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Edited Transcript of IPCOR.ST earnings conference call or presentation 5-Nov-19 8:00am GMT

Q3 2019 International Petroleum Corp Earnings Call

VANCOUVER Nov 9, 2019 (Thomson StreetEvents) -- Edited Transcript of International Petroleum Corp earnings conference call or presentation Tuesday, November 5, 2019 at 8:00:00am GMT

TEXT version of Transcript

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Corporate Participants

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* Christophe Nerguararian

International Petroleum Corporation - CFO

* Mike Nicholson

International Petroleum Corporation - President, CEO & Director

* Rebecca Gordon

International Petroleum Corporation - VP of Corporate Planning & IR

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Conference Call Participants

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* James William Hosie

Barclays Bank PLC, Research Division - Research Analyst

* Joseph Lye

BMO Capital Markets Equity Research - Associate

* Karl Fredrik Schjøtt-Pedersen

ABG Sundal Collier Holding ASA, Research Division - Research Analyst

* Mark Wilson

Jefferies LLC, Research Division - Oil and Gas Equity Analyst

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Presentation

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [1]

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Okay, so a very good morning to everyone, and welcome to IPC's third quarter results and operations update presentation. My name is Mike Nicholson, I'm the CEO. I'm also joined this morning by Christophe Nerguararian, the CFO; and Rebecca Gordon, who's our VP of Investor Relations.

I'll begin in the usual fashion by taking you through the operations update for the third quarter, and then I'll pass across to Christophe and he will run through the financial numbers. And at the end of both presentations, you will, of course, have the opportunity to ask questions and we can take those from the participants who're joining from the conference call, but you can also send your questions in via email.

So to get started with the operations update and just a recap on IPC's corporate strategic pillars, the 4 pillars: delivering operational excellence, maintaining financial resilience, maximizing the value of our resource base and growing through M&A. And I think when you get through the third quarter results, we continue to make good progress in delivering against all those strategic pillars.

So starting now with the highlights from the third quarter. And if we look at our production numbers, our third quarter production was 45,500 barrels of oil equivalent per day, and that was in line with our revised second quarter guidance that we gave. And we're retaining our full year guidance towards the lower end of that full year Capital Markets Day range of 46,000 to 50,000 barrels of oil equivalent per day.

We're going get into -- later in the presentation, our capital program was always a very much back end-loaded Q4 program, so we still expect to be exiting 2019 in excess of 50,000 barrels of oil equivalent per day as we get the production contribution from all of our growth projects.

Good performance in operating costs continued through the third quarter at $13 per barrel. And we are, therefore, retaining the full year guidance that we gave at our Capital Markets Day of just under $13 per BOE.

Likewise, in the capital expenditure program, very active period right now, probably one of the most active periods that we've had for IPC. Big capital spending in the fourth quarter, and we're retaining our $188 million full year capital budget. And as I mentioned, we currently have drilling operations ongoing in all of our key business areas in Canada, in France and in Malaysia. And I'll give some more color around that program as we come through the presentation.

IPC continues to deliver very strong cash flow. If you look at our operating cash flow in the third quarter, it was $70 million. And when you set that in context when we had our Capital Markets Day, we had a full year cash flow guidance range of $163 million at the low end up to $330 million at the high end and our 9-month operating cash flow is $229 million, which is close to 70% of our high-end guidance at using a $70 per barrel Brent oil price assumption and given the year-to-date Brent price assumption has averaged around $65 per barrel, we're certainly trending towards the high end of that guidance range that we gave at the beginning of the year.

And of course, with such strong cash flow generation, we'd always envisaged that we would fully fund our capital program from our cash flows. But with higher absolute oil prices and better realized prices, we generated significant free cash flow in the first 9 months in excess of $80 million. And that's allowed us to materially reduce our net debt. Again, in the third quarter, we've seen our net debt position drop from USD 239 million down to USD 208 million by the end of the third quarter. And the company is still in a very strong liquidity position. We have existing undrawn bank lines of -- in excess of $200 million, and I'm sure Christophe will comment on those facilities later in the presentation, but we certainly think those could be stretched further.

The resource base at the end of last year following the acquisition of BlackPearl we had a material increase in our 2P reserves to just under 290 million barrels of oil equivalent. With the acquisition in the first quarter of some additional land positions, we managed to further increase our contingent resource base to 1.3 billion barrels when you add on the close to 1 billion barrels of contingent resources that we have, and a very long life reserve index on our 2P reserves of around 16 years.

We've always talked about the large discount that our stock trades at relative to our 2P net asset value, that's independently calculated by our third-party certifiers. We saw 37% increase in our net asset value per share at the end of last year to $12.40 per share. And today, IPC is currently trading at a close to 72% discount to that net asset value. And that doesn't give a single dollar to any of our contingent resources, so I'll come back to it later. But for the second time since the company spun off back in April 2017, we're launching a share repurchase program.

That does not mean to say that we do not continue to have our opportunistic approach with respect to further acquisitions. And as I mentioned, we still got a very strong liquidity headroom under our existing unstretched facilities in excess of $200 million so we're still prepared to look for further acquisitions.

I'm very pleased to report that on the HSE side, we've had no material incidents through the third quarter.

