Keyera Corp

TSX:KEY

Good morning. My name is Joelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the Keyera 2024 Year-end Conference Call. [Operator Instructions]

I would now like to turn the conference over to Dan Cuthbertson, General Manager of Investor Relations. You may begin.

Thank you, and good morning. Joining me today will be Dean Setoguchi, President and CEO; Eileen Marikar, Senior Vice President and CFO; Jamie Urquhart, Senior Vice President and Chief Commercial Officer; and Jarrod Beztilny, Senior Vice President, Operations and Engineering. We'll begin with some prepared remarks from Dean and Eileen, after which we will open the call to questions.

I'd like to remind our listeners that some of the comments and answers that we will give today relate to future events. These forward-looking statements are given as of today's date and reflect events or outcomes that management currently expects. In addition, we will refer to some non-GAAP financial measures. For additional information on non-GAAP measures and forward-looking statements, please refer to Keyera's public filings available on SEDAR and on our website.

With that, I'll turn the call over to Dean.

Thanks, Dan, and good morning, everyone. Keyera had an outstanding year in 2024. We continue to execute our strategy and deliver value to both our customers and shareholders by leveraging the strength of our integrated value chain. In terms of safety, we were pleased that we had no lost time incidences for the second year in a row. We also set new volume records across many core assets. This led to record margin contribution across all 3 business segments and record annual adjusted EBITDA and net earnings.

We ended the year in a strong financial position, giving us the flexibility to allocate capital in a way that will maximize value for our shareholders. We also raised our dividend by 4% and received approval for a normal course issuer bid. With our guidance in December, we announced a new target of 7% to 8% fee-based EBITDA growth. This growth is mostly driven by filling available capacity where we're already making great progress.

In our North G&P segment, Wapiti and Pipestone hit record annual volumes. In our Liquids Infrastructure segment, KAPS continues to ramp up and attract new customers. At KFS, our fracs delivered record annual margin contributions and our condensate system also set volume records.

Moving on to growth projects, which continue to progress well. We are pleased to announce today the sanctioning of the KFS Frac II debottleneck project. This project will add about 8,000 barrels per day of capacity and is now expected to be in service in mid-2026. The project will generate strong returns on a stand-alone basis. We're also advancing contracting and engineering for KFS Frac III. We expect to sanction this project later this year for it to be on stream in 2028.

For KAPS Zone 4, we have completed engineering and we're working towards securing sufficient contractual backing to move ahead. We decide to proceed, this project is expected to be in service in 2027. Beyond 2027, we continue to progress potential growth opportunities, including expanding Rail and Logistics solutions to accommodate higher spec product volumes. On this front, last week, we announced long-term commercial agreements with AltaGas, which helps support these growth projects. The deal also efficiently extends our value chain, allowing us to expand market access and diversification for our customers.

You would have seen in our release this morning that we'll be taking AEF offline in the spring for approximately 6 weeks to address an unexpected operational issue. This work is necessary to ensure continued safe and reliable operations. The margin impact of this outage is expected to be about $40 million. We continue to expect to deliver our long-term base marketing guidance of $310 million to $350 million this year, and we'll update our annual marketing guidance in May.

I also want to take a moment to address the threat of U.S. tariffs. This is a much needed call to action. Rarely have we seen our federal and provincial governments so aligned on the need to improve Canada's competitiveness and diversify our market access. Ultimately, this could be very positive for Canada, the energy industry and Keyera. For Keyera overall, we don't expect a material impact.

Our Fee-for-Service segments are volume-based and much of the cash flow is under long-term contracts. Within our Marketing segment, we expect tariffs on iso-octane will mostly be offset by lower butane input costs, higher RBOB spreads and beneficial FX movements. While tariffs create some near-term uncertainty, I'm confident in our ability to continue to deliver shareholder value.

With that, I'll turn it over to Eileen to provide a further update on our quarterly and annual financial performance.

Thank you, Dean. Adjusted EBITDA was $313 million in Q4 and a record $1.3 billion for the full year compared to $339 million and $1.2 billion for the same period last year. These results were largely driven by record annual margin contributions from all 3 of our business segments.

Distributable cash flow was $168 million in Q4 and $771 million for the full year compared to $234 million and $855 million for the same period last year. The year-over-year decrease in distributable cash flow is mostly due to higher cash taxes. Net earnings were $89 million for the fourth quarter and a record $487 million for the full year compared to net earnings of $49 million and $424 million for the same periods last year.

In 2024, corporate return on invested capital was 16% and the dividend payout ratio was 61%. We ended the year in a strong financial position with net debt to EBITDA of 2x on a covenant basis. This gives us the flexibility to allocate capital to maximize value for shareholders, either through dividends, growth investments or share buybacks.

