International Petroleum Corp

STO:IPCO

Earnings Call Transcript 2023-Q2

[Mike Nicholson, executive]

Okay. So a very good morning to everybody, and welcome to IPC's Second Quarter Results and Operations Update Presentation. My name is Mike Nicholson. I'm the CEO. Joining me in presenting this morning is Christophe Nerguararian, the CFO; and we also have Rebecca Gordon with us, who is our VP of Corporate Planning and Investor Relations.

I'll begin with a run-through of the operations reports and some of the highlights, and then I'll pass across to Christophe, who will run through the financial numbers in a bit more detail. And then at the end of both the presentations, we'll of course, open up for the opportunity to ask questions, and we can take questions from those dialing in on the conference line or you can also send in your questions via the web.

So to get started, another very solid quarterly performance from IPC starting with the Q2 highlights and production. The second quarter average production numbers were 51,800 barrels of oil equivalent per day. That's our second quarter this year above the high-end guidance. So with the first half production now running above 52,000 barrels of oil equivalent per day, we're reguiding that our full year production numbers should now exceed the high-end guidance that we gave back in February in excess of 50,000 barrels of oil equivalent per day.

Continued solid performance in delivery on the cost side. Our second quarter operating cost numbers were very much in line with guidance at $17 per BOE. So no need to change the full year forecast that we have. It's maintained at $17.50 to $18 per BOE. And on the CapEx side, our 2023 capital expenditure forecast remains unchanged at USD 365 million. Major milestone achieved during the second quarter with the signing of the Blackrod Phase 1 EPC contract, and I'll come back with some additional color around that later in the presentation.

Very solid cash flow generation. Brent prices kind of stabilized during the second quarter at around $80 per barrel that allowed us to generate an operating cash flow of USD 84 million. That would have been around $8 million higher, but we did have a cargo in Malaysia that slipped into early July that was originally expected to be completed. So still very solid delivery, $84 million. And of course, we'll get the benefit of that cargo lifting in our third quarter results.

And we've taken the opportunity, obviously, with Brent prices averaging year-to-date around $80 per barrel. Our previous CMD full year guidance. We're looking at $70 to $100 per barrel. So we've taken the opportunity to tighten up the full year OCF guidance to now between USD 320 million on the low side, assuming $75 Brent for the remainder of the year, to now up to USD 390 million, assuming $90 per barrel Brent for the remainder of 2023.

Third quarter (sic) [ Second quarter ] free cash flow was USD 16 million. And if we look at the cash flow generated by the base business excluding the Blackrod funding, $65 million of free cash flow from the base business. And like OCF, we're taking the opportunity to tighten up the full year free cash flow guidance range again, assuming at the low end, $75 Brent and the high end $90 per barrel Brent. We're expecting full year free cash flow to be minus $65 million to plus USD 5 million.

The balance sheet is still in a very strong position, net cash position of USD 64 million. And when we look at the overall liquidity that we have with the bond cash that we sit on and the other credit lines, we're in a gross cash position of USD 374 million.

On the hedging side, no changes to the gas hedges, but we have been benefiting from those gas price hedges that we put in place back in late 2022. We've got around 50% of our net loan exposure, which is hedged at around CAD 4.10 per Mcf. That runs from July through October. So those hedges well in the money with Canadian gas prices around $2.50 per Mcf. No Brent or WTI benchmark hedges, the transportation hedge, the WCS to ARV hedges that we put in place remains unchanged through the remainder of 2023 at $10 a barrel. But we have seen some real improvements in Canadian WTI to WCS differentials. They tightened by $10 a barrel from the first quarter through the second quarter.

So we've taken the opportunity with those market tailwinds to lock in 50% of our Canadian oil production for 2024 at around $14 per barrel. And I'll come back to it in a bit more detail when I give an update on Blackrod. But obviously, a significant proportion of our costs will be in Canadian dollars. We've also taken the opportunity during the second quarter to lock in nearly 2/3 of our Canadian U.S. dollar exposure related to our Blackrod Phase 1 investment.

On the ESG side, we continue to strengthen our nonfinancial reporting. We publish alongside the second quarter report today, our fourth sustainability report. And to increase that disclosure, our first stand-alone TCFD report is also issued. And one of the key highlights within the sustainability report is still very much on track to achieving the 50% reduction in our net emissions intensity through 2027, which was extended earlier this year from 2025.

IPC has been very aggressive on our share repurchase programs. That's continued through the second quarter. We committed under our normal course issuer bid to buy up to 9.3 million shares. We're approximately 75% complete through that program with 7.1 million shares repurchased since we started the program back in December of last year.

So if we turn to the next slide, just a little bit more color around the production numbers. You can see the production chart on the right-hand side. The yellow dotted line shows the high end of guidance. So you can see that pretty much through most of the second quarter we were above that high end guidance, except for late May, where we had some planned maintenance on our Suffield oil facility and our Onion Lake thermal facility, but with really strong performance across all the major oil and gas assets and high uptime in Canada.

We also benefited from the production contribution from 4 new Suffield Ellerslie wells that came online during the quarter and have been exceeding expectation, and I'll get into a bit more detail on that on the next slide.

Internationally, our Bertam field has continued extremely high uptime rates in excess of 99%. And in France, we concluded the 4-well drilling program, which also gave us a bit of a boost through the second quarter, and we'll move on to those 2 production investments on this next slide.

Yes. So if we just look at the 2 charts on the right-hand side of the slide here. What we're showing is the guidance for production that we had from the top chart shows the 4-well program, the Ellerslie well program, and on the right -- on the bottom of the slide, you can see the 4-well program in France, which was 3 wells in Villeperdue and a side track in our Merisier field. The second quarter production has been very much supported by the boost that we've seen from those new investments. And I think you can see that both the Suffield Cor4 Ellerslie wells and the French 4-well program has been delivering ahead of expectations. So really pleased, great job done by the teams there in Canada and in France, and also with the high uptime in Malaysia. Really good operational excellence from all the teams across all parts of the business.

