Cenovus Energy Inc (CVE) 2023 Q1 法說會逐字稿

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's first quarter results. As a reminder, today's call is being recorded. (Operator Instructions) Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Cenovus Energy.

I would now like to turn the conference over to Mr. Jason Abbate, Senior Vice President, Investor Relations. Please go ahead, Mr. Abbate.

Thank you, operator, and welcome, everyone to Cenovus's 2023 First 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. They also outline the risk factors and assumptions relevant to this discussion. Additional information is available in Cenovus's 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, then we'll take your questions. We ask that you hold off on any detailed modeling questions. You can follow up with -- on those directly with our Investor Relations team after the call.

And please also keep to 1 question with a maximum of 1 follow-up. You're welcome to rejoin the queue for any follow-up questions you may have. Alex, Please go ahead.

Thanks, Jason, and Good morning, everyone. As I do every quarter, I'm going to start this morning's call with our top priority, health and safety. The safe restart of the Superior and Toledo refineries is of the utmost importance to us. And over the last few weeks, we've resumed operations at both refineries.

On our Q4 conference call, we committed to start running crude at Superior in mid-March, and we did that safely. The refinery is currently running between 24,000 and 30,000 barrels a day, and you can expect it to ramp-up to full rates through the second quarter. In Toledo, we successfully closed the transaction on February 28th. We've restarted the smaller 30,000 barrel a day East side of the refinery and expect a larger West side to be online in May, also ramping up to full rates through Q2. Both of these refineries are currently making on-spec product.

With the construction of Superior now complete and the restoration work of the impacted zone at Toledo complete, we expect these assets to generate significantly improved operating margins through the quarter, approaching breakeven in June and achieving free cash flow by July.

I'd like to acknowledge and thank all the teams involved in achieving these significant milestones. These start-ups were done safely and methodically, and we appreciate the focus by everyone involved. We apply the same attention to safety that we did with these startups to everything we do. Our safety journey is never complete, and we look to continue elevating our performance.

Turning to our operating results. This was a challenging quarter, and to be blunt, not up to the standard we've set for ourselves at Cenovus. I want to address this upfront. In U.S. downstream, the ongoing cost of getting Toledo and Superior restarted, impacted our margins. Because of our vertically integrated strategy, not having these refineries running at full rates, while differentials widened as much as they did, was especially impactful on our corporate cash flows.

Our non-operated refineries, Wood River and Borger, ran below expectations during the quarter, which further impacted cash flow and earnings. This was mainly due to unplanned downtime at Wood River related to the December incident, which led to significant costs associated with fulfilling obligations for finished product as well as the remediation work itself. Wood River is now back up and operational, with the exception of some planned maintenance scheduled to be complete in the middle of May.

Given the operational performance in U.S. manufacturing so far this year, we've adjusted the throughput in our annual guidance down by 40,000 barrels per day at the midpoint, resulting in full year throughput guidance for the downstream to deliver between 580,000 to 610,000 barrels per day. However, with the many significant milestones now achieved, we are paving a path to successfully deliver on our integrated strategy. We've also updated our annual production guidance for the Atlantic region, reducing it by 10,000 barrels a day.

We are taking a conservative view and have removed Terra Nova volumes from our 2023 guidance. Our full year guidance for upstream production is therefore 790,000 to 810,000 barrels equivalent per day.

We continue to progress our strategy with conviction. Our management team is confident the plan will deliver in all areas of our business with the performance that you've come to expect of us, and more importantly, the performance we expect of ourselves. We believe you will clearly see the strength of our operations and integrated strategy in the back half of this year.

Let me further speak to the actions we are taking as a company to improve our asset and financial performance. In the oil sands, production from Foster Creek and Christina Lake will benefit from 3 new pads starting up at each asset and contributing to higher production volumes in the third and fourth quarters. At our Lloydminster Thermals and Sunrise product -- projects, we will continue to optimize our development and operating strategy to support improved production volumes.

