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. There's another strong quarter for IPC, with average production rates of 45,900 bpd for the quarter, which was above guidance for the quarter specifically, and our full year production guidance of 43,000-45000 bpd 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 $18-$19 a bbl, 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 schedule guidance, with first steam expected by year end and first oil in Q3 2026. 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 startup 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. IPC full year CapEx is therefore revised to $340 million for 2025, compared to the original CMD guidance of $320 million. In the quarter, $82 million was spent, with about $56 million of that allocated to the Blackrod Phase 1 development. Dated Brent averaged around $69 a bbl in the quarter. Our operating cash flow was $66 million, and our full year operating cash flow is forecast to be between $245 million-$255 million between $55-$65 Brent for the remainder of the year. Free cash flow for the third quarter after all CapEx was -$23 million, or + $36 million pre-Blackrod expenditure. Full year free cash flow forecast, inclusive of our final major growth spend year at Blackrod, is forecast between - $160 million and - $170 million between $55-$65 Brent for the remainder of the year. We successfully refinanced our Nordic bonds subsequent to Q3. It 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 $435 million, with gross cash available to the business of $45 million, plus additional headroom exists under our RCF in Canada. 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 bbls per day in a differential hedge for 2026 at $12.50 per bbl. No material incidents recorded during the quarter. We also completed our normal course issuer bid program, the 2024-2025 program in Q3, marking an 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 bpd for Q3, and we're averaging around 44.6 thousand BOEs per day year to date. This implies we're very well positioned to deliver within our original CMD production guidance of 43,000-45,000 bpd. IPC production mix is weighted to two thirds oil and one third natural gas. Year to date, operating cash flow is $196 million. And $4.11 per bbl differentials for the Brent to WTI and WTI to WCS respectively for the first nine months of 2025. $66 million out of that $196 million was generated in Q3. There's a slightly tighter differential in the WTI to WCS differential for that quarter. Full year OCF guidance is expected to be between $245-$255 million, between $55-$65 per bbl 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 bbl Brent price. The year to date settled oil price, plus the strip for the remainder of the year, is well below that $75 per bbl Brent. Capital expenditure, inclusive of decommissioning spend, is forecast at $340 million for 2025. This is 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 startup expectation. 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 $80 million. Inclusive of Blackrod CapEx, it's minus $125 million. With the updated pricing outlook for the remainder of 2025, between $55-$65 per bbl Brent, we're expecting $80-$90 million in free cash flow, excluding the Blackrod CapEx, and minus $160 million to minus $170 million in free cash flow, including the Blackrod CapEx. This full year outlook has been updated to include the bond refinancing costs, which was opportunistically executed in October this year. 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. 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 are fewer shares outstanding compared to 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 have seen a 17x increase in our 2P reserves, added in excess of 23 years to our 2P reserves life index, and added greater than a billion bbls of contingent resources and enhanced our NAV by $2.5 billion. The per share metrics are a key focus for the company and a driver for maximizing shareholder value. IPC's 2P NAV as at year end 2024 is in excess of $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 level suggests we are trading at approximately a 40% discount to our 2P net asset value. The Blackrod Phase 1 development 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 $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 timeline. The Phase 1 cumulative capital that has been incurred from 2023 to the end of Q3 2025 is $785 million, or approximately 92% of the total growth CapEx. 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 in de-risking the path to startup. Notably, we have commercial gas usage in place now, and the islanded power generation has been successfully commissioned. With the detailed sequencing of events planned out and a closer line of sight to startup, we feel confident pulling the schedule forward as mentioned. With that, we have brought forward the drilling of the final well pad into 2025 from 2026. This is 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. 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 short cycle sustaining investments for infills and final well pair tied in from ELPAT. In September, as you can see in the production plot, we saw nearly 14,000 bpd at the asset, which is one of the best monthly production figures achieved at the asset to date. The subfield area assets, we have some very steady, predictable, low decline production from the subfield 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. The other assets in Canada, as you can see on the map on the right, is yielding around 4,000 bpd. Seeing great response from our phase two polymer flood at the Mooney asset. In Malaysia, we successfully completed a two-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 a solid production boost come in July and in August, which will come back following the startup from the shutdown. France continues to provide stable low decline production. Now over to Christophe for the financial highlights. Thank you very much, Will. Good morning to everyone. Again, very pleased to be reporting a solid quarter with very strong operational performance, with a production this quarter just shy of 46,000 bpd. The average year to date production is 44,600 bpd. We feel really comfortable about our ability to deliver within that 43,000-45,000 bpd guidance range for the full year. Coupled with operating costs, which on dollar per bbl of oil equivalent remained this quarter below $18 USD, partially driven by low gas and electricity prices. With relatively low costs, it's driven a very strong financial performance as well, with operating cash flows and EBITDA this quarter of $66 million and $62 million respectively, with $81 million, $82 million of CapEx this quarter and $280 million year to date. 