And the [ neck ] and bump that we should see with Pad L which is due to come on stream in -- during the third quarter, very much on schedule to start to see the production contribution at Onion Lake Thermal Pad L.

So with -- as I mentioned in the highlights, with first half production actuals at around 52,300 barrels of oil equivalent per year, we can see that with a high-end guidance of 50,000 barrels of oil equivalent per day we certainly feel comfortable now that we should be in a position to exceed now the high-end guidance of 50,000 barrels of oil equivalent per day, and that will be the fourth year in succession that we'll be able to deliver above our high-end guidance. So again, phenomenal job by the teams across all the business units.

Moving to the operating cash flow. In our February Capital Markets Day, we gave guidance at the lower end of the range, assuming a Brent price of $70 per barrel and at the upper end of the range of $100 per barrel with $5 Brent differentials and $20 WCS differentials. For the first half, oil prices averaged $80 Brent and $5 and $20 for the WTI and the WCS differentials, $180 million of operating cash generated through the first half of 2023. And what we've decided to do is just give a tighter guidance range for the rest of 2023, assuming that Brent oil prices average between $75 and $90. And the tighter differentials that we've seen, certainly on the WCS side of around $15 per barrel for the remainder of this year, and that gives us an OCF range of between USD 320 million and USD 390 million.

If we look at the capital expenditure program, certainly progressing the Blackrod Phase 1 early works. We've signed a major facility EPC contract during the second quarter, and we invested just under $120 million during the first half of 2023. So of course, with a full year CapEx budget of $365 million, definitely a little bit more activity weighted to the second half of 2023, but still in line with that full year budget, no need to change guidance at this point in time.

So when we feed through the cash flow generation and the investment program in the base business, still good first half. Cash flow generation at $80 per barrel, USD 33 million for the first half. And like the OCF guidance, we're again tightening the free cash flow guidance between $75 and $90 per barrel Brent to between minus $65 million at the lower end of the range up to a positive USD 5 million at $90 per barrel. And of course, that assumes funding of Blackrod CapEx of close to $285 million. So still some really, really solid cash flow generation from the base assets.

And when we turn now to the shareholder return framework, our capital allocation framework provides for returns to shareholders as long as the balance sheet is strong, and we define that as our leverage ratio. Our net debt-to-EBITDA is below 1 turn, and we're committed to providing 40% of free cash flow to shareholders.

Clearly, with a big capital program this year, we expect from the base assets before funding Blackrod with the new guidance range to generate between $220 million and $290 million of free cash flow. However, there is a big investment at our Blackrod Phase 1 development project around $285 million. So that would mean we would need oil prices of around $90 per barrel to start, under our shareholder return framework, to be distributing value back to shareholders.

However, the fact that we started the year in such a strong financial position with a net cash on the balance sheet of around $425 million, we've committed to going beyond the returns framework and complete the normal course issuer bid, which should see us repurchase and retire 7% of the shares outstanding. And from the beginning of December. We're well on track to meeting that commitment. We've repurchased 7.1 million shares so far under the NCIB program at an average price of just over SEK 100 a share or CAD 13. And that represents around 75% of the program through the end of 2023, and we fully intend to complete that program by early December.

And this year's repurchase program is on the long line of repurchase programs since the company was formed back in 2017. In aggregate, we've now repurchased close to 59 million shares at an average price of SEK 62 per share through the end of the second quarter. So when we take the market closing price of IPC from Friday last week of SEK 96 a share, we've created more than $180 million in value from the share repurchase program, and we continue that downward step through the anti-dilution staircase.

And if you look where we stand now, only 15% dilution since we started the company, and we've managed to materially grow the company across all of our metrics, a fivefold, more than fivefold increase in production, more than 16x increase in reserves, 20 years added to the reserve life, more than 1 billion barrels of contingent resources added. We've quadrupled our cash flow generation and added an excess of $3 billion in value or with just 15% dilution and certainly a lot more room for further share repurchases in the years ahead, and we'll get to that on the next couple of slides.

So if we look at this next chart here, it shows IPC's current market cap from the end of July, and we show the free cash flow that we expect to generate from the business. And this is after the funding of our $850 million Phase 1 development project in Blackrod. The first 5 years sees us generate a free cash flow of between USD 700 million and USD 1.4 billion between $75 and $95 per barrel Brent. So essentially, oil prices of around $90 per barrel, we can fully fund Blackrod and buy back almost every single share in IPC over the first 5 years. And then, of course, with the cash flow boost that Blackrod Phase 1 will give us up to between $2.6 billion and $4.4 billion in free cash flow over the 10-year period, which represents more than 2 to 3.5x IPC's current market cap just in the next 10 years with the reserves life of an excess of 19 years.

Likewise, from a value perspective, I think if we look at the net asset value of the company using a 10% discount rate, the value of just only our 2P reserves, we're not talking about any value associated with our -- in excess of 1 billion barrels of contingent resource, USD 3.5 billion in value or SEK 270 a share. So today, the company is trading at close to 66% discount to 2P value using a 10% discount rate given our Friday share price close of $0.96 (sic) [ SEK 96 ] per share. So huge room for material share price upside given that massive discount that we're seeing in. Of course, that's one of the reasons why we're prepared to continue with our share buyback program when you look at the free cash flow yield of the company and also the huge NAV discount that we trade at.

