William Lundin: Welcome to IPC's Third Quarter Results Update Presentation. I'm William Lundin, the President and CEO; and alongside with me today is Christophe Nerguararian, our CFO; as well as Rebecca Gordon, our SVP of Corporate Planning and Investor Relations. I'll begin with the quarterly highlights and provide an operational update, then Christophe will expand on the financial details for the quarter. Following the presentation, we'll take questions via the web online or through conference call. It was another strong quarter for IPC with average production rates of 45,900 barrels of oil equivalent per day for the quarter, which was above guidance for the quarter specifically, and our full year production guidance of 43,000 to 45,000 barrels of oil equivalent per day is maintained. Operating costs were slightly below guidance at $17.90, marginally lower unit per production figure than expected, partially due to the production outperformance achieved in the quarter. Full year operating costs are maintained at USD 18 to USD 19 a barrel, likely to end the year around the lower end of this range. We're very pleased today to announce the transformational Blackrod Phase 1 development project is expected to be delivered a quarter ahead of the original scheduled guidance with first steam expected by year-end and first oil in Q3 2026. So great progress on the project has been made to date, which I'll go into more detail later in the presentation. Super proud of the team's efforts to be positioned for an earlier start-up compared to that of our original sanction guidance in early 2023. As a result, we've accelerated some activity from 2026 into 2025, mainly being drilling the final well pad at the Blackrod asset. So IPC full year CapEx is therefore revised to USD 340 million for 2025 compared to the original CMD guidance of USD 320 million. In the quarter, $82 million was spent with about $56 million of that allocated to the Blackrod Phase 1 development. So Dated Brent averaged around $69 a barrel in the quarter. Our operating cash flow was USD 66 million, and our full year operating cash flow is forecast to be between $245 million to $255 million between $55 to $65 Brent for the remainder of the year. Free cash flow for the third quarter after all CapEx was minus USD 23 million or positive USD 36 million pre-Blackrod expenditure. Full year free cash flow forecast inclusive of our final major growth spend year at Blackrod is forecast between minus USD 160 million and minus USD 170 million between USD 55 and USD 65 Brent for the remainder of the year. We successfully refinanced our Nordic bonds subsequent to Q3, took place in October, and that has a coupon rate now of 7.5% maturing in October 2030. Net debt at the end of September stands at USD 435 million with gross cash available to the business of USD 45 million plus additional headroom exists under our RCF in Canada. So for the oil hedges in 2025, we have a mix of swaps and zero cost collars for flat price and differential hedges for around 50% of our exposure for the remainder of 2025. We also have taken advantage of the tight WTI to WCS differential and added around 5,000 barrels per day and a differential hedge for 2026 at $12.50 per barrel. No material incidents recorded during the quarter. We also completed our normal course issuer bid program, the 2024-2025 program in Q3, marking in excess of 6% reduction in our shares outstanding over the course of that buyback program. We have the intention to renew the next NCIB program in December. Production for the quarter, again, was just shy of 46,000 barrels of oil equivalent per day for Q3, and we're averaging around 44,600 BOEs per day year-to-date. So implying we're very well positioned to deliver within our original CMD production guidance of 43,000 to 45,000 barrels of oil equivalent per day. IPC production mix is weighted to 2/3 oil and 1/3 natural gas. Year-to-date operating cash flow is USD 196 million and $4 and $11 per barrel differentials for the Brent to WTI and WTI to WCS, respectively, for the first 9 months of 2025. $66 million out of that $196 million was generated in Q3. There's a slightly tighter differential on the WTI to WCS dip for that quarter. Full year OCF guidance is expected to be between USD 245 million to USD 255 million between $55 and $65 per barrel Brent for the remainder of the year. Really pleased with the base business cash flow generation given we're expected to land in the middle of our original CMD, OCF guidance, as can be seen on the slide, which was based on a $75 per barrel Brent price and the year-to-date settled oil price plus the strip for the remainder of the year is well below that $75 per barrel Brent. Capital expenditure, inclusive of decommissioning spend is forecast at USD 340 million for 2025. So again, slightly increased compared to our CMD guidance, largely due to the acceleration of the drilling activity in 2025 from 2026 for the last well pad at Blackrod given the earlier start-up expectation. And the majority of our non-Blackrod