At our Lloyd Thermals, we have production solidly back over 100,000 barrels per day, while Sunrise will benefit from the first new well pad since 2017 when we start up a pad around the end of 2023. Conventional continues to impress with steady production rates and strong cash flows even with AECO prices declining through the quarter.

We have recently drilled some really prolific wells in the Wapiti area, which are testing at record rates. These were among the top Alberta gas wells in both January and February, giving us further confidence in our future development plans. Asia-Pac continues to generate free cash flow, and our offshore segment as a whole contributed $300 million in operating margin this quarter.

Moving to our downstream operations. I want to reiterate what I previously mentioned. With Superior, Toledo and Wood River, we expect to see improvement on our overall throughput and utilization rates in Q2. The normalized margins and crack capture rates will become further evident in Q3.

Though not as robust as previous quarters, we expect to see a strong market for refined products through the rest of the year, and our U.S. refining network will be in a great position to take advantage of this.

Canadian manufacturing performed well with the Lloyd refinery operating at a 99% utilization rate and the overall segment contributing over $260 million in operating margin.

With the consistent high reliability of these assets, we expect to be able to take advantage of strong product pricing through the year and are well positioned, should the heavy oil diffs widen.

Turning to our financial performance. Our net debt increased this quarter as expected. This was mainly due to the cash tax payment of about $1.2 billion for taxes accrued from last year. Now that we are cash taxable in all jurisdictions, taxes will be paid on a quarterly basis going forward.

The increase in net debt also reflects approximately $460 million to close the Toledo deal and the first variable payment related to the Sunrise transaction. Given where we are today and assuming commodity prices remain around current levels, we expect net debt to fall below the $4 billion floor in the fourth quarter.

Lastly, consistent with our ongoing strategy and commitment to shareholders, our Board approved a 33% increase to the base dividend to $0.56 per share on an annual basis. This increase is a reflection of our commitment to assess the base dividend annually and provide our shareholders with a sustainable and growing dividend over time. This dividend as well as our sustaining capital is well covered in a USD 45 per barrel WTI pricing environment.

Today's call is the last conference call I'll be leading for Cenovus as I move to my new role as Executive Chair of our Board. You will be in Jon's steady hands for Q2. As he takes the helm, this company is positioned well for long-term success, and I know that Jon will lead Cenovus successfully and continue to execute the company's long-term strategic plan. The strategy we set at the beginning of my tenure in 2017 was really simple, optimize our cost structure, strengthen the balance sheet and ensure market access for our upstream production.

I can confidently say that we have delivered on all 3 and then some, and I would like to thank everyone who made it possible. Our staff and management team have been remarkable, and I am truly excited to see Jon lead this company forward.

With that, we're happy to take any questions you may have.

(Operator Instructions) And go to our first caller, Dennis Fong with CIBC World Markets.

The first question I have, maybe directing towards Jon, just given your background and experience in the refining sector, I was hoping to maybe get your take and even maybe some examples of how Cenovus plans to change or improve on the maintenance of the refining assets versus maybe the previous operators, especially now that they're kind of operated or ramping up kind of throughout the portfolio?

Yes, sure. When I kind of look at our portfolio, we're going to be running a portfolio of 5 operated refineries with 2 non-operated refineries in Wood River, Borger. And if you kind of look at the trajectory of the performance of the assets that we've had under our stewardship over the past couple of years since we purchased Husky, I think you'll see that the Canadian assets have operated really quite well and that we get high levels of utilization and reliability out of them.

And similarly, there's been a step change in Lima. And I think that, that is really a credit to the work that Keith and the group of people that we put into our manufacturing business have been able to do in relatively short order.

So my expectation is that when we bring up Superior and Lima, not only we'll work very quickly -- sorry, Superior and Toledo, not only we'll work very quickly to optimize them commercially, but you'll see the same kind of operating performance with the people that we brought in from outside as well as the people that we inherited from the Husky acquisition to bring in the same kind of maintenance processes and reliability processes there.

