International Petroleum Corporation (IPCO) Earnings Call Transcript & Summary

Hello. And welcome to the IPC's Q2 Financial Results 2020. [Operator Instructions] Just to remind you, this conference call is being recorded. Today, I'm pleased to present Mike Nicholson, CEO. Please go ahead with your meeting.

Okay. Thank you, operator, and a very good morning to everyone, and welcome to IPC's Second Quarter Results and Operations update presentation. My name is Mike Nicholson, the CEO. I'm also joined this morning by Christophe Nerguararian, the CFO; and Rebecca Gordon, who's is our VP of Investor Relations and Corporate Planning. I'll begin in the usual fashion by walking through the operational highlights for the second quarter, and then I'll pass the call over to Christophe. He will take you through the financial numbers and results. And then at the end of both of our presentations, we'll open up for questions and the participants who are on the conference call will go first, and then we can turn to the questions that have been asked via the Internet. So to get started, I think it's fair to say that the second quarter has been one of the more challenging quarters that we've had to navigate through in recent times. And of course, we had the twin forces of the coronavirus outbreak and the lack of an initial supply response, which led to profound weakness in oil prices during the quarter. But if I look back, I'm really pleased with the results that our team have taken, the swift actions that we took to reset our business plan. And those were really threefold, and we touched upon those in our first quarter results: It was significantly cutting our discretionary expenditure; it was curtailing some of our higher cost production and; really, the top priority was to preserve our liquidity headroom. And I hope that when you listen to the results this morning, you'll see that we've made really good progress in all 3 of those fronts. And I think IPC now stands on a very solid footing to benefit from the improved market conditions that we've seen more recently. So to start with the second quarter highlights and with our production, our average Q2 net production was just under 36,000 barrels of oil equivalent per day, and that was towards the top end of our Q1 guidance as we saw oil prices improved towards the end of the second quarter, and we started to bring back on some of our production that we had curtailed earlier in the quarter. And as I mentioned, with those improving prices, we did commence the progressive ramp-up of our Canadian oil production. And as a result of that and the continued ramp-up of that production, we are revising now upwards our full year guidance to 37,000 to 40,000 barrels of oil equivalent per day from the previous Q1 guidance of 30,000 to 37,000 barrels of oil equivalent per day. Really good performance in terms of operating cost delivery below our Q1 guidance. Our second quarter OpEx per barrel was below $11. And we're retaining our full year guidance of $12 to $13 per barrel, so unchanged from the first quarter guidance there. In terms of our CapEx and decommissioning estimates, a very marginal increase of $3 million to $80 million for the full year. And turning to the liquidity position of the company. I think we were able to deliver a very positive outcome in what was a fairly challenging environment, and we'll go through it in a bit more detail, but our international and Canadian reserve-based lending facilities were refinanced during the quarter, and we're also able to conclude the securing of our French facility, which we touched on in our first quarter results. In terms of our operating cash flow generation, just below $15 million. And for the second quarter, and I think as a result of the operational decisions that we took, the cost cuts that we put in place and the hedging program that we had in place for the second quarter and we're able to deliver a free cash flow neutral position through the second quarter, which I think was really good performance. Net debt levels increased from just over $300 million to $341 million, and the majority of that increase and net debt was driven by exchange rate movements and working capital movements. And Christophe will come back and shed a bit more light on that in his presentation. In terms of our hedging program, we've taken a decision to put some additional hedges in place for the second half of 2020. That's tied to our decision to commence our production increases in Canada, and really, the main rationale there is to ensure that we can generate free cash flows. We'll bring those production curtailments back online. And we've hedged approximately 2/3 of our third quarter production and with an average WCS price of $28 per barrel and 50% of our Q4 production at $25 per barrel. In terms of how the company now stands when we look at our financial headroom. We're forecasting financial headroom by the end of 2020 of in excess of USD 100 million and that assumes an average Brent oil price of $35 per barrel for the rest of the year and a $22 per barrel WCS price for the second half of 2020. And that represents a significant improvement in our available financial headroom relative to the guidance that we gave in our first quarter report when we expected to use up to 40% of that. Last but not least, on the ESG front. Obviously, a very challenging quarter. Very pleased that we didn't have any material incidents to report. We did put in place stringent coronavirus protection measures in place and none of our operational sites had to face any shutdowns as a result of the coronavirus. So very pleased with them -- that performance and as we touched upon in our first quarter results presentation, we did secure our 2020 carbon offset project, which sets us on a path for the next 5 years to reduce our average CO2 intensity down to the global average of 20 kilograms per BOE. So if we now go into a bit more detail and a recap on our 2020 investment strategy. And if we look at the chart on the left-hand side of the slide, and our CapEx and decommissioning estimates. As I mentioned, we've got a small marginal increase of $3 million for the remainder of 2020. And that's really made up of continuing to finalize the drilling on our Onion Lake Thermal project of our D-Prime well pads. The majority of the drilling took place during the first quarter. We took the decision to suspend that, but it makes a lot of sense to complete the drilling wells. That rig is on-site as the mobilization costs would be much higher if we release that rig, and that gives us the opportunity to recomplete those wells and get them on production next year. We also took the decision to suspend the ramp-up of our end-to-end UOR project and within prices we do capitalize the chemical costs, and we've moved forward again to start ramping up the Suffield end-to-end projects. So that captures the bulk of the CapEx