Okay. A very good morning to everybody, and welcome to IPC's third quarter results and operations update presentation. My name is Mike Nicholson. I'm the CEO of IPC. Also joining me in presenting this morning is Christophe Nerguararian, the CFO. We also have Rebecca Gordon, who's our VP of Corporate Planning and Investor Relations. I'll begin in the usual fashion by walking through the third quarter operations update, and then I'll pass the floor to Christophe, who'll walk through the financial numbers. Then at the end of both of our presentations, we'll open up and you'll have the opportunity to ask questions. Before I get into the highlights, though, for the first quarter, we do talk internally within IPC a lot about excellence, and you're gonna see and hear this morning a phenomenal performance on the operations side.
I'd really like to thank all of our teams in Canada and in Malaysia, in France, and corporately in Geneva for really lifting our production levels back to pre-COVID highs and delivering such a phenomenal operational performance. When you combine that with the strong commodity prices we've seen across the entire energy complex, you're gonna see record high financial results when Christophe runs through his numbers. To start with the highlights for the third quarter and with production. Our third quarter average net production was just under 47,000 bbl of oil equivalent per day, above our high-end guidance for the third quarter.
As a result of the very strong year-to-date production performance, we're now revising upwards our full year guidance to in excess of 45,000 bbl of oil equivalent per day, and that's an uptick of 1,000 bbl a day from our second quarter guidance. Continued good control on the cost front. Operating costs for the third quarter were slightly below guidance, $14.70 per boe, and we're leaving our full year forecast of $15.50 per boe unchanged. On the investment and capital expenditure front, we are reducing our capital expenditure forecast down by $23 million to $50 million, and I'll come back to that. That's mainly as a result of the rephasing of some of our Malaysian expenditure into early 2022. Turning to the cash flow numbers. Record high numbers across the board.
Third quarter operating cash flow was above $90 million. As a result of that, we're now increasing our full year guidance to between $315 million and $335 million. Likewise, record high free cash flow generation, $77 million for the third quarter. Again, we're increasing our full year free cash flow guidance to now between $240 million and $260 million. That translates into full year free cash flow yield of somewhere between 28%-30%. Phenomenal numbers there on the cash flow side. That's of course, fed into significant deleveraging through the third quarter.
The net debt has dropped to just over $160 million, and of course, that's had a profound impact on our leverage ratio, which has now dropped to 0.6 x compared with 3 x net debt to EBITDA at the end of 2020. Christophe will come back to it in his presentation. As we see the hedges roll off, the bank-mandated hedges, that's obviously feeding through into stronger free cash flow generation. Of course, we don't actually have any oil hedges in place in 2022, so that should set us up for continued strong cash flow generation as we move into 2022. Continued excellent performance on the ESG side. No material safety or environmental incidents to report.
We did, alongside our second quarter results, deliver our second annual sustainability report. In that report, we did confirm that we'd secured the carbon offsets that we need for 2021 to bring our net emissions intensity down by 50% by 2025. As a result of the exceptional operational delivery, and strong financial performance, very pleased to be announcing this morning that we're applying to commence our third share repurchase program since the company was spun off back in 2017. That's the highlights. Let's start now to go through in a bit more detail the production performance. At third quarter, production was 46,800 bbl of oil equivalent per day. Exceptional production performance across all of our business units.
If we start with Canada, you can see from the production plot on the slides that we did take the shutdown at Onion Lake Thermal during the second quarter. That was to set us up for our Onion Lake Thermal de-prime pads. That's been brought on stream and has been ramped up ahead of schedule and is delivering above our forecast expectations. A really good start from the Onion Lake Thermal team. During the fourth quarter, we're making good progress with our five-well infill campaign. Don't really expect much production contribution during 2021, but that will add some production growth as we move into early 2022. On the international assets, again, continued strong production in Malaysia and in France. In Bertam, we did complete the shutdown during the second and third quarter.
That was to set us up for the infill sidetrack drilling campaign on our E15 well in our Bertam field. That shutdown was completed ahead of schedule, and we're on track to commence drilling operations in the fourth quarter with a production start-up early in the new year. I'll come back and give a bit more color on that later in the presentation. If we look at that strong third quarter production performance, that's allowed us to now raise our full year guidance to in excess of 45,000 bbl of oil equivalent per day, up from our Q2 guidance of 44,000 bbl of oil equivalent per day.
