TRANSCRIPT OF PRESENTATION OF QUARTERLY FINANCIAL STATEMENTS AS AT - - PDF document

TRANSCRIPT OF PRESENTATION OF QUARTERLY FINANCIAL STATEMENTS AS AT JUNE 30, 2016 Held on the 16th of August, 2016 CANACOL ENERGY LTD. (Translated from Spanish to English) Nicolás Acuña - Financial Vice President Good morning to all and thank you for accompanying us in the presentation of our Financial Statements as at June 30, 2016. In this first slide you can see the production of oil in Llanos-23, the production of gas in La Esperanza and VIM-5, and the incremental production in Ecuador. The corporate netback for this quarter ended on June 30 was $25.58 dollars per barrel

• f oil equivalent, improving the results that we had been having in former quarters.

This is a new graph that we present in this opportunity to report and show you cash

• sales. What is the difference that we have with respect to production? The

difference is based on the concepts of take or pay and gas nominations not

• delivered. This means that under the contracts that we have signed with our main

gas clients there are situations in which they cannot always take the gas and according to the conditions of the contract there are two options. One of them is take or pay, in which clients have to pay for the gas and nothing happens. We basically receive the revenue and we do not have any subsequent obligation; and in addition we have others which are what we call gas nominations not delivered, which for the quarter were eight hundred barrels per day in average. Gas nominations not delivered consist in that clients also pay us but, according to the contract, they have the opportunity to later on take the gas which they have already

• paid. So, we are not reporting such sale as income but as deferred income,

because it is when clients can take the gas that it becomes an income. Now, there is a special condition, as I said, in each one of such contracts: if after the time that clients have to take the gas, which in some cases is six months and in other cases is twelve months, if they do not take it, we can record it as other income and we do not have to deliver the gas. That is why this level of sales and invoicing is higher than that of production with an average in the quarter of 17,817 barrels equivalent. As to operational expenses of the company, we keep having a cost reduction trend with respect to all former quarters. A year ago we had corporate operational expenses of $9.18 dollars per barrel and for this quarter we managed to lower them to $3.47 dollars per barrel. This cost reduction responds to expenses efficiencies in Llanos-23, the fact that we have managed to have service contracts resumed, as all the industry has, and the depreciation of the Colombian peso. As you see, from the former quarter we have come back to the trend of corporate netbacks around $26 dollars per barrel of oil equivalent, again explained by the

increase in production in our gas fields, as you well know, and the reduction of

• costs. In addition, costs in gas fields are quite controlled and quite low.

As we have announced, we had the goal to increase and quadruple gas sales, which we achieved in this quarter from the month of April. This means that we have achieved an adjusted income, which include income from Ecuador, of $45.4 million dollars for the quarter, which is quite higher than the trend that we have, obviously explained by the drop in oil prices, but compensated with these higher gas sales. Our adjusted funds from operations, are also reaching a level of $27 million dollars with respect to what we had a year ago of $16.4 million dollars during the comparable quarter. It is very important to highlight that all the foregoing is reflected in our statements of results in which, despite the negative oil prices which keep being volatile, we generate a net profit of $11.2 million dollars after having very significant losses in the former quarters, such as the case of the loss that we had in the quarter ended

• n December 31st, 2015. Only to remember, this loss was not related to cash but it
• ccurred because of the application of IFRS rules for impairment, due to the drop
• f prices, so that we had to make the adjustment in our oil projects. However, it is