increase. But if you take a step back to our Capital Markets Day at the beginning of the year, when we announced our full year budget was over $160 million. Our latest full year forecast of $80 million still retains a more than 50% cut to that original CapEx budget. If I turn now and look at our operating cost guidance. We're not changing our full year OpEx guidance that we gave in Q1 of $12 to $13 per barrel. But I think you can see we're really on track to delivering a solid OpEx performance for the full year. We'd originally guided to just under $14 per barrel at our Capital Markets Day in February. Our Q1 actual was $12.50, and our second quarter OpEx per BOE was ahead of that guidance at $10.70. And the reason for the good performance was we, obviously, curtailed or higher cost and production. And we also reduced our OpEx project activity set, things like workovers of higher marginal cost well. So that's why we were able to deliver such a good OpEx performance during the second quarter. We turn now and go into a bit more details on our production and the revised production guidance that I've alluded to earlier. Just to set the reduction guidance change in context, when we issued our Q1 guidance of 30,000 to 37,000 barrels of oil equivalent per day. Our low side guidance assumed that we continued through the second half to have exceptionally weak Canadian oil prices and all of our Canadian oil production would have been curtailed through the second half. The high side to 37,000 barrels of oil equivalent per day assumed that the production curtailments that we instituted through the second quarter would have remained in place through the second half of 2020. But that guidance, as I mentioned, has been now upgraded to 37,000 to 40,000 barrels of oil equivalent per day. We have seen through the second half of the second quarter and into July, a significant improvement in Canadian oil prices, and that gave us the encouragement to start to increase our production levels on our Suffield oil project and our Onion lake thermal assets in Canada. And we have paired those production increases with some additional WCS hedging as I referred to earlier to ensure that we will generate free cash flow from those incremental barrels. There was some partial curtailment of our Paris Basin crude production as a result of the impact of the coronavirus on the Grandpuits refinery. And that was started back up in late May, and we've also now brought those production levels back up to pre-curtailment capacity level. So those are now forecast into that revised increased guidance range. As I mentioned on the previous cost guidance slide, we still feel it's too early to significantly increase our CapEx budget. So we don't expect any further growth from the capital projects. Those remain on hold. And we don't anticipate bringing that $80 million of CapEx cuts back into the program in the second half unless we see significant further improvements in crude oil prices. This next slide just shows a little bit more detail on the year-to-date production. I think it's helpful because we did talk about the very swift action that we took in terms of our production curtailments. And if you look at the chart, you can see where really the price weakness kicked in around mid-March. And we're very, very swift to react and start to curtail our Canadian production back down to the nomination and hedge volumes that we had in place to preserve our financial strength. And obviously, prices bottomed out through May, where you can see we're at our lowest production levels. And then we can see prices started recovering through June and July, and that's when we started to progressively ramp back up our Canadian crude production, and that's when the Grandpuits refinery came back on stream. And you can see as we head towards the end of July, we've got production levels back up above 40,000 barrels of oil equivalent per day. So swift action, but now pleased to be starting to progressively ramp back up those production levels, which have fed into that increased full year production guidance. Turning now to our liquidity headroom and our credit facilities. As I mentioned in the highlights, we're very pleased to have concluded during the quarter the refinancing of both of our international and our Canadian reserve base lending facilities. We did touch upon our view in our first quarter presentation that we felt we had capacity to increase our borrowing capacity on our international assets, and that's exactly what we've done. We've increased the facility size from USD 125 million to USD 140 million. And more importantly, we've extended the maturity by 2.5 years to the end of December 2024. Likewise, on the Canadian facility, with the price weakness that we saw in Canada. We did touch upon in our first quarter results that there were some support packages that were being offered by the Canadian government. And in the end, we did not need to rely on any of those support packages. And again, we were able to extend the maturity of our Canadian facility by year to May 2022. There was a modest reduction from CAD 375 million, down to CAD 350 million, but essentially, net-net between international and Canadian facilities, our access to liquidity stayed relatively flat. But of course, we did significantly extend the maturity of those facilities. I think what's also worth mentioning is that we were able to negotiate the removal of our leverage covenant on the Canadian facility, and we didn't have any leverage covenants on our international facility. And as we mentioned in our first quarter results, during the second quarter, we signed up a very low-cost French facility of EUR 13 million. And when you put those altogether, net-net through the second quarter, we're actually able to increase our access to our credit facilities by around USD 10 million. I did mention that we -- with our production increases that we felt it was prudent to put in place some additional Canadian crude price hedges as we bring that production back online. 