Okay. So a very good morning to everybody, and welcome to IPC's First Quarter Results and Operations Update Presentation.

My name is Mike Nicholson, I'm the CEO of IPC. I'm also joined this morning by Christophe Nerguararian, who's the CFO; and Rebecca Gordon, who's our VP of Corporate Planning and Investor Relations.

I'll begin in the usual fashion by walking through the operations update, and then I'll pass across to Christophe, and he'll walk through the financial numbers for the first quarter. And then at the end of the presentation, we'll open up and you'll have the ability to ask questions, and we'll take those from the participants joining from the conference call or from the questions that are submitted online.

Thank you, Mike. Good morning to everyone.

Indeed, a pleasure to be here. What a change from last year.

As Mike mentioned, the combination of very strong operational performance in a much higher oil price and gas price environment means indeed a very good quarter. With Brent on average in excess of $61 for the first quarter and operating costs in line at $14.4 per barrel of oil equivalent, it translated into a very healthy $68 million for operating cash flow and $66 million of EBITDA for that single quarter, translating in turn to a €27 million net profit.

The net debt was reduced by $35 million. So most of the free cash flow, and I'll give you the breakdown, essentially was used to reduce that debt.

As we guided previously at our Capital Markets Day in early February, this year is very light on CapEx. It's very focused on cash flow generation with that cash flow dedicated to debt reduction.

So already from a year-end leverage ratio of 3 times, we've been able to deleverage considerably in this first quarter. And on the trailing 12 months rolling basis, our leverage has come off from 3 times to 1.8 times.

On an annualized basis, our leverage is much closer to 1 times actually. And so we are confident that by the end of this year, we should be indeed on an annual basis with the leverage at or below 1 times.

In terms of realized oil prices, the offtake and the liftings were a bit lumpy in Malaysia and France. We had a strong realized price with strong cargo in Malaysia in February and another cargo in Aquitaine in France.

So we had realized prices, which averaged more than $3.5 per barrel on top of the average Brent for the first quarter. Interestingly, in Canada, we've seen despite a much improved Brent and WTI average level in this first quarter, we've seen that the differential between the WTI and the WCS have remained very tight.

And this is important because, obviously, most of our production -- oil production in Canada is sold off at WCS. In terms of premium or discount for Suffield and Onion Lake assets, you can see that the Suffield here realized price was just shy of the WCS of $45 per barrel.

More importantly, you can see a much improved $2 improved netback at Onion Lake Thermal. And this is really driven by the fact that we are selling now roughly half of our Onion Lake Thermal production blended, so we are buying condensate.

So you can see on our account slightly higher condensate cost purchase to blend into our own production, which we then are able to sell at the WCS specification. So we've closed -- we've narrowed the gap and are able to sell closer to WCS for 50% of our production at Onion Lake Thermal.

Gas prices have improved significantly as well. There was a wave of cold in February, as everyone knows, in North America and the gas prices totally spiked at that moment in time.

We were partially hedged. So we didn't fully capture that spike, but still it's the second best quarter in terms of realized gas price for our business in Canada.

So we sold an average at just above CAD3.1 per Mcf, which is exceptional. And we also have -- I'll talk to it again at the end of that -- those few slides, but we also built up a very strong hedging on the gas, which should see our average realized gas price just shy of CAD3 per Mcf or -- of the remaining production this year.

So good gas prices in Q1 and well positioned to continue to benefit from a strong gas price going forward. I like this slide particularly, because we've turned the corner of 2020, so we are no longer comparing 2020 to the previous year.

Obviously, when you see that, it's obvious that 2020 was a very low year and that 2021 with the -- starting with this first quarter has seen exceptional performance. We're -- we generated $68 million and $66 million of operating cash flow and EBITDA, respectively, as I mentioned before.

I think more importantly, this is both ahead of most analysts' consensus and as well as our own budget. So really a good performance, which we hope and do everything we can to continue to deliver.

In terms of operating costs, no change to our guidance. The OpEx per barrel of oil equivalent this first quarter was at $14.4 per barrel and we maintain our guidance.

We expect to see increased operating costs in the second quarter on the back of a reduced production from the maintenance and turnaround work at both our FPSO in Malaysia and Onion Lake Thermal. But, overall, we should deliver -- we should deliver OpEx per barrel for the year roughly at the level of our first quarter.

