Okay. So very good morning to everybody, and welcome to IPC's 2nd quarter results and operations update presentation. My name is Mike Nicholson. I'm the CEO. Also joining me this morning is Christophe Nergarian, the CFO and Rebecca Gordon, who is the VP of Investor Relations and Corporate planning.
I'll begin in the usual fashion by walking through the operations update for the Q2, and then I'll pass the presentation across to Christophe. He'll take you through the financial numbers for the Q2. And then at the end of the presentations, you'll have the opportunity and task questions. So you can dial in on the conference call. You can also send in your questions via email.
So to get started with the highlights for the second quarter, it's been a very, very strong quarter the company. You're going to see good operational delivery from all of our asset teams across the business. We obviously had improving commodity prices, Stronger benchmark oil prices. We've had strong gas prices in Canada, and we've also had tight differentials. And the combination Of those 2, you're going to see a Fed into very, very strong financial performance, and we're upgrading our production and our financial guidance across all of the key metrics.
So to get started on production, 2nd quarter production averaged 44,000 600 barrels of oil per day. And that was the 2nd quarter in succession. That was above our high end guidance. And as a result of that very strong performance in the first half, we're now revising our full year production guidance to in excess of 44,000 barrels of oil equivalent per day. And in our Q1 presentation, we've been expecting the full year production to be heading towards 43,000 barrels of oil equivalent per day.
And we'll get into it in the presentation, but with the extra 25% interest on our Bertram field and the B prime ramping up. We now expect to be exiting 2020, 2021 with production in excess of 45,000 barrels of oil equivalent per day. And again, previously, our guidance was $43,000 per day. OpEx for the 2nd quarter was exactly in line with guidance at $15.60 per BOE. We are slightly revising up our full year guidance to now $15.50 per barrel, and that's largely a result of higher gas prices, which is good because it affects our revenue line, and we have been increasing some of our higher marginal cost production in Canada.
So both positives that are feeding into that increased guidance, and Christophe We'll refer to that in his presentation. The 2021 capital program is also being increased by $36,000,000 to now $73,000,000 You recall in our February Capital Markets Day presentation that we'd set a very conservative capital budget for 2021. It was going to be more than fully funded at less than $40 per barrel Brent. So with the stronger oil prices that we've seen, we're going to move forward with some very high return quick payback projects, and I'll touch upon I'll book of those later in the presentation. Essentially, it's the infill drilling campaigns that we make thermal in Canada and our Bertrand project in Malaysia, and we also have some additional optimization projects in both Canada and Malaysia.
Cash flow was very strong during the Q2. Our operating cash flow was 67 $1,000,000 that was higher than our high end guidance. And as a result of the very solid delivery in the first half, We're increasing our full year OCF forecast to $235,000,000 to $290,000,000 Free cash flow in the 2nd quarter was US50 $1,000,000 and again, we are increasing our full year free cash flow guidance on the low side from $55 Brent, dollars 135,000,000 to on the high side at $75 Brent, up to $195,000,000 And based upon the closing IPC share price on Friday last week. That translates into a free cash flow yield of somewhere between 18% 26%. The balance sheet continues to strengthen.
Leverage was down our net debt position was down to just over 240 $1,000,000
at the
end of the second quarter, and the leverage ratio continues to drop down to below 1.2 times at the end of June compared to 3 times at the end of 2020. We've also put in place some additional hedges. Christophe will go through the details in his presentation, and that satisfies all of our hedging requirements for 2021. And also, we've been very active on the ESG side, very pleased to report no material safety incidents during the Q2 that we've successfully secured the carbon offsets for 2021 on our 5 year journey to reduce our net emissions intensity by 50%. And we've also published our 2nd sustainability report alongside our 2nd quarter results this morning.
So to get into a little bit more detail, if we start with the production For the Q2, as I stated in the highlights, 44,600 barrels of oil equivalent per day. And if you look at the chart, you can see that that production during the Q2 was above our high end guidance for the 2nd quarter and succession. We've in Canada, we've had very high uptime performance in reservoir performance across all of our assets. We've been ramping up our production on some of our conventional assets at Mooney and the Onion Lake Primary and the planned maintenance shutdown that took place during the month of May was completed ahead of schedule and ahead of budget. So again, if you look at those strong production numbers, of course, it would have been even higher had we not had that turnaround during the Q2.
From the international assets, very good performance in Malaysia and France, and we took the decision to defer the Bertram shutdown from the second quarter until now later in the Q3. But we would still have performed above top end guidance had that shutdown gone ahead during the Q2. And I think if you look to the production that we've seen in July, which sits outside the Q2, We've had an early contribution from DPrime, and you can see from the chart on the right hand side of the page here Things are going very well indeed, and we're seeing some encouraging initial results there. So what does that mean in terms of the full year guidance? We are increasing our full year guidance now to in excess of 44,000 barrels of oil equivalent per day.
So more than 1,000 barrels all equivalent per day upgrade from the Q1 guidance. And we now expect to be exiting above 45,000 barrels a day given the extra interest in Malaysia and the production ramp up at our onion lake thermal D prime pads. In terms of operating cash flow, just to recap, when we gave our CMD guidance back in February, We were looking at a price range between $45 per barrel Brent on the low side and $65 per barrel Brent on the high side. And that gave a full year of CF guidance range on the high end of our production forecast of between $107,000,000 $220,000,000 If we look at the 2nd quarter cash flow generation of $67,000,000 that takes the first half Cash flow generation to $135,000,000 or 60% of our high case guidance. So clearly running ahead of expectation on the back of that strong production performance and tighter Canadian crude differentials.
