TRANSCRIPTION OF PRESENTATION OF FINANCIAL RESULTS FOR THE THIRD
QUARTER OF FISCAL YEAR 2015 ENDED ON MARCH 31, 2015
CANACOL ENERGY LTD.
Nicolás Acuña, Financial Vicepresident
Welcome to the presentation of the quarterly results of Canacol as at March 31, 2015.
As always, we start with a summary of main indicators and financial results and
afterwards Diego Carvajal will make a presentation of future plans of the company.
We start with the presentation of the company’s strategy. We have been commenting
on it in several meetings we have had with you. Due to the price environment of crude
at worldwide level, which we also experience in Colombia and Canacol, the company is
focused mainly on the development of three projects during the year 2015, which are:
gas production and sale in our fields in the Lower Magdalena Valley; development and
production of Llanos 23 light crude field, in Los Llanos Basin; and the incremental
production project that we have in Ecuador. So, here we want to highlight the
following:
With respect to the Magdalena Lower Basin, we have two very important contracts: La
Esperanza, which we acquired in the year 2012, and we have maintained in current
production, and what is the recent acquisition by the end of last year of the VIM 5
block, where we drilled a well that has turned out to be very successful and you have
known from the information we have released, which is the Clarinete 1 well. Our
program, planned for this year, by the end of 2015, specifically for December, is to
increase total production and sales of these two fields from the current 20 million cubic
feet to 83 million cubic feet. Basically we are quadrupling the production and income
that we will obtain from our gas fields.
In addition, to be able to comply with this sales and production program, we are
developing the Clarinete field, mainly with the construction of a flow line, to connect
the Clarinete well to facilities we have in La Esperanza, in the Jobo station, and we are
going to drill two additional wells, which are Clarinete 2 and Oboe 1. In addition, we will
increase and obtain new gas sales contracts.
On the side of Llanos 23, we are investing in infrastructure. We are developing flow
lines, concentrating all production facilities in one place that is called Pointer and
reinjecting water. This whole project has a very clear target to continue reducing costs.
As you have observed in the financial statements, even without having finished these
infrastructure projects, we have already reduced costs. When we finish these projects
during the second quarter and these facilities start operating, we will obtain other
important savings in production costs of the Llanos 23 Field.
In addition, we are finishing the acquisition and later interpretation of 3D seismic of a
major part of the block, where prospects have already been identified. What we are
looking for is to define these prospects very well to be able to drill them. Hopefully we
will be able to do so by the end of this year. This is not programmed yet, but we would
clearly do it in the year 2016.
I finally, as I said, in Ecuador, because it is an incremental production contract with
fixed tariff, we also have focused our efforts, with our partners, on continuing with
investments and production therein.
In sum, all these activities involve capital investments of $84 million dollars during all
year 2015. And based on this level of investment, our production guidance, which we
have defined for this year, will be between 10,000 and 12,000 barrels equivalent per
day.
Well, now we do get into financial matters. In our graph that we present all quarters, of
production evolution in the various fields, down here we have what is mainly the
Rancho Hermoso field and other minor fields that we have in production. As we have
mentioned, the decline and the lower importance of Rancho Hermoso field’s
production is clearly observed. It continues in its decline phase and, therefore, it is no
longer important for the results of the company.
This strip shows the production evolution of Llanos 23 Field, and we see that in the
quarter there was a slight reduction of production from 4,900 to 4,500 barrels.
The red strip corresponds to gas production in barrels equivalent. As you can see, we
have been increasing production. This quarter we ended with 3,500 barrels as a result
of continued and higher sales to Cerromatoso and some minor sales in interruptible
agreements that have allowed us to specifically sell some additional gas to the market
in the north coast.
And in the upper part we have what is production in Ecuador, which is maintained in its
average levels.
So, in sum, we are saying that the production average for the quarter was 10.950
barrels per day; and very important to highlight the note we have here to the side,
about having 48% of our production related to Ecuador and to gas fields, not tied to the
crude price, which allows us handling more stable cash flows.
For what is the average for the whole year 2015 and particularly, as I commented, with
the production and sales increase that we will have by the end of the year, of gas sales,
we are estimating that 60% of our entire production will come from gas sales and the
Ecuador agreement.
