Welcome to the International Petroleum Corp. Q2 Report 2022. Throughout the call, all participants will be in listen-only mode, so there's no need to mute your own individual lines. Afterwards, there'll be a question and answer session. Just to remind you, this conference is being recorded. I'll now hand the floor to Mike Nicholson. Thank you very much, operator. A very good morning to everybody. Great to be here to present IPC's second quarter results. My name is Mike Nicholson. I'm the CEO. Also joining me this morning to present the financial numbers is Christophe Nerguerian, the CFO, and Rebecca Gordon, who's our VP of Corporate Planning and Investor Relations, will moderate the Q&A session at the end. You can ask questions for those joining on the conference call line, and you can also submit your questions online via the webcast. To start with the highlights from the second quarter, IPC is achieving new records on all fronts. If we start with our production numbers, we achieved a record quarterly production in Q2, averaging 49,400 barrels of oil equivalent per day. That's above the high-end guidance that we gave for the second quarter in our capital markets day forecast. I'll come back to it on the next slides, but we now expect our full year production to be towards the upper end of the previously guided 46,000-48,000 barrels of oil equivalent per day. Good quarter in terms of our OpEx delivery in line with guidance for the second quarter is $16.20 per BOE, and that means that we're retaining our full year forecast of $16-$17 per BOE. In terms of our organic growth activities, we have taken a decision to expand the capital expenditure program. We're gonna be increasing that from the previously guided $127 million up to now $170 million. We're gonna be targeting some additional drilling and optimization projects in Canada. In France, it's mainly acceleration. There's a small provision for inflation. I'll come back and give a bit more detail on those numbers. In terms of the cash flows with record high production and record high realized prices, it means we've achieved record operating cash flow for the second quarter of $193 million. Feeding through into our free cash flow numbers after the investment program, again, a record high quarterly free cash flow generation and by IPC of $152 million. That means because of the higher production that we're now increasing our full year free cash flow guidance to now between $395 million at the lower end of the range, assuming an average Brent price of $85 for the rest of the year, and at the higher end of the range, up to $530 million, assuming a $115 per barrel Brent for the rest of the year. In terms of the balance sheet, extremely strong. We finished the quarter in a net cash position with $14 million at June 30, and that's after completing the $100 million substantial issuer bid that was just completed at the end of June. In terms of our hedging, Christophe will go into a bit more detail in his presentation. We've got 60% of our Canadian differential, the WCS to WTI differential hedged at an average of $13 per barrel. And that's put us in a good position because we have seen the differential widen slightly with higher North American gas prices and heavy barrels being released by the U.S. government to put a cap on oil prices. In terms of the other hedges, no changes from the first quarter. 35% of our gas is hedged through the third quarter at $3.60 per Mcf, and we don't have any hedging on any of our Brent or WTI benchmarks. It was an important quarter on the ESG front. We didn't have any material incident, safety or environmental to report, but the teams put a lot of work into publishing our third sustainability report. One of the core elements of that report is that we're on track to achieving our 50% net emissions reduction target by 2025. In terms of our shareholder returns framework, been very active on the share repurchase front. The substantial issuer bid was completed, $100 million of shares repurchased. 8.3 million shares in total were canceled. The NCIB has been well progressed with, again, 8.3 million shares repurchased and canceled by the end of the second quarter. If we dive into a bit more details now on the production for the second quarter and for the full year outlook. As I mentioned in the highlights, our second quarter production was a record quarterly high of 49,400 barrels of oil equivalent per day. That was possible as a result of achieving very high uptime in all of our operating regions. We're also starting to see some of the benefit of the recent development activity that we sanctioned at the beginning of this year. In Canada, a strong production performance across all assets, and I'll come back to it, but we've set new production records at Onion Lake Thermal. Internationally, France has been stable and we've started to see, if you look at the April numbers, the full impact of our Malaysian drilling program, the A-15 and the pump up sizing project, we saw the full benefit during the second quarter. If we look at the full year production guidance now in our capital markets day, we guided that we expected to be somewhere between 46,000 and 48,000 BOE per day for the full year. You can see from the chart that both in the first quarter and in the second quarter, we've been above the high end guidance. That means that we feel pretty confident to state that we now expect our full year production numbers to be towards the high end of that guidance range of 48,000 barrels of oil equivalent per day. In terms of the operating cash flow numbers, you can see that it's been an exceptional first half. In total, we've generated just under $340 million of operating cash flow. Actually pretty close to the full year numbers that we guided, assuming a $70 per barrel oil price. Because of the strong first half, we're now looking to re-guide full year OCF at between $595 million, assuming $85 per barrel for the rest of the year, and a high side case, assuming a $115 per barrel Brent of $730 million of operating cash flow. As a result of the good operating delivery and the high realized price environment, we've decided to take the opportunity to advance some of our investment projects. We're increasing the capital expenditure budget to $170 million, up from the original guidance of $127 million. If you look at the chart on the top right-hand side of this slide, you can see that we're in our Villeperdue West project, which is our project in France. That's about $10 million. That's predominantly related to actually starting that drilling campaign earlier in the fourth quarter. Most of that should be complete through the fourth quarter. That's a $10 million acceleration. In France, we've looked to add some additional activity, $23 million worth of additional investment, three wells added at Ferguson, six conventional oil wells added, and also some further oil and gas optimization projects. We've also put in place a provision of $10 million for some inflationary pressures that we've seen across the business. When you put together that very strong operating cash flow, the increased capital expenditure budget, we're still in an exceptionally strong free cash flow position. The first half alone, we've generated close to $250 million, in excess of $150 million in the second quarter alone, a record high for IPC. Notwithstanding the fact that we've taken the opportunity to increase our CapEx and accelerate some of our growth projects, that still gives us some extremely attractive free cash flow numbers projected for the full year. Now at the low end, just below $400 million of free cash flow, assuming an $85 per barrel Brent price, and that represents a 23% free cash flow yield. At the higher end, assuming a $115 Brent for the rest of this year, $530 million of free cash flow or a yield of in excess of 31%. I think if you benchmark those free cash flow yields against the rest of the industry, that sits at the very top. What are we doing with all of the free cash flow that we've been generating? Certainly in the second quarter, it was a major quarter of returning value to our shareholders under the capital allocation framework that we announced at the beginning of this year. If we start with the normal course issuer bid, we're well on track to completing the NCIB. 8.3 million shares were bought back and canceled by the end of July. The total cost of the NCIB so far has been $65 million, and we've repurchased those 8.3 million shares at an average of 80 cents a share. More materially and through June, we successfully completed the substantial issuer bid that returned to shareholders $100 million through a Dutch auction. It was the first time that we've used this shareholder distribution tool. We're very pleased to complete that. The average purchase price under the SIB was 15.5 CAD per share, and the number of shares canceled under that program was 8.3 million shares. I think when we look at that capital allocation framework that we announced at the beginning of this year, we're certainly well on track to returning the commitment that we made with $165 million already returned to our shareholders through the end of July 2022. I think it's worth just taking a moment to step back and, you know, look at the multiple share repurchase programs that IPC has initiated since we launched back in 2017. We started life with just under 114 million shares outstanding, and the only dilution that we've had was the corporate acquisition of BlackPearl Resources back in December 2018, when we issued just under 76 million shares. If we look back at the share repurchase programs, we had the buyback in June 2017, the two following share buybacks in 2019, 2020 and 2021, 2022, and then most recently, the SIB in 2022 in July. We've reduced the share count down to 139 million shares. From the inception of IPC, we've actually only seen 22% dilution. If you cast your eyes to the right of this slide, you can see that we've had some phenomenal growth across all of the business metrics. We've multiplied our production fivefold. We've increased our 2P reserves nine times. We've extended the longevity of our reserve life by eight years, and we've added 1.4 billion barrels of contingent resources. Cash flow generation has quadrupled, and we've added in excess of $1.8 billion of net asset value, and that's all been done with just 22% dilution. A huge amount of value returned to our shareholders. At the current share price, that's about $350 million it would cost us to buy those back at today's share price. The cash flow numbers are industry-leading, exceptionally strong. I think if you also look at IPC through the value lens, still a very, very attractive investment proposition. If we look at the net asset value of our company, and these are the numbers calculated at January 1, this year. It uses a reserve, a third-party reserve auditor's price decks from that period, and it's a pretty conservative price forecast. The Brent price forecast for 2022 is $75 per barrel Brent, and that drops to $70 per barrel by 2024 and then escalates at 2% per annum thereafter. Even on that relatively conservative long-term oil price outlook, the company, as of the market close yesterday, is trading at a close to 30% discount to that 2P reserves value on that conservative pricing outlook. It assumes that we don't buy another barrel. It assumes that we don't develop a single barrel of our 1.4 billion barrels of contingent resources. Again, an extremely attractive value proposition. If we jump now just into a little bit more detail in some of the highlights on the asset activity through the second quarter. In Suffield, you can see that we've had nice stable performance through the second quarter with the historic declines being offset by the development and optimization activity that we've been undertaking. Given the success that we'd seen with our end-to-end alkaline surfactant polymer project, we've decided to expand that. That was in the original 2022 capital budget. We're planning four