So if we turn now to the assets and to go through each of the key projects, and we start in Canada with our Blackrod Phase I development in terms of scope and schedule and budget. We're now pleased to say we're very much on track with the major milestone passed and signing the EPC contract in the second quarter. Just as a reminder, IPC operates the project with 100% working interest. We sanctioned the project in February of this year. It's a 220 million-barrel 2P reserve that we brought onto our books, and we plan to invest USD 850 million to construct a 30,000 barrels a day Phase 1 project, and we anticipate to achieve first oil late in 2026. And of course, once we've concluded that with Phase 1, we're still in a very favorable position that we have around 1 billion barrels remaining for future Blackrod development phases.

In terms of schedule, the focus right now for this year is the planning and some of the civil construction work, early stages on the facilities side and manufacturing in the workshop. We've got a couple of pictures on the next slide, but still very much on schedule to target that first steam towards the end of 2025 and first oil in late 2026.

If we turn to the next slide and just look at some of the progress, as I mentioned, we did sign the EPC contract during the second quarter. What that means is largely 65% now of our Phase 1 development costs of $850 million have been locked in, and we're very pleased to see the costs were very much in line with our expectation that came out to the back end of the FEED studies that we concluded through 2022.

What we've also taken the opportunity to do is a large proportion of the Blackrod Phase 1 development CapEx is going to be Canadian dollar denominated and obviously, because IPC is a predominantly U.S. dollar business, we've decided to lock in 65% of that Canadian to U.S. dollar exposure through the EPC contract and through the financial markets and the hedging to give us much greater certainty around overall U.S. dollar costs. I'm very pleased to report that having taken those collective actions with the contractual arrangements and the hedges that we've put in place with 2/3 of the costs largely locked in, we're in an extremely good position that we still have in excess of 85% of the $110 million of contingency that we set aside back in February when we came to the market with our guidance.

I think it's still too early for us to think about releasing some of that until we get through finalizing the engineering and getting into the construction, but it's certainly a nice position to be in.

If we just look at some of the pictures on the slide on the top right-hand side, you can see that's the pilot facilities at our Blackrod site. If you cast your eyes down to the bottom left of the slide, you can see that the road access and the bridge, the road has been widened and the bridge has been replaced so that we can manage to mobilize some of the major production modules to site. The 2 pictures of the evaporator systems, those are ex-Imperial oil evaporator towers that were surplus to their requirement. Typically, these can be long lead items. So we're very pleased to be able to secure those for our project. And then on the bottom right-hand side, you can see in the workshop, the start of the fabrication of the separator shell. So very good progress so far and very much in line with expectation with a comfortable contingency or margin remaining on our Blackrod project.

So now to touch on each of the assets. Onion Lake Thermal. If you look at the production chart on the bottom of the slide, you can see very stable production performance through the second quarter. And in terms of the development projects, the major activity this year is the drilling and completion and bringing into production Pad L and that's very much on schedule to achieve first oil during the fourth quarter. And the team are continuing their work to look at further facility optimization projects.

Turning to Suffield. You can see the production now includes the contribution from the acquisition of Cor4. Big jump of production up to in excess of 12,000 barrels per day, tapered off slightly with some of the turnaround work that we had at Suffield. But we should see a bit of a bump back up with the fourth Cor4 well that came into production just in the last month or so.

And on the gas side, still maintaining a very stable shallow decline with an extremely active swabbing program that we've got running through 2023, where we plan to complete around 2,000 swabs on that property.

Again, this is just a bit of zoom in to the Cor4 acquisition and a reminder of the focus of the investment program for this year. We're very pleased to announce in February that the acquisition of Cor4, and if you look on the top right-hand side of this slide, one of the most interesting parts of the acquisition was the Ellerslie play fairway that extends from the Northwest of our Suffield license into the licenses that were controlled by Cor4. We have -- we plan through 2023 to drill 5 Ellerslie wells on the Cor4 property, 1 in IPC's Suffield acreage, which is highlighted in the blue color on the map. So far, we've drilled 4 wells successfully on the acquired acreage during the first half. We've got more than 30 Ellerslie targets remaining in the inventory.

And as you can see from the production, the first 3 wells, we obviously saw some flush production with a ramp up to above 1,000 barrels per day, but we've been able to sustain production levels from the first 3 wells of around 600 barrels a day and with the fourth well coming onstream we've even pushed up above 800 barrels per day. And as you can see from the guidance line, we're running a couple of hundred barrels a day hot from the forecast that we were expecting that was underpinning our guidance. So a great start and a good integration of the assets into the IPC portfolio.

Turning to the international assets in Malaysia. Again, the production performance has been -- it's been extremely good with a very shallow decline. High uptime has continued on the Bertam FPSO, and a good strong base well performance in excess of 99% uptime achieved through the second quarter. And you can see the infills, which are represented by the blue bars that sit on the top account for more than 60% of our production. And our most recent well, our A15 where I think, paid back in less than 4 months, which was drilled in the first quarter of last year.

So given the really good performance we've seen from these recent infill drilling campaigns, the team is looking to see. If there's any remaining development potential in the Northeastern part of the Bertam field, but that's unlikely to happen for at least another year. But still some encouraging results that may see us drill up to another well in that area in the years ahead.

And turning to France, if we look at the production chart on the bottom right-hand side of the slide, you can see France is characterized by a steady stable decline. The base business has had a really good high uptime performance from all the producing assets. And you can see early in the second quarter a production bump back up to above 3,000 barrels per day. And that's really a result of the 2023 first half development activity, the 4-well drilling program successfully been completed at Villeperdue West and the sidetrack that we did in Merisier. You can see the production contribution on the bottom left-hand side of this slide from that development drill campaign that's seen us push back above 3,000 barrels per day in France during the second quarter.