If you look at the chart on the bottom of the page, you can see that this is our third quarter in succession of delivering our production above the high end of our guidance estimates. Again, huge congratulations to all of our teams for delivering such a solid performance. We've seen production recover to pre-COVID highs, which is no mean achievement. Turning now to operating cash flow. Operating cash flow for the first nine months was $226 million. That's on the back of an average Brent price of $68 per barrel. In the first nine months, we've been able to generate more than our original CMD high case forecast of $220 million, which was assuming a Brent oil price of $65 per barrel.
The reason we've been able to deliver such strong cash flow generation is a combination of that higher production performance, better Canadian crude price differentials, and stronger Canadian gas prices. That causes us now to increase our full year guidance for operating cash flow to now between $315 million and $335 million, assuming a $75-$85 average Brent price through the fourth quarter. Capital expenditure, as I mentioned in the highlights, we have reduced our full year capital expenditure forecast by $23 million to $50 million. That's just due to the latest estimates of when the rig is expected to arrive in early December on our Bertam field location. The majority of that drilling expenditure is now rephased into 2022.
Full year CapEx expenditure forecast now of $50 million. When we combine that strong operating cash flow and a relatively light capital expenditure budget, we're seeing record high free cash flow generation for the company forecast for the full year 2021. For the first nine months alone, we've generated more than $20 million above our original CMD high forecast, $176 million for the first nine months. When we look forward for the fourth quarter, we're significantly increasing our full year free cash flow guidance, now up to between $240 million-$260 million between $75-$85 Brent, up from $195 million for the full year that we announced alongside our second quarter results.
When you look at IPC's closing market capitalization at the end of last week, that translates into very attractive 28%-30% free cash flow yield for the full year. If we just put that free cash flow yield in context with the rest of the global integrated E&P industry, it compares extremely favorably. This slide shows a survey of the expected forecast free cash flow yields across that entire integrated E&P industry space. It was a report recently issued by RBC Capital Markets. You can see that the range of free cash flow yields expected for 2021 are between 8%-16%, with an average for the industry of 12%. When you look at IPC's numbers of somewhere between 28%-30%, we're producing cash flow more than double the industry average, which is quite extraordinary.
When we look beyond just the 2021 numbers in our five-year forecast, which only assumes that all we're developing is our 270 million bbl of 2P reserves, we're in a position to hold our production levels today of around 45,000 bbl a day flat over the next five years. You'll notice at the bottom end of the range, we're increasing our guidance by $ 140 million, so increasing it from $600 million to now $740 million to take account of the strong 2021 cash flow performance. At the high end of $75 per barrel, we can generate up to $1.2 billion of free cash flow. That translates into an annual free cash flow yield of between 17% per annum and 28% per annum.
Oil price is $10 a barrel below where we are today. We can sustain these free cash flow yields that we're generating this year for the next four years, which I think is extremely impressive. Of course, that sets us up to continue to generate significant shareholder value in the years ahead through a combination of stakeholder returns in the form of further debt reduction. Today we're announcing our third share buyback program. Obviously, IPC's history and our D&A is M&A, and we've conducted four transactions and acquisitions in the last four years. Of course, we have the capacity to do more in the years ahead as we see the energy transition, and we see the majors look to dispose of some of their non-core assets. Of course, we still have a very significant contingent resource base in excess of 1 billion bbl.
Great strength on the financial front to continue to generate material shareholder value. On the valuation side, if we look at how IPC stands and compares based upon very conservative year-end 2020 pricing, which assumes $48 Brent for this year, rising to only $57 per barrel by 2025. That gives you an asset value of $1.63 billion. If we take off the beginning of the year debt, that gets you down to a 2P net asset value of $1.3 billion or SEK 72.50 per share using the current exchange rate. Which translates into a 34% discount on some very conservative oil pricing. Either through the cash flow lens or the value lens, I think IPC screens extremely favorably.
Turning now to the announcement this morning and the share repurchase. Those that follow the company know that we have already completed two share repurchase programs since the company was created back in 2017. In those first two programs, we've acquired and canceled a total of 34 million shares, and the average share price was just below SEK 33 per share. A lot of value created from those first two share repurchase programs. This morning we're announcing the third share repurchase program. As I mentioned, we've seen very good operational performance. Our production this year looking to be around 5% above our original high-end Capital Markets Day guidance forecast. We're seeing continued strong pricing across the entire energy complex.
