Pembina Pipeline Corporation (PBA) Q1 2025 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to the Pembina Pipeline Corporation Q1 2025 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, May 9, 2025. I would now like to turn the conference over to Dan Tucunel, VP, Capital Markets. Please go ahead.

Thank you, Joelle. Good morning, everyone. Welcome to Pembina's conference call and webcast to review highlights from the first quarter of 2025. On the call today, we have Scott Burrows, President and Chief Executive Officer; and Cameron Goldade, Senior Vice President and Chief Financial Officer; along with other members of Pembina's officer team. I would like to remind you that some of the comments made today may be forward-looking in nature and are based on Pembina's current expectations, estimates, judgments and projections. Forward-looking statements we may express or imply today are subject to risks and uncertainties, which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures, please see the company's management's discussion and analysis dated May 8, 2025, for the period ended March 31, 2025, as well as the press release Pembina issued yesterday, which are all available online at pembina.com and on both SEDAR and EDGAR. I will now turn things over to Scott.

Thanks, Dan. Yesterday, we reported our first quarter results, which were highlighted by quarterly adjusted EBITDA of $1.167 billion. This is a very strong start to the year and builds on the momentum from a record year in 2024, providing confidence in our full year outlook. As Cameron will discuss in more detail, we are currently trending towards the midpoint of our 2025 adjusted EBITDA guidance range of $4.2 billion to $4.5 billion. Given the growth across Pembina's low-risk fee-based business and confidence in the outlook for 2025 and beyond, we were pleased to yesterday announced a $0.02 per share or 3% increase in the quarterly common share dividend, beginning with the dividend to be paid in June. We recognize the importance of our sustainable, reliable and growing dividend to our shareholders, and we are proud of our long track record in this regard. On the commercial front, Pembina has entered into commercial agreements with the leading Montney producer covering Pembina's full value chain, including transportation, fractionation and marketing services. The agreements include significant new and extended long-term take-or-pay volume commitments on Pembina's Peace Pipeline, Frutz Kopay systems and Northeast B.C. Pipeline. The new and extended fractionation agreements are expected to support higher utilization of Pembina's Redwater complex including RFS IV, currently under construction and the proposed RFS III deethanizer is sanctioned. Additionally, the process to remarket Pembina's capacity on the Cedar LNG Project to third parties continues to progress well. We have now shortlisted the preferred counterparties and entered definitive agreement negotiations. Pembina continues to advance several in-flight construction projects to capitalize on growing WCSB volumes, diversify end market exposure and serve our customers better. Pembina has built a strong competitive advantage by effectively delivering projects safely, on time and on budget. Further, we believe that recent and current expansions have been and continue to be executed with superior capital efficiency compared to others in the industry. In addition, Pembina is progressing development of more than $4 billion portfolio of potential projects that includes conventional pipeline expansions such as the Taylor-to-Gordondale project and expansion of the Peace Pipeline system to add capacity to the market delivery pipelines for Fox Creek-to-Namao and further expansions to support volume growth in Northeast B.C., including new pipelines and terminal upgrades. While reiterating their commitment to their path to zero project, Dow recently announced the delay in construction of the project to manage capital allocation in light of current market conditions and economic uncertainty. At this time, other than changing the in-service date of Dow project, the announcement delay has no impact on Pembina's ethane supply agreement and the development of potential infrastructure to meet its commitments. To date, Pembina has not spent material capital to support the ethane supply agreement, and we'll continue to progress these projects but may now have more time available to execute them. Pembina is evaluating the various options available to meet its ethane supply commitment under the agreement with Dow, including the addition of a de-ethanization tower at RFS III within the Redwater Complex. Regarding Alliance Pipeline and ongoing Canadian energy regulator review process, Alliance is working collaboratively with its stakeholders and remains focused on delivering the highest standards of service that customers have come to expect. Based on discussions to date, Pembina expects lower future tolls on the Canadian portion of Alliance, reflecting a negotiated solution that continues to benefit both Pembina and the Alliance shippers through an equitable sharing of value and risk. We expect Pembina will continue to earn appropriate risk-adjusted returns, while shippers will continue to benefit from Alliance's firm capacity, high reliability and cost-effective access to premium U.S. natural gas markets. I will now turn things over to Cam to discuss in more detail the financial highlights for the first quarter.