Looking forward, our 2025 guidance remains unchanged. Growth capital expenditures are expected to range between $300 million and $330 million. Maintenance capital expenditures are expected to range between $70 million and $90 million. Cash taxes are expected to range between $100 million and $110 million. For the time being, our marketing realized margin guidance will be our long-term base guidance of $310 million to $350 million.

As is our usual practice, we will revise this with our Q1 results in May at the end of the marketing contract season. As a reminder, our marketing cash flows are reinvested into long-life infrastructure projects, in turn, driving growth in high-quality Fee-for-Service cash flows.

I'll now turn it back to Dean.

Thanks, Eileen. We remain confident in the basin's continued volume growth. Canada has one of the largest oil and gas reserves in the world, coupled with a very competitive cost of supply. Our customers are in strong financial positions and have a proven track record of adapting to changing market conditions, supporting further volume growth.

Keyera is an essential enabler of this growth. On behalf of Keyera's Board of Directors and management team, I want to thank our employees, customers, shareholders, indigenous rights holders and other stakeholders for their continued support.

With that, I'll turn it back to the operator for Q&A.

[Operator Instructions]

Your first question comes from Rob Hope with Scotiabank.

Maybe the first question is on the recent AltaGas agreement. Can you maybe speak to the genesis and kind of the background of that agreement and more importantly, the potential that it could be further expanded in the future, just given the synergies between the 2 asset bases?

Rob, thanks for the question. First of all, when we think about our business, we think about how do we make our -- we're a service company and how do we make our customers and our energy -- our industry more competitive. And that's what we should be focusing on. And if we do that, I think as an industry, we have an opportunity to supply the world with more energy.

And so when it comes to accomplishing that, if we can create a more efficient service that's a win-win for our customers and for partners, we're happy to work with other partners to make that happen. So when we think about AltaGas, they have assets that are complementary to our integrated value chain. And so we are very happy to work with Vern and his team to create a win-win. And they're supporting our infrastructure, including our frac, and we'll be moving their barrels to our downstream terminals, use our storage and ultimately, rail a lot of product out to AltaGas' site on the West Coast.

So I think it's a win-win for everybody where we can provide a more efficient integrated service and bring more volumes to our system, but also support AltaGas' system and everybody wins. And we -- and maybe to your second part of your question, I mean, we have a great relationship with AltaGas. And for sure, we want to find opportunities to continue to work together, again, to provide a better service for industry where we can all benefit from.

Jamie, is there anything else you want to add?

No.

All right. I appreciate that. And then maybe just switching over to volumes. It seems like volumes at condensate, KFS were very, very strong. Was this in anticipation of tariffs? Or are we just seeing the base kind of liquids volume growth stronger than we originally expected? And then I guess maybe some commentary on how you think volumes progress through the year and into '26?

Yes. Well, first of all, I mean, when we see basin growth, and we expect to see more basin growth over the next 5, 6 years with, again, Coastal GasLink and TMX, which is probably going to fill up faster than everyone anticipated because of the threat of tariffs. When the basin grows, we help enable that growth. And what that means is more demand for our services and volume to our system. And that's exactly what you're seeing.

So when natural gas volumes grow, it's going to grow in the most economic parts of the basin. And we're situated there, both in the Deep Basin and up in the Montney, Duvernay fairway near Grande Prairie. So we're seeing that increased volume growth and with it, a lot of liquids, and that liquids flows downstream through our pipes and our KAPS pipeline, obviously, is a big service that we provide there to supply our frac business and also to supply condensate, which is used for diluent for the oil sands.

So both parts of our business, our upstream natural gas processing and NGL business and also our oil sand services businesses have been performing very, very well, again, to service the growth that we're seeing in our industry.

Yes. No, the only thing I'd add, Dean, is that I think we have a lot of focus on the North. And obviously, we've got some very key assets in the North, and we're looking to expand our position in the North -- the North G&P, yes, sorry. And -- but also, we've seen some really good activity and a changing of the guard in some transactions that have happened in the last few months in our Central Alberta assets, which we're excited for. And we've got strong relationships with those parties, and we expect to hopefully enable their growth as well as we progress into 2025.

Your next question comes from Maurice Choy with RBC Capital Markets.

Just a follow-up on the AltaGas arrangement, which you characterized as a win-win situation here. I guess my question is about timing. Were there past situations where such an arrangement couldn't happen and why right now is the right time to do such arrangement? And separate to that, are there any other entities that you also see yourself having a win-win arrangement?

