International Petroleum Aktie

Welcome to IPC's 2026 Second Quarter Results Update Presentation. I'm William Lundin, the President and CEO, and joined today by Christophe Nerguararian, our CFO; as well as Rebecca Gordon, our SVP of Corporate Planning and Investor Relations. I'll begin with the highlights and provide an operational update, then hand it to Christophe to walk through the financial section. After the presentation, we can take questions, which the audience can submit through conference call or via the Internet online.

Getting right into the second quarter highlights for IPC. Our average production for the second quarter was right in line with guidance at 42,200 barrels of oil equivalent per day, and our full year 2026 production guidance is maintained at 44,000 to 47,000 BOEs per day. Second quarter operating costs came in line with expectation at USD 19.10 per BOE. And the OpEx per BOE forecast for the full year is maintained as per the original CMD guidance at USD 18 to USD 20 per BOE. And of course, the major announcement in the quarter for the company was achieving first oil at Blackrod. It's the largest organic growth project IPC has undertaken since formation in 2017 and to execute ahead of schedule and on budget is a huge achievement that we're very, very pleased about.

Similar to production and OpEx per BOE guidance, we're maintaining our CapEx guidance at USD 163 million for 2026, noting the majority of the capital has been spent in the first half of USD 120 million or around 3/4 of that capital budget. Q2 capital spend was $49 million. Operating cash flow for Q2 was robust at USD 67 million, noting oil prices were higher in the second quarter relative to the first quarter, averaging around $100 barrel Brent. About 40% of our oil production exposure was hedged at a WTI price between low and mid-60s and for the Brent side between the mid- to high 60s for Brent. So despite those hedges in place, still a robust Brent in cash flow. Our full year OCF is forecast at USD 230 million to USD 330 million, assuming $70 to $90 per barrel Brent for the remainder of 2026. And free cash flow for Q2 was a positive $4 million, noting this is the first quarter of positive free cash flow since 2023 as we transition from a higher spending period during the Blackrod build-out to startup.

Full year free cash flow is expected to be between USD 10 million to USD 110 million between $70 to $90 barrel Brent for the rest of the year. Net debt as at the end of Q2 stands at $509 million, about a $4 million reduction relative to the prior quarter, thanks to the positive free cash flow delivery in Q2. We have greater than $150 million of undrawn credit availability under our Canadian bank syndicate. And as of July 1, 2026, our oil production is fully exposed to WTI and Brent oil prices with the prior benchmark oil hedges rolling off, as I mentioned previously. There are some Canadian heavy oil differential transport and quality-related hedges for the remainder of '26 and some into '27 that are in place as well as some natural gas hedges that are also in place for 2026, all of which are in the money currently. And our seventh annual sustainability report was issued alongside our Q2 results.

So as can be seen on the production plot, we've seen continuous flat production performance through the first 6 months of the year with average rates of around 42,600 barrels of oil equivalent per day. Stable performance across the portfolio year-to-date, and we're looking forward to the imminent production growth going into the second half and beyond.

As mentioned, we're well positioned to deliver on our annual production guidance for 2026 of 44,000 to 47,000 barrels of oil equivalent per day. The guidance bands in the production forecast shows a progressive production ramp-up in the second half of the year, and that trend will continue into 2027. The increased forecast is predominantly due to the Blackrod start-up and partially supported by intra-year production investment additions at existing producing assets, which will yield more of an impact at the end of this year and going into 2027. I'll touch on more specific activity detail in the following slides.

Q2 is the inflection point from a production standpoint and higher production quarterly averages will shine through going forward as we transition from inventorying period at Blackrod to consistent sales mode in Q4. We'll also see a material uplift in cash flow generation. Our current production mix is split 70% towards oil and 30% towards natural gas, which is important to highlight, and as per my previous comment, with larger proportion of oil-weighted production coming imminently, our future production mix is going to be higher proportionately weighted towards oil versus natural gas lending to increased cash flow.

Operating guidance is maintained at USD 18 to USD 20 per BOE with Q2 costs settling in at $19.10. As previously reported, we had some production enhancement activity that is going to be expensed, most of which will fall into Q3, which is expected to be a slightly higher OpEx per BOE quarter before dropping in the subsequent quarters. Christophe will expand on this evolution in his section of the presentation.

So operating cash flow for the first half settled in at USD 134 million with an average Brent price of $92 and the WTI price of $82 and WCS of $68. It has been a volatile period on the pricing front so far year-to-date. The cash flow and corresponding prices were higher than our original CMD guidance, as shown on the right-hand side of the slide. So we're pleased to see higher cash flow generation coming through. Looking forward for the full year OCF, we expect to generate between $230 million and $330 million between $70 and $90 Brent, assuming a differential of $5 from Brent to WTI and $14 from WTI to WCS. The proportion of operating cash flow is heavily tilted towards Q4 compared to Q3 for the second half, as can be shown with the lighter shading on the bar chart in the middle of the slide. This is largely due to the prior mentioned additional activity taking place in Q3 and the inventory and treatment at Blackrod. The torque to higher prices is significant, and we are fully exposed to Brent and WTI prices going forward since the Brent and WTI hedges concluded at the end of June.

Our CapEx program, inclusive of decommissioning spend is maintained at $163 million, noting we did increase the capital budget at Q1 relative to Capital Markets Day, large in part due to the sanctioning of short-cycle investments in France and the Suffield area assets in light of the higher commodity pricing environment that we saw as the year progressed relative to starting 2026. We do retain flexibility to adjust our program for the second half given our operatorship status at all the assets in our portfolio.

Free cash flow is projected to be $10 million to $110 million, between $70 and $90 Brent for the remainder of 2026. returning to a free cash flow positive position is really fantastic to see and the waterfall of free cash flow will significantly grow in the years ahead.

So since inception, IPC has repurchased 77 million shares at an average price of SEK 79 per share or CAD 11 per share, translating into around $1 billion of value creation compared to our current share price. We have the ability to repurchase up to 6.5 million shares through our normal course issuer bid program, which represents 10% of the free float. And our current share count today is less than 113 million shares, notably lower than the original share count in 2017. So driving up production value reserves and resource longevity per share is really a key ingredient to maximizing shareholder value.

As previously reported to the market, Blackrod Phase 1 is officially producing oil, achieving this milestone at the end of May, ahead of the original schedule guidance. Costs came in line with the budget at USD 855 million growth capital, and we currently have 5 well pairs online with several other well pairs to be converted upon necessary conformance conditions being met. We held a Blackrod site visit at the beginning of July with our Board and the pride and sheer competency of the top-tier talent at site is really off the charts and the state-of-the-art facility is off to a fantastic start as we get into operational start-up and ramp-up mode. So this is really a unique feat in the industry to deliver a multiyear growth project on budget and ahead of schedule with no material safety incidents, really hats off the entire team involved for executing this transformational greenfield project responsibly.

Blackrod, it's a long-life asset that is officially unlocked as the Phase 1 CPF is now on stream. Plateau production for Phase 1 is 30,000 barrels of oil per day, and we have 311 million 2P reserves assigned to the Phase 1 project, which represents around USD 1.4 billion in net present value using a 10% discount rate based on the conservative year-end '25 reserve auditor price deck, along with the 1/1/2026 breakeven of $47 WTI. We have regulatory approval of this asset to go to 80,000 barrels of oil per day and the combined 2C plus 2P volumes represent 1.45 billion barrels of recoverable resource, which is shown on the graph on the bottom, there's been a substantial increase to the total recoverable barrels compared to that of the early volumes in 2010.

So the depositional environment of this asset really lends to a scalable and repeatable upside, and we continue to work behind the scenes to mature future phase expansions, which are yet to be recognized in the underlying net asset value or future cash flow projections.

Moving on to Onion Lake Thermal. OLT has delivered stable production through the first 6 months of the year. This is our Saskatchewan thermal operation. We did shoot some 4D seismic earlier this year. That data is under review and preparations are ongoing for the next sustaining capital activity. The Suffield area assets consists of our Suffield Block acquisition that we acquired from Cenovus in early 2018 as well as the Brooks package that we purchased from Core 4 in 2023. And this package overall continues to deliver stable, low decline, reliable production. And we're super excited to be drilling again here within the basal quartz formation, production multi-leg lateral wells are planned to be drilled.

And first half production from our Brent-linked assets was around 500,000 barrels of oil per day. Drilling is underway in France with 4-well sidetrack campaign. Initial results from the first well are very encouraging thus far, and we look forward to future reporting on the progress of this campaign. Malaysia dated Brent premium realizations have been very material, as Christophe will share in his section of the presentation. And workover activity is ongoing in Bertam, which will boost production rates from current levels looking ahead into Q4.

Now I'll hand it over to Christophe to expand on the financial highlights.

Thank you very much, Will. Good morning to everyone. So it was a solid quarter operationally. So hands off to all of the teams locally with the production right in line with guidance in excess of 42,000 barrels of oil equivalent per day. We saw some very strong oil prices during the quarter with an average dated Brent price in excess of $100 per barrel. And so with operating costs in line with guidance at $19 per barrel of oil equivalent. IPC generated strong operating cash flow and EBITDA at USD 67 million and USD 64 million, respectively.

I think what's really worth noting here is that almost for the first time in almost 3 years, the operating cash flow fully covers the CapEx. That was true in the second quarter, and that is true year-to-date. And so that's really the turning point we've been talking about for a while with Blackrod first oil achieved at the end of May during the quarter. We've not really turned the corner yet, but almost at least we see a strong reduction in the Blackrod CapEx and still a very strong operating cash flow. So we are really going to move back into positive free cash flow territory. That was the case in this second quarter with a ramp-up at Blackrod in the third quarter. It may or may not be again the case, but we would hope to have another free cash flow positive or right in line with the second quarter.

The real change will occur in the fourth quarter with a much stronger production from Blackrod, translating into what we believe will be a much stronger free cash flow towards the end of the year. So the net debt at the end of the quarter was reasonably flat, just around USD 510 million. Looking at the realized prices, of course, with the war in Iran, the oil, which was not flowing freely through the Strait of Hormuz, we saw very high oil prices in April and May, specifically during the second quarter. So with dated Brent price of USD 104 per barrel on average during the quarter and WTI, WCS at $92 and $78, respectively, those are a very, very high level, which we didn't fully benefit from because around 40% of our production was hedged before the war started early March in Iran.

That being said, maybe just another comment that's interesting is that Will talked about it, but we were lifting cargoes roughly every 2 months in Malaysia. And the premium we get there is always an interesting indication about how tight physical markets are. And clearly, the June cargo, which was priced in April during the quarter, saw a very, very strong, very high premium, which showed how tight markets was. And again, for our next cargo in the third quarter, we've already agreed on a very high premium as well. So that's a sign that the physical market remains very tight.

Looking at the gas prices, not much change, frankly. And sadly, the Canadian gas prices remain at a discount to the U.S. market. It's not fully or very well physically connected with the U.S. market, which enjoys higher gas prices. So during the quarter, we realized a price of CAD 1.75 per Mcf. So it's traditional that there's an element of weakness for gas prices during the summer. But unfortunately, it stays well below U.S. gas prices.

Looking at the operating cash flows and EBITDA for the first 6 months in 2026 and compare those to 2025, reasonably stable here. The production was a bit higher last year. Oil price is a bit lower last year as well. So it's roughly in line with around USD 130 million of operating cash flow during the first 6 months, both last year and this year and around $125 million, both last year and this year. So I think as we touched upon before, with a bit more one-off OpEx with more activity in terms of workovers in Malaysia, in Canada as well, we're expecting maybe the operating cash flow to be in line or lower in Q3, but much higher with the Blackrod contribution during the fourth quarter. And indeed, you can see on the OpEx per barrel.

So we are maintaining our guidance, but you see that clearly with some of the activity, which we sanctioned at the end of Q1 and which is really being carried out in this third quarter, you can see a bump in OpEx -- in the operating cost per barrel in that third quarter that is well anticipated and hopefully well communicated to you and the market. But on average, we're expecting to be in the second part of that $18 to $20 range, but stay within it.

Again, I think it's important to anticipate and note that in the fourth quarter, as Blackrod production is going to further ramp up, you can see the natural decline in OpEx per barrel. And so irrespectively of what you can see here in the third and fourth quarter, I think it's important for us to reiterate that the mid- to long-term operating cost per barrel remain very positive and should be below what we see here once Blackrod is ramping up to its full potential at 30,000 barrels a day in the course of next year, towards the end of next year.

Strong netback, obviously, driven by the strong operational and the solid oil prices. You can see here both in the second quarter and for the first 6 months, relatively stable. with an operating cash flow netback in excess of $17 per barrel of oil equivalent and an EBITDA at around $16.5 per barrel of oil equivalent.

Looking at the net debt really at the cash flow, and I like and I want to emphasize again that for the first time in a while, you can see here the operating cash flow of USD 134 million for the first 6 months, which is covering more than all of our development CapEx and abandonment costs. So we are moving into this phase where finally we are going to generate free cash flow. So it's not fully the case yet for the first 6 months, but we're getting there. You can see that's where the operating cash flow fully covers our CapEx and cash G&A. And we believe that very soon, we'll be covering as well all of our cash financial items and working capital to put us in a solid free cash flow position.

Please note that we had a USD 6 million sale of assets in the first 6 months. Those were lands, which we never really intended to drill. It's an acreage, which we had been -- collected along the prior years, and we're able to sell them to some Canadian companies.

In terms of financial items, well, the situation on the balance sheet and the capital structure is very stable with our bonds and revolving credit facility. So you can see that we have net interest expenses of around USD 10 million per quarter, stable again quarter-to-quarter, and we're expecting stable again in -- going into the third quarter. And G&A is stable as well at around USD 4.2 million, USD 4.3 million per quarter or just above $1 per barrel of oil equivalent. So strong financial results with almost USD 360 million of revenues, a cash margin of $135 million, gross profit of $75 million and a net result of $23 million for the first 6 months.

The balance sheet, not much to mention here. The investment, of course, goes into increasing the value of our oil and gas property assets on the asset side of the balance sheet, and we're continuing to depreciate those assets as we are producing them. We have very little cash now, and we're usually maintaining around $10 million on the balance sheet. And otherwise, we draw or repay under our revolving credit facility as we need.

The capital structure, I mentioned, is very stable. We have our 5-year bonds with a coupon of 7.5% maturing in 2030. So USD 450 million of bonds. On top of that, as an adjustment, if you wish, depending on whether we need it or not quarter-to-quarter, we have access to an equivalent revolving credit facility from our Canadian banks of USD 250 million and only CAD 100 million were drawn at the end of the quarter. We have reduced our outstanding letters of credit now that the Blackrod project is finally on stream. So we have roughly CAD 12 million of letters of credit just to support access to pipelines and some export facilities. And we had a very small amount under our French loan, which was fully repaid in the month of May.

So we didn't fully benefit from the high oil prices only 60% roughly. We benefited from during that second quarter because we had 40% of WTI and Brent exposure hedged. That is no longer the case, excuse me, going forward. We have no benchmark hedging going forward. What we have though for the next 18 months is we've hedged some differential. So we have typically for this year, the differential, the WTI, WCS differential hedged at minus $12.5 which is roughly $2 in the money. And depending on the months, you have the detail on this table, we've also hedged a part of the transportation cost between Hardisty Canada and Houston in the United States. And all of these hedges are in the money, and we can see around $6 million of positive mark-to-market on our balance sheet.

So that concludes my final section, and I will hand over to Will for the overall conclusion.