Interesting to look at netbacks, especially if you look at this in comparison to what we guided previously, early February at our Capital Markets Day, because the EBITDA and operating cash flow per barrel are actually $3.5 higher than what we guided in our high case. So we've really delivered a good performance.

And obviously, the -- given that some of our OpEx are fixed, our increased revenues translates into a much increased EBITDA and operating cash flow, which itself translates into a much stronger free cash flow compared to our previous guidance, and I'll come back to that. Right now by showing you the breakdown of our debt reduction during that first quarter, starting from the $68 million of operating cash flow.

And the free cash flow generation or free cash flow for the first quarter was actually $49 million, just shy of $50 million. And all of the available cash after the change in working capital was allocated to debt reduction.

So we reduced our net debt by just in excess of $35 million. And we had a change in working capital of $13 million, which was driven by increased activity, increased oil prices and higher oil inventories, resulting into this increased working cap quarter from the end of last year to this quarter.

Generally, you've seen that I talked to the fact that OpEx were in line with expectations. The other main costs, our G&A and finance costs are under control, flat quarter-to-quarter and in line with expectations.

So not much to report other than the costs are under control in our business. Now the financial results.

You can see that the cash margin given a very low G&A, very low cash taxes, our cash margin, which is really the revenues less OpEx is at the same level or almost as our EBITDA and operating cash flow at $69 million, translating to gross profit of $38 million and very, very good net profit for the quarter at EUR27 million. Our balance sheet is -- the total size of our balance sheet is relatively flat quarter-on-quarter.

The points to note is obviously the debt reduction on the liabilities side. And then generally because there was more activity in Q1 than Q4, we have more payables, but with increased oil prices, we also have more receivables.

And, finally, given that we only had one lifting in Malaysia, we had a growing oil inventory at the end of March on our balance sheet, generating this positive change in working capital. We consumed some of the free cash flow as part of our increased working cap, which may unfold over the next months and quarters.

The final point is to give some light -- shed some lights around our hedging position. We used a very positive and supportive oil price environment to lock in some hedges for oil production in Canada.

And so we're in a position where roughly 50% of our Canadian oil production is hedged as well as 25% for the second half. And on average, we managed to lock in a $45 per barrel WCS, which is, once again, higher than our best case and our high case from our Capital Markets Day, so very happy with that level, even if today, it is actually even higher at around -- at closer to $50 WCS.

On the gas side, as I hinted before, we have a mix of forward sales contracts and financial hedges which translates into the fact that for this second quarter we're in, and next quarter we're roughly 50% hedged and at CAD2.9 per Mcf. So, again, we should be ahead of our previous guidance.

So, overall, a very good quarter. We've locked in some hedges.

Production performance is very good. So we're looking forward to some other good performance over the next three quarters this year.

Thank you very much, and I will let Mike conclude.

Well, thank you very much, Christophe and some really phenomenal financial numbers there. So just to recap on the first quarter performance.

It's been one of the best quarters that we've seen in more than two years. The last time we had this kind of production levels and free cash flow generation was the first quarter of 2019 when oil prices were averaging around $63 per barrel.

But as I mentioned, IPC stock price was closer to SEK50 a share rather than SEK30 a share this morning. When we look at the outlook in terms of the production performance, good gas prices, strong absolute crude prices and tight differentials, we've really got everything and tailwinds running and synchronization.

So let's just recap on the highlights for the first quarter. Production of 43,700 barrels of oil equivalent per day, above the high-end guidance and with the good production we've seen through April, with the uplift in our Malaysian interest and D-prime and Mooney coming on stream in the second half, we expect full year production to be towards the top end of that guidance range.

Good continued delivery on the OpEx, in line with guidance in the first quarter and no changes made to the full year numbers. Organic growth CapEx remains limited, delivering very strong free cash flow at $37 million, but we do have some optionality at Onion Lake Thermal in Canada and in Malaysia for the fourth quarter, if we continue to see us running above that high-end guidance that we gave in excess of $150 million of free cash flow.

Cash flow for the first quarter was above the high-end guidance at just under $70 million, and the first quarter free cash flow generation was an exceptional $49 million, which represents in one quarter only close to 10% of IPC's market cap at the end of the first quarter. The balance sheet is in a much better position than it was last year during the pandemic.

