Okay. Very good morning to everybody, and welcome to IPC's first quarter results and operations update presentation. My name is Mike Nicholson. I'm the CEO of IPC, and joining me this morning presenting the financial numbers is Christophe Nerguararian, and we also have Rebecca Gordon, who is our Vice President of Corporate Planning and Investor Relations. I'll start in the usual form by running through the highlights and the operations update, then I'll pass across to Christophe, who will walk you through the detailed financial numbers. At the end of both our presentations, of course, there will be the opportunity to ask questions. We can take questions from those joining on the conference call, and you can also send in your questions via email. Via the Internet, sorry. To get started with the highlights from the first quarter, in terms of our production performance, it was a record production level. We achieved average production of just under 53,000 BOE per day, and that was actually above the high-end guidance that we gave back in our February Capital Markets Day. As a result of that, really good start to the year, we're now expecting our full year production numbers to be towards the upper end of that guidance range of 50,000 BOE per day. In terms of operating costs, very much in line with our guidance. Q1 came in at $17.30 per barrel, we're retaining the full year guidance at $17.50-$18.50 per BOE. Big year in terms of our investment program with the sanction of Blackrod. First quarter CapEx was very much in line with expectation, $55 million, and we expect our full year CapEx forecast of $365 million to be maintained. Cash flow generation. First quarter OCF was very much in line with guidance at $76 million. When we look at the full year forecast that we gave back in February, assuming at the lower end Brent $70 per barrel and at the upper end $100 per barrel, that also remains unchanged at between $250 million and $495 million. First quarter free cash flow was a + $16 million, and likewise with our OCF guidance. The full year free cash flow guidance remains unchanged at -$145 million, assuming $70 Brent, and up to $105 million, assuming $100 Brent prices on average for the full year. The balance sheet's in great shape, and Christof will walk you through greater detail. Net cash position of just under $70 million. When you look at the balance sheet with the gross cash with the bond proceeds included, we're sitting on just under $380 million. We have seen weakening in gas prices in Canada, and Christof's got a slide on that in his part of the presentation. We are in a good place in the sense that we put in place in late 2022 when gas prices were very strong, 50% of our net production at favorable prices of in excess of $4 per MCF. No hedges on the benchmarks on our Brent or our WTI exposure. We've got about 50% of our Canadian oil production for the transportation component hedged at $10 per barrel. Excellent ESG performance. No material safety or environmental incidents to report during the first quarter. Very much on track to achieve our 50% net emissions reduction target by the end of 2025, which was further extended through the end of 2027 back in the first quarter in February of this year. We approved a continued share repurchase program, the normal course issuer bid back in December 2022, making great progress in getting through that program. 5.5 million shares have been repurchased through the end of the first quarter, that program is essentially 60% complete. A really good start to 2023. If we turn now and walk through production in a little bit more detail, as I mentioned, in the highlights, a record quarterly production of 52,800 barrels of oil equivalent per day in the first quarter. If you look at the chart on the right-hand side of the slide, you can actually see our CMD low and our CMD high guidance. What we can take away from that is pretty much every day through the first quarter, we were in excess of that high-end guidance. That was really driven by a combination of factors in Canada, an extremely strong performance from our Suffield oil and gas producing assets, which now includes the Cor4 acquisition. I think the decision to acquire that additional production and defer some of the discretionary capital investment that we could have undertaken really gave us some wind in our sails to ramp those production levels up much more quickly than would have been possible had we not made that acquisition. You're also going to see later in the presentation a very strong performance in our Onion Lake thermal property. On the international side, the Bertam field continues to produce extremely well. We've been running a well optimization program. Again, another quarter of facility uptime in excess of 99%, which is just extraordinary. Congratulations to the whole team in Malaysia. In France, we completed our drilling program, our three wells on Villeperdue West and one well, our sidetrack on Merisier. No production contribution from those wells in the first quarter, we do expect to see some of that production coming through in our second quarter numbers. When we look at the first quarter production of just under 53,000 BOE per day, clearly well in excess of the high-end guidance, that's why we feel comfortable already at this time in the year to now re-guide with an expectation that we expect our full year production