Thank you, Christophe. In summary, a solid second quarter for the company and a compelling outlook going forward. Q2 production of 42,200 barrels of oil equivalent per day, OpEx of $19.10 per BOE in the quarter and the original Capital Markets Day production and OpEx guidance is maintained. Capital spend in Q2 was USD 49 million and the full year 2026 outlook is maintained at $163 million.

Operational cash flow was USD 67 million for Q2 and USD 230 million to USD 330 million is expected for the full year. We have in excess of $150 million of undrawn liquidity headroom. Our sustainability report was issued alongside our Q2 results, which I encourage the audience to read. It highlights the responsible business practice undertaken in 2025. And this voluntary report is progressively aligned with the latest standards such as IFRS 2.

So with that, I'll hand it to the operator to open the floor for questions and as well questions can be submitted online.

[Operator Instructions] Our first question is from Teodor Nilsen from SB.

Congrats on Blackrod first oil. My first question on production guidance. As you mentioned, you achieved the Blackrod first oil slightly before expectations, slightly before guidance, but you do not increase production guidance, although first oil was achieved earlier than expected. Why is that?

And second question that is on hedging. Christophe, you highlighted that you don't have too much hedging at least on the oil side going forward. Is that mainly explained by lower CapEx going forward, so lower commitments? Or do you have any particular market view that drives that hedging strategy?

My last question that is on share repurchases. I think we discussed this also last quarter, but now most of the Blackrod CapEx is behind us, should we expect you to do some more on repurchases than you have done over the past couple of quarters? Or yes, any thoughts on that would be useful.

Yes. Thanks for the questions, Teodor. I'll answer the first question, the third question, and I'll hand the hedging question to Christophe to answer that one. So you're right, we're really pleased about Blackrod first oil being achieved ahead of guidance. And I think the type of asset that we're talking about and first oil being achieved, there are going to need to be 40 well pairs online to deliver 30,000 barrels of oil per day. So we did have -- our initial set of well pairs came on ahead of expectation, which is very positive. But at this point in time, we feel like it's still prudent to maintain the full year guidance. And as we progress further into the year, we feel like we're pretty well positioned to deliver at least within the midpoint and potentially in excess of that. So we're maintaining the guidance as things stand at this point in time. But in the field, it's looking very positive at this point at the Blackrod asset.

And on the share repurchase side, regarding the flexibility, that's right. As I mentioned in the presentation, we have the flexibility to repurchase around 6.5 million shares. We haven't done that yet as we remain steadfast on executing Blackrod, which, of course, as you point out, is now on stream. We are pleased to see a marginal net debt reduction in this quarter, and we are monitoring macro, micro conditions as things stand and keeping a close eye on our liquidity, and we remain opportunistic to begin participating in that program.

On the hedging front, Christophe?

Yes. No, thanks for a very good question, obviously. And I think we are generally bullish long term. The short term is much more difficult to take a view on and changes almost on a daily basis depending on the statements coming from the White House in the U.S. Now that being said also, we shouldn't be confused with the very short-term daily volatility and the long-term oil prices where we can hedge. There is a very significant -- the curve is relatively steep and backward dated. And so we obviously cannot hedge at the current spot rates. But we are monitoring that. Now the flip side is we've always communicated that when the bulk of the CapEx is behind us or we don't have any specific debt maturities, we will take a lighter approach on benchmark hedging. So we'd rather focus on hedging and securing good transportation costs for crude to the U.S. Gulf Coast or the absolute WTI/WCS differential. And I think we'll be a bit more cautious on hedging dated Brent or WTI prices. It's not excluded, but we're going to take a much more prudent approach there.

Okay. Makes sense. And actually, if I may have even one more question that is on, could you just please remind me what's the latest you have communicated on time line for sanctioning of Blackrod Phase 2?

Yes. Phase 2 and future phase expansions still lie within our contingent resources. So there hasn't been any prescriptive disclosure in terms of when the next expansion project takes place, but it is a lot of work that's happening behind the scenes on looking into multiple expansion opportunities there. And as those plans mature, we will provide an update accordingly to the market at that point in time.

[Operator Instructions] It appears there are currently no further questions over the phone. With this, I'd like to hand the call back over to our host for any webcast questions.

Okay. Thank you, operator. We have a few questions from the Internet here. So just kicking off with a question regarding the portfolio, Will, perhaps you can comment. With Blackrod now upstream, is now the time to rationalize your portfolio and divest your international assets?

The asset base that we have has demonstrated high cash flow generative ability and the foundation of existing assets has really supported us to put us in a place to be able to unlock the likes of Blackrod Phase 1. There's still lot of life out of the portfolio beyond Blackrod with the existing producing assets. We do think of ourselves as ruthless capital allocators, and we're interested in maximizing value. There's no imminent processes at this point in time to note.

Okay. Thanks very much. We had a few questions on hedging, Christophe, which I think you've covered here. But maybe you could comment on, given we've only got $40 million remaining CapEx for the year, how does management think about the opportunity to increase this to take advantage of commodity prices versus paying down debt?

Yes, increasing CapEx, you mean?

Yes, increasing CapEx.

Well, we've already leveraged to some extent in our portfolio, we have short-term quick payback activity sets. So we've committed some increased activity, as you know, at the end of Q1. We are constantly looking and trying to high-grade those options and possibilities. Will mentioned earlier on to the other question that we're working on future potential phases at Blackrod. So there's always an opportunity to spend 2 million or 3 million and accelerating those future phases and expansion, which we are working on in any case, which may be considered OpEx or CapEx. So I think we're very active. Generally, we don't anticipate to significantly increase further CapEx this year, but a lot of activity is happening behind the scene already.

Okay. Thanks, Christophe. We do have another couple of capital allocation questions, but I think one here, Will, that we haven't covered is our dividends something that's being considered going forward?

Yes. We have the full flexibility on our shareholder returns in terms of dividends or buybacks and subject to the conditions of the company, the liquidity when we look to return value back to shareholders in the form of distributions and subject to where our share price is sitting will kind of dictate the form of shareholder returns. So we have never had a dividend in IPC, and we are in the midst of a lot of growth. And so we really firmly believe the share price appreciation is still to shine through much higher than current levels. So at this very point in time, I think it's less likely that a dividend would be implemented in the short term.

Okay. And then just a quick question. If you can elaborate on any CapEx plans for 2027?

Yes, 2027 budget details will be put together and released to the market at a Capital Markets Day in 2027. We have our year-end '25 reserves plan, which is based on the year-end reserve auditor price deck, which has a CapEx profile, which we have disclosed externally as well for the next 5 years. So subject to commodity prices, the opportunity set of maturation, we may look to add on incremental value-adding activities based on that current assumption, but it's something that will be reviewed in detail at the end of this year and consulted with the Board before we release our final 2027 budget, which will come at Capital Markets Day.

Thanks. And then the final question here really is to do with strategic focus going forward. Will that include some M&A?

Yes, we've always said M&A is in our DNA, and we remain opportunistic to growing inorganically, provided a tangible and robust opportunity presents itself, and we are very much anchored in maximizing shareholder value. We have a tremendous portfolio of organic growth potential within it. And as well, we always want to benchmark against buying back our own stock as well compared to doing M&A. So within the boundaries of that, if the right opportunity presents itself for the right price, we're open and opportunistic to growing through M&A, but it's grounded within those boundaries, as I touched on.

Okay. Thanks very much, Will, Christophe, that's the questions that we have today. So we'll close the conference.

Thank you. Thanks very much. Look forward to reporting in Q3.

Okay. So welcome, everybody, to IPC's 2026 First Quarter Results Update Presentation. I'm William Lundin, the President and CEO. I'm joined today by Christophe Nerguararian, our CFO; as well as Rebecca Gordon, our SVP of Corporate Planning and Investor Relations.

So I'll start with the highlights and give an operational update, then Christophe will touch on the financial highlights for the quarter. Following the presentation, we'll take questions, which can be submitted through conference call or via the web online.

Jumping into the highlights. We're very pleased to report another solid quarter of operational performance. Production for Q1 was at the top end of the quarterly forecast at 43,000 barrels of oil equivalent per day, and we're retaining our full year production guidance range of 44,000 to 47,000 boes per day. We had good cost discipline with Q1 operating expenditure coming in at sub USD 18 per barrel of oil equivalent, and we are maintaining guidance for OpEx at USD 18 to USD 20 per barrel.

Entering 2026, we set a lean work program and budget as we were assuming a base case price estimate of $65 per barrel Brent. And in response to the improved pricing environment, we're taking advantage of our operatorship and increasing our capital program from USD 122 million to USD 163 million, predominantly to accommodate short-cycle investments across some of our producing assets. The Q1 capital spend was USD 71 million.

Operating cash flow generation for Q1 was $68 million, and we revised our full year OCF guidance to USD 220 million to USD 340 million assuming $70 to $90 per barrel Brent for the remainder of 2026. Free cash flow was minus USD 17 million. And we are entering really an inflection point here for the company and there shouldn't be too many more quarters of negative free cash flow going forward with Blackrod first oil expected in the near horizon.

Full year free cash flow is expected to be between 0 to USD 120 million positive between $70 to $90 Brent for the rest of 2026. Net debt stands at $513 million, and we expanded our Canadian credit facility during the quarter to USD 250 million. We also extended the maturity of that to 2028. So that gives us an increased headroom and overall flexibility.

Our benchmark hedges for WTI and Brent for approximately 40% of our production exposure rolls off in June, leaving us fully exposed to benchmark oil prices from July onwards. We have some WTI/WCS differential hedges and transport/quality-related hedges tied to our Canadian heavy oil exposure as well at attractive levels and some natural gas hedges in place that are currently in the money as well. No material incidents took place during the quarter, we're very pleased to report on.

So on to the following slide. As shown on the production graph on Slide 3 here, IPC delivered flat production, really at the high end of our guidance in the first quarter, with overall strong performance across all the assets in the portfolio. So I'll touch on more detail on each of the assets' performance later on in the presentation.

Moving on, we're very strongly positioned to deliver within our CMD production forecast range of 44,000 to 47,000 barrels of oil equivalent per day. Drawing your eyes to the bottom of the production chart on this slide. 2026 is really a story of two tales here with forecast production volumes expected to rise materially at the back end of the year with Blackrod Phase 1 oil production set to come online. In addition to some of the incremental capital adds, fast payback projects we've also added in, this will be contributing more so at the back end of this year for production rates.

Our production mix is weighted 60% towards Canadian crude, which is tied to WCS pricing, 10% to Brent-linked production coming from Malaysia and France and the remaining balance of 30% being natural gas from Southern Alberta. And I'd also like to reiterate here that the 44,000 to 47,000 barrels of oil equivalent per day guidance is an annual average, very much an annual average rather than a quarterly average as can be seen on the high and low guidance bands on that bottom left-hand chart.

OpEx, so we are maintaining that original Capital Markets Day forecast as we set out in February of $18 to $20 a barrel.

First quarter operating cash flow was USD 68 million. The differentials from Brent to WTI, can be seen in the brackets there, was $9 and from WTI to WCS was $14 a barrel. So the Brent to WTI differential was notably high on the back end of the geopolitical conflict in the Middle East, which our Brent-linked production benefits from, of course.

Our operating cash flow full year forecast for 2026 is updated to USD 220 million to USD 340 million based on $70 to $90 Brent, and that assumes a $5 differential between Brent and WTI and a $14 differential between WTI and WCS. So a material improvement compared to our CMD forecast and notably more than funding our incremental capital spend program this year with the revised updated operating cash flow generation outlook.

Moving on to our CapEx program inclusive of decommissioning, which now stands at a forecast of $163 million. So that's roughly $40 million higher than the original CMD CapEx guidance. The increase is mainly due to accelerated fast payback drilling activity at our Southern Suffield assets in Alberta and in the Paris Basin in France, which I will expand on following asset-specific slides.

So we continue to see great progress at Blackrod, and we've updated our 2026 budget outlook for the forecast spend at that asset. Big picture, the multiyear budget for Blackrod Phase 1 growth capital, the first oil is USD 850 million. There has been some minor cost pressure with total costs expected to be approximately USD 857 million, which is less than 1% overall of that original sanction CapEx guidance for the growth capital to first oil.

And we're still expecting the project to be delivered in terms of first oil in Q3 of 2026, which is ahead of the original timeline given at the time of sanction back in 2023. Because of this continued acceleration and positive progress, there are some sustaining completion costs as well being pulled forward, which is a positive outcome overall.

The free cash flow outlook, we're projecting to generate between 0 to $120 million of positive free cash flow between $70 and $90 Brent for the remainder of 2026. Very exciting to be returning into a positive free cash flow generating position this year with a major boost in free cash flow levels anticipated in 2027 and beyond as Blackrod Phase 1 ramps up and comes onstream.

Moving to the share repurchases slide. IPC, of course, has a very strong track record of share repurchases in our brief history as a company. So 77 million shares have been bought back at an average price of SEK 79 or CAD 11 per share, respectively. And that represents around $1.4 billion of value created from the share repurchases when comparing the average share price that those shares were bought back at to our current share price.

Notably on the antidilution waterfall, the only time shares were issued in a transaction was for the BlackPearl acquisition back in 2018. All of those shares have been bought back. And our current shares outstanding is just shy of 113 million shares, which is less than the original starting amount of 113.5 million shares.

And we've transformed the company to where we are today compared to at inception in 2017. Now we see a 4.5x increase in production levels, 18x increase on our 2P reserves in excess of 20 years, added to our 2P reserve life index in excess of 1 billion barrels of contingent resources, added an overall 4x increase to our NAV compared to that of when the company was formed at the beginning of 2017.

So Blackrod. This is a 20-year journey in the making to bring this vision into reality by unlocking a Phase 1 commercial development. I had the privilege of being at site at the end of April. This is a world-class SAGD plant with a best-in-class operational staff. It's a compact site with a small footprint for the CPF and nearby well pad facility tie-ins. This asset is going to propel the company to new levels, and it's been a fantastic journey going from sanction through to development and on to startup now with rotating equipment well in service at this point in time.

Original guidance for this project, again, back in 2023 when it was sanctioned, called for first oil in late 2026 and growth capital up into that point of USD 850 million. We achieved first steam ahead of our original forecast, resulting in a schedule improvement which was announced at the beginning of this year, with first oil expected in Q3 2026. So operations continue to progress well, and we're strongly positioned to deliver within this accelerated timeline.

Cumulative spend as at the end of Q1 from the beginning of 2023 on the growth capital is USD 842 million with some minor works remaining on the final boiler tie-in as well as well pad facilities as we expect to deliver this project overall in line with the original growth capital guidance to first oil.

I really couldn't be more proud of our multidisciplinary IPC teams as well as the vendors utilized in this major undertaking, and we're especially pleased that there has been no material safety incidents under IPC's supervision as prime contractor of the site. Excellent delivery overall and stewardship of this project to date.

So Blackrod valuation. Again, this is a true game-changing asset for IPC. We have regulatory approval up to 80,000 barrels of oil per day with over 1.45 billion barrels of recoverable resource. Phase 1 targets 30,000 barrels per day and 311 million barrels of 2P reserves. And the economics as at the beginning of this year, based on our conservative reserve auditor price deck, is USD 1.4 billion of net present value using a 10% discount rate and approximately a $47 WTI breakeven.

As you can see on the figure on the right-hand side of the slide, this is a massive uniform sandstone reservoir. It's contiguous and homogeneous, lending to a very much predictable and scalable product potential that's validated through the 15 years that it's been under pilot operation testing. In the lower graph here, the dark wedge on the bar chart reflects what is booked in 2P reserves and carried within our valuation. The light blue component of that bar chart is the contingent resources and represents upside to our business.

