Earnings call: IPC reports strong Q1 performance, maintains full-year guidance

International Petroleum Corporation (IPC) has reported a robust start to the year with first-quarter production of 48,800 barrels of oil equivalent per day (BOE/d), which aligns with the upper end of their guidance. The company has also managed to maintain lower operating costs at $17.10 per BOE, which is below their expected range.

Despite significant investments, particularly in the Blackrod Phase 1 development project, IPC remains financially solid with a strong balance sheet and has kept its full-year production and expenditure guidance unchanged. The company’s current trading levels are at a considerable discount to their net asset value, indicating potential growth prospects.

Key Takeaways

• IPC’s Q1 production hit the high end of guidance at 48,800 BOE/d.
• Operating costs were lower than anticipated at $17.10 per BOE due to production efficiency.
• $125 million was invested in Q1, with the majority going to the Blackrod Phase 1 project.
• Full-year production guidance is steady at 46,000 to 48,000 BOE/d, with operating costs expected to be $18 to $19 per BOE.
• IPC’s net debt stands at $61 million, but they anticipate a net cash position until 2024.
• 50% of oil production is hedged in Canada at $80 per barrel WTI and internationally at $85 Dated .
• The company is on track with its emissions intensity reduction plan and share repurchase program, to be completed by December 2024.
• IPC’s net asset value is just under $3.1 billion, with trading levels at a 50% discount to this value.
• Blackrod Phase 1 development is on budget, with first oil expected in late 2026.

Company Outlook

• IPC expects to maintain a net cash position until entering a peak investment year in 2024.
• The Blackrod Phase 1 project is progressing on budget, with first oil anticipated in late 2026.

Bearish Highlights

• The company experienced negative free cash flow due to substantial investment in the Blackrod project.
• Production downtime at Onion Lake Thermal was caused by extreme cold weather in January.

Bullish Highlights

• IPC has generated strong EBITDA and operating cash flow, with a net profit of $34 million.
• Production in Malaysia, France, and Canada has been stable, contributing to a positive outlook.
• The company’s hedging strategy has secured favorable pricing for half of its oil production.

Misses

• IPC’s investments led to a shift from a net cash to a net debt position.

Q&A Highlights

• The company discussed the impact of OPEC+ on oil prices and expects a market deficit due to high global demand.
• IPC is not currently planning to use solvents in the Blackrod SAGD project, preferring established technologies.

International Petroleum Corporation (IPC), with its ticker IPCO, has demonstrated a strong performance in the first quarter, setting a positive tone for the rest of the year. The company’s focus on operational efficiency and strategic hedging has allowed it to exceed production expectations while keeping costs down. IPC’s commitment to sustainability and safety remains a priority, as evidenced by their progress in emissions intensity reduction and their S&P Global ESG ratings assessment. With a robust balance sheet and careful investment in key projects like Blackrod, IPC is positioning itself for future growth while also returning value to shareholders through their share repurchase program. The company’s strategy includes evaluating M&A opportunities and maintaining flexibility in its financial planning, which could further strengthen its market position. Despite market uncertainties and the challenges posed by external factors like weather conditions, IPC is navigating the oil and gas landscape with a clear vision and a focus on delivering value.

Full transcript – None (IPCFF) Q1 2024:

Operator:

William Lundin: Okay. Welcome, everybody, to IPC’s First Quarter Results Update Presentation. I’m William Lundin, the CEO. And joined today by Christophe Nerguararian, our CFO; as sell Rebecca Gordon, our SVP of Corporate Planning and Investor Relations. I’ll start by running through the highlights and operations update, then Christophe will touch on the financial numbers. Following the presentation, we’ll spend some time to take questions, which can be submitted via the web or by conference call. So jumping into the highlights for the first quarter. On the production front, we achieved solid production of 48800 barrels of oil equivalent per day, which was on the high end of our production guidance for quarter. The full year production forecast range for the year is maintained at 46,000 to 48,000 BOE per day. Operating costs per BOE settled at $17.10 for the quarter, which was on the low end of our guidance, largely driven by the production outperformance. Full year operating expenditure guidance is maintained at $18 to $19. It’s a peak investment year for IPC, and we followed through on our plans through the first quarter of 2024 by spending U.S. $125 million, of which $96 million was spent on our Blackrod Phase 1 development project. Capital expenditure for 2024 is also unchanged at U.S. $437 million. So good production and good cost control, combined with healthy oil commodity prices translated into healthy cash flows for the business, with our Q1 OCF coming in at U.S. $89 million in line with our guidance. And our full year OCF guidance between $70 and $90 Brent has tightened as a result of some new oil benchmark hedges that we’ve executed which took place a couple of months back when oil prices spiked. So therefore, the OCF range for the full year is now U.S. $323 million to U.S. $363 million. Free cash flow for Q1 was minus U.S. $43 million. And if we were to exclude the growth investment associated with Blackrod, the base business generated positive $53 million in free cash flow. So similar to the OCF, our free cash flow guidance band has tightened to minus U.S. $154 million to minus U.S. $114 million. Without the Blackrod investment, that is going to be U.S. $220 million, approximately, to U.S. $248 million, between $70 to $90 Brent. So our balance sheet is in good shape with gross cash resources available of U.S. $397 million, and net debt of U.S. $61 million. So we enjoy being in a net cash position for all of 2023 and the majority of 2022. However, as expected in 2024 as a peak investment year, therefore we are going back into a net debt position, primarily as a result of the growth investment at our transformational asset in Blackrod. So Christophe will walk through more detail on the company’s cash position for the end of the first quarter in his portion of the presentation. I commented on the oil hedges that the company added in Q1. We now have around 50% of our oil production in Canada hedged at $80 per barrel WTI and about 50% of our international production hedged at $85 Dated Brent. The WTI to WCS differential hedges are unchanged from our previous reporting periods. So approximately 70% of our Canadian oil production is hedged at a differential of $15 a barrel for the year. On the ESG side, very pleased to share there are no material safety incidents for the first quarter and we’re well on track to achieve our net emissions intensity reduction plan, which is to achieve a 50% reduction by 2025 and maintain those levels through to the end of 2028. Our share repurchase program is progressing, around 3 million shares has been repurchased to date at an average price slightly over SEK 117 per share, and we’re on track to fulfill the NCIB program working on a total of 8.3 million shares by early December 2024. So a little bit more detail on the daily production for the quarter. As is shown on the plot, we had solid performance from our low-decline producing assets, with production pushing above the high-end limit for the first quarter as is shown on the figure on the top right-hand side of the slide. In Canada, the Suffield oil and gas producing assets delivered very well. And in Onion Lake Thermal, we had strong performance for the quarter despite a very nasty cold spell that we saw in early January, which had temperatures in minus 40 degrees Celsius to minus 50 degrees Celsius with wind chill that did result in some production downtime at OLT, but that has been fully restored since then. So another quarter of super high uptime in Malaysia was achieved, resulting in great production performance, and that was further supported by the wells that were worked over at the beginning of the year. And in France, production was in line with forecast from the Aquitaine and Paris Basin producing assets. So as noted in the highlights section of the presentation, our first quarter production was just shy of 49,000 barrels of oil equivalent per day, so slightly ahead of guidance for Q1. And given we’re only a few months into the year, we are going to maintain our production guidance of 46,000 to 48,000 BOEs per day. Our production mix is about a third weighted, with just less than 15% of our production coming from the international assets that are linked to Brent, and the rest of the makeup is mainly Canadian crude tied to WCS pricing. So operating cash flow for Q1 again was U.S. $89 million, in line with guidance for the top level price despite wider-than-forecasted dips in Q1, with Brent to TI being $6 a barrel and WTI to WCS being around $25 a barrel. So that’s mainly due to our good production performance and some positive returns on our hedges despite the differentials being slightly higher than our base budget assumptions. So between Brent to WTI, that’s $5, and WTI to WCS is $20 there. Our full year forecast for OCF is tightened. So we’re expecting to generate between U.S. $323 million to U.S. $363 million in OCF. And that’s largely tightened as a result of the hedges that we’ve layered in throughout the course of Q1, which ultimately protects downside pricing scenarios, which is a prudent move for the company given it is a peak investment year. Capital expenditure for the first quarter, again, was U.S. $125 million. The 2024 CAPEX program remains unchanged at U.S. $437 million, inclusive of decommissioning expenditure. The lion’s share of the capital is allocated towards Blackrod, where we budgeted U.S. $362 million for the year. The majority of the capital has already been spent in Malaysia there, which is attributable to the workovers executed earlier in the year. So free cash flow pre Blackrod funding was U.S. $53 million, post Blackrod funding was minus U.S. $43 million. And similar to the OCF forecast, we’ve tightened our guidance range relative to the CMD free cash flow forecast, and now being $208 million to $248 million in free cash flow for the base business, excluding the Blackrod growth investment. And including the Blackrod growth investment, free cash flow is estimated to be minus U.S. $154 million to minus U.S. $114 million based on $70 to $90 Brent per barrel. On to our shareholder distribution framework, so provided our net debt-to-EBITDA stays less than one turn, we have made a