numbers now to be towards the high end of that 50,000 BOE per day production level. Turning to Operating cash flow, our first quarter OCF was $76 million, slightly below the midpoint guidance that we gave back in our February Capital Markets Day. Underpinning that guidance was an $85 per barrel oil price forecast and a $5 Brent to WTI differential and a $20 per barrel WCS differential. The fact that Brent prices were slightly weaker, $81 per barrel in the first quarter, and differentials were $5 wider than our midpoint guidance, in line with guidance taking into account those lower realizations on both benchmark prices and the WCS differential. No need to change the full year guidance between $250 million and $495 million. On the CapEx front, it's a record investment year for us this year, particularly having taken a decision to sanction our Blackrod phase one development, in aggregate $365 million across the business. The investment program in France is essentially complete and a minimal program that we have in Malaysia. The Blackrod phase one works are Are progressing in line with schedule and budget. The drilling program in both Canada and in France very much in line with budget. $55 million spent in the first quarter, and we still remain on track for that full year forecast. In terms of the free cash flow post the significant investment in Blackrod at the $70 per barrel level, we're forecasting -$145 million of free cash flow. At a $100 per barrel Brent, a + $105 million of free cash flow. First quarter free cash flow, again, very much in line with guidance, $16 million. We do expect our capital expenditure to ramp up over the remainder of the year. Still no need to change the full year guidance numbers that we have here. What are we doing with the free cash flow that the business is generating? We had nine-star shareholder return framework back in our February Capital Markets Day. Our commitment is as long as the balance sheet is in good shape, and we define that as a leverage ratio of net debt to EBITDA below one turn, then 40% of free cash flow is to be returned to shareholders. Significant free cash flow being generated from the base business before our Blackrod project between $140 million and just under $400 million through a $70-$100 per barrel Brent oil price range. Significant capital expenditure, though, in Blackrod this year, just under $290 million, means that essentially the base business plus the Blackrod phase one development is fully funded at around $85 per barrel. I think importantly, because of the financial strength that the company started the year with, we got the approval to continue, notwithstanding the big investment commitment this year to buy back up to 7% of our shares under the normal course issuer bid program. You can see we have made significant progress under that program, having repurchased 5.5 million shares since the start of December when that program was announced at an average share price of around SEK 102 per share. We do intend to fully complete that 7% share repurchase through the end of November this year. This next slide just shows in aggregate the material value that we have created through the successive share repurchase programs. The only dilutive transaction that IPC has undertaken was the business combination with BlackPearl Resources back in December of 2018. Since then, we're now on our fifth share repurchase program. In aggregate, we bought back more than 57 million shares, and the average share purchase price has been just over 60 SEK per share. When we're looking at the share price, which was trading around 100 SEK per share, that means that we've created in excess of $220 million in value from those share repurchase programs. Now we were above 20% dilution at the beginning of this year with the fifth share repurchase program. At the end of the first quarter, we now stand at only 16% dilution. That's quite impressive when we consider that we've grown our production fivefold since we started the company. We've multiplied reserves 16 x, materially extended the longevity of our reserve life by 19 years, added more than 1 billion barrels of contingent resources, quadrupled operating cash flow, and added in excess of $3 billion in net asset value, all with just 16% dilution and a plan to continue to buy back our stock in the years ahead. The reason that we're, you know, we really favor share buybacks is just because of the significant discount that we still see to where just the value of our 2P reserves are trading. If we, if we look at the year-end reserves value between an NPV 8 and an NPV 10, we're looking at a net asset value of between $4.2 and $4. $3.5 billion, and that represents at the 10% discount rate, 270 SEK per share. Trading at a 65% discount to our 2P reserves value, assuming a 10% discount rate. Not a single dollar of value attached to our in excess of 1 billion barrels of undeveloped contingent resources. Very much why we favor continued share buybacks whilst we materially grow the business through investing in our Blackrod project, we think that's a winning combination for our shareholders. Turning now to the assets, I'll start with our Blackrod phase one development project. IPC has 100% working interest in this project, just as a recap. Of course, we took the decision to sanction our phase one development back in February. The capital expenditure estimated to get