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 $435 million. As you can see, real life prices were reasonably stable when you compare the second and the third quarter. On average, Brent was at $69 per bbl during this quarter, WTI $65, and WCS was very tight. That is the good news, I would say. Now we have the proof is in the pudding, and we have been able to see over the last few quarters how tight the WTI/WCS differential has been. That is really a reflection of the expansion of the Trans Mountain Pipeline, which came on stream more than a year ago. Now we can finally benefit in Western Canada from excess egress capacity, which really bodes well for our production from our base assets today. 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 are continuing to enjoy a premium of updated Brent in Malaysia. We are selling our oil on parity with Brent in France and on parity with WCS in Canada. You have the examples here of Sofield and Onion Lake. Gas prices, it is 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, the 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. It is very encouraging. We hope that the storage are going to continue to reduce. We are expecting as well the LNG Canada project on the west coast of Canada to continue to ramp up in Q1. Those elements together should help alleviate the weakness we have seen in the third quarter, which also partially explains why our OpEx per bbl were reasonably low again this quarter. You can see here that on a cumulative basis, for the first nine months, our operating cash flow was just shy of $200 million and EBITDA around $185 million for the first three quarters. You can see that this third quarter was, in terms of contribution to the year-to-date performance, 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 bbl, we still anticipate higher operating cost per bbl driven by some specific project, maintenance, or some workovers in the normal course of business in France or Canada. Overall, year to date, our operating cost per bbl remained below $18 per bbl. We feel very good about our ability to deliver within the guidance range of $18-$19, which we provided for the whole year and which we keep unchanged. The net backs have been around $16 per bbl when you look at the gross cash revenues minus production cost, or whether you are looking at operating cash flow or EBITDA per bbl of oil equivalent for the first nine months. We are at $16, $16 and $15 per bbl, respectively, which is slightly better than our base case guidance net back from our capital markets day. Reconciling the opening to the closing net debt of the last nine 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. You can see here with $196 million of operating cash flow during those first nine 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 bbl, 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 $4 million USD per quarter, or less than $1 per bbl. The financial results now, so during the first nine months, our business generated close to $510 million of revenues, generating a cash margin of around $200 million USD, a gross profit of close to $100 million, and net profit for the whole first nine 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 $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 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 five years. As you know, the coupon is the result of the U.S. five-year swap rate and the credit spread. Bringing those two elements together, even if the credit spread was much tighter than at our inaugural bonds, the overall coupon was slightly higher. 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. 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. 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 - $14.2. We have seen, as we mentioned, the tightness in that differential, which led us a couple of weeks ago to hedge 5,000 a day for 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 continue to have 2,000 a day of Brent hedged at close to $76 per bbl. We've recently layered in just shy of 10 million standard cu ft a day of hedges. I mentioned that we can really see the forward curve for gas prices improving going into next year. 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. 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 nine 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. I will let Will conclude this presentation. Thank you very much. Thank you, Christophe. With the final slide and the summary slide, investment year-to-date through the first nine months of the year in 2025 has been $281 million. $194 million of that has gone towards the Blackrod Phase 1 development. Production, again, for Q3 was very strong at 45,900 bpd. Annual production guidance maintained at 43,000-45,000 bpd. Very stable operating cost base of $17.90 for Q3 and maintaining the full-year guidance of $18-19 bpd. 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. With that, that concludes the presentation overview, and happy to turn it over to the operator for questions. Thank you. Ladies and gentlemen, if you would like to ask a question, please press star one on your telephone keypad. That is star one on your telephone keypad. We'll pause for a brief moment. Thank you. We'll now take our first question from Theodore Nielsen of SB1 Markets. Please go ahead. Good morning. Thanks for taking my question. I'm Theodore. We have some good Blackrod progress. First question, that is on the Blackrod production profile. Could you just give us a reminder of what kind of ramp-up profile you expect there now, assuming first oil year into 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 or last at Blackrod. My third and final question, that is on the LNG Canada project. Could you just discuss the potential price impact on your real-life gas prices of that project and the timeline for the project? Thanks. Thanks very much, Theodore. 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 questions. As it relates to the Blackrod schedule advancement, what we had originally guided for Blackrod was first oil in late 2026 and 30,000 bpd to be achieved in 2028. With the great progress that's been made and the schedule advancement of around a quarter, we expect that profile to move a little bit to the left as a result of that. More details around the exact profile will be refreshed coming into our CMD presentation in 2026. Yeah, thank you very much. On the leverage, you're absolutely right, Theodore. 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 increase the spot AECO price, and the whole forward curve moves with it. This is more the tactical review, if you wish, of where AECO gas price is right now and the impact on the forward curve, where the forward curve tends to move altogether with the spot price. 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. Thank you. Thank you. We'll now move on to our next question from Rob Mann of RBC Capital. Your line is open. Please go ahead. Hey, good morning, team, and thanks for taking my question. 