new wells to be drilled in the third quarter of this year. At Suffield, with the capital additions, we're planning to add two new production wells and two disposal wells. One of the reason we want to add those production wells is this really comes from the contingent resource inventory. If those turn out to be successful, we've got a lot more candidates to follow up on in the years ahead. On the Suffield gas side, Christophe will go into this in more detail in his presentation. We saw record high Canadian gas prices. If we look at our production plot on the right-hand side of this slide, you can see that the low-cost optimization program that we continue to execute is managing to offset those 10% natural declines that we saw in the pre-IPC era. We've ramped up that. You can see the swabbing has doubled from under 6,000 swabs per year back in 2017 to now in excess of 12,000 swabs per annum. Given the strong gas pricing environment, we've decided to increase our capital expenditure and to execute 110 gas well recompletions. Turning now to our Onion Lake thermal project. As I mentioned in the highlights, if you look at the production chart on the bottom of the slide, you can see that during the second quarter, we achieved a new production record averaging in excess of 13,000 barrels a day through the month of April. The 22 drilling program is well underway. Two new infill wells have been drilled, and we currently expect production contribution from those wells online in early third quarter. The drilling at L pad is on track, and we plan to start to see the benefits of that production coming on stream in 2023. We've taken the opportunity to sanction some additional facilities investment as well as part of the capital increase that we've announced this morning. Following the acquisition of Granite back in late 2019. We started the 2022 development program. It's ongoing as we speak. The original capital budget for 2022 saw us looking to drill 16 horizontal wells. Again, with the higher oil price environment and having a hot rig on location, we've decided to add an additional three wells to the 2022 program. We're also currently planning and preparing to upgrade the gas injection capacity as we speak. Out of the total new program of 16 wells, 10 new wells have been drilled, six wells are online at the end of the second quarter. If you cast your eyes down to the production chart on the bottom of this slide, you can see that we've already lifted our production from around 1,000 barrels a day prior to the drilling campaign to now up to 1,500 barrels per day. There's still a lot more wells to be brought online. Extremely happy with the early results that we're seeing from that drilling campaign. Then not too much to add on our Blackrod project. We talked about this in our Capital Markets Day presentation in our first quarter results. The main focus right now of our team in Canada is to progress and to complete the FEED studies by the fourth quarter of this year. Just as a reminder, those FEED studies are looking at just the first phase of our Blackrod project. That's the first 217 million barrels of the 1.3 billion barrels of resources that we have in Blackrod. We're looking at building up to 20 to expanding to 30,000 barrels a day of oil production from that phase one development project. You can see the numbers with a capital expenditure of $540 million projected to first oil. The breakevens are extremely attractive at around $50 per barrel WTI. It's gonna be interesting to see the results later this year of those ongoing FEED studies. Turning to Malaysia now. Very strong quarter. High facility uptime with close to 100% and a strong base well performance. With the A-15 sidetrack program and the three ESP upgrades that were completed during the first quarter, we're now seeing the benefits of having those wells online. Current production, again, if you cast your eyes down to the chart on the bottom of this slide, you can see that we've managed to ramp production back up to above 6,000 barrels per day. That's been extremely beneficial to IPC because what we're seeing is an extremely tight physical market for these Bertam barrels. The July lifting that we've just recently completed, and the September cargo that we've just recently sold has seen realized prices in excess of Brent of between $10 and $20 per barrel. Extremely good timing to be ramping up that Bertam oil project. Turning to France now. Again, if you look at the production chart on the bottom of this slide, you can see we've had good steady production from all the major producing fields. The VGR 113 well, which is our biggest producer in France on the bottom right-hand side of this slide, you can see still significantly outperforming the pre-drill expectations. The original water breakthrough was expected in the third quarter of 2020, and we still haven't seen the water breakthrough through the second quarter of 2022. That's certainly a nice problem to have. When we look at our activity plans in France, as I mentioned in the highlights, we're accelerating the three-well program in Villeperdue West. The majority of that project will be coming into the fourth quarter, and we'll see the benefits of that production uplift as we move into early 2023. Very exciting to be getting started to drill again in our French business. My final slide, last but certainly not least on the sustainability and ESG slide. I mentioned it was, you know, a very active quarter for the company. We had no material health, safety, environmental incidents in the first half. Again, if you look at the chart on the bottom left-hand side of this slide, you can see that we're really in good shape to achieve that 50% net emissions intensity reduction by 2025. In 2021, we reduced our net emissions intensity from 33 kilograms per BOE down to 28 kilograms per BOE. You can see we're well on track to reaching that 2025 target of 20 kilograms per BOE. In parallel with the release this morning, you'll see on our website that we've also