to first oil is $850 million, and we expect first oil in late 2026. Phase one is targeting only the first 220 million barrels of an excess of 1.2 billion barrel resource pool. The phase one development should see production ramp up to a production plateau of 30,000 barrels per day. Of course, there will still be in excess of 1 billion barrels of future phases remaining to be developed. Very much still early days, of course, but in terms of scope and schedule and budget, very much on track. We are expecting to sign the major CPF contract early in the second quarter. That will give us a much higher degree of certainty on a large proportion of the fixed price element of this contract. You know, that will certainly reduce, I guess, or increase the certainty levels of that overall CapEx budget. If you just look at the call-out of the picture on the top right-hand side of the slide here. You can see that the road construction, the civil works is already underway. At the top of the picture, you can see there's a temporary bridge that we've got in place there, and that's to allow us to replace that bridge across the creek to put in place a much bigger capacity bridge. Good to see from the drone footage, the construction is very much underway on the Phase 1 of this project. As I say, in terms of schedule, civil works have started. The big ticket item is gonna be the facilities manufacture and construction, the CPF, and we do expect to conclude that contract during the second quarter. Still very much on track to have steam in the ground in late 2025 and first oil in late 2026. Now turning to the producing assets at Onion Lake Thermal. Very strong performance. If you look at the production plot on the bottom of this slide, you can see that it was a record production level for Onion Lake Thermal during the first quarter. The main activity in this field in 2023 is putting into production our Pad L, which you can see on the call-out on the map on the top right-hand side of this slide. That Pad L should be adding production capacity of in excess of 4,000 barrels per day. We do have some facility optimization ongoing, so we're looking at putting in additional tank storage at Blackrod and also looking to optimize the produced water handling. It will be the first time that we have more production capacity than our 14,000 barrels a day facility capacity. It's gonna be interesting to see if we can sustain productions at those facility capacity levels. That will lead us to start to look at the potential for upsizing the Onion Lake Thermal facility capacity in excess of 14,000 barrels per day over the next couple of years. Turning to the Suffield asset. Again, it's been a very strong performance on the oil and gas side during the first quarter. Starting with the gas on the bottom right-hand side of the slide. There was some moderate gas freeze-off, so slightly lower production decline than we'd forecast. We do expect to see production kind of bounce back in the second quarter as we get past the winter freeze-offs. I think the big news in the first quarter was the material increase in production with the acquisition of our Cor4 assets, which have actually been performing well ahead of expectation. I think in our guidance we said we expected production on average to be above 4,000 barrels per day. You can see that, you know, we're actually well in excess of 5,000 barrels per day. That's because some of the new wells that have been drilled, you know, came on stream pretty quickly and ramped up slightly faster than we had forecast and producing very much in line with expectations. I'll give some more color around that on this next slide. Yeah, here just as a recap, and this is slide showing the Cor4 acquisitions. That was the area, if you look on the map up on the top right-hand side of this slide, the areas highlighted in green, were all the properties that came with the Cor4 acquisition. The blue block was a new license that IPC signed up for in late 2022. Really the target for that land acquisition and the Cor4 acquisition was that Ellerslie play fairway. We really are off to a very encouraging start. In our budget, just as a recap for 2023, we had planned to drill in total six Ellerslie oil production wells. Five of those are expected to be in the newly acquired Cor4 area, one within the Ellerslie block that we acquired. Three of those wells on the Cor4 property have now been completed and put into production during the first quarter. If you look at the chart on the bottom left-hand side of this slide, you can see our sanction case and our actual production from those wells and, you know, some really good flush production early when we put those wells on stream. Now, with cleanup and stabilization, still producing in aggregate in excess of 600 barrels per day from those three wells. That's a really encouraging start because we picked up also in addition to that, in excess of 30 Ellerslie targets in that drilling play fairway, which means that we should be able to sustain production rates at similar levels to those that we have if we're drilling five to six wells per year over the next four to five years. Really good start and happy with the initial results from Cor4. Turning now to the other assets, firstly our Malaysian business. Just as a recap, you know, you go back to 2021, there's been multiple successes with our Bertam field. We first acquired