Cenovus Energy Inc

Good morning, everyone. Thank you for standing by, and welcome to the Sinovus Energy Second Quarter 2025 Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during a session, you will need to press star 1-1 on your telephone. As a reminder, this call is being recorded. I would now like to turn the meeting over to Mr. Patrick Reed, Vice President, Invest Relations and Internal Audit. Please go ahead, Mr. Reed.

Thank you, Operator. Good morning, everyone, and welcome to Sinovus' 2025 Second Quarter Results Conference Call. On the call this morning, our CEO, John McKenzie, and CFO, Cam Sandhart, will take you through our results. We'll then open the line for John, Cam, and other members of the Sinovus management team to take your questions. Before getting started, I'll refer you to our 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 Sinovus' annual MD&A and our most recent AIF and Form 40F. And as a reminder, all figures we reference on the call today will be in Canadian dollars, unless otherwise indicated. You can view our results at sinovus.com. For the question and answer portion of the call, please keep the one question with a maximum of one follow-up. You are welcome to rejoin the queue for any other follow-up questions you may have. We also ask that you hold off on any detailed modeling questions. You can follow up on those directly with our investor relations team after the call. I will now turn the call over to John. John, please go ahead.

Great, thank you, Patrick, and good morning, everyone. As always, I'll start with our top priority, health and safety. This quarter posed some unique challenges, and I couldn't be more proud of the way our people responded. In late May, the Caribou Lake wildfire forced the evacuation of over 2,000 workers from our Foster Creek and Christina Lake operations. The fire came within a couple kilometers of Christina Lake, and as a result, the facility underwent an orderly shutdown as per our protocol. After a brief outage, and thanks to the tireless and determined work of our people, we safely ramped production back up to 250,000 barrels a day and returned to normal operations over the course of the week. Now, this effort included draining and restarting over 50 kilometers of steam pipelines, bringing 26 boilers back online, returning the cogen facility back to service, and remobilizing all 2,000 people back to site. It was an incredible effort, all safely done, and without damage to our assets. It's a privilege to witness how our people step up when it matters most, and I'd like to thank our staff for their resilience and continued commitment and dedication. Now, turning to the quarter. This was a terrific quarter for the company. A lot of important work got done, and many important milestones were achieved. We underwent a heavy maintenance period, completing large turnarounds in both the upstream and the downstream, which came in ahead of schedule and under budget. We achieved some very significant milestones on our major projects, bringing us closer to delivering on our production growth targets and completing our three-year cycle of higher capital investment. And through all that activity, we delivered exceptional operating performance across the company. Together, these achievements set the stage for the second half of the year and beyond, and they were accomplished thanks again to the hard work and determination of our people. Now, I wanna speak to some of the details. Beginning with the upstream, production in the quarter was 766,000 BOE per day as we completed turnarounds at Foster Creek and Sunrise, and managed the production impacts from the wildfire activity at Christina Lake and the steam release at Rush Lake. The turnarounds at Foster Creek and Sunrise both went very well. We completed the work and restored production well ahead of schedule, minimizing volumes lost over the quarter. At Christina Lake, production came back strongly following the brief wildfire-related shut-in. Production was 218,000 barrels a day in the quarter and has averaged over 250,000 barrels a day in July. And we achieved an important milestone with the Narrows Lake tieback to Christina Lake. Narrows Lake produced first oil earlier this month in July. This is a huge accomplishment and a testament to the technical and operations team who made this -a-kind tieback possible. We'll ramp up the first pads at Narrows Lake over the remainder of the year, and this means a lower steam-oil ratio and sustained higher production rates as we maximize the value from this asset. Now, the second quarter was also a very busy quarter at the West White Rose Project. During the quarter, both the concrete gravity structure and the top sides were transported out to the offshore field location. In June, the CGS was placed on the seabed, and in mid-July, the top sides were lifted and set atop the CGS well ahead of

schedule.

