Okay. Very good morning to everybody, and welcome to IPC's second quarter results and operations update presentation. My name is Mike Nicholson. I'm the CEO. Also joining me this morning is Christophe Nerguararian, the CFO, and Rebecca Gordon, who's the VP of Investor Relations and Corporate Planning. I'll begin in the usual fashion by walking through the operations update for the 2nd quarter, and then I'll pass the presentation across to Christophe. He'll take you through the financial numbers for the second quarter. Then at the end of the presentations, you'll have the opportunity to ask questions. You can dial in on the conference call, you can also send in your questions via email. To get started with the highlights for the second quarter, it's been a very, very strong quarter for the company. You're going to see good operational delivery from all of our asset teams across the business. We've obviously had improving commodity prices, stronger benchmark oil prices. We've had strong gas prices in Canada, and we've also had tight differentials. The combination of those two, you're going to see have fed into very, very strong financial performance. We're upgrading our production and our financial guidance across all of the key metrics. To get started on production, second quarter production averaged 44,600 bbl of oil per day, and that was to the second quarter in succession. That was above our high-end guidance. As a result of that very strong performance in the first half, we're now revising our full-year production guidance to in excess of 44,000 bbl of oil equivalent per day. In our first quarter presentation, we'd been expecting the full-year production to be heading towards 43,000 bbl of oil equivalent per day. We'll get into it in the presentation, but with the extra 25% interest on our Bertam field and the D- Prime ramping up, we now expect to be exiting 2021 with production in excess of 45,000 bbl of oil equivalent per day. Previously our guidance was 43,000 bbl per day. OpEx for the second quarter was exactly in line with guidance at $15.60 per BOE. We are slightly revising up our full-year guidance to now $15.50 per bbl, and that's largely a result of higher gas prices, which is good because it affects our revenue line, and we have been increasing some of our higher marginal cost production in Canada. Both positives that are feeding into that increased guidance, and Christophe will refer to that in his presentation. The 2021 capital program is also being increased by $36 million to now $73 million. You'll recall in our February Capital Markets Day presentation that we'd set a very conservative capital budget for 2021. It was going to be more than fully funded at less than $40 per barrel Brent. With the stronger oil prices that we've seen, we're going to move forward with some very high return, quick payback projects, and I'll touch upon both of those later in the presentation. Essentially, it's the infill drilling campaigns at Onion Lake Thermal in Canada and our Bertam project in Malaysia, and we also have some additional optimization projects in both Canada and Malaysia. Cash flow was very strong during the second quarter. Our operating cash flow was $67 million. That was higher than our high-end guidance. As a result of the very solid delivery in the first half, we're increasing our full-year OCF forecast to $235 million-$290 million. Free cash flow in the second quarter was $50 million. Again, we are increasing our full-year free cash flow guidance on the low side from $55 Brent at $135 million, to on the high side at $75 Brent up to $195 million. Based upon the closing IPC share price on Friday last week, that translates into a free cash flow yield of somewhere between 18%-26%. The balance sheet continues to strengthen. Leverage was down. Our net debt position was down to just over $240 million at the end of the second quarter. The leverage ratio continues to drop down to below 1.2 times at the end of June, compared to 3 times at the end of 2020. Christophe will go through the details in his presentation, and that satisfies all of our hedging requirements for 2021. Also we've been very active on the ESG side. Very pleased to report no material safety incidents during the second quarter. We've successfully secured the carbon offsets for 2021 on our five-year journey to reduce our net emissions intensity by 50%. We've also published our second sustainability report alongside our second quarter results this morning. To get into a little bit more detail, if we start with the production for the second quarter, as I stated in the highlights, 44,600 bbl of oil equivalent per day. If you look at the chart, you can see that that production during the second quarter was above our hiring guidance for the second quarter in succession. In Canada, we've had very high uptime performance and reservoir performance across all of our assets. We've been ramping up our production on some of our conventional assets at Mooney and the Onion Lake Primary. The planned maintenance shutdown that took place during the month of May was completed ahead of schedule and ahead of budget. Again, if you look at those strong production numbers, of course, it would have been even higher had we not had that turnaround during the second quarter. From the international assets, very good performance in Malaysia and France. We took the decision to defer the Bertam shutdown from the second quarter to now later in the third quarter. We would still have performed above top-end guidance had that shutdown gone ahead during the second quarter. I think if you look to the production that we've seen in July, which sits outside the Q2, we've had an early contribution from D-Prime. You can see from the chart on the right-hand side of the page here, that things are going very well indeed, and we're seeing some encouraging initial results there. What does that mean in terms of the full-year guidance? We're increasing our full-year guidance now to in excess of 44,000 bbl of oil equivalent per day. More than 1,000 bbl oil equivalent per day upgrade from the first quarter guidance. We now expect to be exiting above 45,000 bbl a day given the extra interest in Malaysia and the production ramp up at our Onion Lake Thermal D-Prime pads. In terms of operating cash flow, just to recap, when we gave our CMD guidance back in February, we were looking at a price range between $45 per bbl Brent on the low side and $65 per bbl Brent on the high side. That gave a full-year OCF guidance range on the high end of our production