the 25% interest back in April of 2021. We then moved forward with the A-15 drilling campaign and the pump upgrade campaign. That combined with very high facility uptime of 99% have meant that we've still been able to sustain rates at around 5,000 barrels per day to the company. What's been interesting is actually if you look at the production performance on the bottom right-hand side of this slide, over the last five months as we've been working on well optimization, we've seen really a kind of pullback on the watercut development from the main production wells. Mainly in the northeastern part of the field, which is some of the most recent wells that we've drilled. In excess of 60% of our production actually comes from the more recent infill drilling campaign. Just as an example, the A-15 well that we drilled and put into production in the first quarter of last year paid back in under five months. Really good returns from these investments. With that kind of water cut stabilizing, it's a little bit too early, but certainly the team in Malaysia are looking at whether there's upside potential, mainly in that northeastern part in the field. There's no new wells assumed in any of our forecasts or our reserve numbers. Perhaps if we start to see this trend continue, maybe there's some further upside potential in the northeastern part of the Bertam field. Turning to France now, you can see steady low decline there. 90% of our 2P reserves in France are developed and producing. We did have very stable high uptime from all the major producing assets. The production dip that you can see on the bottom right-hand side of this chart was really as a result of the political protests in France arising from the Macron proposed pension reforms. There were strikes that were causing disruption to the refinery that we sell our oil to in Le Havre. There was a temporary impact on our production. That's now been fully turned around, and we're back up to pre-protest levels. The big news, of course, is that we've completed during the first quarter the drilling of three wells on our Villeperdue West field. Those wells are now in cleanup phase and expected to ramp up through the second quarter. We also successfully completed the sidetrack of our Merisier 3-H well. That is now just expected to be put into production later in May. We should see in the second half of the second quarter the production contribution coming through from those French investments. Very much great job by the drilling team in France. All of those wells delivered in line with our budget expectations. My last slide before turning over to Christophe on sustainability and ESG. On the health and safety and environmental side, no material safety incidents or environmental incidents year to date. If we just look at the graph in the bottom left-hand side and our climate strategy to reduce our net emissions intensity by 50% through the end of 2025. You can see already last year we were down to 28 kg per BOE, on track to meet that 2025 target, and we have extended that by a further two years through to the end of 2027. That concludes the operations update. I'll pass across now to Christophe to walk you through the financial numbers. Christophe, over to you. Thank you very much, Mike. Good morning, everyone. Moving on to the next slide on the financial highlights. This quarter saw a record production at close to 53,000 barrels of oil equivalent per day. That's the highest ever performance from all of our IPC assets, which have been performing very, very well across the board. It's not just one asset overperforming, it's been a constant performance across our portfolio. Oil and gas realized prices were a bit lower than the previous quarters and $4 lower than our base case guidance. As Mike touched upon, if you looked at the netback we guided at our Capital Markets Day, if you applied the average price for oil and gas and applied those netbacks, you would then find exactly or very, very close to our operating cash flow and EBITDA for this quarter of $76 million. Operating costs stood at just in excess of $17 BOE, we keep the guidance for the full year at in between $17.5 and $18 BOE. We spent close to $55 million on CapEx, generated a free cash flow for the quarter of $16 million. Our net cash position from the end of last year to the end of March went from 175 down to $67 million. I'll come back to that in a few slide. That was mostly driven by the acquisition of Cor4, obviously, and the share buyback program, which is well advanced, more than 60%, as Mike mentioned. In terms of realized prices, if we look more into the details, we can see that the Brent averaged $81.2 per barrel over the first quarter, and the WTI priced $5 below that. The differential between the Brent and the WTI was in line with our initial guidance when we guided for our base case at our Capital Markets Day, an $85 Brent price and $80 for the WTI. The main difference in realized prices was the WCS, because the WTI WCS differentials to that $25 for the first quarter. It's important to remember how the WCS pricing works. It's the month's prior which defines the current month's pricing. Typically, the WCS prices in Q1 were driven by the actual prices of the WCS in December, January, and February. As we know, the December differentials were a bit wide, that impacted as well Q1. On the very positive, on the flip side, we can see