launched our third annual sustainability report. As with last year, the 2022 report is fully compliant with the Global Reporting Initiative standards. What's new for this year is we've aligned our reporting with the Task Force on Climate-related Financial Disclosures, the so-called TCFD. Again, you know, every year, we look to adopt best practice to improve our non-financial disclosure reporting, and I would really encourage everyone to take a good look at the report. There are some tremendous projects that are being undertaken by the whole IPC team. That concludes my part of the presentation. I'll pass across to Christophe now, the CFO, and he will take you through the financial numbers in more detail. Christophe- Yep. Over to you. Thank you very much, Mike. Yeah, indeed, a real pleasure to be talking and walking you through those exceptional set of numbers. Indeed, a record quarter wherever you look. But first of all, it's a tribute to all the IPC teams because the great results this quarter is as much a result of the great operational performance as it is the result of very high realized oil and gas prices. With a production of in excess of 49,000 barrels of oil equivalent per day in the second quarter this year, we were just above the high end of the production guidance range. We're comfortable to state that for the annual guidance, we should sit at the high end of that range for the full year. Operating cash flow and EBITDA were in excess of $190 million for the second quarter. That translates into a very healthy free cash flow in excess of $150 million for this quarter and just shy of $250 million for the first six months this year. It's also worth mentioning that on the back of this very strong operational and financial performance, IPC is in a net cash position at the end of June. That's after spending $100 million of share repurchase as part of the NCIB program, which we announced and completed by the end of the quarter. If you look at the realized oil prices, this slide is a bit busy, but I think what really matters is to reflect on how strong the market has been in the first six months of 2022, and especially, of course, during the second quarter. The WTI, WCS differential remained very tight, below $14 per barrel. Even if the prospect for the second half of this year is higher towards $20, but we're hedged around 60%. Yeah, I'll come back to that. Maybe more importantly, I think it's important to realize that the physical market, the oil physical market, is very tight. That is evidenced by the year to date by a $3 premium of the Dated Brent compared to the ICE, to the financial Brent, if you wish. That is a very clear indication that the physical markets are tight. We see that as well, Mike mentioned, in Malaysia, we used to enjoy a premium when we were selling our Brent or cargoes in Malaysia. We had premiums of single digits. Now for Q3, we've been selling already two cargoes between $10-$20 premium above Dated Brent. Indeed, a very tight market. In Canada, just a last remark on this slide, we are now selling our Suffield and Onion Lake thermal crude oil very close to parity with the WCS. Indeed, with improved logistics at Onion Lake, where we can ship all of our crude in pipe, we are blending now 100% of our production. We're really selling on parity with WCS. Maybe what was even more striking, and that's really where you see the most influence maybe from the war in Ukraine is on gas prices. Obviously, the main impact was felt in Europe, but the LNG market sort of interconnects all of the world gas markets. There was a very significant knock-on effect on the North American gas prices. We're sitting on an AECO base, which is the benchmark for the Alberta gas. That follows quite closely the Henry Hub, which is the U.S. benchmark. You can see that the market was red hot in very high demand for gas, including from North America, explaining why the prices jumped to between CAD 7 and 8 per Mcf. We realized close to CAD 8 per Mcf actually during the second quarter. Even if you look at the first six months, the realized prices were CAD 6.4 per Mcf, and that is twice as much as our initial budget. We were not particularly conservative when we set our budget, but there's been a profound shift in the gas market. Currently, the gas prices are still between CAD 7-8 per Mcf. When we look at operating cash flows and EBITDA, we've generated a staggering operating cash flow and EBITDA for the first six months in excess of $335 million. Everything being equal, we're well on track to generate more than twice that over the full year. It's also quite impressive when you reflect on what was the situation of IPC last year. Operating cash flow generation is more than twice as much what was achieved over the same period last year. Now if we turn to the operating costs, we can see a bit of inflation. Really the way that inflation translates into slightly increasing our OpEx per barrel is through high gas, electricity, and chemical costs. Now, the majority of that inflation or cost increase really is coming from the gas we purchase to run our Onion Lake thermal operations. Now, you have to understand that even if it's those are not the same molecules of gas, we are producing three times more gas than we are consuming for Onion Lake operations. Even if it's obviously a negative on the OpEx front, it's a three times disproportionate positive on the revenue. Net-net higher gas prices, whereas they will translate into higher cost per barrel, are net positive to the bottom line of IPC. On the back of Q1 where gas prices increased already, we had re-guided our operating cost per barrel from $15.2 to a range of $16-$17 for the full year. We maintain that range. If you look on the slide here, where we're giving more granularity on the operating cost per barrel every quarter, you can see that we're trending towards the high end of that range. But again, higher cost, you know, in our case translating to actually higher net back because of the disproportionate