Up here you also see the netback comparison that we obtain all quarters. We went
from $37.7 and $25.1. Now, this quarter, we have ended with $20.5 dollars per barrel
equivalent, clearly explained by the issue of crude prices.
In this next slide we intend to outline our revenues, including the adjusted ones, with
results from Ecuador and funds from operations. We observe that revenues, during the
quarter and in the nine months, have been affected, as was expected because of the
price fall. You know that they have dropped more than 50%. In our case, revenues in the
quarter ending in March were affected with a drop of 47%. Minus $29 million dollars. In
the 9 months the effect is minus $17 million, because in the first 6 months of these 9
months, starting in June 2014, the effect of prices was not so significant. That is why
the main effect occurs in the last quarter, during which prices have dropped more than
50%.
Now then, talking about fund generation, it is important to note that here we see -67%,
falling from $33.2 to $10.9 million and -5% for the 9 months. But if you see these two
figures, revenues dropped $29 million, but funds dropped $22 million. So, one would
ask: what is happening here? This simply has to do with actions performed by the
company given the price fall, to attempt to reduce operating costs. And that is seen
here. We have a difference of $7 million that we did not suffer from the fall in revenues,
simply because of what the company has done to improve its operating costs to react
before this price situation.
Likewise, and here we are going to highlight this with further detail, regarding
operation and transport, in this quarter we had costs for $11.8 million, compared to $16
million that we had in the past quarter. That is, we have had 30% reduction. So here we
already start to see the explanation of why the generation of funds was not so
affected.
Equivalent in barrels, we are saying that we lowered costs of each one of our barrels
from $16.33 to $11.82. But we have also had adjustments and cost reductions in general
and administrative expenses of the group. So, we went from $5.7 million dollars per
quarter to $4.9, a 15% reduction, which in barrels equivalent goes from $5.5 to $4.86.
And as I mentioned before, and Diego will detail this later, our goal is to continue
reducing costs, particularly in Llanos 23. As I mentioned, with the investments that we
are making in facilities, what we look for is to continue reducing production costs in
Llanos 23.
In La Esperanza there is really not much that needs to be done. Operating costs are
very stable, and with the increase in production levels that we are going to have by the
end of the year, operating costs will basically be unaffected and should tend to be
reduced with a higher production volume.
As in all quarters, here we make the comparison and evolution of revenues and costs,
comparing all quarters. We had been in this revenue trend, obviously favored until
September by the good prices that crude had and, as we mentioned in our
presentation of results as at December and with the results of this quarter, revenues
have dropped because of the fall in prices; but it is also seen that costs were rising and,
as we mentioned, we have also achieved to have good cost management.
Here we outline the latest quarters, and also fund generation of $33, $34 and $37, and
again the effect that we see from the fall in prices. I want to highlight that we keep
having a positive operation.
Now then, as a result from the price situation, we are reporting a net loss of US$15.6
million. It has been affected, because of the various accounting records that affect
profit, but these are matters that do not affect our cash. As we have just seen, our
operation is still positive, but there indeed are some accounting effects that lead us to
net loss. A very important one is the deferred tax expense for US$4.7 million. These are
taxes to be paid in the future, but which we must record even when they were not a
cash disbursement in this quarter. In addition, depreciation was higher in this quarter
versus the comparative quarter of last year, of $12 million compared with $9 million.
This is also contributing to generate this loss; and, as you know, the National
Government by the end of last year issued a new tax reform that impacted all
companies with higher taxes in relation to the CREE, and additionally with the wealth
tax, the impact of which will be of $1.5 million, which we already had to record in the
financial statements of the year 2015.
Here, again to highlight, the EBITDA. From this profit or, in this case, this loss, and
compared to the quarter of 2014 in which we had profit, we make all adjustments and
still end with a positive EBITDA that keeps being lower than the one we had a year ago,
but keeps being a positive EBITDA result, which confirms that we remain a company
that generates positive flows.
