Pembina Pipeline - Earnings Call - Q1 2025
May 9, 2025
Transcript
Operator (participant)
Morning, ladies and gentlemen, and welcome to the Pembina Pipeline Corporation Q1 2025 results conference call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press *0 for the operator. 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.
Dan Tucunel (VP of Capital Markets)
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 NetGuard. I will now turn things over to Scott.
Scott Burrows (President and CEO)
Thanks, Dan. Yesterday, we reported our first quarter results, which were highlighted by quarterly adjusted EBITDA of CAD 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 Cam will discuss in more detail, we are currently trending towards the midpoint of our 2025 adjusted EBITDA guidance range, CAD 4.2 billion-CAD 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 announce a CAD 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, [PRUSKA Pay 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 de-ethanizer if 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's progressing development of more than CAD 4 billion portfolio of potential projects includes conventional pipeline expansions such as the Taylor to Gordondale project, an expansion of the Peace Pipeline system to add capacity to the market delivery pipelines from 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 Path2Zero 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's 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 will 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, 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.
Cameron Goldade (SVP and CFO)
Thanks, Scott. As Scott noted, Pembina reported first quarter adjusted EBITDA of CAD 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's 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 Nipissy 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 CAD 4.2 billion-CAD 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 commitments. 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 toll 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 CAD 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 3.4 times, and we expect to exit 2025 at 3.4-3.7 times.
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.
Scott Burrows (President and CEO)
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 (participant)
Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press *, followed by the 1 on your touch-tone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press *, followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. Your first question comes from Jeremy Tonet with JPMorgan. Your line is now open.
Jeremy Tonet (Managing Director and Utilities and Midstream Equity Research Analyst)
Hi, good morning.
Scott Burrows (President and CEO)
Morning, Jeremy.
Jeremy Tonet (Managing Director and Utilities and Midstream Equity Research Analyst)
Thanks for the color today. Just wanted to kind of start off with maybe a bit more color on your producer-customer conversations at this point in how you see, I guess, drilling activity shaping up. Should WTI be going below CAD 60, staying there for some period of time, and corresponding moves in condy prices, how you think that impacts Montney production and your outlook here? Granted, Pembina has material contractual protections, but just wondering any thoughts you could share there.
Scott Burrows (President and CEO)
Yeah, Jeremy, it's Scott. I'll start off and make some comments, and Jaret might chime in as well. 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. I would say we are starting to see some timing of completions. Overall, reductions of CapEx to date, we really haven't seen that.
Jeremy Tonet (Managing Director and Utilities and Midstream Equity Research Analyst)
Got it. Thank you for that. 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. Is it fair to kind of characterize, I guess, the range of outcomes at this point as relatively minor within the grand scheme of Pembina as far as what unfolds in the Canadian process here? Do you see, I guess, on the U.S. side, similar things materializing, or any other color would be helpful? Thanks.
Jaret Sprott (SVP and COO)
Morning, Jeremy. Jaret here. Yeah, I appreciate you mentioning that we are obviously limited in what we can say. What I can reassure you, Jeremy, is that our customers continue to reiterate they enjoy the high reliability and availability of the Alliance asset. They enjoy the high-value end market delivering into the Chicago area. They really value the risk-sharing aspect. Obviously, Pembina takes a material amount of operating cost risk. We believe we are a good, safe, reliable operator. They do appreciate that with respect to that asset. On the Canadian side, that is 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.
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. Unfortunately, that's all we can really say right now due to the active aspect of those negotiations.
Jeremy Tonet (Managing Director and Utilities and Midstream Equity Research Analyst)
Got it. As far as the U.S. side, nothing to think about there at this point?
Jaret Sprott (SVP and COO)
You bet. On the U.S. side, Jeremy, I believe it is December 1 of this year. We will be submitting, it is roughly every five years we have to submit our information to the FERC, and that is coming up, I believe, December 1 of 2025.
Jeremy Tonet (Managing Director and Utilities and Midstream Equity Research Analyst)
That's helpful. Thanks. Last one, if I could, just real quick. Pembina has done a great job getting the balance sheet in a very strong position. 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?
Jaret Sprott (SVP and COO)
Yeah, 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, it's a pretty dynamic environment right now, and we're obviously monitoring things kind of in real time. 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.
Jeremy Tonet (Managing Director and Utilities and Midstream Equity Research Analyst)
Got it. That's helpful. I'll leave it there. Thanks.
Operator (participant)
Your next question comes from Spiro Dounis with Citi. Your line is now open.