And then when we turn now to our sustainability and ESG performance, again, really pleased to say that we have had no material safety of environmental incidents during the first half. As I mentioned in the highlights, we have continued to improve our nonfinancial disclosure. We publish our fourth sustainability report. And alongside that, for the first time is a stand-alone TCFD report. And we've spent a lot of time upgrading all the data that we show on the IPC website. Tremendous amount of work done by the sustainability team, really encourage all of our stakeholders to take a good read through all the materials that's been released this morning to see the good work that's going on within our company.

And in terms of the climate strategy, very much on track to achieve that net 50% emissions intensity reduction through now the end of 2027, which has been extended earlier this year by a further 2 years.

So that concludes the operations part of the presentation. I'll pass across to Christophe now, and he will walk you through the more detailed financial results. So Christophe?

[Christophe Nerguararian, executive]

Yes. Thank you very's much, Mike. And indeed, a very strong performance on the operational front. Congratulations to all our colleagues around the world for indeed a very good performance in this second quarter where the production was just shy of 52,000 barrels of oil equivalent per day and on average for the first half of this year, we produced in excess of 52,000 barrels of oil equivalent per day.

So the Brent was a bit softer. The Brent price a bit softer during the second quarter, but interesting part is that with a tighter differential in Canada on netbacks in this second quarter were actually stronger. The costs remain under control at around 17 -- operating costs at around USD 17 per BOE for the second quarter and USD 17.2 per barrel of oil equivalent for the first 6 months. And so we maintain our guidance for the costs while we've increased our production guidance towards the higher end of the range. That translated into a solid financial performance of roughly USD 85 million for both the operating cash flow and the EBITDA.

I'm just going to pause here for a minute because we have a couple of analysts who noted that we were a bit below on our actual revenues during this quarter and that they were right and wrong. The laws of nature makes it that the end of the quarter is on the 30th of June. And actually, we were literally lifting a cargo in Malaysia on the 30th of June. But the end of the loading of that cargo fell into the 1st day of July, which means that the revenues attached to this cargo will be reported in the second quarter. And we're talking about roughly $20 million of revenue moving from the last day of the quarter to the first day of the third quarter.

So what could look like a miss on revenues is actually the consequence of the fact that we've been selling less oil than what we produced during the quarter. So bearing that in mind, $160 million of operating cash flow and EBITDA for the first half that would have been at least $10 million higher should the -- should June had a 31st day. So the CapEx is close to $60 million for this quarter and $113 million for the first 6 months. Resulting in a net cash flow of USD 16 million for this quarter. Before Blackrod CapEx, the free cash flow for this quarter is USD 65 million. So important to remind that IPC has a very strong ability to generate strong cash flows. The cash position remains very comfortable with a gross cash position of USD 374 million sitting on the balance sheet.

So in terms of realized prices, the Brent was on average $80 for the first 6 months, but was down $3 compared to the first quarter in the second quarter. That being said, because the WTI/WCS differential went from minus 25% in the first quarter to minus 15% in the second quarter. You can see that the WCS calculated for the second half was actually $7 higher. So an interesting quarter where lower Brent and WTI prices translate into a higher WCS contributing to a netback for the overall IPC business.

Otherwise, you can see that we're still gaining very significant premiums for our crude oil, which is in high demand in Southeast Asia. Because of some seasonality during the quarter, the premium you see here are not quite correct, but typically, we have premiums in excess of regularly for our Malaysian crude. Otherwise, in France, we're selling on par with Brent and in Canada or heavy oil, sales on par with the WCS. So again, I was just mentioning only 1 cargo lifted during the second quarter because the last -- we were lifting in the last day of the second quarter, and it's going to be complete and reported with the third quarter at cargo.

Looking at realized gas prices, a bit of a softer market for gas prices compared to the last couple of years. I mean, CAD 2.5 per Mcf for gas prices in the summer is not ridiculously small, but obviously, softer than what we've experienced over the last 2 years and especially compared to last year with the war in Ukraine. So the realized gas price in the second quarter was CAD 2.44 per Mcf.

But it makes, with hindsight, it makes the value of the gas hedges we entered into very, very valuable. Obviously, you see that during the first quarter, we had 50% of our net gas production hedged at in excess of CAD 6 per Mcf. And still in Q2 and going into Q3 and up and including October this year, we have 50% of our net exposure hedged at $4. So that translated into in excess of USD 10 million hedging gain for the first 6 months. And that was mainly driven by those good gas hedges.

Looking at the quarterly and the first half operating cash flow and EBITDA performance, I actually like this slide because it's a good reminder that in 2022, you could -- you see the very strong financial performance, and that is the result of $20 to $30 more. So when oil prices were $20 to $30 higher in 2022, you can see that -- you can see how much cash flows the business would generate. And it's a striking reminder of how much IPC is exposed to the upside.

And so in a market like today, where oil prices are smoothly but surely ramping up with the market turning into a deficit position of 1.5 million to 2 million barrels a day globally. I think we have a business which is rightly exposed to the upside.

Looking at the operating cost, so we've maintained the annual guidance of $17.5 to $18 per BOE for operating costs. We were below for the first half. In the second part of the year, we have included some increased activity around maintenance and workovers, which may or may not fully materialize, but so we feel comfortable maintaining our operating cost guidance below $18 per BOE.

Looking at the netbacks on the following slide. So you can see that for the second quarter, our operating cash flow and EBITDA netbacks were in the range of around USD 18 per BOE. So if you compare that to our Capital Markets Day guidance adjusted for the average dated Brent price. That's where you would realize that all netbacks are a bit low compared to our guidance. And that is just the reflection of what I was explaining before. We've been producing more oil than what we were able to sell because of the last lifting in Malaysia. Otherwise, if you included that last lifting the netbacks are right in line with our Capital Markets Day guidance.