But we have a high expectation for what we're going to get out of those assets and a high expectation internally of how they're going to run. And I think that, that comes out of a level of confidence that we have from the assets that we've been running for the last couple of years already.

My second question here is really around the -- I guess, the current balance of upstream versus downstream within the portfolio. As we kind of look out over the next 12 to 18 months, there is the potential for additional egress, especially with the Trans Mountain expansion pipeline eventually coming online. How do you look at the balanced portfolio between the upstream volumes and your downstream refining capacity? And do you view that to be, we'll call it -- I don't say necessary, but how do you think about balancing those 2 items as you move forward, especially just given the nature of the assets and the availability of accessing global markets?

I'll maybe just give a couple of comments, and then I'll pass it over to Jon. But I would say, right now, we feel pretty comfortable with the portfolio we have and the mix we have between upstream and downstream. You've heard us talk in the past about our plans to modestly grow our upstream. But we think we have a really good portfolio of downstream assets that are largely directly connected and have the ability to run our heavy oil molecules. And we'll always be opportunistic. And if something really compelling came forward, we'd obviously have to take a look at it. But I think right now, we feel pretty good, and maybe I'll pass it over to Jon.

Yes. Maybe I'll just add a couple of points on to that, Dennis, because it really cuts to the heart of everything we're trying to do here in terms of creating that heavy oil value chain. But if you think about what we've created here, we've built an upstream heavy oil portfolio that produces about 800,000 barrels a day of heavy oil blend, and once we get Superior and Toledo up and running, we're going to have takeaway capacity for about 600,000 barrels of that heavy oil. So we'll eliminate the location risk on that.

And then within the portfolio, we can consume about 400,000 barrels a day of heavy. So we really like the way that we put this together and we've been able to kind of mitigate the -- or a large portion of the location and heavy oil differentials that we see in the portfolio. And then on top of that, we have about 740,000 barrels a day of refining capacity, which we get the crack value on top of it.

So in terms of what we've built, getting these 2 refineries up really completes the asset portfolio that we envisioned when we bought Husky, and we think we've built a pretty powerful heavy oil value chain with the assets that we've got. So I don't think there's anything that's really missing from that, that we need to kind of look at above and beyond it today. But as Alex mentioned, we do have a desire to incrementally grow the upstream and we'll have to look at the downstream in concert with that. But today, we feel like we've got a really nice poster of it.

Next, we'll go to Menno Hulshof with TD Securities.

Maybe I'll just follow-up on Dennis's downstream questions. Are there any specific learnings that have come out of the last couple of quarters with U.S. refining that you can speak to today and give you more confidence going forward?

What I would say is, maybe we'll just take a build on what Jon said. We're pretty happy with the improvements we've seen at Lima. Lima performed in 2022 producing almost $1 billion of Op margin through the year. Safety performance was down at kind of world-class performance around 0.1% on a trip. So really happy with kind of the improvements we're seeing there. Obviously, we're not overly happy with kind of the restarts of both Superior and Toledo and working very diligently on that.

Maybe I'll just hit on each of those separately. On Toledo, on March 1st, we took over operatorship. The refinery wasn't running at the time. We basically performed a couple of additional assessments prior to restarting the refinery. We've completed the repairs associated with the fire impacted area back in September. We then restarted the East side of the refinery, which is about 30,000 barrels a day. We have that lined out and producing products.

And now we're turning our focus to the larger part of the asset, which is the additional 120,000 barrels a day, which we'll work to bring on through May and ramp-up the full rates by the end of the quarter. Obviously, through this period of time, when you're not operating, you have a pretty significant impact on free funds flow. You're consuming a lot of OpEx, but you're not generating any revenue. So we do look to kind of Q3 being a really transformational time for the Toledo refinery.

On Superior, we are demobilizing the construction project. It's essentially complete. Teams are ramping down, and we're actively working on the commissioning of the FCC. We were able to commission and start up the crude unit. So we're currently processing in the 20,000 to 30,000 barrels a day of crude on the crude unit and producing finished product out of that asset. And then we'll quickly move over to the FCC and start commissioning that.