forecast of between $107 million and $220 million. If we look at the second quarter cash flow generation of $67 million, that takes the first half cash flow generation to $135 million or 60% of our high case guidance. Clearly running ahead of expectation on the back of that strong production performance and tighter Canadian crude differentials. That's really allowing us to now look forward and upgrade our full-year free cash flow guidance significantly. If we take out $55 per bbl for the second half on the low side, we expect to generate $100 million in the second half. On the higher side, we're introducing a $75 per bbl upside case, which would add a further increment of $55 million, which takes our revised full-year OCF guidance to now between $235 million-$290 million. To put that in context, our low side $55 case cash flow generation is now ahead of our high side $65 case guidance that we gave at the beginning of the year. Very good cash flow generation in the first half feeding into that. As a result of the strong commodity price environment, we did discuss in our Capital Markets Day and our Q1 results that we'd allowed for some long lead items on some high return, quick payback projects. We've decided now to move forward with those and execute those during the fourth quarter. We're increasing the capital expenditure budget by $36 million. We're going to move forward and complete the drilling of the A14, A15 sidetrack on our Bertam field in Malaysia during the fourth quarter. Whilst we have the rig on location, we're also going to take the opportunity to upgrade some of our ESP pumps. Three pumps are going to be upsized. In Canada, we're going to go forward with our five-well infill program at Onion Lake Thermal and also some additional oil optimization projects at Suffield Oil. We're not really going to see much impact on our 2021 production numbers, but what that will do is it should add in excess of 2,500 bbl a day of production growth as we move into 2022. Taking into account the increased capital expenditure budget for this year, we're still able to upgrade significantly our full-year free cash flow forecast. If we go back and look at the same oil price range for our OCF, $45-$65 at the beginning of the year, we were looking at generating $39 million- $155 million of free cash flow for the full year, with close to $100 million in the first half alone or 2/3 of our full-year high side guidance. Looking forward at between $55 million and $75 million, we expect to generate an extra $36 million- $96 million during the second half. That's allowing us to increase that full-year free cash flow guidance to now between $135 million and $195 million. That translates into a free cash flow yield of between 18% and 26%. Some exceptionally strong cash flow generation numbers and multiples. When we turn now and look at our full year guidance, there's no changes to the $55-$65 per bbl case we guided back in February, in excess of $600 million-$900 million, assuming our average production of 45,000 bbl a day over the five-year periods. With Brent prices strengthening, we've added a $75 per bbl sensitivity, which uplifts that free cash flow guidance over the five-year period to $1.2 billion. If we look at the enterprise value of IPC last Friday, less than $1 billion. That means we could fully liquidate the enterprise value of IPC current prices in less than five years. Of course, that gives us tremendous flexibility for stakeholder returns, debt reduction, share buybacks, and dividends over the next five years, as well as funding our M&A activity and organic growth in the significant billion barrels of contingent resources that IPC holds on its books. Very strong cash flow generation. If we also look at IPC from a value perspective, this is our year-end reserves valuation just on our 2P reserves, so just our 270 million bbl of 2P reserves, no value to any of our contingent resources. It was a pretty conservative price tag that was used at the end of last year. We were looking at $40 per bbl Brent for this year, rising steadily to $57 per bbl in 2025. That translates into a net asset value of $1.3 billion, effective date 1st of January of this year, or $0.70 a share. Today, IPC shares are trading just over $0.40 a share. More than a 40% discount into a pretty conservative oil price value on just our 2P reserves. I think IPC also looks extremely attractive through the value lens. If we turn now and just take a quick walk through each of the individual assets, starting in Canada with Suffield Oil. We can see, if you look at the chart on the bottom right-hand side of the screen, we've still got a very solid production performance, averaging above 8,000 bbl per day. The outperformance continues to be driven by the end-to-end alkaline surfactant polymer flood that we've got running. You can see from the blue chart on the top right-hand side of the slide that that project continues to run ahead of expectations, and we're producing more oil today than we were back in 2016 when this was in the hands of Cenovus Energy. We don't have any major capital projects planned for this year, we have added some additional optimization projects. We're going to convert one of the producers on our end-to-end project to a water injector and some optimization on our South Gibson field in Suffield. On the gas side, we've seen very strong Canadian gas prices through the second quarter, that's been driven by a combination of much higher than normal temperatures, which has held back injections into storage, and storage levels have dropped below five-year averages. Really good gas prices through the summer season, which is normally much weaker. Of course, that's feeding through into much stronger cash flow generation from our gas assets. No new drilling at all on the gas properties, but still very active on the optimization front. We're shooting to swab at least as many of the wells as we did in 2020, and we're well on track to achieve that for the full year. You can see current production on a spot basis is still averaging around close to 100 million standard cubic feet a day. A really good job from the team on the ground in holding that production flat and offsetting any of those natural declines. Onion Lake Thermal, as I mentioned in the highlights, the shutdown during May was successfully completed on schedule, on budget. That allowed, as part of that shutdown, one of the work scopes was to tie in the Onion Lake D prime well pad. The first three wells were started up during July, and we've seen some encouraging