Thanks, Scott. As Scott noted, Pembina reported first quarter adjusted EBITDA of $1.167 billion. This represents a 12% increase over the same period in the prior year. In pipelines, factors impacting the quarter primarily included a higher contribution from Alliance due to increased ownership following the Alliance Aux Sable acquisition, favorable U.S. foreign exchange rate, higher tolls mainly related to contractual inflation adjustments, higher contracted volumes on the Nipisi Pipeline and the Peace Pipeline system, higher contribution from Alliance due to higher demand on seasonal contracts and lower firm tolls on the Cochin Pipeline due to the recontracting that occurred in July of 2024. In facilities, factors impacting the quarter included the inclusion of Aux Sable following the Alliance Aux Sable acquisition and higher contribution from PGI primarily related to the Whitecap and Veren transactions largely offset by lower interruptible volumes at Dawson due to third-party sales gas restrictions. In marketing and new ventures, first quarter results reflected the net impact of higher net revenue from contracts with customers due to increased ownership interest in Aux Sable, higher WCSB NGL margins and volumes, lower realized gains on commodity-related derivatives, lower Aux Sable NGL margins and no similar gain to that recognized in the first quarter of 2024 from a change in the provision related to Pembina's financial assurances for Cedar LNG. Finally, in the Corporate segment, First quarter results were lower than the prior period due to higher incentive costs driven by the change in Pembina share price and relative performance to peers in the period compared to the first quarter of 2024. Earnings in the first quarter were $502 million. This represents a 15% increase over the same period in the prior year. In addition to the factors impacting adjusted EBITDA, the increase in earnings in the first quarter was primarily due to the net impact of higher depreciation and amortization expense largely due to the Alliance Aux Sable acquisition, unrealized losses recognized by PGI on interest rate derivative financial instruments compared to gains in the first quarter of 2024, higher unrealized gains on commodity-based derivative financial instruments recognized by PGI, lower unrealized losses on renewable power purchase agreements and crude oil-based derivatives, unrealized gains on NGL-based derivatives, unrealized losses on interest rate derivative financial instruments recognized by Cedar LNG, higher income tax expense, higher net finance costs and lower interest income. Total volumes in the Pipelines and Facilities divisions were 3.7 million barrels of oil equivalent per day in the first quarter. This represents an increase of 9% over the same period in the prior year, reflecting the net impact of the Alliance Aux Sable acquisition, higher contracted volumes on the Nipisi pipeline and the Peace Pipeline system, higher volumes at PGI related to the Whitecap and Veren transactions and lower interruptible volumes at Dawson due to third-party restrictions. Thanks to strong results in the first quarter of 2025, Pembina generated meaningful free cash flow in the quarter, which was allocated to strengthening the balance sheet. Turning to the full year. As Scott mentioned, we are confident in our outlook and currently trending towards the midpoint of our 2025 adjusted EBITDA guidance range of $4.2 billion to $4.5 billion. Notably, the guidance range reflects the following full year and quarterly or seasonal assumptions. Pembina continues to see rising utilization on its conventional pipeline systems and at PGI that aligns with volume growth across the Western Canadian sedimentary basin. However, in 2025, Pembina's revenue volume growth within the conventional pipelines and gas processing assets is expected to be slightly lower than physical volume growth as certain customers expand into their contractual take-or-pay commitment. We expect a higher contribution from Alliance in the first and fourth quarters due to the ability to transport higher volumes during colder periods. Further, the current guidance assumes the existing Alliance tool is in effect for the full year. For the second quarter, our outlook assumes planned maintenance at Aux Sable and Alliance, certain PGI facilities and the Redwater complex as well as restrictions on third-party natural gas egress within the basin. We expect the third and fourth quarters will have higher integrity and geotechnical costs across the conventional pipeline assets. And we expect stronger first and fourth quarter results in the NGL marketing business due to typical seasonality. Additionally, while marketing results in the first quarter exceeded Pembina's original guidance expectations, this has been offset by the outlook for the remainder of the year, which reflects lower commodity prices due to global economic uncertainty. As a result, Pembina's full year adjusted EBITDA outlook for the marketing and new ventures division of $550 million remains unchanged. Pembina does not expect any material impact to its guidance from tariffs on U.S. energy imports. At March 31, 2025, based on the trailing 12 months, the ratio of proportionally consolidated debt to adjusted EBITDA was 3.4x, and we expect to exit 2025 at 3.4x to 3.7x. Our leverage remains well below the low end of our targeted range, reflective of our strong balance sheet and supporting a strong BBB credit rating. I'll now turn things back to Scott.