very important to highlight the profit that we are having in this quarter, which will be maintained throughout the rest of this year 2016. With respect to EBITDA, making adjustments for taxes, interests and depreciation, when comparing with what we had in the same quarter of the former year, we have a much better result of $28.6 million dollars with respect to $10.5 million dollars that we had in the same quarter of the former year. And if we see this on a six- month basis, for the six months from January to June, we had an EBITDA result of $40.3 million dollars with respect to $21 million dollars that we reported a year ago for those six months. Now, a special fact to highlight in the month of August, in addition to the results that are being reported as at June 30, is that the company made a private placement, placing in a first tranche 9.6 million shares at $4.08 Canadian dollars for total proceeds of $39.5 million Canadian dollars. In the following days, the company placed a second tranche of 1.8 million shares, for total proceeds of $7.3 million Canadian dollars, which represent a total placement of almost 11.5 million shares for almost $47 million Canadian dollars, more or less equivalent to $35 million American dollars. The company currently has a base of 172.7 million shares after this placement. So, what does it represent for us? That in cash, as at June 30, we ended with $26.3 million dollars available, and with this placement we are adding $35.6 million dollars, that is, $62.5 million dollars of available cash. In addition, we have restricted cash for $62.5 million dollars which are mainly to back the investment commitments of Ecuador. Besides, we have a capital surplus

• f almost $40 million dollars and in August we should add $35 million dollars

resulting from the private placement to get to more than $70 million dollars of working capital, which strengthen the financial position of the company for the rest

• f the year. Our debt with banks remains the same: $255 million dollars. $180

million dollars of the syndicated loan led by BNP and $75 million dollars of the notes we have placed with Apollo. Thinking about the rest of the year and estimating how the results would be for the whole year 2016, gas revenues are being estimated, having already reached the goal that we mentioned between 85 and 90 million cubic feet of gas per day, in $153 million dollars, with an EBITDAX of approximately $135 million dollars, which is very important with respect to our indebtedness indicator, which would give us an indebtedness ratio of 2.0 times by the end of the year. If you remember, we had been having indicators of around 3.5 times, which is the maximum that we have approved in the loan. Currently, we have closed at 2.8 times in this quarter ended

• n June 30. With these forecasts we would close with an indebtedness ratio of 2.0

times, quite low and very comfortable for the company. It is very important to mention what we are doing for the rest of the year 2016 in relation to drilling. We remain focused on our gas projects. In VIM-5 we finished the drilling of the Oboe-1 well, which added 2P reserves of around 5 million barrels equivalent and we will continue with the drilling of two wells in the Esperanza block. The Nispero well, which is an exploratory well, is currently being drilled. Additionally, in Esperanza we will start to drill the Nelson-6 well in the month of

• October. This well is located in the Nelson area, which is one of the gas production

projects that we are currently developing, and is exploratory because we are targeting a different zone. The main production of La Esperanza field comes from Cienaga de Oro and the target of this well is another reservoir that is called Porquero, which has shown to have gas in the other drillings that have been made, but the target is to test this new structure for the first time. As to oil, we will continue making workovers in Llanos-23. We have already completed two workovers, and the idea is, from here to the end of the year, to keep drilling, making three additional workovers, basically to keep or reduce the impact

• f production declining in the Llanos-23 fields. And in the VMM-2 block we will drill

the Mono Capuchino well in the last quarter of the year. VMM-2, as you remember, has as its target non-conventional crude. Here we will drill a conventional well but targeting the structure with the potential of non-conventional crude; so this well will be very interesting for us. In addition, as I mentioned, with the resources that we have collected with the recent private placement, we will drill another exploration well and another development well in our gas fields, and in addition we will have additional resources for 2017, but very important for us is to continue the drilling and development of gas fields. After achieving the goal of reaching a gas production of ninety million cubic feet per day, we have the new goal to increase in

• ne hundred million additional cubic feet per day, and for that we require to have

additional wells to add reserves. Our guidance or goal for 2016 keeps being the same. In gas, we look forward to having a production average of 75 million cubic feet during 2016. However, from April 21st on, as we mentioned, we have a production of 90 million cubic feet

• approximately. We also have the goal of keeping a netback in gas of $4.56 dollars

per million cubic feet or $26 dollars per barrel equivalent. Lastly, the average corporate production target for the year is between 16,000 and 17,000 barrels equivalent, and for the second half of 2016, including all gas production from April

• n, it will be between 18,500 and 19,000 barrels equivalent.