Now, this feat of engineering included the world's first-ever direct -to-ship transfer of a topside to the Pioneering Spirit crane vessel. With both the CGS and the top sides work complete and set in place, hookup and commissioning activities have now begun. This will include the connection to the CRO's FPSO, which began producing oil earlier in the year following the successful completion of the asset life extension. During the quarter, it reliably produced over 7,000 barrels per day. We plan to commence drilling from the West White Rose platform before the end of the year and achieve first oil in the second quarter of 2026. At Foster Creek, we tied in four new steam generators during the turnaround and turned them over to operations in July. These steam generators will collectively add about 80,000 barrels per day of new steam capacity as part of the optimization project. We will complete work on the de-oiling and water treatment facilities later this year, and we're on track to bring on first oil from the project in early 2026. Now, during the quarter, we also responded to a casing failure in an injector well at Rush Lake, which resulted in a steam release to surface. The release was a localized incident impacting one well at a Rush Lake II asset. In response to the release, both Rush Lake I and Rush Lake II facilities were shut in. Prior to the shut-in, the facilities had been producing about 18,000 barrels a day. The well has been brought under control and we'll work together with the regulator to complete a full investigation and put together a plan to safely restart production. As a result, and out of caution, we have removed Rush Lake volumes from our production guidance for the remainder of this year. The production impact has been partially offset by strong performance from the other Lloyd Thermal Assets, driven by new development wells and optimization work. Overall, it's been a very active and productive period for upstream business, and we continue to deliver on our growth plans. In the downstream, we had strong results in the second quarter, excluding inventory holding losses and expense turnaround costs, the downstream business generated about 220 million in operating margin. The Canadian refining had another exceptional quarter. Crude throughput reached a new quarterly high of 112,000 barrels per day, with a utilization rate of 104%. The reliability improvements made to the Upgrader during last year's turnaround have enabled us to test the capacity of the facility, with crude rates reaching as high as 87,000 barrels a day versus an operable capacity of 78,500 barrels per day. The Lloyd Minster refiner also performed exceptionally well, with rates reaching 33,000 barrels per day and record asphalt production in the quarter, as we took advantage of strong seasonal demand. In US refining, we delivered crude throughput of 553,000 barrels per day, while also executing a major turnaround at the Toledo Refinery. And our execution at the Toledo Refinery was exemplary. We took down eight major refinery units on the east side of the plant, and similar to Lima last year, took a targeted approach to address the issues that we expect to improve reliability going forward. The turnaround was completed 11 days ahead of schedule, and costs came in at the low end of the guidance range. Now importantly, this marks the end of a heavy maintenance period across our downstream business, where we have expensed nearly 900 million in turnaround costs over the last six quarters. With our full network up and running, and our major maintenance behind us, we have a clear runway to demonstrate the capability of the refining network through the rest of the year, and into the second half of 2026. So I'm now gonna turn it over to Kim to walk us through our financial results. Thanks,

John, and good morning, everyone. In the second quarter, we generated 2.1 billion of operating margin and approximately 1.5 billion of adjusted funds flow. Operating margin in the upstream was approximately 2.1 billion. Relative to last quarter, benchmark oil prices were lower, and the Canadian dollar strengthened. This was partially offset by the WCS differential narrowing by more than $2 a barrel in the quarter. Oil sands non-fuel operating costs of 10.73 per barrel increased quarter over quarter due to turnaround activities and lower volumes in the second quarter. We expect operating costs to come down in the second half of the year and into next year as we return for maintenance and begin to bring on additional volumes from our growth projects. In the downstream, we generated an operating margin shortfall of 71 million. Excluding 50 million of inventory holding losses and 239 million of turnaround expenses, operating margin in the downstream was about 220 million in the quarter. In the Canadian refining business, operating costs of 10.63 per barrel decreased by about 20 cents a barrel from the first quarter, coming in below our full year guidance range for the second consecutive quarter. In the US refining business, per unit operating costs of 10.52 per barrel decreased by about $1.60 per barrel from the first quarter and over a dollar barrel relative to the same quarter last year. We continue to make progress in driving down costs in our operated refineries as we increase reliability and structurally remove costs across our network. Capital investment of 1.2 billion included sustaining activity across the business as well as growth and optimization capital in the oil sense where we advanced our key projects and in the Atlantic region with the progression of the West White Rose project. At the end of the second quarter, our net debt was approximately $4.9 billion, a reduction of about 150 million from 5.1 billion at the end of the first quarter. In addition to reducing our debt, we returned $819 million to shareholders through dividends, share buybacks and the redemption of $150 million of preferred shares. We purchased approximately 300 million worth of shares through our NCIB in the quarter or about 17 million shares at an average price of about 17.50 per share. Non-cash working capital decreased by 923 million in the quarter, a significant contributor to our ability to continue to return cash to shareholders while further reducing our debt. We will continue to steward net debt towards our $4 billion target while remaining active with our NCIB. With the value we see in our shares today and with our growth projects on track to start up in the coming quarters, we continue to see a significant opportunity to increase our returns to shareholders going forward through share repurchases. To this end, the company purchased another $129 million worth of shares subsequent to the end of the quarter through July 28th or about 6.6 million shares. With that, I'll now turn the call back to John