positive effect on the revenue side. In terms of net back, I think we have to put this slide in perspective with what we guided the market at our capital markets day earlier on this year in February. If you look for the first six months this year, we've generated operating cash flows and EBITDA in excess of $39 per barrel of oil equivalent. That compares to $21 we guided at $70 Brent price at our capital markets day, or $36 at $100. Even compared and that's quite normal. You'd expect that of the performance given gas prices and an average Brent price of 108 compared to the $100 case. We are for the first six months, $18 above in terms of net back compared to the $70 case and $3 above a $100 case. Very strong performance. Looking at the cash flows for the first six months, you can see that, with the massive $338 million of operating cash flow, we fully funded obviously all of our $70 million worth of development CapEx, exploration and evaluation and G&A and financial costs. The bulk of the operating cash flow went to fund our share repurchase plan through the NCIB on the one hand side and the substantial issuer bid of $100 million, which was announced and closed at the end of June. You can see here that we're showing a total of $121 million spent on share repurchase. Between December last year and July this year, we spent another $44 million. Indeed, as Mike mentioned before, so far we've returned $165 million of capital to shareholders. That slide evidence the fact that we're in a net cash position with $14 million of cash after funding $100 million of SIB. Looking at the G&A and financial items, not much to report here, just to mention that obviously since we issued bonds and refinanced with the bonds procedure for reserves-based lending facilities in Canada and internationally, the net interest expense you have here for the second quarter reflect the accrued bonds coupon, and that will be the case on an ongoing basis. G&A remain under control and stand at $0.9 per BOE at the company level for the first six months. Looking at the net from the revenue down to the net profit, I mean IPC generated an impressive $580, close to $580 million dollars of revenues over the first six months. For the same period, IPC posted its highest ever net profit for six months at $186 million. On the balance sheet, maybe just worth mentioning that the current assets are significantly higher at the end of June than what they were at the end of last year, $631 million versus $151 million. That's mostly the result of all the cash we were sitting on, $328 million worth of cash at the end of June, and $100 million which were dedicated and actually already paid to buy back our shares. You can see as well as the main change on the liability side from the end of last year, the $300 million worth of bonds. Our capital structure has not evolved since we issued the bonds on February 1. We have a five-year non-call three bonds priced at 7.25% for the coupon. We were able to hit the market at the very beginning of this year, and that was a very favorable decision, obviously, compared to where base rates have moved since then. We still benefited at the time from very favorable market conditions. That was complemented by CAD 35 million revolving line from our Canadian banks, which are still supporting us very fondly. That line is purely a liquidity line, which is not used at all. In terms of hedging, we were able to secure roughly 60% of our Canadian oil production hedged for the WTI, WCS differential. Rightly so, we felt at the time that there was a bit more downside than upside, and the downside unexpectedly came from some release from the strategic reserves in the USA announced by the president. I believe it was the end of Q1. They've released roughly 1 million barrels per day from the U.S. strategic reserves. The first batch of release was more heavy oil, hence competing with some Canadian barrels. That has pushed the WTI, WCS differential as we speak higher, closer to -18 or -20. We're hopeful that at the latest by next summer in 2023 when the doubling of the Trans Mountain pipeline capacity comes online, the differential will tighten again. In terms of gas hedging, we obviously didn't expect what happened in Ukraine, and so we had some, what we felt was some very good level hedged for roughly a third of our gas production in Canada. Fortunately, those gas hedges will mature. I mean, we only have hedges until the end of September, and so we'll be fully exposed to the current gas price market in Q4 and already two-thirds in Q3. Just wanted to reiterate that, we have no oil hedges on Brent or WTI, so we are fully exposed to the very strong oil prices currently seen in the market. We have no specific covenants from banks or financiers to hedge anything, so it's really down to us, and we wanna remain fully exposed to the oil and gas prices as it stands. Thank you very much. Okay. Thank you very much, Christophe. Very set of impressive numbers. Just to conclude and recap on the highlights for the second quarter of 2022, we've seen records achieved across the board for IPC. Our production has been over 49,000 barrels a day, and we expect full year production now to be towards the upper end of the guidance limit of 48,000. No change to the most recent OpEx guidance of $16-$17 per barrel. We're adding to the capital budget that's been increased from $127 million up to $170 million to benefit from some, you know, high-value, quick payback, short cycle investments in our Canadian business and some acceleration in France. As Christophe mentioned in his presentation, it's been a phenomenal quarter for record cash flow generation with the second quarter OCF just under $200 million, and free cash flow for the second quarter just above $150 million. Given the very solid first half performance, we're increasing our full year guidance to just below $400 million, assuming $85 Brent, to now $530 million at the high side if we assume $115 per barrel Brent. The balance sheet's in great