Maurice, thanks for the questions. First of all, with AltaGas, we have been exporting product through their terminal at RIPET. And like any service, we probably start smaller to understand how it works, understand the markets, the logistics behind it. And before we jump in, in a bigger way. And that worked out very well, both from -- again, just from a logistics perspective, from a business and relationship perspective.

So when we look at our business now and the likelihood of our frac expansions likely getting sanctioned and we sanctioned our Frac II debottleneck today, we see the need to clear more product. We'll have more spec product in our system, and we have to access the highest value markets. So we've always thought that it's great to have a diversified market access, so we can offer access to IPL PDH, the local industrial markets, the Mid-Continent in the U.S. But certainly, the market on the West Coast is going to continue to grow and be a valuable market for us to clear product out of.

So we thought it was a good opportunity to work with AltaGas to increase our ability to export out of their facility. And we think it's just a great arrangement for both parties. So anything else you want to add?

No, Dean, I think you hit the nail on the head. It's just to emphasize the fact that we've been flowing barrels through RIPET since day 1. But as Dean said, it's a new market to us, needed to get familiar with the market and understand the intricacies and the logistics associated with being able to maximize the value of being in those markets. And the thing I'd also identify is we've publicly stated how much incremental capacity that we're taking out at the RIPET and REEF facility. But there is a phasing in over the time period of our ability to be able to access more capacity, and that will start in 2025.

Go ahead.

Yes. And just maybe to answer the second part of your question, without going into specifics, to my earlier comments, we're always looking for opportunities to make the base and the industry more efficient. And we're open to work with other parties to make that happen where we can create win-win situations. And so I'll leave it at that, but we do see other opportunities as well.

That's great. Maybe just to finish up, I wanted to see if you could elaborate a little bit more on your comments about tariffs or impact of that on your iso-octane business. You touched on the feedstock cost, the RBOB spreads and FX. Could you speak to the market dynamics that could influence the iso-octane premium such as competition for alternatives and also the quality differentials?

Yes. Well, listen, I'll let Jamie comment on this as well. But to my earlier comments, I mean, the bottom line is we don't think there's a material impact. When you look at the demand and the balance of octanes in North America, North America is net short octane. So what it means is that they have to import octanes from -- from a place like us or they also import from Europe and Asia. So from our perspective, we might get hit with the 10% tariff. But if everybody is tariffed at the same level, at least at the same level, we're not disadvantaged.

And so if Europe and Asia are -- they have to pay a 10% tariff as well. What we think happens because, again, they're going to have to track those incremental barrels into North America is that the price of octane is going to actually reprice higher to compensate for that 10% tariff? So we don't know exactly how that trades, but that's a possibility just because North America is short tariffs. And the other comment I want to make is that even if we are -- we have to pay a 10% tariff directly from Keyera.

The reason why we feel pretty good about the compensating factors is that the couple of days leading up to when everyone thought tariffs were going to put into place up to February 1. The market started to trade as if that was happening. And again, during those couple of days before when people expected tariffs to be in place, we saw FX widen, we saw the price of butane in Edmonton fall off. And we also saw WTI strengthen. So those are all offsetting factors that would offset the cost of the tariff if we had to pay it. Is there anything else you want to add?

Dean, you're doing great this morning. Not much to add other than as you pointed out, is that North America is that net importer of octanes. And just to put it into perspective, like we produce 14,000 barrels a day of iso-octane. The octane demand in North America is in excess of 1 million barrels a day. So I mean, as we think about the markets that we've established over the years, these people value our product and the superior nature of our product, and we expect to retain those markets regardless of whether tariffs come into place or not.

Just a quick follow-up. So now that you're approaching the conclusion of your NGL contracting season for 2025, has those prices, particularly the feedstock costs already priced in a tariff such that those costs have come down?

Yes. You know what, that's a great question. And what I'd say is that this year, the contracting is happening a bit later. And I guess that's to be expected just given the uncertainty around tariffs. So we will work towards having all the contracts in place in April. They're just happening a little bit later in the cycle than they normally would because of the uncertainty.

Your next question comes from Robert Catellier with CIBC Capital Markets.

Congratulations on your ongoing strong safety record. I just wanted to follow up quickly on the tariff issue here. I have really two questions. I just want to understand how you're approaching the NGL marketing here in light of the tariff uncertainty. In other words, trying to get a sense of what level of exposure you might be looking for? In other words, are you maybe paring down your exposure a little bit because of the uncertainty? Or is it business as usual? And then on the customer side, just in terms of supporting new infrastructure, does the threat of potential tariffs cause customers to hesitate in supporting new infrastructure?