related capital investments have taken place already, mainly relating to the sustaining activities at Onion Lake Thermal and Malaysia. Free cash flow year-to-date, excluding Blackrod CapEx is just shy of USD 80 million, inclusive of Blackrod CapEx, it's minus USD 125 million. With the updated pricing outlook for the remainder of 2025 between $55 and $65 per barrel Brent, we're expecting $80 million to $90 million in free cash flow, excluding the Blackrod CapEx and minus USD 160 million to minus USD 170 million in free cash flow, including the Blackrod CapEx. So this full year outlook has been updated to include the bond refinancing cost, which was opportunistically executed in October this year, and Christophe will touch on that in his section, as well as the additional costs associated with the Blackrod given the acceleration of the activity. At the end of Q3, we completed our seventh buyback program since the company was formed. We do intend to renew the next NCIB in early December. So a total of 77 million shares have been repurchased through all of these programs at an average price of SEK 79 per share or CAD 11 per share, which is well below our current share price level. There's less shares outstanding compared to that when the company was formed and the size of the portfolio has materially grown with current comparatives to 2017 in production being 4.5x higher. We've seen a 17x increase in our 2P reserves, added in excess of 23 years to our 2P reserves life index and added greater than 1 billion barrels of contingent resources and enhanced our NAV by USD 2.5 billion. So the per share metrics are a key focus for the company and driver for maximizing shareholder value. IPC's 2P NAV as at year-end 2024 is in excess of USD 3 billion, representing a fair share price of SEK 287 per share or CAD 37 per share. No value is assigned to our large contingent resource base in this net asset value calculation. Current share price levels suggest we're trading at an approximate 40% discount to our 2P net asset value. So the Blackrod Phase 1 development, this is on budget and progressing ahead of schedule. The original sanction guidance in 2023 suggested a growth capital expenditure for the Phase 1 development of USD 850 million for the total installed cost of the central processing facility and the well stock needed to fill the plant and first oil was guided for late 2026. With the significant progress achieved to date, we now expect first oil in Q3 2026, around a quarter ahead of the original sanctioned time line. So the Phase 1 cumulative capital that's been incurred from 2023 to the end of Q3 2025 is USD 785 million or approximately 92% of the total growth CapEx. So all the surface kit is in place at the central processing facility. Construction and progressive commissioning is ongoing, supported by a lot of manpower at site. Some key milestones have been achieved and derisking the path to startup. Notably, we have commercial gas usage in place now and islanded power generation has been successfully commissioned. So with the detailed sequencing of events planned out and a closer line of sight to start-up, we feel confident pulling the schedule forward, as mentioned. And with that, we have brought forward the drilling of the final well pad into 2025 from 2026. It's a very exciting time at Blackrod for the company as a whole. I'm especially proud of the strong safety record achieved to date with no material incidents since development activities started in 2023. So key items to highlight here on the schedule really is emphasized here with the first team and first oil activity moving to the left, given the great progress that's been made on the project. Moving on to our producing assets. It was a fantastic quarter at Onion Lake Thermal with incremental production benefits coming in from our short-cycle sustaining investments, 4 infills and final well pair tied in from L Pad. So in September, as you can see in the production plot, we saw nearly 14,000 barrels of oil equivalent per day at the asset, which is one of the best monthly production figures achieved at the asset to date. The Suffield area assets is very steady, predictable low decline production from the Suffield area assets and solid low-cost optimization work on the oil side and solid inventory of drill-ready candidates are actionable discretion of the company. So the other assets, this is Canada, as you can see on the map on the right, is yielding around [ 4,000 ] barrels of oil equivalent per day. So seeing great response from our Phase 2 polymer flood at the Mooney asset. In Malaysia, we successfully completed a 2-week turnaround at the end of September and early October. Our investment program in Malaysia was also successfully executed, which can be seen on the production chart. We saw solid production boost come in July and in August, which will come back following the start-up from the shutdown. And France continues to provide stable low decline production. Now over to Christophe for the financial highlights.