commitment to deliver 40% of our free cash flow to our shareholders. And as a result of the strength of the balance sheet of the company, we’ve made a commitment to go above and beyond this framework by continuing to execute our normal course issuer bid program, which we fully intend to complete before it expires in early December of 2024. And key thing to highlight within this slide is the base business free cash flow generation, representing approximately a free cash flow yield between 12% to 16% based on current market cap on the base business cash flow at $70 Brent to $90 Brent. The share repurchase program, so since inception, we’ve purchased just over 64 million shares at an average price of SEK 66 per share. We are again well on track to complete our current normal course issuer bid program. And since inception, there’s only been 10% dilution to our shares outstanding, which is a very low number when you take into consideration the production, the reserves, the reserves’ life increase, the contingent resources that have been increased since inception as well the overall value that has exponentially risen since the company was formed in early 2017. On to our net asset value, so as of the beginning of this year, our net asset value, using a 10% discount rate inclusive of our opening cash to start the year, is just shy of U.S. $3.1 billion, which represents a fair share price value of SEK 244 per share or CAD 32 per share. And our current trading levels are at about a 50% discount to our net asset value. So it really underpins the reasoning why we are buying back our shares. At Blackrod, very pleased with the progress that we’ve seen through the first quarter of the year as well the overall progress that’s been made since this project was sanctioned in early 2023. The project remains on budget, which is U.S. $850 million to First Oil, that’s scheduled in late 2026. Some of the pictures show the activity happening at site. A lot of the major packaged equipment has been delivered, including the HRSG turbines, the EVAP towers, drum boilers. You can also see the sales tanks that are being erected on the bottom right hand side in the picture there. So a lot of activity is going on at site. We also have our construction camp installed which holds 180 beds, and we are going to twin that camp and that is under progress. Currently, drilling is also tracking very well, with batch drilling operations underway for a 14-well pair pad to start with. And the diluent pipeline, as you can see on the bottom middle hand side of the slide, is being laid down as we speak. So great to see progress happening on all of the key scopes across the Blackrod asset. And on the schedule front, again, you can see everything is happening this year in 2024, and that’s the reason why it’s a peak investment year at Blackrod of U.S. $362 million being spent. So there’s a lot of work going on in the civil side, which is happening in a number of key areas, specific to the central processing facility, drilling pads, and the roads, and the fabrication shop vessels are being assembled. And the sequencing of the modules to be delivered is very key for the overall site logistics management. Drilling is progressing well, with all utility wells being drilled so far. And the first pad is — production pad producers and steam injectors are being drilled, as I noted on the prior slide. And we’re very pleased that diluent pipeline has been installed and the inlet facilities are the next part of that particular pipeline component to be installed for the diluent line. The other key pipelines are for the input fuel gas as well as for the crude takeaway line, and that’s progressing well, with plans to begin installation for those pipelines later in the year. Again, first oil is expected in late 2026, and we’re very well positioned to be able to deliver on that time line. At Onion Lake Thermal, good production performance through the first few months of the year. As I had noted, there was an extreme cold weather event that happened in the middle of January that resulted in a little bit of production downtime. But as is shown on the production figure, we were able to restore that production in an orderly manner. The L pad or sustaining pad, we continue to have wells tied in and the results of that, as shown in the bottom right-hand graph are exceeding the pre-drill expectations. So we look to tie on three more wells and get them on stream throughout the course of the year. Moving on to the Southern assets, specific to Suffield area assets, so we’ve had a great performance from our oil and gas producing assets throughout the course of 2024. The production graph on the top right is our Ellerslie production results. As you can see since we began drilling the wells there, we drilled about eight wells in 2023, and we’ve drilled three wells throughout the course of 2024. We still have two planned later in the year, and the results of these infills have been exceeding our pre-drill expectations. So overall, a very low decline base business production coming from the Suffield oil production in aggregate. And you can see on Suffield area gas production, there’s a little bit of weather downtime in 2024 which happens consistently year-over-year, and we get that production back through flush production. On the other assets in Canada, we have stable production to the tune of around 3,000 barrels of oil equivalent per day. We are drilling out our Ferguson asset, where we plan to do three production wells there as well as at the Mooney asset, we have started sending some polymer flood to the Phase 2 area and expecting a production response from that chemical flood in early 2025. Moving on to Malaysia, so another quarter of exceptional uptime with 99% uptime achieved. Great performance from the well stock in this offshore asset that we have within IPC. As is shown on the production graph, since the workovers were completed on A15 and A20, those wells have come back online in a great way and are very stable. We are continuing to assess further infill potential within the Northeast region of the Bertam field. In France, we had good production performance. Again here, there was some well workover activity that took place in February that was largely routine and planned. And production is stable here around 2,500 barrels of oil per day from the Paris Basin and Aquitaine Basin. On the sustainability front, we’re again very pleased with no material safety incidents that took place through the first quarter. Well on track to achieve our net emissions intensity reduction plans, which sees a 50% reduction come the end of 2025. And we did announce at CMD this year that we’ve extended that reduced emission intensity level from 2025 through to the end of 2028. And I think what so important to highlight here is we recently completed our ESG ratings assessment by S&P Global, and we’re quite pleased with the results there and made progress from the prior assessment. We ranked within the top 11% of the peer groups. There’s 177 companies that were assessed on their ESG practices, so great to be in the top-tier performer as it pertains to that. Now over to Christophe for the financial highlights.

