Cenovus Energy Inc. (CVE) Q2 2022 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's Second Quarter Results. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Cenovus Energy. I would now like to turn the conference call over to Ms. Sherry Wendt, Vice President, Investor Relations. Please go ahead, Ms. Wendt.

Thank you, operator, and welcome everyone to Cenovus' 2022 Second Quarter Results Conference Call. Please refer to the advisories located at the end of today's news release. These describe the forward-looking information, non-GAAP measures and oil and gas terms referred to today and outline the risk factors and assumptions relevant to this discussion. Additional information is available in Cenovus' annual MD&A and our most recent AIF and Form 40-F. All figures are presented in Canadian dollars and before royalties unless otherwise stated. Alex Pourbaix, our President and Chief Executive Officer, will provide brief comments, and then we'll take your questions. We ask that you please hold off on any detailed modeling questions and instead follow-up on those directly with our Investor Relations team after the call. [Operator Instructions] Alex, please go ahead.

Thanks, Sherry. Good morning, everyone. As always, I'm going to start this morning's call with our top priority, health and safety. Our aim at Cenovus is to continuously raise the bar on safety and reliability through a learning culture. This quarter presented additional challenges as we undertook a number of planned turnarounds and maintenance programs at our operated assets. In the upstream, we safely and successfully executed a large turnaround at Christina Lake, along with normal course maintenance at some of our Lloyd thermal projects. And in Canadian manufacturing, we safely and successfully completed plant turnarounds at both our upgrader and refinery in Lloydminster. I want to highlight these accomplishments and thank our staff for their ongoing dedication to safety and reliability. Having these turnarounds and maintenance activities completed positions us well for the back half of the year. Before moving on to our Q2 results, I'll also note that we released our 2021 ESG report today. It's available on our website and updates the progress we are making towards our targets. This includes our efforts on reducing emissions and progressing carbon capture and storage projects as we build towards our longer-term ambition of Net Zero emissions by 2050. Turning now to our results. Over the second quarter, we demonstrated the continued strength of our operations. Following the successful turnaround, Christina Lake quickly returned to normal production rates. And the asset has been running exceptionally well in July, reaching over 267,000 barrels on a single day. At Foster Creek, following a thorough technical and safety review, we've deferred a turnaround originally planned for Q3 to next year. The teams work diligently to optimize the maintenance intervals of the project, and we are confident in our ability to continue operating safely and reliably. You'll see that we have increased our full-year production guidance slightly and the deferral is reflected there. The Lloydminster Thermals continue to run at high rates, and we've started steaming the new Spruce Lake North project. This will add 10,000 barrels per day of capacity and production is expected to come online in early August. We're also on track to close the purchase of the other half of Sunrise in the third quarter. Our team is excited to further deploy our Cenovus operating model. We plan to get production up to its nameplate of 60,000 barrels per day with potential to get even beyond that in the future. In the downstream, with the exception of our Lima refinery, basically, all of our refineries and the upgrader were in turnaround at some point during the quarter. This means reduced throughput, but at the same time, we also saw unprecedented margins in U.S. refining, given historic high crack spreads. We particularly benefited from this at Lima, which ran throughput of over 170,000 barrels per day in June when crack spreads were highest. Overall, we continue to see strong crack spreads above seasonal and historic norms. While the forward curve for the remainder of the year has come down somewhat, it remains strong. Gasoline cracks have softened over the past few weeks with refineries running at high utilization rates and gasoline inventories have returned to more normalized levels. However, while U.S. distillate stocks have been edging up, they continue to remain below five-year averages. Meanwhile, heavy crude differentials have widened and not just at Hardisty. While in the past, widening light-heavy differentials largely meant pain for Cenovus, we now receive a much greater benefit on the downstream side of the business. Clearly, the outlook for U.S. refining has changed drastically, and we are now seeing the benefit of the integrated model we put together with the Husky transaction. While our outlook for the financial performance of the U.S. refining business has dramatically increased, so too have our expected cash taxes. Our total cash tax of $900 million for the quarter was more than double what we saw in Q1. Similarly, we have increased our full-year cash tax guidance mainly to reflect the significant shift in crack spreads