shape, notwithstanding the major shareholder returns through the second quarter, and we find ourself in a net cash position of $14 million at the end of June. The sharp focus on sustainability continues with our third sustainability report published this morning alongside our second quarter results, well on track to reducing our net carbon intensity emissions by 50% through 2025. No material incidents in the first half, and we've increased our reporting standards to align with the TCFD requirements. Last but not least, we've made great strides to progress our shareholder returns under our capital returns framework with the SIB completed, returning $100 million of value to remaining shareholders and the NCIB program ongoing. If we jump to the next slide, that means we find the company in as good a position as we've ever been to continue to create stakeholder value. If all we do is monetize the five-year business plan that we set out back in February of this year from just our 270 million barrels of 2P reserves, if we don't develop a single new barrel of contingent resources, and we've got 1.4 billion barrels of contingent resources, or we don't do any additional M&A, you know, at prices of $95 a barrel, well below today's oil price, you know, we're looking at generating significant free cash flow over that five-year period of $1.8 billion or an annual average free cash flow yield of 21% per annum. Of course, that puts the company in a fantastic position to keep returning value to shareholders. As we speak, there's no debt to be reduced, so, you know, we're looking at continued share buybacks and potentially dividends. M&A is still one of our core strategic pillars. It's the foundation of the value that IPC has created since we started back in 2017, and we still remain very much opportunistic with respect to further M&A activity. Of course, organic growth, our biggest single project is Blackrod. We're undertaking FEED studies, and that should be concluded by the fourth quarter of this year. We've allocated some of the capital as part of our second quarter budget expansion to start to accelerate the maturation of some of the contingent resources that we have within our Canadian business. That concludes the presentation. We can pass back now to Rebecca and see if there's any questions from the conference call or if anyone's submitted any questions online. Yeah. We'll start with telephone questions. Operator, do you have anyone on the line? Thank you. Yeah, we have three questions currently in the queue. The first is Teodor Sveen-Nilsen of SB1 Markets. Please go ahead. Your line is open. Good morning, Mike, Christophe, and Rebecca. Thanks for taking my questions, and congrats on a strong set of numbers. My first question is just on your net cash position. I guess you don't plan to run the company net cash position going forward. Mike, you explained at least three uses of cash: takeovers, M&A, organic growth. I just wonder right now the opportunities you are seeing, which of those three uses of cash should we expect you to accelerate going forward? My second question is on your increased CapEx for 2022. Assume that will positively impact production outlook for 2023. Just wonder whether you can indicate how much that incremental CapEx increase could impact 2023 production. My final question, if I may, on slide six, you show the usual waterfall of the reason for the CapEx increase, so which you show $10 million cost inflation. I guess that's pretty expected, but I just wonder what kind of items do you see the largest cost increases for right now? Thanks. Yeah, no. Thanks, Teodor, for the questions. On the first one, on the cash position and the strategic pillars, I mean, obviously, if you look at the numbers, we're certainly well on track to delivering against the shareholder returns framework. I think if you look at the top end of the guidance so far, we've returned about $165 million to shareholders so far this year. What we've said is we see oil prices averaging $115 at the high end of our guidance for the rest of this year. The total shareholder returns is $186 million. You know, you've got probably more than $20 million could still be returned to shareholders at the upper end of that guidance range. The other two pillars in terms of M&A and contingent resource, we have allocated some capital in the second half as part of the CapEx budget increase. You know, they are targeting some of the contingent resource locations. I think the biggest single likely change in the years ahead would be, provided we get encouraging results from the Blackrod feed studies, to maturing that phase one project, which would see production adds initially of 20,000 barrels a day, and then within a couple of years post first oil in 2026, ramping to 30,000 barrels a day. It's obviously a big project. We guided at the beginning of the year, $540 million of CapEx to first oil. Let's see the results of the feed studies. You know, certainly when you look at the strength of the balance sheet and the amount of free cash flow that we're generating, you know, that becomes something that would be easily digestible for a company like IPC with that financial strength. M&A, I mean, we're still as active as we've ever been on the M&A front. It obviously gets more difficult as you know, as we're in a higher oil price environment. I think, you know, our approach as we mentioned at the beginning of this year when we went to access the debt capital markets is we felt that if we could, you know, proactively raise $300 million and get ourselves on the front foot, you know, when we're having discussions with the majors, with assets that kind of trade in the $500 million-$1 billion category, you know, certainly less competition for those kinds of assets. I think we're in as good a position as we can be with respect to still pursuing M&A opportunities. As you know, we look at about 20 opportunities a year, and we've so far averaged one acquisition per year. Still a focus on all three of the strategic