Christophe Nerguararian: Yes. Thank you very much, Will. And very pleased to be here with you this morning because indeed nice to present a good quarter, both from a production and financial performance standpoint. So with the production just shy of 49,000 barrels of oil equivalent per day for this quarter, we were just above our own internal guidance and we managed to maintain the operating cost reasonably low. I’ll come back to that. And so we generated for this quarter a very strong EBITDA and operating cash flow of U.S. $87 million and U.S. $89 million, respectively. The spend on CAPEX at $125 million was right in line with our internal guidance for this quarter and we spent, out of those $125 million, just shy of $100 million on Blackrod. So of course, this year is our big, big activity driven by Blackrod. And as Will mentioned, very happy with the progress to date. We had, as anticipated, a negative free cash flow driven by this very significant investment, but posted a net profit of $34 million. I’ll come back and explain why the — we moved from a net cash to a net debt position that was driven, of course, by that negative free cash flow, to a lesser extent by some share buyback, as we mentioned as well, for $70 million, and the rest being a change in working capital. In terms of realized prices, solid prices at $83 that for Dated Brent per barrel, in line with the average for 2023. Very happy to report that realized prices in Malaysia remains strong. Our barrels there are still very appreciated by the surrounding refineries, and so we still benefit from around $8 premium on our barrels produced there. In France, we’re sitting on par with Brent. The WTI was at $77 per barrel on average during that quarter. The differential was quite wide at minus 20, which is, of course, not unusual with the common seasonality around that differential in Canada. So that was minus 20 and we were selling on par Suffield and Onion Lake Thermal production on par with WCS. Now as you may remember, and as Will mentioned, we have hedged 70% of our differential at minus 15. So despite the actual differential in the market, thanks to our hedging, we posted significant hedging gains on that front during that first quarter. On the gas price market, a bit of a different story there. It’s quite weak price environment in Q1, but we’re expecting those gas prices to remain pretty weak for the remainder of this year. As you can see, Will mentioned there was a very cold snap in the middle of January which sent gas prices as high CAD 30 per MCF, but on average was only CAD 2.5, which is reasonably low on a historical basis for the winter months. Now with LNG Canada expected to come on stream by the end of this year, early next year, if you would look at the gas price forward curve you would see that the market anticipates the gas prices to increase above CAD 3 per MCF for next year. So we’re keeping a close eye on this and remain very optimistic that we should be able to maybe lock in some gas prices for next year, at least that we’re heading into higher gas price environment towards the end of this year. In terms of operating cash flow and EBITDA, as you can see here on that Slide 23, the performance was good this quarter and actually even better than last year where the production was significantly higher, but in a weaker oil price environment. Operating costs driven by some lower activity, typically some assets are more difficult and more dependent on whether more harsh weather conditions in Q1. So no, it’s not unexpected that we have a bit of a lesser activity there. Some diluent costs were cheaper as well. The weather overall, it was cold but not as cold as some other winters in Canada, so the diluent costs were actually lower than the previous year. So all in all, operating cost of $17.10 per barrel of oil equivalent. We are not changing our guidance but of course, we feel pretty good about our ability to deliver within that $18 on $19 per BOE guidance. As you can see, in the third quarter, we have a regulatory shut-in for a turnaround at Onion Lake Thermal in Canada that happens every three years. And so with less production, we’re expecting our cost per barrel to increase above the range in Q3, but overall, to be well within that range for the year. In terms of netback, as you can see, operating cash flows and EBITDA netback was around $20 per BOE, which is $1.5 better than our base case as communicated during our Capital Markets Day. And that was, to a large extent, driven by lower operating costs, as I just mentioned. Now an important slide to reconcile the opening and closing net debt position for IPC. So we started the year with a $58 million cash position and posted a very good operating cash flow of $89 million, which was fully consumed in added value CAPEX