Moving on to our producing assets. Our current flagship oil-producing asset at Onion Lake Thermal delivered stable production through Q1. We also did some 4D seismic work at the beginning of the year and are reviewing that data to hone in on some additional potential infill targets on existing producing drainage patterns. And also to note on that schematic on the right, H Pad is the next main drainage pattern to be developed in the sequence.

Moving on to the Suffield area assets. So very much predictable and low decline production, the Suffield area assets, which delivered around 23,000 barrels of oil equivalent per day through Q1. We're very excited to be redeploying some capital into these assets, where we've sanctioned a 4-well production drilling campaign within the Basal Quartz area, just west of the Suffield block.

Production from France and Malaysia for Q1 was in excess of 5,000 barrels of oil per day. We had some incremental activity that's also been sanctioned now in France. We look to drill 3 sidetracks in the FAB field and 1 sidetrack in the Villeperdue field. So very exciting to be drilling again in France. And in Malaysia, we also plan to do an operational activity of workover using a hydraulic workover unit later this year on our A13 well.

So with that, I will hand it over to Christophe to go through the financial highlights. Thank you.

Thank you very much, Will. Good morning, everyone.

So indeed, a good quarter with production at the high end of our Q1 guidance at 43,000 barrels of oil equivalent per day. And of course, during this first quarter, when the situation happened between Iran, the U.S. and Israel, the oil prices increased massively from the beginning of March. And so you really have a relatively high average Dated Brent oil price for the whole quarter, in excess of $81 per barrel, but that was really two sides of the story with lower oil prices in January and February and much higher in March.

So overall, that really helped generate on that basis strong operating cash flows and EBITDA for the quarter at USD 68 million and USD 64 million. As we guided before and as most of our investors know, the capital expenditure in 2026 was always expected to be much front-loaded, and so you can see a disproportionate portion of the CapEx spent during this quarter translating into a free cash flow of negative USD 17 million. And it depends where oil prices will be on average for Q2, but it's fair to assume that the free cash flow may be negative again in Q2.

But from that point onwards, we're expecting to turn the corner and to be again back into free cash flow territory for the second half, depending on where first oil kicks in at Blackrod. So USD 13 million of net profit for this quarter. The net debt increased during this first quarter by USD 30 million. Again, it's fair to assume that this net debt would increase again in the second quarter and from that point on progressively. Depending on where oil prices stand, we should see some deleverage from Q3 or from Q4. But certainly this year, we should start to see some accelerated deleveraging as the Blackrod production ramps up over time.

Realized prices, so I mentioned, were strong. And I think it's interesting, a bit sad at the same time, but interesting to see that the physical market is quite dislocated. And so the Dated Brent has been trading at between $5 up to $30 premium on top of the future or the financial Brent, if you wish. And when we lifted our cargo in Malaysia, the last one in March, we had a good premium. And for the future June cargo, which we're going to lift in Malaysia, we can see that the physical market is very tight because the premium we can realize there are very, very high. So you can see we sold in March a cargo in Malaysia at USD 110 per barrel, while on average for the quarter, Dated Brent was USD 81.

The Brent-WTI differential widened a bit at $9 and the WTI/WCS differential stood at negative $14 for the quarter. We're continuing in Canada to sell our heavy oil on parity or very close to the WCS. Gas prices were actually okay during this first quarter. But overall, the market again is quite disconnected between the U.S., and the Canadian market has been a new reality for the Canadian gas prices over the last 18 months now for the lack of infrastructure and communicating infrastructure between the Canadian gas pipeline network and the U.S. market.

So you can see that we realized CAD 2.5 per Mcf during this first quarter. But the forecast is showing for the summer months lower gas prices, which is still a negative to IPC given that we are producing more gas than we're consuming at Onion Lake or that we will consume in the following quarters at Blackrod. Now the positive in the long run is that because we are consuming gas at Blackrod, it will be a relatively cheap feedstock gas going forward.

In terms of financial results, it's interesting to compare '25 and '26. We had during this first quarter '26 similar production and overall revenues between the first quarter '26 and '25. Some of the difference between the 2 quarters in '26 and '25 was coming from the fact that we lost $10 million of hedges -- hedged losses in this first quarter because we had hedged around 40% of our WTI and Brent exposure at between $62 and $68 per barrel. And of course, we've been losing in the month of March mainly.

And given that we are still hedged until the end of June at those around 40% level at current prices, we can expect to make a hedging loss of around USD 30 million during the second quarter. But I think it's important to flag as well that beyond the end of June, we no longer have any benchmark hedged. So we are totally exposed to the Brent and the WTI prices going forward into the second half of 2026.

Looking at the operating costs. So we were below during this first quarter as a result of strong production level and relatively low electricity and gas prices. We can expect higher operating cost per barrel going into the second quarter with a bit of a slightly lower production in the second quarter. In the third quarter, when we're going to move progressively into commercial production at Blackrod, we're going to register some OpEx which will be a bit higher in the first months of operation. But you can see that as soon as the Blackrod production ramps up in the fourth quarter, the OpEx per barrel will progressively reduce, and we would expect that trend to continue into 2027.

You can see the netback on the following graph with gross margin of close to $18 per barrel and operating cash flow at $17.5 and EBITDA at $16.5 per barrel of oil equivalent of netback.

Looking at the evolution of our net debt. So we increased our net debt this quarter by USD 30 million given the reasonably high CapEx of $71 million we spent during the year. So we spent more CapEx than the level of operating cash flow. This is going to reverse in Q2 and even more so in the second half of this year.

In terms of financial items, it's sort of a steady state now in the second half. Last year when we refinanced our bonds, we had some exceptional and one-off fees that we paid as part of that bond refinancing. From now on, it's going to be much more stable. And just to mention that the foreign exchange loss you can see here of $6.5 million during this quarter is a noncash item. Otherwise, the G&A remains reasonably stable and flat at around USD 4 million per quarter.

So looking at the financial results. We generated net revenues of $173 million, netting a cash margin of $68 million and gross profit of USD 37 million, which net of the financial items, tax and tax elements yielded a net profit of USD 13 million for the quarter.

The balance sheet has continued to evolve since we sanctioned the Blackrod project. As you expect, our level of cash has reduced and our level of net debt increased over the last 3 years. But again, we are almost touching distance from reversing this trend certainly going into 2027 but as well going into the second half of this year.

And I will let Will conclude this presentation.

Thank you very much, Christophe. So in summary, very exciting to be ramping up activity really across all regions of operations. Q1 capital came in at USD 71 million and the full year outlook is $163 million now, really leveraging our operatorship and increasing our production exposure to the high commodity pricing environment that we're seeing.

We're well positioned to deliver within our production guidance, and our operating costs remain under control. Operating cash flow generation was robust for Q1 at USD 68 million. And the outlook for the full year is $220 million to $340 million. We have in excess of USD 150 million of undrawn liquidity headroom. There are no material environmental or safety incidents that took place in the first quarter.

And with that, I'm happy to pass it over to the operator to begin questions, and you can also submit your questions online via the web. Thank you.

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

Will and Christophe, first question there is around the small CapEx increase you announced. I just wanted to know what is driven by cost increases and what is driven by higher activity. And second part of that question is related to the activity increase. By how much should we assume that the exit rate production this year increases as a result of the accelerated investments? So that's the first two questions.

And third question, that is on share repurchases. You've, of course, been very successful doing that for the past 2 years as you discussed. But you haven't been doing any repurchase. You have not done any material repurchases the past few months. So I just wanted a background for that. Do you think the share price approached a reasonable level? Or are there other reasons for why you have reduced the buybacks?

Thanks very much, Teodor, for the questions. I'll head those off. First one being the small CapEx increase. So we had an adjustment of $122 million to $163 million for capital expenditure for 2026. So that $40 million some-odd increase, the lion's share of that is for capital activity in France and Canada.

So we're going to be doing 4 sidetracks drilling program in France for approximately $15 million and also in Southern Alberta at our Suffield area assets, more on the more recently acquired in 2023 Core 4 property. We're also going to be drilling 4 wells there. So the total combined amount is around $23 million when you add the France plus the Brooks-related activity that we're undertaking. I also touched on the slight cost increase at Blackrod there as well, which was expanded on throughout the presentation.

But really the vast majority of the cost increases are deliberate cost increases here to increase the activity for production contributing projects. And so that production increase for those 2 projects that I had noted, which will be more back-end weighted this year in terms of the production contribution, we expect to see in excess of 1,000 barrels per day on average delivered for 2027 from those 2 programs.

So very attractive cost per flowing barrel metrics to undertake those capital activities and really a part of our whole strategy as well over the past couple of years while we've been accommodating the growth capital for Blackrod as well as buying back our shares at very cheap levels. Some of the capital activity that's been ripe and ready to go across our existing producing assets, we've elected to wait until more constructive oil prices present themselves.

And here we are now. And that is the reason for why we've kind of prioritized the incremental capital going towards production contributing activity right now as opposed to share buybacks.

We do have the flexibility to restart share buybacks, where we have the NCIB activated up until December of this year. We are steadfast on focusing on getting Blackrod on to production here. We continue to monitor market conditions and overall liquidity headroom. Safe to say we are very strongly positioned, and it's something that we're going to continue to monitor as the year progresses here in terms of restarting shareholder returns.

[Operator Instructions] We will now move on to our next question from Mark Wilson of Jefferies.

Excellent progress as ever and good look with the final steps in Blackrod, obviously. I thought the most interesting area now is the gas side of things in Canada. You mentioned that your hedges are rolling off for WTI. Just remind us where that stands for the gas, particularly as that is looking weaker in terms of infrastructure.

And whether you think there's any longer-term impact from the M&A we've seen into Canadian gas, Shell coming in for ARC and further phases of Canada LNG. Just be interested to hear that.

Yes. Thank you, Mark, and very good questions. So I skipped the table on hedging as Will touched on it already in the opening slide. But you're absolutely right. It was very interesting to see Shell going after ARC, which is a large gas producer, and so this is just speculation at this stage, but probably paves the way or at least increases the chances and the odds that Shell would go and try to expand the LNG facility on the West Coast of Canada, North of Vancouver.

And that's a fairly obvious move when you look at the massive arbitrage you can see between local domestic gas prices and international gas prices. So I think the projection in the very short term is to probably still have reasonably low gas prices onshore Western Canada, but the prospects of having more demand from that LNG Canada plant going forward has probably increased over the last few weeks.

In terms of hedging, we have 50,000 GJ a day of gas hedged at CAD 2.7 per GJ or CAD 2.8 per McF. So unfortunately, that's probably going to be in the money. And so you know us. We remain very opportunistic. If we see any gas prices hike in the forward curve, you should fairly expect us to seize that kind of opportunities. And so that was your main question, around gas prices. No, you're absolutely right, that in terms of WTI or Brent exposure, the hedges are rolling off at the end of this quarter, at the end of June. And so we'll be fully exposed going forward to what looks to be reasonably constructive oil prices going forward.

Sorry, just to add to that in terms of being a great signal in terms of Shell increasing its exposure in Canada just for the upstream overall Canadian landscape there. And now with that acquisition, Shell has secured roughly 3/4 of its feed gas requirements for both Phase 1 and Phase 2 of LNG Canada. So it certainly bodes well and signaling for an FID of Phase 2, but we're still yet to see that for that LNG project on the West Coast of B.C. there.

Got it. Okay. And is it worth mentioning on the broader Canada side of things, what was it I heard recently, is it a sovereign wealth fund? Or is it an infrastructure fund? And any implications?

Yes. That was Mark Carney, and he said a sovereign wealth fund. The extent of the details are yet to be understood in terms of where the funding is going to come from to be able to do that. But that is the headline that Mark Carney announced, was a sovereign wealth fund.

Okay, okay. And then just one last point. I might have missed it in Teodor's question. But the short cycle in Suffield, that's obviously targeting liquids, I imagine.

Yes, oil.

Okay. Very good. Congratulations again. Looking forward to reading the rest of the news in the year as it ramps up.

Exactly, thank you.

Much appreciate it. Thanks, Mark.

Thank you. We have no further questions in the queue. I'll now hand it over to the company for online questions.

Okay. Thanks, operator. So we've got a couple of questions here. Maybe we can just start with a bit of information on the short cycle, Will. Just a couple of questions on Ferguson and whether we have opportunity there to put some rigs in or maybe look at additional drilling there.

Yes, for sure. So Ferguson, there's quite a few opportunities in terms of drilling as well as recompletion, refracking-related activity as well that we are looking into. Some of the activity is likely to be an operating expenditure-related item. So that is something that we do plan to do in terms of a few wells and recompletions on a few wellbores there. So look to see some minor production boost coming from the asset towards the tail end of the year.

Okay. Very good. And then another question here. I mean, obviously, there's a lot of interest on Phase 2. Is there any intention to bring that forward now? Or how are we feeling about the timing given the oil price?

Yes. I think the liquidity position as we've stated for quite some time now is going to change quite rapidly as Blackrod Phase 1 sets to come onstream in the back half of this year, and we look to generate significant free cash flow in the year of 2027 even at more modest oil prices. And if these pricing levels are to hold through 2027, it's going to put us in a very, very good place to look to continue pursuing our key capital allocation strategic pillars in terms of organic growth, shareholder returns and also staying opportunistic towards M&A.

But for Phase 2 specifically, our future expansion potential at Blackrod behind the scenes is definitely something that's being worked up. But of course, we remain very, very much focused on successfully completing and bringing Phase 1 online from an oil-producing standpoint.

Great. Thanks. And then just a quick question on capital structure, Christophe. Could you explain the increase in the RCF, why you went for that?

Yes. Well, if you look back at what IPC has been doing as a corporate, we try to raise and improve liquidity when we don't need it. So it's been a constant discussion with our banking partners and banking friends. We enjoy very good support from Canadian banks these days.

There was the opportunity to increase the Canadian revolving credit facility from CAD 250 million to USD 250 million, which we just did and extended the maturity up to May 2028 as we do every year. So it's all positive for no other specific purpose than having ample liquidity.

Fantastic. Thanks. Will, just a question on regulatory framework, so in Canada, the U.S. and our other operating jurisdictions. Have we seen any changes post the Iran war in those sort of regulatory frameworks or anticipate anything to come?

No, there hasn't been any changes regulatory-wise in the stable jurisdictions where we operate and we have production operations taking place. And specifically in Canada also, they have a sliding framework based on oil prices for the royalties. So no changes expected there or elsewhere within the portfolio at this time.

Okay. Fantastic. And then maybe one final question here. What would be your priority post Blackrod complete in terms of organic growth or shareholder returns or buybacks?

Yes. The infamous question, I think. The punch line here is that we have the ability to do it all, and we look to strike the right cadence in terms of pulling forward organic growth and continuing to screen opportunities in the M&A landscape and balancing shareholder returns as well. And so I think we're going to be really strongly positioned to deliver on all three of those fronts. And the main lens, of course, will be to maximize shareholder value in our pursuit of that capital allocation strategy.

Okay. Fantastic. That's what we have time for today. That's all our questions. So I leave it to you to close, Will.

Excellent. Thanks very much, Rebecca, and thanks, everyone, for tuning in to our first quarter results update presentation. We're very, very strongly positioned, and It's a super exciting time for the company with the next major catalyst being Blackrod first oil. So that will come in due course very soon here. So thanks, everyone, and take care.

Thank you. This concludes today's call. Thank you for your participation. You may now disconnect.