We've seen, our 2021 free cash flow is significantly above our original high-side guidance and is more than double that of the global E&P industry average. Leverage is dropping like a stone, 0.6x net debt to EBITDA at the end of the third quarter. From a value perspective, looking extremely attractive with a close to 34% discount from our 2P net asset value. That does not include a single dollar of value attached to our in excess of 1 billion bbl of contingent resources. That's a very attractive value proposition, and that's why we're seeking approval to repurchase up to 10.8 million shares or approximately 7% of our shares outstanding over the next 12 months under the Canadian Normal Course Issuer Bid rules.
Turning now to dive into a bit more detail on each of our assets, and starting with the Canadian business and our Suffield oil asset. Strong production performance continued through the third quarter, averaging around 8,000 bbl of oil per day, back to above early 2016 levels. We're seeing continued strong outperformance from our end-to-end EOR development project that we started a couple of years ago. Don't have any major capital activities planned this year, but what we do still have a significant drilling inventory ready for execution that's likely to feature in our 2022 drilling programs. This year, focus was really on end-to-end well conversions and some optimization work on our South Gibson field to keep those production levels relatively stable through the year.
Turning to Suffield Gas, it's no surprise that we've seen extremely strong gas prices across the globe, and that's also been a feature of the Canadian market. Christophe will show in his presentation some of the recent gas price trends, which have been very strong in Canada. Our Suffield Gas asset continues to generate very strong cash flow. We aren't investing any capital in 2021. We haven't drilled a new well since we took over operatorship. What we can do, and you can see from the chart on the bottom left-hand side of this slide, is be very active on our optimization front.
Since we've taken operatorship of this asset, we've close to doubled the amount of swabbing activity, and that's allowed us to keep that gas production relatively flat and offset those natural declines in our Canadian Suffield Gas business. Great job done by the teams on the ground with very minimal capital there. Turning to our Onion Lake Thermal asset. You can see on the production slide that we successfully completed our planned shutdown and turnaround during May. That was to allow us to tie in our new D Prime well pad.
That D Prime well pad was completed and brought online ahead of schedule in the third quarter, and we expect that to ramp up and add production in excess of 1,500 bbl of oil per day on plateau. The rig's now moved, and we're in the midst of our five-well infill drilling campaign, which is due to complete before the end of the fourth quarter. The wells are drilled, and we're just working on the completion and the tie-in, and we should see the production impact start to really ramp up during the first quarter of next year. Really good performance by the team in delivering the shutdown, getting D Prime on stream and making great progress on our five-well infill drilling program.
Just as a reminder of the numbers that we showed alongside our second quarter results for that five-well infill program, extremely attractive metrics. We're tackling about 3.5 million bbl of unswept oil with a break-even WCS price of $20 per barrel. When you look at WCS prices today trading close to $70 per barrel, and with a payback at Brent prices of $55 per barrel in only one year, these are extremely attractive infill wells to be executing. Turning to our Ferguson asset in Canada, minimal investment activity during this year. We have done some gas injection and repressurization work through some low cost effective well conversions. We've got the potential with this asset. This is the asset that we acquired from Granite in late 2019.
We did suspend all redevelopment activity during the pandemic last year. We have got the potential to more than double our production with multiple drilling locations, execution ready, and this is likely to feature in our development plans as we move into 2022. On the conventional side, our John Lake and Onion Lake Primary has been ramped up with the very strong Canadian pricing environment that we've seen. Likewise, with our Mooney asset, we're also ramping up production that we started in the second quarter, again, with the strong Canadian crude pricing. When we look at our overall Canadian conventional assets, we've been able to ramp up production to around 1,800 bbl of oil equivalent per day.
Again, tremendous job done by the team to reduce that production last year through the pandemic and bring it back up to pre-shut-in rates following the recovery that we've seen in Canadian crude pricing. Blackrod, which is the biggest portion of our contingent resources, just under 1 billion bbl of our contingent resources. The third well pilot program continues to exceed expectations. You can see the recent production. We're sustaining production at above 800 bbl of oil per day, and that's close to 50% increase in the productivity that we saw from well pair two. That's important because if we can drain more oil from a smaller number of wells, it can improve the overall project economics through less well pads, less infrastructure, reduces our environmental footprint.
Continued good response that we're seeing on that third well pair pilot on our Blackrod project. Turning now to the Malaysian business. Every quarter, we have the same story, close to 100% facility uptime on our Bertam FPSO and a strong base well production performance. During the third quarter, we did complete a planned maintenance shutdown slightly ahead of schedule and on budget. One of the main reasons that we wanted to take that shutdown was to increase the produced water handling capabilities of the Bertam FPSO. That sets us up to drill the A-15 sidetrack, produce at higher liquid rates, and also the pump upsizing campaign that will follow the A-15 drilling. Again, great job done by the team to deliver that Bertam FPSO debottlenecking project. The A-15 sidetrack well has been sanctioned.