investment. So most of the $125 million in CAPEX were dedicated towards Blackrod Phase 1, $96 million, the rest was mostly Malaysia and some other drilling of the Ellerslie wells around Suffield, as Will mentioned. The G&A are fairly low, less than $4 million. So on the cash financial items, the share buyback, so we’re roughly one third through our NCIB program for this year, and we spent $17 million during this quarter. And then you have a significant negative impact of the — coming from the change in working capital. And that was really mainly driven by the very high level of activity at both Blackrod in Canada in December, with the cash going out during the quarter; as well as in December, the start of the workover operations of our two high-producing wells in Malaysia, which were finally brought on stream in January. But some of the activity started in December and the cash only left the company in January and February, and we don’t have that activity at the end of March. The other one was around the payment of the bonds coupon. We accrue for only three months, but we pay our coupon twice a year. So that also has a negative impact in terms of cash. I think if you look at the difference from the opening to the closing position here, that’s U.S. $120 million of cash burn. And it’s very, very important not to draw any conclusion. It is not a spend rate, which is going to continue to impact our cash in the same way in the next three quarters. So it’s not — we were expecting to continue to spend heavily on Blackrod for the next three quarters this year, but we don’t expect to have such a negative change in working capital. So meaning that the cash burn won’t be as much the next following quarters. In terms of G&A and financial items, if I start by the G&A, very happy to report that we continue to have G&A at less than U.S. $1 per BOE so well under control. The next financial items, so we’re obviously spending most of the financial cost is towards the bonds coupon, but to a large extent offset by the 5.5% that we receive on average on our CAD and U.S. dollar deposits with our banks. So our net financial — net interest expense of only $3 million here, the rest are noncash items. In terms of financial results, you’ve seen the numbers. So with revenues in excess of U.S. $200 million and production cost of $116 million. We generated a cash margin of $91 million, gross profit of $55 million and net result of $34 million. Looking at the balance sheet, the main things to note here is obviously the increase in the value of our oil and gas properties despite the continuous depletion of those assets. And that increase is really driven again by this very significant investment during the first quarter of $125 million and almost $100 million on Blackrod. Though capital structure of the business remains really, really strong, no change there, as you know. So we issued $300 million worth of bonds in February 2022, maturing in 2027, and tapped the market for another $150 million worth of bonds in September last year. The maturity is February 2027 and we’ll look at refinancing that in 2026, very likely. We still have access to CAD 180 million on a revolving credit facility in Canada. The current maturity is May 2025, and we’re in the process of extending that by other 12 months, which is well underway. And continue to amortize our unsecured French loan maturing in 2026. So a very, very strong balance sheet, very robust with close to U.S. $400 million in cash at the end of Q1. Maybe one of the changes this year, if you look at the history for the first time, IPC hedged some of the benchmark WTI and Brent. And the reason is obvious, usually we leave shareholders the opportunity to manage their own position appetite towards the oil price volatility. In this very specific year in 2024, given the very high CAPEX we’re intending to spend, we want to secure the free cash flow for base business, which is the main source of funding for the Blackrod project. And the consequence was, we decided the Board and the management level to hedge 50% of our Dated Brent and WTI exposure at 80% and 85%. So effectively, we both hedged WTI and Brent at $5 per barrel higher than our base case. We’ve been quite active on the FX as well. Directionally, the U.S. dollar has been very strong, which means that the spending in the local currencies in Canada, France, and Malaysia are comparatively cheap. So we try to lock in to benefit from those low or cheap currency compared to the dollar for OPEX spending in 2024. More importantly, we’ve hedged a significant portion of our Canadian spending for Blackrod both in 2024, where we’ve hedged more than CAD 400 million at $1.32 FX, and we’ve bought another CAD 150 million at $1.35 for next year to cover some of our CAPEX in 2025. Thank you very much.