2/3 of our third quarter production has been hedged at an average price of USD 20 per barrel. And half of our Q4 production has been hedged at USD 25 per barrel. So when you put all of that together, the cost reductions, the refinance credit facilities and that hedging program, we really have seen a significant improvement in our overall liquidity position and funding position that we presented in our first quarter results. We said back then by the end of the year, we were forecasting above $100 million of available liquidity headroom and we took a very bleak assessment of the forward-looking oil prices. We were assuming back then $25 Brent and $0 per barrel WCS, essentially shutting in all of our Canadian production. And under those assumptions, we were expecting to use up to 40% of that liquidity headroom. In the end, where we stand today, as at the end of the second quarter, we had access to $90 million of liquidity headroom, and we expect to generate free cash flow in the second half of 2020. And that's assuming a Brent oil price of $30 per barrel and a Canadian WCS price of USD 22 per barrel. And those prices are well below the forward curve as it stands today. So putting the company really in a strong financial position for the second half of this year. Final few slides that I have is just going into a little bit more detail on the assets. I think it shows the high levels of discretion and flexibility and the swift action that we took. If we start with our Suffield oil and gas assets in Canada. If you look at the chart on the left-hand side, of this slide, you can see essentially very stable gas production, and we've been able to continue our optimization efforts on our Suffield gas production with a very active and swabbing campaign. If you look on the right-hand side of the chart, which is our Canadian Suffield oil production, you can see that towards the end of 2019 with our very active drilling program by 20 wells drilled last year. We've started to ramp up our oil production towards 8,000 barrels per day. When we saw the oil weakness kick in, in the middle of March, we took that swift action. And you can see we really did beam back down our Suffield oil production to a low in May. And then you can see the progressive ramp up that we've already instituted in June and July as we started to see commodity prices improving. But as things stand today, our remaining 2020 development activity that we'd originally planned is still on hold as a result of the low pricing environment. And will remain so unless we see significant improvements in oil prices. But of course, the team is still very active in maturing additional drilling targets and building the inventory that can be the fuel for further organic growth, both on the oil and the gas side in the years ahead. Turning now to our Onion Lake Thermal assets, similar story, if you recall, last year, we did complete a facilities upgrades and expansion project. That up lifted our production capacity to around 14,000 barrels per day. And if you look at the production graph through late 2019, last year, we did bring online our new F Pad, which brought our production up to close to 12,000 barrels a day, which is the well capacity with the F Pad online. And like the Suffield asset, you can see as prices started to weaken through the end of the first quarter, we took swift action. We actually shut down a complete train. That's the most cost-effective way to curtail our oil production. So we're still generating steam and steaming and maintaining pressure across all the individual well pads, but we cut our production in half by suspending 1 train. Through the second quarter and as you can see into July, we've progressively been ramping that production back up as we saw oil prices improving. Our average rates in July were actually impacted by a shutdown as we wanted to improve the reliability of our facilities as we started to bring production back up. And if you look at the spot rates, where our production levels stand today, we've been in that 9,500 to 10,000 barrels a day range. So I think the actions that our operations team on the ground have taken by maintaining pressure in all of the individual well pads and ensuring that we have consistent temperature in each of the well pads and good conformance of heat across all the well pads has meant that our production ramp-up has actually been running slightly ahead of expectation. And of course, that means that we've seen absolutely no evidence of any reservoir impact due to production curtailment. So I think very sound and solid operating protocols and happy to see that production coming back online slightly faster than we'd originally forecast. And turning to Malaysia now. You can see from the production forecast. We -- the yellow bars on the right-hand side of the chart show the addition of the A20 well which was brought on stream during the first quarter. We did mention in our Q1 results that we had a drilling problem, and we had fluids entered our A15 well and that resulted in us having to drill a sidetrack well to bring that production back online. But with the weak oil price environment we saw through the second quarter, we took the decision to suspend the sidetrack of that well. So you can see the hash blue bars, which would have been the production potential, had A15 being on stream, but we think it's prudent to wait for oil prices to recover and the side track of A15 is most likely to be a 2021 event now as opposed to bringing that production back on stream today, and spending that additional CapEx. But the team in Malaysia is still busy, maturing some additional production opportunities, and we are looking for further drilling targets and particularly around the A15 and A20 area. And we're also looking at optimization opportunities. So things like pump replacements on our existing well stock to see if there is areas for us to bring on some incremental low cost, high-value production there on our Bertam asset. My last slide for the operations update, and we're turning now to our French business. If you look at the production chart, you'll recall from last year that we did do the redevelopment of our Vert La Gravelle field in the Paris Basin. Really good response from that redevelopment. We saw production levels increasing to close to 3,500 barrels a day late 2019. Stable production levels as we moved into the first quarter of 2020. And then, of course, with the oil price slowdown and the impact of the coronavirus, we had to slow down our Paris Basin production as a result of an outage of the Grandpuits refinery. But of course, that refinery was brought back on stream in late May. You can see production ramping back up in June to 3,000 barrels a day. And we're now producing at levels slightly higher than that. So really good response in bringing production levels back up to those pre curtailment levels. All development activity though in France is still on hold until we see a recovery in oil prices. In our original CapEx budget, we had intended to take the rig that would use for drilling our Vert La Gravelle wells to the Western flank of our Villeperdue field and conduct a 3-well program there. And as I mentioned, we prefer to take a more cautious view and keep those -- that additional 3-well program for potential activity as we move into 2021. In France, so we've got a long track record of increasing our reserve and resource base. And I think the successful drilling of our horizontal wells last year, I mean that we do have a decent inventory for further production growth in France in the years ahead. So that concludes the highlights of the operations update for the second quarter. I'll pass now to Christophe, and he will walk you through the financial results and highlights. So Christophe, over to you.

