A 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. Joining me in presenting this morning is Christophe Nerguararian, the CFO, and we also have Rebecca Gordon with us, who's our VP of Corporate Planning and Investor Relations. I'll begin with a run-through of the operations reports and some of the highlights, and then I'll pass across to Christophe, who will run through the financial numbers in a bit more detail. At the end of both the presentations, we'll of course, open up for the opportunity to ask questions, and we can take questions from those dialing in on the conference line, or you can also send in your questions via the web. To get started, another very solid quarterly performance from IPC, starting with the Q2 highlights and production. The second quarter average production numbers were 51,800 barrels of oil equivalent per day. That's our second quarter this year above the high-end guidance. With first half production now running above 52,000 barrels of oil equivalent per day, we're re-guiding that our full-year production numbers should now exceed the high-end guidance that we gave back in February, in excess of 50,000 barrels of oil equivalent per day. Continued solid performance and delivery on the cost side. Our second quarter operating cost numbers were very much in line with guidance at $17 per BOE, no need to change the full-year forecast that we have. It's maintained at $17.50-$18 per BOE. On the CapEx side, our 2023 capital expenditure forecast remains unchanged at $365 million. Major milestone achieved during the second quarter with the signing of the Blackrod Phase One EPC contract, and I'll come back with some additional color around that later in the presentation. Very solid cash flow generation. Brent prices kind of stabilized during the second quarter at around $80 per barrel. That allowed us to generate an operating cash flow of $84 million. That would have been around $8 million higher, but we did have a cargo in Malaysia that slipped into early July that was originally expected to be completed. Still very solid delivery, $84 million, and of course, we'll get the benefit of that cargo lifting in our third quarter results. We've taken the opportunity, obviously, with Brent prices averaging year to date around $80 per barrel. Our previous CMD full-year guidance, we're looking at $70-$100 per barrel. We've taken the opportunity to tighten up the full-year OCF guidance to now between $320 million on the low side, assuming $75 Brent for the remainder of the year, to now up to $390 million, assuming $90 per barrel Brent for the remainder of 2023. Third quarter free cash flow was $16 million. If we look at the cash flow generated by the base business, excluding the Blackrod funding, $65 million of free cash flow from the base business. Like OCF, we're taking the opportunity to tighten up the full-year free cash flow guidance range. Again, assuming at the low end, $75 Brent, and the high end, $90 per barrel Brent, we're expecting full-year free cash flow to be -$65 million to +$5 million. The balance sheet is still in a very strong position. Net cash position of $64 million. When we look at the overall liquidity that we have with the bond cash that we sit on and the other credit lines, we're in a gross cash position of $374 million. On the hedging side, no changes to the gas hedges, but we have been benefiting from those gas price hedges that we put in place back in late 2022. We've got around 50% of our net long exposure, which is hedged at around CAD 4.10 per Mcf. That runs from July through October, so those hedges well in the money with Canadian gas prices around CAD 2.50 per Mcf. No Brent or WTI benchmark hedges. The transportation hedge, the WCS to Argus hedges that we put in place, remains unchanged through the remainder of 2023 at CAD 10 a barrel. We have seen some real improvements in Canadian WTI to WCS differentials. They tightened by CAD 10 a barrel from the first quarter through the second quarter. We've taken the opportunity with those market tailwinds to lock in 50% of our Canadian oil production for 2024 at around CAD 14 per barrel. I'll come back to it in a bit more detail, when I give an update on Blackrod, obviously a significant proportion of our costs will be in Canadian dollars. We've also taken the opportunity during the second quarter to lock in nearly two-thirds of our Canadian U.S. dollar exposure, related to our Blackrod Phase 1 investment. On the ESG side, we continue to strengthen our non-financial reporting. We publish alongside the second quarter report today, our fourth sustainability report. To increase that disclosure, our first standalone TCFD report is also issued. One of the key highlights within the sustainability report is still very much on track to achieving the 50% reduction in our net emissions intensity, through 2027, which was extended earlier this year from 2025. IPC has been, you know, very aggressive on our share repurchase programs. That's continued through the second quarter. We committed under our normal course issuer bid to buy up to 9.3 million shares. We're approximately 75% complete through that program, with 7.1 million shares repurchased since we started the program back in December of last year. If we turn to the next slide, just a little bit more color around the production numbers. You can see the production chart on the right-hand side. The yellow dotted line shows the high end of guidance. You can see that pretty much through, through most of the second quarter, we were above that high-end guidance, except for in late May, where we had some planned maintenance on our Suffield Oil facility and our Onion Lake Thermal facility, but with really strong performance across all the major oil and gas assets and high uptime in Canada. We also benefited from the production contribution from four new Suffield Ellerslie wells that came online during the quarter and have been exceeding expectation, and I'll get into a bit more detail on that on the next slide. Internationally, our Bertam field has continued extremely high uptime rates in excess of 99%. In France, we concluded the four-well drilling program, which also gave us a bit of a boost through the second quarter, and we'll move on to those two production investments on this next slide. If we just look at the 2 charts on the right-hand side of the slide here, what we're showing is the guidance for production that we had from the top. Chart shows the four-well program, the Ellerslie well program. On the bottom of the slide, you can see the four-well program in France, which was three wells in Villeperdue and a sidetrack in our Merisier field. The second quarter production has been very much supported by the boost that we've seen from those new investments. I think you can see that both the Suffield Cor 4 Ellerslie wells and the French four-well program has been delivering ahead of expectations. Really pleased. Great job done by the teams there in Canada and in France and also with the high uptime in Malaysia. Really good operational excellence from all the teams across all parts of the business. The next bump that we should see with Pad L, which is due to