And that's really allowing us to now look forward and upgrade our full year free cash flow guidance significantly. If we take out $55 per barrel for the second half. On the low side, we expect to generate $100,000,000 in the second half. And on the higher side, we're introducing a $75 per barrel upside case, which would add a further incremental US55 $1,000,000 which takes our revised full year OCF guidance to now between $235,000,000 to $290,000,000 So to put that in context, our low side $55 case cash flow generation is now ahead of our high side $65 case guidance that we gave at the beginning of the year. So very, very good cash flow generation in the first half feeding into that.
As a result of the strong commodity price environment, we did discuss in our Capital Markets Day in our Q1 results that we'd allowed for some long lead items on some high return quick payback projects, and we've decided now to move forward with those and to keep those during the Q4. So we're increasing the capital expenditure budget by $36,000,000 We're going to move forward and complete the drilling of the A14 A15 sidetrack on our Bertram field in Malaysia during the Q4. Whilst we have the rig on location, we're also going to take the opportunity to upgrade some of our ESP pumps. Feed pumps are going to be upsized. And in Canada, we're going to go forward with our 5 well infill program, Onion Lake Thermal and also some additional oil optimization projects at Suffield Oil.
We're not really going to see much impact on our 2021 production numbers. But what that will do is it should add in excess of 2,500 barrels a day of production growth as we move into 2022. And taking into account the increased capital expenditure budget for this year. We're still able to upgrade significantly our full year free cash flow forecast. If we go back and look at the same oil price range for our OCF, dollars 45 to $65 at the beginning of the year, we were looking at generating $39,000,000 to $155,000,000 of free cash flow for the full year.
With close to $100,000,000 in the first half alone or 2 thirds of our full year high side guidance. Looking forward at between $55,000,000 $75,000,000 we expect to generate an extra $36,000,000 to $96,000,000 during the second half. So that's allowing us to increase That full year free cash flow guidance to now between $135,000,000 $195,000,000 and that translates into a free cash flow yield of between 18% 26%, so some exceptionally strong cash flow generation numbers and multiples. And when we turn now and look at our full year guidance, there's no changes to the $55 to $65 per barrel case we guided back in February in excess of $600,000,000 to $900,000,000 assuming our average production of 45,000 barrels a day over the 5 year period. With Brent prices strengthening, we've added a $75 for barrel sensitivity, which uplifts our free cash flow guidance over the 5 year period to $1,200,000,000 And if we Look at the enterprise value of IPC last Friday less than $1,000,000,000 that means we could fully liquidate the enterprise value of IPC current prices in less than 5 years.
And of course, that gives us tremendous flexibility for stakeholder returns, debt reduction, share buybacks and dividends over the next 5 years, as well as funding our M and A activity and organic growth in the significant 1,000,000,000 barrels of contingent resources that IPC holds on its books. So very strong cash flow generation. If we Also look at IPC from a value perspective. This is our year end reserves valuation just on our 2P reserves. So just our 270,000,000 barrels of 2P reserves, no value to any of our contingent resources.
And it was a pretty conservative price deck that was used at the end of last year. And we were looking at $48 per barrel Brent for this year, rising steadily to $57 per barrel in 2025. That translates into net asset value of $1,300,000,000 effective date, 1st January of this year, our 72nd share. And today, IPC's shares are trading just over 40 2nd share. So more than a 40% discount and a pretty conservative oil price value on just our 2 key reserves.
Think IPC also looks extremely attractive through the value lens. If we turn now and just Take a quick walk through each of the individual assets starting in Canada and with Suffield Oil. You can see if you look at the chart on the bottom right hand side of the screen. We still got a very solid production performance averaging above 8,000 barrels per day. The outperformance continues to be driven by the end to end alkaline surfactant polymer flood that we've got running.
You can see from the blue chart on the top right hand side of the slide that project continues to run ahead of expectations And we're producing more oil today than we were back in 2016 when this was in the hands of Cenovus Energy. We don't have any major capital projects planned for this year, but we have added some additional optimization projects. We're going to convert 1 of the producers on our end to end project to water injector and some optimization on our South Gibson field in Suffield. On the gas side, we've seen very strong Canadian gas prices through the Q2, and that's been driven by a combination of much higher than normal temperatures, which has held back injections into Storage and storage levels have dropped below 5 year averages. So really good gas prices through the summer season, which is normally much weaker.
And of course, that's feeding through into much stronger cash flow generation from our gas assets. No new drilling at all on the gas properties, but still very active on the optimization front. And we're shooting to Schwab at least as many of the wells as we did in 2020, and we're well on track to achieve that for the full year. So you can see current production on a spot basis is still averaging around close to 100 1,000,000 standard cubic feet a day. So really good job from the team on the ground and holding that production flat and offsetting any of those natural declines.