So if we get into just a little bit more detail now and we start with our production growth as I mentioned in the highlights. You can see our third quarter production was in line with the latest guidance, which was at the lower end of the Q3 guidance range, 45,500 barrels of oil equivalent per day. The ramp-up that you can see on the slide in the fourth quarter is coming from the contribution of 3 infill wells in France from the redevelopment of our Vert La Gravelle field in France and the production adds from the steaming up of our Pad F on our Onion Lake facilities in Canada. And as a result of the ramp-up in the fourth quarter, we're both retaining our full year production guidance at the lower end of the 46,000 to 50,000 barrels of oil equivalent per day range and we're retaining the 50,000 barrels a day exit guidance given that those projects are coming onstream through the fourth quarter.

If we turn now and go into the capital program in a bit more detail, I'm going to start with the Onion Lake Thermal project in Canada. As we discussed in the second quarter results, if you look at the chart on the bottom right-hand side of the slide, you can see in the fourth quarter of 2018 we did -- production was slowed down to deal with very high Canadian differentials. And when we tried to ramp production back up in the first quarter, we were constrained with our facilities as a result of the extremely cold winter that we saw in the first quarter of 2019. I am pleased to say, though, that the team in Canada has taken a very proactive approach, and if you look at what we've done through 2019 in terms of facility optimization on our Phase 1 facilities, the planned fourth boiler has been installed, which lifts the production capacity of both Phase 1 and Phase 2 from 12,000 to 14,000 barrels of oil per day.

Given we were facing water constraints in June, we've got approval to install 2 direct intake hoses, which supplemented water supply. You can see the picture on the top right-hand side of the slide is a produced water recycling skid and that was installed in July. What we've also been able to do is get approval to construct our permanent water offtake system, which was completed in October. So what that means taken together if we face similar weather conditions as we move into 2020, then we have more than enough redundancy in place to deliver the required water for those facilities.

Did mention during the second quarter report that there was a temporary delay in the ramp-up of our F-Pad wells as a result of the water constraints. Happy to say that steam injection commenced during the third quarter, production started up in September and you can see the production uplift on the bottom right-hand side of the chart, on the slide. And we expect by the end of this year when Pad F is fully ramped up to be reaching close to 12,000 barrels of oil per day.

Turning to the Suffield asset in Canada. You'll recall we announced in our Capital Markets Day that we plan to drill 17 conventional oil wells on our Suffield property. By the end of the third quarter, 15 out of those 17 wells have been put online. We've continued with an extensive gas swabbing program and we've completed close to 6,700 swabs by the end of September and we hope to complete around 8,500 by the year-end.

Again, we also continued with our refrac and recomplete program on the gas optimization side. And 75 out of a planned 150 well program has been completed and we still intend to complete those by the year-end.

We announced in our first quarter results that we plan to accelerate our enhanced oil recovery project, which was the N2N project. You can see a picture of the facilities on the top right-hand side of the slide. Pleased to say that we successfully commissioned and started up those facilities and injected chemicals during the third quarter. And at the end of September, 4 out for the planned 8 wells as part of that N2N EOR project were online, and we're still on track to have all those wells online by the end of this year. It will take some time for that project to ramp up as the reservoir reacts to the chemicals that have been injected, but we do expect to see incremental production from this project over the next 2 to 3 years reaching a plateau production of an additional 1,250 barrels of oil per day.

Blackrod, which is our biggest single contingent resource, we approved a budget at the beginning of the year to drill a third well pair. The objective there was to increase the length of the horizontal section and fit that well with the latest completion equipment, and I'm pleased to say that, that's been successfully completed. We drilled close to a 1,400-meter horizontal section, and the plan going forward is to start steaming up early 2020 with production ramping up through next year.

Turning to Malaysia and if we look at the production chart on the bottom right-hand side of the slide here. The Bertam field has been a big success story for the company. We've had 3 phases of development. You can see here the initial first phase is the dark blue bars on the bottom of the slide and those are the base wells. And then in 2016, we drilled an infill well into the A15 area, which is the light blue. And then in the first quarter of 2018, we drilled a further 2 infill wells.

And when we look at the production contribution from those last 3 infill wells that were drilled, it's accounting for close to 55% of the total production from the Bertam field. We did successfully drill earlier this year the B5 pilot well into the A15 area, and the results were better than expected. So as a result of that, the third well that we plan to drill as part of this program is going to be in that A15 area. You can see the location there on the map, the third well is the A20 well.

The 3-well program recommenced in August. If we look at the average production that we had during the third quarter, it was around 5,100 barrels of oil per day. And once we've got all those 3 wells onstream by the end of this year, we expect to be back up to just above 10,000 barrels of oil equivalent per day gross, which is 7,500 barrels a day net to the company. And the last time we were producing at those rates, you can see from the chart, was around July of 2017, so we should see material growth coming from Bertam over the next couple of months.

Turning to France now. Our third quarter production in France averaged 2,500 barrels of oil equivalent per day. The biggest single activity that we had budgeted for 2019 was the Phase 1 redevelopment of our Vert La Gravelle project in France. You may recall that this was a project that was originally started back in the Lundin Petroleum days back in 2014, and we invested EUR 23 million in the production facilities, in the pipelines. And that was supposed to be a 3-well vertical redevelopment program. Given oil prices crashed, we suspended that field redevelopment after the first 2 wells. And what we decided to do this year was to try and take a slightly different approach and to utilize horizontal drilling techniques that we've successfully deployed in our Malaysian projects, also in our projects in Canada. And this is the first time that we've ever drilled in these Rhaetian Triassic reservoirs, a long-reach horizontal section. It's relatively challenging. The thickness of the reservoirs, these Triassic reservoirs, are only 3 to 4 meters in thickness, so the challenge is to keep the well in within the reservoir.