William Lundin: Thanks, Christophe. And to round out on the quarterly highlights. So again, it is a record investment year for IPC. We incurred $125 million in CAPEX spend through the first three months of the year. Full year forecast is just under U.S. $440 million. Production was great for the first quarter averaging 48,800 barrels of oil equivalent per day. Operating costs were low at $17.10 per BOE, it’s translated into strong cash flow of $89 million in OCF through Q1 and minus $43 million in free cash flow for the first three months of the year. Balance sheet is strong. We have $397 million of gross cash resources available that doesn’t include the RCF that we have available in Canada, which has CAD 180 million of additional liquidity available to it. So access to capital is good for IPC. Our net debt is U.S. $61 million as of April 1, 2024. Share repurchase program, we are well on track to compete the normal course issuer bid program, we are 36% of the way there through the amount of shares that we’ve repurchased that are allowable to be repurchased, which is on track. Our sustainability focus is paramount, and no material safety incidents occurred during the beginning of the year. It’s fantastic considering we operate the vast majority of our assets, and we’re well on track to achieve our net emission reduction target within a year’s time. So with that, I will pass it over to the questionnaire. So happy to take any questions via the web or the conference call. Rebecca, do you see any questions coming through?

Rebecca Gordon: Operator first.

William Lundin: Operator first. Pardon me.

Operator: Thank you. [Operator Instructions]. And we have our first question from Teodor Nilsen from SB1 Markets. Please go ahead.

Teodor Sveen-Nilsen: Good morning and thanks for taking my questions and also congrats on a strong set of numbers. Three questions, first is on Blackrod. Obviously that [indiscernible] done. So I just wonder what’s the biggest concern on Blackrod, is that the schedule or is it cost? Second question is on Trans-Mountain Pipeline, I noticed that it just commenced commercial production. What should we expect in terms of changes to the spreads locally in Canada and have you seen any changes to the spreads yet after opening of the Trans-Mountain Pipeline? And then my final question is on production costs. I guess some of the reason for strong first quarter numbers, that was the lower production cost, how much of those that we saw in first quarter should we expect to be repeated in second quarter? Thanks.

William Lundin: Okay. Thanks, Teodor. So starting with your first question on Blackrod and the biggest concern that exists. When we sanctioned this project in Q1 of 2023, we took the decision to add allowances into this project in terms of the level of contingency and as well on the overall schedule. And what also took place is when this project was sanctioned, we’ve just gone through a very high inflationary environment. So we took into account a U.S. $70 million inflation provision out of the U.S. $850 million CAPEX to first oil. And we also have U.S. $110 million of contingency. So these items are for known unknowns that could take place. This is a development in Alberta, which can provide pretty harsh weather conditions. So those type of allowances are there in case of extreme events taking place. So in terms of what’s the biggest risk going forward, I think it just comes down to overall execution and the overall phasing of the logistics and the modules to be delivered at site, ensuring that the site is ready to accept the heavy pieces of equipment and that the fab shop is moving out those pieces of equipment in an orderly manner. But overall, where we sit today with the level of progress, and we spent around U.S. $336 million since this project was sanctioned, being U.S. $240 million through 2023 and U.S. $96 million spent through the first quarter. So things are progressing really well. We feel comfortable to deliver within the overall time line and budget on this project. And given it is an onshore development as well and there’s lots of wells that are being drilled, we need 40 well pairs to reach nameplate production capacity of 30,000 barrels of oil per day. I view the overall execution not super risky in terms of the level of planning that we have in place so far. So overall, we are confident on delivering Blackrod with what’s been provided to the market. On the TMX pipeline, that’s right, line fill is underway. I believe it’s around 70% fill at this point in time, so that’s going to add an incremental 590,000 barrels per day of extra transport capacity for the Western Canadian Sedimentary Basin, which is a complete game changer for Canadian oil producers. And we are seeing the diffs starting to tighten as well. So the forward diff for 2024 is around $12.50 if we were to hedge out from May through to December. And we did take the decision at the — before the start of this year to hedge around 70% of our diff exposure at $15 a barrel. And from prior experiences with these big infrastructure projects, we thought that was a prudent move in case there were any significant delays. There have been delays on this project. They did blow the budget on this pipeline as well. However, it’s great to see that it’s coming on stream, and diffs are going to be tightening and are tightening as a result of that. So no issues with losing out on that kind of insurance hedge that we put in place. And the low operating cost, I think Christophe had touched on that as well during his portion of the presentation. Ultimately, do we think it’s going to be repeated in Q2, if we’re going to have exceptional production performance continue into the quarterly — to the second quarter, we should see low OPEX per BOE prices, but slightly higher than Q1 is the expectation, as we do have natural declines taking place. However, what’s key to point out as well as in the third quarter of 2024, we have two planned turnarounds taking place at two of our significant assets, one in Onion Lake Thermal and one in Malaysia, the Bertam asset as well. So we will see OPEX costs per BOE going up specifically in the third quarter.

Teodor Sveen-Nilsen: Okay, thank you.

Operator: Thank you. And we have a further question from Tom Erik from Pareto. Please go ahead.

Tom Erik Kristiansen: Congrats on a strong quarter. Two questions from me. Balance sheet, obviously looks strong with a cash balance and [Technical Difficulty] cash flow with increased hedging this year. Can you talk a bit about the priorities and if you are evaluating opportunities to use this increased flexibility to do more in the production rate, [Question Inaudible]?