Looking at how our net cash position has evolved, you can see the USD 160 million of operating cash flow, which have fully covered our development CapEx or G&A or cash financial items and a part of the Cor4 acquisition. But with the increased or continuous share buyback during this first half and some decommissioning spending and windfall tax in France, which is included in this change in working cap, we've been using a bit of the cash we were sitting on at the end of last year. And so the net cash position has reduced from $175 million down to $64 million, but we are still sitting on our balance sheet. We still had at the end of June, USD 374 million of cash.

So on average, between Q2 and Q1, we have less cash on the balance sheet in Q2. But we're still gaining very, very nice interest on all this cash in excess of 5% from our banks or core banks. So the net interest are still fairly low compared to the coupon of the bonds because we're getting more than 5% on our deposits. Otherwise, in terms of G&A at less than USD 4 million a quarter, the G&A remained well under control and well below $1 per BOE.

Looking at the financial results, you see the close to USD 400 million of revenues, which, again, could have been $420 million with the last cargo, less the production cost that gives us a cash margin of USD 164 million comparable to the EBITDA and operating cash flow for the first half of this year at $160 million. turning into -- close to $120 million of gross profit and in excess of $70 million of revenues for the first 6 half -- for the first 6 months or the first half of this year.

Looking at the balance sheet, you can see that the main change was the increase in oil and gas properties, and that's more than $150 million increase in oil and gas properties is really the result of the CapEx spending and the Cor4 acquisition, which you partially find on the liability side of the balance sheet with increased provision for future [ abandonment ] liabilities, which were part of the Cor4 acquisition.

In terms of capital structure from a funding and liquidity perspective, there was no change this quarter. We increased on the last day of the first quarter, we doubled the size of our revolving credit facility in Canada at CAD 150 million, which remain fully undrawn. We only have used CAD 5 million to issue letters of credit to support our normal course of business.

In terms of hedges, actually, we've been quite active towards the end of the quarter, and in July, you can find those in the subsequent events relayed -- explained in our financial statements or MD&A. So what we've done is we've leveraged on the good market conditions in terms of the WTI/WCS differential to lock in roughly 50% of our 2024 Canadian oil production. So we were able to hedge close to 50% of that future production at minus $14, which is USD 14 per barrel for 2024, which is a very decent level indeed. The differential for next year now is just above $15, if it goes below $15, we might hedge some more in order to secure a high level of free cash flow in 2024 when we're continuing to heavily invest on Blackrod.

And the other thing, we've hedged the expensive winter months for the condensate, which we need to blend into our production to meet the WCS specifications. So we've hedged 50% of the condensate we need for the winter months. In the winter months, condensate tend to be priced at a premium to WTI. But again, we use the dip in the market to secure WTI minus USD 1.6 per barrel for the condensate we need to buy in the winter months, which is when the market needs more condensate than in the summer.

I think the other important part to note, and Mike touched on that, is that not only have we contracted around 65% of the Blackrod CapEx, but we've also hedged roughly 65% of our Canadian exposure. As you know, we are reporting in U.S. dollar. Our revenues are U.S. dollar related and driven. And so we've decided to hedge roughly 65% of the Blackrod Canadian dollar exposure because the vast majority of our spending on Blackrod is in Canadian dollar, which is reasonably weak now, especially compared to what we had in our budget for the years to come.

And so when you wrap up this FX and put that in the context of the Blackrod project, it helps us secure a very high level of contingency. And we have more than 85% closer to 90% of remaining contingency on the Blackrod budget. So very positive from that perspective.

So that concludes my financial part. I will let you, Mike conclude.

[Mike Nicholson, executive]

Okay. Yes. Thank you. Thank you very much, Christophe. So just to recap on the Q2 2023 highlights. High production of just under 52,000 barrels of oil equivalent per day record production in the first half. And on the back of the very solid production performance, and we're expecting now our full year production numbers to be in excess of 50,000 barrels of oil equivalent per day. As Christophe has shown on the cost side, we've been very much under control and in line with expectation with $17 a barrel OpEx in the second quarter and still very much on track for the full year guidance of between $17.50 to $18 per BOE. A big investment year this year with the first year of funding our Blackrod Phase 1 and no changes to the USD 365 million of capital expenditure guidance.

The base business still generates material cash flows the $80 Brent in the first half. We generated in excess of USD 116 million, USD 84 million in the second quarter. In the second quarter, free cash flow of USD 16 million with a full year expectation now of between minus $65 million to plus $5 million assuming Brent prices average between $70 to $90 per barrel -- $75 to $90 per barrel for the remainder of the year.

As Christophe has shown, the company is financially in a very strong position with a solid balance sheet. Net cash stands at $64 million at the end of June. And with the additional cash proceeds that we have from the bond that we issued at the beginning of 2022 gross cash. It's just under $380 million.

Sustainability wise, we're continuing our good progress on our carbon reduction and offsetting program and still expect to achieve a net 50% reduction by 2025, which is extended through 2027. No material incidents to report. During the second quarter and as we highlighted, we've issued our fourth sustainability report alongside our independent TCFD report.

And on the share repurchase side, it's been part of our core business is to continue to create value by buying back our undervalued shares. 2023 is no exception. We've bought back 7.1 million shares under our NCIB program. It's 75% complete, and we fully expect to conclude the second -- the last 25% during the second half of 2023.