Happy to report that we have successfully completed the 360-meter section, which is our VGR113 well. And you can see on the top right-hand side of the map the location of that well, which is in the western flank of the field. And we started that well up in September. And the initial results, I think it's fair to say, we're very pleased with. We are ahead of expectation. And current production from the field, we see here, above 1,000 barrels a day from this well and France now producing in excess of 3,000 barrels per day. If we actually look at recent rates from the field, we're actually closer to 1,500 barrels per day, and our overall French business is producing closer to 3,500 barrels per day. And that's quite remarkable because when you look at the production contribution from that 1 well, we've got close to 160 wells in our entire French business and we've seen a 40% uplift from that one horizontal well. So very encouraging start, but of course, we need to look at the long-term production performance from that going forward.

The plan going forward now is to drill an additional 2 wells as part of the Phase 1 development. Right now, you can see, highlighted on the map on the slide, drilling is ongoing in the southwestern flank of the field. This is actually a vertical well. It's planned to be initially an oil producer and then we will convert that to water injector.

Right in the midst of evaluating the reservoir, what's been encouraging is that the top structure is shallow to prognosis. So we could see that actually, the productive reservoir section in that southern flank could extend beyond the original mapping that you can see here on the slide. So depending on reservoir quality, which is obviously very important, that would be positive directionally for the overall Phase 2 development.

So very pleased with the initial results we're seeing coming from our French business, and the team have done a great job to deliver on this project.

Turning now, I mentioned the operating cash flow generation. And if we go back to when we set our 2019 capital budget, we were using a planning assumption back at the beginning of the year of a Brent oil price of $60 per barrel and a Canadian WCS differential of $20 per barrel. So our base case forecast was just over $230 million of operating cash flow and for the full year. You can see that our 9-month cash flow of just under $230 million has almost delivered that full year budget planning assumption, so we're certainly well on the way to delivering towards the high end of that cash flow guidance. And if you look at the high-end forecast that we gave back in February, which was $70 per barrel oil price assumption and $15 per barrel WCS differential, our high-end guidance was $332 million and we're 70% of the way to reaching that target when Brent prices have actually only averaged $65 per barrel for the first 9 months. And one of the main reasons that we've been able to do that is the year-to-date Canadian differential has been only $12 per barrel. So that's, as I mentioned, allowed us to generate in excess of $80 million of free cash flow. So putting the company on a very, very strong financial footing.

This next slide just shows the latest 2P net asset value at the end of last year. When we take our asset value and subtract the net debt that we had at the beginning of the year, which was USD 277 million, that gave us a 2P net asset value of just over $2 billion. And you can see as of last Friday, the market cap of IPC was just over $560 million. So the stock is trading at a 72% discount to our 2P NAV with no value to any of our contingent resources. And also, the company's had a long track record of actually being able to replace its 2P reserves, so we feel that that's a very significant discount and doesn't fully reflect the value of our assets.

This next slide just shows a lot of activity that the company has achieved since we spun off back in April 2017. And in fact, a month after the spinoff in May of 2017, we announced a share repurchase of 25.5 million shares at just over $3.50 per share, $90 million of share repurchase. And if you look at all the work that's been done, I'm very proud of what the teams achieved. Today, we're still trading at close to those share levels. So as you will have seen in the release this morning, we've decided to initiate a second share repurchase program.

Touched upon that first program, which was a $90 million repurchase. That was when the company was producing 10,000 barrels of oil equivalent per day. We had 29 million barrels of 2P reserves, no contingent resources and then we were trading at a close to 26% discount to our 2P net asset value.

Fast-forwarding to today, our production by the end of this year will have increased by 5x. We'll have seen a 10x increase in our 2P reserves. In the meantime, we've aggregated close to 1 billion barrels of contingent resources and we're trading at a much wider discount to our 2P net asset value. And as I mentioned that Christophe will go into more detail, the financial performance of the company has been exceptional this year with material debt reductions and a big expansion in our liquidity headrooms. So as a result of that value proposition, we've taken a decision to announce this morning that we plan to buy back up to 11.5 million shares, which is close to 7% of the free float. It's the maximum that's permitted under the normal-course issuer bid rules in Canada, and that's planned to be over a period of the next 12 months. So very pleased with the performance that we've seen from the company over the first 9 months.

So that concludes my part of the presentation. I'll just pass across to Christophe now, and he will take you through the financial numbers. Okay, Christophe?

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Christophe Nerguararian, International Petroleum Corporation - CFO [2]

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Thank you very much, Mike. Good morning, everybody. I'm Christophe Nerguararian, CFO of IPC. Very happy to be commenting and walking through those financial highlights with you this morning. Another sound and good quarter from a cash flow generation perspective.

The production for the third quarter was 45,500 barrels of oil equivalent per day. And as Mike mentioned before, we are very much in line to deliver our revised guidance. We've maintained a 46,000 to 50,000 barrels a day range for the full year and very much on track as well with the recent drilling, which Mike talked about, very much online to exit the year with a production of 50,000 barrels of oil equivalent per day. We anticipate obviously a higher Q4 on the back of this production ramp-up that we're witnessing as we speak.