Christophe Nerguararian: Thank you very much, Will, and good morning to everyone. So again, very pleased to be reporting a solid quarter with very strong operational performance with a production this quarter just shy of 46,000 barrels of oil equivalent per day. And so the average year-to-date production is 44,600 barrels of oil equivalent per day. So we feel really comfortable about our ability to deliver within that 43,000, 45,000 guidance range for the full year. Coupled with operating costs, which on dollar per barrel of oil equivalent remained this quarter below USD 18, partially driven by low gas and electricity prices. So with relatively low costs, it's driven a very strong financial performance as well with operating cash flows and EBITDA this quarter of USD 66 million and USD 62 million, respectively. With $81 million -- $82 million of CapEx this quarter and USD 280 million year-to-date, it's -- this quarter we generated a negative free cash flow of $23 million, $36 million positive before Blackrod CapEx. And our net debt now stands at USD 435 million. As you can see, realized prices were reasonably stable when you compare the second and the third quarter. On average, Brent was at $69 per barrel during this quarter, WTI $65 and WCS was very tight, so that's the good news. I would say, now we have the proof is in the pudding, and we've been able to see over the last few quarters how tight the WTI/WCS differential has been, and that's really a reflection of the expansion of the TransMountain pipeline, which came on stream more than a year ago. Now we can finally benefit in Western Canada from excess egress capacity, which is -- which really bodes well for our production from our base assets today. But also when we bring Blackrod on stream and ramp it up, we should continue to benefit from reasonably strong WCS prices in the future. We're continuing to enjoy a premium of Dated Brent. In Malaysia we're selling our oil on parity with Brent in France and on party with WCS in Canada. You have the examples here of Suffield and Onion Lake. Gas prices, it's not entirely clear yet, but while Q3 was a very weak quarter when we realized that below CAD 1 per Mcf during that quarter. We might be seeing some light at the end of the tunnel. Clearly, 2026 forward curve is showing some good sign with even the summer months in between CAD 2.5 and CAD 3 per Mcf next year, next summer. So it's very encouraging. We hope that the storage are going to continue to reduce. And we're expecting as well the LNG Canada project on the West Coast of Canada to continue to ramp up in Q1. So those elements together should help alleviate the weakness we've seen in the third quarter and which also partially explains why our OpEx per barrel were reasonably low again this quarter. You can see here that on a cumulative basis for the first 9 months, our operating cash flow was just shy of USD 200 million and EBITDA around USD 185 million for the first 3 quarters. And you can see that this third quarter was in terms of contribution to the year-to-date performance was in between the first and the second quarter, driven by very high production at Onion Lake Thermal. In terms of looking ahead at our operating cost per barrel, we still anticipate higher operating cost per barrel driven by some specific project and maintenance or some workovers in the normal course of business in France or Canada. But overall, year-to-date, our operating cost per barrel remained below $18 per barrel. And so we feel very good about our ability to deliver within the guidance range of $18 to $19, which we provided for the whole year and which we keep unchanged. The netbacks have been around $16 per barrel when you look at the gross cash revenues minus production costs or whether you're looking at operating cash flow or EBITDA per barrel of oil equivalent for the first 9 months were at $16 and $15 per barrel, respectively, which is slightly better than our base case guidance netback from our Capital Markets Day. Reconciling the opening to the closing net debt of the last 9 months. You can see here that this is the last year where we are spending so much CapEx because obviously, with 92% of the budget spent on Blackrod, we're getting much closer to first steam and then first oil in Q3 next year. So you can see