come on stream during the third quarter, very much on schedule to start to see the production contribution at Onion Lake Thermal Pad L. With, as I mentioned in the highlights, with first half production, actuals at around 52,300 barrels of oil equivalent per year, we can see that, with a high-end guidance of 50,000 barrels of oil equivalent per day, we certainly feel comfortable now that we, we should be in a position to exceed now the high-end guidance of 50,000 barrels of oil equivalent per day. That will be the fourth year in succession that we'll be able to deliver above our high-end guidance. Again, phenomenal job by the teams across all the business units. Moving to the operating cash flow. In our February Capital Markets Day, we gave guidance at the lower end of the range, assuming a Brent price of $70 per barrel, and at the upper end of the range, $100 per barrel, with $5 Brent differentials and $20 WCS differentials. For the first half, oil prices averaged $80 Brent and five and 20 for the WTI and the WCS differentials. $180 million of operating cash generated from through the first half of 2023. What we've decided to do is just give a tighter guidance range for the rest of 2023, assuming that Brent oil prices average between $75 and $19, and the tighter differentials that we've seen, certainly on the WCS side of around $15 per barrel for the remainder of this year. That gives us an OCF range of between $320 million and $390 million. If we look at the CapEx program, certainly progressing the Blackrod Phase 1 early works. We've signed a major facility EPC contract during the second quarter, and we invested just under $120 million during the first half of 2023. Of course, with a full-year CapEx budget of $365 million, definitely a little bit more activity weighted to the second half of 2023, but still in line with that full-year budget. No need to change guidance at this point in time. When we feed through the cash flow generation and the investment program, in the base business, still good first half cash flow generation at $80 per barrel, $33 million for the first half. Like the, the OCF guidance, we're, we're again tightening the free cash flow guidance between $75 and $90 per barrel Brent to between -$65 million at the lower end of the range, up to a positive $5 million at $90 per barrel. Of course, that assumes funding of Blackrod CapEx of close to $285 million. Still some really, really solid cash flow generation from the base assets. When we turn now to the shareholder return framework, our capital allocation framework provides for returns to shareholders as long as the balance sheet is strong, and we define that as our leverage ratio. Our net debt to EBITDA is below one turn, and we're committed to providing 40% of free cash flow to shareholders. Clearly, with a big capital program this year, we expect from the base assets before funding Blackrod, with the new guidance range to generate between $220 million and $290 million of free cash flow. However, there is a big investment in our Blackrod Phase 1 development project, around $285 million. That would mean we would need oil prices of around $90 per barrel to start, under our shareholder return framework, to be distributing, value back to shareholders. However, the fact that we started the year in such a strong financial position with a net cash on the balance sheet of around $425 million, we've committed to going beyond, the returns framework and complete the Normal Course Issuer Bid, which should see us repurchase and retire 7% of the shares outstanding. From the beginning of December, we're well on track to meeting that commitment. We've repurchased 7.1 million shares so far under the NCIB program, at an average price of just over 100 SEK a share or CAD 13. That represents around 75% of the program through the end of 2023, and we fully intend to complete that program by early December. This year's research repurchase program is, is on the long line of repurchase programs since the company was formed back in 2017. In, in aggregate, we've now repurchased close to 59 million shares at an average price of 62 SEK per share through the end of the second quarter. When we take the market closing price of IPC from Friday last week of 96 SEK a share, we'd created more than $118 million in value from the share repurchase program. We continue that downward step through the anti-dilution staircase. If you, if you look where we stand now, only 15% dilution since we started the company, and we've managed to materially grow the company across all of our metrics. A fivefold, more than fivefold increase in production, more than 16 times increase in reserves, 20 years added to the reserve life, more than 1 billion barrels of contingent resources added. We've quadrupled our cash flow generation and added in excess of $3 billion in value, all with just 15% dilution, and certainly a lot more room for further share, share repurchases in the years ahead, and we'll get to that on the next couple of slides. If we look at this, this next chart here, it shows IPC's current market cap from the end of July, and we show the, the free cash flow that, that we expect to generate from the business, and this is after the funding of our $850 million Phase 1 development project in Blackrod. The first five years sees us generate a free cash flow of between $700 million and $1.4 billion US dollars, between $75 and $95 per barrel Brent. Essentially, oil prices of around $90 per barrel, we can fully fund Blackrod and buy back almost every single share in IPC over the first five years. Of course, with the cash flow boost that Blackrod Phase 1 will give us, up to between $2.6 billion and $4.4 billion in free cash flow over the 10-year period, which represents more than 2 to 3.5 times IPC's current market cap, just in the next 10 years, with a reserves life of in excess of 19 years. Likewise, from a value perspective, I think if we, if we look at the net asset value of the company using a 10% discount rate, the value of just only our 2P reserves, we're not talking about any value associated with our in excess of 1 billion barrels of contingent resource, $3.5 billion in value or 270 SEK a share. Today, the company's trading at, you know, close to 66% discount to 2P value, using the 10% discount rate, given our Friday share price close of CAD 0.96 per share. Huge room for material share price upside, given that massive discount that we're seeing. Of course, that's one of the reasons why we're prepared to continue with our share buyback program when you look at the free cash flow yield of the company and also the huge NAV discount that we trade at. If we turn now to the assets and to go through each of the key projects, we start in Canada with our Blackrod Phase 1 development. In terms of scope and schedule and budget, we're now pleased to say we're very much on track with the, the major milestone passed and signing the, the EPC contract in the, in the second quarter. Just as, as a reminder, IPC operates the project with a 100% working interest. We sanctioned the project in February of this year. It's a 220 million barrel 2P reserve that we brought onto our books, and