Rob, thanks for the questions. I'm going to answer your second question, and then I'll turn it over to Jamie to answer the first one. Overall, no one really knows what will happen if 10% tariff were applied to our energy industry and whether the buyer absorbs that or it's the producer or the seller of the product or it's some combination in between. So I think that remains to be seen.

But at the end of the day, our basin in Western Canada is a very low-cost producer environment. So we have some of the best reserves and we can produce them at the lowest cost. And so will 10% actually make a difference in terms of what gets produced in the basin? I doubt it. And we're not getting the sense from the producers either.

So when we look at infrastructure that's required, we still see a lot of development in the Deep Basin and for sure, in that Montney, Duvernay fairway. We see more development extending into BC, which is why there's a lot of interest in our Zone 4 -- KAPS Zone 4 project. And right now, in our basin, one of the most significant bottlenecks is fractionation capacity. And because we have KAPS and because we have an integrated service that we offer now, with all of our integrated deals, again, in our system, we have a lot of demand for incremental frac capacity.

So again, I don't think tariffs would affect any of those projects in a material way. And we see strong demand based on the conversations and contracts we signed with our customers. Jamie, do you want to address the first question?

Yes. So Rob, thanks for the question on the contracting season. Yes, as Dean alluded to, because of the tariffs, it's really put a pause on contracting throughout industry. It's not unique to Keyera. And I think as we've had conversations with our customers, their understanding ultimately of the impact that it potentially could have on them and ultimately on Keyera as well. So we've been looking at and discussing with customers inserting tariff language into our contracts for 2025 and frankly, probably from here on out because I mean, Trump is going to be in office for the next 4 years. And we just never know what -- where his mind might be taking them on any given day.

But as we look at it from the perspective of the different commodities, on the C3 side, it points to the value of our access to the West Coast. And also then as we think about C3 leaving down into the U.S., traditionally, our model is to sell that product FOB Edmonton. So we don't take a lot of risk on the C3 side of our business. And then on C4, because Alberta is a net butane, sorry, is a net exporter of butane out of Western Canada. We just look at tariffs as likely resulting in a reduction in the value of butane molecule in Alberta, given the fact that Keyera is a consumer of butane in our business and that short. We're going to benefit from that if tariffs are coming into place. But really, at the end of the day, we're striving to get the maximum value for our customer, but also recognizing that the risk should be borne by the appropriate party within our contracting structure.

Okay. That's a helpful and fulsome answer. I would -- I want to just move on to G&P for a minute here. Obviously, the volumes have been very strong in the North region, less so in the South, which is not a surprise. But I'm curious what you think needs to happen to increase throughput in the South region. And maybe you can provide updates on the South Duvernay play and development at Rimbey and any other development you think is possible for the Keylink pipeline system.

We're excited about the emergence of the Duvernay play in the South. And we've talked about it before. I mean, it's great to have more oil-weighted plays, oil condensate weighted plays down in our Central Alberta portfolio. And in that way, the producers have more than one way to win. It's not just off of natural gas. And that gas is very rich. So we're always very interested in the NGLs that get extracted, and we have capabilities to do that. So we think it's a great development. But overall, Jamie, do you want to talk about our South portfolio?

Yes. We talk a lot about the Duvernay and the Duvernay, we're very excited about the development of the Duvernay in the Rimbey area, but also as it trends up through towards Drayton Valley and some of the assets that we have up in the Drayton Valley area as well. And as Dean alluded to is that play is really about the condensate or the light oil that's coming off of that play. But the natural gas that comes along with it is very high in ethane and C3+.

So the -- but in the Spirit River, which is the primary play for the rest of our South assets, the economics for drilling those wells are very robust even at the gas prices that we're seeing right now because as Dean says, they've got a lot of natural gas liquids in them. And as I alluded to in the previous question is that we've seen some of our key customers sell themselves and basically roll over into other companies' hands that really they're -- these are becoming their Tier 1 assets.

So if you look at some of the presentations of the companies that have done some acquiring over the last 6 to 12 months, you'll see that they bought those assets because they've now become their Tier 1 assets. And as a result of that, their intent is to get after developing those assets where the previous company perhaps just had run the course and had been positioned themselves for a sale process. So the economics are good for those plays. And now with the right players and a willingness to work with an infrastructure provider such as Keyera, we see that there's lots of opportunities for future growth in '25 and beyond.

Your next question comes from Aaron MacNeil with TD Cowen.

Dean, maybe just to build on Maurice's question. You mentioned that the U.S. market is short octanes and obviously, the market is quite large relative to AEF. But can you speak to Valero's announcement that it will increase its production by 6,000 to 7,000 barrels a day in 2026. Like what's the potential impact to broader supply-demand? And do you think the market can absorb that growth from Valero and potentially others?