with our Chicago 321 assumption increasing nearly 50% since our last guidance at the end of April. That said, we do expect cash taxes for the remainder of the year to be slightly lower than in Q2, more in the range of around $600 million for each of the third and fourth quarters. We have also increased our operating cost guidance for the downstream. This reflects turnaround costs and throughput impacts in the first half of the year, particularly on the joint venture refineries operated by our partners. That said, with almost all turnaround activity now completed for the year, you can expect per barrel operating costs to fall significantly in the second half versus the higher rates seen in the first and second quarters. In terms of our financial results, the quarter's adjusted funds flow of $3.1 billion was the highest in Cenovus' history. Free Funds flow was $2.2 billion and excess free funds flow was also about $2 billion. Given net debt was between $9 billion and $4 billion at the end of Q1, we've allocated about 50% of Q2 excess free funds flow towards shareholder returns, which is over and above our base dividend. As such, we delivered over $1 billion to shareholders through share buybacks in the second quarter. As I've talked about before, share buybacks are the preferred mechanism for variable returns, at least when our share price is around the range it has been recently. We will continue to look at share buybacks on an opportunistic and disciplined basis with a view to intrinsic value at mid-cycle pricing of around $60 WTI. Q2 was a great example of how our financial framework and shareholder return strategy can work in tandem to maximize returns to shareholders while also continuing to deleverage the balance sheet towards our net debt floor. The ability to deliver these returns is rooted in our continued operational strength. To optimize opportunities in the portfolio, we've increased our 2022 capital guidance adding about $400 million. This includes about $120 million this year for the restart of the West White Rose project. We've also added about $200 million in the oil sands. About half of that will go towards Sunrise, including the additional 50% interest once that acquisition closes. Capital at Sunrise will progress application of Cenovus' operating model to increase production back to nameplate. The rest of the additional capital in oil sands will be spread across Foster Creek, Christina Lake and Lloyd Thermals for incremental drilling to drive increasing volumes through 2023. We've also added around $100 million in the conventional business to accelerate some drilling activity into the fourth quarter. This will take advantage of the continued outlook for strong natural gas pricing and also accounts for some inflation. All of this incremental activity continues to meet our hurdle rate of cost of capital return at $45 per barrel WTI with even higher returns at today's commodity prices. The increased capital will position us very well for strong momentum in production volumes as we go into 2023. And we also expect to see higher upstream production over the second half of the year, increasing towards 800,000 barrels a day and above. Our drilling program in the conventional business will drive a few thousand BOEs of short-cycle production adds. Spruce Lake North production will also be coming online in the Lloyd Thermals, adding that 10,000 barrels a day I mentioned earlier. And once the Sunrise acquisition closes, the increased interest will represent about 25,000 barrels a day of incremental production. Looking further ahead, we still see Indonesia production increasing by about 10,000 BOE per day with the developments there as we head into next year. And Terra Nova is expected to come back from its off-station later this year and back on production in early 2023. Thinking about the downstream, while the Toledo refinery is coming back to normal rates following its major turnaround, we will soon have all assets back to normal operations, and the Superior refinery rebuild is set to be turned over to the operations team to begin start-up activities in September as we work towards a full restart around the first quarter of next year. Overall, the first half of 2022 delivered solid results, and we're positioned for an even stronger second half of the year, with net debt down to $7.5 billion at the end of Q2, we'll once again be looking to allocate 50% of Q3's excess free funds flow to variable shareholder returns. And we plan to continue demonstrating the strength of our business and the kind of shareholder returns we can deliver. With that, let's move on to everyone's questions.

[Operator Instructions] We will now begin the question-and-answer session and go to the first caller, who is Menno Hulshof with TD Securities.

Good morning everyone and thanks for taking my questions. Maybe I'll just start with West White Rose. It looks like you're going to be spending about $500 million to $600 million a year on a net basis in the 2023 through 2025 timeframe. And they're not huge numbers, but they're not small either, especially if inflation remains an issue. So I guess my question is, how much of the cost is locked in? And are you seeing opportunities to further reduce your 56% stake in that project? And if so, is that something you'd be interested in doing?