Quarter end net debt is $286 million. And we're seeing that -- the power of that free cash flow on the deleveraging.

At the end of December, our net debt-to-EBITDA ratio was 3 times and already by the end of the first quarter, that's dropped to 1.8 times. And if you annualize our Q1 EBITDA we'll be down close to 1.1 times.

So, again, the balance sheet is now in really good shape. Good performance on the BD front, we were able to conclude the acquisition of a 25% interest in our Bertam field in Malaysia for no consideration, and that adds from the 10th of April 1,250 barrels a day of extra production.

So it's a bit like picking up an infill well without having to pay for the CapEx to drill it. On the ESG side as well, no material safety incidents, no interruptions to any of our operational sites.

As I mentioned, we've secured the carbon offset credits that we need in 2021 to offset our 2020 emission reductions target. So I think it's been a very solid performance and congratulations to the whole IPC team that have been a part of delivering this performance.

So that concludes the presentation part. I guess we can turn over now to open up for some Q&A.

I have three questions actually. First on guidance.

Mike, you said that you likely will come in the upper end of the current guidance. I just want know how sensitive is that statement to oil and gas prices.

Let's say that, okay, we'll see $50 and oil prices are not close to $70 through the remaining of the year, would you still expect to end up in the upper end of the guided range?And second question is on the emission reduction, you're talking about 50% reduction by 2025. And that they will come from both operational initiatives and also some other offsetting initiatives.

I just wonder is it possible to be more specific and also maybe share, of course, around the costs and investments required for those 50% reduction. And my final question is on the pecking order for cash flow, of course, net debt is coming rapidly down now.

So how do you think around dividends versus M&A? And when should we expect the dividend?

So the first question on the cash flow guidance, let me just refer back to the slide to give you a bit of direction there, Teodor. Yes.

So if you look at the full year numbers that we gave in our guidance, you can see on average, you're looking at between a $10 increase in Brent crude prices. So at $55 per barrel.

We're assuming around $100 million of free cash flow. And at $65, we're looking around $150 million.

So one can see for every $10 per barrel, you're looking at about a $50 million increase. Now, of course, that's on a full year basis.

So you need to adjust that for the period of the year that's remaining. Christophe showed at Capital Markets Day in his presentation that the impact of a $5 per barrel tightening of the Canadian crude price differential would translate into about a $30 million uplift in free cash flow as well.

And if you look at that high-end guidance that we gave at $65 of around $150 million, it assumed WTI differentials of $4 and a WCS differential of $17, so you had a $21 discount from your $65 per barrel price forecast. So we were looking at WCS prices of $44 per barrel in that upside scenario and Canadian crude prices today are trading around $53-$54.

So I think all the information is there in the netbacks to be able to extrapolate that. But if you're looking at $65-plus today and $30 differentials with the bid in Q1, we should be looking at well in excess of that high-end guidance.

And your second question was on the ESG and the carbon offset projects. And you talked about the numbers in the projects.

So far in terms of operational reductions that we've seen from our assets, which in about 100,000 tonnes, and that's been split between our project -- Bertam project in Malaysia, where we invested in dual-fuel power generation, which allowed us to use the flash gas off the separators to generate power to run our pumps as opposed to using diesel. And in Canada, it was the investment in the heat recovery units that reduces the amount of gas that we need to run our facilities.

So if you look at the offsets that we secured relative to the operational emissions reductions for this year, it's about 100,000 tonnes each. The particular project that we've partnered with -- for last year and for this year's credits is a solar power project.

It's a 100-megawatt project in the northern region of Punjab. Its credits that are generated by greening up the grid in Northern India.

So without that project going ahead, it's about 70% of India's energy production comes from coal-fired power generation. So by moving forward with this solar project that generates carbon credits, which we are purchasing through our partnership with First Climate.

And the cost of those is all embedded in our operating cost guidance forecast. And then on the -- your third question with respect to priority for the free cash flow generation.

I think right now, as you've seen it's, all the free cash flow that we're generating is going towards debt reduction. And during our Capital Markets Day presentation and we're asked about buybacks, which is your question.

We said the last time that we launched a buyback program was when our leverage ratio was below 1 times. And I think, we reported this morning a big step forward towards that deleveraging.