As I mentioned in the highlights and the capital guidance, this still is scheduled to commence drilling in Q4. It's now likely to start in December of this year, slightly delayed from our original plans, and that's as a result of the operator who has the rig having to sidetrack the last well in their drilling program, resulting in a delay in us picking up that rig. First oil is now not expected until early 2022. Amazing project, 1.5 million bbl of resource to attack. Break-even Brent price of less than $20 per barrel. Of course, our Bertam crude trades at a premium to Brent. With Brent prices in excess of $85 a barrel with the premium, amazing rates of return from this project.
150% rate of return at $55 per barrel and a $55 per barrel Brent one-year payback. Results are likely to be much better than those that we're publishing here on this slide. The pump upsizing campaign, which will continue after the drilling of the A-15 well in the first quarter, is expected to be completed before the end of the first quarter. That should add incremental production on average of around 800 bpd , and very similar metrics to the A-15 drilling, $20 per barrel Brent breakevens and paybacks around one year at $55 per barrel Brent. A nice production bump that we should see on our Bertam asset as we move into the new year. In France, same story again, excellent performance and delivery from all of our producing fields.
If you look at the production plot on the top right-hand side of this slide, you can see the performance of our long-reach horizontal VGR-113 well. Production rates have stabilized at around 900 bpd . You can see from our pre-investment forecasts, which were around 600 bpd , we're producing at 50% above those expectation levels. It's been a tremendously successful drilling campaign on our VGR project. We had originally expected water breakthrough to come a year ago in the third quarter of 2020, and we still haven't seen any water in this well through the third quarter of 2021. Good results that we're seeing from that VGR-5 injector conversion that we did to support pressure to the 113 well.
Very stable production in France over the last quarter at around the 3,000 bpd level. Finally, on sustainability and ESG, alongside our second quarter results, we did publish our second sustainability report. We conducted a materiality assessment earlier this year, which means that the report just issued is fully GRI compliant. One of the core principles in terms of our emissions reduction strategy is to reduce IPC's net emissions intensity by 50% through 2025. We've been able to do that through a combination of reducing our operations emissions and securing carbon offsets. We've doubled the number of carbon offsets to cancel through 2021, up from 50,000 tons last year to 100,000 tons for 2021. That's been done in conjunction with our partner, First Climate.
That concludes one of the record quarters that we've ever seen since IPC was started back in 2017. I'll pass the floor now to Christophe, who will go through in more detail the very strong financial numbers. Christophe, I'll pass the floor to you.
Thank you very much, Mike. Good morning to everyone. Indeed, it's very pleasant to be here standing in front of you again for a very good set of results. The first comment, and I think Mike insisted, and rightly so, we've been carried by a very supportive oil and gas price environment, obviously. But the performance of our assets in terms of production is nothing short of exceptional, being significantly above the high end of our capital markets previous guidance. For the third quarter, with production that is just short of 47,000 bbl of oil equivalent per day, it brings the nine months average in excess of 45,000 bbl of oil equivalent per day.
We feel now comfortable to guide that we should be in excess of that level for the full year guidance. As I just said, the oil price environment is very supportive. We saw an average Brent price of $73.5 per barrel for the third quarter and an average of $68 for the first nine months. As you know, the fourth quarter seems to point even significantly higher than that. We expect the good performance to continue and improve again in the fourth quarter.
Operating costs remain under control and have been a bit lower in this third quarter at $14.7 per boe, lower than the previous two quarters, and that's a direct reflection of the higher production during this quarter. Operating cash flows and EBITDA for this quarter are around $90 million, giving the full first nine months operating cash flow, which as you know, are the revenues less OpEx, less cash taxes in excess of $225 million. As a result, the net debt has reduced significantly, actually halved from the end of last year, from $321 million down to $161 million.
We expect that net debt to continue reducing significantly between now and the end of the year. Already net debt to a 12 months EBITDA on a rolling basis has come down from 3x last year to 0.6x and should further reduce, as I just said, at the end of this year. Another important measure obviously is the free cash flow, which was a record high this quarter at $77 million and $176 million for the first nine months. We had some oil hedges where we lost for the first nine months, $23 million. In the absence of any hedging of free cash flow for the first nine months would have been actually $200 million.