early performance. The remaining three wells are planned to come on stream during the third quarter. We should see production steadily grow to in excess of 1,500 bbl a day by the end of 2021, which should help feed into that exit rate guidance in excess of 45,000 bbl of oil equivalent per day. In addition to that, we are now moving forward with the five well infill project. You'll recall we had budgeted the long lead items for that project, but we wanted to see if oil prices would stay firm through the first half before moving forward with that project. That's obviously happened. We are now going to move forward with that project. If you look at the numbers on this slide, you can see why we're doing so. The break-even on this investment in WCS terms is around $20 per bbl. WCS today is trading at somewhere between $55-$60 per bbl. Rates of return with Brent at $55 are in excess of 100%, and the payback is around one year at $55 per bbl Brent. Clearly, with oil prices where they are today, it's a very high return, quick payback project. We'll be moving forward with this in the fourth quarter, and that should help with some production growth as we move into 2022. Ferguson, minimal activity. No capital allocated to the Ferguson property. You'll recall that IPC acquired the Granite company which owned this asset in late 2019. There is the potential to more than double production with multiple drilling locations already identified, and you can see those highlighted in yellow in the bottom right-hand side of this slide. Our team has been very active and busy working on development plans, and that's likely to feature in our 2022 capital budget as we look to get started with the development of that field, having taken a pause during 2020 as a result of the weakness that we saw as part of the COVID pandemic. On the conventional side, we've also been ramping up some of our production at John Lake and Onion Lake Primary with improved WCS pricing. Mooney, the EOR project, was also restarted during the second quarter with stronger WCS pricing. Those have fed through into some of the increased production that we're now re-guiding with both conventional and Mooney projects expecting to add about 1,800 barrels a day of production during the second half of 2021. Blackrod continues to perform very well. You'll recall we did drill a third pilot well pair last year. It's 1.4 km in length, and we continue to see really good heat conformance from the heel to the toe of that well. That's very important. Production, you can see on a spot basis, is actually heading up towards 900 bbl per day, which is certainly ahead of where we expected at this point in time, notwithstanding the fact that we were taking a small ago. If we take well pair three at these levels, of course, that's can produce high construct less well pads. That can be costs. We're continuing to see good and positive results from the third well pair at Blackrod. Turning now to the international assets, and if we start with Malaysia, it's been another phenomenal quarter with production uptime of 100% through the quarter. We did complete the from April. Part of the reason that our capital expenditure budget is to move forward with the execution like thermal, you're seeing assessment. Great. Brent prices today are closer to $75. At $55 Brent, the rate of return is in excess of 150%, and the payback is in one year. We expect to receive a payback on this at $75, certainly well below one year. That well drilling is expected to take place during the fourth quarter of this year and won't really impact our numbers until we move into 2022. What we're also going to do when the rig is on location is take the opportunity of that to increase the pump size of the main part of the Bertam field. During the shutdown in the third quarter, we're planning to upgrade the liquids handling capacity of our FPSO. It's going to be increased from 17,000 bbl a day to 24,000 bbl per day. That will allow us to produce not only the A15 well, but those additional producers at higher liquid rates. We expect incremental production adds from the A15 sidetrack in excess of 1,500 bbl a day and around 800 bbl per day from the pump upsizing campaign. Again, if you look at the numbers, breakevens around $20 per bbl Brent, paybacks of one year. Very similar metrics to the infill drilling. We'll be moving ahead with that once we've completed the A15 sidetrack in Q4. Turning to France now. If you look at the production chart, very steady production through the second quarter. A good performance from all the major producing fields. Our VGR project, which was responsible for the production uplift in the second half of 2019, continues to exceed pre-investment expectations. If you look at the production plot on the top right-hand side of this slide, you can see that we're producing effectively about 50% more on plateau than was in our simulation model. We've still not seen any water breakthrough from this well when it was simulated to come in Q3 of last year. We're seeing a very good response from the conversion of VGR 5 to a water injector, which is providing pressure support to the 113 well. Things still going very well in France, in particular with our VGR 5 project. And turning now to our sustainability and ESG. Alongside this morning's second quarter results, we are publishing our second sustainability report, and we've stepped up the compliance with our GRI reporting standards, which is a global reporting standard. As part of that process, we conducted a company-wide materiality assessment at the beginning of this year. That really does lift the non-financial disclosure of IPC to a different level. It really is an excellent report. I would encourage everyone to read it. There is a huge amount of fantastic work that's been done across all of our business units, and it's a great credit to all of those teams on the ground, and I would like to personally thank everyone for the great work that's been done. Just in terms of the highlights on our emissions intensity reduction, the target to reduce by 50% through 2025, that's to be achieved through reducing our operations emissions and through carbon offsetting. You can see we're making very good progress in achieving that aim. The 2020 net emissions, or sorry, our gross emissions, were down from 40 kg to 39 kg per BOE. We successfully doubled our offsets, so from 50,000 tons to 100,000 tons in 2020, which reduced our net emissions intensity down to 33 kg per BOE. We're well on track to meeting that net target by 2025 of 20 kg per BOE. That concludes the operations updates. I'd like to pass the presentation across now to Christophe to run through some very nice financial numbers, and then we'll take questions at the end of both presentations. Christophe, over to you. Thank you, Mike. Good morning, everyone. Indeed, it's a good quarter with a very solid financial performance. It's the second quarter in a row, which I'm happy to be here again. 