On the last 12 months basis we're 1.8 times. Our sense is before we -- we want to be pretty cautious because we have to recognize that the recovery that we've seen in oil prices has been really at the feet of OPEC in Saudi Arabia, in particular.

And we've still got a significant amount of supply that's been withheld from the market. So we would like to see the continued rollout of the vaccination program.

We'd like to see a fundamental recovery in demand in the second half. If we see continued stronger oil prices, that will see us deleverage.

And then you're going to see stock levels move back to much more fundamentally balanced levels. And I think if we've got those -- that combination of things within stock to make us feel much more confident about relaunching the buyback program.

I think that covers all your questions, Teodor.

Yes, it did. But actually on the first question, my question was more on the volume sensitivity and not on the cash flow, but I can reach out to Rebecca later on.

Thank you. Actually, we had a lot of online questions on dividends and buybacks, so I think you've answered that, Mike, so we'll avoid those ones.

Mike question on Onion Lake. How much production shut in do you expect during the ramp-up of D-prime and how much incremental production thereafter when D-prime comes online?

So, I mean, to give some general guidance, the way the team in Canada have planned, the shutdown is gradually across the full month of May. So there are two trains at Onion Lake Thermal.

So we've got a couple of days at the beginning of the month, where we had a full shutdown. And then for the remainder of the month, there's going to be one train down for approximately half a month and another train down for the second half.

So typically, Onion Thermal is producing around 10,000 to 11,000 barrels per day, and we expect a reduction in production just for that particular month of around 4,000 barrels a day on average across the month of May. In terms of the adds from D-prime, we expect, as I mentioned in the presentation, a slow ramp-up, but we should be seeing in excess of 1,500 barrels a day of additional production adds from D-prime towards the end of this year.

Next a question on hedging for Christophe.

Yes.

So what is the hedging strategy going forward with respect to Canadian oil? And then we have another question here from a different investor, which is, when will you stop hedging Canadian production?

Will it be when Enbridge Line 3 online?

And obviously, coming from where we're coming and with 2020 back in our mind, we were happy to be able to lock in some of our Canadian oil production at above the high end of our range. So Mike mentioned before, the high end for WCS prices in our budget was $44.

We've managed to hedge above that level at $45, 50% in the second quarter, 25% of our Canadian oil production in the second half of this year. There's always some reason to ensure minimum cash flow is going forward to deleverage -- to deleverage, to prepare the balance sheet in case we want to do a bit more CapEx, to have a solid balance sheet in case we find some M&A opportunities.

So it's really about managing the unexpected. We don't have a formal policy.

We don't have bank hedging covenants as we speak. Given that WCS can be hedged for the second half of this year right now at $50 on average, we will continue to discuss, and appreciate if we want to lock in a bit more for the second half of this year, because WCS $50 is a very high level, obviously, more than 10% above where we guided in the high end of the range.

Just to comment on the last part of the question, I think it's a very fair point to note. As Mike explained before, that we're almost there with Line 3, which is still expected to come on stream by the end of this year.

TransMountain and expansion of TransMountain is also progressing very well. So all of this should stabilize going forward the WTI-WCS differential.

So bodes very well from for IPC business in overall and in Canada, in particular. And so we'll reevaluate what we want to do in terms of hedging for '22.

But, definitely, if you look at the last two years -- 2019, 2020 and this first quarter, on average, the WTI-WCS differential has been between 12% and 13% on average over those periods. So really good sign for our business.

So Mike regarding the additional growth opportunities. First question is, is there any threshold oil price level you want to see over a sustained period of time in order to do formally updates to the CapEx program?

No, we haven't set an absolute target. I mean, obviously, the interaction between Brent prices and continued strong differentials will help.

So if we are still trending towards the high-end guidance or even above that with tighter differentials, that certainly puts us on very solid footing to move forward with those. And I think what's going to be important is the outlook into 2022, because if we make these additional investments, it's going to have a limited impact on our 2021 numbers.

But if it can add entry-level production capacity for 2022, and as I said, we've seen that solid recovery in demand and inventory levels, rebalance, I think it's more how that forward outlook is into 2022 transpires before we decide to do anything more from those offshore projects.