Onion Lake Thermal, as I mentioned in the highlights, the shutdown during May was successfully completed on schedule, on budget. That allowed us Talked about shutdown, one of the work scopes was to tie in the Onion Lake D' prime well pad. The first Three wells were started up during July, and we've seen some encouraging early performance. The remaining 3 wells are planned to come on stream during the Q3. So we should see production steadily grow to an excess of 1500 barrels a day by the end of 2021, which should help feed into that exit rate guidance in excess of 45 1,000 barrels of oil equivalent per day.
In addition to that, we are now moving forward with the 5 well infill projects. You'll recall we had budgeted the long lead items for that project, and we wanted to see if oil prices would stay firm through the first half before moving forward with that project. That's obviously happened, and we are now going to move forward with that project. And if you look at The numbers on this slide, you can see why we're doing so. The breakeven on this investment In WCS terms, it's around US20 dollars per barrel.
WCS today is trading at somewhere between 55 in $60 per barrel. Rates of return, the Brent at $55 or in excess of 100%, and the payback is around 1 year at $55 per barrel Brent. So clearly, with oil prices where they are today, It's a very high return, quick payback project. So we'll be moving forward with this in the Q4, and that should help with some production growth as we move into 2022. Ferguson minimal activity, no capital allocated to the Ferguson property.
You'll recall that IPC acquired the Granite Company, which owned this asset in late 2019. There is the potential to more than double production with multiple drilling locations already identified, and you can see those highlighted in yellow in the bottom right hand side of this slide. The team has been very active and busy working on development plans, and that's likely to feature and our 2022 capital budget as we look to get started with the development of that field having taken a pause during 2020 as a result of the weakness that we saw as part of the COVID pandemic. On the conventional side, we've also been ramping up some of our production at John Lake and Onion Lake Primary with improved WCS pricing.
And Muni,
the EOR project was also restarted during the second quarter with stronger WCS pricing. And those have fed through into some of the increased production that we're now reguiding with both conventional and muni projects expecting to add about 1800 barrels a day of production during the second half of twenty twenty one. Blackrod continues to perform very well. You'll recall we did drill a 3rd pilot well pair Last year, the 1.4 kilometers in length, and we continue to see really good heap conformance from the heel to the toe of that well. And that's very important production you can see on a spot basis It's actually heading up towards 900 barrels per day, which is certainly ahead of where we expected at this point in time, notwithstanding the fact We continue to take a smaller number of the goal.
If we could We have a number of key priorities that we have in place. We We can produce higher than we can construct less well pads and that can be So we're continuing to see good and positive results from the 3rd well period at Blackrod. Turning now to the international assets and if we start with Malaysia, it's been another phenomenal quarter with production uptime of 100% through the quarter. We did complete that Most of you have seen We are pleased with our capital expenditure budget to move forward with the execution. Like, I think, you're in the Q1 of 2019.
The Brent prices today are closer to $75 A $55 Brent, the rate of return is in excess of 100 and 50% and the payback is in 1 year. So we expect to receive a payback on this at $75 certainly well below 1 year. So that well drilling is expected to be during the Q4 of this year and won't really impact What we're also going to do When the rig is on location is take the opportunity of that to increase the pump size in the main part of the Bertram field. During the shutdown in the Q3, we're planning to upgrade the liquids handling capacity of our FPSO. It's going to be increased from 17,000 barrels a day to 24,000 barrels per day, And that will allow us to produce not only the E15 well, but those additional producers at higher liquid rates.
And we expect incremental production adds from the A15 sidetrack in excess of 1500 barrels a day and around 800 barrels per day from the pump upsizing campaign. And again, if you look at the numbers, breakevens around $20 per barrel Brent, paybacks of 1 year, so very similar metrics to the infill drilling, and we'll be moving ahead with that once we've completed the A15 side trend in Q4. Turning to France now. If you look at the production chart, very, very steady production through the Q2, a good performance from all the major producing fields. Our VGR project, which was responsible for the production uplift in the second half of twenty nineteen, continues to exceed pre investment expectations.
If you look at the production plot on the top right hand side of this slide, You can see that we're producing effectively about 50% more on plateau than was in our simulation model. We've still not seen any water breakthrough from this well when it was simulated to come in Q3 of last year. And we're seeing a very good response from the conversion of VGR5 to water injector, which is providing pressure support to the 1-1-three well. So things still going very well in France, in particular, with our Verla Gravel project. And turning now to our sustainability and ESG.
Alongside this morning's 2nd quarter results. We are publishing our 2nd sustainability report, and we've stepped up The compliance with our GRI reporting standards, which is a global reporting standard, As part of that process, we conducted a company wide materiality assessment at the beginning of this year. So that really does lift the non financial disclosure of IPC to a different level. It really is an excellent report. I would Encourage everyone to read it.
There's a huge amount of fantastic work that's been done across all of our business units, and it's a great credit to all of those teams on the ground. And I would like to personally thank everyone for the great work that's been done. Just in terms of the highlights on our emissions, intensity reduction, the target to reduce by 50% through 2025. It has to be achieved through reducing our operations emissions and through carbon offsetting. And you can see we're making very good progress and achieving that in the 2020 net emissions sorry, our gross emissions were down from 40 to 39 kilograms per BOE.
We successfully doubled our offsets of from 50,000 to 100,000 tonnes in 2020, which reduced our net emissions intensity down to 33 kilograms per BOE, and we're well on track to meeting that net target by 2025 of 20 kilograms per BOE. So that concludes the operations update. So I'd like to pass the presentation across now to Christophe to run through some very nice financial numbers, and then we'll take questions at the end of both presentations. So Christophe, over to you.