2020 was obviously a bit more challenging, but we're back on track evidencing IPC ability to generate very strong cash flows in a higher oil price environment. I think the first important comment to make is the very strong operational performance across all of our assets, all of our geographies. We've seen a very high uptime, a very good, efficient operations from all the team around the world. It's a tribute to them to see production averaging in excess of 44,000 for the second quarter and averaging as well in excess of 44,000 BOE per day for the first six months. Obviously, carried by a very strong oil and gas price environment. The financial results are extremely strong as well for a second quarter in a row. It's worth mentioning, I'll come back to that, but despite the fact that on average for the first six months, the Brent was at $65 per bbl, which is in line with our high case during our Capital Markets Day guidance. The actual financial performance is much stronger, thanks to better realized prices in Canada, both on the oil and on the gas side. Better operational performance ahead of our initial Capital Markets Day guidance, better financial performance as well, which has led us to re-guide both the production guidance in excess of where we were, in excess of 44,000 bbl of oil equivalent per day for the full year. As well, increase both our operating cash flow, but also our free cash flow generation for the full year, and I'll come back to that. The very strong operating cash flow and EBITDA at $67 million and $65 million for this quarter, respectively, translated into a very strong deleveraging as well. The free cash flow for the quarter is around $50 million, $99 million of free cash flow for the first six months, which obviously has translated into a very fast deleveraging. As a matter of fact, you may recall our net debt to EBITDA, so our leverage at year-end last year was just around three times, we're down to 1.2 times on a 12-month trading basis. A very fast deleveraging. As I was mentioning, in terms of realized prices, even though the Brent average for the first six months was exactly at 65, in line with our high case, Capital Markets Day case, the realized prices were much stronger. This is coming from the fact that in Canada, the WTI to WCS differential has tightened quite a bit and was around $12, much tighter than what we had in our budget at $ 17. 17. That translated into a WCS average for the first six months of $50. Because we are selling both our Suffield oil and Onion Lake oil production at a $1-$3 discount to WCS. We had realized prices for Suffield and Onion Lake, respectively, at $49 and $47 per bbl, which was much stronger, again, as I said, compared to our guidance. If you look even back at 2019, you can see that our realized prices in Canada are much stronger than they were ever. Very good performance there. In Malaysia, on average, we sold two cargos at Brent plus a premium of $3 per barrel, and France usually is exactly in line with Brent. For some timing differences, average $1.5 above Brent, but is usually in line with Brent. On the gas side, a very positive development there as well. First, if you look at the second quarter, we realized gas price sales in excess of C$3 per Mcf, which in itself is already the best performance ever since we acquired the Suffield gas asset. Almost more importantly, as the summer was fairly hot, there's been a lot of gas utilization, generally in North America. What that means is that there's less gas being injected in storage, which is usually what's happening during the summer phase, where we're actually building up storage volumes for the winter to heat people, especially in North America and Western Canada in the wintertime. What's happening with that is because the summer has been quite warm, there's a lot of gas utilization, which means also we anticipate there will be less gas available from storage in the winter, this winter. What that means as well is that when you look at the forward curves, it currently sits in excess of C$4 per Mcf for next winter. Not only a very strong performance for Q2 now, but we're also very well positioned to continue to benefit from very strong gas realized prices. This slide on operating cash flow and EBITDA is very much telling and illustrates IPC ability to generate very, very strong cash flows in a higher oil price environment. I mean, that's more or less the same for all oil and gas companies, but one of IPC's specificity is that we are not paying, or very little, cash taxes, which means that together with a very solid control of our cost, we're able to generate those strong cash flows in a higher oil price environment. That also shows that we have a very strong torque towards higher oil prices. I'll come on again, but so we generated EBITDA and operating cash flow for six months in excess of $130 million, actually between $130 million and $135 million during those first six months. The costs, the OpEx per barrel, that remains totally under control. What happens is that we're re-guiding the full-year OpEx barrels of oil equivalent from 14.5 to 15.5. It is mostly a conscious decision. What happened is that we're bringing back on stream some higher cost production, which is highly valuable, with very strong netbacks as we speak. Tiny bit of increased OpEx there, but it's an objective and conscious decision. The other one is that we've increased activity, again, to maintain and increase production overall. Again, a conscious decision, which justifies slightly higher OpEx there. The only thing which is out of our control are increased electricity costs in Canada. Obviously the flip side is that we're benefiting from some very strong and high gas prices, as I just mentioned. Overall, a good story. Costs remain under control. Some of that increase is a conscious decision, still leading us to increase slightly our guidance for the full year at $15.5 per bbl. Looking at the net back, it's a very interesting slide, especially if you compare that to our Capital Markets Day guidance. We generated, for the first six months, between $16.4 and $16.8 per BOE of EBITDA and