And then just finally, as a reminder of the transformation that we're all very excited about here within IPC as we embark upon this large investment in our organic growth expansion. Very stable low decline base business that can average production in excess of 50,000 barrels a day through the 2023 to 2027 period. Still material free cash flow generated in the first 5 years of our business plan, having funded $850 million of Blackrod CapEx generating between $700 million and $1.4 billion in free cash flow between $75 and $95 per barrel Brent. And to put that in context, IPCs, current market cap is around $1.2 billion. So we can repurchase every single share at $90 Brent in that first 5 years.

Once Blackrod is up and running, we're going to grow production 30% and be able to sustain in excess of 65,000 barrels a day for the next 5 years. We'll only have produced 20% of our 2P reserves, and we'll see a free cash flow yield really jump to between 30% and 50% per annum, assuming $75 to $95 Brent. So very exciting transformation underway in IPC's business.

And that concludes the presentation of the operations update and the financial report for the second quarter. We can turn now and open up to take any questions that you may have. So Rebecca, I'll pass back to you to coordinate the Q&A.

[Rebecca Gordon, executive]

Okay, can we have any questions that have come through the telephone lines?

[Operator]

[Operator Instructions] We will take the first question from the line of James Hosie from Barclays.

[James Hosie, analyst]

I guess, firstly, Blackrod. You guys finalized that significant portion of the capital budget with the EPC contract. I'm just wondering what you mean by costs being largely locked in, if there are particular aspects of the contract where you retain the price risk? I mean just more generally, where do you see the most significant remaining risk to the budget that could draw on that contingency you now have? And then on the production guidance against to be blunt, you just raised the range. I mean, should we be thinking 50,000 to 51,000 barrels a day now? Or could you do even better than that?

[Mike Nicholson, executive]

Yes. Okay. Thanks, James. Yes. So yes, you're right. When we say largely fixed price. So there's really 2 parts to the TD contract that we've signed. The first part is a fixed price component. And then there's -- which is about 45%, [ shows here ] the 65%, and then there's a target price component, which can have a certain amount of variability. So around 20% of that, which we estimate could vary kind of plus/minus 10%. And we chose not to lock that part of the contract in because if you ask the EPC contractor to take that risk. Typically, they'll be more conservative and fix a higher number that we think we can potentially do better.

So it's very much a conscious decision to give us some flexibility to do better than locking in that last 20%. But as I say, you're looking at around plus/minus 10% on that much smaller part of the overall contract. And then when we look at the remaining contingency, I mean the bulk of the rest of the CapEx is mainly going to be relating to the drilling. I think there is still -- we haven't finalized all of the detailed engineering.

So I think one of the reasons why we think it's still too early to look at potentially releasing some of the significant contingency that we still got in the budget is until we've finalized all of that detailed engineering work, and we started the fabrication, and we've got a higher degree of certainty there. So hope that covers your questions on the Blackrod contract.

On production, when we say above 50,000 barrels per day, we haven't been specific to say it can go above 51,000. So I think if you're looking in that range that you talk about between 50,000 to 51,000, I think we feel very comfortable with that kind of reguidance range.

[Operator]

We will take the next question from Teodor Nilsen from SB1 Markets.

[Teodor Nilsen, analyst]

A couple of questions from me, both related to buybacks. I understand that you will buy back less shares in the second half than the first half of this year and you say that you only buy back if oil price is above $90. So that's my understanding. Is that the buyback reduction mainly driven by the CapEx increase in the second half? Or are there any other factors going into that consideration?

And second question on buybacks. That's more long-term question. How should we think around buybacks going forward versus dividends? What kind of share price or what kind of discount in NAV do we need to see for you starting paying cash dividends instead of buying back shares?

[Mike Nicholson, executive]

Yes, I mean, I think your first question, which relates to the pace of the buyback. So I wouldn't read anything into the pace of having 25% left between the beginning of August and the end of November. The program that was approved already for 2023 was already kind of well ahead of that. That's strictly committed to under our capital allocation framework to go up to the full 7%. And we just -- the share price was weaker in December when we started the program.

So the pace of buybacks was a little bit faster. We also in February after our year-end results, we saw a little bit of weakness. So we took the opportunity to pick the pace up there. But yes, certainly nothing to read into the fact that there's slightly less between now and the end of November to conclude the share re-buyback program.

And then the second question on the longer-term outlook, I mean I think if we look at the -- still the very large discount in excess of a 70% discount to our 2P net asset value. And in fact that, that doesn't bring any valuation to the 1 billion barrels that we have in our contingent resource base and the free cash flow yield that we see the base business is going to be generating going forward. I would say for the foreseeable future, you're going to be looking at share buybacks as opposed to dividend until we see that massive value disconnect unwind.

[Teodor Nilsen, analyst]

Okay. So what kind of discount are we talking about? Would you be okay to pay cash dividends at a discount to NAV, or do you need to see evaluation after full NAV to see a confidence in cash dividends?

[Mike Nicholson, executive]

Yes, I mean we haven't set a fixed discount, Teodor. And the reason being there is, of course, it does move around every year as -- as you know, we -- when we look at our 2P net asset value, we take our reserve auditors' independent view on long-term prices. So it does change from year to year. But there's -- yes, there's not a fixed element right now, but with such a large discount. I think for the foreseeable future, the focus will be on share repurchases as opposed to a dividend.

[Operator]

We'll take the next question from Mark Wilson from Jefferies.

[Mark Wilson, analyst]

A couple of just points. Bringing on that pad, the new pad at Onion Lake, Mike, I didn't catch whether you said, 3Q or 4Q, just reiterate on that? And then longer term, great to see your first sustainability report. Could you just outline on the 2027 and I think the 20 kilograms CO2. Are you aiming to maintain that with Blackrod on stream? Is that what we should read into the 2027 target?