Now I will comment on two recent matters that we have anticipated in the company,
as well as other additional actions to keep working in the future in the development of
the company’s operations. As you know, we had a syndicated credit led by Credit
Suisse that was initially for an amount of US$220 million. In April we had principal to be
paid for US$176 million dollars. At the end of the month of April, after a long process
that we followed with the BNP Paribas bank, we refinanced this debt with a new credit
for US$200 million, whose main features are: maturity on September 30 of the year
2019, a very competitive and very good rate that does not vary with respect to the one
we had with Credit Suisse, of LIBOR plus 4.75%, but the main thing of this refinancing
has to do with the grace period. We are going to start paying principal of these US$200
million from the month of December of 2017. What does this mean for the Company?
That we will no longer have to make quarterly amortizations of US$14.7 million until
December of 2017, which frees cash to be able to continue investing in the
development of our production of the company. So, if you do the math, we are talking
about close to $15 million, for 8 installments, so we are freeing little less than $80
million dollars in cash that we would have to be paying had we remained with the
financing we had with Credit Suisse.
And this other matter is also very important. We also achieved a better condition in
relation to covenants, where the main is “leverage ratio”, which basically is debt
divided by EBITDAX. As you see in the financial statements that we published with
Credit Suisse, our “leverage ratio” level was 2.75. Here we have improved significantly,
to reach a level of 3.5. Obviously this gives us more flexibility with respect to the
current price situation. If prices rise, well, we will have a large margin. But as you know,
for all companies in the sector, this was one of the main indicators that the whole
industry and all analysts and the financial market were watching.
As to the cash situation, by the end of the quarter we have US$44 million of free cash
and US$74 million of restricted cash, where you remember that the main component of
this is our investment that we support in Ecuador, for more than US$45. Now, it is
worth noting that the final cash result that we had on December 31 and has dropped
with respect to March, is mainly due to payment of pending accounts we had from 2Q,
which refers to the quarter ended in December, but they actually were payments that
came from all the investments that we made during the year 2015. So, in this quarter,
we received all this invoicing and we got up to date, which meant a cash disbursement
of US$46 million. This is nothing special, just payment of such investment commitments
from the end of last year. In addition, what I mentioned about debt amortization, and
we also had other working capital matters and other operating activities.
So, with this situation as at March 31st, plus what I have just commented on financing,
we have a much better situation in terms of cash today, in the month of April. As you
remember, we financed $200 million and paid $176 million, so we have twenty four
million additional and free, that enter as cash in the month of April, and in addition in
April we also made a US$25 million disbursement of senior notes that we issued last
year with Apollo. So, as you can see, we are talking about $25 plus other US$24 million,
plus $44 million, so we have a cash position in the month of April that is much better
and very similar to the one that we had at the end of December of last year.
Another important matter to highlight was the acquisition of the additional 25% of VIM
5 and VIM 19 blocks during this last quarter. If you remember, last year we completed
the acquisition of 75% and another partner, with whom we had been working, had 25%.
These price situations create problems, but they also create opportunities, and that is
basically what Canacol did. In this situation that affects all and particularly the partner
that we had with 25%, it was possible to make this additional acquisition of 25% of these
two blocks. VIM 5, where we already have a discovery, and VIM 19, with an additional
and interesting gas potential, and basically, the cost of this transaction, for a little more
than US$34 million dollars, equivalent in these payments, that were in shares, 8.7
million shares of the company, valued at the time in US$2 dollars, US$5 million payable
in September of 2015, at our option, at Canacol’s option, to be paid in cash or in shares,
and debts that this partner had with us, of US$15 million. So, basically, what you can see
is that we entered into this transaction without having to draw a single peso from our
cash, but we obtained 25%.
And these are other matters conditional in the future, to which the seller of this
interest is entitled, with the right to a 1% royalty on additional revenues for gas sales in
discoveries other than Clarinete. That is, the production from Clarinete does not have
this royalty. If we get to drill into another structure, another field, and we make a
discovery and achieve to have sales, then there will be the right to a 1% royalty on such
new production. And there is a cap of up to US$10 million. In addition, when we make a
reserves report in June of 2016 in Clarinete, if we achieve to increase reserves with
respect to what we have in the reserves report made in February and which was the
basis for this negotiation, if those reserves increase, well, there will be a right to 1.13
million per each bcf of these additional reserves of Clarinete, 25%. And again, also with
a cap of 13 million. So, basically we want to comment that we have made a negotiation
taking advantage of the opportunity that these circumstances and the market situation
create, without disbursing one single peso, one single dollar.