Thank you, Mike. Good morning, everyone. Indeed, it's a good quarter with a very solid financial performance, And it's the Q2 in a row, which I'm happy to be here again. 2020 was obviously a bit more challenging, But we're back on track, evidencing IPC ability to generate very strong cash flows in a higher oil price environment. And I think the first important comment to make is the very strong operational performance across all of our assets, All of our geographies, we've seen a very high uptime, very good efficient operations from all the team around the world.
So it's a tribute to them to see production averaging in excess of 44,000 for the Q2 and averaging as well in excess of 44,000 BOE per day for the 1st 6 months. Obviously, carried by a very strong Oil and Gas price environment, the financial results are extremely strong as well for a second quarter in a row. And it's worth mentioning, I'll come back to that, but despite the fact that on average for the 1st 6 months, the Brent was at $65 per barrel, which was in which is in line with our high case during our Capital Markets Day guidance. The actual financial performance is much stronger, thanks to better realized prices in Canada, Both on the oil and on the gas side. So better operational performance ahead of our initial Capital Markets Day guidance, Better financial performance as well, which has led us to reguide both the production guidance in excess of where we were in excess of 44,000 barrels of oil equivalent per day for the full year and as well increase both our Operational operations cash flow, but also our free cash flow generation for the full year, and I'll come back to that.
The very strong operating cash flow and EBITDA at The $7,000,000 $65,000,000 for this quarter, respectively, translated into a very strong deleveraging as well. The free cash flow for the quarter is around $50,000,000 so $99,000,000 of free cash flow for the 1st 6 months, which obviously has translated into a very fast deleveraging. As a matter of fact, So you may recall, we our net debt to EBITDA, so our leverage at year end last year was just around 3 times And we're down to 1.2 times on a 12 months trading basis, so a very fast deleveraging. As I was mentioning, in terms of realized prices, even though the brand average for the 1st 6 months was exactly at 65 in line with our high case Capital Markets Day case, the realized prices were much stronger. And this is coming from the fact that In Canada, the WTI to WCS differential has tightened quite a bit and was around $12 Much tighter than what we had in our budget at 2017.
And so that translated into WCS average for the 1st 6 months of $50 And because we're selling both our Saffield Oil and Onion Lake Oil Production at $1 to $3 discount WCS. We had realized prices for Suffield and Onion Lake, respectively, at $49.40 $7 per barrel, which was much stronger again, as I said, compared to the compared to our guidance. And if you look even back at 2019, you can see that our realized prices in Canada Are much stronger than they were ever. So very good performance there. In Malaysia, we on average, we Taub, 2 cargoes at Brent plus premium of 3.
You guys are up a barrel. And France usually is exactly in line with Brent For some timing differences, average $1.5 above brands, but it's usually in line with brands. On the gas side, a very positive development there as well. First, if you look at the Q2, so we realized gas price sales in excess of CAD 3 per Mcf, which in itself is already the best performance ever since we acquired the Sulfill gas asset. Now almost more importantly, as the summer It was fairly hot.
There's been a lot of gas utilization generally in North America. And what that means is that there is less gas being injected in storage, Which is usually what's happening during the summer phase, where we're actually building up storage volumes for the winter to hit people, especially in North America and Western Canada in the wintertime. Now what's happening with that Is because the summer has been quite warm, there's a lot of gas utilization, which means also we anticipate there will be less Gas available from storage in the winter this winter. And so what that means as well is that when you look At the forward curve, it currently sits in excess of CAD 4 per Mcf for next winter. So Not only a very strong performance for Q2 now, but we're also very well positioned to continue to benefit from very strong gas realized prices.
This slide on operating cash flow and EBITDA is very much telling and illustrates IPC's ability to generate very, very strong cash flows in a higher oil price environment. I mean, that's more or less the same for all Oil and Gas Companies, but one of IPC's specificity is that we are not paying a very little cash taxes, Which means that together with a very solid control of our costs, we're able to generate Those strong cash flows in a higher oil price environment, that also shows that we have a very strong talk towards higher oil prices. And I'll come on again, but so we generated EBITDA and operating cash flow for 6 months in excess of $130,000,000 actually between $130,000,000 $135,000,000 during this those first six months. The costs, the OpEx per barrel, that remains totally under control. What happens is that we're reguiding The full year OpEx barrels of oil equivalent from 14.5 to 15.5, It is mostly a conscious decision.
What happened is that we're bringing back on stream some higher cost production, which is highly, highly valuable with very strong netbacks as we speak. So tiny bit of increased OpEx there, but it's an objective and conscious decision. The other one is that we've increased activity, Again, to maintain and increase production overall. So again, a conscious decision which justifies slightly higher OpEx there. The only thing which is outside of our control are increased electricity costs in Canada.
But obviously, the flip side Is that we're benefiting from some very strong and high gas prices, as I just mentioned. So overall, a good story. Costs Remain under control, and some of that increase is a conscious decision, still leading us to increase slightly our guidance for the full year at 15.5 U. S. Dollar per barrel.