Again, a record high since IPC inception. In terms of realized price, as I said, it's been the most supportive oil price environment at least since 2019. We can note that the differential is very important. It's not just the headline Brent prices we need to focus on, but obviously, it's the WTI, and also for Canadian business, as you know, the Western Canadian Select and the differential between the WTI and the WCS. The Brent WTI differential has been consistently tight around $2-$3 per barrel over the last couple of years, much tighter than in 2019. The very important point is that the WTI WCS differential has been constantly tight around $12-$13 per barrel over the last two years.
It's really an important factor because you see that over the last two years, the WTI has considerably increased, but the differential has remained at the same level. Obviously, our realized prices have considerably improved over the last 18 months. In Malaysia, we consistently sell above Brent price, so realized prices for the first nine months are $2 above the Brent level. But I'm happy to report that the market continues to pick up, and we see that premium significantly increasing again in Malaysia. In France, we tend to sell just on par with Brent. That is the case for the first nine months at just $0.60 above the Brent price for the first nine months.
In terms of the WTI, it averaged $52.5. As we speak, we are much closer. We're in between $68-$70 for the WCS. You can expect a much stronger, even much stronger realized price for Canadian oil production in the fourth quarter. Looking at the gas prices now. It's since the logistical issues that the gas network faced in 2019 in Alberta. That was fixed at the end of 2019. You can see on that graph that there's a very strong correlation between the U.S. Henry Hub gas price in dollar per MMBtu, and the AECO, which is the Alberta reference gas price, in Canadian dollar per Mcf.
It may not be exact on a day by day basis, but over a week or a couple of weeks, the correlation is extremely strong. This is what you see on this graph with the blue line. In terms of realized price, you can see that going ahead, the Henry Hub continues to increase and so does the AECO gas price. Again, even more constructive gas price heading into Q4. Not to mention that on average, you can sell at the AECO gas price in excess of CAD 4 for the entire year next year, 2022. Looking at the realized price for the third quarter, we realized CAD 3.72 per Mcf.
That was the best performance in the third quarter ever and close to the highest for IPC. Looking now at our operating cash flows and EBITDA. I mean, as much as 2020 was difficult, it's very nice actually to be comparing our performance, our financial performance in 2021 compared to last year. You can see that IPC assets and portfolio of assets are extremely torquey to the oil price. In a much higher oil price environment, the financial results and the torque is phenomenal to that upside.
I won't dwell on the numbers again, but just mention that for the first nine months in this year, the EBITDA and operating cash flow are both in excess of $220 million. In terms of OpEx, you can see a reduction this quarter, which was mainly driven by an increased production, close to 47,000 bbl of oil equivalent per day. We're maintaining our full year guidance at $15.5, but it's fair to say it's probably on the conservative side. We expect to be better than that for the full year, depending on where the production stands for the fourth quarter. It's looking good so far.
In terms of net back, happy to report that our operating cash flow and EBITDA on the U.S. dollar per barrels of oil equivalent basis for the third quarter was $7-$8 higher than the high case we previously guided at our capital markets day. Really strong performance. You realize that because there's a very low level of cash taxes, we basically only pay cash taxes in France 'cause we have lots of tax losses going forward. We benefit almost directly to the bottom line of all the increased oil and gas prices. Looking at the cash flows, the operating cash flow, and how that contributed to the net debt reduction I mentioned. The net debt halved in nine months.
We went from a net debt of $321 million at the end of last year, down to $161 million at the end of September. The trend is expected to continue, obviously, in the fourth quarter. It's good to see that G&A OpEx are under control. The operating cash flows increased significantly, so did the net debt reduction as a consequence. Just talked about OpEx. In terms of G&A, they remain flat and under control as well, and in line with the previous years. We're managing to maintain low and essentially flat G&A costs year and quarter on quarter. In terms of the financial items, it's important to focus on the cash items there.
You can see as a consequence, obviously, of the debt reduction, the cash interest expenses and related loan fees are reducing in the same proportion. Looking at the financial results. We generated over the first nine months in excess of $450 million. That generated a cash margin of just shy of $230 million. Gross profit of $131 million, and the first nine months net results are just shy of $80 million. Looking at the balance sheet, you can see that we've had, as you know, and as Mike mentioned, a reasonably light investment CapEx this year.
The depletion of our assets was higher than our CapEx, showing a reduction in the value for oil and gas properties. The current assets increased as a result of higher receivables due to just higher production and higher oil and gas prices, as well as increased inventory, because we were carrying a lot of oil on our FPSO Bertam at the end of September, as we were gonna have a lifting in October, which happened already. On the liability front, the obvious point to note is the reduction in financial liabilities, which we've described already. In terms of hedging, nothing changed really from last quarter. We are not hedging any oil from our Malaysian and French operations.