To conclude our perspective for the year 2015, we continue and maintain a wide and
diversified portfolio of oil and gas assets, and we continue exploring alternatives and
new opportunities in the market. As I said, more than 50% of our production is not
exposed to the volatile environment of the crude price. In addition, with refinancing,
we have improved our financial structure and we continue having access to financial
partners. Surely you have seen the market as it is. News for the oil industry is not the
best. Accessing financial markets is not easy, but markets have had confidence in us.
The syndicate we closed with BNP is composed of six banks that show their confidence
in the company. So, we have access to financial markets. And, in addition, our financial
partner, as you know, is Apollo, with which we could make an additional disbursement
of US$25 million.
With this, we are very well positioned to act in this price uncertainty. We keep
maintaining positive production levels and cash flows. Once we increase gas
production four times, we will have significant cash flow generation. By the end of the
year we will focus on growth of the local gas market (we will later talk about what is
happening with the gas market) and we intend to keep our investments in the main
strategic assets that we have, which are Ecuador and Llanos 23.
And this is all for this part. I turn the floor over to Diego.
Diego Carvajal, Vicepresident of New Businesses
Good morning to all. We are going to see something more from the operational point
of view and actions that we are performing and we expect to complete during the rest
of the year.
This slide is simply a summary of recent history. You can see the development of the
company represented here, from its creation in 2008, when it depended 100% on the
Rancho Hermoso Field. We initially talked about Rancho Hermoso S.A., and we
depended completely on oil.
By the end of 2011 we acquired Carrao Energy and brought a series of interesting assets
to Canacol, which would later result, in additional production, particularly of crude, and
development of contracts with very large partners, in what has to do with the Middle
Magdalena Valley for unconventional assets.
In 2012, we acquired the Shona Energy Company, in a strategic decision to diversify our
portfolio and focus on gas, at a time in which most companies considered that gas was
not a good business in Colombia, and much less in the north zone. But we believed in
growth of the North Coast market and were aware of the decline in the Guajira fields,
which we will later see that are still declining at an annual rate of approximately 20%,
and therefore we believed that there actually was a good market, plus the fact that
there already was a very high quality client: the Cerromatoso nickel mine, owned by
BHP Billiton, which guaranteed a very stable cash flow that would help us.
Finally in 2014 we identified the exploratory potential in the two additional blocks that
were acquired from OGX. And this was already approved as a good decision with very
positive results with the discovery of Clarinete, of which we will talk later. It is worth
mentioning that in the report of Wood Mackenzie on exploration results at a Latin
American level, Latin America understood as everything south from the Rio Grande,
that is, including Mexico, Clarinete is the third largest discovery made in Latin America,
only behind a discovery made by Pemex in the Gulf of Mexico, and then there would
come the discovery announced by Ecopetrol, Repsol and Petrobras, “Orca”, here in the
Colombian offshore, and the third largest discovery reported last year, a well drilled
last year and proven this year, is the one of Canacol, with an equivalent of around 60
million barrels. We are talking about close to 350 bcf.
Numbers in terms of exploration success rate are 63%, which is a good rate according
to any standard, more than 50 million additional barrels in 2P reserves, and obviously
the development wells, because the rate is always much higher.
What are we doing? Or what is the outline of the investment strategy for this year? We
are focused basically on gas, because the contracts that we have are mostly
independent from crude price, WTI y por lo tanto, to the extent to which we have this
production we are not depending on crude price fluctuations. The guidance for this
year is between 10 and 12 thousand barrels per day, of which, as Nicolas mentioned
before, with the production that we expect to have by the end of the year, we would
be talking of 60% independent from WTI. US$84 million of capex for exploration and
development. And these very important figures. At this time we have certified 345 bcf
of 2P reserves or 60 million barrels equivalent and 23 million barrels of crude. The
figures that appear here are the NPV-10 with an “EV” of US$571 million.