here with $196 million of operating cash flow during those first 9 months that fully covered the CapEx of the Blackrod Phase 1 CapEx. But then with the CapEx from the rest of the assets, some cash G&A at $12 million, so less than $1 per barrel. Over $30 million of cash financial items and $100 million of share buyback, the closing net debt was $435 million at the end of September. Our net financial items are very stable. You can see a very small increase in net interest expense quarter-on-quarter, driven by the limited drawdown under our revolving credit facility. Otherwise, the costs are very stable. The exception is this FX loss, which is a non-cash item, really driven by some accounting reassessment revaluation of intra-group loans. It doesn't bear any weight on the cash flows of the business. The G&A remain in cash terms around USD 4 million per quarter or less than $1 per barrel. The financial results now. So in the -- during the first 9 months, our business generated close to USD 510 million of revenues, generating a cash margin of around USD 200 million, gross profit of close to USD 100 million and net profit for the whole first 9 months of $34 million. When you look at our balance sheet, it's very obvious what's happening, and it's an interesting way to look at the way we've been funding the investment in Blackrod. You can see our oil and gas assets increasing by close to USD 250 million, which is the net effect between the CapEx invested and some depletion. And you can see our cash, which has decreased from $247 million down to $45 million over that same period. Looking at our capital structure, Will touched upon it. We were lucky or very smart. We marketed the refinancing of our bonds at the end of September, which was one of the -- really one of the best weeks to go to market. The oil price was still in between $65 and $70. More importantly, the credit spreads were as low as they've ever been over the last 5 years. So as you know, the coupon is a result of the U.S. 5-year swap rate and the credit spread. And bringing those 2 elements together, even if the credit spread was much tighter than at our inaugural bonds, the overall coupon was slightly higher. And so the previous coupon was at 7.25% and now the current coupon is 7.5%. The good thing is that the maturity was extended as a consequence to October 2030. And we've introduced a new feature. We've introduced a $25 million semi-annual amortization starting in April 2028 once we have reached essentially the plateau production at Blackrod. The rest of the capital structure has not changed. And on this last slide of my presentation part, you can see a recap of all of our hedging positions. We're continuing to make money to generate money under our oil WTI swaps or oil WTI collars between $65 and $75, losing money on our WTI/WCS differential swaps at minus $14.2. But we've seen, as we mentioned, the tightness in that differential, which led us a couple of weeks ago to hedge 5,000 barrels a day of our 2026 exposure at minus $12.5, which is one of the best levels we've ever seen in the market for the year ahead. We continued to have 2,000 barrels a day of Brent hedged at close to $76 per barrel. We've recently layered in just shy of 10,000 -- 10 million standard cubic feet a day of hedges. I mentioned that we can really see the forward curve for gas prices improving going into next year. And so we hedged at CAD 2.8 per Mcf, the summer months, the summer strip from April to October, which is typically based on the seasonality, the lower gas prices months. In terms of FX, we've hedged in the past our FX exposure for most or 80% of our exposure to the Blackrod Canadian spending. CapEx, we have nothing in -- as for 2026 yet. We may layer in some FX protection swaps next year given the reasonable weakness in Canadian dollar, but that will be the decision will be made between now and year-end. So again, as a recap, a very strong operational performance, which has driven a very strong financial performance in this third quarter, good performance in the first 9 months, where we're going to deliver essentially within the guidance range we provided at our Capital Markets Day in all our material key performances. Thank you for that. And I will let Will conclude this presentation. Thank you very much.