We have a very low leverage there and a reasonable low CapEx program, and that CapEx program has a very quick payback. We didn't feel like we had to do any hedging there. In Canada, we had roughly 40% of our oil production hedged for the second half this year. At this stage, we've not put in place any oil hedges for 2022, given the very strong market dynamics there or expected manageable CapEx program for 2022, which we will disclose to the market at our capital markets day next February. We fully benefit from the potential upside at this stage for 2022.
In terms of gas, we've hedged roughly 20% of our gas production for next year's first nine months. We might put a few more hedges for gas, given the very strong market again, as I said, for the entire next year. You know it's cyclical. Prices tend to be much stronger during the winter period, but including winter and summer for the whole of next year, we could actually sell forward some of our gas in excess of CAD 4 per Mcf, when historically we've set our budget for the year at CAD 2.50. It tells you how strong that market is and how profitable our gas business is in Canada.
Lastly, as I touched upon the free cash flow for the first nine months was as high as $176 million for the first nine months. Had we not hedged anything in 2021 so far, the free cash flow would actually have been $200 million because we had $23 million of hedging losses. We're obviously happy where we stand and expect to post another good quarter next quarter in terms of free cash flow. I will let Mike conclude. Thank you very much.
Thank you very much, Christophe. We can all agree it's been phenomenal set of numbers delivered during the third quarter. Just to come back and conclude again with the highlights for the third quarter of 2021. It's been an extraordinary operational delivery across all the business units. Production for the third quarter above high-end guidance, just under 47,000 bbl of oil equivalent per day. Increasing guidance again, now to above 45,000 bbl of oil equivalent per day for the full year. As Christophe alluded to, below guidance OpEx during the third quarter, and probably a relatively conservative $15.50 forecast retained for the full year. The capital expenditure program now expected to be $50 million, with some rephasing of our Malaysian CapEx into early next year.
Eye-watering cash flow numbers, $91 million of OCF for the third quarter, a record for the company, allowing us to uplift our guidance for the full year to $315 million-$335 million. Free cash flow in just one quarter of $77 million, again leading to an uplift on our full-year numbers, up to $240 million-$260 million. As Christophe mentioned, if we didn't have any hedges in place for this year, we would have been heading more towards the $300 million level. That represents on those forecasts a full year free cash flow yield of between 28%-30%, which is more than double the global E&P industry average.
Net debt dropping like a stone, just over $160 million by the end of the third quarter. Leverage is down to 0.6x relative to 3x at the year-end. As Christophe mentioned, the fact that we have not got any oil hedges in place for next year means that like for like, the cash flow generation capacity of the assets should be stronger as we move into 2022. ESG side, no material safety or environmental incidents. Second sustainability report published alongside our second quarter results, fully GRI compliant, and on track to deliver our net emissions intensity reduction by 50% through the end of 2025. Last but not least, on the back of such strong operational delivery, and strong energy prices across the entire complex.
The value proposition and free cash flow yields that we see for IPC lead us to be very pleased to announce our third share repurchase program this morning, following our spin-off in 2017. That concludes a record-breaking quarter for the company. Happy now to pass the call back to the operator, and we can take questions from those joining on the conference call, and you can also send in your questions via email. Let's open for questions.
Thank you. If you wish to ask a question on the phone lines, please dial zero one on your telephone keypads now to enter the queue. Once your name is announced, you can ask your question. If you find it's answered before it's your turn to speak, you can dial zero two to cancel. Our first question comes from the line of Teodor Sveen-Nilsen from SB1 Markets. Please go ahead. Your line is open.
Good morning, and thanks for taking my questions. Three questions. First one on your share repurchase, which is good to see that you announced it. I just wanted to hear your consideration on cash dividend versus buyback. Why do you prefer buybacks? Second question on the phasing in Malaysia, how should we assume that will impact 2022 production? I guess it maybe will be a minor negative effect. Third question is you highlighted that you have a hedge on some gas for 2022, but no hedges in place for oil. Just wanted to hear whether it's tempting or not to put in place some oil hedges for next year. Thanks.
Yeah, thank you, Teodor. I'll take the first question on the rationale for the share buyback. I think as we alluded to in the presentation, I think if you look at where IPC is trading in terms of its free cash flow multiple, you know, relative to our market cap, you know, more than double the industry average or on some extremely conservative oil prices. You know, going from $47 this year up to $57 by 2025. We're still trading at a 34% discount to our 2P net asset value. You know, with such strong metrics, that was really what favored us moving forward with the share buyback as our first step in shareholder distributions.