Aaron, thanks for the question. Overall, when we look at the gasoline pool, which is 9-plus million barrels a day. And I think with what's happening in the U.S. with President Trump and likely a clawback of all the incentives for electric vehicles. It just means that there's just going to be a lot more ICE vehicles sold for a much longer period of time.

So overall, we think that gasoline demand is going to remain strong. In the whole scheme of things, 7,000 to 8,000 barrels or 10,000 barrels of octane is just really a drop in the bucket. So we don't think that has a material impact at all. And the other thing, I guess, I continue to point out is that we have a very superior product with our iso-octane. It's very high in octane, low in RVP and low in sulfur. So those are very strong qualities.

And the customers that we have that buy it, now they are very used to working with our product. So I think there's some stickiness in terms of demand for it. So we feel pretty confident overall. We're aware of what's happening. We also know that there's going to be some refineries that are shutting down in the U.S., too. So that's also going to change the balances. So overall, again, we want to reiterate, we don't think it's a big impact to the market.

Yes. Makes total sense. And sort of switching gears to timing of potential FIDs. I'm probably reading too much into this, but during the December update, I think you had characterized FIDs for Frac III and Zone 4 as a potential first half of 2025 event. And then the language this morning for Frac III was sometime later this year. I know the in-service dates, the timing for that hasn't changed. So again, probably reading too much into it. But could you give us a sense of if those time lines have remained the same?

I'll confirm you're reading too much into it.

Fair enough.

Overall, starting with Zone 4, we feel pretty good about the project. I mean we've always thought there's going to be more development along that Zone 4 fairway into BC. And certainly, with LNG Canada ramping up, you're hearing the BC Premier, talking about fast tracking some energy projects, which one is the last time you heard that.

So I think there's a lot of optimism of what's going to happen there. Customers along that fairway, they want competition. And it's also good to have a new pipe in service from an integrity perspective and reliability of service. So that's our alternative that we're providing to the market. You probably would have read that North River Midstream received their provincial approval last month.

So from project perspective, the Class III engineering is all complete. All the regulatory approvals have been received by both us and also North River Midstream. So we have a shovel-ready project. And again, that's very meaningful to potential customers. So what I can say is that we continue to contract customers and volumes on that system, and we have a lot of momentum. So we still think that we get to a sanctioning decision here sometime by the middle of this year and that's also to meet in-service date.

On Frac III, Jamie and his team have done a phenomenal job and again, really leveraging and providing our integrated service offering to our customers. So what that means is that we're touching our energy molecule many times to our system and again, to provide an efficient service for our industry. And with that, it means that we're contracting a lot of volumes on the downstream side with our frac business.

So we continue to advance our engineering and contracting is going very well. So we think that we'll get to a sanction decision sometime in the middle of this year as well. Anything you guys want to add?

Thanks for the clarification. Turn it back.

Your next question comes from Ben Pham with BMO.

Maybe just to start out with the Allied business, and you reached a new high watermark in Q4. Can you talk about quarter-over-quarter, what -- how much was frac and storage driving that increase? And related to that is, do you think the Q4 contribution is ratable going forward?

Yes. Thanks for the question, Ben. And before I turn this over to Eileen, I just want to emphasize, when we're building KAPS, people are asking about, well, what is the benefit of KAPS. And again, I just want to really emphasize and this exemplifies it, our results exemplify what we were accomplishing is that this basically integrates our upstream gas gathering and processing business and our downstream frac business.

And I can tell you, pretty much every deal we sign is now integrated deals. So with KAPS in place, we're adding more volumes on that system, but it's also supporting our downstream fractionation, storage, our terminalling business. And then again, as we said before, our oil sands services business has been very strong as well. But Eileen, please go ahead.

Sure. Thanks for the question, Ben. Yes, the only thing I would add is that absolutely what Dean said, in the fourth quarter, all assets, especially in LI were running really, really well. Frac utilization, we're doing more contracts, longer-term contracts through our condensate system, storage. So all the things that we've been saying are coming to fruition. The one thing I would note, when you're looking at other quarters is frac utilization tends to be higher in the winter and in the summer, it does tend to come down.

The other thing I would note is like overall, our Fee-for-Service realized margin, that's G&P and LI grew by 9% year-over-year. And really taking it back to what Dean said, ever since KAPS came on in '23, that it is that integrated value chain. It has, without doubt, made us more competitive as a company. So even with the strength in the year-end results for 2024 on the fee-based side, we continue to have lots of confidence in being able to meet our EBITDA target going out to 2027.