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 culmination of things, but just curious if you can provide any further details there. Yeah, thanks, Rob. Further to the explanations provided in the development section and 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 two turbines that provide 15 MW of power each, so a total of 30 MW. Those have been successfully commissioned. 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. Everything's being lined out to have a higher degree of certainty around that first steam and then corresponding first oil date. We feel good at this point in time with it not being too far away to provide that update to the market overall. Yeah, that's great. Thanks. Maybe just shifting gears to one other question, if I could. You've added some hedges on in 2026, and 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. Thanks. Yeah, that's correct. 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 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. 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. For next year, I mean, the strip, it's pretty flat in the curve as we look at flat price right now. There's maybe a tiny bit of contango. Still, field 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. Great. Thank you. Thank you. Thank you. And we'll now take our next question from Christopher Becker of Larson Securities. Please go ahead. Hi, guys. Christopher from Larson Securities here. First of all, congrats on a strong quarter, and thanks for taking my questions. 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. Thank you. Thanks, Christopher. Yeah, 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. We set ourselves up for success on the onslaught of sanctioning this project. With the steady execution that's taken place across all key disciplines, whether it be mechanical, electrical, and the construction on the operational hires and the drilling front, everything's 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 $850 million to first oil at this point in time. 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 controlling developer in this process. Definitely something that we'll add into our toolbox that will be beneficial for unlocking future phase expansions of the asset. Thank you, Will. Thank you. Thank you. Once again, as a reminder, if you would like to ask a question, please press star one on your telephone keypad. Thank you. We'll now move on to our next question from Mark Wilson of Jefferies. Please go ahead. Hello. Good morning. 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 startup. 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. 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 de-risk the production from Phase 1 before you may start thinking about committing to Phase Two. Thank you. 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 hats off to the team at site. They've done a tremendous job pushing this project forward. 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 would also hopefully translate into higher flat prices as well at that point in time to give us good cash flow generation. I think as we look forward, we remain opportunistic in our capital allocation approach at all times. It's going to be a balance of always targeting to maximize shareholder value. Looking at stakeholder returns, organic growth, M&A, it's going to be a balance of all three 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 pilot well pairs that have been successfully producing for many years, specifically well pair three. It's a bit difficult to give an exact timeline 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 startup. What we've said previously is we'd expect sometime likely end of the decade, provided oil prices were healthy. This is something that sits within our contingent resources, and until we really go forward and mature that into reserves, it'll be something that will keep us upside in the back pocket. Thank you. We'll now take our next question from Jonas Schon of Clarkson. Please go ahead. Hey, guys. Thank you for taking my questions and congratulations on the progress on Blackrod. Given that you have kind of progressed very well, can you elaborate a bit on 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 the progress during the wintertime here? Yeah. Thanks, Jonas. As we look forward going into the startup for Blackrod, weather is for sure a variable that exists for startup overall. We have seen some snow take place a little bit earlier than expected. Things like heat trace are very important at site, which the team is all over. 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 startup. As I mentioned, we have some water inventoried in some tanks. It is 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, 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. Thank you. We have no further questions in the queue. I'll now hand it over to the company. Thank you, Operator. We did have a lot of questions on the sequencing of Phase 1 and Phase 2, which I think you have already covered there, Will. We also had some questions on potential growth programs in Malaysia and France. Can you give a bit of detail on that? Yeah. As I mentioned in the presentation in the international asset section, we are really pleased with the production boost that we have seen at the Malaysian asset as a result of that step-out drilling campaign and the workover that has been achieved. This asset, we do hold a couple of wells in our contingent resources, but we do not 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 Fantone-Embrun 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. Great. Also, a couple of questions on Canadian natural gas prices, which I think you have 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? Yeah, that is correct. Obviously, as we are ramping up the oil production, we are going to ramp up our gas usage as well. We are expecting at this stage that towards the end of the decade, so 2029- 2030, we will turn into being, everything being equal, a net gas consumer. That is the projection at this stage. Yeah. I think, Will, you have 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 Two. There was actually another question on M&A. 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? Yeah, it's been a 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 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 expect to close and go over to Cenovus very soon here. I think overall M&A landscape, I think I'd expect to see further consolidation to take place through time. We're a company that's executed quite a few acquisitions in our recent history, and something like growing through M&A is, again, within our DNA. 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. 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. Thanks to everyone. Will, you want to close? Thank you. Thanks very much, Rebecca. Appreciate it. 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.