Thank you, operator, and welcome everyone to Cenovus’ 2021 fourth quarter and year end results conference call. I will refer you 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 will 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, and if you could please keep to one question with a maximum of one follow-up, you can rejoin the queue for any other questions. Alex, please go ahead.

Thanks, Sherry, and good morning, everybody. Before we get to our operating and financial results, I thought I would update you on our ongoing response to COVID-19.

We’re closely monitoring the Omicron variant and maintaining safe and reliable operations at all of our field sites. And I’d say over the last two years, we’ve learned a lot about how to maintain the health and safety of our people and communities and to ensure business continuity.

We have robust protocols in place and adjust them as needed. The pandemic underscores for me how foundational safety is to the way we operate, and how focused we must be on continuous improvement in our performance.

Meanwhile, the natural disasters in British Columbia this year presented an example of how our teams work together to not only ensure business continuity, but also meet the needs of the local community. It was a challenging year for British Columbia with widespread forest fires followed by severe flooding, which caused significant interruption to the supply of refined products to impacted areas.

In both situations, our teams work tirelessly to keep this product supply moving safely and our sites and impacted areas operational, where it was safe to do so, in order to continue meeting the needs of the communities and customers we serve. And I think this really reflects the way we do business at Cenovus including how seriously we take our role in the local communities where we operate.

And as we complete our first year as a combined company, we have harmonized our safety programs and are continuing to roll out our Cenovus Operations Integrity Management System outlining how we manage health, safety, operational integrity, and environmental risk. Despite the challenges related to the integration and COVID-19, we have had solid overall health and safety performance in 2021.

The year was not without recordable injuries, though, and this further underscores how focused we must be on continuous improvement in our top tier safety journey. Above all, our focus is doing everything possible to make sure everyone goes home safe every day.

Turning now to our fourth quarter and annual results, our first year as a combined company has been a really good one for Cenovus. We accomplished everything we set out to do in 2021 and more.

That’s not to say that there weren’t a few bumps along the way but when I look what we’ve accomplished overall this year, I really want to commend our employees and leadership team on a job very well done. I’ll start with the Upstream segment, we continue to deliver very strong Upstream operating performance.

Our total production was 825,000 BOE per day in the fourth quarter, an increase of 20,000 BOE per day, over the third quarter. Despite experiencing some extremely cold weather in Alberta and Saskatchewan in December, the production increase was led by record quarterly average production rates at our three largest oil sands assets, Foster Creek, Christina Lake and the Lloydminster thermals.

Foster Creek production for the fourth quarter was nearly 212,000 barrels per day, an increase of about 25,000 barrels per day over the third quarter. We spoke in our last quarterly call and at our Investor Day about the performance of the new well pads at the west arm of the reservoir and these pads continued to deliver some of the highest rates we’ve ever seen at Cenovus.

Production guidance for Foster in 2022 is in the range of 185,000 to 205,000 barrels per day, which includes the impact of a planned turnaround in the year. Production at Christina averaged 251,000 barrels per day in the quarter reflecting additional production volumes from redevelopment and re-drill wells that we spoke to about at our Investor Day.

Production guidance for Christina in 2022 is in the range of 230,000 to 250,000 barrels per day, which also includes the impact of a planned turnaround later this year. And at the Lloyd thermals, we continue to see the benefits of applying Cenovus’ operating techniques.

These assets have delivered an average of nearly 100,000 barrels per day in the quarter. Our realized pricing across the oil sands segment reflected the volatility in WTI and WCS prices that we saw between October and November.

Results also reflected higher condensate pricing and our normal additional seasonal blending requirements for diluent in the winter months. In addition, an increase in natural gas prices contributed to higher oil sands operating costs quarter-over-quarter to about $11.76 per barrel.

Turning to conventional, as a result of higher commodity prices and reliable operations, the conventional business delivered nearly $260 million of operating margin in the fourth quarter. Production was about 5% lower than the third quarter due to asset sales, but unit operating costs still held relatively flat with the third quarter.

Our offshore operations continue to be a strong contributor to our business, delivering operating margin of over 400 million in the quarter and contributing over 1.4 billion of operating margin in 2021. Asia Pac operations continued performing well with daily production of over 62,000 BOE per day in the fourth quarter, which was slightly above the previous quarter.