Thanks, Cam. In closing, I want to remind you that Pembina will hold its Annual Meeting of Shareholders today at 2:00 p.m. Mountain time, 4:00 p.m. Eastern Time. It will be a virtual-only meeting conducted via live audio webcast. Participants are recommended to register for the virtual webcast at least 10 minutes before the presentation start time. For further information on the annual meeting, please visit the Investors tab at www.pembina.com. Thank you for joining us this morning. Please go ahead and open up the line for questions.

[Operator Instructions] Your first question comes from Jeremy Tonet with JPMorgan.

I just want to kind of start off with maybe a bit more color on your producer customer conversations at this point and how you see, I guess, drilling activity shaping up? And should WTI be going below 60, staying there for some period of time, how in corresponding moves in county [ph] prices, how you think that impacts Montney production and your outlook here, granted Pembina has a material contractual protections, but just wondering any thoughts you could share there?

Yes, Jeremy, it's Scott. I'll start off and make some comments, and Jaret might chime in as well. But I would say, to date, we haven't seen any material changes to drilling plans. I would say we have seen, in the last couple of days, a couple of producers start discussing about moving completions into Q3 and Q4. So I would say we are starting to see some timing of completions. But overall reductions of CapEx to date, we really haven't seen that.

Got it. And then maybe shifting over to Alliance, if I could, and recognize that you're in a place where you can only say so much at this juncture. But is it fair to kind of characterize, I guess, the range of outcomes at this point is relatively minor within the grand scheme of Pembina as far as what unfolds in the Canadian process here? And do you see, I guess, on the U.S. side, similar things materializing? Or any other color would be helpful.

Jeremy, Jaret here. And yes, I appreciate you mentioning that we are obviously limited in what we can say. But what I can reassure you, Jeremy, is that our customers continue to reiterate, they enjoy the high reliability, availability of the Alliance assets. They enjoy the high-value end market, delivering into the Chicago area. And they really value the risk-sharing aspect. Obviously, Pembina takes a material amount of operating cost risk. We believe we're a good, safe, reliable operator. And they do appreciate that with respect to that asset. On the Canadian side, that's unlike any other of the major gas transmission pipelines in Canada. Additionally, we heard from our customers that they do not want us as part of the negotiated settlement to move to a cost of service model like a true traditional cost of service model. So with all that said, we continue to work with them expeditiously to get to a negotiated settlement that we can get into the Canadian energy regulator as quickly as possible that ultimately will provide Pembina with that risk-based return. And that's, unfortunately, that's all we can really say right now due to the active aspect of those negotiations.

Got it. And as far as the U.S. side, nothing to think about there at this point?

You bet. And then on the U.S. side, Jeremy. So I believe it's December 1 of this year, we'll be submitting -- it's roughly -- it's every 5 years. We have to submit our information to the FERC, and that's coming up, I believe, December 1, 2025.

That's helpful. And last one, if I could, just real quick. Pembina has done a great job getting the balance sheet in a very strong position. And just wondering if there's the opportunity to go from defense to offense if different opportunities shake loose as far as potential smaller bolt-ons or what have you?

Yes, Jeremy. I would say that a couple of things. One is that, you've certainly seen us do that over the course of time on a targeted basis. Obviously, we very, I think, successfully leveraged the PGI relationship to add some really exciting opportunities there over the past year or so. I would say that in terms of capital allocation, obviously, we're -- it's a pretty dynamic environment right now, and we're obviously monitoring things kind of in real time. But at the same time, we always stand ready to make our business better as opportunities present. I would say that the prospect for big game hunting is not something we're focused on. But certainly, the smaller value-add opportunities if they come about, we're certainly going to be in a position to act on.

Your next question comes from Spiro Dounis with Citi.

I wanted to start with the DS Tower and the Dow contract. It sounds like your plan right now is still to develop it at some point, maybe even without Dow announcing the facility timeline once again. I just want to confirm, one, that's correct. Two, just curious if there's a point in that agreement with Dow where they would need to pay for the supply regardless of that cracker being online. And then lastly, sorry for the multipart question here. But in the interim, this does seem to free up some capital, if you're not developing this tower imminently. So just curious how you're thinking about redeploying some of that capital?