we plan to invest $850 million to construct a 30,000 barrels a day Phase 1 project. We anticipate to achieve first oil late in 2026. Of course, once we've concluded that with Phase 1, we're still in the very favorable position that we have around 1 billion barrels remaining for future Blackrod development phases. In terms of schedule, the focus right now for this year is, is the planning and the and some of the civil construction work. Early stages and on the facilities side and manufacturing, in the workshop. Got a couple of pictures on the next slide, but still very much on schedule to, to target that first steam towards the end of 2025 and first oil in late 2026. If we turn to the next slide and just look at some of the progress. As, as I mentioned, we, we did sign the EPC contract, during the second quarter. What that means is largely 65% now of our Phase 1 development costs of $850 million have been locked in, and we're very pleased to see that costs were very much in line with our expectation that came out of the back end of the FEED studies that we concluded through 2022. What we've also taken the opportunity to do is a large proportion of the Blackrod Phase 1 development CapEx is gonna be Canadian dollar denominated. Obviously, because IPC is a predominantly a US dollar business, we've decided to lock in 65% of that Canadian to US dollar exposure through the EPC contract and through the financial markets and the hedging to give us much greater certainty around overall US dollar costs. Very pleased to report that having taken those collective actions with the contractual arrangements and the hedges that we've put in place, with two-thirds of the costs largely locked in, we're in an extremely good position that we still have in excess of 85% of the $110 million of contingency that we set aside, back in February when we came to the market with our guidance. I think it's still too early for us to, to think about releasing some of that until we get through, you know, finalizing the engineering and getting into the construction, but it's certainly a nice position to, to be in. If we just look at some of the pictures on the slide. On the top right-hand side, you can see that's the, the pilot facilities at our Blackrod site. If you cast your eyes down to the bottom left of the slide, you can see that the road access and the bridge, the road's been widened, and the bridge has been replaced so that we can manage to mobilize some of the major production modules to, to site. The, the two pictures of the evaporator systems, those are ex-Imperial Oil evaporator towers that were surplus to their requirement. Typically, these can be long-lead items, so we're very pleased to be able to, to secure those for, for our project. In the bottom right-hand side, you can see in the workshop, the, the start of the fabrication of the separator shell. Very good progress so far, and very much in line with expectation, with a comfortable contingency remaining on our Blackrod project. Now to touch on each of the assets. Onion Lake Thermal, if you look at the production chart on the bottom of the slide, you can see very stable production performance through the second quarter. In terms of the development projects, the major activity this year is the drilling and completion and bringing into production Pad L, and that's very much on schedule to achieve first oil during the fourth quarter. The team are continuing their work to look at further facility optimization projects. Turning to Suffield, you can see the production now includes the contribution from the acquisition of Cor4. Big jump of production up to, to in excess of 12,000 barrels per day, tapered off slightly with some of the turnaround work that we had at Suffield, we should be a bit of a see a bit of a bump back up with the 4th Core Four well that came into production just in the last month or so. On the gas side, still maintaining a very stable, shallow decline with an extremely active swabbing program that we've got running through 2023, where we plan to complete around 2,000 swabs on that property. Again, this is just a bit of a zoom in to the Core Four acquisition and a reminder of the focus of the investment program for this year. We're very pleased to announce in February the acquisition of Cor4, and if you look on the top right-hand side of this slide, one of the most interesting parts of the acquisition was the Ellerslie Play fairway that extends from the northwest of our Suffield license into the licenses that were controlled by Cor4. We plan through 2023 to drill five C ore Ellerslie wells on the Cor4 property, one in IPC's Suffield acreage, which is highlighted in the blue call-out on the map. So far, we've drilled four wells successfully on the acquired acreage during the first half. We've got more than 30 Ellerslie targets remaining in the inventory. As you can see from the production plot, the first three wells, we obviously saw some flush production with a ramp up to above 1,000 barrels per day, but we've been able to, you know, to sustain production levels from the first three wells of around 600 barrels a day. With the fourth well coming on stream, we've even pushed up above 800 barrels per day. As you can see from the guidance line, we're running a couple of hundred barrels a day hot from the forecasts that we were expecting that was underpinning our guidance. A great start and a good integration of the assets into the IPC portfolio. Turning to the international assets in Malaysia, again, the production performance has been. It's been extremely good with a very shallow decline. High uptime has continued on the Bertam FPSO, and a good strong base well performance in excess of 99% uptime achieved through the second quarter. You can see the infills, which are represented by the light blue bars that sit on the top, account for more than 60% of our production. Our most recent well, our A15 well, I think, paid back in less than four months, which was drilled in the first quarter of last year. Given the really good performance we've seen from these recent infill drilling campaigns, the team is looking to see if there's any remaining development potential in the northeastern part of the Bertam field. That's unlikely to happen for at least another year. Still some encouraging results that may see us drill up to another well in that area in the years ahead. Turning to France, if we look at the production chart on the bottom right-hand side of this slide, you can see France is characterized by a steady, stable decline. The base business has had a really good high uptime performance from all the producing assets. You can see, early in the second quarter, our production bumped back up to above 3,000 barrels per day, and that's really a result of the 2023 first half development activity, the four-well drilling program successfully being completed at Villeperdue West and the sidetrack that we did in Merisier. You can see the production contribution on the bottom left-hand side of this slide, from that development drilling campaign that's seen us push back above 3,000 barrels per day in France during the second quarter. When we turn now to