Hi, it is Norrie Ramsay here from the Upstream part of our business. Yes, I mean our spend profile is $500 million through to $700 million in those three years, as you say. Most of it is locked in. We have previously purchased all the hardware equipment. So we're not exposed to any inflation from those kind of areas. And we've actually kept the asset activity kind of warm. So again, all of this is recognized within the budget reset that we did as we restarted the project. So we don't expect any further exposure to cost escalation as we move forward. Our equity kind of share just now is exactly where we would like it to be for now. We'll continue to work with our co-venturers to ensure that we can maximize the value from the project as we move forward. And we look forward to safe production in early 2026.

Terrific. And maybe I'll just follow-up with a quick question on heavy differentials in crude by rail, WTI, WCS currently in that $21 range, WCS Maya in that $16 range. So maybe you can just comment on what we should be expecting in terms of activity levels from Bruderheim or even the Hardisty Hub and whether or not -- yes, whether we should see an uptick? Or do you need to see these differentials stabilize in this range for the foreseeable future before committing to anything? And maybe just remind us on the cost structure as well. Thanks.

Hi, Menno, it's Keith Chiasson. Really, it's a combination of two factors, I would say. We're seeing kind of the light heavy spread in the U.S. Gulf Coast kind of wide note and numerous factors kind of contributing to that, one being kind of the strategic petroleum reserve release, which we're anticipating that should lighten up in the August timeframe and currently forecasted to end in October. But with those additional medium sour barrels coming into the market as well as kind of the current WTI structure, it's really impacting kind of the demand for heavy barrels in the U.S. Gulf Coast. And then when you look at Alberta, we're seeing obviously, ramp-up of all the oil sands projects following turnaround timing, and so we're seeing more production coming online. Interestingly enough, though, we're seeing very low apportionment on the pipeline, so there's still sufficient egress. And what I would offer up is crude by rail, although the spread is kind of getting into that historic norm, there's been a huge ramp-up in distillate prices, which is putting some pressure on the cost of crude by rail. So you're not quite seeing it ramp up at this point in time. From a company perspective, we're obviously a lot better positioned to benefit from a wider differential than historically we were. And between our Canadian operations and our U.S. operations, the downstream is capturing some of that crude advantage with these current wide differentials.

Terrific, thanks Keith. That's all I had.

We'll now take our next question from Greg Pardy with RBC Capital Markets.

Hey, thanks. Thanks, good morning. A couple for me. But the first one is how should we think about sustaining CapEx as we kind of look into '23, just given all the inflationary pressures and size of the business and everything else?

Hi Greg, it's Jon McKenzie. So the guidance that we've given to the market pretty consistently since we did the Husky acquisition with sustaining capital is kind of in that $2.4 billion range. And that included upstream, downstream and kept production flat as well as our fixed plants in that safe and stable condition. So I think there's two things to consider. One is we're adding assets. So as we take on the other half of Sunrise and bring Toledo up, for example, that will increase our sustaining capital requirements. And then there is the inflationary pressure that you've talked about. So we're currently working through our 2023 budget right now, and we'll give you a more definitive answer to that question as we work through that. But I think it would probably be fair to say that it's moving from around $2.4 billion into the $2.6 billion, $2.7 billion range. But as we add assets, we've got to take into account of that. And then in some of the areas like conventional and some of our drilling costs, we are seeing some of that inflationary pressure, but it's not an order of magnitude higher. It's incremental to where we were at 2.4.

Hey Greg, it's Alex. And I'd agree with everything John said. And just to kind of put it in perspective, if you think about that $400 million capital addition, probably about $100 million of that represents kind of true inflation. So on the budget that we're talking about sort of a relatively modest single-digit impact.

Okay, thanks for that. Second is just kind of an operating question. I mean the bull case, right on Cenovus has been favorable operating improvements in the upstream. And I think you've demonstrated that, but there's also a lot going on in the downstream. I'm just wondering if you can describe a few of the things maybe what's going on with Toledo or elsewhere in terms of just making that operation much better and profitable.