With respect to financial results, during 2016 we look forward to having revenues of $153 million dollars and an EBITDAX of $135 million dollars. Thinking more in the future, we seek to test enough reserves with the wells that we intend to drill, to go

• ut to the market and sign new 10-year take or pay contracts, to add sales and

production for 100 million cubic feet per day in 2018. To reach this goal, in addition to drilling, we require the construction or expansion of a gas pipeline to the North Coast. Now I give the floor to Noel Valencia, who comes to present the technical information of the company. Noel Valencia - Production Manager Good morning, my name is Noel Valencia. I am the Production Manager of Canacol in Colombia. This is the first slide which shows the portfolio of assets of the company and where we are focused. These are the gas fields that we have in Sucre and Córdoba. Here we have the Clarinete, Palmer, Esperanza and Oboe fields. Here we have the value of the company, which is $778 million dollars. Our exploratory success since 2008 is of 65%. The participation of the board and management is 25% and the goal for 2016, which Nicolas has already mentioned, is between 16,000 and 17,000 barrels

• f oil equivalent per day.

2P reserves as at December 2015 are 79 million barrels including oil and gas. In addition, as at June 30, 2016, we included five million barrels of oil equivalent related to the Oboe-1 well, which was drilled during the first half of 2016. Because

• f this, they are not included in these 79 million barrels of oil equivalent as at

December 31, 2015. Here we have the NPV-10 before taxes of $1.4 billion dollars. If we take this NPV-10 of $1.4 billion dollars before taxes, we should have a share value of C$7.22 dollars. Reserve replacement of the last year was of 1.103%. Discovery and development costs were $2.85 dollars per barrel of oil equivalent and our 2Preserves have a life of 10 years. Outside 2P reserves we have the potential of exploration resources, which amount to 1,045 million barrels of oil equivalent. Here it is important to review how we have been increasing our reserves throughout the last years, from 2009 to 2015. The part of the graph in blue is gas, and what is in black is oil. In the last five years Canacol has discovered more

natural gas that the other Colombian exploration companies. We had gas reserves

• f 20 million barrels of oil equivalent last year. As at December 31st of 2015 we

reached 65 million barrels equivalent of 2P reserves of gas and 14 million barrels

• f 2P reserves of crude oil. How did we do it? How did we go from having 43

million 2P reserves of oil and gas at the end of 2014 to having 79 million 2P reserves at the end of 2015? And from having 7 million barrels of 2P reserves in 2009 to having 79 million in 2015? In 2012 and in 2014 we had two acquisitions: Shona in 2012 and in 2014 we acquired VIM-5 and VIM-19. In addition, we had three important gas discoveries: Palmer, Oboe and Clarinete. With respect to light crude, we have 14 million barrels of 2P reserves and we have potential exploration resources of 33 million barrels in crude oil. In non-conventional crude, in the long term, we have a great opportunity in shale oil; 458 million barrels as potential exploration resources. This is the behavior of production this year. We went from 11,746 barrels equivalent of production in the first quarter of 2016 up to 17,817 barrels equivalent

• f production during the second quarter of 2016. After the entry in April 21st of 90

million cubic feet of gas per day, we have an average of 17,817 barrels equivalent per day. Something very important here is that 86% of our sales is insensitive to crude volatility because this percentage of sales comes from our gas contracts and in a small percentage from our contract in Ecuador. Light crude is 14% of sales, which is the crude that we have in Llanos-23 mainly. Recent discoveries of natural gas move production from oil to natural gas. With a budgeted price of $40 dollars per barrel of crude, we forecast an EBITDAX of $135 million dollars this year. Should the oil price have a $10 dollar increase, we would have an increase in EBITDAX of $4 million dollars. In this graph we see that if the price of the oil barrel were zero dollars, and we would be required anyway to pay oil production costs, we would have an EBITDAX