much tighter differentials now. Actually, even if you look at the next quarter, the next few quarters until the end of this year and even into next year, you can see that the WTI WCS is below $15, actually even below $14 per barrel. We remain confident that we should be at or below the average of $20 we guided previously. Otherwise, in terms of realized prices in France and Malaysia, no big changes. We're still selling our crude in Malaysia at a very decent premium, $7 in the first quarter and in line with the WCS in Canada. In terms of realized gas prices, kind of the same story there. Realized prices at CAD 3.6 per Mcf for the first quarter. That was significantly lower than the previous few quarters from 2022. We had some very good hedges in place. We hedged 50% of our net gas production in this first quarter in excess of CAD 6 per Mcf. That generated very significant hedge revenues of $6 million. Operating cash flows and EBITDA, again, driven by the wider differential in this quarter was half of the first quarter from 2022, when the Brent in the first quarter of 2022 was in excess of 100 and differential much tighter. As I mentioned, operating costs, we feel comfortable to confirm the guidance for the full year in between $17.5 and $18 per BOE. Looking at the netbacks, that's interesting. I will focus on the operating cash flow and the EBITDA netback at $16 per BOE. That is actually $5 below our base case, and it's totally consistent with the fact that, again, this quarter, Brent and WTI were $4 below. WCS was $9 below our guidance, that's reflected into this $5. That's $5 reduction in operating cash flow and EBITDA netback. Again, it's the recent development are very positive, we expect to do much better in the current quarter and in the following quarters. Looking at the net cash, I briefly touched upon that. If you look at the acquisition of Cor4, that was for $62 million. There was $2.8 million of cash in the company, the net acquisition cost of $59. We spent close to $46 million on share buyback already. That explains most of the reduction in cash flows. You can see here the $54 million of development CapEx, the G&A, which remained very small and under control at below $1 per BOE, and a change in working capital, which includes, for instance, some finance costs because we paid some coupon in the first quarter, but only accrued for three months. There's a bit of lag there. Totally understandable. Otherwise, it's interesting to note it's a very small amount that the cash financial item is virtually zero, and that is explained by the fact that we can make between 5% and actually 5.5% on our cash deposits, whether it's in US dollar or Canadian dollar, and so that almost fully offsets our cost of debt. G&A and the financial items. I touched upon that. G&A, as I said, is well under control and remains below $1 per barrel for equivalent. Looking at the financial results, you can see here the results. It's important to note that the Cor4 acquisition in the IFRS numbers are only taken into account from the acquisition date, which was very early March, which is not the case for the production. The production includes is a pro forma, includes Cor4 from the beginning of the year, but the gross profit of $64 million and the net profit of $40 million here exclude the first two months of Cor4. On the balance sheet, you can see the increase in oil and gas properties, which was driven by the CapEx we spent on our base business and the acquisition cost of Cor4. In terms of the capital structure, there was no change, or no major change. We still have $300 million worth of bonds at 7.25% for the coupon with a maturity in February 2027. As some of you may have noticed, we announced earlier in March that we organized some fixed income bond investors meeting to test the market to support us to issue a $200 million TAP. We don't need the money. Obviously, the balance sheet is in very strong shape. Now, we wanted to see if we could raise more "cheap capital," and by cheap, I mean, given that we have very high deposit rates. When we approached the market, it was when the Silicon Valley Bank was going down, and so we decided to pull again 'cause we don't need more money. We still have the French loan, no change here, and it amortizes until 2026. The important point is we increased the revolver credit facility from CAD 75 million - CAD 150 million. Its maturity was as well extended from February 2024 - May 2025. This facility is fully committed, fully available, fully undrawn. In terms of hedging, we hedged, as we told you before, we hedged the transportation cost for Canadian oil production of 12,000 barrels a day between Hardisty and Houston. This hedge paid off at the beginning of the first quarter. Now we're roughly $2 outside the money. The gas hedging was very profitable. I mentioned more than $6 million revenues from the gas hedges in the first quarter, and those hedges remain in the money for the next while from April to October. We also made some had some positive contribution from our FX hedges because the dollar was extremely strong earlier when we bought forward some euros to pay for the French OpEx and some Canadian dollar to pay for the Canadian OpEx. Thank you very much. That concludes my part, and I will let Mike conclude. Yeah. Thank you very much, Christophe. Just to conclude in summary with the highlights from Q1 of 2023, another