for some closing remarks. Great, and thank you, Cam. So as I touched on before, we had a terrific quarter and have successfully delivered on a number of key initiatives. We completed the turnarounds at Foster Creek, Sunrise and Toledo, well ahead of schedule and under budget. We achieved first oil at Narrows Lake and are now bringing on new production from some of the best quality resource in the basin. We have begun hookup and commissioning of the West White Rose Project ahead of schedule after successfully completing critical work to make the concrete gravity structure with the top sides in July. And we've tied in four new steam generators at Foster Creek that brings us one step closer to completing the optimization project and adding over 30,000 barrels a day of production at Foster Creek. Our growth projects are approaching completion. Our major maintenance activities for the year are largely behind us, and we are focused on driving value from our operations. This is a pivotal moment for the company as we execute on our plan to deliver higher production and lower capital into 2026 and increase free funds flow. We have a clear view on the work in front of us to remain focused on creating long-term value for our shareholders. And with that, we're happy to answer any of your questions.

Thank you. If you have a question at this time, please press the star one one on your touchtone telephone. We ask that you please limit yourself to one question and one follow-up. One moment for questions. Our first question will come from the line of Meno Holeshov from TD Kallen. Your line is open.

Good morning, everyone. Good morning, John. I'll start with a question on US downstream and with the understanding that you don't disclose utilization by refinery. And you did touch on this to some degree in your opening remarks, but can we just get a rundown on the status of your pad two operated refineries? And given that the little bit of downstream turnaround activity that was planned for Q3 looks to have been pushed to Q4, how would you frame the bookends for Q3 utilization in market capture?

Yeah, so the way I would frame it is, we've always talked about being competitive in the downstream and we've defined that as kind of a Q1, Q2 cutoff point and we measure it using Solomon. So what we're driving towards is kind of that 98% availability right across the refining network that we have in the US. Today, all those refineries are kind of wide open. We're out of turnaround at Toledo. Everything is operating as we would expect it to and we expect to see that through the third quarter. I think we have some scheduled maintenance is relatively small at Toledo when we think that's probably the confusion you have with additional turnaround work. But as in any refinery, you have regular scheduled maintenance that you undertake during the course of time. But if I kind of look out from now, the only big turnaround we have happens in 2026 at Lima and that looks like that's gonna be in the back half of the year, Q3, Q4, and then 2027 at Toledo. So we are through this major maintenance cycle that we've been in over the last six quarters and we're really looking forward to seeing what we can do over the next

12 months and then more broadly with much less maintenance going forward through 26, 27.

Terrific. Thanks for that, John. And then maybe just flipping over to Rush Lake. It's good to hear that you've already developed a plan to restart the well and I'm not gonna ask for background on the root cause because I know there's an ongoing investigation. But given that it looks to have been a case in failure on an injection well, can we assume there's minimal risk to Rush Lake design capacity and operating protocols and are there any re-trues at all for your other Lloyd projects? Thank you.

Yeah, I think out of an abundance of caution and conservatism, we've removed Rush Lake production for the rest of this year. So you're quite right. We're just finishing our root cause analysis and the investigation right now. We're confident that this is a casing failure on one well. And as I said in my call notes, we've got control of the site. We're moving to sort of the recovery phase of this where we'll work with the regulator and convince ourselves that we've got a good safe startup plan for this. But both two things need to come together and we need to finish the investigation. But suffice it to say, we're in the recovery portion of this incident.

That's great. Great to hear. Thanks again. I'll turn it back.