operating cash flow. That is actually $3 higher than our high case from our Capital Markets Day. So, we've been able, with the conscious decision to have slightly higher OpEx, to increase our profitability by more than, or just about $3 per BOE of operating cash flow and EBITDA, which is a very strong success. I was mentioning previously, when you consider cash flows and our deleveraging effort, as you know, we are not sitting on cash, and so all of the cash which is being generated goes so far to repay debt and deleverage our company. What happened is that, so we generated $ 99, call it $100 million of free cash flow during the first six months this year. That was all used to finance the debt reduction. Actually, $80 million were used to repay debt. We went from $320 million down to $240 million of net debt from the end of last year to the end of June. We're obviously continuing in July and August to deleverage. The full $100 million didn't go into debt reduction because we had a negative change in working capital, which is actually a positive, just means that we have higher receivables as a result of higher production and higher oil and gas realized prices. Overall, a very good story. If you think again about what Mike was just mentioning at the beginning of this presentation, we are re-guiding the full year free cash flow to between $135 million-$195 million. If you want to be optimistic, roughly at current prices, we can expect to generate another $90 million-$95 million of free cash flow. Everything being equal, if all this additional free cash flow was dedicated to debt repayments, which is our primary target as we speak, the net debt at year-end could fall to $150 million. So, a very strong balance sheets. We should be in a very strong situation, again, from a balance sheet perspective, with a very low gearing. The non-linear OpEx remain under control. As I mentioned, the G&A are fairly flat year-on-year at roughly $12 million per annum, roughly between $3 million by quarter or $6 million for the first six months. In terms of interest expenses, it is interesting to note that there is a double positive effect looking forward. As we are going to deleverage, we have less debt outstanding, so we are going to pay less interest mechanically. Also the second positive effect is that because some of our cost of debt is linked to our leverage, with an improved leverage, our cost of funding is going to reduce as well. You can expect a reduced cost of debt in the third and fourth quarter this year. On the financial results, we generated for the first six months just short of $280 million, which translates into roughly a 50% cash margin. Revenue less production cost is roughly 50% of our revenue. At a very high level, which translated into gross and net profits of respectively $72 million and $49 million for the quarter. Looking at the balance sheet, not much to comment upon, with the exception of current assets and current liabilities. Current liabilities increased as a result of increased activity, both on the OpEx and CapEx fronts. Current assets increased far more faster, as a result, obviously, of higher production compared to last year, also higher oil and realized gas prices. We're expecting to receive more money, effectively the end of the accrued revenues at the end of June, which we cashed in July, have swollen the debts, which is a positive. Everything being equal, if we were to stay at the same oil prices, we would see the change in working cap narrowing down. The $50 million negative working cap change would actually go to repay the debt by year-end. We're very well-placed to continue to aggressively deleverage. In terms of hedging, there was the conscious decision not to hedge any of Malaysian or French oil production. We benefited during this first half of the market prices, and we will continue to do so because there's no oil hedging, for our French or Malaysian oil production. In Canada, we had some bank covenants, which we met, that was about hedging 40%. It was 25% in the first half and 40% of all oil production in Canada had to be hedged, which we did. Our strategy was to put a floor at the high case of our Capital Markets Day. In our Capital Markets Day, we had $44 for WCS. We managed to hedge exactly that level for the first 5,000 bbl a day in Canada. Actually, we added another 3,300 bbl a day, but with a collar, meaning that between $44 and $63 per bbl for the WCS, we're actually benefiting from the market price, which is what's happening now, as Mike mentioned. The WCS is trading between $55 and $60 now, so we're benefiting fully from that price, and we will continue to do so in the second half. On the gas side, as I said, so we had some gas sold forward or hedged for the second quarter. Just place some a, we have no more oil hedging for 2022, but for the gas, we started to layer in a bit of gas hedges for the first quarter next year. We managed to lock in the phenomenal level of CAD 440 per Mcf for the gas. Very well-placed going into the second half of this year and then into 2022 with an overall increasing production and still very strong prices. In terms of hedging impact. We had hedging losses of around $15.15 million for the first half this year. Everything being equal at the current prices, we would expect more or less the same hedging losses. I think what I want to say here is that without any hedges, the free cash flow generation ability of IPC for the first half was not $ 100 million, but was actually $115 million. Everything being equal, if you annualize that, it means that at current oil prices, we could generate another $100 milliion- $115 million or $110 million without hedging and $10 million- $15 million less with the current hedges we have in place. Overall, a very strong performance in assets which are performing very well in higher oil price environment, including because we're paying virtually no taxes in Canada and Malaysia and just a little bit in France. I will hand back the floor to Mike for conclusion. Okay, thank you very much, Christophe. Great set of numbers. Just to go over the highlights again for the second quarter, I think it's been a very strong performance in terms of the operational delivery. As I've mentioned, second quarter in succession where we've performed above our high side production guidance, 44,600 bbl of oil equivalent per day for the second quarter. Which is causing us to increase our full year guidance now to in excess of 44,000 bbl a day. Our exit rate's above 45,000 bbl a day, which is a 2,000 bbl a day increase