The second question on the phasing of the Malaysian drilling, we expect to pick up the rig and commence drilling in early December. So really that $23 million that's been rephased from 2021 into 2022 is likely to be largely spent in the first quarter of 2022 with early production during that first quarter from the A-15 sidetrack well. Third question on hedging. Christophe, do you wanna take that?
Yeah, on hedging. Yeah, no, you're right. At this stage, we don't have any oil hedging for 2022. Really, if you look back over the last three years, on average, we had 20%-25% of our Canadian oil production hedged. Which was a combination of factors and driven by the level of CapEx and the level of debt. As I was hinting before, we expect for the significant reduction in our debt by the end of this year, and a manageable CapEx program, and we tend to set our budget also at a lower level than the oil price we see in the market.
The third element is that the market's in backwardation, so actually you can hedge at a significantly lower level than what the current oil prices are. When you put all of these elements together, I'm not suggesting we will never hedge 2022, but the reality is that we are not hedged, and we don't have any immediate plan for hedging. We would like to offer that upside to our investors and shareholders for the time being, and the spending in terms of future CapEx, debt load, or buyback is obviously included in this reflection. Now, in terms of gas, we've seen gas prices soaring across the globe.
Maybe not as much in North America than we've seen in Europe, but still a very significant run in Canada following the Henry Hub. That's why we were showing the correlation between the Henry Hub and the AECO gas price. We might add some hedging there. We've hedged already 20%, and we expect another good year in 2022 based on what the forward market suggests.
Okay. Thank you. That's clear. Congrats with strong results. That's all from me. Thanks.
Thanks, Teodor.
Thanks.
Thank you. Once again, if there is any further questions, please dial zero one on your telephone keypads now. Okay, currently there seems to be no further questions from the phone lines.
Okay. Thanks, operator. We have a couple of web questions here. Christophe, first of all, can you comment on the profitability of the gas business for IPC?
Yes. We usually don't really disclose the OpEx per Mcf. What I can say is that we already enjoy a very good profitability when we use a CAD 2.50 per Mcf for budgets. You can imagine that CAD 3.5, CAD 4.5 the gas prices actually for next winter, for this coming winter across end of 2021 and early 2022 is CAD 5 per Mcf. We're talking about a multiple Canadian dollar per Mcf profitability net of OpEx.
Thanks, Christophe. Mike, we have a couple of commodity price questions here. Commodity price environment, how is it impacting the asset market? Are you still seeing opportunities for value accretive deals in Canada?
Yeah. I mean, of course, it's definitely having an impact on the asset market. I wouldn't say that companies are rushing to materially upgrade their long-term oil price forecast for acquisitions to anything like $75-$85 right now. I think what you have to do now in the asset market is be more creative when you're structuring acquisitions. For example, typically at this point in the cycle, when you see such a rapid increase, contingent payments and some of the upside share start to feature in transactions enable them to proceed successfully. It's really just structuring things tend to change when you see such an uptick in commodity prices. There's absolutely still you know interest in assets out there in the market in Canada and internationally.
We always keep our discipline. It always has to start with the quality of the subsurface. We're still as active as ever on the M&A front. You just have to be more creative on your deal structuring.
Okay, thank you. Thinking about 2022 in particular, are you looking to dividends and buybacks as a solution to squeeze that differential between the market cap and NAV? Specifically, when will you consider a cash dividend?
The short answer is yes. We announced this morning the third share repurchase program. Clearly with free cash flow generation of between $740 million and $1.2 billion between $55-$75 Brent, as we've said, we've got a lot of flexibility to look at returning cash to shareholders in the years ahead. Very pleased to announce the commencement of that this morning.
Okay, how do you plan to monetize Blackrod's resources?
I think it's a stepwise process and, you know, I think when oil prices were much lower a couple of years ago, we took a fairly bold, contrarian move to continue to invest and complete the third pilot well pair, extending the length of the horizontal drilling section by 50%. The first answer is by using the latest technology and drilling long-reach horizontal wells to improve the productivity of the project and to try and get the cost base down. That was one of the first tenets of unlocking the value proposition on Blackrod.