Yes. Thank you very much, Mike. Good morning to everyone. Moving on to Slide 12 about the financial highlights. As Mike mentioned, as we all unfortunately witnessed, I mean, Q2 was a very difficult environment to work in. And it's fair to say that IPC reacted extremely swiftly to the changing economic environment in Q2. As early as mid-March, there was the decision to pretty much cut all discretionary CapEx, and reduce curtail production by 40% to 50% in Canada to maintain profitable operations. And the result of that very swift and early decision in March is that the IPC was free cash flow neutral in the second quarter. The production because of this voluntary curtailment in Canada was just shy of 36,000 barrels of oil equivalent per day, roughly 10,000 barrels a day lower than during the first quarter. And with Brent prices below USD 30 per barrel on average during the second quarter. The operating cash flow was just shy of USD 15 million. And EBITDA just above a USD 12 million, obviously, much lower than any of the quarters we experienced in the past, and especially if you compare that to our performance in 2019. But I think together with the curtailment of the production during Q2 in Canada, it's worth mentioning that we did not only cut discretionary CapEx. We also spent quite a bit of time and efforts to reduce and manage our all costs and OpEx down, and that resulted into a low unit cost per BOE at below USD 11 per BOE for the quarter. So a good performance on -- for IPC in managing our cost. On the following slide, on realized prices, I mean, it's worth mentioning, okay, well Brent was fairly low, just below $30 per barrel average. But the important fact for all of our Canadian production, despite the curtailment. We're still making money in Canada from the production, which we left -- we were left producing. And that was partially driven by narrowing of the WTI, WCS differential, which was at $11 on average, but -- which has been improving through the second quarter. Now if you look at the realized prices, happy to report that Malaysia, we are still and continuing to see premiums to Brent. So we're selling Alberta cargoes at a premium to Brent, at plus $2 on average, but it's on the average, it tends to be higher than $2, but plus $2 on average for the quarter. In France, we are virtually selling our oil at on par with Brent, the reason why we report here on average realized price, USD 5 below the Brent prices that we had a lifting in Aquitaine. As you know, we have 2 parts in France. We're producing from the Paris Basin as well from the Southwest of France, where we have 1, sometimes 2 lifting per year. And that lifting occurred in April, which was the lowest pricing in Q2, the lowest month in Q2. So on average, below, but feel comfortable that the realized price for the -- in France continues to be at or just below the Brent price. In Canada, we had the same with Suffield, but we curtailed production mostly at Suffield in May and June. So we tend -- we sold a bit more volumes from Suffield in April than in May and June and April, prices were the lowest. So on average, we sold of Suffield -- we had a realized price at Suffield below the WCS. But for me in June, it was higher than -- marginally higher than WCS. So overall, a fairly weak quarter, no doubt, but we see a lot of room improvements and improved prices in Q3. And we witnessed that already in July, and we're comfortable that we're right, really realizing already WCS prices today, which are higher actually than our realized prices in the first quarter. Moving on to the Slide 14 on realized gas prices. So the good news, generally speaking, in Alberta is that the injection, the storage capacities for gas are working much better. So that has driven Eco prices much higher over the next -- over the last 8 to 9 months. So that's a strong positive for the province of Alberta and for our ability to sell on AECO or Empress prices. Now the differential between AECO and Empress has narrowed and was virtually 0 over the last quarter. Now this being said, we still witness sometimes in the forward market, some very nice premium for Empress over AECO. And so typically, we sell forward some of our gas production. And as an example, we've sold forward. They are not hedges formally, but they are forward sales. And so we've locked in already for the winter strip between November 2020 and March 2021. We've locked in some positive premiums of between $0.20 to $0.40 per Mcf for gas production. So we continue to watch the forward market and cease opportunities. But overall, a very strong AECO prices, which is overall side of the good dynamics in Canada and Alberta for gas prices. On Slide 15, the very positive things with IPC that were exposed to oil price upside through all our assets. The flip side is that in a low oil price quarter like Q2, we suffered from a cash flow perspective and only generated [ $12 million ] and [$15 million] of EBITDA and operating cash flow, respectively, but we see the -- we believe we've turned the corner and anticipate already a much better results for the second half this year. In terms of operating costs, as I mentioned, as much as we reacted very quickly on the curtailment for some of our less profitable Canadian oil production. We were very quick also in managing and reducing our costs down in the proportion of gas production increased during the second quarter. And the unit cost of production for gas is much lower than for oil in Canada. So the overall unit cost was driven down in the second quarter. On average, for the first half, we are just shy of USD 12 per BOE. So there is -- we are maintaining our annual guidance of USD 12 to USD 13 per BOE for the full year, knowing -- recognizing that we're just below the low end of that range for the first 6 months. In terms of netback, Slide 17. I mean that goes together with the reasonably low operating cash flow and EBITDA we generated during this second quarter for the first 6 months. Our operating cash flow is just shy of USD 5 per BOE for