Hi Greg, it's Keith. Yes, thanks for the question because there is lots going on. I think in Alex's opening remarks, we talked about Lima kind of hitting kind of record throughput in June of north of 170,000 barrels a day into a high crack market. So that was very good. But we're also working with our joint venture partners in our U.S. downstream at some of our non-op assets to further enhance capabilities. So Toledo is currently in a ramp-up mode, but it has finished the second phase where it will be able to handle higher TAN barrels, higher total asset number barrels, which gives it an additional crude advantage as well as additional heavier barrels. So significant increase in capacity there. Wood River has gone through some expansion projects to improve their clean product yield which, obviously, in these type of crack spreads makes a big difference. And then Borger is now with the new pipeline connection able to access Canadian heavy barrels as well. So we're seeing a significant ramp-up of Canadian heavy moving across into Texas and into that joint venture asset, which adds additional value and crude advantage. And then finally, we are in the process of taking over from construction at Superior and starting to progress our start-up of that refinery. So everything is tracking as per plan and for a Q1 full product start. So a lot's going on and pretty exciting time.

Terrific, thanks very much.

We'll now take our next question from Dennis Fong with CIBC World Markets.

Hi, good morning and thanks for taking my questions. The first one is just around Sunrise. Given the current production levels, how should we be thinking about the potential projects that you have either underway or potentially underway at the timing to close as well as potentially the timing or ability to return production to at least 60,000 barrels a day or higher, just kind of given what you see currently on the asset and the relative underspending that it's seen more recently.

Hi, Dennis, it's Norrie Ramsay from our Upstream business again. We're actually quite excited about the Sunrise asset. As we take over 100% kind of ownership of it, our development plans are unchanged. We are actually looking to continue to apply our Foster Creek and Christina Lake subsurface philosophies to the site. As we do expand the site, we're actually seeing very good redrill opportunities. To date, the wells that we've been drilling are coming in slightly above our forecast, which is kind of reassuring. And as we've actually studied the geology, we're seeing a lot more opportunities. So the asset was really underinvested for a number of years. And what we are doing is reinvesting and getting it back to how we'd like it to operate. I'm confident we can actually get above the nameplate of 60,000 barrels a day, and I'll take the next 24, 30 months to actually get there. In the meantime, we continue to grow production through this year and into next year. And it's all showing up exactly as we're forecasting as we go forward. So I'd expect probably within three years, you'll see us above nameplate levels, and we'll try and reach those numbers as quickly as we can.

Great. Great, thanks. My second question is a little bit maybe more around capital allocation here. Just given kind of what we've seen with respect to reduced cost structures alongside the term debt retirement that you've done through this quarter and potentially further along as you're generating incremental free cash flow, how are you thinking about kind of the increased level of profitability within the asset integration, the upstream and downstream initiatives that were already outlined? And how does that potentially affect you or maybe guide [Technical Difficulty].

Did we lose him?

Yes, actually sir. It looks like his line is disconnected.

Okay. Well, maybe we'll move on. And if Dennis comes back, we can answer that.

Not a problem. Your next question will come from Neil Mehta with Goldman Sachs.

Good morning, team. I want to start-off on capital allocation. And it looks like you guys slowed down on buyback when the stock ran. And then post the quarter, you really leaned into it. So you've done a good job optimizing your cost base. Can you just talk about your philosophy around capital allocation, how you think about the buyback versus the variable dividend? And if the company is on track to shift to a 100% free cash flow payout as we think about 2023?

Sure, Neil. It's Alex. I'll jump in and others may have some thoughts. But when you think about that financial framework, I mean that the thinking behind that has not changed at all. And I think when you think about how we look at dealing with that free cash flow, we will always think about the discipline that we will apply. It is entirely focused on shareholder value. And you quite rightly note that we leaned into the share buybacks quite heavily in Q2 and at periods where we felt represented real significant value versus our NAV at kind of a mid-commodity case. I suspect, I mean, going forward, we will be very much focused on shareholder value, and we will go after one of the two of those, depending on where we think we're driving the most advantage for our shareholders. So if you see the share price of $16 and we got a lot of spare cash, no one should be terribly surprised to see us focused on shareholder returns and vice versa, if we're at $30, we'll probably be focusing on variable dividends. But the real important commitment is between 9% and 4%, 50% of that is going to shareholders. And once we hit four, it's a 100%. In terms of kind of forecast, we don't forecast cash flow. But I look at where all of the analysts are, and I think most of them expect that we'll probably be at that $4 billion floor sometime either before or around the end of the year. And I wouldn't see anything that would move me off that view.

And the stock prices were Canadian, I would imagine. Is your view...

Yes.