Looking at the netback, it's a very interesting slide, especially if you compare that to our Capital Markets Day guidance. We generated for the 1st 6 months between $16.4 $16.8 per BOE of EBITDA and operating cash flow. And that is actually $3 higher Then our high case from our Capital Markets Day. So we've been able, with the conscious decision to have slightly higher OpEx, To increase our profitability by more than or just above US3 dollars per BOE of Operating cash flow and EBITDA, which is a very strong success. I was mentioning Previously, when you consider cash flows and deleveraging effort, as you know, we are not seeing cash.
And so all of the cash, which is being generated goes So far, to repay debt and deleverage our company, what happened is that so we generated $99, call it, dollars 100,000,000 of Free cash flow during the 1st 6 months this year. And that was all used to Financed the debt reduction, actually, euros 80,000,000 were used to repay debt. So we went from euros 320,000,000 down to euros 240,000,000 of net debt from the end of last year to the end of June. And we're obviously continuing in July August To deleverage, the full €100,000,000 didn't go into debt reduction because we had a negative Change in working capital, which is actually a positive just means that we have higher receivables as a result of higher production and higher Oil and Gas at realized prices. So overall, a very good story.
Now if you think again about what Mike was just mentioning at Beginning of this presentation, we are reguiding the full year free cash flow to Between $135,000,000 to $195,000,000 So if you want to be optimistic, roughly at current prices, we can expect to generate Another $90,000,000 to $95,000,000 of free cash flow. So everything being equal, if all this Additional free cash flow was dedicated to debt repayments, which is our primary target as we speak. The net debt at year end could fall to $150,000,000 So a very strong balance sheet. We should be in a very strong situation again from a balance sheet perspective with a very low gearing. The not only OpEx remain under control, As I mentioned, the G and A are fairly flat year on year at roughly €12,000,000 per annum, so roughly €3,000,000 between €3,000,000 for by quarter or for the 1st 6 months.
And in terms of interest Expenses, it's interesting to note that there is a double positive effect looking forward As we are going to deleverage, we have less debt outstanding. So we're going to pay less interest mechanically. But also the second positive effect is that Because some of our costs some of our cost of debt is linked to our leverage. So with an improved leverage, Our cost of funding is going to reduce as well. So we can expect you can expect a reduced cost of debt in the 3rd Q4 this year.
On the financial results, so we generated for the 1st 6 months Just short of US280 $1,000,000 which translates into roughly a 50% cash margin. So revenue less Production cost is roughly 50% of our revenues at a very high level, which translated into gross And net profits of, respectively, USD $121,000,000 for the quarter. Looking at the balance sheet, not much to comment upon with the exception of current assets And current liabilities. So current liabilities increased as a result of increased activity, both on the OpEx and CapEx fronts. But Current assets increased far more faster as a result, obviously, of higher production compared to last year, but also higher Oil and realized gas prices.
So we're expecting to receive more money effectively at the end of the The accrued revenues at the end of June, which we're cashing in which we cashed in, in July, have swollen a bit, Which is a positive. Everything being equal, if we were to stay at the same oil prices, we would see The change in working cap narrowing down. And so the USD 50,000,000 negative working cap Change would actually go to repay the debt by year end. So we're very well placed to continue to aggressively deleverage. In terms of hedging, so there was the conscious decision not to hedge any of our Malaysian or French oil production.
So we've benefited During this first half of the market prices, and we will continue to do so because there is no Oil hedging for French or Malaysian oil production. In Canada, we had some bank covenants, which we met. That was about hedging 40%. It was 25% in the first half and 40% of oil production in Canada had to be hedged, which we did now. Our strategy was to Put a floor at the high case of our Capital Markets Day.
So in our Capital Markets Day, we had 44 for WCS. So we managed to hedge exactly that level for the first 5,000 barrels a day In Canada, actually, we added another 3,300 barrels a day, but with a color, meaning that between $44.63 U. S. Dollar per barrel for the WCS, we're actually benefiting from the market price, which is what's happening now, as Mike mentioned. The WCS is trading between 55 and 60 now.
So we're benefiting fully from that Pricing will continue to do so in the second half. On the gas side, as I said, so we had some gas Sold forward or hedged for the Q2. We just placed some we have no more oil hedging for 2022. But for the gas, we started to layer in a bit of gas hedges for the Q1 next year, And we got the phenomenal we managed to lock in the phenomenal level of 4.40 catamcmcf for the gas. So very well placed going into the second half of this year and then into 2022 with an overall increasing production And still very strong prices.
In terms of hedging impact, We had hedging losses of around USD 15,000,000 for the first half this year. Everything being equal at the current prices, We would expect more or less the same hedging losses. So I think what we want to what I want to say here is that Without any hedges, the free cash flow generation ability of IPC for the first half was not $100,000,000 but was actually $15,000,000 And so everything being equal, if you annualize that, it means that at current oil prices, We could generate another $100,000,000 to $115,000,000 or $110,000,000 without hedging and $10,000,000 to $15,000,000 less with the current hedges we had in place. But so overall, a very strong performance in assets, which are performing very, very Well, in higher oil price environment, including because we're paying virtually no taxes in Canada and Malaysia and just a little bit in France. I will hand back the floor to Mike for conclusion.
Okay. Thank you very much, Christophe, great set of numbers. And just to go over the highlights again for the Q2, I think it's been A very, very strong performance in terms of the operational delivery. As I mentioned, 2nd quarter in succession where we've performed above our high side production guidance, 44,600 barrels of oil equivalent per day for the Q2, which is causing us to increase our full year guidance now to in excess of 44,000 barrels a day and our exit rates above 45,000 barrels a day, which is a 2,000 barrels a day increase relative to our February guidance. As Christophe has touched on, we're slightly edging up our OpEx guidance to $15.50 per BOE for the full year.
