via the drill bits. In 2018 the management team will focus its efforts on increasing production to 230 million cubic feet per day exiting 2018 via the second expansion of the Promigas gas pipeline to Cartagena and Barranquilla, and continuing to add gas reserves via the exploration drilling program we have planned for 2018.

We anticipate to provide more detail concerning this drilling program along with plan capital expenditures when we release our 2018 guidance in mid-December of 2017. At this point, I would like to open the line to questions.

Hey, good morning, and thank you for the presentation. I have a couple of questions.

The first one would be is regarding the production mix between Esperanza and VIM-5. I noticed that it went further like concentrated to Esperanza.

Is this an effect of the royalties of steel or does it have something to do with the plants containment that we see during this quarter? And for how long we expect to see like a similar mix?

And the second one would be regarding the financial lease for compression stations. I noticed on that detail that you entered the financial lease.

And I was wondering if you could give us a little bit of guidance on what were the chances of the lease for – what amount, et cetera? And the final one would be regarding is physically those contracts that you signed that include the transportation cost to Cartagena.

My question is regarding how much of the contract like how much Mcf per day are signed with these type of contracts and for how long? Thank you very much.

Okay. I think I can handle that, Charle.

With respect to – let's start with, I think there's three questions there, so let's start with the gas production mix amongst our block. The Esperanza block has roughly 8.5% or 9% royalty on it, whereas the VIM-5 block has – the royalty rate is 22%.

Due to the significant X factor that OGX read the block prior to us had originally bid with the government. So obviously, preferentially, we would like to produce from the block with the lower royalty.

Given we have so much gas currently behind pipe we are able to do that. Our production mix going forward obviously as we move towards 230 million, there will be more gas coming from VIM-5.

And hence, a higher royalty rate anticipated with that production mix. Having said all of that, our blended rate that you can anticipate going forward is probably in the range of 12.5%.

And as we get years out from now it may creep up to roughly 14.5% and we’ll obviously provide guidance on that by year, but those are some goal posts for now. I believe the second question was in respect of the compression lease.

So there was a lease that we had announced with Interflex. The number that is in the financial statements in the commitment note of just over $50 million relates to a 10-year lease.

So that would be roughly $5 million or $5.5 million per year. That number – per year number is actually split into two; so there is a finance component out of that, i.e., finance/last capital lease.

And the Interflex also runs the operating costs and the compressors themselves. Those two – the difference between the finance leasing and the operating portion of that lease it's roughly 50-50.

And if you did the math on that that cost of the increase in our OpEx relating to compression as I believe I stated last time, across our 130 million a day portfolio, when it hits 130 million it would be roughly $0.06 an Mcf and an increase in op costs, which will put us in the 40 or low, 40s range at that point in time. Obviously, it's substantially less when we're doing 230 million as opposed to 130 million.

So I think – and the embedded interest rates in that compressor lease was very, very low in the range of up 3% or 4%. So we're pleased with that financing option.

Lastly, I think you'd asked the question about transportation and how much of that portfolio up to the Caribbean Coast has the embedded transportation cost in the headline number. I'm going to avoid that question for the large part, obviously, we're in a competitive business and there are competitive negotiations ongoing.

Having said that, I think the relevant thing here is that we will still enjoy even net of transportation roughly $5 an Mcf net of transportation. So I think that's the relevant part of this discussion.

I think that's it for now.

Yes, thank you very much.

Okay, thank you very much. I have several questions.

I have both – a couple of one in regard to the results. And here it’s an important highlight that the important we saw in production and transportation cost we scaled to 7.5 million versus 5.7 since first quarter 2016.

I want to know order details on that increase and how sustainable or recurring it will be. And the second, I have the same question for G&A, which came below the expectations and below last quarter’s level.

I want to have some additional guidance in that regard. I have another couple of two more questions.

The first one is regard to Mono Capuchino. I wasn’t expecting this amount to see incorporation of some additional volumes of Mono Capuchino that you mentioned.

It will start the operational within 60 days. And I think during this quarter what can we expect going forward?

And I also want more details in regard to the season agreements you presented to the market in Colombia last week. What are the motivations of that efficient agreement and what details can you give us on that regard?

What was the purpose of that? Thank you.

I'll answer the first couple questions and then maybe hand it off to Charle. With respect to G&A, we did have some efficiencies come through this quarter.

I’d say on average we're probably still, well to-date for the nine months we're averaging a bit under $6 million a quarter. If you take our total divide by the nine months.

And I’d expected that $6 million a quarter is probably the proper number for you to budget going forward. I’ll touch again, I think for the third time with respect to the transportation costs.

Unless I'm viewing this wrong I'm not sure it matters if we have one molecule, all of our transfer all of our gas tied to energy graded price as long as that net price is still roughly $5 and that will be the net price for the foreseeable future being years moving forward. And once again we will have further guidance on that in mid 2017.

With respect to Mono Capuchino now I will hand it back to Charle.

Yeah, with respect to Mono Capuchino we started production from that well in late September. That well is operated by ourselves, we have a 40% working interest in that well and Petra has 60%.

It is producing from the shallow section of the VMM 2 contract. So current production from Mono Capuchino net to us is between 300 and 400 barrels per day.

So we should be seeing the production results from Mono Capuchino coming through here in this fourth quarter. With respect to your last question, which I believe relates to a purely mechanical transfer of titles here in Colombia, I’ll leave that to Carolina Orozco to describe.

Yes. So basically, Juan Camilo, just to make sure you are referring to the press release about an internal corporate restructure between subsidiaries?