We also saw a lower Brent price generally across oil and gas prices both on the Brent side but in Canada as well, lower oil prices, but still managed to deliver close to USD 70 million of operating cash flow just in Q3. And as a consequence, for the first 3 months -- for the first 9 months for the first 3 quarters of this year, we've generated close to USD 230 million of operating cash flow, almost all of the operating free cash flow that we guided in our original midpoint guidance for the full year 2019.

Moving on to the next slide with having a look at the realized prices. As I said, in Q3, the Brent was lower at $62 per barrel on average and the WTI at $56, also $5 lower than what we saw in Q2. Despite that, you see on this graph the realized prices, and it's interesting to see and to note that in Malaysia, we've increased the premium oil production received above the Brent. We used to be at Brent plus $3 to $5. And over the last quarter, we've realized prices in Malaysia of Brent plus USD 5 to USD 8 per barrel. In France, the realized prices are in line with the Brent slightly below, trades at a small discount to Brent. Whereas in Canada, Suffield essentially is in line or just ahead of the Western Canada Select, which traded at an average of $44 in the third quarter. And Onion Lake has a further discount to WCS given the fact that it is a bit heavier than the WCS. Actually, the Suffield and Onion Lake realized prices, if you would adjust for the quality, are priced off a similar base. In Suffield, we are blending our production with diluent. So it's -- we have a bit more OpEx to get to that realized price. So really, the realized prices for Suffield and Onion Lake are comparable.

In terms of gas prices, it's interesting to see, so you see the red bars here showing the AECO price, which is the reference gas price in the province of Alberta in Canada, the blue being the premium, at which we, IPC, are selling our gas in Canada because we're selling at a price point called Empress, that's why we reference here the Empress gas price. Empress selling points sits on the border of the Alberta and Saskatchewan province and has been traded, as you can see on this graph, at a significant premium to the AECO price over the last couple of years. And what that means, you can see that, consistently, Empress gas price has been in excess of CAD 2 per Mcf over the last 18 months. And you can also see that over the last couple of quarters, actually over the last 3 quarters, given a significant -- a systematic hedge program, which is not a financial hedge program but really selling forward part of our production, you can see that we managed to over perform the spot price, and we have a realized gas price over the last couple months especially well in excess of the average gas prices of Empress.

In terms of operating cash flow, as I said, obviously, we've witnessed this year for the third quarter but also year-to-date on average much lower oil prices that we enjoyed in 2018. Despite that fact and with the nice additions of the former BlackPearl assets, you can see that the -- or the ability of IPC to generate strong operating cash flows is still very much the case in 2019. And as discussed before, we generated USD 229 million of operating cash flow year-to-date, close to $70 million just in Q3. And in EBITDA, we've generated 9% more than for the first 9 months in 2018. We generated an EBITDA for the first 9 months of $225 million.

Operating cash flows -- operating cost, excuse me, are under control. You can see that they are relatively flat. We've guided the market that we expected 2019 operating cost just shy of 13, 1-3 U.S. dollars per barrels of oil equivalent. And we're very much on track to deliver that performance. So operating costs under control for the full year.

Now if we look at the netbacks in 2019. So for the first 9 months on average, obviously, 40% of our production being gas in Canada, this is why the revenue on the dollar per barrels are much lower than the oil prices themselves. So revenues year-to-date have averaged USD 33 per BOE, so for the first 9 months. If you deduct from that the USD 13 per BOE of operating cost we were just talking about, you get to operating cash flows and EBITDA almost at the same level just north of USD 18 per BOE for the first 9 months of this year. And if you compare that to the overall CapEx we've guided the market for 2019 of USD 188 million, you realize that the operating cash flow covers, you only need 2/3 -- actually slightly less then 2/3 of the operating cash flow to cover the CapEx program. So out of those $18 per BOE, more than $7 are free after covering our investment program in 2019.

The other points beyond the operating cash flow is that the free cash flow or actual ability to repay and reduce IPC debt has been very, very important in 2019 as it was the case already in 2018. And so we started the year, the 1st of January in 2019, with a net debt of USD 277 million and we were able to replay close to USD 70 million of bank debt, of external debt, in -- over the first 9 months. On top of that, as you can see on this graph, we have repaid -- we still had USD 14 million owed to Lundin Petroleum from the spinoff date in April 2017. Those were the last ties we had with Lundin Petroleum. And so if you add that debt repayment to Lundin Petroleum, actually, we've repaid in excess of USD 80 million for the first 9 months.

You can see here that the sum of the development CapEx and exploration and evaluation is around $114 million. As Mike mentioned, we've always guided that the investment program and CapEx program this year for IPC was very much back-loaded and so we still expect to spend $188 million CapEx for the year with lots of activity, as you can guess, during the fourth quarter.

In terms of G&A, happy to report that the G&A of the company remain very low and under control on average. The G&A of IPC are less than a dollar, around $0.70 per barrel of oil equivalent.

As we also mentioned to you at the end of the second quarter, we've repaid the most expensive layer of capital we had in Canada in the group overall. We had some outstanding notes with a yield of 8%. We took them out and refinanced them at the end of the second quarter [last] year. And as a result, you can see that the interest expenses are -- have reduced significantly in this third quarter together with, obviously, the overall reduction in the IPC debt. Now we said it would be the case and it is actually the case in that third quarter, on average, the cost of financing for IPC is below 5%.