Jaret here. Yes, maybe I'll just take a step back. So we announced, it was probably May of 2024, actually. We announced the supply agreement with Dow. And I think we've been saying quarter-over-quarter, we've been evaluating -- Pembina has the luxury of having multiple supply sources across its entire portfolio, and we've just been taking a prudent approach to evaluating what's the most cost-effective approach to that supply. And we have been signaling that RFS III, which was a clone of RFS II, does make a lot of logical sense to build the DS side of that asset as part of our overall portfolio. And we continue to believe that, that still makes a lot of sense. There was minimal capital being spent on the portfolio of assets in the calendar year of 2025. So even with the most recent reprofiling or delay that Dow has mentioned, there isn't a material change to our overall capital in 2025. And we still believe, not knowing exactly when the new onstream date might be announced, we believe that it's kind of that -- it's just normal routine execution, doing the DS Tower. Now my team is probably cringing that I'm saying that, but it's not like a 3 or 4 year build for what we're doing. So we absolutely believe that when we do get a little bit more line of sight, we'll be able to act quickly and have that asset on to meet our supply portfolio commitments.

Got it. That's good color. Second question, going back to the Alliance quickly. I don't think this was addressed in the prior question, but I know at one point, you've been talking about with these same customers, discussion around expanding that pipeline. Just sort of curious where those stand right now, if we're looking at maybe a singular integrated solution here when you announced the resolution year and how you're thinking about the timing?

I won't get into the specifics of the negotiation, but I can say that, obviously, demand for incremental gas egress is extremely strong. And we have a couple of opportunities. We -- obviously, Alliance was built for a full path expansion all the way down into the Chicago market. And there's also opportunities to do shorter haul expansions with less compressor stations here on the Canadian side into the Alberta Heartland. So we're just continuing to evaluate those and kind of in the pre-FEED engineering stages of that. But lots of demand for incremental liquids rich gas egress.

The next question comes from Theresa Chan with Barclays.

I wanted to go back to the comments about risk sharing within Alliance. To your comment about your customers appreciating that Pembina is taking the risk. Does that mean the risk sharing or incremental risk shift from Pembina to customers is off the table? Or is that still a point of negotiation? And if so, if the risks were to move, what would that illustratively even look like?

I don't think I can get into too many of the details, but maybe I'll just provide some color that unlike some of the other pipelines in Canada, we do take operating cost risk. And the reason Pembina at the time and the joint venture previously was open to that is that we do believe that we're extremely good at providing safe, reliable and cost-effective operations. But with that said, as we're the back and forth goes with the customers, there could be changes to that overall risk sharing profile as different inputs into the economic model change. So it's pretty live and dynamic right now, but -- and that's all I can say about that.

Okay. Fair enough. And to the earlier color about the bifurcation between volumes and revenue and EBITDA contribution due to the gap as customers ramp into the MVCs. When do you expect that to true up?

Theresa, it's Cam here. I would say that that's consistent -- that's a pretty consistent phenomenon or pretty consistent experience that we've seen. And the reason being is that as you've seen from us and continues to be the case, we continue to sign up new contracts on a regular basis. So as we continue to sign up new contracts and obviously, the contracts are a leading indicator against the fiscal volumes, they typically come first, the volumes come second, we've continued to see that lag over time. I'm not sure that we will expect those to true up. I think we continue to sign contracts as evidenced by this quarter. And so we will continue to see a gap between those revenue and physical volumes as a result of that.

And maybe I'll just add to that, that you do have to delaminate the difference between, so what we call our high vapor pressure products. So that's your C3+ and your C2+ versus your LVP or low vapor pressure, so your crude and your condensate. It is customer dependent and it is commodity dependent. Obviously, Pembina has a suite of pipelines in our conventional systems, C2+, C3+, condensate and crude. So there is different dynamics happening. Some customers are over on certain aspects of their contracts. But overall, you will see that true up. But it's not a blanket statement that all of our customers are below their firm for their take-or-pay and they're all drilling into it. It is dynamic between asset commodity and customer and region.

Your next question comes from Aaron MacNeil with TD Cowen.