our sustainability and ESG performance, again, really pleased to say that we have had no material safety or environmental incidents, during the first half. As I mentioned in the highlights, we, we have continued to, to improve our non-financial disclosure. We published our fourth sustainability report, and alongside that, for the first time, is a standalone TCFD report. We've spent a lot of time upgrading all the data that we show on the IPC website. Tremendous amount of work done by the, the sustainability team. I really encourage all of our stakeholders to take a good read through all the materials that's been released this morning and see the good work that's going on within our company. In terms of the climate strategy, very much on track to achieve that net 50% emissions intensity reduction through now the end of 2027, which has been extended earlier this year by a further two years. That concludes the operations part of the presentation. I'll pass across to Christophe now, and he'll walk you through the more detailed financial results. Christophe? Yeah. Thank you very much, Mike. Indeed, a very strong performance on the operational front. Congratulations to all our colleagues around the world for indeed a very good performance in this second quarter, where the production was just shy of 52,000 barrels of oil equivalent per day. On average, for the first half of this year, we produced in excess of 52,000 barrels of oil equivalent per day. The Brent was a bit softer. The Brent price a bit softer during this second quarter, but the interesting part is that with a tighter differential in Canada, our net backs in this second quarter were actually stronger. The costs remain under control at around 17 operating costs at around $17 per BOE for the second quarter, and $17.2 per barrel of oil equivalent for the first si months. We maintain our guidance for the costs while we've increased our production guidance towards the higher, the higher end of the range. That translated into a solid financial performance of roughly $85 million for both the operating cash flow and the EBITDA. I'm just gonna pause here for a minute 'cause we have a couple of analysts who noted that we were a bit below on our actual revenues during this quarter, and they were right and wrong. The, the, the laws of nature makes it that the, the end of the quarter is on the 30th of June, and actually, we were literally lifting a cargo in Malaysia on the 30th of June. The end of the loading of that cargo fell into the, the first day of July, which means that the revenues attached to this cargo will be reported in the second quarter. We're talking about roughly $20 million of revenue moving from the last day of the quarter to the first day of the, of the third quarter. What, what, what could look like a miss on revenues is actually the, the consequence of the fact that we've been selling less oil than what we produced during the quarter. Bearing that in mind, $160 million of operating cash flow and EBITDA for the first half, that would have been at least $10 million higher should June had a 31st day. The CapEx is close to $60 million for this quarter and $113 million for the first six months, resulting in a net cash flow of $16 million for this quarter. Before Blackrod CapEx, the free cash flow for this quarter is $65 million. Important to remind that IPC has a very strong ability to generate strong cash flows. The cash position remains very comfortable, with a gross cash position of $374 million sitting on the balance sheet. In terms of realized prices, the Brent was on average $80 for the fir st six months, but was down $3 compared to the 1st quarter in the 2nd quarter. That being said, because the WTI, WCS differential went from -$25 in the 1st quarter to -$15 in the 2nd quarter, you can see that the WCS calculated for the second half was actually $7 higher. An interesting, interesting quarter, where lower Brent and WTI prices translate into a higher WCS, contributing to a higher, contributing to a higher net back for the overall IPC business. Otherwise, you can see that we're still gaining very significant premiums for our crude oil, which is in high demand in Southeast Asia. Because of some seasonality during the quarter, the premium you see here are not quite correct, typically, we have premiums in excess of CAD 7-8 regularly for our Malaysian crude. Otherwise, in France, we're sitting on par with Brent, in Canada, our heavy oil sells on par with the WCS. Again, I was just mentioning only one cargo lifted during the second quarter, because we were lifting in the last day of the second quarter, it's going to be complete and reported with the third quarter, that cargo. Looking at realized gas prices, a bit of a softer market for gas prices compared to the last couple of years. I mean, CAD 2.5 per Mcf for gas prices in the summer is not ridiculously small, but obviously softer than what we've experienced over the last two years, and especially compared to last year with the war in Ukraine. The realized gas price in the second quarter was CAD 2.44 per Mcf. It makes, with hindsight, it makes the value of the gas hedges we entered into very, very valuable. Obviously, you see that during the first quarter, we had 50% of our net gas production hedged at in excess of CAD 6 per Mcf, and still in Q2 and going into Q3, and up and including October this year, we have 50% of our net exposure hedged at CAD 4. That translated into in excess of $10 million hedging gain for the first six months, and that was mainly driven by those good gas hedges. Looking at the quarterly and the first half operating cash flow and EBITDA performance, I actually like this slide because it's a good reminder that in 2022, you could, you, you, you see the very strong financial performance, and that, that is the result of $20-$30 more. When oil prices were $20-$30 higher in 2022, you can see that. You can see how much cash flows, the business would generate, and it's a, it's a striking reminder of how much IPC is exposed to the upside. In a market like today, where oil prices, are, are, are smoothly but surely ramping up with the market turning into, into a deficit position of 1.5-2 million barrels a day deficit globally, I think, we have a business which is rightly exposed to the upside. Looking at the operating cost, so we've maintained the annual guidance of $17.50-$18 per BOE for operating costs. We were below for the first half. In the second part of the year, we have included some, some increased activity around maintenance and workovers, which may or may not fully materialize, but we feel comfortable maintaining our operating cost guidance below $18 per, per, per BOE. Looking at the, the netbacks on the, on the following slide, you can see that for the, for the second quarter, our operating cash flow and EBITDA netbacks were in the range of, of around $18 per BOE. If you compared that to our, our Capital Markets, the guidance adjusted for the, for the average dated Brent price, that's where you would realize that our netbacks are a bit, are a bit low compared to our guidance, and that is just the reflection of what I was explaining before. We've