Yes. And then your view of mid-cycle, if I remember, Alex, was $60 as kind of WTI is what you guys have talked about? Has the world changed for you in any way? I mean, there's a lot of reasons to think that that mid-cycle could have been repriced higher. So I'd be curious of your thoughts there?

I don't know. I'm a simple guy, and I'm not sure the world has changed that much. A lot of people in my position have gotten a lot of trouble by assuming we're in a new era of commodity prices. We still think there are times in the cycle where oil can get to $45 or potentially even below. We don't think the world works at $45 oil. So -- but we still -- I still think those fundamentals apply. A lot of oil can be brought on in this world for $60. And for the time being, we're going to continue with that -- I mean, potentially conservative outlook, but that's really the discipline we're applying here.

Yes, we appreciate that. Thank you so much.

No worries.

We'll now take our next question from Manav Gupta with Credit Suisse.

Hey guys, as we get closer to the start-up of Superior refinery. Can you help us remind what would be the feed slate, heavy, light, WCS and crude? And also, what would be the output looking like? I mean, in terms of gasoline yield ties and then secondary product yield, if you could talk through the reconfigured superior refinery as it starts to come online?

Yes. Thanks, Manav. It's Keith. You should think of Superior as kind of being reconfigured. It used to run in batch operations and through the rebuild, we're actually going to be able to run continuous operations. So we're looking at a throughput of around 49,000 barrels a day when it starts up. And a large percentage, 60% to 70% of that will be Canadian heavy product that will be able to run through it. When you think of the product slate, about a third is will be asphalt and then two-thirds are going to be a finished product with some accelerated products as small percentages. So that's the way you should be thinking about it. And like I said, it's gearing up for Q1 2023.

Perfect. And one quick follow-up here is, I think last quarter earnings call, I did ask you guys a question that do you envision a world where you could be the 100% operator of Sunrise and then BP Toledo refinery? I think one of those things has already come true. And I just wanted to go back and revisit although you didn't do a combined deal, can we still see the possibility that for the right price, you could be the full operator of BP Toledo refinery?

Hey Manav, it's Alex. That guidance that I suspect that one of us gave you in the last quarter would have been that our goal ultimately, in terms of our assets is to own our assets and operate those assets that are core and strategic to us. We think that the Toledo refinery is a very strategic asset for us. I would also note that we've been going through probably one of the biggest turnarounds that refinery has ever gone through, and that would probably not be a good time at which to contemplate a change of ownership. But it is something we continue to be focused on, and we think there's a lot of industrial logic of us eventually having a larger role there.

Thank you so much for taking my questions.

No worries.

We'll now take our next question from John Royall with JPMorgan.

Hey good morning guys. Thanks for taking my question. So just looking at your adjustments to the downstream OpEx guidance, can you give us a sense for the magnitude of the bump from the maintenance side relative to the other pressures you called out on gas and waiver, et cetera? And what I'm wondering is if there was a meaningful portion of it from the wet or inflationary type pressures, what was better on the upstream side where we didn't see a guidance bump there?

Hey John, it's Keith. Yes, a large percentage of that is due to the maintenance activity, and it's kind of the numerator and the denominator. A couple of our joint venture turnarounds went longer. So we saw some impact in utilization that's impacting kind of throughput for the year. And in addition, people may not know, but we expense our turnaround. So a lot of that turnaround cost goes right into the OpEx side of things and when they run long, they cost more. So a large percentage of the bump was in the unit OpEx was associated with both the throughput reduction as well as the cost overruns on the joint venture refineries. So I think when you look at the second half of the year, all of that maintenance is behind us and we should see a significant reduction in unit OpEx going forward.

Got it. That's really helpful. And then can you talk about the drivers behind the deferral of the turnaround at Foster Creek? Was it simply just around trying to capture today's prices with backwardated curve into next year, are there other drivers in pushing that out?

Yes. It's Norrie Ramsay here from the Upstream. I mean, we have ongoing maintenance, planned maintenance throughout the year in all of our assets. And what we try to do is minimize the opportunities for full outages. So I mean, this was as straightforward as we basically assess the work scope. We are doing regulatory inspection this year. So I mean, on the asset, there's about 1.5 MBD on the year reduction against what we could be doing even with the deferment. But it's literally just a case of as we go through the planning of our turnarounds and our large maintenance programs, we try and actually optimize and spread it across multi-year as much as we can. So it is a relatively straightforward process. We've done the essential maintenance this year and that we'll continue to do that. And we're really just deferring and the outage to minimize it. We can do that early next year. So it's just part of our annual process.