However, we saw increased realized prices and FX. We continue to see strong gas demand in Asia and as we said at our Investor Day, we continue to explore with our partners opportunities to add additional value there.

In Indonesia, a production sharing contract was signed for the Liman contract region in East Java and in December we drilled the development well in the MBH field, which was completed in January. In the Atlantic, lower production volumes reflected some turnaround activity in the region but we are able to capture a higher net back overall, as the business realized the benefit of strong Brent pricing.

So moving to the downstream business; in the US manufacturing segment, refinery utilization averaged 72% in the quarter. This reflects the impacts of a planned turnaround at the Lima Refinery.

The Lima turnaround was a major one in every five year event, involving planned outages at the crude unit and the cat cracker units, with a total cost of around $145 million. Following the turnaround, we encountered some challenges with secondary processing units, which impacted run rates beyond the initial six to eight week planned timeline extending through December and into January.

Due to the reduced rates, turnaround-related expenses and repairs associated with the outage, unit operating costs for US manufacturing in the fourth quarter increased to 1688 per barrel. We also expect throughput and operating expenses in the first quarter to be modestly impacted due to the continued reduced throughputs in January.

The repairs of Lima are now complete and I’m pleased to report that operations are back to normal. The operations team is confident that this was one-time issue and has been resolved.

In the Canadian manufacturing segment, we continue to see very steady and reliable operating performance at the Lloyd upgrader and asphalt refinery with an average utilization of 98% in the fourth quarter. This finished out a strong performance year for the Lloyd complex with 96% average utilization for the full year.

Fourth quarter utilization and unit refining margins in this segment were similar to the third quarter generating an operating margin of $131 million, reflecting the strong reliability of these assets, as well as capture of wider price differentials at the upgrader. For those of you who joined us at Investor day in December, you know we’ve announced ambitious targets for our five environmental, social, and governance focus areas.

These are all available on our website, however I wanted to remind you of a couple this morning. We are committed to spending at least $1.2 billion with indigenous businesses between 2019 and year end 2025.

Working with indigenous business partners has always been an important part of our approach to supporting indigenous reconciliation. And as part of our efforts to address climate change and greenhouse gas emissions, we have set a target to reduce our absolute scope 1 and 2 emissions by 35% by year 2035 from 2019 levels.

We’re also maintaining our ambition of net zero emissions from our operations by 2050, which includes our work with the oil sands pathways to net zero initiative. Turning now to our financial results; in the fourth quarter, we generated cash flow from operating activities of nearly 2.2 billion, adjusted funds flow close to 2 billion scope and free funds flow of more than 1.1 billion.

Capital spending was $835 million in the quarter, which placed us well within our guidance range for the full year. We recorded a $1.9 billion impairment in the US manufacturing segment this quarter.

The impairment related to the carrying value of our assets in US refining and changes in current independently derived commodity price outlooks, specifically around crack spreads, RINs, and the WCS differential. We also booked a reversal of prior impairments in Q4 related to our conventional business.

This does not reflect any change in the way we think about the downstream business. We continue to see long-term value in our integrated model and to reduce cash flow volatility that comes with a more diverse portfolio of upstream and downstream assets.

On the corporate side, we saw an increase in our general and administrative expenses in the fourth quarter, which impacted adjusted funds flow. This mainly related to a non-cash accrual for a synergy incentive plan that was implemented at the time of the Husky transaction.

This one-time incentive program was clearly very, very effective in motivating our employees to pursue those synergies for our shareholders. We generated $7.2 billion in adjusted funds flow and free funds flow of nearly 4.7 billion in 2021, with total capital for the year coming in at about 2.6 billion.

These results really speak to the free funds flow generating ability of the company, especially when you consider that free funds flow reflected one-time costs associated with the Husky transaction and capital for the superior refinery rebuild, on which we’re still collecting related insurance proceeds in 2022. This financial performance including asset sale proceeds received in the fourth quarter enabled us to reduce our net debt by another 1.4 billion over the quarter, closing 2021 with net debt below 9.6 billion.

That’s a reduction of 3.5 billion since January 1, 2021. In the fourth quarter, we also announced the sale of Wembley assets in the Conventional business, the Tucker oil sands project and the disposition of two-thirds of our retail stations.