And similar to Toledo, it's been consuming both capital and OpEx in the first quarter without generating any revenue. And so looking forward to kind of the April-May timeframe to get that asset up fully running and into the end of June time period to start realizing the full value of those 2 assets. So a lot of focus on safely getting these 2 assets back up and running. They do complete the heavy oil value chain that Jon alluded to and are a big part of the ongoing strategy. And we're happy with the teams we have in place, and we're confident in our capability to safely restart and run these reliably.

Yes. Menno, I would just -- I agree with all of Keith's comments. And I would just observe that, for the various reasons we've talked about, particularly with respect to Superior and Toledo, we have not been in a position to demonstrate the full capability of this machine when we have all of our downstream assets running and our upstream assets and the incredible impact that having all of that together gives to our operating margin. And you heard me say in my prepared comments, I think everybody should really look forward to the second half of the year because I believe we will see the full value of that engine operating both downstream and upstream. And I think we're all very happy to be getting through this construction phase and moving into that, bringing everything online and getting everything lined out.

Maybe I'll flip over to upstream and Sunrise in particular. I'm just eyeballing the slide here. It looks like the incremental 15,000 to 20,000 barrels per day of new capacity is slated for, give or take the middle of next year. Can you just remind us of the scope of work for that incremental capacity and maybe even the capital efficiency? And if we take it to a higher level, is there anything jumping out in terms of best practices from Foster Creek and Christina Lake currently being applied at Sunrise?

Yes, I mean not only this year our production at Sunrise is flat, and there haven't been any new pads drilled since 2017. So what we have is 3 pads actually being developed at the moment. And as you said, we plan to have production beamed up really early next year as we start to actually bring on those pads. What we have been doing is applying our Foster Creek and Christina Lake of subsurface strategies.

And what we've been doing are drilling longer wells within the reservoir and actually been able to deploy steam more efficiently across the -- and the reservoir as we do that. So our SOR, so our steam oil ratio, which is one of the measures of our operating costs, we see that continuously being driven down the way. And similarly, we're applying our low-cost strategies from an operating viewpoint across the surface facilities, and we see our OpEx coming down as we do this.

So going forward, as we drill more wells into the reservoir, we actually plan to get to nameplate within the next 18 months. And from there, we're actually looking at debottlenecking going forward.

And moving on, we'll go to Greg Pardy with RBC Capital Markets.

A lot of focus on the U.S., and I recognize why. But then you've got this great asset called the Lloydminster Upgrader. And I wonder whether that one holds further promise for you either in reducing your condensate costs on a go-forward basis or what have you -- But I'm just wondering what the -- perhaps the medium to longer-term plans might be for Lloydminster?

Yes, great question. We're obviously spending a fair amount of time looking at the opportunities to integrate our world-class upstream assets with the Lloydminster area and complex. We actually are advancing at the refinery debottleneck opportunity right now, and that will expand the capacity of the refinery. We're also looking at a second debottleneck that will essentially increase throughput by almost 60% over the next few years at the refinery. The refinery is also a feed into our upgrader.

So we're pretty excited about, to your point, being able to bring over some of our higher condensate upstream dilbit and processing at this asset because then we can recycle that condensate, but also looking at the upgrader and pulling out additional diesel production out of the asset as we process more dilbit through the combined infrastructure that we have there. So pretty exciting opportunities that we're seeing there, a robust list of opportunities that we're progressing and ongoing debottlenecking and improvement in those assets.

I mean, I know this kind of goes without saying, but all of those projects that Keith is talking about, as always, with this company, we'll return their cost of capital at a $45 WTI price environment.

And relatively on that one.

Sorry, I missed that, Keith?

Yes. I was just going to say relatively low capital to kind of get those debottlenecks done too.