What does it show? It is a summary of the company’s history. It shows a gradual and
organic growth in what has to do with oil reserves, which have continued to increase,
and we currently have 23 million barrels.
In gas reserves, the initial acquisition of Shona, that brought some reserves, the
gradual growth of reserves with the drilling of exploratory wells, and finally the great
Clarinete discovery that allows us take the reserves to the equivalent of 60 million
barrels.
Again, you have seen this map many times. It simply shows where we are focused and
where is our investment this year. In sum, we have in the east, which is light crude, in
Llanos, which is light crude, and in the Lower Magdalena Valley, which is dry gas.
These are areas where we have positive netbacks, and these two areas, the one of
Ecuador and the one of the Lower Magdalena Valley, where we have revenues that are
independent from WTI.
Of the $84 million dollars for this year, the most part of them go to development and
what we are seeing here in the distribution of the graph is that close to half is focused
on development, facilities and wells to be ready to produce 83 million cubic feet per
day by the end of this year. This means that we would practically multiply the current
production by four to reach these 83 million and the EBITDA would go up from $30 to
$150 million dollars. The rest goes to Llanos and to Ecuador.
What important matters are left in terms of activity for this year? Two wells that we will
be drilling in the Clarinete discovery.
Firm, at least one workover in 2015 for Llanos 23.
The flow line of Clarinete to Jobo, which we have to finish to be ready, is already in
construction. We are purchasing land, we have the environmental permits.
And in what has to do with light crude, which is basically Llanos 23, we are generating
additional options that will be viable to the extent to which prices continue evolving in
a positive manner. We have one firm and we may have many more, depending on how
the crude price evolves, but at this time they are not included.
The flow line that is also progressing and the facilities that will allow us continue
reducing the opex; and the 3D seismic that is important for Llanos 23. Part of the
seismic was already acquired, the acquisition ended in January of this year, we already
received the processed cubes, and we are in the interpretation process to confirm the
structures previously identified. This interpretation must be complete by the end of
June, so that we may be prepared to drill in the second half of the year.
Here we see the current evolution of reserves, this is what we had already seen that we
have, in terms of acres, which is an important factor in the position one has in a basin.
Canacol at this time definitely is in a very good position in the Lower Magdalena Valley
and in the rest of the country, we have 23 contracts in total, with almost 3 million acres,
and 280 million barrels equivalent are the potential of prospective resources in
inventory.
Gas demand has significantly increased in the sector, in the whole country it keeps
increasing, but most of all in the north sector, in the coast. If you see this graph, these
data come from the Mining and Energy Planning Unit, where it is shown that yes,
indeed, between 2014 and 2018, it is estimated that gas demand will increase
throughout the country, but definitely in the north coast is where this demand increase
is going to be more focused. In Colombia, compared to gas demand growth, we are
talking of an average of 9% versus 1% estimated on a worldwide level. All lines show
that, definitely, with the decline in Guajira and the increase in demand, well, our gas,
the one we have right now, that is already committed, as well as new possible
discoveries, will have the possibility to generate very favorable contracts for us.
These figures again show how the demand increase will be of around 15% and what will
be available in 2018 will be around 500 million cubic feet per day, today with a 20%
decline for these three fields. Demand in 2018 will be estimated close to 575 million
cubic feet per day, which shows the gap that definitely would be our purpose to close.
In the Lower Magdalena Valley, we have 6% of the production in Colombia. This is a
schematic delimitation of what is called the Lower Magdalena Valley Basin. Among the
more important features, this feature here is what is called the Santa Marta –
Bucaramanga Fault. These are tectonic features. This is a lineament that is between the
Middle Valley and the Lower Valley, and a fold area that separates the Lower
Magdalena Valley from the fold belt of the Caribbean Coast.
With the two gas discoveries that we made in the year 2014, 2P reserves tripled. That is
a very positive result also from the perspective of exploration and organic growth for
this part of the reserves, and this is accompanied by contracts. As we have said several
times, unlike crude, to be able to talk of gas reserves, resources in the subsoil plus a
contract are required. The signed gas contracts allow us increase production by six
times more during the following three years. If we refer only to the Lower Magdalena
Valley basin, in the blocks that Canacol has in exploration and production, we have
around 15% of the basin, which leaves us very well positioned. The other important
players up to now have been Pacific, which was in La Creciente area, and Hocol, which
also has several blocks in the sector. But definitely, in terms of exploratory potential
and recent results, our blocks have proven to be the more prospective.
