Welcome everybody to IPC's 2026 first 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 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 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 $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.

In response to the improved pricing environment, we're taking advantage of our operatorship and increasing our capital program from $122 million to $163 million USD, predominantly to accommodate short-cycle investments across some of our producing assets. Q1 capital spend was $71 million USD.

Operating cash flow generation for Q1 was $68 million, and we've revised our full-year OCF guidance to $220 to $340 million USD, assuming $70 to $90 per barrel Brent for the remainder of 2026. Free cash flow was -$17 million USD, 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 $120 million positive million USD 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 $250 million USD.

We also extended the maturity of that to 2028, so that gives us some 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, very pleased to report on.

On to the following slide. As shown on the production graph on slide three 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.

I'll touch on more detail on each of the asset's performance later on in the presentation. Moving on, we're very strongly positioned to deliver within our CMD production forecast range of 44 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 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. I'd also like to reiterate here that the 44 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, 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 $68 million USD.

The differentials from Brent to WTI, as can be seen in the brackets there, was $9, and from WTI to WCS was $14 a barrel. 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 $220 to $340 million USD based on $70 to $90 Brent, and that assumes a $5 differential between Brent and WTI and a $14 differential between WTI and WCS. 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, 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 Suffield assets in Alberta and in the Paris Basin in France, which I will expand on in the following asset-specific slides.

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 multi-year budget for Blackrod Phase 1 growth capital to first oil is $850 million USD.

There has been some minor cost pressure with total cost expected to be approximately $857 million USD, which is less than 1% overall of that original sanction CAPEX guidance for the growth capital to first oil. 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 nil 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 on stream. 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 79 SEK or CAD $11 per share respectively. 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 anti-dilution 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 amounts of 113.5 million shares.

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

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 on-site at the end of April.

This is a world-class SAGD plant with the 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 the 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 until that point of $850 million USD.

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. 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 $842 million USD, 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. We 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 supervision as prime contractor of the site.

Excellent delivery overall and stewardship of this project to date. 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 $1.4 billion USD 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 production potential as 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, 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.

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, 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 four-well production drilling campaign within the Bantry 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 have some incremental activity that's also been sanctioned now in France. We look to drill three side tracks in the FAB field and one side track in the Villeperdue field.

Very exciting to be drilling again in France. In Malaysia, we also plan to do an operational activity, a workover using a hydraulic workover unit later this year on our A13 well.

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.

Indeed, a good quarter with production at the high end of our Q1 guidance at 43,000 barrels of oil equivalent per day. Of course, during this first quarter, when the situation happened between Iran, the US, and Israel, the oil prices increased massively from the beginning of March.

You really have a relatively high average oil price, Dated Brent oil price for the whole quarter in excess of $81 per barrel. That was really a two-side of the story with lower oil prices in January and February and much higher in March.

Overall, that really helped generate on that basis strong operating cash flows and EBITDA for the quarter at $68 and $64 million US. 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 $17 million US.

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, $13 million US of net profit for this quarter.

The net debt increased during this first quarter by $30 million US. 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.

Certainly this year, we should start to see some deleveraging and accelerated deleveraging as the Blackrod production ramps up over time. Realized prices, 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.

The Dated Brent has been trading at between $5 up to $30 premium on top of the future, the financial Brent, if you wish. 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.

You can see we sold in March a cargo in Malaysia at $110 US per barrel while on average for the quarter Dated Brent was $81. The Brent-WTI differential widened a bit at $9, and the WTI-WCS differential stood at 14, -$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 US and the Canadian market.

It's 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 US market. You can see that we realized 2.5 Canadian dollar 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're 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're 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.

During this first quarter '26, we had similar production and overall revenues in between the first quarter '26 and '25. Some of the difference between the two quarters in '26 and '25 was coming from the fact that we lost $10 million of hedge losses in this first quarter because we had hedged around 40% of our WTI and Brent exposure at between $60 to $68 per barrel.

Of course, we've been losing in the month of March mainly. 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 $30 million during the $30 million US during the second quarter.

I think it's important to flag as well that beyond the end of June, we no longer have any benchmark hedge, we're totally exposed to the Brent and WTI prices going forward into the second half of 2026. Looking at the operating costs, 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 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.

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 a 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, we increased our net debt this quarter by $30 million US given the reasonably high CAPEX of $71 million we spent during the year. 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 a 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.