Okay. So welcome, everybody, to IPC's Capital Markets Day presentation for 2026. I would like to say thanks to everyone joining in person here in London today for the event and those tuning in on the web. We have a lot of material to get through today and an exciting outlook for the company. But before going into the agenda and the materials within the presentation, we'd like to show a little video edit that was recently put together, just demonstrating the importance of energy and what's taking place at Blackrod as well. So a little 5-minute edit we'll put up.

[Presentation]

Fantastic. Okay. So with that, motivational video that got put forward. I will then now go into the overall presentation. So starting the agenda here in traditional format, I will begin with the overall introduction as well as the overview and strategy for the company. And I'll pass it to Nicki and Chris, who will go into the operational assets as well as at the corporate level.

And then Christoph will touch on the financial overview, specifically for 2026. Following that, Rebecca Gordon will expand on the reserves evaluation for the year. I will conclude with a summary slide and we'll take some Q&A.

So jumping right into it, to touch on the 2025 highlights after this slide, majority of the presentation will be focused on 2026 and going forward. So what do we do in 2025? I think the big achievement for the company was delivering first steam at Blackrod at the end of 2025. This was something that was ahead of our original expectation. We expected for steam at Blackrod in Q1 of 2026 when we sanctioned this project back in 2023. So it's a testament to the quality teamwork and execution overall at that asset.

On the capital expenditure front, we spent $344 million for the full year 2025. It was the second highest capital expenditure program for the company, trailing the year prior to that, and we're really now on the heels of the major investment at Blackrod with only around $30 million left to execute the Phase 1 development project specifically. So delivering within guidance on capital expenditure as well as on production. The full year production level for the company in 2025 was 44,900 barrels of oil equivalent per day. Close to the high-end CMD guidance range.

And on the operating expenditure per unit production, full year costs settle in at $17.80. So good cost control overall there. Good production and average prices of around $69 Brent throughout the course of 2025, then that we generated around $259 million in operating cash flow, which was slightly above our Q3 latest guidance between $245 million to $255 million. Balance sheet.

We prudently and opportunistically undertook a bond refinancing at the end of 2025. That closed in October. We are pleased with that. That's $450 million of Nordic bonds and the maturity of that now is in October of 2030. We also have a revolving credit facility in Canada, where we have around 200 million CAD available at this point in time.

On the sustainability side, no material incidents throughout the year, which we're very pleased about. In the share repurchase front, we completed our share buyback program for the 2024, 2025 NCIB, which a big highlight there and getting through that program is we now have less shares outstanding relative to when the company was formed back in 2017; and two, expand on the growth that the company has achieved in a relatively short period of time. I think it's important to have an understanding and appreciation in terms of where we started, how our track record looks and what it looks like going forward.

So in 2017, 113.5 million shares outstanding for the company. Now there's 112.2 million shares outstanding for the company. What's happened on production. We've increased it roughly fivefold. Our 2026 production guidance is 44,000 to 47,000 barrels of oil equivalent per day. When the company was formed, there is less than 30 million barrels of 2P reserves and 18x increase to that number where we now have in excess of 520 million barrels of proved plus probable reserves, 4x increase on a reserve life index, now have a reserve life index in excess of 30 years.

And contingent resources, 0 contingent resources in the company when we were formed back in 2017, we had 1.2 billion barrels of contingent resources, very much the feedstock for organic growth the company. Share price was approximately USD 4 per share when the company was formed. And now we are up to around $20 per share. So it's been a great growth within the company and really a key focus on increasing and improving and enhancing the per share metrics overall. So expanding on the 2P reserves, 18x, as I had mentioned, in terms of the overall growth in reserves since we started. We've now produced 135 million barrels, which is shown in the light blue bars on this bar chart which is a significantly higher amount than the starting 2P reserves and also to highlight again here the red shading between 1 bar to the next is the reserve replacement that's been achieved.

So notwithstanding 2020, there's been material reserves replacement achieved by the company through a combination of acquisitions as well as through organic growth. And this is something that's not assumed going forward in our valuation numbers or our corporate cash flows in terms of achieving any reserve replacement despite having a proven track record of doing so. So what are we going to do over the next 5 years? If we just look at that 2P reserve position, we don't assume any contingent resource maturation and no M&A between 2026 and 2030, we expect average production of 62,000 barrels of oil equivalent per day between $65 to $85 Brent expect to generate between $1 billion to $2 billion of free cash flow.

And we have 3 key strategic pillars when we think about capital allocation for the company, which is organic growth, stakeholder returns as well as M&A.

Jumping to the production growth. So this is a slide that shows a little bit of backward looking our current year and is also forward-looking. What's important to highlight within this chart is, of course, we have meaningful production growth coming. If you look at between 2026 to 2028, we're expecting in excess of 50% growth in production as a result of the Phase 1 development project, Blackrod coming on stream represents around a 15% compound annual growth rate.

And you can also see when we made this decision to sanction this project back in 2023, we made a deliberate decision to accommodate capital for the growth project at Blackrod as well as shareholder returns in the form of buybacks, and there's been very shallow decline overall, and that's one of the key highlights within the IPC portfolio. It's a low decline business. And we've actually managed to keep our production per share flat through this period, and now it's going to grow quite high as we get Blackrod coming to first oil in Q3 of 2026.

And so this slide is an overview of Blackrod and really what's taken place over the last 2 decades. This is a classic story of long-term staying power. And when you have opportunity to get exposed to vast resource like an asset at BlackRock. You want to keep it, you want to maintain a 100% working interest and you want to keep putting capital into this asset through time to eventually get yourself into a position where you can sanction of development and extract and convert those reserves into production and ultimately into cash flow and monetize them.

So I think what is also important to highlight on this slide is really was Pearl exploration. It was the company that originally acquired some working interest in the Blackrod asset, and that was a company that was a majority shareholder was the family in that company. That company ended up merging with a company called BlackCore to form BlackPearl Resources, which, of course, we're also a shareholder in the Lundin family was. And through the years, there's been a lot of capital put into the asset for delineation works, pilot facilities, shooting 3D seismic, lots of wells have been drilled there.

And notably, in September 2016 is when we achieved regulatory approval or Blackrod -- BlackPearl did for the 80,000 barrel per day development. And so there's been 3 separate well payers that have been put forth at this asset, and all of them have been very successful proving the commercial viability. And so now we're finally getting to the stage where we're about to produce oil from the commercial development, which has been essentially around a 20-year journey. So very, very exciting to be getting to this point in time.

On the BlackRock valuation itself, the 30,000 barrel per day development that we're embarking on for the Phase 1 project, as 311 million barrels of 2P reserves. So we saw a significant increase in 2P reserves through 2025, which Nick and Chris will expand on in their section of the presentation. This 30,000 barrel per day development is an $850 million CapEx program to first oil. And that project -- this project is very much on budget. We spent around $820 million to the end of 2025. So very much derisked and the value of Blackrod Phase 1 project is $1.4 billion using a 10% discount rate based on our latest reserve auditor price deck.

The breakeven of the project is sub-$50, it's around $47 WTI for the breakeven. And what's really exciting as well at this asset is, again, regulatory approval to bring an extra 50,000 barrels per day forward at this asset. So the upside that exists is 1.142 billion barrels of contingent resources. And further to, as I explained on the prior slide, through time with the money that's been deployed and maintaining ownership within this asset through the different vehicles, there's been a substantial increase in the overall recoverable resource.

We're talking about in excess of 2x and even back a few years ago in the mid-2010s, about a decade ago or so now, let's call it, it was booked into reserves at a point in time as well. And so that really highlights that this project has been shovel ready for a significant period of time. BlackPearl Resources elected to develop Onion Lake thermal as opposed to going forward, with the Blackrod development.

And as a result of doing the combination with BlackPearl resources that we did at the end of 2018 going into 2019 is definitely very much a 1 plus 1 is bigger than 2 type of transaction, which has given us the financial firepower, of course, to go forward with this development. So what's valued today in our numbers is the darker part of the bar chart on the slide, and this is all upside that has not yet been valued here. And this is a contiguous laterally extensive reservoir that's fully connected.

So we very much believe in future phase expansions at this asset. And some of the recent history as well. We've learned, big fields get bigger through time. Of course, as I had mentioned, we've already seen that at the Blackrod asset without producing a single barrel from the commercial development quite yet, but also within Lundin Energy at Alvheim field, Edvard Grieg, Johan Sverdrup. These are -- the numbers essentially on the left-hand side is at the time of plan and development and operation, the expected 2P reserves.

The time of the sale when Lundin Energy went to Aker BP. That is the cumulative production as well as the point forward 2P reserves for the EUR. So there's been significant increases at those particular fields and the latest data points that we had. And on Onion Lake Thermal, coming from BlackPearl, of course, within IPC portfolio today, also a significant increase in overall recoverable volumes there relative to the time of sanction. So we definitely are excited to see this bar continue to grow on the right side, the Blackrod chart as we continue to mature resources into reserves.

Moving on to our second key strategic pillar as a company, stakeholder returns. So share repurchase has been an important part of the equity story within IPC. We repurchased 77 million shares since the company was formed at an average price of SEK 79 per share or CAD 11 per share. That equates to in excess of USD 1 billion in value created from all the share repurchase that have taken place compared to our current share price. So very value enhancing by doing those buybacks.

The normal course issuer bid program for 2025, 2026 has been renewed. We do have the ability to purchase up to 6.5 million shares, which represents around 6% of the shares outstanding. We haven't been buying back. At this point in time, we made steadfast and focused on executing the Blackrod Phase 1 development, and we're going to be monitoring oil price conditions throughout the year before we get back into buying back our shares.

Also on the slide on the right-hand side is showing the overall liquidity for IPC in both Stockholm as well as in Toronto there. So through '24 and '25, we've seen a pretty sizable uplift in terms of the value of shares traded, which was around USD 3.4 million per average trading day in 2024 and in 2025, that uplifted to 5.1 million shares. And looking forward into January and the beginning of 2026, we've also seen an increase in trading liquidity, which has been quite positive despite free flow coming down and insiders not selling their shares.

Cash flow per share growth, this is from 1 of our close banks as well. We've taken this chart to demonstrate what we really believe is going to create a lot of value for the company, which is the cash flow per share growth in the years ahead. So this is showing a basket of different publicly traded Canadian oil and gas companies. and this assumes a $65 WTI price, $3.50 AECO looking at to 2026 to 2030 in terms of the overall growth in cash flow per share on a CAGR percentage, you can see where IPC stands right at the top of that list.

Moving on to our third key strategic capital allocation pillar, which is M&A. And so we have a very profitable track record within IPC, all the assets that we have acquired and companies. There's been 5 separate transactions that have taken place in the company. Total acquisition price for all of these different acquisitions is around $940 million and excluding the Blackrod CapEx, those assets have generated in excess of $1.2 billion in free cash flow, so essentially more than paid themselves back.

And if we look at the free cash flow from -- our starting assets, those assets have generated a significant amount of around $450 million in free cash flow, so really an important metric for the company is free cash flow, and we're in this inflection point year here with Blackrod set to come on stream later this year. We're going to be positioned to generate really meaningful and serious amounts of free cash flow, which is very, very excited. And this slide is a testament to that as well, what we're showing is the enterprise value of the company is approximately USD 2.75 billion . And so this is a range of free cash flow sensitivities at different prices.

And you can see at $75 a barrel, we're looking to liquidate our enterprise value through the free cash flow generation of the company based on our 2P reserves. And of course, it's also important to note again here that we have a 30-year reserve life index, and this doesn't assume any contingent resource maturation either. Touching on the portfolio being very much weighted more so to Canadian oil. I think it was important to give a little bit of an update in terms of how the outlook is within the Western Canadian sedimentary basin.

So this chart on the bottom here is showing the total export capacity that exists within the Western Canadian Sedimentary Basin. And the black line is the total supply forecast as well. And the red line is the projected dip and the previous actuals for the differential WTI between WCS. And so as we've seen with new egress capacity coming on stream. That's resulted in an excess takeaway capacity and excess buffer, which has resulted in tighter differentials. We saw a differential of $11 per barrel average in 2025, which was one of the tightest years, actually the tightest year in the differential since the company stepped foot into Canada.

Also to note here with one of the most recent expansions to the export system in Canada, the TMX pipeline going to the West Coast of Canada. There's been a major uptick overall oil exports going to places other than the U.S. So I think that, that's going to be a common theme going forward as well as there still is excess takeaway capacity going to the West Coast and there also is low-hanging fruit opportunities to increase the takeaway capacity from that system as well.

On the net asset value when we started the company, it was $0.5 billion roughly was the net asset value. If we look at our NAV as at the beginning of 2025 using the latest and greatest reserve auditor price deck stands at around USD 2.2 billion. I think it's important to note, and Rebecca will also expand on that in her section that there is a material pricing adjustment to the reserve auditor price deck. It came down around $10 a barrel on flat price, which was quite significant.

And notably, it's a $62 oil price expected for 2026. And we're in a situation right now where prices are much in excess of that. So if we were to look at our net asset value using the year-end '24 price deck for the prior year's price deck, our net asset value looks to be at around $3.1 billion, not any value assigned to the contingent resources, of course. So we see significant upside associated with that. And our market cap today is around $2.3 billion. And the power of the growth of the buybacks is a slide we do like to show, which really shows the value that you can create through share buybacks.

And so what this mathematical calculation is demonstrating if also we were to do over a 5-year period is use the surplus free cash flow generation between 2026 to 2030 to buy back our shares, the point forward value of the company coming at the beginning of 2031 at a $75 oil price would be around SEK 500 per share, or 74 CAD per share. And at that point, you'd be effectively private with SEK of cash left over to be returned to shareholders. This assumes there's no insider selling taking place.

And in a more bullish scenario at $95 oil over the next 5 years, we would be at SEK 950 per share, CAD 141 per share. So with some of the good share price performance as well. We've updated these share prices and really is a testament to what the power of the buyback can do overall for the company.

So with that, I'll hand it to Nicki to touch on the operations outlook. Thank you.

Thank you, Will, and it's my pleasure to take you through the 2026 operations outlook, and then on through some of the asset detail with Chris Hogue, who will go through our Canadian assets. So just kicking off with our year-end 2025 2P reserves update and we're very happy to report it's been another excellent year for reserve replacement IPC, with positive revisions in all of our operating regions. The 277% reserves replacement has been largely driven by our ongoing job of maturing the 2C resource of Blackrod into 2P reserves, and then we eventually bring those resources onto production.

Also at Blackrod on the back of the very positive drilling campaign. We've seen an uplift in total volumes in the field, and you see that reflected both in our 2P reserves and in the next slide in our 2C contingent resources. So notwithstanding that increase to our 2P reserves and the maturation of those barrels from 2C, we have also seen an uplift in our 2C resources. We continue that track record of maturation from 2C to 2P reserves. But also, we've increased the volume of our 2P resources, which are now sitting at over 1.2 billion barrels of oil equivalent.

At Blackrod, we've acquired and secured some land around the Phase I development. And also, like I mentioned, on the back of the very positive drilling results, we've increased volumes there as well. So moving on to our 2026 investment strategy. And it's no surprise that the focus in 2026 is the start-up and ramp-up of our very exciting Blackroad Phase 1 development.

Elsewhere, there's a focus on production optimization, and we're really fine-tuning the next round of sanctionable projects at the other assets. And of course, at the discretion of the company, we can pull some of those projects forward if we feel the environment is right to do so.

Okay. So just moving on to our 2026 production forecast and very happy to announce our 2026 annual average production guidance of 44,000 to 47,000 barrels of oil equivalent per day. This is a guidance range that's very much underpinned by the performance and ramp-up of the Blackrod asset. And that's very clear. If I just draw your eyes down to the chart here, you can see through the first half of the year, our production is at the lower end of our guidance range and then ramps up through the second half of the year as Blackrod's brought online.