Yes. Maybe one thing I just want to add to, we've been talking about being at full capacity at our fracs for the last few years. And what's different, I'd say, is that -- and give a lot of credit to Jarrod and the team at KFS that when they've had maintenance outage, they found ways to find small debottlenecks so that we could run sort of higher capacity limits at that site. So with the work that they've done and with very good reliability, that's helped us generate strong results at KFS and our frac business.

Okay. So other than just some seasonality, it sounds like if utilization remains strong, Q4 is a good ratable number going forward.

Yes. Yes. I mean what I say is we're able to run our fracs higher at higher capacity levels. So the cash flow is going to be higher in the winter months because of the cooler ambient temperatures there. So there's a little bit of seasonality, but it's not super significant.

Got it. And when you think about the AF outage in this spring, do you plan or anticipate to roll out into the potential 2026 outage as well?

I'll turn that question over to Jarrod.

Yes, it's a good question, Ben. It's unfortunate that we've had an outage of the second year in a row. And what's important to note, too, is that the circumstances from last year to this year are different. And the plants otherwise operated very well for us over the past couple of years, and you've seen that reflected in the results. So there's nothing we found last year, expected this year, see otherwise with how the plants performing to suggest that we'd require another outage before our 2026 turnaround.

So the plan is to go down this spring and address what we need to and then come back up and try to have a strong run to the 2026 turnaround.

Got it. And maybe a cleanup question on the tariffs. I know that is octane product, pretty much all of it goes to the U.S. But can you clarify what else you're exporting? I think propane is in the mix there? Is there anything else? And just general, just percentages going to the U.S.?

I'll turn that over to Jamie to respond.

Yes, Ben. So yes, iso-octane, the majority, 85% of iso-octane sold into the U.S. And then as I alluded to is that on the C3 side, we -- on propane -- sorry, hopefully, everybody understands what C3 is, is on the propane side, that would be the other product that we would be exporting to the U.S. And to repeat what I said in the previous question is that the way it's structured is traditionally, we sell that product to another counterparty in Edmonton, and they ultimately would take the risk associated with tariffs.

Your next question comes from A.J.O'Donnell with TPH.

Maybe just shifting gears a little bit. I was hoping I could talk about capital allocation. Given the strong performance to end 2024, really no change in spending guidance for 2025 and flexibility on the balance sheet. How are you guys thinking about using the NCIB in 2025? Have your views changed at all?

I'll turn that over to Eileen, but I'd just say that, obviously, we're in an enviable position. And I'm really pleased in the last year, our net debt was reduced by about $185 million. So again, we have plenty of optionality. But Eileen, please go ahead.

Sure. Thanks for the question. Yes, we're happy that this is a tool that we now have available to us. And if anything, we would look to use it opportunistically, especially with more market volatility. It's nice to have this option. But as we've said before, the preference continues to be to grow our underlying business and build infrastructure that's going to be around for decades. And again, with the macro environment being so positive, there's just several opportunities. So I think we can deliver higher returns than even buying back stock.

So again, our goal remains really unchanged. It's to allocate it to the highest value option, organic growth, inorganic growth or buybacks.

Great. Maybe just one more on the debottleneck project and that moving forward. I think you guys have already highlighted a few times about how tight the frac market is. And I'm just trying to think about how we should view that facility ramping up. Do you kind of see that filling up almost immediately? Will it take some time? And then just as a tag along, I don't want to get too far ahead, but if we do see KFS 3, get FID-ed or sanctioned soon, could we see the timing of that project pull forward as well?

So thanks for the question. Yes, to confirm, the debottleneck project, we expect that it will be fully utilized when it comes into service just based on the demand growth within our basin. And then on Frac III, our -- the in-service date of 2028 that we've communicated, that would -- there'd be very little opportunity to pull that forward. We've been progressing that project to be able to hit that date, but there's very little opportunity to be able to accelerate that.

Your next question comes from Theresa Chen with Barclays.

Looking at the collapse in octane spreads recently beyond what would be seasonally implied based on butane being in the gasoline pool during the cooler months. Based on what you are seeing, what do you think is driving this?

Theresa, I just want to make sure I understand your question. So you talk about...

Premium.

And then butane pricing?

No, no, no. Premium less regular gasoline to collapse and the octane spread in gasoline specifically.

Right. Well, you know, first of all, what I'd say is that in 2023 and 2024, the octane spreads were exceptional. Like those are the highest that we've ever seen since we've owned that facility since 2012. So I think those are exceptional years, and we shouldn't expect octane premiums to be in that range. But in the winter months, the octanes are usually trade at a lower value and they get stronger as you get into the summer driving season. And that is just a seasonal trend that you see every year.