Just to mention that the foreign exchange loss, you can see here of $6.5 million during this quarter is a non-cash item. Otherwise, the G&A remain reasonably stable and flat at around $4 million US per quarter.

Looking at the financial results, we generated net revenues of $173 million, netting a cash margin of $68 million and gross profit of $37 million US, which, net of the financial items, tax, and tax elements, yielded a net profit of $13 million US for the quarter. The balance sheet has continued to evolve since we sanctioned the Blackrod project.

As you would expect, our level of cash has reduced and our level of net debt increased over the last three years. 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.

I will let Will conclude this presentation.

Thanks very much, Christophe. In summary, very exciting to be ramping up activity really across all regions of operations.

Q1 capital came in at $71 million USD, 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 $68 million USD, and the outlook for the full year is $220 to $340 million. We have an excess of $150 million USD of undrawn liquidity headroom, and there are no material environmental or safety incidents that took place in the first quarter.

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.

Good morning, Will and Christophe. Thanks for taking my questions.

First question, that is around the small CAPEX increase announced. I just wanted to know what is driven by cost increases and what is driven by higher activity.

Second part on that question is related to the activity increase. By how much should we assume that your exit-rate production this year increases as a result of the accelerated investments?

That's the first two questions. A third question that is on share repurchases, who've of course been very successful doing that for the past few years as you discussed.

You haven't been doing any repurchase or not any material repurchases the past few months. Just wanted background for that.

Do you think the share price approaches 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, we had an adjustment of $122 million to $163 million for our capital expenditure for 2026. That $40 million some-odd increase, the lion's share of that is for capital activity in France and Canada.

We're going to be doing four sidetracks drilling program in France for approximately $15 million, and also in Southern Alberta at our Suffield area assets, more in the more recently acquired in 2023 Cor4 property, where we're also going to be drilling four wells there. 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. Really the vast majority of the cost increases are deliberate cost increases here to increase the activity for production-contributing projects.

That production increase for those two 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 two programs, 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.

Here we are now, and that is the reason for why we've kind of prioritized the incremental capital going towards a 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 onto 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.

Thank you.

Thanks a lot. Excellent progress, as ever, and good luck 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.

Thank you. Yeah.

Thank you, Mark, and very good question. 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 that paves the way, probably, 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. 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.

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 so 50,000 GJ a day of gas hedged at 2.7 CAD per GJ or 2.8 CAD per mcf.

Unfortunately, that's probably going to be in the money. 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. That was your main question around gas prices.

Now, 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. We'll be fully exposed going forward to what looks to be reasonably constructive oil prices going forward.

Mark, just to add to that, in terms of just being a great signal in terms of Shell increasing its exposure in Canada just for the upstream overall Canadian landscape there. Now with that acquisition, Shell's secured roughly three-quarters of its feedgas requirements for both Phase 1 and Phase 2 of LNG Canada.

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 BC there.

Got it. 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?

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.

Thank you. Then just one last point, I might have missed in Teodor's question, but the short cycle in Suffield, that's obviously targeting liquids, I imagine?

Yes. Oil.

Very good. Thank you very much.

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

Thank you.

Exactly. Thank you.

Much appreciated. Thanks, Mark.

Thanks, operator. 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?

For sure. 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. Look to see some minor production boost coming from the asset towards the tail end of the year.

Very good. Then another question here.

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?

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 on stream 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. 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.

For Phase 2 specifically or 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 a oil-producing standpoint.

Great. Thanks.

Then just a quick question on capital structure. Christophe, could you explain the increase in the RCF, why you went for that?

Yeah. 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, it's been a constant discussion with always 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 250 million CAD to $250 million US, which we just did, and extended the maturity up to May 2028, as we do every year.

It's all positive for no other specific purpose than having ample liquidity.

Fantastic. Thanks.

Just a question on regulatory framework, in Canada, the US, 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. Specifically in Canada, also they have a sliding framework based on oil prices for the royalties.

No changes expected there or elsewhere within the portfolio at this time.

Fantastic. Then maybe one final question here.

What would be your priority post-Blackrod complete in terms of organic growth, or shareholder returns, or buybacks?

The infamous question, I think the punchline 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. 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.

Fantastic. That's what we have time for today.

That's all our questions, 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 very soon here. Thanks everyone, and take care.