We expect to exit 2026 in excess of 50,000 barrels of oil equivalent per day. From an operating cost perspective, I'm very happy to report that our operating costs are stable. We've announced our operating cost guidance range of USD 18 to USD 20 per BOE in 2026. So with that very exciting production ramp-up and start-up at the Blackrod asset, it's no surprise that our capital expenditure forecast in 2026 is dominated at the asset. So we have around USD 90 million of spend in total at Blackrod in 2026, USD 31 million to complete the Phase 1 project.

And to take advantage of the economies of scale during our current drilling campaign, we've added 6 sustaining well pairs to that campaign. We've also made the decision to capitalize our operations costs until we reach first oil. And it's just worth pointing now here is there's a very low cost to mature our barrels from 2C resources to 2P reserves at Blackrod, and that's something we plan to continue to do into 2026.

So just before I hand over to Chris to take us through some of the asset details in Canada. I just want to touch on our 5-year outlook. And on the back of the very exciting production ramp-up at Blackrod this year, for forecast and our 5-year average production to be 62,000 barrels of oil equivalent per day. And in that period, we expect our operating costs to be very stable, around USD 17 to USD 19 per barrel. And on the back of a significant period of capital expenditure, our long-term sustaining capital outlook is around USD 5 per BOE.

And you can actually see where we've been from a capital expenditure perspective in the chart here. So we've had the heavier spend during the Blackroad Phase 1 project. That comes off now as we start to harvest more free cash flow from the assets. And the other thing I just want to mention here. This doesn't give any credit to the 1.2 billion contingent resources that we hold, and we have a track record of developing these into reserves and bringing them online. And with that, I'll hand you over to Chris for the Canadian asset overview.

Welcome to the Canadian asset overview. Located in Western Canada, Alberta and Saskatchewan, our flagship project, Blackrod is what we call the Athabasca Oil Sands area, the largest oil sands producing area in Alberta. 2025 was a big year, lots of key achievements. I guess the first thing really is we achieved steam in December of 2025. We did that by using progressive commissioning. You don't need all the plant right away. You only need certain areas of the plant to start to warm up the reservoir by circulating steam, down your drilled well pairs and getting the reservoir starting to heat up.

So by doing progressive commissioning, we can do just that. We can get using some of the plant and then use the circulation from that operation to be able to commission the rest of the plant. So we'll dive into that a little bit more. The workforce at site is approximately 300 people today. It is starting to come off from about a peak of about 400 people that we had. And it eliminates Q2 this year, we get down to wrapping up the project. All of our infrastructure to get our oil sales to market being our diluent pipeline coming in, our gas coming in and our dilbit pipeline going out is all in place and ready to go.

So we're just waiting for a ramp-up and we can start to sell some oil. Just to connect you with what we've built out here is a good visual kind of shows the tight neat package to develop 30,000 barrels a day. So you can see right in the center, that's the central processing facility that has big water handling plant. But that's where you do recycled water. You use all the produced water that comes back from the formation, you clean it to a boiler spec, you create steam and you steam all the wells from that facility.

pYou see well pad A up to the top left of that slide. There's a drilling rig on there now is drilling the Pad A South drilling pattern. You see Pad B over to the right, which is completed and ready to go. We are steaming wells currently on both well pad B and on well pad A currently.

Up to the top right of the slide is our construction count. So that is not permanent. That holds about 330 beds. There's a camp just to the north of that, that is our operations camp, that is permanent, it's about an 80-bed camp and that remains. And just south of that is our pilot facility that we've been operating for 1.5 decades now, really shows 30,000 barrels from a very, very tight package.

How did we get from first investment to first oil as quick as possible. So the strategy was to do a bunch of simulation simultaneously operations at the same time to ensure we can we can get that first oil as quick as possible. So there was a number of things that started at the same time. We only had engineering at a certain level of percentage complete. We had some regulatory work that we had to do off the beginning but we're able to deploy that strategy to make sure we kept that time from first investment to first oil as tight as possible, which is key to the project.

This takes into account a bunch of seasonal effects. We had to build a road going into this project. It's a 32-kilometer road. Most of it needs to be built in the winter time because of the type of wet road that we had to deal with, all heavy loads had to be brought in, in the wintertime when it was frozen as well. So the strategy for the construction, how to take into account those seasonal type effects. You can see the man hours now tailing off in '26. We've got a commissioning wedge of people out there. We are a prime contractor. So we've commissioned all this ourselves. We set our safety culture at the beginning.

We've stuck with the safety culture. We've had over 2 million man hours to date on the project. We've done it safely. So we've just really kind of held that safety culture as prime. And we're pretty excited about where we sit today to continue to bring wells on throughout 2026. Progressive commissioning. What does that mean a little bit? So we didn't need all the plant right away to start warming up the reservoir.

So you bring on the pieces of equipment that you do need first. So you focused our engineering, you focused construction, you focused drilling in the places that you need to get your first type of wells on. So we're able to do that, get steaming, get warming up the reservoir and then use those circulation returns to commission the rest of the plant. So it just works naturally and in sequence.

Stage 1 is complete. We're circulating now, and Stage 2 is well underway to start adding wells throughout the program. What are we producing? So we've got 3 drainage patterns online today. So you can see on the right-hand side, B North A North. So there is wellbores, 30 SAGD pairs there, representing 2 different drainage patterns, then there is a cell representing the third drainage pattern.

So between those 3 drainage patterns, we have the 40 wells that are included in the project, and we also have 6 sustaining wells that we will be drilling at the same time to capture the economies of success, the scale of economy, I guess, really to keep things going. We figure it's about savings in drilling costs, if we had a demob and then move back to do those 6 sustaining wells.

So we're continuing with that as we speak. Pad A South -- sorry, Pad B South is our future drainage pattern that we would look at some time in 2-plus years from now. Steam chamber development very key to ensuring that we are getting the recovery that we want. We need to sweep the oil from these drainage patterns and we need to sweep them very efficiently to run at the best steam oil ratio that we can extracting that 60% oil recovery that we expect to get out of the reservoir here.

So making sure that you have conformance, good steam from heel to toe as part of your warm up and steam chamber development period is very critical. So what I'm showing here is the top right, you can see the 2 well pairs approximately 0 to 4 meters off the base of the pay and then the well between the producer and the injector at the heel is about 6 meters apart. And then throughout the lateral, it is about 5 meters apart.

And you start to inject steam down a long string and up a short string, and you use the entity of ensuring you get saturated steam to the toe of the well to start to heat the reservoir. The bottom right is showing an example. So we have lots of eyes in the ground. We have fiber in the ground. So we have fiber that goes from the wellhead through the build section, all the way out to the toe. And you can read that fiber real-time, see what's going on and we can monitor how we are doing in terms of warm-up practices out there.

What I'm trying to show there is pre-warmup, you see a very cold blue pipe along the lateral section, heel to toe, and you see a red line about reservoir temperature around 16 degrees Celsius. Right away, on day 2 after getting some steam going, you start to see saturated steam and 200 degrees Celsius range starting to heat up the pipe in the build section, the intermediate build section to the heel. After about a week, we've moved steam progressively down to about halfway through the heel to toe.

And then at Week 2, we have optimized whereby we have saturated steam to the toe and that is where you want to try to get to. You don't want to push more than required because you're just wasting steam. You really need to get it right to, you get saturated steam to the toe to ensure you're using that condensation from saturated steam to fluid as part of getting that heat into the reservoir and ensuring that conformance is consistent across the heel to toe for the entire drainage pattern ensures that we get the drainage that we're playing from this resource.

Production ramp-up bit of an illustrative plot at this point, but it does bring a point of view to a few things. As we mentioned, we are ramping the wells up in steps. So you can see us moving towards 40 wells over the course of the year. And you can kind of see the production from the 3 drainage patterns starting to layer on. So within a 24-month period, we will be at our peak rate. Right now, we are planning to be at a 30,000 barrel a day peak rate by the end of 2027.

So Blackrod is a large, very homogeneous depositional environment whereby all wells look very similar. The reservoir is very similar across the entire play. That's huge because we have over 1 billion barrels of contingent resource that you heard earlier in the presentation, which we haven't valued, we haven't looked at. But at our discretion and when we feel it makes sense, we continue to add drainage patterns. We continue to plan out and design how we'd like to drill the horizontal wells into drainage patterns to grow the project and mature resource into reserves.

You can see in 2024, we added some drainage patterns. And then again, in 2025, we've added some drainage patterns to continue to drill. We're at the 311 million barrels of 2P today associated with the project. And again, at our discretion when it makes sense and the right time to use capital, we can continue to grow that resource, get ready for future other expansions of the existing facility, add another 5,000 or 10,000 barrels to the existing facility or do a Phase 2 growth, a whole other 30,000-barrel phase or both.

So it gives us the ability to be flexible when it makes sense for us. Jumping off our Blackrod flagship in Onion Lake Thermal, our other thermal project, so operating between 12,000 and 14,000 barrels a day has been for a decade. It has -- those are the drainage patterns you see in the bottom right, you see the A trough H drainage patterns. H is the next drainage pattern to do. The other ones are pumping and operating today.

In addition to those -- inside those drainage patterns, we use 4D seismic to figure out where oil hasn't been swept. There may be unswept areas and we're able to slide in infill wells, which we have done that. We're showing a few infill wells in there in 2025 to go ahead and ensure we're getting that maximum recovery from those drainage patterns. And then you can see a number of future drainage patterns. We've got a large resource here as well. But again, we have different capital projects whereby we could continue at this pace or we can accelerate some and put some capital into this facility, expand it and bring forward a couple of thousand barrels a day on this project as well.

So very exciting from there. Our results from our infill wells are excellent, and the wells continue to pump in a very, very good way.

Suffield area assets. So we have a mixture of molecules down here. We have gas through to some heavy oil. We like the gas, a bit of a natural hedge to against all the fuel gas that we do burn on our thermal project. So it's nice to have that gas down there. What we've done here is just through good prudent workovers, both on the gas asset and on the oil side asset, we're able to keep that decline to a minimum.

Without the right care and attention, the right focus to those ones, that decline would be twice what it is today, we're able to do that very economically and keep those barrels on production, continues to be a really successful story, these assets down there. We have an inventory of drilling locations set in here as well that at any time we could drill and the price is right, and we come -- improve the balance sheet a bit, we have some drilling targets here as well on the books that we can get at to both grow and offset further decline here.

Just kind of wrapping up with our other assets. Most notably is our Mooney project. So it's an enhanced oil recovery. It's a polymer flood. In Northeastern -- sorry, northwestern Alberta. It has been in the company portfolio for some time. We drilled it in 3 phases: Phase 1, 2 and 3 on primary horizontal production. It was very successful. We started flooding it with polymer in Phase I, had great results. We've moved the flood now to Phase 2, and we're starting to see very similar results as well. So very exciting on what we're seeing there. And there's additional expansion in Phase II to continue moving that flood forward. So we're very happy to see the success we're bringing with that project.

It comes to the end of the Canada asset overview at this time. Thank you.

Thank you, Chris. And just moving on to our international assets, and I'm just going to touch on Malaysia first. So on the back of a successful drilling campaign in 2025, the field development studies continue in Malaysia. And the focus really in 2026 is continuing the operational excellence that the team in Malaysia really have flown the flag [indiscernible]. We've not had a material incident at FPSO Bertam in over 10 years. And last year, and once again, we've had facility uptime in excess of 99%, which is almost unprecedented for this type of facility.

On the bottom right-hand side of the chart here -- sorry, on the bottom right-hand side of the chart, I just want to draw your eyes down to this, which is a very important part of the story, not just at Bertam, but really shows what IPC do. So original sanction, we sanctioned Bertam with around 13 million barrels of recoverable oil. And as you can see to date, we've produced way in excess of that.

And actually, to the end of economic life, we expect to produce almost double that. And that's not a coincidence or by luck. That's through the continuing development or maturation of 2C reserves into 2P reserves and continual infill well drilling campaigns, which give you value for that total resource. And not just the operational excellence we see obviously then helps with the value story. So this is a blueprint that we like to take forward in all of our assets.

Moving on to France, where we also have a history of offsetting historical declines through infill well drilling programs. And although it's not budgeted or in the firm 2026 budget, we have firmed up the next round of infill well targets, and we will sanction them at the discretion of the company when the environment is right.

The next round of targets set up in the northern part of the Villeperdue field and extension, we call Fontaine-au-Bron. So we have 3 well side track there that will be sanctioned when we feel that it's the right time to do so. Before moving on to the budget summary, I just want to touch on sustainability. Safety performance is at the very foundation of operational excellence and operational excellence is something that we really pride ourselves on IPC.

I'm very happy to report that we've had no material incidents since inception. In 2025, we issued our sixth sustainability report. And from a climate perspective, we remain on track to deliver our 50% net emissions reduction to 20 kilograms CO2 per BOE, and we aim to maintain that through to the end of year 2028.

So in summary, for 2026, very happy to announce an annual production guidance range of 44,000 to 47,000 barrels of oil equivalent today, a range that's very much driven by the ramp-up of the Blackrod Phase 1 development. With the ramp-up of that Phase 1 development, our 5-year business plan targets 62,000 barrels of oil equivalent per day on average.

Our investments in 2026, really focused on bringing that asset online and ensuring the best possible fastest ramp-up there. We have the ability to ramp up our investments at the other assets, and we will do it if the right environment happens. From a reserves perspective, we've continued that track record of maturing our 2C resource into 2P reserves. We've had 277% reserves replacement year-end '25, which takes our year-end 2P reserves to 521 million barrels of oil equivalent.

And with that, I'll hand you over to Christophe for the financial overview.

Thank you very much, Nicki. Good afternoon to all. For those of you who've been here for a few years, you know that we like to give you the opportunity to actually pick up the price deck you want to analyze IPC under. And so from the -- from a base case perspective, the market has told us what to use essentially So we're using a Brent price of $65 per barrel plus or minus $10 for low and high case. We've been a bit conservative using a $5 differential from Brent to WTI. And we've seen the differential between WTI and WCS slightly widening at the beginning of this year.

So it was minus 11 last year. It is now currently around minus 14. I'll show you we have some hedges at minus 12.5, but for the purpose of running our base case here, we're using minus 14 between WTI and WCS.

And you can see the reference of the actual realized prices in 2025 on the right-hand side. For the [ EcoGas ] prices, we were a bit optimistic that it's going to continue to improve a bit. In 2025, the gas prices were a bit depressed. The storage levels were reasonably high. We are making -- not we, but Canada and Shell with the LNG Canada project are making progress, and they brought on stream the second train of that LNG plant on the West Coast side in British Columbia.

And so we believe that it's going to help unwind a bit those high level on the gas storage, long story short, we're using CAD 225 per Mcf for our base case and across the low and high case. But again, as usual, and to help you navigate and pick your exact your in-house price deck, we're giving you as well sensitivities about what the impact on cash flows would be if the WTI WCS differential was to widen or tighten by $3 per barrel.

And same thing with the gas prices, we're giving you the cash flow impact of 1 -- plus or minus 1 Canadian dollar per MCF impact on prices. Again, if you've been following our Capital Markets Day over the last few years, you noticed that we usually give 2,000 barrels a day range for production. Of course, we're at this turning point where -- in Q3, we're going to turn on finally, the production at Blackroad Phase I the ramp-up is going to be reasonably steep and fast.