So when we think about norms of where octane spreads are right now, we think it's in a very normal range, so -- and which still generates a very healthy margins for that business. Jamie, anything you want to add?

Yes. No, 100%, I mean, versus historical, the octane premiums that we're realizing for our product are frankly slightly ahead of what we would have seen pre-COVID. They're not to the levels, as Dean said, where we would have seen over the last couple of years, but those were extraordinarily strong years. The other thing I would say is that sometimes people do focus on there typically is a suppression of octane premiums when we go from a summer spec to a winter spec on gasolines, and that's very short-lived. That's probably a 2-week anomaly of which we just then hold on to our products. It happens every year. We hold on to our product and ultimately then reengage back into the market once that market has corrected itself.

Theresa, one thing I also want to -- I'd like to add just on octane that I think it's important to understand is that we've seen a growing trend of demand for higher octane blends in the gasoline pool. And that's because most of the engines or ICE vehicles that are being produced today are being produced with turbocharged engines with high compression.

And so for example, last year, about half of the vehicles manufactured had a gasoline spec of over 90 octane requirement for the engine. So we think that the demand for higher octane blends of gasoline, that trend continues to increase over time. So with that, we believe that those octane premiums, we think that are going to be fairly steady in a pretty good range going forward.

Got it. And just to clarify, what I was talking about butane being in the gasoline pool during the month, I was referring to the RVP change of spec change between summer and winter. Going to the medium-term outlook for octane, and you alluded to this a bit earlier, Dean. So in addition to the incremental alkylate production that Valero bring online FCC debottlenecking project, what's also interesting to us is the planned naphtha cracking capacity coming online globally.

So when that low octane naphtha comes out of the gasoline pool and serves as a petchem feedstock instead, this would presumably decrease the need for high octane blend stocks to counterbalance as a result and could likely be a headwind for octane economics. So how are your assets positioned to put this in mind?

Yes. Like I say, I mean, I'll let Jamie respond as well. But overall, there are a lot of factors that affect the gasoline pool, octanes. Yes, we're aware of that -- I mean, naphtha can be used for different purposes as well versus going into gasoline feedstock. Overall, we feel pretty confident, though, that the trend for higher octane blends of gasoline continue to increase over time.

And on that basis and also the strength of overall gasoline demand, we just think that because we have a premium product that it will always be in pretty high demand. And some of the places that we sell it to in the Mid-Continent, we are the best source logistically for them to receive it off, like a lot of places we sell are not on the U.S. Gulf Coast where they can receive it from the local refiners or local service providers there are off the water. So I think for all those reasons, we feel pretty good.

Your next question comes from Patrick Kenny with National Bank Financial.

I just wanted to go back on the performance of the condensate infrastructure in the quarter. Obviously, well positioned as TMX was ramping up there. Just wondering how we should be thinking about additional upside from here or white space available without having to spend material dollars going forward? Or if and when we see further egress expansions come to light, whether it's down the mainline or Trans Mountain, would that call for incremental investment into your condensate capabilities over the next couple of years to handle that additional wave of volume?

That's a great question, Patrick. And I'll turn that over to Jamie. But one of the things that I'd like to point out is that at the beginning of 2023, when we bought an additional 22% interest at KFS, really, we focused on the frac capacity that we're acquiring because that was in such high demand. But with it, we also received 0.2% of 17 million barrels of cabin storage. So that gives us some capacity to provide additional services for oil sands as an example. And we do have the hub for diluent. About 70% of all the diluent that goes up to oil sands originates from our system.

So as demand increases for diluent, certainly, we see that demand and volumes on our system increase. I would also point out that we have our Norlite pipeline, which is a joint venture with Enbridge. We own 30% of it. So we see increasing demand there as well. So overall, we're pretty well positioned to help service the oil sands business and also help it enable growth.

Yes. The only thing I'd add to that, Pat, is that we have a really good handle on, obviously, the system, our condensate system, our Fort Saskatchewan condensate system with respect to what would be required to accommodate that growth. And we've identified it would be nominal dollars. It's going to take some dollars, but not big dollars and ultimately, there'll be a very high rate of return dollars to invest in expanding the capacity of that system.

Okay. That's great, guys. And then I guess with the balance sheet in great shape, maybe this is for Eileen. There's no need to sell anything, obviously. But curious, given where the Canadian dollar is, if there might be any opportunity to monetize any non-core or perhaps underperforming assets in the U.S., especially with your 4 and 3 quarter U.S. notes coming due later this year. Just curious if the plan is to roll those over and keep a small level of USD debt within the KAPS structure or again, perhaps look to dial that back?