The second, as we've said for many years, and it follows the contrarian approach we took to the three Canadian acquisitions we've made in the past four years, was waiting for the egress position and the pipeline situation to improve. With Enbridge's Line 3 coming on stream during mid-October, and Trans Mountain likely to be completed by the end of next year. That completely changes the market dynamic for Canadian egress and should materially change the outlook for Canadian differentials in the next five to 10 years. Of course, that provides a much solider commercial framework for where Canadian crude price differentials sit. Of course, with very, very strong benchmark prices and projects like Black Rod start to become more interesting. I think it's a combination of technology and the market environment.
As we see things, you know, those things are starting to cooperate in synchronization. We just need to see the continued sustained productivity of our third well pair. So far so good.
Is Canada likely to remain the focus region for M&A, or are there any other geographies you prefer, like Africa or Malaysia?
Nothing's really changed since the spin-off. As I mentioned, if you look at any of the Lundin Group companies, where they were successful in creating value, it starts with the quality of assets. We continue to screen assets in Canada and internationally. If we can see the upside that we can bring and unlock that value, then we're open to still even entering new jurisdictions. No, we're not just wedded to looking at Canadian acquisitions. It's where we can see the best value proposition for our shareholders.
Okay. Thanks, Mike. I think we have one more question from the operator. If we could just switch back to the operator for that question.
That's right. We've got a question from Mark Wilson of Jefferies. Please go ahead. Your line is open.
Thank you. Good morning. I'd like to ask on operational side of things. Onion Lake has seen the investment and will be seeing the investment through towards the end of the year. You also mentioned in the call how Suffield Gas, you haven't drilled any new wells since taking over assets, but you've had great success from the swabbing activities. Could we talk then about the possibility of drilling new wells at Suffield? Is that a possibility, say, for 2022, or is there a barrier to drilling new wells? That's my first question. Thank you.
Thank you, Mark. It's a very good question. The short answer is we do have a material inventory of new gas wells in our contingent resources. We've got about 2,500 locations booked, which is about 30 million boes of our contingent resource base. I would say it's less likely next year that we would start new gas drilling, notwithstanding that significant inventory. Because what we would most likely do if we chose to ramp up our gas activity is repeat some of the refrac and recomplete work that we've got from our existing well stock. We see much higher returns and much quicker paybacks if we go into the existing well stock and spend a bit of capital accessing some new bypass reservoir horizons.
I would say most likely in the short term, it would be further gas optimization from the existing well stock before drilling new gas wells. We do have a not insignificant inventory there.
Got it. Okay. No, very clear. By contrast, I suppose Onion Lake could possibly see more well pads. Would that be the case?
Absolutely. I mean, if you look at our 2P reserves in Onion Lake, I think are around 160 million bbl-170 million bbl. You know, the current facility, we can keep those production levels relatively stable for the next 20+ years by just drilling new well pads. You're likely to see continued investment in new well pads in the years ahead. Also on the back of the early results we're seeing from the infill drilling program, the team's also looking to see if we can squeeze some additional infill drilling locations from our existing well pads. Because clearly the returns that you get with such minimal investment are very attractive, as you can see from the numbers in the presentation.
It's gonna be a combination going forward, Mark, of both new well pads and hopefully some additional infill drilling.
Christophe was very clear on not planning on hedging any oil. He also mentioned, just to check if this hasn't been answered, check on gas side of things because Christophe mentioned, you know, you can sell gas at CAD 4 a barrel or through 2022 if you wanted to. Does that appear an attractive market to hedge some gas into for 2022?
Yeah. No, it does. We always monitor when to place those hedges. We placed some in the last couple of months. The market has continued to be even more bullish. We may hedge furthermore, trying to understand or see where the market is going. Yeah, it's likely at some point we'll lock in some more hedges at the CAD 4+ level.
Okay. The last point is, there's media reports that you've started a process to sell your assets in France. Could you speak to that, please?
Yeah. I think we never comment on press speculation, Mark. You know, I think when we look at the French businesses, as you can see the performance from the recent VGR and long-reach horizontal drilling, we're producing at above 50% from the pre-investment rates, and there's still a lot of upside. Don't forget we did suspend the redevelopment of our western flank of our Villeperdue assets. I think there's still a huge amount of running room in our French business, and it's got one of the best fiscal takes in the world. I think France still has huge value proposition for IPC shareholders.
Okay. Thanks for those answers and, wonderful set of results. Good luck for the future. Thank you.
Thanks very much, Mark.
Thank you.
Okay. I think that concludes the presentation. I'd just like to finish by thanking everyone for tuning in and for your attention this morning, and we look forward to presenting our year-end results and capital markets day updates in early February. Thank you very much once again.
Thank you very much.