Second question on the will drilling candidates. Why are you looking for M&A when you have those returns on your -- into will drilling candidates.

If you want to grow where can you find best returns?

I mean I don't think -- if you look at those two projects alone, we're talking about $30 million of incremental investment. And if you're looking at tight differentials and free cash flow potential, as I mentioned, in excess of $180 million, if you add in the tight differential upside on our high case, I don't think we're limited by looking at further M&A by a $30 million investment addition program.

I think we've got the financial capacity to do both.

And a question on M&A again. So are you involved in any current M&A processes in ?

And is that a focus area for M&A?

We don't comment on particular specific jurisdictions. But I think a general comment is, for sure, we've seen an uptick in M&A activity, particularly relative to 2020.

And we're always actively engaged in screening a number of opportunities. And like most of the time since IPC was spun off back in 2017, we have ongoing a number of opportunities that we're engaged in.

So it's just part and parcel of what we do on a month-to-month basis.

in terms of operations and the netbacks we're seeing from onshore Canada, what are we seeing from producers in neighboring properties? Are we seeing the same sort of benefits or is it a mixed bag then?

I mean, I think in general, across the Canadian energy space, of course, absolute prices and crude differentials and gas prices impact all producers alike. And I think what you're going to see in the first quarter is across the whole Canadian energy space, a fundamental improvement in your free cash flow generation.

So it's not isolated to IPC. But I think the fact that we bought into that whole story at a point where differentials were distressed and valuations were extremely low.

I think we've got a phenomenal platform to create a huge amount of value for our shareholders.

One for Christophe. Just a question on the longer term leverage ratio.

Well, again, I mean, 3 times at the end of last year is not in absolute terms an issue, but for the industry it's a -- for the upstream, it's a bit high. So we feel much -- definitely much more comfortable today.

We don't have a set leverage level that we want to achieve. Typically, if by year-end, we are at or below 1 times, it opens the door to doing or to considering buybacks, as Mike mentioned before.

But that means you weigh it against some very, very good payback and very good high-return projects that we may consider as the additional CapEx we could spend in Canada or Malaysia. But, yes, of course, we want to deleverage from -- continue to deleverage from where we are, and we expect that to naturally happen in the next two, three quarters.

Mike, one last question from the webcast. Will you be positioned in a couple of years to develop flat growth on your own or will you need to bring in a partner?

I think it's too early to answer that question right now. I mean, all the work that is going on right now by our team in country is to really mature the whole kind of subsurface and development concept on Blackrod.

And by moving forward with the third well pair and using the latest technology, so much longer horizontal drilling using the latest steam flow control devices, as we've said, to try and reduce the construction and drilling footprint and environmental footprint and get those breakeven costs down, we're going to be in a very, very good position. I think, the one thing about that project that sets it apart from other growth projects is that we have all the environmental permits and the construction permits in place.

So if we choose to move forward with the first phase development of the 180 million barrels out of the 1 billion barrels of contingent resource, we can do so without any further approvals. So that's, obviously, very attractive to partners.

And whether we choose to move forward ourselves or to bring in a partner, I think a project of that size and scale, it would be more prudent to dilute our interest. But no decisions have been made in that respect perspective thus far.

I believe we have one more question on the line. Operator, you can help with that.

I was just wondering on your debt facilities and whether any of the facilities have restrictions on your ability to resume shareholder returns? And also, is there kind of a list of priorities in terms of which facilities you'd be looking to pay down first through this year?

Well, as you know, you have all sorts of covenants and limitations in debt facilities, but there are provisions, which in certain cases, allow you, including driven by leverage, which allow you to allow us to return capital to shareholders. So that's embedded in the credit facilities we have.

If we can, and as much as possible, we would like to obviously reduce and repay our most expensive credit lines, so as much as possible, that's what we do and focus on. And, generally, especially in Canada, where some of the finance costs are driven by leverage, we should also see, especially in the second half of this year when the leverage really materializes some reduction in the cost of debt.

Operator, no more questions?

Okay. Thank you very much, operator, and thanks, everyone, for taking the time to tune in this morning.

I think it's been an exceptionally strong performance by IPC during the first quarter, and we look forward to that continuing and then reporting in early August for our second quarter results. So thank you very much, indeed, everybody.

Thanks, everyone.