Spiro Dounis (Director and Midstream Analyst)
Thanks, operator. Morning, team. I wanted to start with the DS Tower and the Dow contract. Sounds like your plan right now is still to develop it at some point, maybe even without Dow announcing their 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 tracker being online. And then lastly, sorry for the multi-part question here, but in the interim, this does seem to free up some capital if you're not developing this tower imminently. Just curious how you're thinking about redeploying some of that capital?
Jaret Sprott (SVP and COO)
Good morning, Jaret here. Yeah, maybe I'll just take a step back. We announced it was probably May of 2024, actually, we announced the supply agreement with Dow. 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. We have been signaling that RFS III, which was a clone of RFS II, does make a lot of logical sense to build the DF side of that asset as part of our overall portfolio. 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.
Even with the most recent reprofiling or delay that Dow has mentioned, there is not a material change to our overall capital in 2025. We still believe, not knowing exactly when the new on-stream date might be announced, that it is just normal routine execution doing the DF tower. Now, my team is probably cringing that I am saying that, but it is not like a three- or four-year build for what we are doing. We absolutely believe that when we do get a little bit more line of sight, we will be able to act quickly and have that asset on to meet our supply portfolio commitments.
Spiro Dounis (Director and Midstream Analyst)
Got it. That's good color. Thanks for that. Second question, going back to Alliance quickly. I don't think this was addressed in the prior question, but I know at one point you'd 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 here and how you're thinking about the timing?
Jaret Sprott (SVP and COO)
I won't get into the specifics of the negotiation, but I can say that obviously demand for incremental gas egress is extremely strong. We have a couple of opportunities. Obviously, Alliance was built for a full path expansion all the way down into the Chicago market. There are also opportunities to do shorter haul expansions with fewer compressor stations here on the Canadian side into the Alberta Heartland. We are just continuing to evaluate those and kind of in the pre-FEED engineering stages of that. Lots of demand for incremental liquids-rich gas egress.
Spiro Dounis (Director and Midstream Analyst)
Understood. No, that's great to hear. I'll leave it there for today. Thank you, gentlemen.
Jaret Sprott (SVP and COO)
Thanks.
Operator (participant)
Your next question comes from Theresa Chen with Barclays. Your line is now open.
Theresa Chen (Managing Director of Midstream and Refining Equity Research)
Morning. 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? If so, if the risks were to move, what would that illustratively even look like?
Jaret Sprott (SVP and COO)
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. 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. With that said, as 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. It's pretty live and dynamic right now, and that's all I can say about that.
Theresa Chen (Managing Director of Midstream and Refining Equity Research)
Okay. Fair enough. To the earlier color about the bifurcation between volumes and revenue and EBITDA contribution due to the gap as customers ramp into the NVC, when do you expect that to true up?
Cameron Goldade (SVP and CFO)
Can you say, it's Cam here. I would say that that's a pretty consistent phenomenon or pretty consistent experience that we've seen. 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. As we continue to sign up new contracts, and obviously, the contracts are the leading indicator against the physical 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. We will continue to see a gap between those revenue and physical volumes as a result of that.
Jaret Sprott (SVP and COO)
Maybe I'll just add to that that you do have to delineate the difference between what we call our high vapor pressure products. So that's your C3 pluses and your C2 pluses versus your LVP, your 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 system, C2 plus, C3 plus, condensate, and crude. There are different dynamics happening. Some customers are over on certain aspects of their contracts. Overall, you will see that true up. It's not a blanket statement that all of our customers are below their firm or their take-or-pay, and they're all drilling into it. It is dynamic between asset, commodity, customer, and region.
Theresa Chen (Managing Director of Midstream and Refining Equity Research)
Thank you for that detailed answer.
Operator (participant)
Your next question comes from Aaron MacNeil with TD Cowen. The line is now open.
Aaron MacNeil (Director and Equity Research Analyst)
Morning, all. Thanks for taking my questions. 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. Just open-ended, anything you'd be comfortable sharing, just giving you the opportunity to do that.
Jaret Sprott (SVP and COO)
Yeah, you bet. Appreciate the question. It is one of our—I cannot say it is one of our largest customers. It is a Northeast B.C. customer. I think what I would 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 choose us for a safe, reliable, and cost-effective option specifically around the conventional pipeline. It is not only the safe, reliable operations 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, etc. We do recognize they have choices, and we do appreciate them choosing us to be their service provider.