Looking at the financial results. You can see an impressive generation of revenues for the first 9 months of close to $410 million with a production -- an average production over the first 9 months of 45,300 barrels of oil equivalent per day. When you deduct production costs, depletion and exploration and business development costs, IPC generated a gross profit of close to USD 110 million for the first 9 months of the year. As discussed before, minimum G&A, low financial items and low taxes, mostly in France the taxes we're paying, although the $14 million here are mostly noncash, a very small portion, 20% of that is cash and mostly in France, leading to a net result for the first 9 months of the year of $65 million.

Looking at the balance sheet. So the strong message here is that the balance sheet is in good order. We have a leverage. If you look at the last 4 quarters, we have a leverage, debt-to-EBITDA, which is below 1x at 0.8x. And we've managed, as I discussed, to reduce the debt by $80 million just over the first 9 months this year.

And if you look back from when IPC had its most debt in January 2018, when we made our Suffield acquisition, so at the beginning of 2018, we had an net debt of USD 355 million, and so we've reduced our net debt by in excess of USD 160 million over the last year and 9 months. And so our message today when Mike was talking about the planning or plan to repurchase up to 7% of our stock, this buyback program doesn't hurt our liquidity at all because we still have more than $200 million of financial flexibility under our credit facilities today.

Over the summer, we had an exercise with our banks to look at whether we could extend and increase those facilities, the answer was positive, so we believe we could actually have an increased financial flexibility from $200 million to $250 million -- up to $250 million. And so our ability to buy back our shares will not hinder our ability to continue to actively invest in our organic growth because we still have lots of opportunities in our portfolio. And at the same time, as Mike mentioned, and it still remains a pillar, we are continuously reviewing acquisition opportunities. So given the strong balance sheet we enjoy today, buying back our shares absolutely not change our view and our strategy about investing in our portfolio as well as looking at possible acquisitions in Canada and internationally.

Thank you very much. On that, I will let Mike conclude.

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [3]

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Okay. Thank you very much, Christophe. So just to conclude and to run you back through the highlights from the third quarter and the first 9 months, hopefully you have the impression the company is really in great shape, when we look at our production numbers for the third quarter delivering 45,500 barrels of oil equivalent per day, and we expect all full year numbers to be towards that 46,000 barrels of oil equivalent per day for the full year. But with the investment program in Canada, in France and Malaysia, still expecting to exit this year above 50,000 barrels of oil equivalent per day.

Good delivery both on the operating costs and delivering our capital budget, exactly in line with guidance around $13 per barrel and expecting just under $13 per barrel for the full year.

And we expect to deliver the capital budget this year just below USD 190 million.

And as I mentioned during the presentation, it's been one of the most active periods right now since we spun IPC off back in April 2017. We've got -- we just finished the Blackrod drilling. We've got a drilling rig running in Suffield in Canada. We've got our drilling rig on our Vert La Gravelle property in France. And we have a drilling rig on our Bertam facility in Malaysia. So really peak activity levels right now.

Christophe's touched upon the financial numbers, very strong cash flow generation during the third quarter, $70 million, heading towards the high end of that full year guidance range of $163 million to $330 million with close to $230 million generated in the first 9 months alone. That's equivalent to the full year cash flow we expected in our budget assumptions. And as Christophe referred to, we generated $80 million of free cash flow in the first 9 months alone.

That's clearly fed into that strong liquidity position, so we fully funded the capital program. Our net debt has come down further again during the third quarter, down from $239 million to $208 million at the end of September. And as Christophe discussed, we've got currently in excess of $250 million under our existing credit facilities, and we certainly believe there's capacity to stretch those further. So the company is financially very strong.

Material resource base, 290 million barrels of 2P reserves and excess of 1 billion barrels of contingent resources and a healthy long-life reserve base of around 16 years.

When we look at the shareholder value, we've seen a 37% increase in our net asset value per share last year to $12.40 per share, that hasn't fed through into our current share price. We're today trading at close to 70% discount to our 2P net asset value. And we've got a material contingent resource base and a long track record of converting contingent resources into reserves and production and value.

So as a result of the combination of the strong value proposition and the very healthy financial position that the company finds itself in, we've decided today to launch a share repurchase program to buy back 11.5 million shares. And of course, given the strong financial position of the company, that absolutely does not mean that we can't still continue to be opportunistic with respect to further acquisitions.

And last but not least, very pleased that we did -- had a safe third quarter with no material incidents to report.

So that concludes the presentation part of the third quarter release. At least perhaps I can ask Christophe to come back, and we can open up for questions now.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from the line of James Hosie from Barclays.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [2]

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I guess just, firstly, on your buyback plans. Can you say when you expect to get the necessary TSX approval and then how quickly you think you can be completing that full 11.5 million share repurchase?

And then, secondly, just the operating cash flow performance, which as you highlighted, is trending towards the top end of the full year range, which is obviously very good. But is that down to better-than-expected price realizations or something else that's driving that despite production being at the low end of your full year guidance range?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [3]

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Okay. Yes. Thanks, James, for the questions. So if we start with the first with respect to the timing of the buyback, so we will be applying to the TSX today for the normal-course issuer bid. Typically, that takes about a week for the approval to come back and then there's 2 days from the date of that approval for when you can actually commence the repurchase. So you're looking at somewhere around the 12th or 13th of November provided approval is forthcoming that we could then start to commence that share buyback program.