Yes, about the one between Canacol Energy Colombia and Shona Energy Colombia.

Sure so basically the reason or the rationale behind these restructuring was mainly for tax purposes, but I think as all of these subsidiaries report directly on our part directly to the Canacol Energy Limited, which is the company that consolidates. They are basically no effect which these corporate distribution that we did internal.

Yes, sorry Carolina. I can probably add some color that thanks.

I better understand the question now. Canacol is – for those that have been around long-enough are well aware that we've had a series of acquisitions there that were done to form the company along with their founding assets.

Of course all those companies came with their own structures when you merged them under one umbrella structure things obviously are more complicated than they need to be. So we, actively look to consolidate that structure and have tax efficiencies, where proper, and where available.

And we did some of that planning and some of that planning quite frankly was seen in Q2, where the tax rate was significantly lower. Our implied tax rate was significantly lower in Q2 than it turned out to be in Q3, specifically because Q2 saw some of those tax efficiencies recognized.

Okay, thank you.

Hi, good morning guys. I have a couple of quick ones here.

So the first one is basically a follow-up regarding the realized gas prices. And as you mentioned, Charle or Jason, you have an average prize of $5 per Mbtu net of transportation.

And in the quarter what we saw is the average realized price of gas was actually $5 and your transportation costs went up by $1 per Mbtu. So I just wanted to have more color on triggered these increase in transportation costs and what is the net price at which at which you are selling your either at the head will or including transportation costs.

So that's, my first question. And my second question is related to the upcoming bidding round and Colombia is planning to host, [indiscernible] bidding round.

And I just wanted to know you take on these round and what are your thoughts on that.

Okay, thank you. I’ll start with the transportation costs.

So let’s delve it this a little bit further I suppose. So our gas revenue price per MCF in Q2 was $4.96 and it had zero transportation related to it.

In Q3 that number was the exact same $4.96 and if you do the math on the $1.8 million in transportation costs it works go to $0.26 which would mean we would have netted $4.70. That’s once again related to two small interruptible contracts.

And I think last quarter we discussed the effects of the rainy season et cetera and showing some interruptible contracts until our new contract on December 1 kicks in. Said contract actually is at $5 plus transportation typical cost, right.

So that covers off Q2 and Q3 and once again looking forward to whether it's Q4 of 2018 or 2019 and beyond. Those net revenues received per Mcf net of that transportation costs will continue to be approximately $5 per Mcf.

The second question I'll hand over to Charle.

Thank you. And with respect to the upcoming bid round being hosted by the ANH [indiscernible] I would say the following.

I would say that the technical merits of some of the blocks are interesting with respect to the potential for gas and oil. So technically there is some interest there however, contractually the ANH has come out with very difficult contractual terms in this round.

Particularly with respect to exploration work program commitments in the form of wells and seismics. I believe we're looking on average for each block minimum work programs of $36 million, which are extraordinarily high especially given the state of the industry.

And I think that that the contractual commitments associated in this bid around will certainly be tracked from the interest expressed by industry in his bid around. So those would be my comments with respect to the upcoming bid around.

Thanks Charle. If I may I’d like to squeeze in on other one.

I mean you announced in the Canacol data, you’d like to divest or dispose all the oil assets. And I want to know if you could share with us how much are you are expecting to raise from divest or disposal of these assets?

Yes, thank you. Thanks for that question.

As you know the percentage mix of our current production and future production is becoming increasingly more heavily gas weighted and that really reflects, its really a reflection of the materiality of our gas portfolio compared to our conventional oil portfolio. So we just from an investment decision perspective, it makes a lot more sense for us to deploy capital towards exploring and developing our gas assets where our margins are 80% and netbacks $25, $26 much better margins and netback associated with oil production and much lower level of investment of course.

So naturally, we're looking at what to do with our conventional oil portfolio. And at this point, we are planning either to do some form of a divestment of our portfolio which would include engagement of a bank to look to divest our entire conventional oil portfolio or a potential spin-out of our oil portfolio into a new company.

So we're currently evaluating both of those options with respect to which would yield the best value for Canacol shareholders and we expect to be acting upon one of those two courses of action in Q1 of 2018.

Thanks guys.

Okay, thank you. I'll answer that question.

As I mentioned you know we are focused exclusively on gas exploration and production and as a result we have not been investing much capital at all on our oil assets that would include no new drilling or workovers of existing wells. So the decline in the oil production in both Colombia and Ecuador is simply a reflection of the natural decline of the producing wells given that we are deploying no capital to maintain or build production.

All right, with respect to Pandereta. With respect to testing in general, the maximum rates that we can test with our testing equipment is between 25 million and 26 million cubic feet per day.

So I anticipate test results in that range from Pandereta, which is a well that as we announced this morning or last night I should say, we have encountered gas. So we will begin flow testing operations in Pandereta within the next week.

So I expect that we will be delivering testing results probably within the next two to three weeks for the Pandereta-1 gas discovery. With respect to Canadonga, we have not finished drilling that well yet so we really do not know yet what we have in the main target, the Ciénaga de Oro.

We have not yet drilled through that reservoir yet, we anticipate to be completed the drilling at Canadonga within a week and based upon the results once we are completed drilling, we will formulate a testing program for that.

Hello, thanks again. I just wanted to squeeze a small follow-up question regarding the divestment of the assets, of your oil assets.

I was just wondering does this include the Ecuador assets as well or is it just Colombia? Thank you.

Thank you, thank you Maria. We will be divesting all of our oil assets, all of our conventional oil assets.

We would like to plan to divest.

Okay, thank you.