I will say that this is a—I'll use the word material volume. It's existing volumes across the enterprise, so the pipelines, the fractionation in our marketing business, but it is also new. There is kind of twofold here. One is that it shows the resiliency and the requirement for high utilization across the base assets, but it also reinforces the need and necessity for new expansions, albeit the Taylor to Gordondale area, new pump stations within Alberta, etc. We've referenced pump station expansions between Fox Creek 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 is obviously—we've talked about it. It's a very meaningful piece of our contract structure. It's not quite 10%, but it's pretty close.
Obviously, the commitments beyond that flow through both the frac as well as other pieces. When we talk about it being a fairly material contract, that's the renewal piece. Obviously, the new piece of it is quite material, not quite to that magnitude, obviously, but very meaningful on its own.
Aaron MacNeil (Director and Equity Research Analyst)
Wow. Okay. That was more than I expected to get. Thanks for that. 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 guess I bring that up because the original CER complaint essentially compared Alliance to rate-regulated pipelines. The question is, how do you define an appropriate risk-adjusted return? Obviously, it's not a rate-regulated return, but is the right way to think about it in the context of prevailing industry-built multiples, or is there anything you can share there?
Jaret Sprott (SVP and COO)
Maybe I'll touch quickly on that. That's one of the biggest challenges through this negotiation is exactly what you just touched on. We are different than any other asset, and we're just working through that. What does that risk premium look like for Pembina?
Aaron MacNeil (Director and Equity Research Analyst)
Yeah. I appreciate that. That's a tough one to answer. Thanks.
Jaret Sprott (SVP and COO)
Yeah. 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. That is a no-risk scenario. 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. Perhaps that's what we're getting at with an appropriate risk-adjusted premium. Probably as far as I can go there, but I just make those data points clear.
Aaron MacNeil (Director and Equity Research Analyst)
That's super helpful. Thanks, everyone, for the answers. We'll turn it back.
Operator (participant)
Your next question comes from Praneeth Satish with Wells Fargo. Your line is now open.
Praneeth Satish (Senior Equity Analyst)
Thanks. Good morning. Maybe let me get my Alliance question out of the way here. 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. 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?
Scott Burrows (President and CEO)
On the timing piece, I'd say that's still part of the negotiation. No update. With that in mind, we really can't comment on 2025 guidance. Giving that clarity is another angle to try to figure out kind of where we're at in our negotiations. It's just too confidential and sensitive. We're just not going to answer that question. I apologize. As soon as we can say more, we will.
Praneeth Satish (Senior Equity Analyst)
Understood. That's fine. Switching gears, maybe if we could get an update on the Greenlight Electricity Center project. 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. Has the JV secured pricing on the turbines and other critical equipment costs and just any broader update you can provide?
Chris Scherman (SVP of Marketing and Strategy Officer)
Sure. It's Chris Sherman. Thanks for the question. The project's progressing nicely. We're really focused on our interconnection applications at the minute, at the moment. 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. We're going to be prudent with our order placement. Frankly, the timing still aligns with our expectations. Everything's going well and on track both commercially and on the project side.
Praneeth Satish (Senior Equity Analyst)
Got it. Thank you.
Operator (participant)
Your next question comes from Robert Hope with Scotiabank. Your line is now open.
Robert Hope (Managing Director of Equity Research)
Hello, everyone. First question 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? Could incremental ethane and C3 plus allow that project to stand on its own?
Scott Burrows (President and CEO)
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. Without knowing the specifics around the extent of Dow delay, I really can't comment on that. As of right now, we're continuing to progress that pipeline just due to when the in-service date was. No change from that on our end.
Jaret Sprott (SVP and COO)
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 was obviously early works.
We're obviously going to get more information as the weeks and the next two, three months tick by here. We'll obviously make judgments at that point. I just want to make clear that we were not spending material dollars on that in 2025. Obviously, just some early works and engineering work.
Scott Burrows (President and CEO)
You did nail it, Rob. Oh, sorry. There is a creative C3 plus 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.
Robert Hope (Managing Director of Equity Research)
All right. Appreciate that. Maybe diving deeper into the Dow agreement. It appears that the commentary today is that it is a delay, not a cancel. If the delay from Dow is substantial, do you have a sunset date or any recourse?
Jaret Sprott (SVP and COO)
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. Outside of that, I don't think we want to sort of go much deeper than that.
Robert Hope (Managing Director of Equity Research)
Understandable. Thank you. I'll hop back in the queue.
Operator (participant)
Your next question comes from Patrick Kenny with National Bank Financial. Your line is now open.