Thanks, Manil.

Thank you. One moment for our next question. Our next question will come from Dennis Fong from CIBCWM. Your line is open.

Hi, good morning. And thanks for taking my questions. I guess first off, congrats on a really strong quarter. My first question here is just around next steps for some of these up and coming projects or ones that you're working on next. I know you've highlighted Sunrise, Lloyd Thermal and conventional Lloyd Heavy Oil, including multi-laps as kind of potential next projects. Can you discuss around sizing of capex and how you would think about the cadence of growth as well as cadence of spending over the next few years as you kind of look towards these projects as well as kind of how do you maybe right size them given obviously the volatile commodity price environment we're sitting in?

Yeah, so as we've kind of signaled to the market, we're really coming to the end of an investment cycle that we've had in this business that started in 23 and really concludes this year. So we've been pretty clear that 2026 capital will be much reduced from where we were in 23, 24 and 25. And we've kind of used kind of a low 4 billion as a good marker for you to build into your models. You know, one of the things that we think about as it relates to some of the shorter cycle assets that we've got, and I guess in particular as it relates to Lloyd Minster, is we just feel like we've got some real tremendous structural advantages there and that we own a huge block of land. It's full of oil. We own all the infrastructure. We've got all the pipelines and then we have a lot of the royalty rights there as well. So as with any investment, we kind of right size it and we make sure that it returns capital and return on capital at $45. And then we kind of think about what's the right pacing and staging to use in terms of how big that investment needs to be. So we think about all kinds of things like can we do this efficiently? Do we have the drilling location sized and set up and ready to go and that pacing and staging? So I think, you know, when you think about 2026, it might be somewhere around the 150 to 200 million range that we would put into that cold heavy oil business and Lloyd and that kind of supports, you know, growth in the kind of 10% range

as we move towards 40,000 barrels a day. But,

you know, like any investment,

it's got to make money at 45 bucks.

Great, thanks, John. Really appreciate that color. My second question here and maybe a bit of a follow on to Menno's first question and frankly not to belabor a focus on the US downstream. Now that you've completed major maintenance on Toledo and obviously Lima last year, can you talk towards what maybe your team saw or changed during those turnarounds? That provides you and the teams with incremental confidence around kind of this runway for stronger operations going forward.

Yeah, so we've now had a chance to get inside every asset except for Superior, which we rebuilt and restarted in 2020, 324. But in Superior for, sorry, in Toledo, we had a chance to take the east side of the plant down. You know, the big units and the big moneymaking units that we had a chance to get into for the first time were the Isocracker, the crude unit, the reformer. Got inside the sulfur systems, the vac tower, the small cokers, the hydrogen plants and the flare. So those are pretty significant assets. So when we got inside them, you know, we didn't find a significant amount of fond work, which is always a good thing. But the improvements that you make on that and getting everything clean, dusted and gives you a much better confidence that you can continue to run those kinds of assets, the reliability rates that we're looking for. So we were pleasantly surprised in the turnaround by what we didn't find. And we look forward to a good clean run in Toledo.

Great,

thanks, Sean. I'll turn it back. Great, thanks, Dennis.

One moment for our next question. Our next question will come from the line of Greg Pardee from RBC Capital Markets. Your line is open.

Yeah, thanks, Finn. And thanks for the run, Daniel. I mean, good question so far. John, maybe just to switch into Asia for a minute. You know, Liwan, Indonesia, as I sort of think about those assets, Liwan's not oil price driven. It's a good field, reduces your break even. But just curious how you sort of think about those two assets and how they fit in a portfolio long-term.

You know, the way I think about them, Greg, is we have real competency inside our footprint both in Asia and Indonesia. Now in Indonesia, we're a non-operated party with 40%. In the South China Sea, we operate the deep water. But I think as you pointed out, these assets throw out a significant amount of free cash flow. So it's fixed price gas, plus we get liquids. You know, we produce that gas where we get about a $12 realization for it. We produce the gas for about a buck. It's got very minimal capital requirements, sustaining capital requirements. And you know, the fiscal terms are actually quite good in terms of royalties and taxes. So our strategic event on those has really been to operate well and harvest cash from them. And I think, as you know, they kind of generate about a billion dollars of free cash flow every year. And our goal there is really to try and extend the contractual terms around the gas sales and get as much free cash flow as we can out of those assets going forward. So it's kind of a harvest strategy today with an idea that we've got some contractual optimization to do through time.