pillars. On the second question, which was does any of the changes to the CapEx budget impact the 2023 production numbers? We haven't given any formal guidance for 2023 as we speak. My sense, we've obviously given the long-term guidance of 47,000 barrels per day. With those activity adds most likely affecting exit rate production, you know, I certainly would expect that we would be able to perhaps do slightly better than the 47,000. I'll reserve judgment until we finalize, you know, all of our budget setting through the year end and when we announce our capital program for 2023, 'cause obviously that's gonna have an impact on also on our 2023 production numbers. Certainly it's gonna give us some nice tailwinds as we head into 2023. Then the third question on cost inflation, the $10 million that we mentioned. I mean, it's really, it's more in relation to the facilities and drilling costs that we've got on the program this year. If you take the $10 million across the $170 million revised program that we now have, that's really only 6%, and that's quite a bit better than what we're seeing across average across the rest of the industry. It's a combination of factors, Theodore. It's higher rig rates, it's higher materials costs, and we're also seeing higher fuel costs for the service companies that are running their equipment. I would say those are probably the three biggest single contributors to the $10 million increase. Okay. Thank you. Thank you. Our next question comes from the line of Mark Wilson at Jefferies. Please go ahead. Your line is open. Good morning, Joel, IPC. Breathtaking set of results again, but it's obviously the longer term delivery that's got you to this point. In terms of guidance and outlook, I think it's just a case of investors can learn to trust management decisions, and you've been very clear on Blackrod and everything like that. The only questions I'd like to ask is firstly on just you clearly said you're not laying in any more hedges, you're fully exposed to gas. If you wanted to, what is actually the market like for hedges, just out of interest, are they actually able to be laid on 2023 for oil and gas? Would be the first point. Then the second point, the emissions reduction shows about 30% down across 2019 to 2021 on a unit basis. Could you just give us the stepping stones in that? I'm sure it's in the sustainability report, but if I could just ask what is underlying reduction and how much is offsets? Thank you. You wanna take the first one? Yep. Christophe? Well, maybe I'll take the second one first, Mark, on the emissions reduction intensity. Yeah, I mean, if we look at the original baseline that we saw back in 2019, there were 40 kilograms per BOE. I would say you know, the majority of the reduction is down to the carbon offsetting program. We have implemented a couple of projects earlier towards 2019. For example, in our Bertam facilities, we invested in dual fuel power generation facilities to reduce the flaring of the flash gas that comes off our separators on the Bertam FPSO. We'd invested in heat recovery units at our Onion Lake thermal expansion project. Actually one of the elements of the optimization project is to add some additional heat exchangers to optimize our facilities. Clearly we're not gonna see the benefits of those investments until next year. I would say the lion's share of the decrease has been through the carbon offsetting programs that we talked about a couple of years ago. Christophe, do you wanna hedge? Yeah. Look, I'm looking at the quotes we had from yesterday. Between now and the end of the year, we would be able to hedge AECO between CAD 5.50-CAD 6.25 per gigajoule, so times 1.05, between 5.5-6.5 CAD per MCF. This is for the AECO. As you know, we're selling our crude very close to the WCS, literally on the border between Saskatchewan and Alberta, so closer to the end user's market. As we speak, we have a positive premium on top of AECO of CAD 1.5 per MCF. This is more from the spot market, but we could hedge between $5.50 and $6.50 AECO and still expect $0.2550 on top of that for realized price. Fairly healthy and, yeah, significantly higher, twice as much as our previous budget. Oil? On oil, it's you still have a very significant. We are not against hedging philosophically. We're just shocked with the. As I was mentioning, there's a very tight physical market. You're losing almost $10 between now and the end of this year. The market is in steep backwardation, and you lose another $10 per barrel between January and December 2023. Hedging today would mean to accept up to $15 or $20 discount to where oil prices are today, which we're not willing to accept just right now. Okay. Yeah. Just to finish, maybe hedging decisions are made also. It's not just an abstract discussion, it's linked to our capital commitments, whether it's debt repayment, CapEx or capital distribution. Being in a net cash position today puts us in a very comfortable place, and we don't have to put some hedges in place. That's a very good point as well, Christophe. No, thank you for that, excellent set of results. Looking forward to those FEED study at the end in Q4. Thank you very much. Thanks, Mark. Thank you. We have one further question in the queue at this time. It's from the line of Tom Erik Kristiansen of Pareto. Please go ahead. Your line is open. Thank you for taking my question, Mike, Christophe and Rebecca. Of course, congrats on the good results and on operational delivery as well. A couple of points I just wanted to get a bit more details on is the activity level. You are among the companies that are moving faster now to add activity to increase production basically due to the current oil price environment, which is positive, I think. How much more can you do in the portfolio if oil stays at this level, say throughout next year? Is there a lot of different projects that you can sanction that you had previously not put into your plans or to be profiles that will come on? Could you say anything about what you