This is a figure that is worth taking into account. In the Lower Magdalena Valley. In the
prospects and leads that we have identified, some of them, the most part already
covered with 3D and others only with 2D, the potential of resources is of more than 2
trillion cubic feet, 2 tcf (American trillions); which truly shows what is yet to be drilled in
the Lower Magdalena Valley, what is yet to be drilled specifically in VIM 5 and in the
other blocks we have. The growth potential is definitely gigantic.
And the risk, after the Clarinete results, well, the risk from the geological point of view
is considerably reduced.
In the new blocks that we purchased, which are (that is the VIM 21 block) in new blocks
that we acquired from OGX, you can see, first, the geographical convenience as they
are close to the facilities that we already have, the size of VIM 5, and here what we are
showing is, this is the discovery, what is in red are already discovered fields, and these
shapes in yellow color are leads and prospects. The major part of this sector is covered
with 3D and we would be doing 3D in other sectors to confirm the existence. But the
potential, the message I want to leave you, is that the potential in terms of prospects,
unrisked prospective resources, is of about 2 tcf.
This we had seen at some point. We bring it back. This is the structural map detailed at
Ciénaga de Oro top level. Only to remember where the discovery is, this is Clarinete 1
and the location of the two firm wells to be drilled this year. The first is Clarinete 2.
Remember that in Clarinete 1 we tested 40 million cubic feet, in short tests; and if we
have Clarinete 2, which is in a higher position, the potential should be equally
important, which would give us the possibility to sign new contracts, because we
would already have more production capacity. The Oboe 1 well, that you see, is slightly
further away from Clarinete 1.
What needs to occur from here to December so that we may increase our production
up to 85 million cubic feet? We are expanding the facilities in Jobo from 50 to 100
million cubic feet per day. We have to finish the flow line that goes from Clarinete to
Jobo, which is of about 15 kilometers. There we have looked for all possibilities to
speed up the construction process.
This, then, is the target, going from 20 million cubic feet per day to 83, although it is
worth mentioning here that, as Nicolás said, during one day of this week we had a
record production, because apart from the stable 20, 21 million cubic feet that we sell
to Cerromatoso, we add the production of interruptible agreements.
Promigas is the owner of the line that goes from Cartagena to Sincelejo and then to
Jobo, up to here. The line that goes from Jobo to Cerromatoso is property of
Cerromatoso. We sell gas here at wellhead, that is, transportation and maintenance of
the line is not ours, here are the 20 million cubic feet, at this time we do not have the
capacity to send to the north, but such are the works that are being done, to increase
from 15 to 75 million cubic feet what has to do from Jobo to Sincelejo, and such
requires modernizing the pipelines. This is what Promigas is doing. This is a project that
is ongoing, and when we talk here, between Sincelejo and Cartagena, about seeing the
possibility of expansion of the oil pipeline, it is also because here is La Creciente, which
is Pacific’s, and very close to La Creciente are the Bonga and Mamey fields of Hocol, so
what they are doing is building a pipe to connect and get here to Sincelejo. The
additional capacity that will be here by the end of the year includes our additional 65
million cubic feet that will go up to here, plus the possibility to include 30 million cubic
feet of what Hocol will produce; that is, all this is being considered, including the
volume needed by our competitors in the area. The only thing that will be done in this
Filadelfia section will be adding compressors, with which capacity will be increased to
send to Cartagena.
All this will finally lead us to having the capacity, in December of this year, to send the
additional 65 million cubic feet in the north, covering the contracts that we have, some
at US$5.40 per KPC and the other at US$8 per KPC. Fixed prices, indexed to 2 and 3%.