And we're also bringing forward some investments that would likely have taken place next year into the Q4 of this year in both Canada and Malaysia, the Onion Lake Thermal and Bertrand to add some high return quick payback projects to give us a production boost as we come into 2022. Very strong operational cash flow guidance for the second Assuming Brent prices to $55,000,000 in the second half or up to $195,000,000 assuming $75 Brent for the second half. And those translate into very attractive free cash flow yields of between 18% 26% based upon our market cap on Friday. Christophe touched upon the deleveraging. Net debt was down to $240,000,000 The leverage ratio falls to just below 1.2x by the end of the second quarter, so materially down from 3x at the end of last year.
And we've got some additional hedges in place through the second half that meet all of our hedging requirements. And Christophe talked about the uplift close to $15,000,000 alone in the first half had we not had those hedges in place. Again, very good performance on the ESG side, no material incidents to report during the first half. Our carbon offsets have been secured to increase or reduce our net emissions intensity during the Q2 and through 2020. And we've published our 2nd sustainability report.
And as I said, it's an excellent report, and I would encourage everyone to read the good initiatives that are ongoing within IPC. So that concludes the Q2. I'll ask Christophe now to come up and join me, and we can open up and take some questions.
Thank And we have a couple of questions coming through so far. The first is from Timo Seerman of SB 1 Markets, please go ahead. Your line is open.
Good morning, Mike and Kristopher.
And thank you for the update. A couple of questions for me. I just wonder, first, some I never thought on the cash flow story here.
Of course, you're
reducing debt substantially here. And in the long term, How do you think around dividend versus growth? 2nd question, General industry question for Canada actually. Do you see any cost inflation or are there any supplier bottlenecks at all? And my Question just on the your small OpEx or increased OpEx guidance.
What's the split between higher Energy costs and also an introduction of our high cost production. Thank you.
Okay. Thank you, Tidor. I'll Take the first two and then Christophe can take the 3rd question. In terms of the priorities between growth and dividends or I guess we can talk about share buybacks as well. I mean, I think We haven't changed our long term 5 year business plan.
And I think when you look at the cash flow generation that we've said, so between Brent prices of $55 and now up to $75 per barrel. That base business plan where we just liquidate Our 2P reserves and produce on average 45,000 barrels a day over the next 5 years It's going to allow us to generate somewhere between $600,000,000 $1,200,000,000 of free cash flow on the high side. So we can continue to invest in our 2P reserve base and some of our growth projects. But at these higher oil prices, All the debt can be repaid and every single share can be repurchased. And we'll still have 2 thirds of our reserve base at the end of the 5 year period and 1,000,000,000 barrels of undeveloped resource.
So we're not precluded From doing both is, I guess, the point I'd like to make. We've got huge financial flexibility to both pursue our growth opportunities and to return value to shareholders. And the second question, I think, was on the general cost environment in Canada. Christophe will answer the more specific question on OpEx. But obviously, we've seen higher gas prices feeding into higher electricity prices, but that's obviously a positive for us because we produce 100,000,000 standard cubic feet a day of gas and we consume only 30.
So that's a net positive. When we look at the moving forward with the infill drilling project, the 5 wells, we haven't changed our guidance on that CapEx of $7,000,000 from February. So we're not seeing any material in terms of the capital components of those investments that we're executing. Christophe, on the OpEx?
Yes. So on the OpEx, I think we mentioned, so what happened is that the country's decision to bring more production back on stream, some So which we shut in last year in the context of much lower oil prices. So for instance, some of the conventional, including new It was restarted in April this year, and the consequence was to increase the OpEx on the unit Per barrel basis. Now we also so that was a conscious decision. Another conscious decision was to work A workover somewhere else to maintain or increase slightly production.
So that was also a conscious decision for that was providing with very, very quick payback in the current oil price environment. What was imposed on us was some higher electricity costs. But again, The flip side of those increased electricity costs was the very high realized gas prices we saw during this First half, which is actually going to continue. As I just mentioned, when you look at the forward gas curve, It's actually increasing to well above $4 per Mcf during the winter period. So we We're not embarrassed, if you wish, by this slight OpEx for BOE increase.
It's actually good news because we bring more Production on stream with very strong netbacks in the current environment.
Okay, good. Thank you.
Thank you. Our next question comes from the line of Lars Amond of Armijo, please go ahead. Your line is open.
Hi, everyone. Congratulations to very strong results and broad based guidance raised. Our question and you can imagine what I would like to ask more in-depth is, we see that on a 12 month annualized basis, net debt to EBITDA is now going 1 on the last 12 months is just over 1 as you stated in the press release. And as you mentioned, Mike, is Obviously, you're going to produce a massive free cash flow amount over the next couple of years. So when is actually the starting time To buy back the shares because you increased free cash flow guidance despite more CapEx with major IRRs.
So when should we hear more about when you're going to start a buyback or paying a dividend?