But of course, if you take plus or minus 2, 3 weeks of delay or acceleration, because the ramp-up of the production is very steep, it's hard to actually pinpoint only 2,000 barrels of production range. So we've widened it to 3,000 from 44 to 47 for the whole year. Very happy to report that we're finally off the peak investment years. We've had 3 heavy years of investments year to until the end of 2025. We spent USD 820 million of CapEx at Blackrod Phase 1. We're going to invest only $122 million this year, and the bulk of it is really focused on delivering the first oil at Blackrod.

Same comment on the -- for the production range and the operating cost range. We usually give a narrower operating cost range. Here, we're using 18 to 20, the reality is that in the early days of Blackrod, sorry, the operating cost per barrel are going to be slightly higher, so that's why it's moving roughly from $18 in '25 to $19, the midpoint operating cost per barrel in '26.

As soon as we get into 2027 with much more production coming from Blackrod, you should expect that operating cost per barrel smoothly go down and reduce down to $18, if not below. So when you wrap all of these assumptions together you can -- taking into account, of course, the gas prices. The revenue on a netback basis are in the range of $38 million, around $38 million with operating cash flow of $10 EBITDA in the same range, just below at $9.5 per BOE and roughly breaking even in terms of free cash flow at $0.2 per barrel for the whole year.

If you look at a bit more granularity approach, very consistent with what we've been telling you years after years. In Malaysia, we continue to enjoy very strong premium over the dated Brent we're selling our -- we're assuming here that we're setting on Malaysian barrels at $4 premium over the dated Brent. And the reality is that we tend to achieve and realize higher prices. That was the case in the fourth quarter 2025, and we've already sold our next cargo in March.

And we've realized already a higher premium than 4. In France, we're selling roughly on par slightly below dated Brent. And for the Canadian heavy barrels, we're assuming we're sitting exactly on parity with the WCS and a very small premium on our gas price for gas realized prices for the Suffield assets. You know what we've been telling you in the past and that's still very much the case. We usually like to leave our investors with the choice on how to manage their own exposure to commodity prices.

with the exception of 2 cases when we would have significant debt maturities or when we would face when we would be in the process of massively investing. Those CapEx years are over. We've refinanced our bonds, so we have no material CapEx, no material debt maturities in 2026. That being said, the oil prices have been a bit on the weak side. And so we've been opportunistically taking advantage of some blip in the market to secure slightly better oil prices than in our base case. So you can see here -- we've managed to hedge 1,500 barrels a day of Brent at $66.7 per barrel, so higher than of $65 base case level.

Same with WTI. We've hedged until the end of June 7,500 barrels a day at $61.5 per barrel. Originally in late last year, we hedged 5,000 barrels a day of the WTI WCS differential at minus 12.5. Frankly, the idea was to protect us to take the business and the cash flows against any potential leak or anything can happen on those pipelines.

We didn't know about Venezuela, but the reality is that with a few barrels from heavy oil from Venezuela hitting the U.S. Gulf Coast, the differential has widened to minus 14, that hedges protect us against that unexpected event. And you can see here that we've locked in some very decent gas prices for the summer period between April and October at CAD 2.8 per Mcf.

So again, what does that mean in terms of netback. Again, we're giving you those netbacks and so you can pick which production you believe is renewable to assume for the whole year 2026. On that basis, depending on whether you're looking at the low base or high case, you will see in the base case here. So $38 of revenues netback with $19, which is the midpoint range of operating cost.

It translates into $10 per barrel of cash margin or operating cash flow. That compares to $15 -- almost $16 per barrel in 2025. So you can see that if we can hedge a bit more at higher prices or if oil prices are a bit more optimistic that will have a significant immediate impact -- positive impact on netbacks. This is hopefully an initial view of what 2027 holds for us. So I was telling you that in the early days, the operating cost per parallel in Blackrod are a bit higher than on a normalized basis.

You can see that while production at Blackrod is ramping up in Q3 and more significantly in Q4. The operating cost per barrel are driving down, within that $18, $20 range. So you can expect that trend to continue into 2027. Looking at the operating cash flow. So we won't be paying cash taxes at $65 Brent that translates into an operating cash flow netback of $10.4 million, in line with the cash margin netback.

If you look here in terms of profit before tax, once you've deducted our depreciation and depletion, some very light exploration costs, G&A, which remain at $1 per barrel and financial items, which are reasonably constant at around $3, of course, a bit more or less depending on oil prices and how much money we'll have to use and draw under the revolving credit facility translates into profit before tax of negative $2 per barrel in the base case and negative $2 on a net profit basis as well.

I think that's an important slide, again, going back to how you want to play with your own model. You see that widening or tightening of the WTI WCS differential of $3 will impact your operating cash flow by 1 -- plus or minus $1.2 per barrel. So that translates. If you take the midpoint production guidance range, that would be 45,500 barrels a day times [ 1.2 ] is $20 million. So effectively for $3, on the differential that translates into an impact of USD 20 million of operating cash flow.

And $1 upward down -- a CAD 1 up or down per Mcf on the gas price would impact our operating cash flow by plus or minus USD 10 million. You can see here going from the operating cash flow netback to the free cash flow netback. So we're breaking even at -- on the base case, but with some upside if differential were to be better if we can lock in further hedges in the weeks and months to come. It's a bit sad, but the reality is, there is some political and stability or tensions will probably use those opportunities to hedge a bit more.

The capital structure is reasonably unchanged effectively what we did end of September and early October. We refinanced and so extended the maturity of our bonds. We benefited from good market conditions by then. And it was pleasant to see a lot of bond investors continuing to support us. So our coupon moved from 7.25% to 7.5%. That was really the result of higher base rates but the credit spread shrank at that time as a testament to the quality the business of IPC and the strength of our balance sheet.

The rest has not changed. We still have access to CAD 250 million of revolving credit facility from our Canadian banks. Maybe just one word here, because we were able to book PDP reserves at Blackrod, we will have the opportunity to increase that Canadian revolving credit facility with our Canadian banks if we wanted to because traditionally Canadian banks lend against the value of those PDP reserves. And now we have PDP reserves at Blackrock. And that's it for me. Thank you very much.

Thanks, Christophe. So Will has taken you through our short-term cash flows and what we're looking to do in terms of strategy for IPC in the future. Chris and Nicki of taking you through the project, Blackrod with -- so close coming in Q3 this year and also our base production and how well we're doing on the base and then we've got Christophe, who's taken through our liquidity, strong balance sheet, good position, ready for the second half of this year, which is what we're all excited about, I think. So -- and I get to do the fun part, which is the long-term valuation.

Not as fun when you look at the long-term pricing forecast, but this is a pricing forecast that's put in place by our reserve auditors at a point in time, right? So Will was saying before that they came down to $62 a barrel in 2026. Well, we're at the beginning of February, and we're already at $69. So you can see that you can almost pick your price deck and decide where the value of IPC sits, but we think this is just a 2P position as well.

Our value is a lot more extensive. And it's more extensive on press and it's more expensive because of our contingent resources. But we'll get into that also. And more than $10 drop actually. So for the front 2 years, you can see $15 to $18 has come off the reserve auditors price deck. And we're also off a bit on gas. It's clear that the reserve auditors and actually most of the Canadian markets still think that the gas price will come back up to those sort of 3 levels.

And Christophe explained a bit about the Canada LNG situation there, which should clear up some of that storage position in Western Canada. And so net present value. And so if you look at this graph here, you can tell at the bottom, in the red line, this is the 5-year average of the reserve auditor price deck that we use, which happens this year to be ERC's pool.

We had an average of $80, which you saw on the previous graphs, and then that's dropped to an average of $70. But importantly, what I want to point out here is year-end sorry, year-end '25, at year-end '25, if we run that price deck at the year-end '24 price, so we just pulled it back here, you can see that our value goes from $3.3 billion at the end of year-end '24 to $3.6 billion. And what does that mean? It means that technically, we've been extremely strong, and we have increased on a like-for-like basis the value of our underlying assets.

And then we have a $2.7 billion, which is still coming up close to $3 billion valuation at the end of year-end '25 using the new price deck. What does this all mean? So my favorite technical words this year have been contiguous and extensive lateral reservoir. So if you look at what that actually means, you come from a technical perspective and we're economists in this room mainly. And you realize that what that translates to is reliable reservoir, and that translates to reliable cash flows. And that's why you see here between an NPV10 1P and an NPV10 3P, it's a really close range, right?

So you can see the upside sitting there at $3.4 billion. And even on a downside case, you're still up close to $2 billion. and that is really a reflection of Blackrod and the reservoir that sits underneath all of these numbers. And we are mainly now an oil sands focused company. You can see that 75% of our value sits in oil sands, 50% of it in Black rod. And this is really important because it is the underpinning of long-term cash flows into our forecast.

Lukas Lundin always used to say to me, Rebecca, you've never got a number that you couldn't discount. So you used to say show me the cash flows. So here we go. This is it -- this is the Blackrod Phase 1 cash flows from $65 to $85 a barrel, is undiscounted and before taxes, but what it does do is it shows you the longevity of these assets. This is how you create generational value. And this, again, is just Phase 1, right? So $65, you're going to generate between $180 million and $300 million of cash flow a year between $65 and $85. And this is there for the next 30 years. We couldn't even fit it on the graph and then you will replicate this time and time again to create the real base of the company. And having shown you this, I'm then going to pass on to Will to talk about how we're going to return value to shareholders will. Thanks, everyone.

Great. Well, thanks very much, Rebecca, and rest of the team for the solid presentation overall, creating generational value. It's what it's all about. And so we remain steadfast on executing and doing within the company overall here. So production 2026 guidance, 44,000 to 47,000 barrels of oil equivalent per day, an uptick relative to our 2025 numbers, largely as a result of Blackrod set to come on stream in the second half of this year.

We expect a 50% increase in our average annual production from this year to 2028. That is coming very soon. Growth Blackrod Phase I 311 million barrels of 2P reserves assigned at the Phase 1 project, represents USD 1.4 billion in value using a 10% discount rate. Cash flow generation between $65 and $85 Brent is $1 billion to $2 billion in free cash, balance sheet.

Again, we've got the bond refinancing complete at the end of last year. As Christophe had mentioned, in favorable conditions, we also have CAD 200 million of revolving credit facility availability through our Canadian syndicate and shareholder returns in excess of 27%, absolute share reduction since 2022 relative to where we stand today. It's really turbocharging that production growth and cash flow growth with less shares outstanding is really what we believe is going to translate into significant value creation for our stakeholders.

M&A, 5 acquisitions since inception. We remain opportunistic at growing through M&A and safety focus, again, no material incidents since inception, which is super, super important for us given that we are operators of all the assets that we have within the portfolio. So I'd like to give a special shout out as well to the worldwide teams in IPC for everyone's dedication and commitment and hard work to a tremendous year in 2025, it's going to be a really exciting year in '26 and the ones ahead.

And of course, to the other IPC personnel that are here on the stage with me and also in the audience here. Really appreciate all the commitment and hard work given to the company. We are very well positioned to create significant value for our stakeholders. So with that, we're ready to jump into Q&A, which is we can field questions from the audience and then also can be submitted via the web.

Congratulations on a strong quarter, and thank you for presentation as always. I have a question regarding Blackrod Phase 2. What do you need to see from Blackrod Phase I before sanctioning the project.

Yes. No, it's a great question in Blackrod Phase 2. I think that resource is there. It's well delineated, well understood. And so it's largely going to be a capital allocation decision that's going to take place to bring forward a material expansion. As Chris had shown in his portion of the presentation, we retain a lot of flexibility in terms of how we want to bring those contingent resources forward into reserves, whether it just be tying back to the existing central processing facility, expanding our debottlenecking the Phase I or developing a brand-new CPF as well.

So it's going to be a balance of looking at liquidity conditions, oil prices and also seeing how the performance of Phase 1 comes along as well and if there's any lessons learned that we can take into account from that into a future growth expansion.

Thank you. Echoing all our great presentation, as always. And I have a question on the Phase I actually and not being an engineer, we rely on your estimates on time to -- from first steam to first oil. So does the 6 to 9 months estimate still -- that's still in play. The question is really when in Q3, should we expect first oil?

That's a good question. I mean we haven't been specific on the exact month or data deliberately. I think we're really well positioned as things stand. And as Chris had shown in terms of the heat conformance that's starting to take place early out of the gates on some of the well pairs that we're circulating, steam under things look really good at this point in time. So we're confident to be able to deliver within that Q3 estimate for first oil. And depending on things -- how things go, I think there might be a little bit of upside on that as well.

Clear. Will and in terms of funding, this is probably for you Christophe or both of you. I guess now, as you said as well, answering the question a bit, you probably have more capacity now given the 2P reserves that you have on Blackrod and strong balance sheet with less than $1 per barrel in 2p in debt in general. So to fund further growth, what do you consider the most in terms of funding opportunities, strong access to the bond market, of course, but also probably more secure funding options as well?

Yes. No, you're absolutely right. If we want to deploy further capital in our portfolio, we can raise more debt effectively if we wanted to look at some M&A opportunities that could be a combination of raising debt on the targets and maybe issuing further bonds, if those were very long-term cash flows, I think the reality is that in terms of leverage whether it's early or later in Q3. When you get to first oil, that is when the business is going to deleverage.

So in terms of trajectory, you should expect the leverage to continue to grow before dropping again. So it's probably not the right time to releverage right now as we speak but effectively in the -- towards the end of this year or early next year. It's something that we could consider if we wanted to sanction any new projects or consider M&A.

Makes sense Then the last 1 from me is on M&A. What -- do you have any comments on region and type of assets that you will be looking at now? Is it Canada primarily and what type of asset would be a good target for you at this stage?

Yes. I think our message on growing through M&A has been pretty consistent in the past and really hasn't changed as well where we have existing areas of operations that make sense to grow in those jurisdictions, mainly the likes of Canada and also in Southeast Asia as well. So these are areas of interest given the footprint that we have existing there and the relationships as well with the key contractors and people in place, but we are also opportunistic and growing elsewhere within the world.

We've done a number of screening opportunities in other places outside of Malaysia and Southeast Asia also and West Coast Africa as well. We've looked at things in Latin America also. So we really remain opportunistic at our core. But I think also what I would add to that, too, beyond geographical location is something that we'd be looking at, what we're interested in M&A and that's in production.

We're very long resource as a company, clearly, with all the contingent resources and the barrels that we have in place. So when looking at M&A right now, the priority focus is something that's in cash flowing, it's been in production and ideally has low leverage to it as well.

It's kind of a 2-part question around your CapEx program going forward. So we see a bit of a step up in '27. Is that just reinvestment back into the legacy assets? And then we see a material drop in 2029. Is that related to like the timing of sustaining well pairs? Or is there an asset that comes offline because it does bounce back in 2030?

Pardon me, do you want to take that, Nicki?

Generally, what you're seeing there is a combination of investment in the legacy assets, if you want to call them that, and also the next sustaining pads like on Onion Lake thermal. And the reason you see it fluctuate is because these pads come on between 18 and 24 months. So you will see variations in the year. But I think what's notable here is the major step down from '25 down into the future, and that's what we're trying to highlight.

Got you. And then like in 2028, when Blackrod's fully up, your corporate breakeven will improve materially do you foresee yourself becoming a dividend-paying company or will return of capital be exclusively geared to buybacks, whether it's through an NCIB or an SIP again?

We'll retain the optionality, ultimately, of course, in terms of dividends or buybacks. We really believe in the power of what the buyback can do, as I showed on the previous slide there. But when it comes to that point in time in terms of making the decision whether to go dividend or buyback, we're going to look at the return potential under both mechanisms. Also compare that and weigh that against investing within the portfolio through an organic growth perspective and essentially what delivers the best set of returns in our view, will dictate which form of shareholder returns we decide to pursue.