relative to our February guidance. As Christophe has touched on, we're slightly edging up our OpEx guidance to $15.50 per BOE for the full year. We're also bringing forward some investments that would likely have taken place next year into the fourth quarter of this year in both Canada and Malaysia, Onion Lake Thermal and Bertam, to add some high return, quick payback projects to give us a production boost as we come into 2022. Very strong operational cash flow guidance for the second [audio distortion] assuming Brent prices fall to $55 in the second half or up to $195 million, assuming $75 Brent for the second half. Those translate into very attractive free cash flow yields of between 18% and 26% based upon our market cap on Friday. Christophe touched upon the deleveraging. Net debt was down to $240 million. The leverage ratio falls to just below 1.2 times by the end of the second quarter, so materially down from three times at the end of last year. We've got some additional hedges in place through the second half that meet all of our hedging requirements. Christophe talked about the uplift, close to $15 million lower than the first half had we not had those hedges in place. Again, very good performance on the ESG side. No material incidents to report during the first half. Our carbon offsets have been secured to increase or reduce our net emissions intensity during the second quarter and through 2020. We've published our second sustainability report. As I said, it's an excellent report, and I would encourage everyone to read the good initiatives that are ongoing within IPC. That concludes the second quarter. I'll ask Christophe now to come up and join me, and we can open up and take some questions. Thank you. If you wish to ask a question, please dial zero-one on your telephone keypads now to enter the queue. Once your name has been announced, you can ask your question. If you find it's answered before it's your turn to speak, you can dial zero-two to cancel. We have a couple of questions coming through so far. The first is from Teodor Sveen-Nilsen of SB1 Markets. Please go ahead. Your line is open. Good morning, Mike and Christophe, thank you for the update. A couple of questions from me. I just wonder first some high-level thoughts on the cash flow story here. Of course, you're reducing in net debt substantially here. In the long term, how do you think around dividend versus growth? Second question, general industry question for Canada, actually. Do you see any cost inflation or are there any supplier bottlenecks at all? My third question, just on your small OpEx, or increased OpEx guidance there, what's the split between higher energy cost models or an introduction of high-cost production? Thank you. Okay. No, thank you, Teodor. I'll take the first two, and then Christophe can take the third question. In terms of the priorities between growth and dividends, or I guess we can talk about share buybacks as well. I think we haven't changed our long-term five-year business plan. I think when you look at the cash flow generation that we've said, so between Brent prices of $55 and now up to $75 per bbl. That base business plan where we just liquidate our 2P reserves and produce on average 45,000 bbl a day over the next five years, is going to allow us to generate somewhere between $600 million and $1.2 billion of free cash flow on the high side. We can continue to invest in our 2P reserve base and some of our growth projects. At these higher oil prices, all the debt can be repaid and every single share can be repurchased. We'll still have 2/3 of our reserve base at the end of the five-year period and 1 billion bbl of undeveloped resource. We're not precluded from doing both, is I guess the point I'd like to make. We've got huge financial flexibility to both pursue our growth opportunities and to return value to shareholders. The second question, I think, was on the general cost environment in Canada. Christophe will answer the more specific question on OpEx. Obviously we've seen higher gas prices feeding into higher electricity prices. That's obviously a positive for us because we produce 100 million standard cu ft a day of gas and we consume only 30. That's a net positive. When we look at moving forward with the infill drilling project, the five wells, we haven't changed our guidance on that CapEx of $7 million from February. We're not seeing any material in terms of the capital components of those investments that we're executing. Christophe, on the OpEx. Yes. On the OpEx, I think we mentioned, what happened is that through the conscious decision to bring more production back on stream, some of which we shut in last year in the context of much lower oil prices. For instance, some of the conventional, including Mooney, was restarted in April this year. The consequence was to increase the OpEx on a unit per barrel basis. That was a conscious decision. Another conscious decision was to work over some wells to maintain or increase slightly production. That was also a conscious decision because that was providing a very quick payback in the current oil price environment. What was imposed on us was some higher electricity costs. But again, the flip side of those increased electricity costs was the very high realized gas prices we saw during this first half, which is actually going to continue, as I just mentioned. When you look at the forward gas curve, it's actually increasing to well above $4 per Mcf during the winter period. We are not embarrassed, if you wish, by this slight OpEx per BOE increase. It's actually good news because we bring more production on stream with very strong net backs in the current environment. A bit counterintuitive, but it's positive. Okay, good. Thank you. Thank you. Our next question comes from the line of Lars Dollmann of Aramea. Please go ahead. Your line is open. Hi, everyone. Congratulations to very strong results and broad-based right guidance raised. I have a question. You can imagine what I would like to ask more in depth is, we see that on a 12-month annualized basis, net debt to EBITDA is now going sub one. On the last 12 months, it's just over one, as you stated in the press release. As you mentioned, Mike, obviously, you're going to produce a massive free cash flow amount over the next couple of years. When is actually the starting time to buy back the shares? Because you increased free cash flow guidance despite more CapEx with major IRRs. When should we hear more about when you're going to start a buyback or paying a dividend? Thank