the first 6 months and EBITDA just over USD 4. That's, obviously, well below our original guidance from our Capital Markets Day and even lower and our Capital Markets Day guidance was already lower than our performance in 2019. So no doubt that we are feeling very comfortable. We improved those netbacks going forward. Looking at the cash flows and how our net debt improved. So of the free cash flow -- the free cash flow was neutral for the second quarter. Now if you look at the cash flow generation since the beginning of this year, our net debt increased by roughly USD 35 million, and it's pretty obvious on this Slide 18 that the operating cash flow only covered a portion of the CapEx we were spending in the first 2.5 months of this year. Indeed, most of the CapEx of the $62 million, of CapEx spent and reflected here on this chart, all of those were spent or committed or the work was given the go-ahead in the first 2.5 months between the first of January and mid-March when oil prices started to crash. So the result was an increase over the first 6 months of USD 35 million of debt. In terms of G&A, it goes along the same as OpEx and on a unit per basis and unit per barrel as well. We are keeping our costs under control. The same goes with G&A, which remain below budget, as you would expect in the current environment. In terms of costs, interest expenses were actually a bit lower in Q2, mainly driven by the reduction in the base rates, be it in Canada or in the U.S. The U.S. LIBOR was significantly down on average in the second quarter as well as the Canadian base rate. Now if you look at the cost of debt in 2019, it was roughly 4.5% in the first half of this year. Again, driven by base rates our cost of debt on average was 3.5%. We expect the second half of this year to be in line with 2019 at around 4.5% and that should increase by another 1% going into next year on the back of the refinancing we just did, and I'll come back to that. On Slide 20, financial results, we generated, as you'd expect and hope, a positive cash margin but after depletion, exploration and G&A costs, not to mention financial items. We generated a net loss for the first 6 months as we saw before. In the -- on the balance sheet front, the size of our balance sheet marginally increased. I mean CapEx and depletion were roughly the same in the first 6 months was almost a wash. But the value for oil and gas properties on our balance sheet increased as a result of the Granite acquisition, which we closed on 5th of March. And in parallel, our debt levels increased from the end of last year as we booked -- as we concluded and closed this acquisition. It's worth mentioning that unlike some of our peers, we had -- we didn't have to book any asset impairment or write-off, and that was a consequence of the fact that the acquisitions we've made in Canada or the book values we were carrying for international assets were fairly low compared to the actual economic value. And so we were able to support our book value, both at the end of Q1 and at the end of this quarter as well. As much as we spend time in managing our costs including CapEx and curtailing those production -- this production in Canada, which may not have been profitable in the second quarter. The other half of the management time and resources were spent in managing and engaging with all our credit stakeholders and all the banks, which we're dealing with. And it was a very good outcome for all of us, both our banks and ourselves, even if the cost of debt has marginally increased. Overall, we were able to refinance, and as Mike mentioned, more importantly, extend the maturity of all our loans. So overall, we've increased access to credit clients by USD 10 million. Why we've almost maintained the exact same liquidity access as we had when we guided the market with our liquidity position in May when we released our first quarter. So we increased our international facility from USD 125 million to USD 140 million with a maturity date at the end of 2024 now. The Canadian facility was widely reduced down from CAD 375 million down to CAD 350 million. But very importantly, all the banks accepted and supported us in extending the maturity by another 12 months until May 2022. And as an answer to some questions we've received from investors or shareholders, we don't have -- we currently don't have any leverage covenants. We had one in our Canadian facility, but it was removed. And so we're not subject to any pressure point from that perspective. In terms of hedging, we voluntarily entered into some hedging program and we hedge 2/3 of our Canadian oil production for the third quarter and half of our Canadian oil production for the fourth quarter. As part of our discussions with our banks, we also voluntarily committed to hedge 25% of our production in the first and second quarter next year, with a view to continue to deleverage, to secure being free cash flow positive and continue to be able to deleverage over the next 12 months essentially. The results of the production curtailment, the management of our costs and the extension and maintaining of access to our credit facilities is -- we anticipate to maintain access to in excess of USD 100 million at the end of this year. So a much improved situation in terms of liquidity to what could have been the case if we had not been able to refinance and extend the maturity of our credit facility that we just went through with the support and help of our bank. On the next slide, on Slide 23. You have the recap of the hedges we put in place for that third and fourth quarter. Suffice to say that the realized WCS price for that portion of the hedges we put in place is USD 28 per barrel for the WCS price in the third quarter and USD 25 for the fourth quarter, being that all of the ramp-up in our production, we anticipate in Canada will be free cash flow positive at those levels. That's how I conclude my follow-up on the financial highlights, and I'll hand over back to Mike for the conclusion of this second quarter release.