[Mike Nicholson, executive]

Okay. Yes. Thanks, Mark. So for the first question on Onion Lake Thermal, yes, we do expect to see the start of the ramp-up of production in Onion Lake Thermal in the fourth quarter, potentially could be earlier in the third quarter if the good progress continues that we're seeing. And just as a reminder, the production contribution from Pad L should be in excess of 4,000 barrels a day over time as we ramp up all of the wells. And as I think we've talked on previous calls, the facility capacity Onion Lake Thermal is 14,000 barrels per day.

So it will be one of the first times that we will be testing the facility constraints of Onion Lake Thermal and we'll have enough well stock to exceed the facility constraints. So of course, that's why we mentioned on the slide that the team is looking at further optimization projects to see if it's going to be worthwhile investing in expanding the facility, say, from 14,000 barrels a day up to 16,000 barrels a day, but it will certainly be -- we'll be in a very strong position that we should be able to see those much higher average production levels sustained over the next few years with the addition of Pad L.

And then the second question on Blackrod, and the net emissions reduction target to 20 kilograms per BOE. We've deliberately not set a target yet beyond 2028 because with Blackrod, of course, one of the things that we did look at before the sanction of the Phase 1 project was the potential for carbon capture. And that wasn't an economic investment at the time that we chose to take the final investment decision.

But our view has always been that as the technology improves. And probably more importantly, as we hope to see some positive fiscal improvements, both federally and at the provincial level and that has been discussed for carbon capture and storage project. We've certainly got the geological formation to be able to do that at Blackrod.

So I think the reason that we've been reluctant to commit to kind of beyond 2028 when we ramp Blackrod up is we hope to be able to see technology improvements and fiscal incentives to allow us to consider a carbon capture project at Blackrod in the medium to longer term.

[Mark Wilson, analyst]

Okay. Interesting. Then last point, the net asset value, Mike, you always show it. You always talk to it, huge discount to it. What's everyone missing there in that calculation?

[Mike Nicholson, executive]

Yes. I mean, I think it's not -- as you know, Mark, you've been following us for a long time. It's not something new. And I think when we took the decision back in 2017 to buy into Canada and materially expand IPC's business into Canada. That was very much a feature of that market when we acquired BlackPearl, the company, IPC then was more internationally focused. We were trading at a 25% discount to our 2P NAV and the BlackPearl discount was in excess of 70%.

And I think it's partially probably tied to the fact that there has been historically more volatility in the Canadian market with the issue that you've had with the lack of pipeline export capacity to the U.S. and the big volatility that we've seen in Canadian crude price differentials. There's no secret that production was run far ahead of available pipeline export capacity and that had created a lot of volatility. And we start to see that position materially improve. Obviously, at the end of 2021 when Enbridge's Line 3 came into service.

We've seen the tightening and differentials that Christophe talked about through the second quarter with the OPEC cuts and the SPR, now turning to some repurchases rather than emptying the strategic reserve and with Trans Mountain coming into service from first quarter of next year. I think that should give a lot more certainty on perhaps one of the risk factors that's been hanging over Canadian market. So perhaps we can start to see that discount narrow once that key piece of infrastructure comes into service in the first quarter of next year.

[Operator]

Thank you. There appears no further questions. At this time. I'll hand it back over to your host for closing remarks.

[Rebecca Gordon, executive]

Actually, we do have a couple of questions from the Internet. So perhaps I can start with you, Christophe. Have you considered additional bond issues in which case, what kind of coupon would you expect on an additional bond?

[Christophe Nerguararian, executive]

Yes. No, that's a very good question. We always keep an eye on the bond market because effectively, if you see where we stand today, we have a coupon of 7% and 25% and we can deposit money or cash in excess of 5%. So the cost of carry is very, very small and gives us lots of flexibility for buybacks, for Blackrod or for potential acquisition in the future. So as part of the $300 million bonds we issued, we did that under the framework. It was a framework of $500 million.

So what that means is that we could tap up to an additional $200 million under the exact same terms and condition and the only change would be the -- at which price we issue those additional $200 million. And currently, our bonds are trading at between SEK 94 and SEK 95. There's clearly some more and more funds coming back to the bond market. So it has a bit of a tailwind there. So we keep an eye on it. The coupon would be -- probably would translate probably at around the yield at 8.5%, 8.75%, a bit on the high end of what we could consider. So we are not ready to act, but we certainly keep an eye on this market.

[Rebecca Gordon, executive]

My question from Tom Erik Kristiansen from Pareto. Given the high inflation in the market at the moment, did you need to use some of the estimated contingency on Blackrod or has the buffer relative to the CapEx, that hasn't been locked in, increased? Yes, if we can start with that one, Mike.

[Mike Nicholson, executive]

Yes. I mean I think as we've shown, we've still got in excess of 85% of the contingency remaining. And we haven't seen any big movements on the non-EPC contract costs. I think we're being prudent. I think it's a sensible thing to do at this stage in the project. As I mentioned, we still haven't finalized all the detailed engineering and we still got the drilling work scopes to go out to tender and get firmed up. But as I said during the call, with the contract signed and in the rearview mirror, we certainly feel extremely positive about where we're standing today.

[Rebecca Gordon, executive]

Also from Tom Erik on M&A. How are current energy prices impacting potential deals? So do you still see opportunities through acquisitions of capital-constrained assets?

[Mike Nicholson, executive]

I think the short answer is very much yes. And a clear example of that was our Cor4 acquisition back in February of this year. It was a very nice strategic tuck-in acquisition, and it was exactly as Tom Erik has highlighted there, this was a smaller company that certainly didn't have access to the same capital that IPC had and perhaps wasn't drilling as fast as we would do and therefore bring in that land position and resource base into the IPC portfolio. This has also allowed us to create some synergies.