Llanos 23. This graph has been seen by you many times already, this is part of history,
the acres. What is important here is that, if we go back a little in history, with the
information of Rancho Hermoso and the 2D seismic that existed then, we identified
that this Rancho Hermoso fault continues to the north. What we initially did was, and
we had old 2D seismic that went across the block, with the 2D seismic we identified
leads and prospects that we would later reconfirm with 3D seismic. We did a relatively
small 3D seismic program, initially 70 kilometers to the south, 30 kilometers to the
north, and with that 3D seismic we identified the prospects that later became
discoveries.
But there is much potential in the area. What you see here in orange color are
prospects and leads identified in 2D, which, to increase the probability of success, we
needed to cover with 3D. So, already in the north, this yellow area shows the seismic
that was already acquired, here we already finished the acquisition in the field, which
was already processed and we are interpreting. We have confirmed the existence of
several of these leads, which are now are actual prospects, and when we complete the
interpretation, with volumetric and depth calculations to drill the wells, which is what
we expect to have by mid- or late June, we might be in capacity to drill, and at that
moment we might really be in capacity to reverse the natural tendency of production
decline in Llanos 23. You know that in Los Llanos the reservoirs are so good that they
also decline very fast, that is, they get to production very fast, produce at very
interesting rates, but they also have high decline rates. The only way to replace this is
with new wells, which is what we have been doing. When we have this prospects and
drill, we are going to reverse the tendency and we will surely increase production
again. In the meantime, with workovers, we also expect to have a positive impact. We
are not going to get in a workover the production of a new well, but such will be
interesting figures that may impact and may also reverse the reduction tendency.
This is just a summary of our position as to shale oil in Colombia. Our partners Exxon,
Shell and ConocoPhillips. This is a well announced by Exxon to be drilled in VIM 37 with
Sintana, which if given on time will provide us with useful information for our own
assessment.
An important figure to remember here is that the estimated mean in terms of reserves,
this would already be recoverable, recoverable reserves for Canacol, is around 185
million barrels, which is to say other size of company at the time in which this works
out.
So we definitely remain focused on gas, while we wait for the recovery of oil prices.
The potential of exploration resources, more than 280 million barrels equivalent and
the figure that I would like for you to keep in mind is the gas potential of the prospects
that we have, which may be close to 2 tcf.
In Colombia, actually, in recent years, there has not been a discovery of the size of
Clarinete. This is big for Colombian standards in what has to do with gas.
In the three fields of Chuchupa, Ballena and Riohacha, when they were discovered in
the time of 1970, total resources were of about 3 or 4 tcf, and they have produced for
many years.
Well, thank you very much. Are there any questions?
<Breakfast invitee makes a question>:
Well, thank you for the presentation. I have three questions. The first is what risks do
you see of not being able to deliver the gas that you have already contracted for
December of 2015? I refer, above all, to the gas pipeline that goes from Clarinete to
Jobo, if that has some type of risk that may delay you. The second question is how
much can consolidated costs be reduced in terms of opex and SG&A? And the third
question is if you have seen something in these blocks of the round of Ecopetrol, of
which there has been talk these days, I don’t know if you are looking into some gas or
oil in general.
<Diego Carvajal answers>:
ANSWER: Well, the first question. Risks of the flow line from Clarinete to Jobo. We do
not anticipate major risks. First, because what usually causes delay in these works is
getting the environmental license, which we do not require. Up to the beginning of this
week, we had already negotiated around 70% of the lands, which is the other thing that
may be delayed. We have the environmental permits, given by regional corporations,
so we do not anticipate much delay in this sense.
<Nicolás Acuña answers>:
Well, as we have mentioned, we have three large projects: Ecuador, where there are no
costs. Zero opex, all costs assumed by Petroamazonas. Therefore, well, there is no cost
reduction there because costs are zero. In gas, what has to do with gas, as I noted,
costs are basically fixed, which is the Jobo station operation. Basically, with the
production increase, we would expect a marginal reduction of costs per barrel as
volumes increase, but we will also increase costs. We expect that in gas production
operating costs will be maintained at the levels we currently have, of about US$2.50
per barrel equivalent. Where we do have opportunity for reductions, what we already
commented on, is in crude production from Llanos 23 with the investments that we will
be doing in facilities. Basically we are going to have three savings: Transportation cost
reduction. We are currently transporting by tanker trucks from all fields. In each one of
those fields we have loading facilities, we have personnel and so all this transportation
cost plus all these personnel will be reduced because we will concentrate it in one spot
that is down from Labrador, where we say that the new Pointer facilities are. We will
transport all crude through the flow line and we will collect it in one station, which will
allow us saving transportation costs, because distances are shorter and everything is
concentrated in one only place, and also, obviously, what has to do with the part of
maintenance and operations and personnel concentration. And the third important
saving is water treatment. Today we have to treat the water. In Pointer we will
transport crude and water, and water will be reinjected in the Pointer well.