quarter of record production for the company, just under 53,000 BOE per day, driven by the very high uptime performance from the base assets and the good performance from the Cor4 acquisition. We now expect full-year production levels to be upwards towards that 50,000 BOE per day upper limit. OpEx very much in line with guidance, no change there. Likewise with CapEx, on track for our full year $365 million budget. As Christophe mentioned, the first quarter OCF numbers were very much in line with guidance and consensus. Of course, they were impacted largely by the wider differentials. We've seen a $10 improvement as we move into the second quarter, so that bodes well for the remainder of 2023 and no change to our free cash flow guidance. Very strong balance sheet, still in a net cash position, notwithstanding the fact that we acquired Cor4 for more than $60 million, we bought back more than $45 million worth of stock during the first quarter, and still in a gross cash position of $378 million. A very robust balance sheet indeed. On the sustainability side, the carbon reduction program is well on track, and we had no material safety or environmental incidents. Last but not least, 60% of the way through our proposed share repurchase scheme and 5.5 million shares repurchased, and we plan to conclude at the full 7%. A share repurchase program through the end of November 2023. That concludes the presentation part. We can now turn over to the operator, and we can take any questions that you might have. Thank you. If you would like to ask a question, please press star one on your telephone keypad. To withdraw your question, please press star two. Again, please press star one to ask a question. We'll take the first question from Teodor Sveen-Nilsen from SB1 Markets. Please go ahead. Good morning, Mike and Christophe. Thanks for taking my questions. A few questions from me. First, just on the gas prices in Canada, which obviously are lower now than in 2022. Does the lower gas prices impact then your gas strategy or the way you operate at all? Second question is on the $850 million CapEx for Blackrod. How much of that CapEx is contracted, and how much is exposed to potential cost inflation? A third question just on accounting. I noticed that the depreciation in first quarter was very low. As far as I understand you had changed some of the depreciation principles. Could you just take us through what actually has happened here and what we should expect going forward in terms of depreciation per barrel? Thank you. Okay. Thanks, Teodor, for the question. I'll take the first couple, and then Christophe can finish up on the depreciation question. On the gas, I mean, yeah, you're right. We've seen gas prices pull back. In terms of does it impact what we do with our Suffield gas property, I mean, the short answer is no. Even since we acquired those assets back in 2018, we haven't actually drilled any new gas wells. The one thing that we have been very successful at undertaking is ramping up our gas optimization program. We doubled activity levels, and we're talking about just swabbing the well stock that we have, and we've doubled that from 6,000 to around 12,000 wells per annum. Really the break, even if we look at those swabbing activities, it's below $1.20 per Mcf. Even with gas prices at the current market levels, we would very much still continue with that program. Of course, as Christophe showed in his presentation, 50% of our net gas production that's exposed to market prices has actually been hedged at in excess of CAD 4 per Mcf through the summer quarters. You know, we are in a very fortunate position that we should benefit from hedging gains certainly for the next two quarters, should we see the continued weakness in gas prices. On the... I think your second question was how much of the Blackrod capital expenditure is expected to be locked in under a fixed price contract and that's very much gonna be the EPC contract for the fabrication of the CPF and all of the production facilities. What we're expecting there, Teodor, is approximately up to around 50% of that work scope will be under a fixed price contract. As I mentioned in the report, once we've finalized that contract, and that should be finalized by the end of this quarter, then that's gonna give us obviously a much higher degree of confidence and certainty with respect to the overall CapEx budget. It's not something that we're worried about. I mean, the FEED studies were completed in December of last year. Costs were very much current, so, you know, we don't really expect there to be any material negative surprises in that respect. I think the third question was on the depletion, Christophe. Maybe you can take that one. Exactly. The depreciation, indeed, there was an adjustment this quarter. I guess the most important point is that it's a one-off. What happened is that we benefited from a program from the Alberta province in Canada, where they were funding some of the decommissioning activity. The way it was initially reflected on our balance sheet was a reduction in our provisions. We didn't want to hit the P&L. Apparently, the. We had to adjust based on our discussion with auditors. It looks a bit more aggressive because it's a non-cash item which increases on net profit. The important point again is that it's a, it's a one-off, and you can expect depreciation to be in line with