Patrick Kenny (Managing Director of Energy Infrastructure and Research Anaylyst)
Hey, good morning, guys. I'll try not to ask anything too commercially sensitive here. 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. I guess if you had a bit more color on what kinds of opportunities you're looking at in order to access non-US markets, both on a proprietary basis as well as utilizing third-party infrastructure, that'd be great.
Chris Scherman (SVP of Marketing and Strategy Officer)
It's Chris Sherman. 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. We have also talked about a desire to optimize Prince Rupert to increase some of the margins there. 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 markets, 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.
Patrick Kenny (Managing Director of Energy Infrastructure and Research Anaylyst)
Okay. That's great. I guess just on the remarketing of the capacity of 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 tons? I am 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.
Scott Burrows (President and CEO)
Yeah. Yeah. Added, 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. That is driving pretty significant interest in the Cedar capacity. We are pleased with where that's going. Also, the fact that obviously we're FID'd and we're a year into construction and a year closer in service date. I think all of those factors are leading to decent interest in this project. We are pretty pleased with where we're going. 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. They are big, complicated agreements.
As we have said for the last several months, we will do the right deal for Pembina, not the fastest deal for Pembina. We continue to progress that. I would say as it relates to a potential Cedar II, 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 II. Until we have line of sight to that gas on Coastal GasLink or other solutions, that is kind of the gating item. That is something that we continue to work on.
Patrick Kenny (Managing Director of Energy Infrastructure and Research Anaylyst)
Okay. That's great color. I appreciate it, guys. I'll leave it there.
Operator (participant)
Your next question comes from Maurice Choy with RBC Capital Markets. Your line is now open.
Maurice Choy (Director of Canadian Energy Infrastructure)
Thank you. Good morning, everyone. I just wanted to take a broader picture about the long-term WCSB outlook and hone in on the Taylor to Gordondale NGL pipeline project. Clearly, there is a competing third-party project out there. They are obviously against your projects in the CER process. Just your thoughts as to how you think the CER will resolve these sort of issues and taking one step further, any reason why you would think there would not be sufficient contracting volumes for both projects to proceed in the coming quarters?
Jaret Sprott (SVP and COO)
Morning, Maurice. Jaret here. Yeah, we recognize that there's currently two projects moving forward. You may be surprised to hear this, but I think I mentioned to you 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. Overall, between LNG Canada phase one, Pembina is highly confident LNG Canada phase two happens for all the reasons Scott just mentioned: world-scale resource and low commodities. You got your Cedar. You 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.
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 [PETCAM] facility. We are very bullish that both projects are required. We will 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.
Maurice Choy (Director of Canadian Energy Infrastructure)
Understood. I'm going to just finish up with a clean-up question here. Cam, I think in your prepared remarks, you mentioned you expect to exit 2025 at 3.4-3.7 times that EBITDA. I think that shifted a touch by about 0.1 from what you mentioned in last conference call. Clearly still well below the low end of your target range. Just wondering what assumptions have changed, especially given that the guidance for EBITDA hasn't, perhaps some growth spending, let's assume. Just a thought there.
Jaret Sprott (SVP and COO)
Yeah. 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 non-cash working capital as well as the timing of our cash tax payments. It is really more so timing than any sort of structural change.
Maurice Choy (Director of Canadian Energy Infrastructure)
I'm sorry. Just to reconfirm, the guidance that you have right now still assumes interim aligned tolls. Is that right?
Jaret Sprott (SVP and COO)
Correct.
Maurice Choy (Director of Canadian Energy Infrastructure)
Perfect. Thank you.
Operator (participant)
Your next question comes from Robert Catellier with CIBC Capital Markets. Your line is now open.
Robert Catellier (Energy Infrastructure Analyst)
Hey, 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 their products were less competitive because of tariffs. Or is it something about the economy or anything related to Canadian policies? Yeah, Rob, it's Scott here. That's a better question for Dow. 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 has the tariff uncertainty done to activity levels for Watson Island and the export outlook in general?
Chris Scherman (SVP of Marketing and Strategy Officer)
It's Chris. 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. I think in the long term, it really positions Watson and 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. We've got supply security concerns for a good part of the world that's going to be looking for alternate sources. Canada is a great piece of that.
We will be looking to leverage that as much as possible.
Robert Catellier (Energy Infrastructure Analyst)
Okay. Thanks, everyone.
Operator (participant)
Your next question comes from Sumantra Banerjee with UBS. Your line is now open.
Sumantra Banerjee (Equity Research Associate)
Hi. Thank you for taking the question. 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.