Obviously, great to see the Montney contract with the quarter. Just wondering if you could provide any more detail beyond what's in the release. I can obviously appreciate that the disclosure is intentionally vague, but we're fielding the obvious questions from investors on magnitude of the contract volumetrically, duration, new level of contracting at both Taylor-to-Gordondale and RFS IV? And maybe just confirmation that it is a B.C. Montney customer given the contracting on specific pipelines that you noted? So just open-ended, anything you'd be comfortable sharing.

Yes. You bet. Appreciate the question. So it is one of our -- I can't say it is one of our largest customers. It is the Northeast B.C. customer. And I think what I'd like to leave the group with is that this announcement, I think it just provides confidence that we recognize our customers do have a choice to flow on other service providers, and they continually to choose us for a safe, reliable and cost-effective options specifically around the conventional pipeline. And it's not only the safe, reliable operation and cost effective. It is that suite of different assets that I just referred to, the different pipelines connected to all of the fractionators in the Fort Saskatchewan area connected to all of the egress outlets, et cetera. So we do recognize they have choices, and we do appreciate them choosing us to be their service provider. I will say that this is -- I'll use the word, material volume. It's existing volumes across the enterprise, so the pipelines, the fracs in our marketing business. But it is also new. And it's there's kind of twofold here. One is that it shows the resiliency and the requirement for high utilization across the base assets, but also reinforces the need necessity for new expansions albeit the Taylor-to Gordondale area, new pump stations within Alberta, et cetera. We've referenced pump station expansions between Fox and Namao. These are all incrementally required as customers reaffirm their base volumes and sign up with new revenue barrels throughout our system.

Aaron, I'll just maybe add a couple of data points. The renewal piece, obviously, we've talked about it, it's a very meaningful piece of our Peace contract structure. It's not quite 10%, but it's pretty close. And obviously, the commitments beyond that flow through both the frac as well as other pieces. And so when we talk about it being a fairly material contract, that's the renewal piece. Obviously, the new piece of it is obviously quite material, not quite to that magnitude, obviously, but very meaningful on its own.

Wow. Okay. That was more than I expected to get. I'm really sorry to go back to Alliance, but you did mention the risk sharing earlier and that you're not a cost of service pipeline. I just -- I guess I bring that up because the original CER complaint essentially compared Alliance to rate-regulated pipelines. So the question is, how do you define an appropriate risk-adjusted return? And obviously, it's not a rate regulated return, but like is the right way to think about it in the context of prevailing industry build multiples? Or is there anything you can share there?

Maybe I'll just -- I'll touch quickly on that. It's -- that's one of the biggest challenges through this negotiation is exactly what you just touched on. And we are different than any other asset, and we're just working through that. What does that risk premium look like for Pembino?

Yes. I appreciate that. That's a tough one to answer.

Yes, Aaron, the only thing I'd say is, I mean, obviously, the filings are public. You can look at all the other pipelines, which are effectively no risk utility type structure and see that the ROEs there have climbed into the mid-teens in some cases. And so that's a no-risk scenario. So if you sort of look at Alliance, obviously, taking on the kind of risk that it does today, we believe that it's appropriate to earn a premium to that. And perhaps that's what we're getting at with an appropriate risk-adjusted premium. Probably that's as far as I can go there, but I'd just make those data points clear.

Your next question comes from Praneeth Satish with Wells Fargo.

Maybe let me get my Alliance question out of the way here. It just kind of recognizing you're limited in what you can say, but can you clarify the timeline for when the tolls would take effect as it relates to EBITDA? I know sometimes that the timing of the actual settlement, it can be different than when you accrue it in EBITDA. And then second, without giving a specific number, are you able to confirm that any potential impact would be contained within the guidance range that you've provided within the midpoint to low end of the range?

So on the timing piece, I'd say that's still part of the negotiations, so no update. And with that in mind, we really can't comment on 2025 guidance and giving that clarity will just -- is another angle to try to figure out kind of where we're at in our negotiations, and it's just too confidential and sensitive. So we're just not going to answer that question. I apologize. As soon as we can say more, we will.

Understood. That's fine. And then switching gears, maybe if we could get an update on the Greenlight data center project. And I guess, specifically what I wanted to know is any more color on whether the JV has entered the queue for gas turbines because we're seeing the lead times elongate, the prices go up. Have you -- has the JV secured pricing on the turbines and other critical equipment costs and just any broader update you can provide?