you very much, Lars, for the question. Very valid question. We haven't changed our messaging at all on this point since the beginning of this year. We obviously started the year with debt levels that were slightly on the high side, coming through a rough 2020. What we've said since the beginning of this year is the last time that we were in the market buying our shares back, when that started in October of 2019, our leverage levels, our actual leverage on a last 12 months basis was below 1x. Obviously, things have progressed extremely well through the first half, and we've seen net debt come down, as you rightly say, from 3x to 1.2x. Based upon the guidance that we've given on a forward-looking basis, provided oil prices hold up, we will be dropping below 1 x by the end of the third quarter. Those were the levels the last time that we started a share buyback process. I do understand that on an annualized basis, we're below 1 x, but I think we'd prefer to be just slightly more cautious and see the money in the bank and the debt levels down before we launch shareholder returns. It means effectively that if oil prices or energy prices stay roughly where they are and we get the same fantastic uptime, that this is a talking point then for Q3 results? I think what I'm saying is we'll certainly be below those leverage levels where we were doing share buybacks last time, Lars. Another question I have is on these projects, obviously Malaysia, you mentioned you're going to drill A15, the sidetrack, and what is the IRR on that one now in current oil price environment? Can you remind me on that? You're also going to do the ESPs, bigger ESPs. What is the impact going into 2022 on that production? Because obviously will not be really affecting this year. Yeah Then also, on Onion Lake, is what kind of more projects like in Onion Lake of more drilling, more pads? Actually, what can we expect there looking out, let's say 12 months? Okay. No, thanks, Lars. Yeah, just as a recap, the investment, $22 million of CapEx for the A15 sidetrack. The rates of return on that project, which we disclose a $55 per bbl Brent, are around 150%. Obviously with oil prices above $70, one can expect well in excess of 150% rate of return. Yes. If you look at it in terms of break-even, less than $20 a bbl. That well will be producing in excess of 1,500 bbl a day of production when that comes on stream. Which is, sorry, interrupting you, which is effectively now as you own 100% of Bertam in the FPSO and in the field, is fully obviously now with IPC, right? That's exactly right, Lars. Yeah, that's correct. Likewise, very similar metrics for the pump upsizing campaign. $20 per bbl breakeven Brent, greater than 125% rate of return at $55 Brent. Obviously current price is well in excess of that. Again, a payback of around one year at $55, so under one year, to return the cash, at current oil prices. That adds incremental production on average of about 800 bbl a day, for next year. That reflects the 100% interest as well. Sorry, one more question then is on the final one from me to leave time for everyone else, is on the site in Canada, is on the hedging side. Christophe mentioned that there was obviously some hedging being put upon you because of your debt. How is that really going to develop and what is the relaxation of that? Is the strategy actually on the oil side to be completely unhedged going forward? Christophe mentioned very, very high, strong lock-in of over $4 on the gas side. What is the strategy on the gas side hedging going forward? Yeah. So, in terms of bank covenants, so going into 2022, we no longer have any covenants. It's a semi-annual discussion with our banks. The discussion and the subject will come up again, but obviously with the strong deleveraging and repayment, I think, we will be in a position maybe to decide a bit more from our end. The logic, as I was trying to explain, for the oil hedges in Canada, was to secure at least the level we had in our high case, for which we disclosed at our Capital Markets Day. At the time was $44 per bbl for WCS. That was the logic to pick that level and we were able to have that level secured for the 40%, for the second half this year, which was imposed on us. Going forward, we always have that discussion. It's an ongoing discussion. It also depends on how much cash we have to use to repay the banks. It may in the future depend on how much cash we commit to return to shareholders, which we want to secure and hence, secure a minimum oil price level. It can depend on the level of CapEx, that we want to ensure to be able to finance. There's always a good reason to have that discussion, the strategic discussion, to ensure we generate enough free cash flows to come up with the funding of the different use of capital. In terms of gas. Yeah, exactly. On gas. Yeah. On gas, what's happening in any case, we're, quote-unquote, "producing too much gas to sell everything on the spot." At the very least, we have to hedge one month ahead, 70%- 80% of our production. Now when we see market windows opening like the one we're in now, where we can secure hedges or forward sales at a level which we've never experienced before, frankly, since we moved into Canada. The general strategies that we give ourselves the flexibility to hedge with the board support, to hedge up to 50% or to sell forward up to 50% of our gas, especially at those level. Keep probably 50% unhedged. That would be the rule of thumb. Bearing in mind, again, we've just locked in C$4.40, in the last two years to three years when we were running our budget at between C$2.50 and C$2.75. Those are significantly higher numbers and almost go straight into the bottom line. As you mentioned, Christophe, that you had tremendous pricing now in a forward. Would you be ready to hedge as much possible in the gas side and just keep the oil open? Or do you think just strategy-wise, it's enough what you do in it? Yeah. Lars, I think as Christophe has said, there's always a balancing decision with the target to get up to 50%. I think there are some quite interesting dynamics, we're seeing lack of storage injection through the summer where normally storage levels would be filling back up in anticipation of the much stronger winter demand season. I think we'd still like to have some exposure to potentially tighter gas markets in the winter. Right now, I think a balance between 50% is still a prudent level. It gives our investors a bit of exposure should we see winter tightness materialize. A cold winter could really send gas prices