Cameron Goldade (SVP and CFO)
Yeah. Good morning. It's Cam. As I mentioned earlier, I think it's something we've clearly been watching in real time as the markets evolved 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 had 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. We obviously haven't changed that leading up to the Q1 print here. We were in blackout through April. We wouldn't have been in a position to execute any share buybacks, even if that would have made sense at the time.
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. Obviously, are reconsidering whether we shift some of that free cash flow towards share buybacks. Would not put a pin in it at the moment, but certainly something with lots of active debate and will ultimately be market condition dependent.
Sumantra Banerjee (Equity Research Associate)
Got it. Thank you. That's very helpful. Just a more general one on guidance. You've mentioned that you're tracking towards the midpoint currently. Of course, there's a lot of talk about volatility in the macro. Are there any projects or other factors that could push you more towards the top end of the guidance?
Cameron Goldade (SVP and CFO)
I would say that the biggest one would obviously be just in the near term is, frankly, probably going to be where we see the commodity business. I mean, I think it's no secret that that is the biggest driver of variability in our business. Obviously, we do have some interruptible volume exposure in our business. 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. Certainly, Q2 and Q3, we do expect to be sequentially lower compared to Q1, which is normal. That's a function of all the elements we saw. The cost picture on that side is largely well understood.
Really, it's the revenue opportunities that could come on top of that. If I summarize that, I would continue to say that market price variability will be the biggest single driver. Lastly, sort of the interruptible volume situation as egress on our own or on third-party pipelines becomes available or constrained.
Sumantra Banerjee (Equity Research Associate)
Great. Thank you so much.
Operator (participant)
Your next question comes from Ben Pham with BMO Capital Markets. Your line is now open.
Ben Pham (Managing Director and Pipelines and Utilities Analyst)
Hi, Ben. Good morning. A couple of questions on the marketing and the guidance you have maintained for the year. Q1, you have pretty much hit almost half of it so far. Can you share details on hedging on that segment? Also, just the trend around propane barrels. Is the trend over time from your vantage to move more barrels to the Canadian West Coast? How and if that could impact the long-term outlook in marketing EBITDA?
Chris Scherman (SVP of Marketing and Strategy Officer)
Sure. It's Chris. On the hedging side, our frac spread businesses go in at around 50% hedged here across the full year of 2025. We have a degree of protection from the volatility that Kem was mentioning on the frac spread side. As to how we are thinking about the market long-term, we have been, I think, fairly consistent for a while that we think the long-term resilient markets for the Canadian wave of growth that has come and will continue to come is global. US demand has been strong. There are lots of different narratives out there about how that might unfold over the next while. I think in the long term, the most resilient markets are going to be global. We will 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. As we look forward, we truly think the most resilient markets are going to be global. I would just add to that, Ben, that in terms of the 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 10-15% above current levels.
Ben Pham (Managing Director and Pipelines and Utilities Analyst)
Okay. Got it. Just on Alliance, but I'm not going to ask the polls. I just wanted to go back. When you underwrote that asset, you had some synergy expectation. Just want to where you tracked to that. Also, just wasn't there something about the Aux Sable marketing business in terms of higher volumes in the late decade timeframe? Just where are you over that?
Chris Scherman (SVP of Marketing and Strategy Officer)
Yeah. Hey, 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 is a significant amount of commercial opportunities in the Aux Sable business. Some small opportunities on the cost side across both assets, but more so on the commercial side. 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 CAD 40 million-CAD 65 million. That obviously had a ramp to it. Some of those come very quickly. Some of those take a little bit of time.
Certainly for 2025, we're tracking towards our intention there, which is probably at the lower end of the range as we expected. We continue to see the integration opportunities. We'll continue to look for more. So far, tracking according to plan.
Ben Pham (Managing Director and Pipelines and Utilities Analyst)
Okay. Got it. Just one last quick cleanup. I do not think this applies to anything else in your asset base. If anything, just think about that Alliance. Any other assets through 2026? I guess that is your current guidance timeframe that is up for toll challenges or reviews in an excellent bit?
Chris Scherman (SVP of Marketing and Strategy Officer)
Those are the two assets. Obviously, the two assets here that are sort of federally regulated would have been Cohsen and Alliance. Obviously, we've dealt with both of those. Nothing else.
Ben Pham (Managing Director and Pipelines and Utilities Analyst)
Okay. Okay. Got it. Thank you.
Operator (participant)
There are no further questions at this time. I will now turn the call over to Scott for closing remarks.
Scott Burrows (President and CEO)
All right. Thank you, everybody, for joining us today. We look forward to speaking this afternoon at our AGM. Thank you.
Operator (participant)
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating. Please disconnect your lines.