Sure. It's Chris Scherman. Thanks for the question. The projects are progressing nicely. We're really focused on our interconnection applications at the minute -- at the moment. And we haven't made any turbine long-lead purchases, but we are actively engaged with equipment suppliers. We're very alive to the cost and timing dynamics that are unfolding out there, and we're going to be prudent with our order placement and frankly, the timing still aligns with our expectations. So everything is going well and on track both commercially and on the project side.

Your next question comes from Rob Hope with Scotiabank.

First question is on the Yellowhead straddle. So ATCO continues to pursue that project even with the Dow delay. How do you think about the potential to straddle that asset in the context of a Dow delay? Or could incremental ethane and C3+ allow that project to stand on its own?

I think from a timing perspective, Rob, nothing really changes on our end in terms of that project. That was always a late 2028, 2029 project. So without knowing the specifics around the extent of Dow delay. I really can't comment on that. But as of right now, we're continuing to progress that pipeline just due to when the in-service day was. So no change from that on our end.

And Rob, I would just add that obviously, the announcement from Dow and the assessment on our part and everything that comes with that is kind of happening in real time here. Dow is obviously a big customer of ours and a big partner. We were not spending material dollars on that in 2025, obviously, it's obviously early works. And so we're obviously going to get more information as the weeks and the next 2. 3 months tick by here, and we'll obviously make judgments at that point. But I just want to make clear that we weren't spending material dollars on that in 2025. Obviously, just some early works and engineering work.

You did nail it, Rob. Sorry, that there is accretive C3+ that can be extracted from the gas if this did go into service and the ethane component on the sales side was a little bit delayed. There is NOI associated with this that would be accretive to the project.

All right. I appreciate that. And then maybe diving deeper into the Dow agreement. So it appears that the commentary to say is that it's a delay, not a cancel. But it's the delay from Dow is substantial. Do you have a sunset date or any recourse?

I appreciate the question, Rob. I think out of respect for our partner, we're going to refrain from sort of getting into the nitty-gritty of the agreement. I guess what I would say is that we feel very comfortable that we have capital protection for capital, which we would spend. And outside of that, I don't think we want to sort of go much deeper than that.

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

I'll try not to ask anything too commercially sensitive here. But just on the strategy to diversify your NGL markets. I just wanted to get a better sense as to where you're at today relative to, say, where you want to land in terms of exposure to various markets? And I guess if we had a bit more color on what kinds of opportunities you're looking at in order to access non-U.S. markets, both on a proprietary basis as well as utilizing third-party infrastructure, that would be great.

It's Chris Scherman. I think we've been fairly clear about our aspirations around propane and some of the optimism and bull case we have for the West Coast of Canada. I think the positions we have today, both through our own facilities and others are serving us well. We like that ratio as far as how it fits into our portfolio, but we've also talked about a desire to optimize Prince Rupert to increase some of the margins there. And honestly, if the price is right, we'll look at more off the West Coast for propane. As well, we're keenly watching butane. We're looking at a number of different projects to try to figure out where butane is going to fit best into North American market, other product markets as well as potentially off the coast in the future. I can't get too much into that, but we're putting a lot of effort and time into all of those.

Okay. That's great. And then I guess, just on the remarketing of the capacity at Cedar. Would you say your patience is paying off here in terms of the geopolitical trends supporting higher demand and perhaps stronger economics for this capacity versus the first 1.5 million tonnes? And just curious as well if you can comment on the level of interest in the potential expansion at Cedar. Just wondering if counterparties are considering dovetailing an option for the expanded phase as well.

Yes. Pat, it's Scott here. I think it's more than just the geopolitical changes, I think it's also the fact that we continue to see growing gas out of Northeast B.C. that needs an egress solution. We're continuing to see strong ARBs between Canadian gas and Asian gas prices. And so that's driving pretty significant interest in the Cedar capacity. So we're pleased with where that's going. Also the fact that obviously, we're FID-ed and we're a year into construction and a year closer in service date. So I think all of those factors are leading to decent interest in this project, and we're pretty pleased with where we're going. So I would say the patience has paid off. I mean at this stage, we are working very hard to turn the definitives into a final executable agreement, but they're big complicated agreements. And as we've said for the last several months that we'll do the right deal for Pembina, not the fastest deal for Pembina, and we will continue to progress that. I would say as it relates to a potential Cedar 2, certainly, the gas demand is there. We saw that from our recontracting efforts. Based on early stages negotiations on Cedar capacity, we believe there is demand for a Cedar 2. But until we have line of sight to that gas on Coastal GasLink or other solutions, that's kind of the gating item and that's something that we continue to work on.