Okay. Now, thank you, Christophe. So yes, just a recap and a summary. Clearly, some severe headwinds that we faced as we came through the second quarter, but the swift action that we've taken, I think, has really put IPC on a very solid footing to start to plan for the recovery. And that's what we've essentially started to do. So just a recap on our production, second quarter production just below 36,000 barrels a day was towards the upper end of our first quarter guidance. And very importantly, we've started the progressive increase of some of the voluntary curtailed Canadian oil production late in the second quarter. And that's allowed us now to revise up our full year guidance to 37,000 to 40,000 barrels of oil equivalent per day. Very solid OpEx delivery through the second quarter, below $11 per barrel, and we feel we're well on track now to meeting our full year guidance of $12 to $13 per barrel. Still retaining a significant reduction in our CapEx budget, more than 50% lower than our February Capital Markets Day budget at $80 million. And as Christophe has gone through in detail there, we've really put ourselves on a solid financial fitting with the refinancing of both of our international and Canadian RBL facilities as well as having secured access to our new French facility. Given the very weak oil prices, and we're still able to generate just under $15 million of cash flow. And with the hedges we put in place, with the large cost cuts and all of those tough operational decisions. I think it was a real achievement that we're able to be free cash flow neutral through the second quarter. Debt levels, as Christophe mentioned, rose to $340 million, but that was largely driven by noncash exchange rate movements and working capital movements that we're anticipated. New hedges in place, paired with our production ramp-up to guarantee that we generate free cash flow from those incremental barrels. So 2/3 of our Q3 production hedged at $28 a barrel and half of our Q4 production hedged at $25 per barrel. And the company is really on a solid financial footing. Now as we look forward, and we project both Brent and Canadian oil prices well below the forward curve. We see ourselves having access to more than USD 100 million of spare financial headroom by the end of this year. So that's a significant improvement from our Q1 guidance when we expected to use up to 40% of that headroom. And as I mentioned earlier on our ESG side, I'm very pleased that we had no material incidents. The coronavirus protection measures that we put in place allowed continuity of our operations. And we were able in the first quarter to secure our carbon offset project. So all in all, a tough quarter, but I think as we look back, very positive, set of results given the circumstances. So that concludes the presentation. I'm happy now to turn back to the moderator, and we can start to open up for some questions.