Okay, makes complete sense. And just a quick one for Cam. I mean, you know, the working capital tailwind was huge in the quarter. Should we expect much of that to reverse in 3Q, 4Q? You think?

Hey, Greg, it's Cam. Well, I would say number one, I think working capital is something we're always gonna be focused on, making sure we minimize it to the best we can. I think the tailwinds you saw in the second quarter, you know, a big chunk of it was driven by just the price movement we saw in the quarter. So there's probably about a four or $500 million impact on working capital release we had as it relates to commodity price changes on our inventory balances. And then the second piece I would say is there was some tax refunds that we were expecting that we were able to bring in the door through the second quarter that amounted to a couple hundred million dollars. So, you know, I think the goal for us is to try to minimize any builds in working capital. I think obviously timing of production to sales, those types of things will always move around quarter to quarter, but I think the goal is to try to, try to maintain and minimize and keep working capital as low as possible. So I wouldn't expect, you're gonna continue to see fluctuations because of commodity prices, but I think we're gonna try to minimize that as much as we can. And I think obviously this quarter, that release really helped us not just de-leverage, but also continue on a fairly robust shareholder return program through the quarter.

Okay, very good, thanks. Thank you both.

Thanks, Greg.

Thank you. One moment for our next question. Our next question will come from the line of Neil Mehta from Goldman Sachs. Your line is open.

Yeah, good morning. Good morning, John's team. Morning now. Morning, sir. Now you've been always very transparent about your perspective around M&A and have a long history of doing really good M&A, including the Husky deal. And certainly that's been a lot of the investor focus and attention around a certain asset. Just your perspective on whatever you can say, whatever comments you would make about M&A strategy and how do you think about a potential bolt-on deal?

I don't think anything has changed in the way that we look at M&A. We have a portfolio that we quite like. We don't see any holes inside that portfolio. And as it relates to capital allocation, inorganic and organic opportunities need to compete. So nothing's really changed over the course of our tenure in terms of the way we look at M&A. And Neil, if you're thinking about a particular M&A piece, we're obviously not gonna comment on

that. And we'll just keep our eyes open then. Why don't we turn over to the operations here and talk about West White Rose. The concrete gravity structure is a big deal, getting that on. And just talk about now you're moving into hookup and commissioning, so what are the gating items? And remind us again what that translates to from a free cashflow perspective.

Yeah, so in the last couple of years, starting with your free cashflow question, we've been investing about $800-plus million a year into that project. And that's all gonna kind of flip over and generate about $800 million of free cashflow using kind of a $60 WTI, $63 Brent pricing when we reach full production at 28, 29 timeframe. So it's a huge change in terms of cashflow generation versus cashflow consumption that we're really excited about. You're absolutely right, it's a huge step for us to get this CGS on the seabed floor. And this was done with precision, it was done really, really well. And as I mentioned, my call notes well ahead of schedule. And I'm always amazed at our technical people in this company, whether it's in oil sands or whether it's in the offshore or even in the projects group, what they're able to do. And getting the top sides made it up with the gravity-based structure as seamlessly as we did. And with the precision that's involved was a real feat for this company, a real credit to those people. So if you were kind of looking at critical path now, the piece of commissioning that's on the critical path is getting the top sides welded to the gravity-based structure. It's a huge effort and that will get underway in short order. And we anticipate the entire commissioning and hookup schedule to be about three months. And then prior to the end of the year, we will start drilling our first well at the West White Rose Project with the first oil expected in early Q2, 2026.

Thanks, John, good luck with that important. Thank you.

One moment for our next question. Our next question will come from Patrick O'Rourke from ATB Capital Markets. Your line is open.

Morning, Patrick. Hey, guys, good morning. Just looking here, you're able to improve the outlook for the operating costs in the Canadian downstream unit with this update to guidance here. I'm wondering what the key drivers are here. Is it utilization? Is it reliability enhancement and margin capture? Or how much of that really came down to lower than anticipated gas prices in the Western Canadian sedimentary basin?