think is the IRR on the investments you're now taking on the additional CapEx you're putting to work here? How is the return looking on that in the current environment? That's number one. On the buyback and capital distributions, would there be kind of obviously with the current framework you have and current oil prices, you will build a cash position that is increasing every quarter basically going forward. Is that kind of your prudence, you think, due to Blackrod potential M&A, or is there kind of a limit to how much net cash you will have on the balance sheet before you actually accelerate the buyback program, for instance, beyond kind of what I think guided in terms of distribution policy this far? Thank you. Okay. Yeah. Thanks, Tom Erik. Yeah, on your first question about 2023 and what activity levels can we do next year. I mean, if you look at, for example, I mentioned the wells that we're gonna be drilling at the Suffield oil property, those are in a formation where we don't have too many wellbores. It's called the Detrital Horizon, which is slightly deeper than the base Mannville formation where most of our production wells have been drilled. One of the reasons that we want to test that formation is, you know, we've got, you know, a quite a deep inventory of follow-up candidates if we're successful in achieving you know, good production from those wells. So there's certainly some contingent activity that could follow if we're successful with those. Likewise, in our Onion Lake, which is also included in the 6 wells that we're adding as part of our conventional oil drilling. You know, we're looking at testing some new drilling techniques there as well. Those sit in our contingent resources. Likewise, if that's successful, you know, there's a lot of wells that we can accelerate or mature from our contingent resource base into our reserves if we get encouraging results from that program. There's clearly a lot of discretion that we have. I think as we look forward on Malaysia, we'll see obviously we don't have any additional drilling thus far for next year. I think we wanna see the continued results of A-15. My sense is just directionally that we'll see the kind of investment levels in France and Malaysia drop off and, you know, we're looking for the discretionary projects in Canada to step up. Of course, the big one is Blackrod. If we decide to move forward with that would be obviously a big move of contingent resources potentially into reserves next year. As Christophe mentioned in his presentation, I think the good position that we find ourselves in is because we pretty much operate all of our assets 100%. We've got huge discretion on the pace of activity and the size of capital budget that we set, you know, year on year. In terms of the returns, I mean, there's quite a lot of wells. I haven't got the individual rates of return. You know, if you're looking at the kind of Brent equivalent breakevens for these infill drills, infill wells that we're drilling on the conventional properties and at Ferguson, you're looking at a Brent equivalent breakeven of between $40-$50 per barrel. Clearly when prices are triple digit, it makes huge sense to go forward with those. If you look at the kind of paybacks, assuming even much lower oil prices of $75 per barrel, you're getting payback between one and 1.5 years on that activity. Again, obviously at current oil prices, we're getting very fast returns on those additional investments. That's why we took the decision this morning to accelerate some of those projects. On the capital allocation framework, as we mentioned, you know, we've made good progress on the share buybacks. I think when you put in context, you know, at $95, we're gonna be generating $1.8 billion over our five-year business plan. The fact is we can return value to shareholders, we can still continue to do material M&A, and we can still develop Blackrod Phase 1. The short answer is we can do all three. Okay, thank you. All right. Thanks, Tom Erik. Currently, we have no further questions on the phone lines at this time. Okay. Thanks, operator. We're a little bit over, but just two very quick questions from the web. Christophe, if I can direct this one to you. Bondholders have seen prices of recent issues decline this year. Are there any plans to improve the balance sheet or perspectives for a ratings upgrade? Yeah, well, I think the balance sheet is as strong as it gets, being in a net cash position. I know it's a bit frustrating for a bondholder because the bonds are trading slightly below par. The reality is that you're holding bonds which are virtually cash collateralized. From a credit perspective, it's as good as it gets, I would say. If you buy some more, you could have some capital gains on the way looking forward. The other comment around rating increase, that would probably require either some M&A or the development of Blackrod because the... Don't quote me on that, but directionally, the two rating agencies we talked to mentioned that around or we would need to increase production by 20,000-30,000 barrels a day. Okay, thanks, Christophe. Mike, this one's for you. The NCIB is almost completed. Will you start any additional buyback program? Yeah. I think when you say the NCIB is nearly completed, there's still 2.5 million shares left under that program. You know, I think let's see where the development of oil prices are, if we're trending towards the high end of the free cash flow guidance. We've certainly got the option once that's finished to look into additional shareholder returns. For the time being, I think we're comfortable with the capital allocation framework that we've put out at the beginning of the year. Okay, thanks very much. We're a little bit over, so we'll close out the call, and thanks to everyone who's on the line and listening. Talk to you, results, Mike. Yeah. Thank you very much to everybody, and we look forward to presenting the third quarter results, and we'll speak then. Thank you very much. Thank you.