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

I just wanted to take a broader picture about the long-term WCSB outlook and holding on the Taylor-to-Gordondale NGL pipeline project. Clearly, there is a competing third-party project out there, obviously, against your projects in the CR process. So just your thoughts as how you think the CR will resolve these sort of issues? And taking one step further, any reason why you would think there wouldn't be sufficient contracted volumes for both projects to proceed in the coming quarters?

Maurice, Jaret here. So yes, we recognize that there is currently 2 projects moving forward. And we're actually -- you may be surprised to hear this, but I think I mentioned it before. We're very supportive of both projects moving forward, removing egress constraints for our Western Canadian sedimentary basin customers, upstream customers is critical. That's what midstreamers do. We remove constraints so they can get to higher value markets. And overall, between LNG Canada Phase 1, Pembina is highly confident LNG Canada Phase 2 happens for all the reasons Scott just mentioned, world-scale resource and low commodities. You've got your Cedar, you've got other projects in the works and/or in construction. We believe that the overall NGL and condensate demand in Canada, we still import 250,000-plus barrels a day as a nation and the NGLs that are going to come with that incremental gas egress need to get to a market, need to get to a fractionator, need to get to a petchem facilities. So we're very bullish that both projects are required and we'll continue to work with our customers and work with the regulator and the communities to satisfy the requirements to get ours across the finish line.

Understood. If I just finish up with a cleanup question here. Cam, I think in your prepared remarks, you mentioned you expect to exit 2025 at 3.4x, 3.7x debt to EBITDA. And I think that shifted a touch by about 0.1 from what you mentioned in the last conference call. So clearly, still well below the low end of your target range, but just wondering what assumptions have changed, especially given that the guidance for EBITDA has perhaps some gross spending was assumed, just a thought there?

A little bit of timing of spend, Maurice, and also just assumptions on timing of cash flow. It really sort of speaks to timing of cash flow in the calendar year versus subsequent year. That has to do with changes in noncash working capital as well as the timing of our cash tax payments. So it's really more so timing than any sort of structural change.

Understand. And just to reconfirm the guidance that you have right now still assumes interim Alliance tools, is that right?

Correct.

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

Just a follow-up on the situation with Dow. I wonder if you have any sense on what they need to see to resume this project? Was it delayed because of a trade-related issue? For example, maybe the products was competitive because of tariffs? Or is it something about the economy or anything related to Canadian policies?

Rob, it's Scott here. I -- that's a better question for Dow. I just -- out of respect for our partner. I can't comment on that.

Okay. I understand that. And then just moving on to just tariffs in general. What are the tariff uncertainty done to activity levels for Watson Island and the export outlook in general?

It's Chris. Well, first of all, tariffs have driven lots of volatility, which we've all seen and undoubtedly, some shifting trade patterns. I think in the short term, we've seen strong volumes off the West Coast, which is really in line with increased demand for, frankly, Canadian propane as a result of some of the dynamics going on in the Gulf Coast and some of the curtailed supply from China. But I think in the long term, it really positions Watson, it really positions the West Coast of Canada really, really well. We've got tremendous resource in Western Canada. We've got a really proven pathway to get product to the West Coast. And we've got supply security concerns for a good part of the world that's going to be looking for alternative sources, and Canada is a great piece of that. And so we'll be looking to leverage that as much as possible.

Your next question comes from [indiscernible] with UBS.

Just to go back to capital allocation and leverage. It's great to see that you increased the dividend and also the leverage target range went down. Just wanted to get any high-level thoughts on capital allocation priorities going forward?

It's Cam. As I mentioned earlier, I think it's something we've clearly been watching in real time as the markets evolve through the greater macro volatility in the last couple of months here. Clearly, in our guidance, we indicated a preference or sort of a base case disposition towards debt reduction in 2025 as we have free cash flow, which we expected to have and continue to expect that. I think as we've seen things ebb and flow throughout the course of the year, we've obviously taken that information in. And we obviously haven't changed, that's leading up to the Q1 print here. We're in blackout through April. So we wouldn't have been in a position to execute any share buybacks even if that would have made sense at the time. And so we are sort of looking at all the signals here and are looking at things on the back of the first quarter release and as we come out of blackout and obviously, are reconsidering whether we shift some of that free cash flow towards share buybacks. I wouldn't put a pin in it at the moment, but certainly something with lots of active debate and will ultimately be -- ultimately be market condition dependent.