Yes, thank you very much, Lars, for the question. Very valid question. I mean, I think we haven't changed Our messaging at all in this point since the beginning of this year, I mean, we so we obviously started the year with debt levels that were slightly on the high side coming through a rough 2020. And what we've said since the beginning of this year is the last time that we were in the market buying our shares back when that started in October of 2019. Our leverage levels our actual leverage on the last 12 months basis was below one times.
Now obviously, things have progressed extremely well through the first half, and we've seen Net debt come down, as you rightly see, from 3 times to 1.2 times. And based upon the guidance that we've given on a forward looking basis, Survived oil prices hold up, we will be dropping below one times by the end of the third quarter. And those were the levels, the last thing that we started a share buyback process. So I do understand that On an annualized basis, we're below one times, but I think we'd prefer to be just slightly more cautious and see the money in the bank and the debt levels down and before we launch shareholder returns.
So it means effectively that if oil prices or energy prices stay Roughly where they are and we get the same fantastic uptime that this is a talking point then for Q3 results.
I think what I'm saying is we'll certainly be below those leverage levels where we're doing share buybacks last time large.
So another question I have is on these projects is, obviously, Malaysia, you mentioned You're going to drill a 15 in the site track. And what is IRR on that one now in current oil price environment? Can you remind me on that? And then you're also going to do the ESPs, bigger ESPs. What is the impact going into 2022 on that Because obviously, we'll not be really affecting this year.
And then also on Onion Lake is what kind of More projects like in Onion Lake of more drilling, more pads, actually what can we expect there looking out, let's say, 12 months?
Thanks, Lars. So, yes, just as a recap, the investment, dollars 22,000,000 of CapEx for the A15 sidetrack And the rates of return on that project, which we disclosed a $55 per barrel Brent around 150%. So obviously, with oil prices above $70 and one can expect well in excess of 150% rate of return. If you look at it in terms of breakeven, less than $20 a barrel. And that well will be producing in excess of 1500 barrels a day of production when that comes on stream.
So Which
is sorry,
good afternoon.
Which is effectively now as you own 100 percent of Bertram in the FPSO and in the field is fully obviously now with Right.
Yes, that's exactly right, Lars. Yes, that's correct. So and then likewise, very similar metrics for to the pump upsizing campaign. So $20 per barrel breakeven, Brent, greater than 125% rate of return at $55 Brent. So, obviously, current price is well in excess of that.
And again, a payback of around a year at $55 So, under a year and to return the cash at current oil prices. And that adds incremental production on average of about 800 barrels a day for next year and that reflects the 100% interest as well.
So sorry, one more question then is on the final one for me to leave time for everyone else. On the site in Canada is So Christophe mentioned that there was obviously some hedging being put upon you Because of your debt, how is that really going to develop? And what is the relaxation of that? And is the strategy actually on the oil side to be completely unhedged Going forward, Christophe mentioned very, very high strong lock in of over $4 on the gas What is the strategy on the gas side hedging going forward?
Yes. So in terms of bank covenants So going into 2022, we no longer have any covenants. It's a semiannual discussion with our banks. So the discussion and the subject will come up again. But obviously, with the strong deleveraging and repayments, I think we will be in a position maybe to decide a bit more from our end.
The logic, as I was trying to explain for the oil hedges in Canada, was to secure at least The level we had in our high case, which we disclosed at our Capital Markets Day, so at the time was US44 U. S. Dollar per barrel for WCS. So that was the logic to pick that level, and we were able To have that level secured for the 40% for the second half this year, which was imposed on us. Going forward, I mean, we always have that discussion.
It's an ongoing discussion. It also depends on how much Cash, we have to use to we need to repay the banks. It may in the future depend on how much Cash, we commit to return to shareholders, which we want to secure and hence secure a minimum oil price level. It can depend on the level of CapEx And we want to that we want to ensure to be able to finance. So there's always a good reason to have that discussion, the strategic discussion to ensure We generate enough free cash flows to come up with the funding of the different use of capital.
Thermal gas.
Yes, exactly, on
the gas. Yes, on gas. What's happening in any case, we're producing too much gas To sell everything on the spot. So at the very least, we have to head 1 month ahead 70%, 80% of our production. Now when we see market windows opening like the one we're in now, where we can secure Hedges or forward sales at the level which we've never experienced before, frankly, since we moved into Canada.
The general strategy is that we give ourselves the flexibility to hedge with the board support, To hedge up to 50% or to sell forward up to 50% of our gas, especially at those level And keep probably 50% unhedged. That would be the rule of thumb. Bearing in mind, again, we've just locked in, so EUR 4.40 billion in the last 2 to 3 years When we were running our budget at between €250,000,000 €275,000,000 So those are significantly higher numbers and almost go straight into the bottom line.
As you mentioned Christophe that you had tremendous pricing now Forward. Would you be ready to hedge as much possible in the gas side and just keep the oil open? Or do you think it's Strategy wise, it's enough what you just did.
Yes. Yes, largely, I mean, I think as Christophe has said, It's always a balancing decision with the target to get up to 50%. I think there are some quite interesting dynamics, and We're seeing storage lack of storage injection through the summer where normally storage levels will be filling back up in anticipation of the much stronger winter demand season. So I think we'd still like to have some exposure to potentially tighter gas markets in the winter. So right now, I think a balance between 50% It's still a prudent level.
It gives our investors a bit of exposure. Should we see winter tightness materialize?
A cold winter could really send gas Prices in January, February, very, very high.