<Diego Carvajal answers>:
The third question was about Ecopetrol processes. We are, yes, we are taking part and
looking into opportunities of some exploratory blocks that they are offering. They have
already started a formal process and we were invited to participate. In those fields,
those blocks, because they are exploratory, they are really more for crude than for gas;
but, anyway, we are looking into them and if there is something interesting we will
definitely go for them. We keep looking for opportunities. We are positioned in the
Lower Magdalena Valley. We keep looking for opportunities.
<Breakfast invitee makes a question>:
Good morning. What are the production expectations for Llanos 23? Now that we are
in an important decline in production for this period, what do you expect for what is
left of the year in the production of this well?
<Diego Carvajal answers>:
Look, the fact that we have significantly reduced the lifting cost, tightening our belts
these days, surely if the crude price continues evolving many projects will become
viable, including some workovers. Each workover that is achieved is a very fast work of
intervention. It must have an impact. And the others would be the exploratory wells.
So, depending on that we will be seeing results. The advantage here is that workovers
obviously are wells that are already producing, what is done is that a zone is turned
down, closed, and another is opened, because the well is already connected, so those
barrels come in immediately. And the exploratory ones, well, as we have a main line
that goes from the north, passes underneath the river, reaches Pantro, well it will be
very easy to connect any discovery and it also may be put into production immediately.
But this will depend on that. Today it is firm, remember, a workover, but as things are
evolving, this is very dynamic, so then, to the extent to which prices improve, other
workovers would turn to be viable, and there we would have to increase production.
<Breakfast invitee makes a question>:
Good morning. Thank you for the presentation. I have several questions. The first
related to the reduction in cash position of 80 million and an investment cash flow, a
capex of around $30 million, excluding acquisitions. The capex plan is $84 million, but
taking into account that in the first quarter, well it is the third part, can we expect this
$84 million capex to be widely increased in 2015? The second question is related to, I
want to know a little about, you announced that Altenesol has already sold the LNG or
the gas once you give it to them. I would like to understand who the purchaser of such
gas is. And the third question is what can we expect for the next quarter in terms of
asset impairment, taking into account, well, that oil prices are clearly lower and no
impairment has been recorded in Llanos 23?
<Nicolás Acuña answers>:
ANSWER: Well, with respect to capex, well, basically the investment program that we
have is the one we have presented to you, for US$84 million. This capex is supported in
cash flows we have, our production plans, our operating costs and refinancing and
disbursements that we have made, and, obviously, with the initial cash we have in the
year. So it is sufficiently supported and the company, with the current price situation,
well, has defined that such is the level of capex that can be supported with this price
situation and with the flow forecast that we have. If the price remains there, we will be
able to make further decisions because additional cash flow will start to be generated
and we may look for additional projects. But at this time, such is the investment plan
we have, with the estimated cash flow.
<Diego Carvajal answers>:
Yes, the initial press release mentioned that the purchaser that Altenesol has is a firm
named Adventures International. It’s them.
<Breakfast invitee makes a question>:
The third point is the matter of impairments in the quarter that closes the fiscal year.
<Nicolás Acuña answers>:
Well, obviously when we end on June 30, studies will begin with our reserves auditors,
who are DeGolyer and MacNaughton, and they will make their reserves study, and
based on such reserves study, which basically will be with the price forecast that the
market will have at the time, well, they will make their analysis and based on that we
will determine if there is or there is no need to record any impairment. As you know,
historically we have been recording impairments in Rancho Hermoso. We want to tell
you that basically in Rancho Hermoso there will be no more impairments because there
is nothing else, we recorded all the possible impairment. In gas there will be no
impairments.
Thank you.