been producing more oil than what we were able to sell because of the last lifting in, in Malaysia. Otherwise, if you, if you included that last lifting, the, the netbacks are right in line with, with our Capital Markets, the guidance. Looking at how our net cash position has evolved, you can see the $160 million of operating cash flow, which have fully covered our development CapEx, our G&A, our cash financial items, and a part of the Cor4 Oil acquisition. With the increased or continuous share buyback during this first half, and some decommissioning, spending, and windfall tax in France, which is included in this change in working cap, we've been using a bit of the cash we were sitting on at the end of last year. The net cash position has reduced from $175 million down to $64 million, but we are still sitting on our balance sheet. We still had, at the end of June, $374 million of cash. On average, between Q2 and Q1, we have less cash on the balance sheet in, in, in Q2, but we're still, we're still gaining very, very nice interest on all this cash, in excess of 5% from from from our banks, our core banks. The net interests are still fairly low compared to the coupon of the bonds, because we're getting more than 5% on our, on our deposits. In terms of G&A, at less than $4 million a quarter, the G&A remain well under control and well below $1 per per BOE. Looking at the, the financial result, you see the close to $400 million of revenues, which again, could have been $420 million with the last cargo, less the production cost, that gives us a cash margin of $164 million, comparable to the EBITDA and operating cash flow for the, for the first half of this year at $160 million, turning into close to $120 million of gross profit and in excess of $70 million of revenues for the first six months or the first half of this year. Looking at the balance sheet, you can see that the, the main change was the increase in oil and gas properties, and that more than a $150 million increase in oil and gas properties is really the result of the CapEx spending and the Cor4 acquisition, which you partially find on the liability side of the balance sheet, with increased provision for future abandonment liabilities, which were part of the, the Cor4 acquisition. In terms of capital structure from a, from a, from a funding and liquidity perspective, there was no change this quarter. We increased on the last day of the first quarter, we doubled the size of our revolving credit facility in Canada at CAD 150 million, which remain fully undrawn. We only have used 5 million CAD to issue letters of credit to support of our normal course of business. In terms of hedges, actually, we've been quite active towards the end of the quarter and in July. You can find those in the subsequent events relate explained in our financial statements or MD&A. What we've done is we've leveraged on the good market conditions in terms of the WTI, WCS differential to lock in 50, roughly 50% of our 2024 Canadian oil production. We were able to hedge close to 50% of that future production at minus 14, which is $14 per barrel for 2024, which is a very decent level indeed. If the differential for next year now is just above $15. If it goes below $15, we might hedge some more in order to secure a high level of free cash flow in 2024 when we're continuing to heavily invest on Blackrod. The other thing, we've hedged the winter months for the condensate, which we need to blend into our production to meet the WCS specifications. We've hedged 50% of the condensate we need for the winter months. In the winter months, condensates tend to be priced at a premium to WTI, again, we use the dip in the market to secure WTI minus $1.6 per barrel for the condensate we need to buy in the winter months, which is when the market needs more condensate than in the summer. I think the other important part to note, and Mike touched on that, is that not only have we contracted around 65% of the, the Blackrod CapEx, but we've also hedged roughly 65% of our Canadian exposure. As you know, we are reporting in US dollar. Our revenues are US dollar related and driven, and so we've decided to hedge roughly 65% of the Blackrod Canadian dollar exposure because vast majority of our spending on Blackrod is in Canadian dollar, which is reasonably weak now, especially compared to what we had in our budget for the years to come. When you wrap up this FX and put that in the context of the Blackrod project, it helps us secure a very high level of contingency, and we have more than 85, closer to 90% of remaining contingency under the Blackrod budget. Very positive from that perspective. That concludes my financial part. I will let you, Mike, conclude. Okay. Yeah, thank you. Thank you very much, Christophe. Just to recap on the Q2 2023 highlights. High production of just under 52,000 barrels of oil equivalent per day, record production in the first half. On the back of the very solid production performance, we're expecting now our full year production numbers to be in excess of 50,000 barrels of oil equivalent per day. As Christophe has shown on the cost side, everything very much under control and in line with expectation, with $17 a barrel OpEx in the second quarter, and still very much on track for the full year guidance of between $17.50 - $18 per BOE. Big investment year this year with the first year of funding our Blackrod Phase 1, and no changes to the $365 million of capital expenditure guidance. The base business still generates material cash flows. The $80 Brent in the first half, we generated in excess of $160 million, $84 million in the second quarter. In the second quarter, free cash flow of $16 million, with a full year expectation now of between -$65 million to +$5 million, assuming Brent prices average between $70-$90 per barrel, $75-$90 per barrel for the remainder of the year. As Christophe has shown, the company is financially in a very strong position with a solid balance sheet. Net cash stands at $64 million at the end of June. With the additional cash proceeds that we have from the bond that we issued at the beginning of 2022, gross cash sits at just under $380 million. Sustainability-wise, we're continuing our good progress on our carbon reduction and offsetting program, and still expect to achieve a net 50% reduction by 2025, which is extended through 2027. No material incidents to report during the second quarter, as we highlighted, we've issued our fourth sustainability report alongside our independent TCFD report. On the share repurchase side, it's been part of our core business is to continue to create value by buying back our undervalued shares. 