Hey John, it's John McKenzie and I'll just chime in and elaborate a little bit more on what Norrie was talking about. But any time that we defer a turnaround or take out scope from a turnaround, we do a thorough risk evaluation. Safety and reliability of our assets is always paramount. But where you have an opportunity to defer maintenance into the future, and you can do it, managing the risk in a safe and reliable way. It adds value for everybody. So it really didn't have anything to do with how we were seeing pricing today. It was just an optimization that Norrie and his group were able to undertake.

Great. Thanks guys. Thank you very much.

We'll now take a question from Dennis Fong with CIBC World Market.

The kind of final bit of that question was really just around the base dividend. I'm not sure if you guys answered it, if you guys did, let me know and I'll listen to the replay.

No, we didn't, Dennis. We didn't get around to talking about the base dividend, but why don't you repeat the just your question and we'll try to give you an answer.

Sure. It was just around -- you've done a lot to reduce cost structures, including term debt requirement retirements -- excuse me, as well as a lot of the asset integration, the increased working interest from Sunrise and some of the initiatives from both the upstream and the downstream and the superior refinery coming back online. So just given all those things and there is capacity for increasing of the base dividend versus that sustainability level in kind of that $45 WTI range. How are you guys looking at this on a go-forward basis? Is it more kind of pegged, I guess, towards leverage? Or is it, again, still just given, again, there's the opportunity now to look at increasing the base dividend? How are you guys evaluating it right now?

Leverage is a part of it. But really, I mean, when we look at that base dividend, it's all about sustainability at the bottom of the commodity cycle. And we're -- as I kind of alluded to earlier, we're not moving off that kind of $45, we call it our resilience case. And we believe fundamentally that it is important for a dividend paying company to have a competitive dividend and to have a reliably growing dividend. And that is our plan, and the five year plan we have in front of us would contemplate that if we are able to continue to deliver as we expect we would -- we would expect that dividend -- the base dividend would also grow at pace as we continue to grow the business.

Great. Thanks. And then if you just indulge me for one more. Just more on the ESG side. I know or at least from both your opening comments as well as the news release, some of the CapEx, I believe from the conventional side is related to decreasing emissions. Can you discuss a little bit about what some of those initiatives happen to be for this year and how that might carry on into 2023 as well as a little bit further down the line, helping kind of contribute to that 35% emission reduction plan that you outlined, both within your sustainability report, but also previously at your Investor Day?

It's Rhona DelFrari. Yes. So we have -- as we said, we have about $1 billion in our five year plan right now. And as we're working over the next months to update that five year business plan, you'll be seeing some more specific details about exactly where we're going to be designating those capital dollars. And so we're on track for where we are. I mean these are long-term targets into 2025 and beyond for the emissions in particular. And so we've mentioned some of the CCS projects that we're doing feasibility studies on. Those are some of the big dollars, but you're not going to see in the early years, it's more about figuring out what the best pathway is, and that's where we're putting a lot of the capital in the early years. What we are seeing in the short term though is opportunities in conventional to reduce some of the methane emissions and our well pads going forward or net zero well pads, basically. But you're going to see some of it paying off closer to the 2030 around there or 2035 as we're getting closer to that target.

Okay. Okay. Perfect. So it is more methane reduction.

Yes. And you'll get more detail when we come out with our revised five year business plan at the end of the year.

Perfect. Thank you very much.

[Operator Instructions]. And we'll now take a question from Chris Varcoe with the Calgary Herald.

Hi, this is a question for Alex. Alex, you talked a little bit earlier about inflation. And I'm wondering where are you seeing inflation bite the most? And at what point does it become a concern for you as you're putting together your capital spending plans for the rest of the year and into 2023?