[Operator Instructions] Our first question comes from Teodor Nilsen, SB 1 Markets.

I have 3 questions, if I may. And firstly, on the M&A market in Canada? And how has the Q2 downturn impacted the M&A market? And do you see more opportunities now than before, such that we should expect to pursue more M&A opportunities now than before? Second question, it's on hedging. Very positive to see the impact from hedging, but it's not very typical lending style to hedge to the extent that you are doing. So is this directly related to your credit facilities or what has actually motivated these hedges? And third question, just a wee detail on the financials. What's the tax rate on the second quarter FX gain?

Okay. Thanks, Teodor. I'll take the first 2 questions, and then Christophe can take the last tax question. So first, you asked about the M&A market in Canada? And are we seeing more opportunities than before. I think -- I guess, it's still slightly early days, but we do anticipate that we're going to likely see a pickup in activity. And I think one of the key triggers for that, Teodor, is as companies come through their bank refinancing and redetermination processes. And I think ITC came out that very, very strongly. We had only a very small reduction in our credit facilities. And I think we've seen from some other companies in the space, they've had much larger reductions. And of course, that's going to put in place some additional balance sheet stress. So I do anticipate there being much more opportunities as we move into the second half. We'll continue to be opportunistic and have a focus on asset quality. But certainly, my expectation is we're likely to see more opportunities in the second half than we saw in the first half. Your second question you was in relation to hedging and I'm saying that it's not typical for lending companies to hedge. And I think that's a fair assessment. But I would counter by saying that we went through a certainly very atypical second quarter. One that we basically turned our whole thought processes on our head where we had to voluntarily curtail some of our production because prices fell to such low levels. And 1 particular example is if you -- I mentioned that we curtailed the second train on our Onion Lake Thermal project. And what's really important is on these kind of longer life thermal projects as you don't ramp up and ramp down production from month-to-month. So we were sitting towards the end of April, early May, as we're looking at our June nominations, and it was absolutely an operational-driven decision to hedge. We wanted to make sure that if we were bringing that production back on, for at least 3 months, we would have certainty that we could ramp production back up to full production rates. So it was really an operational-driven decision, and we wanted to ensure that if we brought that production back online that we've been able to generate free cash flow. So really, that was the motivating factor besides putting those hedges in place. And the third question, Christophe?

Yes. So the main change in FX that you can see is driven by the revaluation of some loans. External loans are U.S. dollar denominated, and we had some intra-group loans dominated in Canadian dollars. So when you reevaluate and consolidate our financials in U.S. dollar, it changes up or down the value of payables and receivables on the debt side, but it has no tax effect. It's a pure accounting revaluation between the U.S. dollar and the CAD. So no tax effect.

Our next question comes from David Round, BMO.

First one, just on liquidity. And I was just looking for it there. So correct me if I'm wrong, but I think you talked in the past about maybe not maximizing the borrowing capacity of the assets, and there have been potential for additional capacity. Are you happy with this latest redetermination that you're now doing that? And the price deck is conservative enough that we won't see -- or there'll be lower risk of downward revisions in future. And secondly, just maybe 1 for Mike. Obviously, you've put growth projects on hold. Assuming we're still at current prices next year, how many of the projects that you've earmarked for 2021 do you think actually go ahead? And is it purely a returns calculation? Or is liquidity also a key consideration there?

Okay. Thanks, David. I'll take the second question first, and then Christophe can answer your liquidity question. Yes. I mean, if we're looking at all prices in the in the low $40s. It's a little bit early. We're still obviously going to go through our business plan and then 2021 budgeting. But my sense is if we still see a continued weakness in oil prices. We're going to want to take a more conservative approach to ramping up our capital expenditure until we're certain that there's not going to be a second wave of coronavirus and the demand outlook looks much, much clearer. So although a lot of our projects are reasonably quick paybacks. I would expect us to take a slightly more cautious approach to ramping up our production and ensuring that we're going to generate the highest levels of free cash flow.

Yes. As for the first question, I think it's directionally fair to say that we expect less pressure from the fall determination now. You tell me what he oil prices will be, I'll tell you what the bank price will deck be. Nobody knows, obviously. But generally, if it was as of today, the banks, especially in Canada, have told us that their price deck would be higher today than the 1 they used when we went through the redetermination, which ended up in the reduced amount from CAD 375 million down to CAD 350 million. So everything being equal, if in the fall, we're all in the same situation as of today. I think it's fair to say that there would be less pressure.

Our next question comes from Johan Spetz, Pareto Securities.