The three transactions together represent additional proceeds of nearly 1.5 billion. Tucker closed in January and Wembley is also expected to close in Q1.

Retail is still expected to close in mid-2022. I’ll also take this opportunity to provide an update on our NCIB program, which we announced in the fourth quarter and began executing in November.

As of February 7, we have repurchased approximately 26 million shares at a weighted average price of $16.31 per share. Looking back over the past year, we’ve created a better and more resilient Cenovus.

We’ve delivered on everything we’ve set out to do, including successful integration of the Husky business delivering over and above our targets for upstream operations, Canadian downstream, transaction synergies, asset sales, net debt reduction, and increasing shareholder returns. Now, assuming commodity prices continue to hold, we will rapidly hit our net debt target of 8 billion, implying we could be looking at even more free funds flow to allocate in 2022.

I assure you, we will continue the capital discipline you’ve come to expect from us. And above all, opportunities for adding value for our shareholders and increasing shareholder returns will be top of mind for this management team.

So with that, we’re happy to take your questions.

Yeah, thanks. Good morning.

Thanks for the rundown, Alex. So maybe just to extend from what you’d said on -- that was really my first question, you’re going to be sub-8 billion, looks like -- it doesn’t sound like there’s a lot of appetite for increasing organic investment in the ground and so forth.

Can you just shed any light as to the options maybe that you’d have from a shareholder return perspective? And would those be highest priority right now in terms of things on your to-do list?

Yeah, no. Thanks for the question, Greg.

I mean, I think what we said and you’ll recall, at our Investor Day, I think we made very, very clearly, that as we delivered the balance sheet, we were going to increasingly look at allocating cash to returning to our shareholders. You’ve seen that.

We got off, I think, to a quite a decent start with our NCIB. You’ve seen us double the dividend and here we are rapidly heading towards and below a billion in net debt.

And I think what I would say is, we are very, very focused on the importance and the urgency of returning more value to our shareholders. We’re in -- frankly, we’re delivering it at a pace probably quicker than anyone here even thought about.

And we have a little bit of work to do, as a management team, as a Board, but I think that our shareholders can expect that in fairly short order, we will be coming back to our shareholders with an updated plan on how we’re going to continue to return and increase our returns to shareholders. So I think I’d say just bear with us, we’re very live to the issue, we just need to do a little bit of work to come back with a plan that we can announce to our shareholders.

Okay, thanks for that. And really just the second question, it is probably more for Jon.

But what, what should we expect from your US refining ops? And I’m not thinking so much about cash flow generation, but just perhaps utilization or steps taken to improve reliability or performance or what have you -- anywhere you want to go on that would be fine.

Thanks, Greg. I’ll make a few comments and then I’ll let Keith chime in.

The first comment I’d make is US refining is absolutely core to our strategy of the company and during the quarter we did execute a 45-day turnaround in Lima. The actual execution of the turnaround was quite good.

The total cost, as Alex mentioned, was about $145 million. We did struggle with the isocracker and the reformer coming out of that turnaround but then Lima refinery is now up to normal rates of operation.

We expect it to run through 2022 at normal rates of operation. What we have seen in the past is utilization has been lower than historic due to largely commercial reasons, so as the cracks continue to justify, we will continue to take those rates of utilization up.

I would mention we do have another major turnaround in 2022 at Toledo and that will be executed by our partner at BP. But going forward, you should expect to, I think, see more historic rates of utilization and availability, as we get into a more robust crack market.

I don’t know, Keith, there’s anything else you want to add to that.

No, I think you got it. The Lima turnaround is a once in five year type of event, and that’s now behind us and the refinery is back online.

And, I think just, Greg, in the quarter, obviously, we saw some seasonal weakness in cracks, neck cracks of RINs around $10. And, obviously, gasoline impacted a little bit with Omicron, but we’re expecting kind of that to be transitory and really thinking that gasoline and diesel demand will be really strong, through 2022.

So, even with the turnarounds Jon alluded to, we’re expecting higher throughput in 2022, based on what we’re saying.

Hey, Greg, it’s Alex. I would agree with everything that Jon and Keith said, and I might just put one kind of overarching comment on the US downstream.