more historical dollar per BOE going forward. Okay. Thank you. As a reminder, to ask a question, please press star one. We'll take the next question from Mark Wilson from Jefferies. Yeah. Thank you. Good morning, guys. Just, first point, just remind us on the profile of Blackrod CapEx from here across 2024 and 2025 versus the guidance you've given for this year, please. Yeah. Yeah. We haven't given detailed forward-looking guidance. If we, if we look at 2024, we're around. We're up to around $400 million for Blackrod. Then in 2025. About 100%. ... about 110 mark. That's the rough phasing. Okay, great. Thank you. The second point, two points here. Number one is the difference between Suffield and the newly acquired assets. Thank you for the color on Ellerslie-Fairway. You just mentioned in the previous answer regarding the fact you've always focused on swabbing and not drilling on the Suffield licenses existing, obviously now you are drilling on the new Cor4 assets, and they were drilling when you acquired them. Could you just talk to the reasons behind that, the drilling on those areas versus why you wouldn't drill on Suffield? That's the first question. The second is excellent slide on the share dilution over time versus acquisitions. I think you mentioned you've done four... five acquisitions since listing, and they've mainly been onshore Canada. You did get the 25% in Bertam. Could you just speak to the advantages as you see it for M&A in, into onshore Canada versus international? Thank you. Sure. Thanks, Mark. Let me take the first question in relation to investment in the Suffield asset. Just to be clear, I think Theodore's previous question was specifically related to, does it change our investment in the gas property? Of course, in Suffield, we produce around 16,000 BOEs-17,000 BOEs of gas, and around 7,000 barrels of oil. When I was saying we haven't drilled a single well on the Suffield property, it was very much in relation to just the gas wells that we have on the property. Of course, we have, since we acquired Suffield from Cenovus, drilled, you know, a large number of glauconitic infill wells in the Suffield property, and we also did a large enhanced oil recovery project on our N2N field. On slide 14, when you look at the oil production since IPC acquired that, you will actually see some oil production growth. That was, that was very much where all the investment has been focused on. The comments around no investment on Suffield are that all we've really done in the gas properties is gas optimization. That's just because we generate higher returns on capital and drilling oil wells as opposed to gas wells. The highest return activity is the gas optimization at Suffield. I think with the acquisition of Cor4, you know, when we look at the typical rates that you get from glau wells on the Suffield property, you're looking at average recoveries of, call it 60,000 barrels-80,000 barrels in production in that 60 barrels-80 barrels per day range. Whereas when you look at these new Ellerslie wells, you know, we're looking at rates, as we can see, of up to 200 barrels per day per well. Actually the investment in new drilling in Cor4, for example, if we assume $ 75 oil, you spend around $1.5 million and you get a 100% rate of return at $ 75 oil, and it pays back in less than a year. Those just get high graded and get moved to the front of the queue. It doesn't mean to say we won't be doing any new drilling in our other Suffield properties. It's just that these rank higher in our overall capital allocation. I think your second question was on onshore in Canada and the merits of acquisition onshore relative to the offshore. I mean, of course, if you look at the benefits of onshore acquisition, you typically acquire a much larger number of wells with each of those wells producing at a lower rate. Certainly from, if you like, from a portfolio perspective and certainty of forecasting and production forecast, if you've got a much larger number of wells producing at smaller rates, it just means that the, I would say the confidence you have in delivering your forecast is. Makes life a bit easier than if you're, for example, in the offshore environment and you've got a smaller number of concentrated wells that produce at higher rates. It, it certainly doesn't mean to say that we wouldn't look at other international assets. The big challenge for us, I guess, is when you, when you look at the value of our own assets trading at 65% discount to the 2P net asset value, then any new barrels that we bring into the company ultimately have to compete with that and share buybacks. That's not easy to do. I hope that answers your question there, Mark. No, it does. No, thank you. The oil versus gas at Suffield, that's great clarity. Got that. Okay, I'll hand it over. Thank you. There are currently no further questions in the queue. As a reminder, to ask a question, please press star one. There are no further questions in the queue. I'll hand the call back over to Mr. Nicholson for any closing remarks. Thanks, operator. We have a couple of questions online here. Perhaps the first one for Mike here. For the Cor4 acquisition at 2022 well appeared in Raymond James's top well list. Can you give a bit more detail on some of the economics of the wells such as IRR, payback time? Is IPCO planning to ramp up production in that area? Okay. Thanks, Rebecca. I'll