William Lundin: Thank you, Christophe. And so with the final slide and the summary slide, investment year-to-date through the first 9 months of the year in 2025 has been USD 281 million, USD 194 million of that has gone towards the Blackrod Phase 1 development. Production, again, for Q3, was very strong at 45,900 barrels of oil equivalent per day. Annual production guidance maintained at 43,000 to 45,000 BOEs PD. Very stable operating cost base of $17.90 for Q3 and maintaining the full year guidance of USD 18 to USD 19 per BOE. Good prices and healthy production, good cost discipline translated into strong cash flow generation for the quarter with $66 million in operating cash flow generated and $36 million in free cash flow for the quarter, excluding Blackrod CapEx there. Balance sheet, again, net debt, we have $435 million as at the end of Q3 and gross cash of $45 million. No material incidents took place in the quarter. And we completed our share repurchase program in the quarter as well. So with that, that concludes the presentation overview and happy to turn it over to the operator for questions.

Operator: [Operator Instructions] We'll now take our first question from Teodor Nilsen of SB1 Markets.

Teodor Nilsen: Congrats on good Blackrod progress. First question then is on the Blackrod production profile. Can you just give us a reminder of what kind of ramp-up profile you expect there now, assuming first oil in Q3 next year? Second question that is on your leverage. When do you expect the net debt to EBITDA to peak? I assume that will be around or maybe slightly later than first oil at Blackrod. And my third and final question, that is on the LNG Canada project. Could you just discuss the potential price impact on your realized gas prices of that project and time line for the project?

William Lundin: I'll take the Blackrod question, and then I'll hand it over to Christophe for the net debt-to-EBITDA and LNG Canada, second and third parts of your question. So as it relates to the Blackrod schedule advancement, what we had originally guided for Blackrod was first oil in late 2026 and 30,000 barrels of oil per day to be achieved in 2028 with the great progress that's been made and the scheduled advancement of around a quarter, and we expect that profile to move a little bit to the left as a result of that. And so more details around the exact profile will be refreshed coming into our CMD presentation in 2026.

Christophe Nerguararian: Yes. Thank you very much. On the leverage, you're absolutely right, Teodor. You should expect the leverage to progressively and then a bit faster reduce once we reach the first oil on Blackrod. As for gas prices, I mean, the reality is that the weather forecast is quite cold right now in Alberta, so that's clearly helped. Over the last few days increased the spot AECO price and the whole forward curve moves with it. So that's -- this is more the tactical review, if you wish, where AECO gas price is right now and the impact on the forward curve. Well, the forward curve tends to move altogether with the spot price. But now on the fundamentals, we understand that the ramp-up of the LNG Canada project is progressively increasing the local gas demand and is going to continue to help, hopefully, increase gas prices. Certainly, this is what the market anticipates when you look at the gas forward curve, which is in excess of CAD 3 for the whole year next year.

Operator: And we'll now move on to our next question from Rob Mann of RBC Capital.

Robert Mann: I'm just curious if you could dig into some of the factors that have allowed you to pull forward the schedule of Blackrod. I imagine it's a combination of things, but just curious if you can provide any further details there.

William Lundin: Yes. Thanks Rob. And so further to the explanations provided in the development section in the Blackrod part of the presentation, exceptional progress is made to date here. And with certain milestones achieved such as acceptance of first gas into the plant and commercial gas, firing up our power generation. We have 2 turbines that provide 15 megawatts of power each, so a total of 30. Those have been successfully commissioned and with the overall progressive commissioning and turnover strategy and some of the other milestones that have been achieved, it's given us further confidence to be able to pull forward that schedule. We have water inventoried in tanks now as well. And so everything is being lined out to have a higher degree of certainty around that first steam and then corresponding first oil date. So we feel good at this point in time with not being too far away to provide that update to the market overall.

Robert Mann: Yes, that's great. Maybe just shifting gears to one other question, if I could. You've added some hedges on in 2026. So maybe just curious how you're thinking about that program moving forward, just given the commodity price outlook here and as you move toward completion of Blackrod?

William Lundin: Yes, that's correct. So we've added some differential hedges in place as well as some gas hedges for the summer period at this point in time. We will monitor forward curves on the flat price as well as further differentials and gas prices and it's potential for us to add on more hedges, provided they're at prices that we deem attractive overall. We do have a significant amount of our CapEx rolling off as a result of Blackrod getting to its final stages before starting up here. And as well with getting the refinancing done, which would have matured in early 2027 previously, that also is a significant factor that's been executed and taken care of by the company. So for next year, I mean, the strip that's pretty flat in the curve as we look at flat price right now as maybe a tiny bit of contango. Still feel prices are relatively low as it relates to Brent and WTI looking forward into 2026. But if there were to be a bit of a spike or a bump, we may look opportunistically to lock in some hedges.