And then this is -- if I look at your first quarter, you built 12,500 barrels a day in terms of inventory. AECO prices were high, but they dropped significantly. And then the timing on your condensate purchases would have meant that your blending costs were that much higher and so your dry bed realizations were that much lower. Is it fair to say though that as you go through the second -- as we go through the second quarter here, that all of those headwinds are essentially turning into tailwinds, whether it's operating costs or even from the standpoint of realizations?

Yes, Greg, I think a few things. We will be building a little bit of inventory as we -- and we're seeing it already as we start the refineries in that infrastructure. We were able to send some additional barrels down to the Gulf Coast to capture some additional margin that we saw kind of coming out of the December and January time periods when differentials were wider. But to your point, differentials have now really narrowed in and the spread between condensate and WCS has also narrowed. So all of those are now moving over into tailwinds, and we've seen the realizations significantly improve over the past couple of months.

Yes. And Greg, just on the condensate side. I mean, one of the things that we've seen through the first quarter and continuing is condensate on the Gulf Coast has been really discounted relative to Fort Saskatchewan. So we've been taking full advantage of our assets to bring condensate up to the Gulf Coast into Alberta to meet our condensate demand with our heavy oil assets as well. So those arms are still wide open for us.

(Operator Instructions). And next, we'll go to Neil Mehta with Goldman Sachs.

My first question is around the net debt levels in the quarter, were $6.6 billion. But I think in your script, you talked about how you still have a lot of confidence in being able to get to under $4 billion by the fourth quarter. Can you just kind of walk through some of the assumptions? I would imagine you'll have some working capital release that should help in addition to the organic free cash flow as we're finding ramps, but give the market a little more confidence in your ability to achieve that sub-$4 billion levels?

I'll give some color on that. I wouldn't expect a significant working capital release. That being said, you did see the build this quarter, and that was really driven, as we talked about the cash tax payment of $1.2 billion. But that's really underpinned, as Keith talked about, is our organic cash flow. We do -- as Norrie talked about, we have pads coming on here at the end of the year -- back half of the year. We also have the ramp-up in Superior and Toledo. And it's really that organic cash flow we'll be driving in the generation. We're not relying on significant working capital releases. So it is the operations, Neil.

And remind us the commodity price assumptions that are embedded in getting to that sub $4 billion number...?

Yes. I think we're around... Yes. Go ahead.

No, please, go ahead.

Yes. So the commodity price assumptions we're talking about there at $75-ish WTI and a Chicago crack of $28 pre-RINs and you're probably in -- around the $20, $21 mark for the crack go forward for the residual part of the year.

And then the follow-up is, as you get to that sub $4 billion level, and given the stock has underperformed at the start of the year, how do you think about the return of capital dynamics? And how do you take advantage of maybe some volatility in this time?

Well, Neil, and I've said this many times, and I think this view is shared by the management team and the Board. But all things being equal, we do prefer share buybacks than variable dividends. And right now, at this kind of share price, we are well below our target level for share buybacks. And I would -- we would be alive to the opportunity that would present as long as we're at this kind of share price level. I think we might have lost Neil.

And moving on we'll go to John Royall with JPMorgan.

So my first question is just on the variable payments to BP on the Sunrise acquisition. Can you remind us how those work and what are the expectations going forward? I know it's potential for another $600 million on the variable piece. And how much do you ultimately expect to pay in the current environment?

So the way that transaction was structured is we pay every quarter based on where WCS pricing is above $52 for every quarter. So -- and effectively take the price difference between $52 and where WCS is and multiply it by $2.8 million. So that payment is -- does not have a quarterly cap, but it does have an aggregate cap of $500 million. And so you should expect there'll be payments under those terms of those agreements until we hit that $500 million. There's also a term. So 2 years -- after 2 years, the payments stop irrespective of whether we get to that cap or not.

And then maybe you can speak to just -- if you have any sort of broad expectations for -- there are a lot of moving pieces, maybe where you think refinery utilizations will end up in 2Q?

And then another thing we noticed is that the Wood River went into turnaround for 2Q and there was previously no maintenance in the schedule for 2Q. Was this just pushed out from 1Q or is it incremental to overall guidance?