Hey, Chris, others may jump in on this. But I think where we've really been seeing it is up in the oil sands, it is definitely an issue. It's not been as big an issue for us. And I think that is largely because a lot of our -- most of our activities in the oil sands are really planned out in staged years in advance. So we have the benefit of lots of our contractors on long-term contracts, a lot of our materials procurement being procured well in advance. So it has been -- it hasn't hit us hard on the oil sands side. We are seeing a lot more pressure on the conventional side, and that would be in things like tubulars, like drilling pipe, casing, drilling contractors, drill rigs, completion rigs, frac rigs, those sorts of things. And I think overall, probably we're seeing escalation of costs right now kind of maybe up towards that 10% range. But individual components could be significantly higher, but we've been able to manage it kind of in and around that level or a little bit below.

Just a follow-up on that. How does that influence, I guess, your 2023 capital plan? Do you expect them to have to escalate because of that? Just how do you position that, I guess, as you're assembling those programs for 2023?

We're right in the process of developing our budget for 2023. And obviously, inflation is going to be something that we have to consider. I mean, my challenge to the team is always to try to find a way to eat inflation or make up for inflation. And some years, we're able to do that. Next year might be a bit of a challenge. But I think it's definitely something we have our eye on. But I think right now, it's something that is manageable and is not going to meaningfully sort of change any of our investment decisions over the coming year.

Just finally, one last question I wanted to ask you about the federal government releasing its discussion document last week for the oil and gas emissions cap. I guess I was wondering what your general reaction to it was in the two options that were presented in terms of the cap and trade system versus a higher carbon pricing that would be directed towards the oil patch.

Yes. Chris, I mean, first off, maybe I'll talk about the two policy options that the government talked about in their paper. And I would say either of those options are more ambitious than what can reasonably achieved. I am very worried that if we remain on this path, it could lead to shutting in production. And at a time when the world is literally crying out for more oil and gas production. And we're talking about a plan to reduce oil and gas sector emissions by 42% from 2019 levels by 2030. You obviously would be aware of our pathways initiative. And those targets that we put out, including the 30% target by 2030, that was intended to be -- that target was intended by pathways to represent the best case that we could do if everything worked out really, really well, and we were able to get investing in these carbon reduction strategies very, very, very quickly. I look at those goals, those are much more aggressive goals that are being asked of any of the other industrial sectors in the country, including agriculture, heavy industry and transportation. And as I said, I think they're going to be incredibly difficult. I don't think they're possible to hit. And if we stay on them, what you're going to see is a -- ultimately, the risk could be a cut in production from Canada at a time when these resources are just incredibly desperately needed worldwide.

Thank you.

No worries.

We'll now take our next question from Nia Williams with Reuters.

Hi. Following on from what you were just saying about how the world desperately needs oil and gas resources. As Cenovus, are you expecting to grow pre-production as well? Or will you be quite cautious on production growth given oil market volatility and also the federal regulations that you were just talking about?

Well, I mean, I think there's certainly going to be and I think the government intended that there'll be a great deal of consultation and discussion before any of those things are finalized. So I think the decisions we're making right now are more focused on sort of practicality and what is possible for our company to do. And I think we have been talking about since the Husky acquisition, we've really been talking about organic, a lot of organic growth in the business, kind of brownfield growth, call it, capacity creep, debottlenecking and rather -- we're not focused on any large-scale projects. But I would just give you an example. If you look at last year, we ended the year at around 800,000 barrels a day. In the interim period, we have divested of over 40,000 barrels a day production. And you just heard us say today that we expect to end this year, once again, back at about 800,000 barrels of production. I think that's pretty meaningful growth. And we've been able to avoid any really large-scale greenfield projects in doing so.

And what about production next year? What are you anticipating there?

Well, I would -- we haven't completed that work. But if we end this year as Norrie suggested at around 800,000 barrels a day, I would expect we will be in that range. And I suspect the company will continue to be able to find ways to add barrels here or there, and we'll continue those kind of what I would call organic brownfield kind of debottlenecking growth opportunities.

Okay, thanks.

Yes, no worries. Thanks Nia.

And it appears there are no further telephone questions. I'd like to turn the conference back over to Mr. Pourbaix for closing comments.

Well, thanks very much, operator. And once again, thanks, everybody, for taking the time out of your busy days and I'm sure a number of you from your vacations, and everybody take care and be safe.

And once again that does conclude today's conference. We thank you all for your participation, you may now disconnect.