As Jon said, at the start, this is an absolutely core part of our business and our integrated strategy. And I think that our investors should expect to see the exact kind of focus that we put on the thermal business in 2021 and the results we’ve delivered there.

Jon and Keith and Norrie are putting that same collective effort into making sure that we deliver that same kind of performance out of the US downstream business. It is an area of very significant focus for us in 2022.

Understood, thanks very much.

No worries.

Hi, good morning, and thank you for taking my questions. The first one here, actually both might be directed more at Jeff.

But as you noted there in your opening comments, Alex, you did take a $1.9 billion impairment charge, just kind of digging into the financials and not wanting this to be a modeling stock question. It looks like the discount rate changed in terms of some of your assumptions but I was hoping that we could get a little bit more detail and color around some of the changes and assumptions as well as the embedded RINs pricing that you’re looking at, going forward, with respect to the impairment charge.

Yeah, Jeff here. Thanks for the question.

I mean, number one, I’ll say this really reflects third-party price lines and where those currently sit in, and that’s really the driver. And as you can see in the upstream, similar to what we’re seeing in the downstream is, it’s really their reflection of the IQRE prices, so we had the reversal.

So number one, it’s a reflection of that, Dennis, and that really drives a lot of evaluation in changes with those third party price lines, number one. And number two is the discount rates will vary and will adjust and look at different pieces depending on structures and of the investments in the refinery.

So, we’ve moved that a little bit between -- for the different investments, but really that reflect -- that’s flexible and a region [phonetic] can always change depending on where market is. But really, it’s a reflection of those third party price points, Dennis.

Okay. Okay, thanks.

And then the second question, maybe it falls a little bit along, but Greg was asking there to begin with. The company has done a really good job in terms of managing term debt maturities, especially with the most recent redemption.

Just in terms of an optimal capital structure, how should we be thinking about that just given the amount of free cash flow that you’re generating? How should we be thinking about the term debts and kind of the structure as well as the maturities as we are going forward?

And is there any ways that you can think about optimizing or improving the cost structure on that side?

Yeah, so it’s Jeff again. Number one, as Alex talked to is, we said we’d be balanced between ten and eight and we’ve reflected that over the last quarter and into this year with the share buybacks dividend and then the [indiscernible] that you’re referred to, they were largely balanced.

I would expect us -- generally, we’ve always talked about holding a cash for up to a billion, I’d expect us to operate more between a billion to 2 billion. And so as we accumulate cash, until we get to 8 billion, we’ll continue to balance shareholder returns and deleveraging.

And, to your point, we’ll look across the maturity profile. We did the [indiscernible].

We want to maximize our deleveraging but we’ll look up and down the curve and as we did in Q3 last year, if there’s opportunities where we can see to optimize the cost and the term, we’ll look at that and balance it all out. So it really is market dependent.

Great. Thank you for the color.

Thanks, Dennis.

Yes. Hi.

Good morning. First question, just as I’m thinking about the first quarter, some of your peers have talked about some working capital headwinds.

I didn’t know if there was any -- I know you had some tailwinds in the fourth quarter, I didn’t know if there are any things we should be thinking about there in a rising oil price environment, because absent that, it would seem like you could potentially hit that target of 8 billion in the first quarter. So just any thoughts you’d have on either of those comments?

Hi, Phil. It’s Jon speaking.

I think one of the things that we did a really good job of in Q4 is managing working capital, and you would have noticed there was about a $300 million working capital release. And that being said, one of the things that we did see in December in particular was some pretty weak pricing, both WTI as well as the WTI, WCS spread and so we did take an opportunity to build some inventory and not sell in December, and some of those sales will be reflected in January and February of this year.

So we don’t necessarily see any working capital impediments or headwinds going forward. We think it’s something that I think we managed through Q4, and you’ll see us continue to manage through Q1.

We did put some barrels into cap line in Q4 and that’s all reflected in the number. But, overall, we did see that working capital release and we are expecting to sell some of that production that we stored in Q4 and Q1.

Got it. And anything on the broader view at these spot prices of the ability to be below the 8 billion target by the end of 1Q.

So you’re asking me to get pretty digital about when we’re going to get -- what I’ll tell you, Phil, is the thing that’s going to happen in Q1 is we are going to get some proceeds from those two asset sales that Alex mentioned, both Wembley and Tucker, which is now closed, and those are material in nature. So, we are rapidly moving towards 8 billion.