Yeah, it's all of the above, Patrick. Anytime you're trying to take costs out of a refining business and get your unit cost down, obviously you're looking at the denominator as well as the numerator, the equation, and getting good production on the top line is a big help. And when we ran those, the upgrade or in the refinery at the levels we did, you're gonna see a consequence on your unit costs on the output of that equation. One thing is I'd tell you, is I think Eric and his team, and I couldn't be more proud of these guys, not just in Lloyd Minster, but also in our operated refineries in pad two, have been grinding out costs over the last number of quarters and they're kind of getting after this in a very tactical and in a very meaningful way. And what we've seen over the quarters is a continued reduction in not just the absolute spend, but as you get that better reliability and you're not spending as much on maintenance and you're getting the volumes that come through, it shows up in the numerator and the denominator of that equation. But this is really blocking and tackling, and this is getting under the covers of the business, operating in a very deliberate and tactical way. And we think we've got more to come. So we're on a journey as it relates to unit costs and these guys have been on it and they continue to stay on it, driving that kind of performance. As it relates to energy, and in particular in Lloyd Minster, there's no doubt, we benefit from reduced gas costs and reduced electricity prices. But the same principles apply. You're still trying to minimize the amount of gas you use and minimize the amount of electricity you use and use it as well as possible. So all I would say is this is really blocking and tackling 101 and Eric and his team have been all over this for some time and we're seeing the results now.

Okay, and then I was gonna ask about West White Roads, but I thought that was pretty comprehensive there. So I'm just gonna switch back to the US downstream and maybe this relates to my last question. How low do you think you could get the operating costs there? If you could quantify the opportunity on a per unit basis and then what's really, when you think about the driver of incremental margin there between market capture, lower costs, product slate optimization, what's really gonna be the biggest driver of margin as we roll into the next 12 months where you don't have the same level of major turnaround activity that you've had through this

quarter? So there's always three drivers of margin in a refinery. One is you gotta get the crude slate right and I think we do a pretty good job of that. Now, differentials have been very tight as differentials or if differentials widen, we would capture more of that in our downstream and that's kind of a -to-one relationship in the UpGrader and at Toledo and Superior in particular, we do have a pretty high diet of heavy oil. So as the differentials widen, you'll see margin capture in those three assets in particular, those four, if you include the Lloyd refinery increase. We have a lot of work we're doing on the product side. So product placement is another area where you can drive additional value and additional margin capture and we've opened up the dock at Toledo. We think that's a very strategic asset. We continue to increase our terminal positions, not just in pad two, but we opened asphalt refinery in pad four recently. That was part of our disclosure in a prior call and we worked that piece of it every day. So the commercial piece of the business works on it. As it relates to unit costs, we've been pretty clear that we're not competitive on unit costs and we need to get our unit costs down through time. We're gonna do this in a smart way. We're not going to jeopardize reliability or safety to get there, but the trajectory that you've kind of seen that business on, I would expect it to continue through time. But we think there's probably another $2 per barrel that we can get out of our US refining assets through time. But that's gonna be, a journey is gonna be something that we're gonna be very deliberate about. And as I said before, we're not gonna compromise reliability and safety, which are always kind of job one in running a

refineries.

Okay,

thank you very much.

Thanks Patrick. Thank you. One moment for our next question. Our next question will come from the line of Manav Gupta from UBS. Your line is open.

Good morning guys. I just wanted to understand this a little better. You were down for about a week because of the fire and then you probably took a week to ramp back up. And so just trying to understand the opportunity barrel that was lost. So if these fires would not have happened at all, what would be a good number in terms of the volume that would be higher for the quarter versus when, if because of these fires?

Yeah, so on Christine, I think that's the asset you're talking about. We were down for about four days and then we ramped up to full production over the coming week. So about 11 days in total to go from a standing start to 250,000 barrels a day. I think adding up the barrels that we lost, it's about 2 million barrels. So if that were the number that you were gonna use as the kind of LPO or lost profit opportunity, I think that would be a good number to put in your model.