William Lundin: Thanks, Tom Erik. The line was a little bit muffled there. I think I caught the majority of your questions. I’ll talk to the priorities of the company in terms of the increased strength, the balance sheet where we’re at, and what our plans are in terms of our corporate strategy, as well as I can touch on M&A, and then I’ll hand it to Christophe for the balance sheet question that was raised. So in terms of the base business and the performance that we’ve seen so far, I mean, this is a peak investment year for the company. It’s roughly 33% higher investment relative to what we invested CAPEX-wise in 2023 as a company. So I think in terms of adding more incremental base business activity is not something that we have in our firm plans at this stage. But behind the scenes, we’re constantly evaluating the portfolio and ensuring that the quickest payback opportunities that exist within the portfolio are — is actionable in a short time frame as possible. So as we look towards later in the year, it might be something that we’ll consider. But at this point in time, we’re sticking to our plans of the overall budget of U.S. $437 million on the CAPEX side. In terms of the buybacks and accelerating that, and given this normal course issuer bid program, gives us some autonomy and flexibility in terms of the level of buybacks that we can do over a period, provided we’re not in a blackout period. We do see share price weakness, we can ramp it up a little bit. But the way that we are looking at the remainder of the share buyback program is to really trickle it through the remainder of the year, and that program expires on December 5, 2024. For the M&A side, we think of it largely the same as we have been from the early days and when the company was formed in 2017, focusing on assets of high quality in nature. Good subsurface ideally in production in jurisdictions that are stable, fiscally attractive, and ideally where you can put some debt against the target acquisition. So if we’re able to continue acquiring assets in jurisdictions where we operate in that makes a whole lot of sense, given the strength of the operational teams that we have in place. However, we’re not shy from investing into assets in different jurisdictions where we don’t operate currently, provided it meets some of the criteria that I had just mentioned. But I think it is important to note that just the size of acquisitions right now for IPC that we’re looking at are going to be to the smaller size relative to what we did with our first couple of acquisitions as a company in Suffield and Blackrod. So I’d say around $200 million roughly is maybe a target acquisition number that we’d be willing to entertain. And Christophe, I’ll let you address the…

Rebecca Gordon: Right. The balance sheet question was about the flexibility to invest in our basins.

William Lundin: Okay.

Rebecca Gordon: Yes.

Christophe Nerguararian: But yes, in terms of balance sheet, I’ll answer the question you maybe didn’t ask. But yes, we still have lots of flexibility. We have a framework under which we issued the bonds, which is for up to $500 million, so we could easily tap the market for another $50 million of bonds if we wished to. And we still enjoy very good relationship and lots of support from our Canadian banks who made it clear that they would be here for us if we needed them. So we feel not only good where we are today and with our cash position, but we believe we maintain quite some flexibility should we want to leverage the business a bit more.

Tom Erik Kristiansen: Okay, thank you very much.

Operator: Thank you. [Operator Instructions]. We currently have no further telephone questions. So I’d like to hand over for questions from the webcast.

Rebecca Gordon: Okay. Thanks, operator. So we have a couple of questions here from Mark Wilson, Jefferies.

Mark Wilson: Will you discuss the impact that TransCanada can have on the WTI/WCS differentials, can you go into a bit more detail there?

William Lundin: Yes, absolutely. So why I say this is a game changer for the Western Canadian Sedimentary Basin with respect to the TMX pipeline coming onstream is because with that just under 600,000 barrels per day of extra takeaway capacity. Now the WCSB, Western Canadian Sedimentary Basin, is in a position where there is ample export capacity or takeaway capacity relative to the overall production in that area. So we’re talking about 200,000 to 300,000 barrels per day of extra takeaway capacity, and that’s really driving the tightening differentials. And I think further to the benefit of this pipeline that it goes West instead of just going straight into the U.S., it gives a lot of optionality in terms of where that crude can go to with Aframaxes being able to take the crude product from the BC — the Coast of BC and be able to go to places like Pad 5 in California and the States are also have that crude make way to Asian markets. So as a result of that, we see increased competitive tension should therefore drive down the overall transport component of the differential. And I’d also note that with the Dos Bocas refinery in Mexico set to — starting to ramp up here, that is of similar heavy grade to Canadian oil. So with that production being removed, that usually goes to the Gulf Coast, another positive catalyst for heavy Canadian Oil.

Mark Wilson: Okay. And can you speak to the overall goal on share buybacks, because clearly, you’re focused on that over dividends and you continue to make the discount to NAV argument, so essentially, what is the argument for listing versus taking the company private?