Pat, I'd say overall in the USD debt, relative to our size today, it's not super material. I mean it's something that we're always looking at, whether it is to roll it over or just pay it down. Again, given where the balance sheet is today, I think we have lots and lots of flexibility, and that's a great place to be. I think it's a huge competitive advantage for us.

Yes. In terms of dispositions, Pat, you would have saw that we -- in 2024, we did sell off a number of our smaller non-core assets. And that's to make sure that we can focus our attention on assets that are more core to our business, both today and into the future. So we're pleased with that. And I'd just say, overall, we continue to evaluate our portfolio, and we will continue to high grade over time.

Okay. Perfect. Sorry, last one, if I could, on the AEF outage -- apologies if I missed it, but I just wanted to confirm that this new operational issue doesn't give you any pause as it relates to that debottlenecking opportunity you were looking at? Or maybe on the flip side, might this 6 weeks of downtime just give you a chance to do some prep work and perhaps accelerate the time line for the 5% to 10% expansion?

Yes. Thanks, Pat. It's a great question. And it would be nice if we'd be able to do that. What I would say is the outage work we need to do doesn't really impact the debottleneck project in any way. We continue to still develop that. As far as pulling things forward to try to do that in this outage, whether it's related to debottleneck or even the turnaround, in 2026. There just isn't time to do that. So it's unfortunate. It'd be great to do that. We try to whenever we get an outage, but it's really going to be just specific to the work that we need to do now and then the turnaround 2026, so the debottleneck project will stay on their original time lines.

Yes. That's great. I'll leave it there.

[Operator Instructions]

Your next question comes from Nate Heywood with ATB Capital Markets.

I just wanted to turn the focus back to the G&P business. And I appreciate your comments around the Duvernay and Spirit River. But focusing more on the North, we saw in the commentary that there's some additional spending towards connections for new customers at Wapiti. And we saw really strong volumes to close out the year in the Northern region in December, which was a really big step-up from volumes we saw earlier in the quarter. So I just wouldn't mind getting your take on the volume outlook from the region and maybe if the exit 2024 rate is a good utilization going into 2025?

Nate, thanks for the question. I'll turn that over to Jamie to respond.

Yes, Nate. So yes, we have had some really good positive contracting momentum around all our Northern G&P assets. But certainly around Wapiti, we've gotten to a point now where we're fully contracted on the initial capacity of that facility. And the reference is we did some tie-in work back in the fall during one of our outages. And we've got one more customer that we've contracted for that's going to be delivering volumes in 2026. And that's what that tie-in is referenced to.

But fundamentally, obviously, the Montney is a world-class resource. And as we look at how we're going to be able to work with customers to be able to satisfy their growth aspirations, we're really looking at how can we optimize around our Simonette facility that has available sulfur processing capacity and front-end capacity at that facility. And we've got a lot of interconnection and pipe in the ground that allows us to shift some volumes around in that Wapiti Gold Creek, Simonette area, but also looking at greenfield opportunities as well or expansion opportunities at our existing facilities. So lots of conversations going on, very positive and constructive conversations.

And again, just to emphasize that all the opportunities that Jamie and his team is working on, they're also trying -- they're also working on integrating those deals. So it's not just G&P, it's also caps, frac and our downstream business, including marketing.

Got it. I appreciate that commentary. Just maybe turning back to the capital projects with KFS 3 and KAPS Zone 4, sounds like you're making good progress. I just wanted to know if you can provide some detail around the construction environment you're seeing going into the latter half of 2025 and into 2026 and maybe some considerations around cost inputs.

That's a great question, Nate. Given our plans and plans of others across the province and particularly in the Heartland, what I'd say is it's not a new challenge. We've had times in the past where there's been periods of high activity that have really challenged the availability of resources. And in the recent past, when we were doing KAPS, there was significant other pipeline construction in Western Canada at the time.

So I think the key is looking further out and both around construction and operations personnel that we'll need when those projects are done. And the earlier that we identify those needs and the sooner we can get on it. So a couple of things that come to mind are contracting strategies in terms of who we use and how we structure those arrangements. So it will take some creativity to ensure we can get the quality workforce we need.

And in terms of our own operations folks, I think about even just the importance of culture. We know workers have choices in this environment, and we want to be an employer of choice. So it's a good problem to have since it means we've got line of sight to growth, but it's definitely top of mind for us as we develop those projects.

There are no further questions at this time. I will now turn the call over to Dan for closing remarks.

Yes. Thank you all once again for joining us today. For any remaining questions, just feel free to reach out to the Investor Relations team. I hope everyone enjoys a nice long weekend for those who have the extended weekend here. Thank you.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.