2023 is no exception. We've bought back 7.1 million shares under our NCIB program. It's 75% complete, we fully expect to conclude the last 25% during the second half of 2023. Just finally, as a reminder of the transformation that we're all very excited about here within IPC as we embark upon this large investment in our organic growth expansion. Very stable, low decline base business that can average production of in excess of 50,000 barrels a day through the 2023 to 2027 period. Still material free cash flow generated in the first five years of our business plan, having funded $850 million of Blackrod CapEx, generating between $700 million and $1.4 billion in free cash flow, between $75 and $95 per, per, per barrel Brent. To put that in context, IPC's current market cap is around $1.2 billion, so we can repurchase every single share at $90 Brent in that first five years. Once Blackrod is up and running, we're gonna grow production 30% and be able to sustain in excess of 65,000 barrels a day for the next five years. We'll only have produced 20% of our 2P reserves, and we'll see a free cash flow yield really jump to between 30% and 50% per annum, assuming $75-$95 Brent. Very exciting transformation underway in IPC's business. That concludes the presentation of the operations update and the financial report for the second quarter. We can turn now and open up to take any questions that you may have. Rebecca, I'll pass back to you to. Yep. coordinate the Q&A. Operator, if you have any, any questions that have come through on the telephone lines? Sure. Thank you. As a reminder, if you would like to ask a question, please signal by pressing star one on your telephone keypad. We will take the first question from line, James Hosie from Barclays. The line is open now. Please go ahead. Hi. Good morning. Yeah, a couple of questions from me. I guess, firstly, Blackrod. You guys finalized that significant portion of the capital budget for the EPC contract. I'm just wondering what you mean by cost being largely locked in. Are there particular aspects of the contract where you retain the price risk? Just more generally, where do you see the most significant remaining risk to the budget that could draw on that contingency you now have? Then on the production guidance, I guess, to be blunt, like, why did you just raise the range? I mean, should we be thinking 50,000-51,000 barrels a day now, or could you do even better than that? Yeah. Okay. No, thanks, James. Yeah, so yeah, you're right. When we say, when we say largely fixed price, so there's, there's really two parts to the TDE contract that we've signed. The, the first part is a fixed price component, which is about 45%, shall we say, of the 65%, and then there's a target price component which can have a certain amount of variability. Around 20% of that, which we estimate could vary kind of ±10%. We chose not to lock that part of the contract in, because if you ask the EPC contractor to take that risk, typically, they'll be more conservative and fix a higher number that we think we can potentially do better. It was very much a conscious decision, to give us some flexibility to do better than locking in that last 20%. As I say, you're looking at around ±10%, on that much smaller part of the overall contract. When we look at the remaining contingency, I mean, the bulk of the rest of the CapEx is mainly gonna be relating to the drilling. I think there is still. You know, we haven't finalized all of the detailed engineering. I think one of the reasons why we think it's still too early to, to look at potentially re-releasing some of the significant contingency that we've still got in the, in, in the budget, is until we've finalized all of that detailed engineering work, and we've started the fabrication, and we've, and we've got a higher degree of certainty there. I hope that covers your questions on the Blackrod contract. On production, when we say, you know, above, above 50,000 barrels per day, we haven't been specific to say it can go above 51. I think if you're, if you're looking in that range that you talk about between 50-51, I think we feel very comfortable with that kind of, with that kind of, re-guidance range. Okay. That, that's fine. That's helpful. Thanks for the clarity. Okay. Thanks, James. Thank you. We will take the next question from line. Teodor Sveen-Nilsen from SB1 Markets. The line is open now. Please go ahead. Good morning, Mike and Christophe. Thanks for taking my questions. A couple of questions from me, both related to buybacks. I understand that you will buy back less shares in second half than first half of this year, and you say that you will only buy back if oil price is above $90, as far as I understand. Is that the buyback reduction mainly driven by the CapEx increase in second half, or are there any other factors going into that consideration? Second question on buybacks, that's more long-term question. How should we think around buybacks going forward versus dividends? What kind of share price and what kind of discount in NAV do we need to see for you starting paying cash dividends instead of buying back shares? Thanks. Yeah, okay. Thank, thank, thanks, Teodor. Yeah, I mean, I, I think, I think your first question, which relates to the, to the pace of the buybacks, I wouldn't read anything into the, to the pace of, you know, having 25% left between, you know, the beginning of August and, and the end of November. The, the program that was approved, already for 2023 was, was already kind of well ahead of that, that's strictly committed to under our capital allocation framework, to go up to the full 7%. We just, you know, the share price was weaker in December when we started the program, so, the pace of buybacks was a little bit faster. We also, in February, after our year-end results, we saw a little bit of weakness, so we took the opportunity to pick the pace up there. Yeah, certainly nothing to read into the, to, to the fact that there's slightly less between now and the end of November to conclude the share re-buyback program. The second question on the, on the longer term outlook, I mean, I think if we, if, if we look at the, you know, still the very large discount, you know, in excess of, you know, 60-70% discount to our 2P net asset value. The fact that that doesn't bring any valuation to the 1 billion barrels that we have in our contingent resource base and, and the free cash flow yield that we see, the base business is gonna be generating going forward. I would say for the, for the foreseeable future, you're gonna be looking at share buybacks as opposed to, to dividends until we see that massive value disconnect unwind. Okay. What kind of discount are we talking about? Would you be okay to pay cash dividends at a discount to an NAV, or do you need to see valuation up to full NAV to consider the cash dividends? Yeah. I mean, we, we haven't set a fixed discount to you, Dor. And the reason being there is, of course, it does move around every year. As, as you know, when we look at our 2P net asset value, we take our reserve auditors independent, you know, view on long-term prices. So it does change from year to year to year. But there's, yeah, there's not a fixed element right now, but with such a large discount, I think for the foreseeable future, the focus will be on share repurchases as opposed to dividend. Okay, understood. That's all for me. Thank you. Okay. Thanks, Teodor. Thank you very much. Thank you very much. We'll take the next question from line. Mark Wilson from Jefferies. The line is open now. Please go ahead. Thank you, and good morning. A couple of just points. Bringing on that pad, the new pad at Onion