2 million barrels, thank you. That's exactly what I was looking for. And my second question to you was, you generally have a informed view on the differential, especially on the heavy side. So multiple things going on here, opaque raising some volumes, then Chevron getting to drill back, but then very high US utilization and desire for heavy barrels. So like, what's your outlook for the heavy light differential into the year end?

Well, Jeff Murray gets paid to provide insights on these kinds of questions. Maybe I'll turn it over to him.

Sure thing, John. Manav, there's sort of two parts to that. There'd be what is the differential in Alberta and what is the differential in the US Gulf Coast? And I think you were referencing a lot of global things that impact that US Gulf Coast differential. We've seen that be quite narrow compared to history, sort of a minus two, minus three to WTI. And that's been obviously appropriate for where things have been. Looking forward, I think the question you need to ask yourself an answer is, if there is increased OPEC plus production, when does that come and how much is it? Because much of that volume would be medium sour, which tends to have an impact on the diff in the Gulf. I wouldn't see that going anywhere further past what is more a normal long run average of, maybe $2 wider, minus three, minus four, minus five. That tends to percolate back into Alberta. And then I would say on Alberta, it's the same thing I probably said the last couple of quarters, TMX is here and TMX is working and TMX is doing what it's supposed to do, which is to maintain the Alberta differential quite tight to the Gulf Coast. And I think we would see that persist definitely through the fourth quarter.

Thank you so much.

Thanks, Manav. Thank you. At this time, we have no questions in the queue. So we will wait a minute to give you the chance to connect with us if you do have a question. I would like to remind you that if you are on the phone and wish to ask a question, please press star one one. One moment for any questions. Our next question comes from the line of Emma Graney from The Globe and Mail. Your line is open.

Yeah, good day, guys. Thanks for taking my question. I'm just curious to get your take on the new policy environment that we're seeing from Ottawa, Bill C5 and that kind of thing. And where you think this might set Canada going forward, particularly with some other opportunities.

Okay, well, thanks for your question, Emma. I'm gonna turn this over to Jeff Lawson to give you an answer.

Hey Emma, thanks for calling in. How's your day? Pretty

good,

mate. Good. I'll give you a bit of an answer. I think the federal liberal government has been the most constructive with us and our industry than we've seen in the course of the past decade. So they're out here often, they're visiting and they're really trying to make an effort, I think to improve the Canadian economy. So, bills are bringing in a major projects. I think they're well-intentioned. They've got a lot of work to do with industry and with the provinces to get things done. And what we say is perfectly consistent. We love the notion of new projects and strengthening the Canadian economy. At the same time, we need to take a step back and say, what's precluding us from proceeding with these things? And really, there's a lot of regulatory hurdles. So there's a lot of talk about an energy corridor, a new pipe to the coast. Yet we still have a tanker ban, an emissions cap, methane regulations, an industrial carbon tax that isn't competitive with other jurisdictions. So those are things we need to see, we think, change for major projects to occur. And I say the good thing is that the governments are all engaging on those discussions and being thoughtful about what we're putting forth to them. So I'm cautiously optimistic we're moving in the right direction, but we've got a ways to go.

Great, thank you for that. The other thing I was gonna ask is basically, when you come to that policy kind of change, I know you don't wanna weigh in on M&A and Meg specifically, but I'm curious whether this broader policy change kind of shifts anything in the energy environment and infrastructure environment when it comes to mergers and acquisitions.

I think it shifts everything positively. I think just going back over the past decade, we've seen a flight of foreign direct investment in this country and all sectors because we have uncertainty of regulation, we have burdens of regulations, there are long timeframes to get projects done which are not competitive with other places. So if we become more competitive, we'll become more attractive to foreign capital, we'll see higher valuations in various industries in different companies, and we'll be more inclined to pursue organic and inorganic growth. So we'll have the funding to pursue organic growth and we'll also have the funding and backing, everyone will, to pursue more M&A initiatives instead of simply returning capital to shareholders. So I think it's a virtuous circle and it would drive more M&A.

Thank you. There are no further questions registered at this time. I would now like to turn the meeting over to Mr. John McKenzie.

Great, and thanks everybody for their questions today and for those of you online. We absolutely appreciate your interest in the company and please enjoy a great day.

Thank you. This concludes today's program. You may all disconnect. Thank you for participating in today's conference and have a great day.