Yes, so on utilizations, as we kind of alluded to, the Canadian part of the business is running well. And in the U.S. we would expect utilization to continue to improve through the quarter and then we have full utilizations in third quarter.

On Wood River, you're spot on. There was a planned turnaround early in Q1 that got deferred to Q2 as they repaired and restarted from the incident back in December. All of that is progressing well. That should wrap up here towards mid-May, and then all of our joint venture assets will be running through the remainder of the second quarter and into the third quarter as well.

(Operator Instructions) And we do have a follow-up from Dennis Fong with CIBC World Markets.

Just as -- out of curiosity, now that you're operating, obviously, the 3 refining assets in the U.S., can you maybe make a comment on how you plan -- And I know RINs costs have kind of decreased a little bit through the start of this year. But I know that happened to be kind of maybe a pinch point in years prior. How do you plan on managing RVO requirements as well as RINs costs within your refining assets now that you operate the refineries?

Obviously, we're live to the fact of our blending requirements, and we are a participant obviously in the market and kind of -- ratably offset our requirements kind of quarterly. Obviously, we are continuing to look at, are there any additional opportunities to further impact that. But the way our assets are structured and where they're located, there's no evident easy opportunities to do that. So we'll continue to look at it. But right now, we're just ratably offsetting those through the quarters.

Yes. I mean, that's the important piece that Keith just highlighted as we ratably buy and we don't really take a position on RINs outside of just managing that RVO requirement.

(Operator Instructions) And we'll next go to Chris Varcoe with Calgary Herald.

This is a question for either Jon or Alex. We heard just a couple of weeks ago that the Trans Mountain costs, to complete that project have now gone up to about $30.9 billion. I'm wondering what kind of impact that's going to have upon your tolls on that project and the economics of it? And can you remind us how many barrels you'll be moving on and once the expansion is completed?

The -- All of the shippers -- we obviously all have long-term shipping agreements that provide for some level of sharing. I'm not sure that number or that formula is public. But what I would tell you is that even at the price we're at now, this still represents a good egress asset for us. And I think it's really going to help the situation in the province over the long-term.

And just on a separate topic, we saw the federal budget come out a couple of weeks ago with some changes to respond to the U.S. IRA. I'm wondering whether you thought those changes were sufficient enough for pathways in company to move ahead on your carbon capture projects and some of your other decarbonization projects?

Chris, this is something I've said many times. I mean, look, we appreciate the words that the government had in the budget, for example, about the investment tax credit. We are right now in an ongoing discussion with the federal government and the provincial government. It is -- The ITC was a welcome addition. We very much appreciate that -- the government stepping out to help us in that way. But I think at the end of the day, we are going to need more support from governments. This is an incredibly -- just an incredible undertaking that the industry is proposing to do -- to reduce and ultimately move towards net 0 by 2050.

There's going to be -- we estimate just for the oil sands, that's going to be a $75 billion cost. But you have to put that against the value that this industry brings to Alberta, brings to the country. I think the last I saw, we employ directly or indirectly about 0.5 million workers in this country. And just this year, we're going to pay somewhere in the range of $50 billion in taxes and royalties to all level of governments. And we are going to do our part. We are going to fund tens of billions of dollars of this transition, but we are going to need more help to do it, especially if we have any kind of hope to remain competitive with other oil producing jurisdictions around the world that I would point out are largely doing nothing to address their emissions.

Finally, I just wanted to ask you about -- we're talking about the federal response, but I'm wondering where the discussions are sitting right now with the province? They've had some discussion about maybe expanding their APB grant to include CCUS. Is that enough? Or are you looking for something else as it relates to the provincial government's involvement?

I mean, as always, the devil is in the details, Chris. But my -- we are well in -- continuing in discussions with the Alberta government. I think those discussions have been productive. I think both the industry and government appreciates what we're trying to achieve. And I think they're going in the right direction. And you know what, there's many ways that the province could support this work we're trying to do. The APB idea is one of them, but I'd probably just hold off on being specific about it until we have more discussions with the province and the Feds.