Lake, Mike, I didn't catch whether you said 3Q or 4Qs. Just reiterate on that. Then longer term, you know, great to see your first sustainability report. Could you just outline on the 2027 and the, and I think the 20 kilograms of CO2, are you aiming to maintain that with Blackrod on stream? Is that what we should read into the 2027 target? Thank you. Okay. Yeah, thanks, Mark. For the first question on Onion Lake Thermal, yeah, we do expect to see the start of the ramp-up of production in the Onion Lake Thermal in the fourth quarter. Potentially could be earlier in the third quarter if, you know, if the good progress continues that, that, that we're seeing. Just as a reminder, the production contribution from Pad L should be in excess of 4,000 barrels a day over time as we ramp up all of the wells. As I think we've talked on previous calls, the facility capacity, Onion Lake Thermal, is 14,000 barrels per day. It, it will be one of the first times, that we will be testing the facility constraints of, of Onion Lake Thermal, and we'll have enough well stock to exceed, the facility constraints. Of course, that's why we mention on the slide that the team is looking at further optimization projects to see, if it's gonna be worthwhile investing and, and expanding the facility, say, from 14,000 barrels a day up to 16,000 barrels a day. It will certainly be, we'll be in a very strong position that we should be able to, to see those much higher average production levels sustained over the next few years with the addition of Pad L. Then the, the second question on, on Blackrod and the, and the net emissions reduction target to 20 kilograms per BOE. We've deliberately not set a target yet beyond 2028 because with Blackrod, of course, one of the things that we did look at before the sanction of the Phase 1 project was the potential for carbon capture that wasn't an economic investment at the time that we chose to take the final investment decision. Our view has always been that as the technology improves, and probably more importantly, as we hope to see some positive fiscal improvements, both federally and at the provincial level, that has been discussed for carbon capture and storage project. We've certainly got the geological formation to be able to do that at Blackrod. I think the reason that we've been reluctant to commit to kind of beyond 2028 when we ramp Blackrod up is we, we hope to be able to see technology improvements and fiscal incentives to allow us to consider a carbon capture project at Blackrod in the medium to longer term. Okay. Okay, interesting. Thank you. Last point, the net asset value, Mike, you always show it, you always talk to it, huge discount to it. What's everyone missing there in that calculation? Yeah. I mean, I think, I think it's, it's not... As you, as you know, Mark, you've been following us for a long time, it's not something new. I think when we, when we took the decision back in 2017 to buy into Canada and materially expand IPC's business into Canada, that was very much a feature of that market when we-- certainly, when we acquired BlackP earl, the company, IPC then was more internationally focused. We were trading at a 25% discount to our 2P NAV, and the Black Pearl discount was in excess of 70%. I think it's partially. Probably tied to the fact that there has been, there's been historically more volatility in the Canadian market with the, with the issue that you've had with the lack of pipeline export capacity to the US and the big volatility that we've seen in Canadian crude price differentials. It's no secret that production was, was run far ahead of available pipeline export capacity, and that, that had created a lot of volatility. We start to see that position materially improve, obviously, at the end of 2021, when Enbridge's Line 3 came into service. We've seen the tightening in differentials that Christophe talked about through the second quarter with the OPEC cuts and the, and the SPR now turning to, to some repurchases rather than emptying the, the strategic reserve. With Trans Mountain coming into service from first quarter of next year, I think that should give a lot more certainty on perhaps one of the risk factors that's been hanging over Canadian markets. Perhaps we can start to see that discount narrow once that key piece of infrastructure comes into service in the first quarter of next year. Got it. Okay, that's, that's really interesting. Thanks for... Thanks for the answers. I'll, I'll hand it over. Thanks, Mark. Thank you. There appears no further question at this time. I'll I'll hand it back over to your host for closing remarks. Thank you. Actually, we do have a couple of questions from the internet. Perhaps I can start with you, Christophe. Have you considered additional bond issues? In which case, what kind of coupon would you expect on an additional bond? Yeah, no, that's a, that's a very good question. We always keep an eye on the, the, the bond market because effectively, if you see where we stand today, we have a coupon of 7.25%, and we can deposit, our, our money or cash at, in excess of 5%. The cost of carry is very, very small and gives us lots of flexibility for buybacks, for Blackrod, or, or, or for potential acquisition in the future. In, as part of the $300 million bonds we issued, we did that under the framework. It was a framework of $500 million. What that means is that we could tap up to an additional $200 million under the exact same terms and condition, and the only change would be the at which, at which price we issue those additional $200 million. Currently, our bonds are trading at between 94 and 95. There's clearly some, some more, more, more firms coming back to the, to the bond market. It, it has a bit of a tailwind there. We, we, we keep an eye on it. The coupon would be probably, would translate probably at around, or the yield at, 8.5%, 8.75%, so a bit on the high end of what we could consider. We are, we are not ready to act, but we certainly keep an eye on this on this market. Okay. Thanks, Christophe. Mike, question from Tom Erik Kristiansen from Pareto. Given the high inflation in the market at the moment, did you need to use some of the estimated contingency on Blackrod, or has the buffer relative to the CapEx that hasn't been locked in increased? Yeah, if we can start with that one, Mike. Yeah, I mean, I think, I think as we're, as we're shown, we've still got in excess of 85% of the, the contingency remaining, and we haven't seen any big movements on the non-EPC contract costs. I think, I think we're being prudent. I think it's a sensible thing to do at this stage in the project. As, as I mentioned, we still haven't finalized all the, the detailed engineering, and we've still got the drilling work scopes to go out to tender and get firmed up. As I said during the call, with the contract signed and in the rearview mirror, we certainly feel extremely positive about where we're standing today. Okay, great. Also from Tom Erik on M&A. How are current energy prices impacting potential deals? Do you still see opportunities through acquisitions of capital-constrained assets? I think, I think the short answer is very