In terms of timing, there are very clear rules about how much you can buy on a given day. So what they look at is the average trading volume over the last 6 months and on any given day, you're allowed to buy up to 25% of that. So I think when you look at IPC's trading volumes, you're looking at around 165,000 shares per day we can purchase between the 2 exchanges. So I can't calculate the exact days in my head, but I'll leave you to do the math

(technical difficulty)

few months it would take if we were to execute that everyday up to the maximum available amount.

And then on your second question, which I think was about the reasons for the operating cash flow. I mean I think we did give a wide range, so we showed from -- on the low side when we're down at $163 million. That was assuming a Brent price of $50 per barrel and a WCS differential of $20 per barrel. And at the high side, we were assuming Brent prices of $70 a barrel with a differential of $15 per barrel. Now what our actual realized prices year-to-date, Brent has averaged for the first 9 months $65 and the Canadian differentials is actually better than our high-end guidance of $15. In fact, it's been $12 per barrel. So it's a combination largely driven by those 2 factors. And I think we're running slightly ahead on our $2.50 per Mcf gas price assumption. So I would say a big part of it is stronger realized prices trending towards the top end of that price range that we gave.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [4]

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Okay. That's all clear enough. And just on the TSX approval, is there any reason why it isn't just a straightforward approval from them? Is there any particular concern you have on getting that?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [5]

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No. We don't have any concerns. It's a fairly mechanical approval process. So no, we don't anticipate any surprises.

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Christophe Nerguararian, International Petroleum Corporation - CFO [6]

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It's a fairly

(technical difficulty)

process in Canada.

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Operator [7]

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Our next question comes from the line of Karl Fredrik Schjøtt-Pedersen from ABG Sundal Collier.

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Karl Fredrik Schjøtt-Pedersen, ABG Sundal Collier Holding ASA, Research Division - Research Analyst [8]

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Just wanted to hear it if it's possible to get some more color on 2020 in terms of production and also how you plan to move about in terms of harvesting from this year's CapEx program or continue with high growth also for 2020?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [9]

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Yes. Thanks, Karl Fredrik, yes. A little bit early to give guidance in terms of production or CapEx, but it was a very big CapEx expenditure year this year. And I would say, in particular, in Malaysia, we had 2 pilot wells. We had the Keruing exploration well and we had 3 infill wells and I would say, directionally, I would expect less activity as we move into 2020 in Malaysia.

Of course, in Canada, we'll be looking at potentially additional pads that we could look to develop and bring online to get up to that facility capacity. So -- and I would still -- we mentioned in our report today that we've matured enough drilling locations to continue with a drilling rig on our Suffield property in Canada. So I guess, directionally, we can expect to be flattish in Canada.

So net-net, I would say expect capital expenditure levels to be lower than we've seen this year. But I don't want to put a firm number on it right now. We'll do that in our Capital Markets Day.

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Karl Fredrik Schjøtt-Pedersen, ABG Sundal Collier Holding ASA, Research Division - Research Analyst [10]

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Okay. And could you comment on -- you're now guiding Malaysia to a gross production above 10,000 bopd. Could you indicate how those production profiles look like? Is it -- how quickly will they decline and to what levels?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [11]

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Yes. I mean we'll factor in the decline levels into our guidance next year. But you can get an idea from the chart, Karl Fredrik, on page, let me just go back, yes, if you look -- with no further drilling on the slide on Page 7, you can see the decline rate. So these wells do start to decline and you start to see a build in water. I guess the one area that's going to be interesting to look and you've seen in our previous presentation materials that the A15 area has continued to deliver reserve increases year-on-year and that's been driven by lower-than-expected water cut builds. And we did announce in our second quarter results that we'd seen better-than-expected predrill results from the B5 pilot well that went into that area. So I think that will be one of the biggest areas to watch for is to how quickly we see the water cut building in that A15 well and that's planned to be the [high street] well as part of the 3-well program, and we're expecting to complete that towards the end of this year. So we'll have more to talk about in Capital Markets Day in February.

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Operator [12]

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Our next question comes from the line of Joseph Lye from BMO Capital Markets.

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Joseph Lye, BMO Capital Markets Equity Research - Associate [13]

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Just one question from me. Have you seen anything from the third pilot well pair at Blackrod that has given you some indications for potential capital efficiencies that could lower the breakeven there? And has it changed the way you're approaching the phasing of the development?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [14]

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Yes. Thank you. That's a good question and that's one of the reasons why we wanted to stretch out and to drill a longer horizontal section. If you recall, the original first 2 pilot well pairs were around 950 meters. So the idea of one extending that horizontal section to 1.4 kilometers and also installing the well completion with inflow control devices that can optimize steam and heat dissipation across the entire length from the heel to the toe of the steam injector, the whole purpose of that is effectively to have a smaller number of well pads that you have to construct to drain the same amount of oil and also to optimize the cost to generate your steam. So absolutely, one of the reasons as to why we've drilled a longer horizontal section is to try and improve the capital efficiency of that project.