• f $107 million dollars in 2016. We have calculated the barrel of oil at an average
• f $40 dollars for the whole year and the EBITDAX is at $135 million dollars, but if

the oil price were in average $45 dollars per barrel, we would have an EBITDAX of $142 million dollars, and if it reached $60 dollars per barrel, we would have an EBITDAX of $153 million dollars. This is the sensitivity according to the result of the oil price. Another important point to highlight is the good prices in gas sales that are in our contracts, compared to the rest of the world. In Europe, the gas price has gone from $12 dollars per MMBTU in 2014 to values above $4 dollars per MMBTU. In United States and in Canada the price went from being between $4 and $6 dollars to close to $2 dollars, and we have achieved prices of $5.6 per MMBTU in average for the year 2016, which increase between 2% and 3% per year. These are the various producers in North America and what it is the breakeven point? Their breakeven is between $32 dollars and $65 dollars. We, on the

contrary, have a breakeven point in our gas projects of five dollars per barrel, which is very low, so we have a great opportunity even with low oil prices. This slide refers to the efficiency of Canacol in the gas business. We have invested $97 million dollars to add 10,000 barrels of oil equivalent per day to our production. The competition in Colombia had to invest $807 million dollars in average to achieve those 10,000 additional barrels of oil equivalent in daily production. We achieved this production increase with the drilling of eight wells while our competition achieved it drilling 73 wells in average. Our netback is $27 dollars and that of our competition is $17 dollars in average. Why? Because our business depends on a higher percentage on gas, while that of our competition depends mostly on crude. It is clear that the competition invested much more money to generate the same production increase and drilled nine times more wells, which shows the capital efficiency in our company. We have four gas fields of which 100% of the capital is ours; we do not have

• partners. This at an operational level is very good. Our main work is to take the gas
• ut of the wells, of Nelson, Palmer, Oboe, Clarinete, take it through a flow line up

to the Jobo Station, and place it there in optimal conditions to deliver it to clients. From the Jobo Station we distribute 25 million cubic feet per day to the south through the Cerromatoso gas pipeline, particularly to the Cerromatoso nickel plant. The other 65 million cubic feet are taken to all the clients that we have in the north. The declining of the three mature fields of Chuchupa, La Creciente and Ballena is

• f approximately 20 percent per year. The demand of the north of the country

increases three percent per year approximately. That is, there is a great

• pportunity to keep growing. We are providing 65 million cubic feet with the entry of

the gas pipeline from the 21st of April of this year, and 25 million cubic feet to the south, for a total of 90 million cubic feet. For 2018 we have planned the new gas pipeline, with which we would have a capacity to send 100 additional million cubic feet. In this way we would be distributing 165 million cubic feet to the north and 25 million cubic feet to the south, with which our EBITDAX would go from $135 million dollars to $310 million dollars per year with this new gas pipeline. And we are already making great strides for this, not only in drilling and exploration, but also in how to bring to life the gas pipeline construction project. And how are we going to do this? Look: we provided 25 million cubic feet last year. Today we are providing 90 million cubic feet. The offer of the other three mature fields for 2020 is 212 million cubic feet approximately, and Canacol’s share in the coast market would be 165 million cubic feet for 2018. This is the total demand and here we will see how we start to have gas shortage. That is, opportunities to keep growing, to keep looking for a potential gas market in the coast. With the forecasted 127 million cubic feet of shortage in supply, there is a great opportunity and we look forward to take part in this opportunity with the exploratory results of