much yes, and a clear example of that was our Cor4 acquisition back in February of this year. It was a very nice strategic tuck-in acquisition, and it was exactly as Tom Erik has highlighted there, this was a, a smaller company that certainly didn't have access to the same capital that IPC had and perhaps wasn't drilling as fast as, as, as we would do, and, and therefore, bringing that land position and resource base into the IPC portfolio. You know, this has also allowed us to, to create some synergies, and if you, if you look at the value of where that, you know, asset was trading, we've purchased in excess of 5,000 barrels per day for around $62 million. You're looking at around $30,000 per barrel, flowing barrel. Still extremely favorable acquisition with fast payback and a decent inventory. I think as long as you can look hard and you're patient, there are, you know, good assets and companies out there, but of course, there are still a much larger proportion of assets that we think are probably overvalued. Okay, thanks, Mike. Just following on from that M&A question, another question from Jürgen Wiedemann, also Pareto. Do you see some opportunities in gas assets now that the prices have come down significantly? Are you looking at any M&A there? Yeah, I mean, I wouldn't say it's an immediate focus right now. I mean, IPC is in an extremely favorable position on the gas side because we produce more gas than we consume at Onion Lake Thermal. We produce about two times the gas that we do consume at Onion Thermal. As time goes by, as we start to ramp up our Blackrod Phase 1 production profile, that will continue essentially up until around 2030. I think the current short-term strategic priority is less focused on the gas, but as we start to approach the second half of 2020, then, you know, we may start to take a bit more interest in some gas assets, but not for the time being. Okay. Thanks, Mike. Christophe, a couple of questions for you. One from Ruben Dujah. On the $20 million of revenue that you said would fall into Q3 versus Q2, how does this reflect on the underlift in your revenue line in Malaysia? Technically and accounting-wise, it's not an underlift because we just lift when we lift, so we're not late for lifting, if you wish. The way we account for that is because we cannot report the revenues this quarter, you actually cancel out and reduce your cost of operation for that portion of the barrels you've not sold. You've produced, but not sold during the month. Actually, if you look in your cost of production, there's a negative cost in change in inventory in Malaysia. You can find that in the MD&A. It's roughly $5 million of reduction on the cost of production in Malaysia, that is roughly the cost of producing those barrels that we've produced, but not sold. Okay, thank you. Then there is some talk of higher pipeline charges for Trans Mountain. How do you think about Trans Mountain impacting the likely WCS, WTI spread once it's operational? Yeah. Do you have an expectation of timing for that? Yeah, that's, that's a, that's a really interesting one. I mean, different, different views. The latest we heard is that the line fill could occur towards the last part of Q4, so we're talking about.. Or we heard about December. It's just hearsay at this stage. That means the, the, this increased capacity of TMX could be available for exporting additional barrels in the first quarter next year. It's not clear exactly what, what that cost increase is gonna be for tariffs. The CapEx of the overall project have ballooned and exploded through the course of building that project and with the legal challenges. For sure, the tariffs will be a bit higher. Nevertheless, what matters to us is that Western Canada is going to have increased export capacity, and there are discussions about the fact that increased export from the Trans Mountain pipeline could go to PADD 5, so to California and the US and to Asia, but also to PADD 5, which may use some of the barrels which would otherwise go to PADD 2 and PADD 3. That could create less supply for, from Canada to PADD 3, and then PADD 2. Overall, it is going to have a stabilizing effect on the differential, and very likely a reduction effect as well for the, for the years to come. We don't know whether it's going to be -10 or -15. What we know is that it's gonna be more stable and for a number of years, which is very beneficial to all Canadian heavy oil producers and to IPC in, in particular. As Mike mentioned, That was the number one reason we went to Canada, where we found that there was a disconnect between price and value of assets, and we believe that with TMX coming on stream, although two years later than once anticipated, but finally coming on stream, this disconnect between value and price of assets and valuation is mostly going to be bridged. Okay. Thanks, Christophe. Mike, just a couple of small questions on the other assets. Pad L seems like it'll bring on eight new wells. Is there a possibility to produce over the current 13,000 barrel a day facility capacity? Are there facility constraints when all these wells come online? Yeah, thanks. Well, I, I think I answered that question when Mark Wilson asked, that, yeah, we, we are.. Pad L will add about 4,000 barrels a day of production capacity over time, we're currently producing around 13, and the facility is around 14. We will have more production capacity and well stop than facility capacity, and the team's looking to see if it makes sense for us to, to look to expand that. We're gonna be in a really good position to sustain high production rates at Onion for a number of years. Okay, thanks. How are we looking at the Ellerslie acreage? Do we have the capacity to find the more prolific wells there, one of which has delivered 205,000 barrels in 17 months? Yeah, I mean, of course. As I said, we've got an inventory, of more than 30 drilling targets, and of course, our team on the ground. When we go through our project ranking process, we obviously start from the subsurface up, and we look at reservoir properties in terms of thickness and reservoir quality, and we look at offset wells, and we decide which are the best wells to be drilled within the inventory. Unless there's any particular license reasons why we have to drill a well in a certain location, typically, the rule of thumb is that well that will generate the highest returns and generate the quickest payback will be drilled first from the inventory, pending any license commitment drilling that we need to undertake. Great. Okay. Thank you, Mike. That's the end of the internet questions. Just to conclude, thank you very much for everyone, for tuning in to, I think what's been a very good operational and financial performance for the second quarter. Obviously, with Canadian differentials tightening and tight physical markets, we're seeing Brent prices start to trend upwards. I think the company is in great shape to generate some really good results for the second half, and we look forward to updating everyone in early November, alongside our third quarter results. Thank you very much, everyone, for tuning in. Thank you. Thanks, everyone.