And moving on, we'll go to Peter Passi with Duluth News Tribune.

Well, congratulations gentlemen, on finishing work on the refinery in Superior. I'm curious, you said, I think, that you're running about 20,000 to 30,000 gallons of crude through the facility right now. Can you talk a little bit about what the throughput will look like when you're at full capacity and when you expect to reach that? Is that likely to be second or third quarter?

That was -- those were barrels, not gallons, but I think what I'll do is I'll turn -- no worries, I'll turn you over to Keith Chiasson, who is our EVP downstream, and he can give you the detail.

Peter, it's pretty exciting to talk about this asset. We've been -- since we've taken over the asset in January 2021, we've been in the middle of a construction project and rebuilding and it's nice to be coming out of the back end of that. I'd tell you that our staff that have been through this whole period of time are really excited to restart the refinery. So through this month, we've been able to bring on crude to the tune of 24,000, 25,000 barrels a day and ramping to 30,000 barrels a day.

And then we will start commissioning the FCC imminently here to bring on the remainder, which will take it up to its nameplate capacity of 49,000 barrels a day. The teams have spent a lot of time on training, community involvement and making sure everybody is ready for this restart. So pretty exciting times and Cenovus may not be that well known in the area yet. But we're working on building our reputation. In Canada, we have a reputation as world-class operators and we are definitely planning to replicate that south of the border at our U.S. assets, including Superior.

Can you tell me how that capacity, the 49,000 barrels a day, compares to the facility you inherited before the fire?

Yes. It's roughly similar, Peter. The only difference is prior to the incident, they were in batch operations, so you'd run a batch and then slow down and change over your crude slate. We've made a lot of improvements in the control systems and the equipment to be able to now run continuously. So you should see us having higher utilization rates because of that at a similar nameplate capacity.

I understand the workforce is also growing. It has been about 200 people. I think you're looking at roughly 350 with this new facility. Can you talk a little bit about why this is more labor intensive or is it about safety or -- I imagine its a number of factors?

Yes. I think, Peter, when you're quoting that type of number, you're also including some of the contract workforce that we have. And we're also planning on growing our asphalt business in the region. And because we're running continuously, we'll be producing more products. So it just requires a little bit larger of a workforce. And I would tell you, as we onboard the people, they've been really excited to join the company and get ready for safe, reliable operations.

And next, we'll go to Patrick Butler with Radio-Canada.

You mentioned you're taking a conservative view on Terra Nova and removing Terra Nova from your corporate guidance. Why is that? And could you provide the current time line for return to production at Terra Nova? Has that changed?

I mean a lot of these questions, you probably have to direct to the operator. The operators informed us that you've delayed taking the facility back offshore. We're continuing some maintenance work at Bolam , which is in Newfoundland. So I'd just refer you to the operator in this case. They know and they have the information on when they plan to restart.

And could you also provide an update on West White Rose? I know there's been a major pour started recently. Can you talk about the operations in Argentia right now?

Yes. We're actually very excited about it. There's 2 big pieces of work on West White Rose at the moment. We have -- on each shift, we have, I mean, literally 1,000 people on 3 shifts working in Argentia, where we're actually doing a pour which will complete the bulk of the gravity-based structure. That will take 60 days and loosen. In the next 40 days or so, that part will be finished. The other thing is we've completed putting together the Topsides facilities which are down in Texas. So the projects coming together well, but there's obviously a long way to go before we finally see safe production.

All right. And can I just ask you who is speaking just now?

Sorry, Norrie Ramsay, I run the upstream part of our business.

I'll now turn it over to Mr. Pourbaix for final comments.

Well, thanks very much, operator. And I would encourage everyone who is interested to tune into our Annual Meeting of Shareholders at 11:00 this morning Calgary time. You can find a link to access the call on our website. With that, our call is now complete. Thanks for joining us, and have a great day.

Thank you. And that does conclude today's call. We'd like to thank everyone for their participation. You may now disconnect.