And if you look at the value of where that asset was trading, we've purchased in excess of 5,000 barrels per day for around USD 62 million, so you're looking at around $30,000 per barrel, flowing barrel. So still extremely favorable acquisition with fast payback and a decent inventory. So I think as long as you can look hard and you're patient, there are good assets and companies out there, but of course, there are still a much larger proportion of assets that we think are probably overvalued.

[Rebecca Gordon, executive]

And just following on from the M&A question, another question from Jørgen Weidemann also Pareto. Do you see some opportunities in gas assets now that the prices have come down significantly? Are you looking at any M&A there?

[Mike Nicholson, executive]

Yes. I mean I wouldn't say it's an immediate focus right now. I mean, IPC is an extremely favorable position on the gas side because we produce more gas than we consume. At Onion Lake Thermal, we produce about 2x the gas that we do consume at Onion Thermal. And as time goes by and as we start to ramp up our Blackrod Phase 1 production profile, that will continue essentially up until around 2030. So I think the current short-term strategic priority is less focused on the gas. But as we start to approach the second half of 2020, then we start to take a bit more interest in some gas assets, but not for the time being.

[Rebecca Gordon, executive]

Christophe, a couple of questions for you, one from Ruben Dewa. On the $20 million of revenue that you said will fall into Q3 versus Q2, how does this reflect on the under lift in your revenue line in Malaysia?

[Christophe Nerguararian, executive]

Yes. Technically and accounting-wise, it's not an underlift because we just lift when we lift. So we are not late for lifting, if you wish. The way we account for that is because we cannot report the revenues this quarter, you actually cancel out and reduce your cost of operations for that portion of the barrels you've not sold -- you've produced but not sold during the month.

So actually, if you look in your cost of production, there's a negative cost in change in inventory in Malaysia. You can find that in the MD&A, it's roughly $5 million of reduction on the cost of production in Malaysia. And that is roughly the cost of producing those barrels that we've produced, but not sold.

[Rebecca Gordon, executive]

Okay. And then there is some talk of higher pipeline charges for Trans Mountain. How do you think about Trans Mountain impacting the likely WCS/WTI spread once it's operational? And do you have an expectation of timing for that?

[Christophe Nerguararian, executive]

Yes, that's a really interesting one. I mean different views. The latest we heard is that the line field could occur towards the last part of Q4. So we're talking about -- or we heard about December. It's just hearsay at this stage. But so that means this increased capacity of TMX could be available for exporting additional barrels in the first quarter next year. And it's not clear exactly what that cost increase is going to be for tariffs. The CapEx of the overall project have ballooned and exploded through the course of building that project and with the legal challenges. So for sure, the tariffs will be a bit higher.

Nevertheless, what matters to us is that Western Canada is going to have increased export capacity. And there are discussions about the fact that increased export from the Trans Mountain pipeline could go to Pad 5, so to California in the U.S. and to Asia, but also to Pad 5 which may displace some which may use some of the barrels, which would otherwise go to Pad 3, so that could create less supply from Canada to Pad 3 and then Pad 2. And overall, it is going to have a stabilizing effect on the differential and very likely a reduction effect as well for the years to come.

So we don't know whether it's going to be minus 10% or minus 15%. What we know is that it's going to be more stable and for a number of years, which is very beneficial to all Canadian heavy oil producers and to IPC in particular. And as Mike mentioned, this is -- that was the #1 reason we went to Canada where we found that there was a disconnect between price and value of assets. And we believe that with TMX coming onstream, although 2 years later than once anticipated. But finally coming on stream, this disconnect between value and price of assets and valuation is smoothly going to be bridged.

[Rebecca Gordon, executive]

Thanks, Christophe. Mike, just a couple of small questions on the other assets. Pad 8 seems like it will bring on 8 new wells. Is there a possibility to produce over the current 13,000 barrel a day facility capacity? Are there facility constraints? When will these wells come online?

[Mike Nicholson, executive]

Yes. I think I answered that question when Mark asked we are -- Pad L will add about 4,000 barrels a day of production capacity over time, and we're currently producing around 13,000 and the facility is around 14,000. So we will have more production capacity and well stocked than facility capacity, and the team is looking to see if it makes sense for us to look to expand that. But we're going to be in a really good position to sustain high production rates at Onion for a number of years.

[Rebecca Gordon, executive]

And then how are we looking at the Ellerslie acreage? Do we have the capacity to find the more prolific wells there, one of which has delivered 205,000 barrels in 17 months.

[Mike Nicholson, executive]

Yes, I mean, of course, we've got -- as I said, we've got an inventory of more than 30 drilling targets. And of course, our team on the ground when we go through our project ranking process, we obviously start from the subsurface up and we look at reservoir properties in terms of thickness and reservoir quality. And we look at offset wells and we decide which are the best wells to be trailed within inventory. And unless there's any particular license reasons while we have to drill a well in a certain location, typically, the rule of thumb is that well that will generate the highest returns and generate the quickest payback will be drilled first from the inventory pending any license commitment drilling that we need to undertake.

[Rebecca Gordon, executive]

Great. Okay. Thank you, Mike. That's the end of the Internet question.

[Mike Nicholson, executive]

Okay. So just taking good, thank you very much for everyone for tuning into I think what's been a very good operational and financial performance for the second quarter. Obviously, with Canadian differentials tightening and tight physical markets, we're seeing Brent prices start to trend upwards. I think the company is in great shape to generate some really good results for the second half, and we look forward to updating everyone in early November alongside our third quarter results. So thank you very much, everyone, for tuning in.

[Christophe Nerguararian, executive]

Thank you.

[Rebecca Gordon, executive]

Thanks, everyone.