just repeat what I said in the answer to Mark on the previous question. Typically you're looking at around a million and a half dollars in investment per well. If we take a mid-cycle price of around $75 per barrel Brent, we'll typically generate about 100% rate of return on that investment. The payback at $75 Brent is less than one year. Really attractive economics. You know, with an excess of 30 new locations in our 2P reserves, we've got the ability to drill certainly five wells, five to six wells per annum over the next five years. Great. Thanks. Question from James Hosie from Barclays. Perhaps first question for you, Mike: Should we expect group production to decline gradually Q- on- Q through the rest of 2023? Are there any assets where decline rates are set to be particularly steep? Yeah, I think I referred James to slide four in our presentation. You can see the high and the low guidance through the rest of 2023. It's relatively stable production through Q2 and Q3 then declining into Q4 from the base production levels. Of course that assumes a certain amount of downtime. We do have a shutdown in the third quarter on our Bertam field. No material declines from those levels. We do have the benefit of the new pad L coming into production in the second half at Onion Lake thermal property. Of course that's to a certain extent gonna be constrained by the 14,000 barrels a day facility capacity that we have there. Great. Thanks. Perhaps Christophe, can we assume that the current NCIB continues irrespective of commodity prices as it's funded from cash in hand? Or could you pause the NCIB if Brent is materially below the $85 threshold? Yeah. No. Our firm intention as I think it was pretty clearly stated is to continue the NCIB. Actually we mentioned that 60% of the whole program is complete. We actually continued already in April, so it's a bit over. It's between 60% and 65% that's already complete. Unless there would be an absolute dramatic fall in oil prices, we absolutely intend to continue and deliver 100% share buyback under the NCIB by the end of November. Okay. Thanks, Christophe. Mike, there's one further question for you, which is, any thoughts on future oil and gas prices in 2023/2024? The million dollar question. I mean, of course, there's obviously been a lot of concern in the market. We've seen rising interest rates to try and tame inflation levels, of course that has stoked some recessionary concerns and the impact that that's gonna have on oil demand. I guess if you look at the physical markets, the preemptive actions that OPEC+ have taken on when they stepped in to increase their production cuts unexpectedly sends a signal that they're not prepared to see sustained oil price weakness. I guess if you take a step back and look at the fact that the SPR releases are gonna stop or have stopped, and that we're only just back to around five-year average global inventory levels with most commentators forecasting us to move into a deficit position as early as the second quarter. It certainly feels like we're set up for much, much tighter physical markets between now and the end of 2023. I think the big tension is gonna be how does the recovery in China and India play against some of those recessionary concerns, and do we see physical markets getting much tighter? My guess is probably, but I guess we need to see how that recovery in China and how those concerns with respect to recessionary impact on demand plays out through the rest of the year. Okay. Thanks, Mike. I believe we have one more question that's just come through on the, on the telephone. Perhaps, operator, you could patch that through. Yeah. Thank you. We have a follow-up question from Mark Wilson from Jefferies. Please go ahead. Yeah. Thanks for the follow-up. Just in one of those answers, Mike, you referred to slide four where you show your guidance. You know, two points about that. Number one, looking at it just looks like, well, unless there is some decline somewhere, you know, you're in pretty good state for against your guidance. The real question I've got is you show the gas and the oil split in that chart, the full year 2020. You see the Q1 there with the, you know, the majority gas and then the oil WCS. Am I reading the full year correct? Where's all the gas going? Do you see what I mean in the shading? I does. I mean, typically our gas is around a third. The gas shading does look odd in the first quarter there. I need to have a look at. My suspicion there is, it looks like the blue and the red is actually inverted if you look at the previous year's. Okay ... production. I think that's just a mistake on the coloring on the legend Mark. Yeah. Sorry for that. Yes. Apologies there. Good, good pick. Good spot. Oh, your graphics are always so correct, so that was worth asking. Thank you. Yeah. No, I think if you look at the full year guidance, Mark, on the right, the blue- That makes sense now. Yeah. ... the blue corresponds to the oil WCS. I think it's just an inversion on the Q1 scaling on the part. Yeah, we missed that one, so good catch. Yeah. No, that makes sense. All right. Thank you. Understood. Okay. Thanks, Mark. There's no other questions by the internet or by phone. Mike, you wanna finish up? Yeah. Thank you very much, everyone, for tuning in. Look forward to catching up early in August to present our second quarter results. Thank you very much.