I’m not -- I don’t have actual date as to when we’re going to get there but we are rapidly converging on $8 billion of net debt.

Okay. Fair enough for that.

Thank you. And then just one follow-up, obviously, ConocoPhillips was pretty clear on their earnings call, that they intend to sell down their full stack by the end of the first quarter.

And so just in terms of managing that, is there anything Cenovus is thinking about or is that more of the shareholders, we’d have to be buying the stock, and you just kind of buy it back in the open market or any update there and then hopefully, it is in the review soon.

Yeah, I mean, I -- it’s Alex, Phil. And I think first off my observation is that our NCIB program, I think, has been a reasonably effective offset to Conoco’s action selling down their block.

I mean, at this point, you guys have heard me say this so many times that it sounds pretty rote but we’re always happy to work with them, we haven’t really found any opportunities to a coordinate and it’s made a little bit difficult by the rules, but as long as the pricing works for us with our NCIB program, we think that that remains a pretty effective offset to their sell down. Into your point, there’s some comfort that it appears that it’s going to be coming to the end here pretty quickly.

Right, okay. Fair enough.

Thank you.

Yep, no worries.

Good morning team. I wanted to spend some time on risk management.

And maybe there’s a question for Jon or Jeff, but just talk about your philosophy around inventory management and risk management and hedging. It was a big number in the fourth quarter, is that something that as we think about Q1 with oil prices having picked up, you would think would sequentially move higher.

So just talk about the philosophy around that, in general, and any quantification you can provide at the forward curve would be terrific too?

Sure. So, what we have Neil, are really two programs that are alive within the company and both of them are short term.

But what we built in this company is an integrated oil producer, where we are moving our barrels out of Western Canada and into our refining network in pad two as well as to market more broadly, through the pipeline access that we’ve got it and that was always a core consideration how we built our strategy. We didn’t want to be in a world where we were forced to sell our barrels at a discount in hardest day.

And market access is something we’ve talked about at length over the last four years, and something that we’ve achieved through time and more particularly with the Husky acquisition. So if you think about this company, we carry, typically around 45 million barrels of inventory through month end, and what we will do is we will hedge around 40% of those barrels from month to month, so that if we have a precipitous decline in the WTI price, about 40% of that inventory is hedged.

In a rising price environment, you’re going to see those barrels, they will become less valuable and will lose money. In a falling price environment, you get exactly the opposite effect, but net-net, over the term of the cycle, you would expect that to be revenue neutral through time.

We’ve just gone through a period where we’ve had seven consecutive quarters of rising prices. So that’s program one.

Program two is another program we run where we take our WCS exposure and we align the pricing windows between WTI and the WTI, WCS differential, so that we don’t have a pricing exposure, where we set the differential in one month, and then the WTI price in the following month. So we bring those together and collapse them and we do that on about 60% of our exposure.

So again, because we’re bringing the WTI price forward in a rising price environment, that program will lose money in a low -- in a declining pricing environment, it will make money. But net-net, over the cycle, it’ll be revenue neutral or better.

And those are the two things that we do.

And then Jon, can you help the Street calibrate using the forward curve what those hedging impacts could look like, as we think about 2022?

Well, it depends on where the price of WTI goes through 2022 but if you’re in a world where you’ve got kind of flat pricing, it should be largely revenue neutral.

Thank you team.

Thanks, Neil.

Hey, guys. I know it might sound like a modeling question, but it’s not actually a modeling question, so bear with me.

Foster Creek in this quarter was at 212,000 and Christina 251,000. Now if you look at the annual guidance, you basically are breaching the upper end of guidance on both those, I think Christine has 250,000 upper end, Foster 205,000.

So when we think about 2022, should we model you now at least at the top end of it, if not over the top end as it relates to these two assets?

Manav, what a thoughtful and insightful question, I ask Norrie this all the time, and Norrie will give you a response.

Hi, Manav. It is Norrie here.

I would suggest we give you a range because there’s ups and downs, as we kind of go through. Our fourth quarter, we had very strong safe performance.

We weren’t impacted by the weather. We continue to have a strong program of activity going forward but I would just guide there is a range and you could use both ends of the range, as we kind of go forward.