in January, February, very, very high. Thank you, guys. Thanks, Lars. Thank you. As we have one third question on the phone, just to remind participants, if you do wish to ask a question, please dial zero- one now. The last question currently in the phone queue is from the line of Ruben Dewa at Jefferies. Please go ahead. Your line is open. Good morning, guys. Ruben here from Jefferies. Thank you for taking my question and well done on the strong quarter. It is just a very quick clarification one from me. You mentioned gas price realization is pointing towards $4 per Mcf going at the end of 2021, I believe. Are these the kind of realizations you would expect to see throughout 2022, given the low storage levels you mentioned? Thank you very much. Ruben, sorry, the line quality was very poor. Could you try one more time or maybe send it via messaging to Rebecca? Yeah. Sorry. I just wanted to clarify on the gas price realizations. You mentioned that the level you're pointing towards $4 per Mcf going towards the end of 2021. I mean, the type of realization you would expect to see throughout 2022, given the low storage levels you mentioned. Ruben was just asking, what's the gas price we expect to see in 2022, given the low storage that we talked about previously, and the $4 that we've been able to hedge? Okay. Yeah. Sorry, just the line quality, Ruben, was very bad. If we look right now, obviously there's a difference between winter pricing and summer pricing. The latest numbers, if I recall correctly, for full year strip for AECO gas next year, you're looking at around $3.20-$3.30 per Mcf. To put that in context, as Christophe mentioned, our kind of base case CMD planning assumption over the last two years to three years has been around $2.50. It's a decent uptick from historical levels. Okay. Thank you very much, and sorry about the line. That's okay. As there are no further questions on the phones at this time, I'll hand back the floor to Mike. Yeah. Yeah. We've got a few web questions here. I'm going to skip all the questions on buyback from dividends that we can ask the capital allocation. First question, Mike, given the CapEx increase for 2021, do you maintain the cumulative figure from 2021 to 2025 is $250 million? Yeah. Okay. No, the short answer to that one is yes, we do. As I mentioned in the presentation, if you go back and look at our Capital Markets Day presentation, we did set a very limited capital expenditure budget deliberately this year to maximize our free cash flow generation at lower oil prices. What we saw is a step-up in capital expenditure into 2022. Essentially what we are doing by moving forward with the Malaysian and the Canadian investment programs in Q4 this year is bringing a portion of that capital forward. The short answer is there's no increase in that long-term guidance. Okay. Christophe, why has EBITDA not increased versus Q1 if there's a higher WCS and only slightly higher operating costs? Yeah. Operating cost obviously is one element. The other one being the hedging losses, where we registered almost $11 million in Q2 of hedging losses. I guess the free cash flow generation of $50 million, if it had been unhedged, would've been more like $61 million in Q2. I think that does underpin the financial generation capacity of the assets going forward. Yeah. Just to follow up with that, what would be the impact of hedges on free cash flow in the second half of the year? We would expect, so it was $15 overall for the first six months, and we would expect more or less the same level as current oil price extends. Those are factored into the free cash flow guidance up to $195. Yeah. Unhedged, the full year guidance would have increased by almost $30 million. We're talking in the high case, $225 million. Yeah. We do have a question on how does IPC manage to pay such low cash taxes? Just as a reminder, we do have all of our tax balances available on our website for representation. One of the biggest reasons, of course, is we've got $1.4 billion worth of depreciation and tax losses that are carrying forward in Canada. That's CAD 1.4 billion. We'll be delaying paying cash taxes in Canada for quite some years yet. Yeah. All the details. Yeah. We're almost in the same situation in Malaysia with some good tax position, meaning no tax payments, and there's a limited tax payment in France. There is just one more on capital allocation I keep in mind. Is your plan to reduce debt to zero before returning any cash back to shareholders? No. There's no firm plan to get to zero before shareholder returns commence. As I mentioned, back in 2019, leverage was just below one times when we commenced our share buyback program, and we should drop to those levels during the third quarter. Can we expect a ramp up in CapEx for Blackrod in 2022? I think 2022 is probably on the early side. We've seen very encouraging production performance from the pilot well results. We want to see those plateau levels sustained for a period. So, I think 2022 would perhaps be on the early side to start serious development expenditure. Okay. On the M&A, what are your thoughts on buying producing assets? What sort of size production are you looking at? We never set ourselves a target on production levels. I guess if we decide to go into a new jurisdiction, it obviously has to be something that's going to be material for the company. Still, we genuinely believe that IPC is well-positioned to benefit from the whole energy transition, and we've definitely seen an uptick in the number of assets that are coming onto the market from the majors, but also coming out of private hands that have been perhaps gone outside the original investment horizons. I think the strategy of acquiring producing assets and then applying our operational expertise to those assets has been very successful, and we still remain very opportunistic and still quite excited to play a role in further M&A on the production asset side. Okay. I think that's all the time we have for questions. Apologies if anyone feels like their question hasn't been answered. Please feel free to email me separately, and we can certainly follow up. Otherwise, I think we should close up. Okay. Thank you very much for everyone who's tuned in this morning. I think it's been an exceptional second quarter, and I think things are obviously continuing that momentum through the third quarter with continued strong oil prices and some production adds. We look forward to presenting the Q3 results in early November. Thank you. Thank you very much. Thanks, everyone.