Got it. That's very helpful. And then just a more general one on guidance. So you mentioned that you're tracking towards the midpoint currently. And of course, there's a lot of talk about volatility in the macro. But are there any projects or other factors that could push you more towards the top end of the guidance?

I would say that the biggest one would obviously be just in the near term, it's frankly probably going to be where we see the commodity business. I mean I think it's no secret that, that is the driver biggest driver of variability in our business. Obviously, we do have some interruptible volume exposure in our business. And certainly, where there are dislocations on competing pipelines or alternatively egress constraints elsewhere and we stand to benefit from that. That's another driver of variability. Obviously, we do see seasonality in our business as we highlighted in the release and certainly Q2 and Q3 we do expect to be sequentially lower compared to Q1, which is normal, and that's a function of all the elements we saw. The cost picture on that side is largely well understood, but really, it's the revenue opportunities that could come on top of that. So if I summarize that, I would continue to say that market price variability will be the biggest single driver. And then lastly, sort of the interruptible volume situation as egress on our own or on third-party pipelines becomes available or constrained.

Your next question comes from Ben Pham with BMO Capital Markets.

A couple of questions on the marketing and the guidance you've -- and for the year, Q1, you pretty much hit almost half off of it so far. Can you share details on hedging on that segment? And also just a trend around propane barrels. Is the trend over time from your advantage to move more barrels to the Canadian West Coast? And how and if that could impact the long-term outlook in market and EBITDA?

Sure. It's Chris. So on the hedging side, our frac spread businesses, in and around 50% hedged here across the full year of '25. And so we've got a degree of protection from the volatility that Cam was mentioning on the frac spread side. And then as to how we're thinking about the market long term, we've been, I think, fairly consistent for a while that we think the long-term resilient markets for the Canadian wave of growth that's common will continue to come is global. U.S. demand has been strong and there's lots of different narratives out there about how that might unfold over the next while. But I think in the long term, the most resilient markets are going to be global. And so we'll be striving to get as much growth as possible, access to those markets. We remain constructive on our portfolio and think we've got a nice balance at the moment between some North American markets and global markets. But as we look forward, we truly think the most resilient markets are going to be global.

And I would just add to that, Ben, that in terms of hedging, Chris mentioned that we're both 50% hedged, we are hedged at levels which are in excess of the current sort of outlook for the balance of the year to the tune of 10% to 15% above current levels.

Okay. Got it. And just on Alliance, but I'm not going to ask the tolls. I just wanted to go back. When you underwrote that asset, you had synergy expectations. Just wondering where you track to that? And then also just, wasn't there something about the Aux Sable marketing business in terms of higher volumes in the late decade time frame? Just where are you with that?

Yes, Ben, good call out. First thing I would say is that if you remember back to our announcement there, I would say that the lion's share of the synergies, the material amount of them were actually coming from the Aux Sable business. There's a significant amount of commercial opportunities in the of Aux Sable business. Some small opportunities on the cost side across both assets, but more so on the commercial side, and those are largely on the Aux Sable side. I would say that, so far, our perspective is we're tracking very well to our plans, timing. I think we communicated at the time a range of $40 million to $65 million, and that obviously had a ramp to it. Some of those come very quickly. Some of those take a little bit of time. And certainly, for 2025, we're tracking towards our intention there, which is probably at the lower end of the range as we expected and continue to see the integration opportunities, and we'll continue to look for more, but so far tracking according to time.

Okay. Got it. Just one last quick cleanup, and I don't think this applies to anything else in your asset base. But if anything, just to think about Alliance, any of your assets through 2026, I guess that's your current guidance time frame that's up for toll, challenges or reviews in an excellent bit?

Those are the two assets. Obviously, the two assets here that are sort of federally regulated would have been Cochin and Alliance. And obviously, we've dealt with both of those. So nothing else.

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

Right. Well, thank you, everybody, for joining us today, and we look forward to speaking this afternoon at our AGM. 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.