We have turnarounds both at Foster Creek and Christina Lake this year and that’s balanced with we have strong inventory, a very low finding and development costs kind of going forward and we will continue to strive to maximize our production.

Okay. The second question, I remember you –

Manav, I am sorry, this is Jon. Manav?

Yes, sir.

Apologies. So maybe I’ll just remind you of two other things as well that Norrie has spoken to.

We do have turnarounds in both Foster and Christina this year and there will be reduced production during those turnaround. So we do intend to take Foster Creek down in the Q2 timeframe and Christina Lake in the Q3 timeframe, but that will impact those production numbers but what we’ve given you in the guidance, I think, is something that’s representative of where we’re going to be.

Perfect. And my quick follow up here is I think at the time you did the deal on Foster and Christina with Conoco, the contingent payment had a timeline.

I think it was five years from the time you did the deal. But can you help us understand at what point will the contingent payments stop, if they would, as it relates to these two assets?

Manav, it is Alex. There is a date circled on my calendar of May of this year and I think that is the -- that is when it rolls off.

17th.

May 17th. Norrie has more granularity than me, May 17th.

17th at 12 o’clock.

So that’s exactly five years because May 17 was the closure of the date of these two assets back in 2017. So basically post 2Q, you do not pay them right, is that the right way to think about it?

Correct.

Thank you. Thank you for taking my questions.

Thanks, Manav.

Hi, it’s question for Alex. Alex, there’s been a fair bit of talk about Trans Mountain pipeline expansion not taking place in 2022 but occurring sometime or at least being completed sometime in 2023 and with a substantially higher price tag.

I guess, what are you hearing and what kind of impact will it have upon Cenovus as a shipper on that expansion?

Hey, Chris. Yeah, I mean, as I think a lot of people are aware, we’re quite a significant shipper on TMX and, as such, we’re in regular contact with the owner and developer and I would say from our perspective, we’re, like, confident that nothing we’re seeing really will make a significant difference for us as a shipper.

And we expect that at any of the range of outcomes that we would model that that toll will still be an attractive toll for getting our production to market.

Can you tell me how many barrels have you committed to the expansion?

Geez, I’m not sure that that’s public, Chris. I think you could just go -- we are one of the largest shippers on TMX, and it is a very meaningful volume.

Just to follow up lastly, we’ve seen a rapid expansion in WCS prices in the last couple of weeks and obviously in oil prices. I’m curious how this is affecting your thoughts or changing your thoughts at all on capital spending in 2022?

Does oil moving towards $100 a barrel or WCS being at $100 a barrel change your perspective at all?

You know Chris, I’m kind of old enough and bear enough scars that I guess when it comes to pricing, I’m always very cautious. We anchor all of this company’s development plans at the bottom of the cycle for oil and gas.

We won’t invest in a project that doesn’t deliver an acceptable return at the bottom of the cycle, which for oil, we would describe as kind of 45 WTI, so although we’re pleased to see these higher prices, it’s just not something we can count on now. That being said we do have quite an active program, both in the oil sands and in our conventional business.

So, we’re going to be employing a lot of service -- a lot of drilling and service rigs, a lot of contractors, just with our basic sustaining capital program.

One final question if I could and that is where -- what is your understanding of where we’re sitting with the tax credit from the federal government on carbon capture sequestration? And have you, I guess, got any response yet on whether EOR is going to be included or not from the federal government?

So, we have been consistently in discussions with the federal government, Chris, and I mean, my goodness now going on probably the better part of a year. And I suspect that the next major milestone in this discussion is probably going to come from the federal government with more details about what their plan on the investment tax credit is going to be in the 2022 budget, which, as I understand, is likely going to be announced in March or April.

But I, obviously, at the end of the day a lot of that work is within the government’s mandate, but I would say we’re working very collaboratively together, and we look forward to hearing from them. We have had discussions about EOR and, I certainly -- when I have the opportunity I certainly like to remind the government that EOR right now is probably the most cost effective way of sequestering CO2 but at this point, we don’t have any guidance as to whether they’re going to consider that.

Thank you.

Thanks, Chris.

Hi, there. You talked about looking to add value in Asia.