William Lundin: So it’s a really good question there, Mark. In terms of the share buybacks, I mean, the way we’re looking at it is we try and be quite simplistic in general in terms of we have an intrinsic value in excess of $3 billion, referencing our 2P reserves NAV 10, using a 10% discount rate. And provided oil prices stay about where they are with the production benefit coming from the Blackrod Phase 1 development as we get closer to that project coming on stream, the overall value of the business is going to continue to increase as well year-over-year. And we also have greater than 1 billion barrels of contingent resources that we don’t assign any value to. So this isn’t a one-year significant NAV for IPC, we see this very much increasing year-over-year. And provided that we’re going to be trading at a discount, one of our key strategic pillars as a company is shareholder returns, and so those returns are going to be going to the form of buybacks. And if we are to be in a position where we’re starting to trade close to our fair value or even at a premium, where we all believe we should be trading at, at that point in time we will click the dividend button. So we are really approaching this year-over-year and making an emphasis for the company to ensure that there’s a level of shareholder returns every year.

Mark Wilson: Okay, great. Christophe, question for you. Have you seen any effect of ESG ratings or metrics on the cost of capital?

Christophe Nerguararian: Not any direct impact. Of course, some bond investors might be prevented from investing in our bonds. So we don’t talk to them, so we don’t know that. What I can tell you is that there was a very good response when we went to the market to raise bonds. Again, as I mentioned, we enjoy very good and strong relationship with Canadian banks continuing to support us. I don’t see a major change from the last couple of years, there was a shift probably five years ago with some typically European banks we traded from the market or supporting upstream companies. But I believe it was — there weren’t so many changes the last couple of years.

Mark Wilson: Yes, good. Also, can you just walk through briefly the change in decommissioning expense this quarter compared to Q4 2023?

Christophe Nerguararian: Yes. No, there was less activity this quarter for sure, but we’re maintaining our full year budget, and the activity should pick up typically in Q2 and Q3.

Mark Wilson: Okay. Yes. And just a specific question, Will. How long is the maintenance shutdown on Onion Lake in Q3 and does that result in production to zero during that time?

William Lundin: It’s going to be 2-week production downtime is what we budgeted for, also the same amount of time for Malaysia as well there at Onion Lake Thermal. Because we have two trains, we are planning to stagger the shutdown activities so that we can keep some level of production going through the facilities. So there will be very limited downtime, if any, where we go to actual zero production during the turnaround.

Mark Wilson: Okay. Thanks very much. And then potentially a question for next CMD, but Blackrod SAGD Tech. So peers are talking about new tech for drilling pads and use of solvents. Is that something that’s being considered for Blackrod or is it just traditional initially?

William Lundin: So we don’t have plans right now in our base assumptions to implement any solvents into our SAGD development project at the Blackrod asset. That is something that the teams are monitoring in terms of what type of response other projects are getting by using these type of solvents. We believe there’s Project Imperial that’s doing a lower Grand Rapids SAGD development using a patented solvent additive materials. So it’s something that we monitor. But being in an IPC, we like to stick to our guns in terms of using technologies that’s tried, proven, and tested and incorporate that into plans. We really want to see new technologies that are trialed overall, be successful before we incorporate them into our base plans.

Mark Wilson: Okay. Thanks. And we just got time for one last question. Will, you’ve mentioned on multiple occasions in past presentations that you’re bullish on oil, can you explain your conviction and is reliant from a kindness of OPEC+?

William Lundin: No, OPEC+ market share has reduced a little bit to current time being around 27%. In years prior, in excess of 30%. But nevertheless, their influence is still significant. And obviously, the growth ambitions that Saudi Arabia has with Vision 2030, it’s very, very important for them to have high commodity prices to meet their funding objectives. So I think OPEC+ definitely plays a big effect in terms of overall oil prices. And what we see now with global demand expected to be an all-time high again this year in excess of 103 million barrels per day and supply projected to be slightly under that, the market is expected to be in a deficit for the remainder of the year. And I think for OPEC to have any barrels being returned to the market, that would need to be a result of inventories being drawn significantly further from where they are despite them already being below the five-year average. So with those key elements to consider, I believe the overall supply-demand balance is pretty tight. We have seen higher than expected inflation staying for longer here, which probably going to result in rates being around for longer. So I think that’s something that will be interesting to monitor as the year progresses in terms of if there’s any bearish sentiment and recessionary fears if they come back on the table. But physically, fundamentally, the oil market, I think, is tight and it’s going to be robust for many years to come, which should result in healthy commodity prices for the foreseeable.

Rebecca Gordon: Thank you very much. So that’s all the questions we have time for. Thanks everyone for attending the Q1 conference call.

William Lundin: Thanks, everyone.

Christophe Nerguararian: Thank you.

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