I had a couple of questions. One is on -- you touched on Venezuela and the widening of the spreads. I don't know if you could -- what's your best guess as to the delta of barrels that could actually impact Canadian exports. And maybe linked to that, the upcoming USMCA negotiations and what that do or not for Canada. Then the second question, given that the current price take it sounds like Blackrod is probably going to go post payout later than you thought before, with the Onion Lake Thermal expansion make more sense. And when you think about acting on that?

And then my last question is on gas. As you go towards the end of the decade and you become net gas consumer, and if your view is that gas prices are on the up, are you worried there or what are your options? I think Chris mentioned there is some inventory in [ Suffield ] area that could be tough. I don't know if that -- that's an option. But just generally trying to understand gas resource for you.

Yes. Thanks very much. I'll try and head those off, starting with your last 1 there in terms of the natural gas position. So we do enjoy being a net long position on the natural gas position within Canada, which essentially means we sell more gas than we consume, which is ideal from a thermal producer standpoint. And then that net long position based on the latest reserve reserves that's been executed, looks to be around '29 or so and that inflection point where we start consuming more gas than we're selling.

And if we see gas prices go much higher relative to current levels, we are sitting on approximately 25 million barrels of contingent resources at Suffield, whereby we could increase additional natural gas production in the block there if prices were much higher relative to where they are today. However, in saying that it's a nice have and it's not a key priority to ensure that we're always in a net long position. If there's an M&A opportunity that has some gas components to it. That is a nice attribute in terms of trying to extend that net long vertically hedged position that we have in terms of some of the other projects that we have within the portfolio based on the reserve auditor price deck that we've seen, some of the expansion project, Onion Lake Thermal, we've pushed out into our long-term plans as a result of that.

And what's really important in the company, given that we operate all the assets is that we mature all expansion growth projects to the best of our ability to put the company in a position where we can decide which project is best to allocate capital towards when the time is right to do so. So that will be continued refinement work taking place throughout the course of 2026 on that. And then, of course, Blackrod is going to have some sizable expansion opportunities, which also will be consistently worked on.

And so within Canada as well and the differential outlook, I think what's important to highlight, if I just take a step up here and point to this graph, specifically or the map pardon me, from Canada and the Western Canadian sendimentary basin, the vast majority of the barrels that get exported from the country do land in this pad 2 area. It's around 2.5 million barrels per day. And at this level here, there's no pipelines that flow up north going to this region and that pad specifically, and the refineries are geared to take the heavier crude at that location.

And then there's around 0.5 million barrels or so that goes to the Gulf Coast as well. And so this is the area where there could be some competition for Venezuelan crude. When we entered the beginning of this year, the forward differential was around just at $12.50 around -- just under $13 a barrel for 2026, the differential between WTI and WCS. As a result of the Venezuelan commotion, we did see diffs widened by $1 to $2 predominantly because of the potential competition of the similar grade given that there's heavy refineries processing that type of crude in the Gulf Coast.

But what we have seen is increased exports going to Asia and other markets as well. And I think what's interesting here is that with Venezuela, if it's no longer sanction cheaper barrels that are being purchased from China, then China is going to look to continue to increase and hoover up more barrels from Canada and the logistics to get to Asia from the West Coast of Canada as opposed to from Venezuela is a lot more favorable from that point.

So despite a slight uptick in the differential, we still remain very constructive and positive about the overall outlook. And it is also very much grounded in the situation where there is excess takeaway capacity relative to the supply. And with some of the promotion that's been taking place between the neighboring countries in North America, I think the large demographic of Canada recognize that you need to have more flexibility and be able to have more diversification, possibility to send more barrels away from the U.S., and there's a number of major projects, the Northern Gateway project being one of them, which we're hoping to hear more about later at some point this year, whether that goes forward, which would be 1 million-barrel per day pipeline to enhance this overall, which is not assumed in these numbers put out. Curtis, it looked like you might

Just a couple of quick questions. First, just on the buybacks. Over the past 3 years, you've fully utilized your buyback even when you were outspending cash flow. This year, you're pausing on the buybacks right now even though you've switched to positive free cash flow. So just curious, what are you waiting to take place before you do start initiating buybacks? Are you just waiting for Blackrod to be completely built? Or is there a certain WTI price in mind?

Thanks, Amir. Yes, we're really taking a position of prudence when we're thinking about 2026. I mean, of course, our net debt has naturally risen as a result of the spending program that's taken place largely at Blackrod and the share buybacks that have been undertaken by the company. And so it's really going to be a level of monitoring oil prices, liquidity headroom Blackrod starting up. We do have that NCIB renewed. So it gives us flexibility to be able to initiate buying back shares.

But for the time being, we feel the prudent move is to hold on shareholder returns for this very moment in time.

And the second question is just on Blackrod in terms of PDP reserve bookings. Was there any Blackrod booked last year in PDP? Or has it all shifted into in '25? Is it fully

booked in PDP?

Yes. Those -- we had 2 pads that we got PDP recognition as we achieved steam circulation first steam in December there, and we had some oil circulation returns coming. That resulted in approximately 40 million barrels of high-grading classification of reserves for Blackrod Phase I into PDP classification.

And In terms of the ramp-up phase, what are kind of the key activities that may push the first oil back or forward that we need to pay attention to throughout this year. And the risks are around them, please?

Sure, I can take that. Just make sure I heard your question correctly, but you're asked about what kind of key activities need to be underway to ensure first oil shows up at Blackrod?

Yes. More like what are kind of the key elements of the ramp-up phase that could kind of push the time of first oil.

Got it. Yes, very clear. So we underpinned everything from our pilot. So well pair 3 had a warm up cycle. And then we talked about that a little bit earlier on how much time we need to do before we will be able to put pumps in the ground to start the ramp of the production ramp. So we do have a strategy and a plan in place based on 10 years of operating out there already. And we're on that line. So the key things are once we need to confirm conformance. So after we put a volume of circulation in the ground over a certain period of time, we start doing what we call falloff tests, and we started doing pressure cycling.

So we can confirm that we are having good conformance in our drainage patterns from heel to toe, we are seeing proper heat out in the reservoir. So that's our first indication before we can really move into production mode. So make sure that we do get good heat and conformance throughout the drainage patterns. That's one. And we believe, based on the strategy we have, there is a little upside there, but we're holding and underpinning what we've done with our Well Pair 3.

So then the second piece to that is actually stripping out all the circulation completion and installing the completion for production. So that's the second big event that we need to do, and there's capital associated with that. And that is the next big thing to do, and we expect to start doing that kind of in the Q2 this year, so then we can really start the ramp. And that's when we call it our ramp to 30,000 barrels as we start to put artificial lift in the ground, these ESPs that we are using. That's the second component. And then the third, I guess, is, and we're already there on that one.

Now that we've kind of derisked that is just to make sure that facility is ready to handle all the oil production. The facility is ready to treat all the produced water that is coming back to it, so we can create boiler feedwater, so we can continue to steam the wells and warm the reservoir. So we're quite far ahead on that third step of making sure that the facilities are ready to go. But that just -- that continues -- its kind of the 3 steps to get our ramp to 30,000 barrels. I hope that answers your question.

Yes. And then on hedging, so some of the feedback when we did the bond issue was your hedging activities. And you've done some hedges already in now. Can you -- when you kind of move into a next phase when Blackrod is on stream, can you elaborate a bit on kind of what kind of hedging strategies you would consider?

Yes. And I think as Christophe laid out in his portion of the presentation, there's 2 conditions that where we're a little bit more open towards hedging, whether it be large capital expenditures or debt maturities coming up, and we don't have a strict hedging policy in place, but it is largely an opportunistic one. What we really did enjoy was back in 2022 when we had zero headline benchmark oil hedges in place. And of course, $100 oil environment, we printed $430 million in free cash flow.

So I think it's likely to expect that Bond Blackrod ramping up and looking more forward into '27 and '28. It's probably less likely that there will be many hedges in place as there has been in years prior.

And then on financial policies, like when you get kind of complete this year and you get more free cash flow generation, would you have any kind of target in place on leverage?

Don't have a particular target on leverage. We have said in the past that getting to below 1x is a reasonable level that we'd like to be at. And I think through time, we're going to be going into a rapid deleveraging situation upon Blackrod ramping up, but there's no strict framework that relates to Stewarding into an exact leverage ratio.

Okay. First of all, congrats on a strong 2025. And also I have 1 question on topic of have already touched upon. And as you showed on one of your slides, the NAV per share shows significant upside if cash is used for buybacks going forward. How do you balance the Phase 2 versus kind of aggressive share buybacks and capital returns given your discount currently to NAV?

Yes, it's a great question. And bringing back again to that 2022 period where we generate a significant amount of free cash flow for the company, and we also progressed FEED studies on the Blackrod Phase I development. We put ourselves in a position where we are in a net cash position. And we made the decision to sanction the Phase I development project, but we also scaled back on the base business investment on our existing producing assets to accommodate for shareholder returns in the form of share buyback.

So what we're going to be doing is trying to strike that right balance. We feel like our capital allocation measures have been deployed in the right way previously. And it's always going to be looking at the lense of what's going to get the best returns and what's going to maximize the value for our shareholders.

I just want to follow up on the previous questions regarding buybacks in this year. Do you see a firm kind of oil price environment when you can unwind buybacks.

Appreciate the follow-up. We're not going to get drawn into a particular oil price specifically in terms of what will dictate when we go back in. We're going to be monitoring oil price conditions, liquidity headroom, Blackrod progress, which we very much believe in to continue to go well and when the appropriate time to do so to return value back to our shareholders in the form of buybacks will be a decision taken by the company.

All right. And a brief question as well. Blackrod breakeven, you guided it $47. Do you see any kind of cushion for this breakeven guidance in a lower price oil environment?

Or can you elaborate on that, please? I mean what's kind of -- what oil prices -- I mean kind of -- is it reasonable to assume in the lower price environment that this breakeven level could be lower in case, for example, input cost will be lower as well?

It's a good question. I mean you obviously have things like chemicals that sit in your operating costs, which are then sort of oil price dependent. There's a couple of factors like that. Big one is gas price. If gas price moves down, obviously, your breakeven will also move down at the same time. So there's a few sort of dependent factors on price that will push that breakeven at a lower level if you have a lower level of oil price.

Okay. But what prices we're used for this 47 [indiscernible]

There is full oil price deck again. So your gas price is $3 plus and then your -- I mean the chemicals price is at the current oil price is full price deck, we haven't messed with that for the breakeven. So it's at the $70 long-term price deck.

We're using the OpEx as they are in the base case. And so we're reducing the WTI price down to the level where the NPV 10% would equal 0. That's how we calculate that breakeven. And then you have 2 realities, which are a bit contradictory. We look at ourselves as essentially a fixed price, a fixed cost business. until 2020 because in the COVID days when oil prices were so low, we realized that actually, there was -- we could further improve and reduce OpEx.

So in a normal, whatever that means in a normal oil price environment of OpEx are reasonably fixed with the element of the gas price, which may go up or down. But in a very low oil price environment like 2020, we realized that actually, we could further reduce our OpEx. So it's a very good question and a long way of explaining that. What I'm trying to say, I guess, is that that price -- that breakeven price could go lower in a lower oil price environment. But we have to keep all the assumptions the same to calculate the breakeven to be intellectually correct

Okay. is that it from the audience. Yes. We have some questions from the Internet. So I'll just run through those quickly. Nicki, perhaps you can comment on this one. If prices increase to $80 to $85, do we have any sort of quick production wins that we could put on to the books from our base portfolio?

yes, indeed, we have a number of opportunities that are ready for sanction. The pace that they would come on depends on which opportunity we decide to sanction. And again, that would be something that we look at, at the time, dependent where are with the Blackrod project and the general environment.

Okay. Great. Chris, just a question on potential Phase 2 execution time about how long after sanctioned do you think we could get a Phase 2 up and running?

Yes. Great question. We're able to utilize some of the existing infrastructure we have now to bring Phase 2 on, things like roads, things like some of the existing pads, the tank farm, the gas line, the dilbit line. So we don't require the full time frame that we had did before, but it's probably 2 years.

Perfect And I might flip this one to Curtis, who's our VP of Marketing from Canada in the audience. And the question is, how do you intend to market the Blackrod barrels, Curtis?

Thanks, Rebecca. So I guess our view is that landing heavy oil in Edmonton has never really looked better than it looks today. We have a number of refining customers as well as global customers that are really excited to see a new barrel come down there. We can move west, we can move east, and there's a really constructive picture right now in order for us to be able to get the best value for that barrel?

Yes. Great. And perhaps you can pass that to Ryan. We've got -- Ryan, just a general question about recovery factors for the Blackrod barrels like a 2P and contingent resource level.

Yes. Thanks, Rebecca. And so just to tie back to a point that Chris made earlier, we have over 10 years of pilot history at Blackrod, which gets us very well grounded in what we can expect in terms of recovery factor and steam oil ratios. So Well Pair 2 and Well Pair 3 are both pointed to that 60% recovery factor range. So in terms of our base case, we're looking at 50% to 60%.

Okay. Perfect. Christophe, just maybe on these operating costs, can you just explain how we expense them preproduction on Blackrod, how that works and then how it will work going forward with Blackrod's operating costs?

Yes, you can do it in a couple of different ways, but the most logical way is that you capitalize all the operating costs until first oil, which is what we're going to do. And so those capitalized costs are part of the CapEx program in 2026. From the day we turn on the commercial production at Blackrod, we'll be accounting for those OpEx as what they are, i.e., OpEx.

Okay. And perhaps we've got even more questions on M&A here. It's obviously Blackrod Phase 2 versus M&A. Would you be looking at Canada, how would we fund that?

Yes. I think it's the classic response in terms of capital allocation considerations and again, what's going to give us the best bang for our buck. And we're very fortunate to be in a position where we are as long as resource as we are. So as we mature the development plans at the likes of Blackrod for future phase expansions, understanding what type of economic enhancements that's going to deliver to the business and having being able to benchmark that against looking at M&A opportunities ensures that wherever the capital is going to be deployed is going to be the place that gets the best value for the company ultimately there. .

And one of my favorite questions so far, which is commodity prices if they go on a run, when do you no longer need to or want to hedge?

Yes. No, exactly. I think when I had mentioned in 2022, we're in a really strong position. The balance sheet was in good shape. Our leverage ratio is very low. And so we enjoyed being in a position where we gave our investors exposure to commodity prices. And I think that's a traditional theme across Lundin group companies, generally speaking as well. And so as we look to get a sizable increase in our overall cash flow generation coming from the Blackrod asset it's likely to expect there won't be a lot of benchmark hedges in place. There may be things like differential hedges or other condensate hedges or things of that nature. But in terms of benchmark, hedging likely looking forward into '27 and the year beyond that subject to what's happening in the oil market conditions, of course, there's less likely to be a lot of hedges in place.

Okay. Great. A couple will have just come in, yes. It's probably, Curtis, on this one. Would you be looking at pipeline capacity for Blackrod to export barrels.

Yes. We look at everything that comes out. I would say we don't need to have any particular pipeline product in order to bring our barrels to market or have future sanctions. So I'd say we look at each 1 independently. Overall, we're supportive, obviously, of more pipe. We'll help fill it if it comes at a really good price. And the other thing that I'll say is that maybe sitting here today, we feel a little bit better about that overall long-term market with some of the constructive open season market that we've seen. So there's a lot of options out there, which maybe wasn't the case historically. So I'd say we feel a lot better this time this year as opposed to this time last year with what we've seen.