Do you see there have been more opportunity for investments there than in Canada at the moment?

Hey, Nia, it’s Alex. You know, look, we have a very good operation in Asia Pacific, we’re quite happy with it.

We have great partners and we have been able over time to continue to add development opportunities, and we continue to have those discussions. So, it’s relatively early days, but I think it’s a business that we see continued opportunities to make some modest investments in a pretty attractive basin.

Okay, thanks. And then, as a follow up, do you expect to allocate any capital funding towards the Oil Sands Pathways alliance this year?

Sorry, you kind of broke up there for a sec. I didn’t get the first part of that.

Do you expect any major capital allocation to the Oil Sands Pathways initiative this year?

I think we’re anticipating very significant capital investment over sort of the eight to ten years out in the future, but I would anticipate most of the work we’re doing right now would be around kind of feasibility studies, engineering, permitting -- work on permitting. So it is a relatively modest capital allocation for the next couple of years, but ramping up, particularly if we’re successful with the federal government in that investment tax credit for carbon capture and sequestration.

As I’m sure you’re aware, we have a foundational project, which is building a carbon trunk line to a carbon sequestration facility in and around the Cold Lake area. And that, if the investment tax credit were to come to pass, you would see the partners certainly ramping up capital over that kind of eight to ten year period.

Okay, thanks. Do you have a rough estimate at this point how much the project would cost?

What sort of numbers are we talking about?

It really depends ultimately on a number of factors, but I think it’s something you could think of kind of being in this in this scale of many single billions of dollars.

Okay, thanks.

Yeah, thank you.

Yes. Hi, thanks for taking my question.

I actually have two of them for you. And the first is about the future of your joint venture with Phillips 66 for the Wood River and Borger Refinery.

On their call, they had said that discussions had been floated about not having the joint venture anymore and they said that their world has changed talking about you. So I was just wondering how your world has changed and what is the future of the joint venture for those two refiners?

And then when I’m done, I have a second question.

Sure, I mean, first off, I would say that that partnership with Phillips has been an excellent partnership, they are a great partner, and they’ve been a great operator of those assets. But I think what has changed is that our strategy, and particularly with the conclusion of the Husky acquisition, I mean, we are really moving towards a strategy of being a fully integrated energy producer all the way from the production through to the refinery gate and in a world like that, you can see a scenario where we definitely, ultimately long term view our strategy as being an operator of refineries.

And if we can, when we’re involved in refineries that are great refineries, we’d love to have 100% of it, all things being equal. So I don’t think -- there’s not an urgency in any way to deal with that partnership but I think the comments from Phillips would align with ours that over time people’s – company’s strategies change and their goals change and this might be a situation where we look to other alternatives.

But there’s no urgency and we certainly don’t have anything to announce, there’s probably a lot of discussion to come on that.

So how would that work out, though, because, for example, like Wood River uses a lot of WCS and I imagine that comes from you. So I mean, how would that work out for you?

I mean, would you take it? Would they take it?

I mean, would you keep some kind of supply arrangement going forward? Have you not thought that far?

No, it’s really hard to speculate. It could be could be any of the above and we really are at really sort of a preliminary stage at having those discussions, so it’s too early to comment.

So do you have any timeline then that you that -- around these discussions where you expect to reach a conclusion?

No, I think these things kind of go at their own pace and I honestly wish I could give you a little more detail but it’s going to take a lot more discussions between the parties before we determine what the outcome is. So it is going to take a bit of time.

I understand. Now here is my second question and you said earlier in this comment that you put barrels into Capline in Q4.

So can you give me any idea how much and if this is -- are you a committed shipper? Have you committed barrels?

And how do you see this playing out for you and getting, I guess, it’d be getting WCS to the Gulf to Louisiana? How do you feel about that?

Yeah, we are committed Capline shipper and we would look at that, as part of an integrated strategy to maximizing the value for our barrels. And obviously the Gulf Coast has generally been a pretty attractive market for the heavy barrels.

So it’s just another route to market that we hope to maximize our net backs.

Okay, great. Thanks so much for your time.

I really appreciate it.

No worries. Thanks very much.

Well, thanks so much, operator and thanks, everybody, once again for your engagement with the company and your time today and we’ll let everyone get back to the rest of their day. Thanks again.

Take care.