Thank you, guys.
Thanks, Lars.
Thank you. And the last question currently in the phone queue is from the line of Reuben Juer at Jefferies. Please go ahead. Your line is open.
Good morning, guys. It's Biren here, everyone. Thank you for taking my question and well done on the strong quarter. Is there a very quick clarification one for me? You mentioned the enterprise realization is going towards 4 dollars per year going down in 2021, I believe.
Any final realization you would Expected to hear about 2022 given the low score level you've mentioned.
Thank you very much. Ruben, sorry, it was the line quality It was very poor. Could you try one more time or maybe send it via messaging to Rebecca?
Yes. Sorry. I just wanted to clarify on the gas price realizations. So you mentioned that the level of the point is towards $4 per Mcf Going towards the end of 2021, I mean, the kind of realization we would expect to see throughout 2022, given the low story levels you mentioned.
So, Rupu was just asking what's the gas price we expect to see in 2022 given the low storage that we talked about previously and the $4
Okay, okay, okay. Yes, yes. Sorry, just the line quality, Ruben, was very bad. I mean, if we look right now, Obviously, there's a difference between winter pricing and summer pricing, but the latest numbers, if I recall correctly for full year strip for Eco Gas next year. You're looking at around dollars 3.20 to $3.30 per Mcf.
So to put that in context, as Christophe mentioned, Our kind of base case CMD planning assumption over the last 2 to 3 years has been around $2.50 So It's a decent uptick from historical levels.
Okay. Thank you very much. Sorry about the line.
That's okay.
And as there are no further questions on the phones at this time, I'll hand out the floor to Mike.
Yes. We've got a Two web questions here. I'm going to skip all the questions on buybacks and dividends, so that's the capital allocation. So first question, Mike, given the CapEx increase for 2021, do you maintain the cumulative figure from 21,000,000 to 25,000,000 £50,000,000
Yes, okay. Now the short answer to that one is yes, we do. As I mentioned In the presentation, if you go back and look at our Capital Markets Day presentation, we did set a very limited capital expenditure budget deliberately this year to maximize our free cash flow generation at lower oil prices. And what we saw is a step up in capital expenditure into 2022. So essentially, what we are doing by moving forward with the Malaysian and the Canadian investment programs in Q4 this year is bringing a portion of that capital forward.
So the short answer is there's no increase in that long term guidance.
Christophe, why has EBITDA not increased versus Q1, the higher WCS and then slightly higher operating costs?
Yes. So operating cost, obviously, is one element. The other one being the hedging losses, whether We registered almost €11,000,000 of €11,000,000 in Q2 of hedging losses.
So I guess the free cash flow generation of $50,000,000 it would have been unhedged, would have been more like $61,000,000 in Q2. So I think that does underpin the financial generation capacity assets going forward.
And just As well as what would be the impact of hedges on free cash flow in the second half of the year?
So we would expect it was 15% overall for the 1st 6 months, And we would expect more or less the same level as current oil prices stand.
And those are factored into the free cash flow guidance up to €195,000,000
Yes. So unhedged, the full year guidance Would have increased by almost €30,000,000 We're talking in the high cash to €25,000,000
We do have a question on how does IPC managed to pay such low cash taxes. So just as a reminder, we do have all of our tax elements Available on our website for presentation. And one of the biggest reasons, of course, is we've got $1,400,000,000 worth of Appreciation and tax loss instead of carrying forward in Canada that's CAD1.4 billion. So we'll be delaying cash taxes in Canada
That's on the edge, yes. Yes.
We have more or
less Yes.
We're almost in the same situation in Malaysia with some good Tax position meaning no tax payments and there's a limited tax payment in French.
Yes. There is just one more on capital Is your plan to reduce debt to 0 before returning any cash back to shareholders?
No, there's no firm plan to get to 0 for shareholder returns commenced. As I mentioned, back in 2019, leverage was just below one times and when we commenced our share buyback program, and we should drop to those levels during the Q3.
And can We expect to ramp up the CapEx for Blackbaud in 2022.
I think 2022 is probably on the early side. I mean, we've seen very encouraging production performance from the pilot well results, but we want to see those plateau levels sustained for a period. So I think 2022 would perhaps be on the early side to start serious development expenditure.
And on the M and A, what are your thoughts on buying producing assets? What sort of size production
We never set ourselves a target on production levels. But I guess, to go into if we decide to go into new jurisdiction, there obviously has to be something that's going to be material for the company. But still, we generally believe that IPC is well positioned to benefit from the whole energy transition, and we've definitely seen an uptick in the number of assets that are coming onto the market from the majors, but also coming out of private hands that have been perhaps going outside the original investment horizons. So I think the strategy of acquiring and producing assets and then applying our operational expertise to those assets has been and very, very successful. And we still remain very opportunistic and still quite excited to play a role in further M and E on the production asset Jade.
Okay. So I think that's all the time we have for questions. So apologies if anyone feels like their question hasn't been answered. Please feel free to email me separately and you can certainly follow-up. But otherwise, I think
Yes. Okay. Well, thank you very much for everyone who's tuned in this morning. I think it's been an exceptional second quarter, and I think Things are obviously continuing that momentum through the Q3 with continued strong oil prices and some production adds. So we look forward to presenting the Q3 results in early November.
Thank you.
Thank you very much.