It's Johan Spetz of Pareto Securities. So a quick question on the revised production guidance range. For 2020, you increased it now to 37,000 to 40,000 BOE per day. Could you talk a bit about the considerations going into that revision, given that you -- I think you pointed out that you're already near the top end of that range. Just wanted to hear a bit how you're thinking about the second half of the year in terms of production there?

Thank you, Johan, and a good question. I mean, if you look -- as I mentioned, if you look at our first half production on average, we were just above 40,000 barrels of oil equivalent per day. And as you mentioned, you can see that we've hedged back above 40,000 barrels a day. We've taken a fairly cautious approach to setting the bottom end of that guidance, I would say at 37,000 barrels of oil equivalent per day. Clearly, there's still some certain uncertainties out there with respect to the size and the potential impact on demand of a second wave of the coronavirus. So what we've assumed on that lower end of the guidance is there are some further price weaknesses in the second half and that we would curtail our Canadian production back to the hedge levels that we've indicated in our second quarter results. So certainly on track to meeting towards the upper end of that guidance, but still want to be relatively cautious, should markets take a turn for the south in the second half.

Right. And so as a quick follow-up then to exceed 40,000 sustainably in the second half of the year, is it fair to assume then that you would potentially need to add a bit of CapEx on top of the guidance that you have in place now at $80 million. Is that fair?

Yes. Yes. I mean, not necessarily, but, of course, we always have assumptions in there about uptime performance on all of our operating facilities. And if I take Bertam as an example, we've continued to have a 100% uptime right through the coronavirus crisis. So we don't necessarily need any additional CapEx for us to achieve the upper end of that guidance range.

[Operator Instructions] Okay. There appears to be no further questions. So I'll hand back to our speakers for any further remarks.

Yes. Thanks very much. We've got a couple of questions from the Internet, but running out of time rapidly. So I'll just hand over to Mike to I think what is an important question on, an update on the oil and gas pipeline construction in Canada, Mike?

Okay. Yes. So I guess, we've got the 3 major pipeline projects. The first being the Enbridge Line 3 replacement and I think what we've seen there, the most recent announcements by the company was that the Minnesota regulator has needed some extra time to issue the water quality certificate impairment. That was delayed by 3 months to -- from the August -- from mid-August to mid-November. The Canadian side of Line 3 has been completed and the company has estimated that the U.S. side is expected to take somewhere between 6 to 9 months. So following the delay in that permitting, the latest estimates for the in-service date of that project are somewhere between mid- to late 2021. Towards July, Enbridge CEO was on record, as said, I think he was asked about the potential of a democratic administration and the impact that could have on the Line 3 replacement, and Enbridge stated that they're focused primarily on permitting with state level agencies and doesn't need to seek access to cross-border federal permits. So they stood by that latest guidance of between mid- to late 2021 for Line 3 to be in place. The second project, which has already started construction, the Trans Mountain pipeline, which will go west and add just close to 600,000 barrels a day of incremental export capacity to Asian markets. The first section of the pipeline in Alberta is more than 60% complete, construction has begun in Kamloops, in British Columbia. And Trans Mountain have guided -- they expect construction to be underway on all sections of the pipeline before the end of 2020. I think importantly, in early July, there was a Supreme Court ruling and set aside appeal from First Nations Groups that they had not been adequately consulted. So that was really the last major outstanding legal challenge. So that project is moving forward. The last one, where there's a bit more uncertainty is around TC Energy's, Keystone XL pipeline. At the end of the first quarter, TC Energy did announce the government of Alberta and themselves took a final investment decision. And the Alberta government was actually injecting USD 1.1 billion of equity into that project to cover all of the construction costs through the end of 2020 and given the potential political uncertainties. Construction of Keystone XL has started in Canada, and it's able to proceed in all areas outside the waterways where there was a recent ruling by a Montana judge in April that invalidated construction across some river crossings. TC Energy themselves in their latest earnings release said that they plan to pursue other permitting means to gain the required regulatory authorizations to construct the pipelines across wetlands and under water bodies. And interestingly, also the Presidential permit was issued. This allowed an increase of the existing Keystone system from 590,000 barrels a day up to 760,000 barrels a day. So I think directionally positive movements on all of the 3 main pipeline projects.

Okay. Thanks, Mike. This is the time for us to end the presentation. So now thanks to the audience.

Okay. Thank you very much for everyone for taking the time to tune in, and we look forward to presenting the third quarter results. Thank you, everyone.

Thank you, now.

Thank you.

Ladies and gentlemen, thank you for attending. You may now disconnect your lines.