I think we said on the slide that we're actually expecting to start the steaming up early in 2020, so we'll see the production uplift hopefully climb through 2020. So it's too early, unfortunately, today to give you any firm results, but we're doing a lot of work, a lot of effort has been put in to building the geological model, the dynamic reservoir simulation model and to be able to tie those into the results that we're seeing from the third pilot well pair, which hopefully can give us the confidence that we can see these lower capital costs, higher productivity, and that feeds into a lower overall break-even price for that project. So that's exactly what we're working on right now.

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Operator [15]

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(Operator Instructions) And our next question comes from the line of Mark Wilson from Jefferies.

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Mark Wilson, Jefferies LLC, Research Division - Oil and Gas Equity Analyst [16]

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Very good operations again. Incredible to see the growth from such a lean operation. I've got 2 questions, please. The first is on the net asset value, suggests around $8 a 2P barrel, I think that $12 NAV you give. You seem to be trading below $3. You paid around $4 for Suffield and BlackPearl. What do you think both analysts and the market is missing in terms of the delta to your net asset value? That's the first question.

The second is it's clear to everyone in terms of operational delivery, and frankly, the format of your presentation, the parallels to your old parent, Lundin, are extremely clear. However, there's one thing that's appeared to be missing from what you show versus them. In terms of ESG, you show the safety, no material incidents, but little on emissions of the produced barrels, let's say, in CO2. Is that data you publish or do you plan to?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [17]

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Yes. No. Thanks Mark, and it's a very valid question and certainly something that is also very important to us. And we haven't got a slide in the presentation today, but if we do look at the ESG side and the CO2 emissions of IPC, of course, we benchmark ourselves relative to the areas that we operate in. And 80% of our production comes from Canada, 90% of our reserves are in Canada. And if we look at the average CO2 intensity in Canada, it's about 59 kilograms per barrel of oil equivalent. Now IPC's average emissions are around 32 kilograms per barrel, so we're about 40% below the Canadian average when the majority of our production comes from Canada.

And I think there's been a lot of good work that's been done by the teams in the engineering of all of our projects to minimize our CO2 emissions. So for example, in our Bertam project in Malaysia, when we were looking at the power generation systems to run the ESPs on the platform, we were recapturing the flash gas that comes off the oil production to be able to run a dual-fuel Wärtsilä generators, which crowds out having to use diesel for power generation. And there's been a huge amount of work done on engineering on the Onion Lake Thermal facilities in terms of heat recovery in minimizing the energy requirements and footprint for that facility. And I think in total, we've saved about 125,000 to 150,000 [tons] per annum in CO2 from those projects.

So we do, if you look in our corporate presentation, we set that out. It's in the corporate presentation, but I just didn't particularly highlight that in the third quarter results today.

Coming back to your first question, which I think was on the discount to core NAV. Perhaps one of the biggest issues is, I think, The Street and the sell-side tends to be slightly lower in terms of their long-term oil price forecast, I guess around $65 per barrel long term. And we have to use, as part of our NAV calculation, the view of our independent third-party reserve certifier. But they're fairly in line with the market. I think this year's price, McDaniel who's our reserve certifier, they used $64.50 Brent to for this year climbing steadily to $70 per barrel by 2020 on the Brent side. So that's the oil price deck that they use. So that's perhaps one area where there's a disconnect. But I think we recognize we're -- although we came from the Lundin Petroleum background, we are still a new company. I guess we have to prove ourselves. There's been a long track record of being able to continually converting contingent resources into reserves. And I think the longer we can continue to show that, hopefully, that should start to feed into compressing that discount that we're seeing. And also I think the steps that we're taking, we've been talking since we spun off in early 2017 about that discount and the fact that the company finds itself in a really strong financial position with the M&A deals we've done, with the good operational delivery, we can now actually put our money where our mouth is and repurchase our own shares. So I think that's also a very clear signal to the market that we're prepared to back that position.

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Operator [18]

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And as we have no more questions registered, I now hand back to our speakers for any closing comments.

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [19]

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Okay, now I'd just like to -- you have some questions. Okay.

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Rebecca Gordon, International Petroleum Corporation - VP of Corporate Planning & IR [20]

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It's filled up a bit while you were talking. So the first one is from [Jesper Holmberg], just a quick question on Blackrod. How long do you need to run the third pilot at Blackrod to get a good enough data?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [21]

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I think, I mean, by the time we'll be steaming up and putting that well on production through 2020, we're going to get good initial data through the summer when we start to see that well ramping up and reaching its plateau production, and of course, that's going to be one of the very important pieces of information, to see can we get that productivity uplift from a longer horizontal section. So that will come in 2020. Then, of course, the overall productivity of the well, that's going to take a couple of years for us to be able to fully evaluate that. But one of the reasons that we're doing the geological model and the dynamic reservoir simulation, we will actually be simulating the performance, so the intention is that when we start to see the initial results from the third pilot well, we can start to calibrate that to see if we can extrapolate that on a field-wide basis rather than waiting 2 to 3 years for the full results from that well. So I think the early information that we'll get through 2020 is going to be extremely valuable.