Great. Thanks, Curtis. We just have a question on M&A, which is would we be looking definitively for assets that have tax balances. The quickest way to answer that is we have, at the moment, more than USD 1 billion worth of tax pools to use against our current tax. So we won't be paying tax anywhere for the next 2 to 3 years at current prices. So not necessary for M&A, always nice to have, but it wouldn't be at the forefront of our policy right now. And Will -- one more question. It's on M&A strange. Are you also looking at Brent-linked jurisdictions like Africa, South America, would we be looking external to Canada and the current jurisdictions we're in?

No, absolutely. It's all on the table. And essentially, in looking at M&A, it's all about being very disciplined and very selective. There's a ton of value to be created from our existing portfolio. But given the business model that we have within IPC, it's very much one that is scalable and the capital allocation decisions that have been made to sanction Blackrod, we have been looking at growing through M&A over the past few years as well, but there hasn't been the right opportunity that we've really sunk our teeth to quite yet, but we remain vigilant and persistent on continuing to screen assets and companies to look to grow through M&A.

Okay. That's it for the Internet questions..

Fantastic Okay. Well, thanks, Rebecca, and thanks for all the questions that came through from the audience and as well as in the web. It's great having a good attendance in the audience. I hope everyone enjoyed the presentation today as well as those who are tuning in, and we very much look forward to reporting at the next period, which is our Q1 results early in May. And with that, that concludes our Capital Markets Day presentation for 2026. Thank you very much.

Okay. So welcome, everyone, to the IPC 2025 Year-End Update Presentation. My name is William Lundin. I'm the President and CEO. And along with me is Christophe Nerguararian, the CFO; as well as Rebecca Gordon, our SVP of Investor Relations and Corporate Planning.

I'll begin with some of the highlights and then Christophe will touch on our financial performance in 2025. So this presentation update is really focused largely on our 2025 results. We will be quite efficient overall. And our 2026 forward-looking business plans will be covered later on today during our CMD presentation. So jumping into the highlights for the year, for the fourth quarter as well as 2025. Overall, it is a really strong year for International Petroleum. Our Q4 production average was 45,600 barrels of oil equivalent per day and we're very pleased to finish with a full year production average of 44,900 barrels of oil equivalent per day, which is near the top end of our guidance range, which was 43,000 to 45,000 BOEs per day.

The Q4 and annual operating costs achieved was $17.40 and $17.80 per barrel of oil equivalent, respectively largely in line with the forecast range of USD 18 to USD 19 per BOE for the full year. And we're really thrilled to have delivered first team at year-end 2025 for the Blackrod Phase 1 development project approximately a quarter earlier than originally guided when the project was sanctioned in the beginning of 2023. So full year capital expenditure for IPC, inclusive of decommissioning was $344 million, which is in line with our guidance of USD 340 million. The Blackrod Phase 1 development remains on budget with $228 million of growth capital incurred in 2025, and a cumulative spend of $820 million spent on the Phase 1 developments out of the total $850 million budget from the time of sanction again in early '23.

The company generated robust operating cash flow of $259 million in operating cash flow. When taking into account the full growth CapEx, our free cash flow was minus $153 million for the year. So both of those metrics were settling in slightly ahead of our latest guidance. On the heels of our major Blackrod spend program, our net debt number stands at $484 million at the end of 2025. We did elect to refinance our $450 million of bonds in late 2025. That closed in October which extended the maturity to late 2030. That was a prudent undertaken by the company, given the favorable conditions in the debt capital markets. In addition, IPC has access to CAD 250 million RCF in Canada. This gives us good liquidity access as we enter into the inflection year of 2026 with material cash flow growth expected from Blackrod upon it ramping up later in 2026 and into the years beyond that.

So the hedges that we implemented in 2025, they served as a net benefit to the company, mainly driven from the headline benchmark oil price swaps that we had on Brent and WTI. Very pleased there are no material HSE incidents recorded in 2025, and we issued our sixth annual sustainability report in August last year. Share buybacks, a major achievement for the company to return back to the original share count in 2025 relative to inception, thanks to fulfilling our 2024, 2025 NCIB program where we bought 7.7 million shares, representing an approximate 6.5% absolute reduction in our shares outstanding.

One of the core quality characteristics of the IPC portfolio is our low decline production. As shown on the slide, on the bottom left, the company has a really excellent track record of delivering within or ahead of guidance and 2025 was another year of just that with full year average production of 44,900 BOEs per day. Some of the short cycle sustaining activity we successfully executed last year at Onion Lake Thermal and the Bertam field in Malaysia gave us a nice boost in production midway through 2025. Again, our operating costs were stable with the full year outturn settling at $17.80 per BOE, slightly below guidance, mainly due to cheaper energy input costs in Canada and also slightly benefited from the higher production relative to the mid-case estimate signed at CMD 2025.

Strong production and cost discipline, combined with the full year average oil price of $69 Brent translated into operating cash flow of $259 million for the year. This is a great result considering at CMD, we expected a mid- to midpoint OCF of $245 million at $75 Brent and the reguided OCF forecast for Q3 2025, as shown on the right part of this slide was between USD 245 million and USD 255 million. OCF in Q4 was $63 million. And you can see the oil price for Q4 was lower than the annual average Brent at $64 per barrel Brent for Q4, and we also saw a slightly wider Brent to WTI differential of $5. However, the WTI to WCS discount remained tight throughout the year, settling in at around $11.

The 2025 capital program was successfully delivered with $344 million spent. Recall at Q3 2025, we announced the schedule acceleration on the Blackrod Phase 1 project with first steam to be delivered by year-end 2025 as opposed to Q1 2026. With that, we decided to bring forward the drilling activity for the final pad at Blackrod and reguided our CapEx to $340 million from $320 million. So that drilling activity has gone very well and will continue into 2026. So just shy of $230 million of Blackrod Phase 1 growth capital was spent in 2025. Again, bringing the total to $820 million spent in the project since the beginning of 2023. Project remains on budget to deliver within the $850 million growth capital budget to first oil, which is expected in Q3 2026.

And the other Blackrod spend of $26 million in 2025 was spent on capitalized operations as well as resource maturation works as we transition from build to start-up operating related expenditures will rise as planned and be reclassified to OpEx upon oil production coming from the commercial development. And the rest of the capital and decommissioning program was delivered in line with forecast and mainly being the Onion Lake Thermal infill program in Bertam drilling plus workover campaign.

So for the free cash flow, similar to the operating cash flow, our 2025 CMD pricing outlook assumed Brent between $65 and $85 per barrel following the continuous downward pressure we saw in prices throughout the year, the Q3 pricing guidance was adjusted to $55 to $65 Brent for the remainder of 2025. Final free cash flow pre-Blackrod expenditure was $103 million, and post all expenditures was minus $153 million, slightly ahead of the latest Q3 guidance. And to know relative to the CMD free cash flow guidance, in addition to the revised CapEx I explained on the prior slide, we also opportunistically called our bonds, which was not in the base case assumption for 2025. So notwithstanding those 2 movements or final FCF would have settled closer to the middle of the CMD FCF guidance.

On the share repurchase front, the antidilution measures continued in 2025 with the fulfillment of our 2024, 2025 normal course issuer bid program which resulted in IPC canceling around 6.5% of our shares outstanding. We now have less shares outstanding compared to that of the amount at inception for the company and the portfolio growth enhancements, you see 4.5x on production, 18x on 2P reserves significant add on the reserve life index and in excess of 1 billion barrels of contingent resources added and multiple higher on net asset value. It's really remarkable what's taking place in the company through the course of the last 9 years since we've existed. So 77 million shares have been repurchased an aggregate since inception at an average price of SEK 79 per share or CAD 11 per share, which is well below half of our current share price. So that's translated into significant value creation for our smart long-standing shareholders.

I'll pass it to Christophe to touch on the financial highlights.

Thank you, Will. Good morning, everyone. Very happy to be here for this fourth quarter results. As mentioned by Will, the production was very strong during this fourth quarter. And we averaged for the whole year just at the high end of our production guidance at 44,500 barrels a day of oil equivalent. The oil prices were a bit lower in the fourth quarter below $65 Brent, but with operating costs overall under control at $18.4 per BOE for the quarter and below $18 for the whole year. We generated very strong cash flows overall, so an operating cash flow of $63 million for the quarter and $260 million for the full year.

Very happy to report again the strong delivery around our investment program. This is the -- 2025 was the second largest investment year for IPC since inception. We dedicated USD 340 million to our investment overall during the year and more than $228 million to the Phase 1 at Blackrod. So this is really what turning a corner and by the end of 2025, we have spent USD 820 million at Blackrod Phase 1. And so we really only have a small amount left to complete and reach first oil in 2026.

The free cash flow was negative at $28.6 million or $150 million for the whole year. The net debt stands at $484 million at the end of the year, but we still have a large access to liquidity through the revolving credit facility with our Canadian supportive banks. Realized prices, you can see that the -- for the whole year, the Brent averaged 69%, WTI 65%. I think what really catches the eye here is the very tight WTI/WCS differential we enjoyed in 2025 at minus 11%. It was close to a record low for the Canadian market. And so of course, that translated into profitable business across the board, profitable activity in France, where we're selling our crude and parity with Brent.

In Malaysia, we continue to enjoy a strong premium up and above the dated Brent on that subject, very happy to report that, that trend is continuing because we continue to see very high premiums for our Malaysian cargoes in the first quarter of 2026. In Canada, we're selling on parity or very close to parity with the WCS which was $48 in the fourth quarter, $48 per barrel in the fourth quarter and $54 million for the whole year on average.

Gas prices remain relatively weak. Unfortunately, as we mentioned previously, the storage levels are reasonably high in Canada and in Alberta, in particular. And you see that the decoupling of the Canadian gas prices with the U.S. gas prices is continuing. Now the good news is still gas prices were reasonably higher in the fourth quarter. It's traditional for the winter months, but still, that was a good outcome for the quarter.

The second good piece of news is that the LNG Canada plant is now running his second train, and so progressively, we're expecting that second train to alleviate the congestion at the gas storage in Canada. So the gas prices are not strong yet, but we hope that the situation over time is going to continuously improve. Looking at our operating cash flows and EBITDA year-on-year. Of course, as you would expect with lower oil prices in 2025 and lower production or operating cash flows and EBITDA in 2025 were lower.

Now I think it's important to flip this chart on its head. And when you look ahead, as we'll be talking about this afternoon for the production range in 2026. We are finally going to increase production in 2026, and that's going to further increase in 2027. So even if you can see here, cash flows lower in '25 compared to 2024. We are turning a corner here and you can expect progressively with higher production and hopefully higher oil prices in the years to come our ability to generate stronger operating cash flows again. The operating costs remained relatively flat. Overall for the year, we were below the guidance of $18 to $19 per barrel of oil equivalent, slightly higher costs in the fourth quarter in because we had 2 liftings, 2 cargoes in Malaysia, but overall, the cost remain under control.

The netback you can see here that it's been relatively stable, whether you're looking at the fourth quarter or for the full year with $42. That includes, obviously gas prices, but with $42 per barrel of revenues and $18 per barrel of operating cost. The gross margin is around USD 15 per barrel and operating cash flow was $15 per barrel of netback in the fourth quarter and close to $16 per barrel of netback for the full year. We increased our net debt during this year, which was really the result of the last high spending, high investment here at Blackrod Phase 1 and the share buyback program, which we completed in 2025.

So we generated USD 260 million of operating cash flow, which fully covered our investment in Blackrod Phase 1, but not the Blackrod CapEx, together with $100 million of share buyback, we increased our net debt by around USD 280 million. The cost of roll, as I mean, remain under control, certainly with the operating cost per barrel at around $18 per BOE. You can see here that the net financial income have been very stable quarter-to-quarter, a bit higher in the fourth quarter as a result of the bond refinancing. The cash cost of that bond refinancing was around USD 18 million. The G&A remained relatively low at around $1 per barrel.

Looking at the financial results here in this graphic format, you can see revenues of USD 686 million for the whole year, generating a cash margin of $260 million and gross profit, so net of essentially the depletion and depreciation of gross profit of USD 128 million in net profit of USD 29 million for the year. The balance sheet is interesting. There's a clear balancing from the cash. We had USD 246 million of cash on the balance sheet, only $7 million at the end of '25. And of course, all this cash were invested into our assets. And you can see that the value of our oil and gas properties increased from $1.5 billion to close to $1.8 billion and essentially this is in relation with the Blackrod Phase 1 investment, obviously.

The balance sheet remains strong and in good shape. Our leverage was around 2x at the end of the year. We refinanced the bonds, leveraging on some very good markets conditions in -- at the end of September and early October 2025. Happy to report that we have still full access to the Canadian revolving credit facility, only $50 million was outstanding at the end of last year. And we continue to have very good relationship with our Canadian banks and lots of support on that front. So we are good from a liquidity perspective.

In terms of hedging, I think some of the -- of course, the teams on the ground perform very, very well in 2025. The production they delivered was very strong at the high end of the range. But of course, during 2025, we're able to place some very good hedges, which clearly helped the financial performance of the fourth quarter and the whole year as a whole. And so we generated hedging gains on our WTI hedges, on our Brent hedges and on our gas hedges, and we lost money that was on the protection we entered into at the beginning of the year on the differential and lost a bit of money on the FX as well. But overall, our hedges contributed positively to our financial performance in Q4 and for the whole year 2025. And you will see this afternoon, we'll be talking about some of the further opportunistic hedges we've placed for 2026.

Excellent. Thanks, Christophe. So to conclude with the summary for the 2025 highlights. Strong year again was -- we spent USD 344 million, $228 million out of that was spent on the Phase 1 development project at the Blackrod asset. Production was 45,600 BOEs per day for Q4 and averaged 44,900 barrels of oil equivalent per day for the full year right near the top end of our guidance range for 2025. Operating costs were $18.40 for Q4 and the full year 2025 unit cost was $17.80 for the year.

Good cash flow generation again at $259 million in operating cash flow was generated from the business and taking into account all the growth capital expenditures, $153 million, minus $153 million in free cash flow for the year. Again, we prudently refinanced our bonds at the end of 2025, extending maturity now to 2030. Net debt is at $484 million as at the end of last year and starting into 2026. Very pleased, given we are the operator at all of our assets. There are no material incidents that took place, safety or environmental and that's also a big shout out to the teams at Blackrod, where there hasn't been any material incidents, no LTIs since the beginning of the development activity started in 2023, really impressive safety performance by the teams.

And of course, a huge achievement there in executing and getting first steam ahead of the original guidance at the end of 2025. Share repurchases. We fulfilled our NCIB program, 7.7 million shares canceled out. We now have less shares outstanding compared to that of when we began life. So a strong year and very excited to update the market as well with our forward-looking plans later on today.

We can now transition into Q&A, which can be submitted over the web. And with that, I'll look towards Rebecca to see if we have some questions trickling in on the system.

Well, we do will. But unfortunately, there are all questions relating to our forward guidance for this afternoon. So if you don't mind, I think what we'll do is we'll hold on to the questions. We'll ask them as part of the CMD later on, and so we'll disclose all the information this afternoon relating to your questions here. So thanks [ Tod ], Samuel and Rob. We'll update you this afternoon. Thank you.

Okay. Thanks very much.

Thanks, everyone.

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.

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.

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

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?

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.

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.

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

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.

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.

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?

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.

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

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?

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

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?

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.

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

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?

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.

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

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?

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.

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?

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.

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.

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.

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?

Thank you.

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.