• ur fields. The fields discovered to this date are: Nelson, Palmer, Oboe and

• Clarinete. We are finishing the drilling of the Nispero-1 exploratory well, and in

addition we will be drilling other exploratory wells. In addition, all these exploratory prospects included in the 3D seismic are prospects with the possibility of entrapping gas. So we have significant exploratory opportunities. All the fields that are here are one hundred percent ours. We are talking about more than 785 thousand acres and four gas fields. Here, the results that we have had could not have been better. They are indeed very, very good. We tested Clarinete-1 with 44 million cubic feet in December 2014, 149 feet of net pay, 26 percent of porosity, which is a very good porosity. In Clarinete-2ST, we tested 30 million cubic feet, with a thickness of 127 clean sands

• f gas production and 23% percent of porosity. This makes gas flow very well; and

in Oboe-1, which was in March of 2016, we tested 66 million cubic feet per day. The average has been 47 million cubic feet per well. Very good, indeed, the result

• f the last fields. We expect that with Níspero-1 it will also be this good.

3D seismic information. With it Canacol mitigates the exploratory risk. We are now applying better technology for seismic analysis and this has led to better exploratory results. We have a significant opportunity that we will look for in Nelson-6, which we have identified with this new technology and with this higher level of seismic detail. And it is Porquero. Porquero is in all Nelson wells. This is the Nelson reservoir. In the Nelson structure, Porquero has been present in all the Nelsons, but we are going to test these sands with Nelson-6. This is a formation that is not in production in the coast and which may give us good results. Crude in Llanos-23. Particularly coming always from the oil business, because I worked for 16 years with Petrobras, I can say that I like this block very much. I worked in the Llanos for many years and it has a very significant potential. Here, in this 3D seismic, there is a fault. All these wells are in production. While other companies have 42, 43 percent of success in Llanos, we have 83 percent of

• success. Five out of six wells that have been explored have found oil. Imagine: in

this 3D seismic we have 13 more prospects to drill, with the possibility of adding 20 million barrels to the 14 million reserves that we have there. In addition, we have identified 5 exploratory leads, with a potential of 16 million additional barrels. As you can see in the map, outside our Llanos-23 block, the competition is producing

• il from these same faults. With very good productions. Here there is a very good

production of oil, here there is also very good production, and here there is also good production. For example, the Maracas field produces very good crude, and the fields here, Cravo and Cravo Sur, produce very good crude too. All these are

• n the same faults with very important reservoirs which we have not set out to look
• for. And, well, if they are that good, why haven’t we set out to look for them?

Because of the oil price. We had two drilling teams here and we had to stop them when oil dropped to $30 dollars. But when oil goes back to $50 dollars, we will surely drill again. Something that is also very important here is that facilities are already made. We have a line that goes from north to south and has a production

• station. Therefore, any prospect that we may find here will be projected to this flow

line.

In this graph we see the crude production forecast. We have approximately 2,400 barrels per day. This blue is what we have today. If we included the forecast of prospects ready to be drilled, we would reach 10,000 barrels per day of production, and if we included the additional prospects and leads we would get in two years and a half or three years to 25,000 barrels of production in Llanos. All these figures are estimates. A crude of excellent quality, light crude, in average 32, 34 degrees API, which is sold at a very good price. With respect to the financial aspect, we have a debt with the BNP of $180 million and another with Apollo of $75 million dollars. We finish the amortization of the debt with BNP in September of 2019 and with Apollo in December 2019. And with respect to the indebtedness indicator, we estimate that we will lower the indebtedness indicator this year to 2 times, and we will get to 1.4 times in 2017, which is a very comfortable position for the company. How? Keeping production of 17,000 barrels of oil equivalent to generate approximately $135 million dollars of

• EBITDAX. Now, if the oil price were better, we would have an even better

economic result. And here, to close, is the company value: $778 million dollars. 2P reserves of gas have a NPV-10 before taxes of $1,165 million dollars and the proven and probable reserves of crude of $193 million dollars. That is, adding only gas and oil reserves, we would be talking about $1.4 billion dollars. If we took the exploratory resources into account, for you can see the potential that we have in gas and the potential that we have in crude, we would be talking about $2,124 million dollars. This is what I have in my presentation. Thank you.