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Rebecca Gordon, International Petroleum Corporation - VP of Corporate Planning & IR [22]

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Okay. Thanks, Mike. Just got room for a couple of more questions. So from [Jan Thomas], could you please bring more light on nature of acquisition opportunities you're considering with respect to commodity, geography, corporate/asset type of acquisition, Mike?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [23]

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Yes. Well, people always try to put us in a box and we try to retain as wide a mandate as we possibly can. I mean we're -- we've done an asset acquisition with Suffield. We did a corporate acquisition with BlackPearl. I think we're oil people, sp I would say, we're much more focused on an oil-weighted acquisition. We've materially increased the reserve and the resource base right now. And I think our experience this year has been we see more value perhaps as you move further up the maturity side of the value chain. So it's been tough when you look at production deals, which are trading at a dollar for a dollar for 2P net asset value. When we're trading at such a discount, it makes it difficult for us to be able to justify to our shareholders paying dollar for a dollar for production deals. So I would say the more recent focus has been on less mature resources because we think we can create more value from that kind of opportunity. But of course, things change and we continue to be opportunistic.

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Rebecca Gordon, International Petroleum Corporation - VP of Corporate Planning & IR [24]

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Okay. Thanks, Mike. Christophe, are there any benefits on staying on the TMX given the lower trading volumes there?

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Christophe Nerguararian, International Petroleum Corporation - CFO [25]

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Well, the -- that's our main stock, so we are on the TMX. Now it's true that, for historical reasons, most of the liquidity happens in Sweden and you can see that the 2 -- the Canadian value of our stocks is in line with the SEK value of our shares in Stockholm. As Mike mentioned, in terms of buyback program, given that we are capped to buying back no more than 25% of our average daily liquidity, most of the buyback will indeed happen on Stockholm. But we intend as well to be active as much as we can in Toronto and the TSX.

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [26]

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I think just one final point on the TSX. For corporate acquisitions, the rules are more favorable in the TSX to more quickly complete corporate acquisitions.

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Rebecca Gordon, International Petroleum Corporation - VP of Corporate Planning & IR [27]

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Thanks, Mike. Mike, have you got any estimate of the possible impact of the Keystone pipeline leak?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [28]

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No. I mean we've seen some short-term widening of the Canadian differential, the WTI to the WCS. TC Energy, they haven't released any firm dates of when they expect the pipeline to come back into service. But I think we're in a much better situation than we were back in 2017 when we had the last leak. Back then, storage levels were at much higher -- were in a much higher position. And with the production curtailments that were announced in December of last year by the Alberta administration, we've actually seen stock levels in Alberta normalize back to their 5-year average of around 25 million barrels. So when you look at tank tops at 37 million barrels, you've still got a significant buffer of over 20 days before you hit tank tops, which is one thing that give us a bit more slack in the system.

I think the second thing that's very different since late '17, early 2018 is the ramp-up in crude-by-rail capacity that you've seen back in early 2018, you had around 125,000 barrels a day of crude-by-rail capacity. And when we saw January in this year when differentials were wide, we were exporting about 350,000 barrels a day of crude-by-rail out of Canada. And with the government-mandated crude-by-rail export contracts ramping up this year of 120,000, combined with commitments that other operators have made for long-term contracts, we should have rail capacity available of an excess of 0.5 million barrels a day. So although it's clearly negative from an egress position, we do expect that pipeline to come back in service and I think there's relatively more slack in the system.

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Christophe Nerguararian, International Petroleum Corporation - CFO [29]

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Yes. The market was expecting the situation to normalize in a week or so, in a week to 10 days. So the diff is currently minus 20. It's fair to assume it will go back to the mid-teens or something in a week or 2.

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Rebecca Gordon, International Petroleum Corporation - VP of Corporate Planning & IR [30]

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Okay. Thanks. Final couple of questions. Does IPC have any plans for Onion Lake Phase 3?

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [31]

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So Onion Lake Phase 3, I think the short-term plan next year, given that we've installed the fourth boiler in the Phase 1 facilities to increase capacity up to 14,000 barrels a day, will be to look at new well pads that can grow production towards that facility capacity. And then, of course, we'll look at further optimization and whether it makes sense to add another 3,000 or 6,000 barrels a day facility. So early days yet, but I think the focus for next year is more likely to be on the existing -- optimize facility capacity and reaching that.

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Rebecca Gordon, International Petroleum Corporation - VP of Corporate Planning & IR [32]

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Okay. Thanks, Mike. And final question regarding buybacks, Christophe, is there any maximum price where you don't want to buy shares?

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Christophe Nerguararian, International Petroleum Corporation - CFO [33]

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It's a lovely question and we would love to ask the questions to ourselves when the stock price will be SEK 40 and SEK 45 and SEK 50. I think we -- our stock price was above SEK 60 at some point. Clearly, there's a massive undervalue for us. As a management and as a Board, I think it's important we walk the talk. We've been expressing our concern in terms of the distinction between the value and the price of our shares. Now it's about walking the talk and we're planning to aggressively buy back our shares. There is no fixed ceiling at this point, but we clearly want to walk the talk.

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Rebecca Gordon, International Petroleum Corporation - VP of Corporate Planning & IR [34]

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Okay. That's the end of Internet questions.

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [35]

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Okay. So...

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Christophe Nerguararian, International Petroleum Corporation - CFO [36]

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Thank you very much.

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [37]

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I'd just like to thank everyone for tuning into the presentation this morning and we look forward to talking again for our year-end results presentation and our Capital Markets Day, which we'll set out our investment plans for next year. So thanks, once again, for your attention.

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Christophe Nerguararian, International Petroleum Corporation - CFO [38]

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Thank you.

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Mike Nicholson, International Petroleum Corporation - President, CEO & Director [39]

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Thank you.