Operator: And we'll now take our next question from Christoffer Bachke of Clarksons Securities.

Christoffer Bachke: Christoffer from Clarksons is here. First of all, congrats on a strong quarter. So only one question today, and that relates to Blackrod. So given that the Blackrod Phase 1 is now progressing ahead of schedule and also now close to the first steam, could you please elaborate on what specific efficiencies or lessons learned that have driven that outperformance? And also whether any of those gains could translate into cost or timing benefits for potential future Blackrod phases?

William Lundin: Given we're still in the midst of the project execution, I mean, it all comes down to the overall planning that the team has put forth before sanctioning this project and putting allowances in place on schedule and cost is always a prudent thing to do. So we set ourselves up for success on the onslaught of sanctioning this project. And with the steady execution that's taken place across all key disciplines, whether it be mechanical, electrical and the construction, on operational hires, and the drilling front, everything has been going very, very well. That's put us into this position to update the overall schedule advancement for Blackrod. As it relates to the overall budget, we are maintaining that overall budget of USD 850 million to first oil at this point in time. And I think once we get this asset fully fired up and producing at plateau production rates, there's undoubtedly going to be positive lessons learned from undergoing this development where, of course, we have 100% working interest and have been the controlling developer in this process. So definitely something that we will add into our toolbox that will be beneficial for unlocking future phase expansions of the asset.

Operator: [Operator Instructions] And we'll now move on to our next question from Mark Wilson of Jefferies.

Mark Wilson: Excellent progress. You've clearly got a hell of a team up there at Blackrod. We've seen it in-person and on the ground and now you've accelerated that start-up. Now Will, you said you'd update on the ramp-up at the CMD. I'd like to ask about that and then the bigger picture because you've just mentioned on the last question, unlocking future phase expansions. And with Blackrod Phase 1 having a ramp-up potentially towards 2028 and combining that with the improved WTI/WCS situation that you've spoken about with TransCanada, you're in a completely new situation in terms of your outlook. I just want to know how much you want to derisk the production from Phase 1 before you may start thinking about committing to Phase 2?

William Lundin: Thanks, Mark. Appreciate the color and the commentary that you provided. That's right, we had a great field visit earlier in Q2 with yourself and many others included there. So no, hats off to the team at site. They've done a tremendous job pushing this project forward. So very pleased with where we're at overall. It is a great situation when you look at the WTI to WCS outlook right now as well with it being very tight and there being excess takeaway capacity relative to the supply for the future years ahead, which matches the ramp-up profile quite nicely with respect to Blackrod, which should also hopefully translate into higher flat prices as well at that point in time to give us good cash flow generation. So I think as we look forward, we remain opportunistic in our capital allocation approach at all times. And so it's going to be a balance of always targeting to maximize shareholder value. So looking at stakeholder returns, organic growth, M&A, it's going to be a balance of all 3 of those. We have to monitor our liquidity position, balance sheet and take into account all the learnings as well from Blackrod. We are very confident, of course, in terms of what to expect for that production ramp-up, given that we have direct analogs at the asset with well -- pilot well pairs that have been successfully producing for many years, specifically -- well pair 3. So it's a bit difficult to give an exact time line in terms of when we would look to do a sanction of the future phase expansion at Blackrod. It's really going to be dependent on oil prices, liquidity, leverage position, and of course, taking into account some of the learnings from Blackrod over the course of the start-up. But what we've said previously is we'd expect sometime, likely end of the decade provided oil prices were healthy. And so this is something that sits within our contingent resources. And until we really go forward and mature that into reserves, it will be something that will keep us upside in the back pocket.

Operator: And we'll now take our next question from Jonas Shum of Clarksons.

Jonas Shum: Congratulations on the progress on Blackrod. So given that you have kind of progressed very well, can you elaborate a bit on kind of what are the key remaining milestones, and the risks for that. You mentioned that the weather forecast for Alberta was indicating relatively cold weather. Could that have any ramifications on kind of the progress during the winter time here?

William Lundin: Yes. Thanks Jon. So as we look forward going into the start-up for Blackrod, weather is for sure a variable that exists for start-up overall, and we have seen some snow take place a little bit earlier than expected. And so things like heat trace are very important at site, which the team is all over and heat trace is largely installed in the key areas and the rest of it will be implemented as well in due course here. As we look to the overall start-up, as I'd mentioned, we have some water inventoried in some tanks. And so it's really getting the downstream equipment of that ready to be fired up with respect to the associated pumps in the boiler feed water system leading up into the steam generation and then going downhole. So -- of which we expect that to be completed and fired up by year-end to give us first steam by year-end and then correspondingly first oil in Q3 of 2026.

Operator: We have no further questions in the queue. I'll now hand it over to the company.

Rebecca Gordon: Okay. Thank you, operator. So we did have a lot of questions on the sequencing of Phase 1 and Phase 2, which I think you've already covered there, Will. But we also had some questions on potential growth programs in Malaysia and France. Can you give a bit of detail on that?

William Lundin: Yes. So as I mentioned in the presentation in the international asset section, we're really pleased with the production boost that we've seen at the Malaysian asset as a result of that step-out drilling campaign and the workover that's been achieved. That this asset, we do hold a couple of wells in our contingent resources, but we don't have any further development wells held within our 2P reserves at Malaysia. In France, there are a number of robust investment opportunities and specifically within a field called Fontaine-au-Bron that looks very attractive and is ultimately ready to be sanctioned at the discretion of the group, which will be largely dictated by oil prices.

Rebecca Gordon: Great. And also a couple of questions on Canadian natural gas prices, which I think you've covered, Christophe. But perhaps you could give a bit of color on a question, which is, will Blackrod eventually make you a gas net consumer? If so, when is this point going to be reached?

Christophe Nerguararian: Yes, that's correct. Obviously, as we are ramping up the oil production, we're going to ramp up our gas usage as well. And we're expecting at this stage that towards the end of the decade, so 2029 to 2030, we will turn into being -- everything being equal, we will turn into being a net gas consumer. That is the projection at this stage.

Rebecca Gordon: Yes. And I think, Will, you've covered off really our sort of capital allocation priorities in the future. There were a couple of questions there about whether we would look to buy back shares in the future, whether it was Blackrod Phase 2. There was actually another question on M&A. So it would be interesting to hear your perspective on the recent M&A activity in the sector, thinking specifically of the big interest in the market for the long-lived assets of MEG. Any thoughts would be appreciated.

William Lundin: Yes, it's been very interesting item to monitor in the market with respect to the MEG and Cenovus deal that is likely to close quite soon here, I believe. That type of -- how do you say, the takeover bid that took place or the hostile actions that have taken place on MEG were something that not, I think, a lot of the industry was expecting, quite savvily done in general by the Strathcona company. Obviously, very high-quality asset at Christina Lake and the Tier 1 oil sands deposit that they have within the MEG portfolio that we expected to close and go over to Cenovus very soon here. And so I think overall M&A landscape, I think I'd expect to see further consolidation to take place through time. And we're a company that's executed quite a few acquisitions in our recent history. And so something like growing through M&A is, again, within our DNA, and we're going to be opportunistically looking to assets or companies to grow through and combine with, provided they fit the right criteria for the company.

Rebecca Gordon: Okay. Fantastic. I think that most of these other questions have actually been answered through the course of the operator questions. So we'll leave it there. We're out of time. So thanks to everyone. Will, you want to close?

Christophe Nerguararian: Thank you.

William Lundin: Thanks very much, Rebecca. Appreciate it. And thanks, everyone, for tuning in. And look forward to the next update, which will be our year-end results and Capital Markets Day presentation in early February 2026. Thank you.